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    \27\ EPA's record demonstrates that plants typically have one or
two planned shut-downs annually and that the length of these
shutdowns is more than adequate to complete installation of relevant
treatment and control technologies.
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8. Legacy Wastewater
    For purposes of the BAT limitations in this rule, this preamble
uses the term ``legacy wastewater'' to refer to FGD wastewater, fly ash
transport water, bottom ash transport water, FGMC wastewater, or
gasification wastewater generated prior to the date determined by the
permitting authority that is as soon as possible beginning November 1,
2018, but no later than December 31, 2023 (see Section VIII.C.7). Under
this rule, legacy wastewater must comply with specific BAT limitations,
which EPA is setting equal to the previously promulgated BPT
limitations on TSS in the discharge of fly ash transport water, bottom
ash transport water, and low volume waste sources.
    EPA did not establish zero discharge BAT limitations for legacy
wastewater because technologies that can achieve zero discharge (such
as the ones on which the final BAT requirements discussed in Sections
VIII.C.2, 3, and 4, above, are based) are not shown to be available for
legacy wastewater. Legacy wastewater already exists in wet form, and
thus dry handling could not be used eliminate its discharge.
Furthermore, EPA lacks data to show that legacy wastewater could be
reliably incorporated into a closed-loop process that eliminates
discharges, given the variation in operating practices among

surface impoundments containing legacy wastewater.
    EPA also decided not to establish BAT limitations for legacy
wastewater based on a technology other than surface impoundments
(chemical precipitation, chemical precipitation plus biological
treatment, evaporation) because it does not have the data to do so.
Data are not available because of the way that legacy wastewater is
currently handled at plants.
    The vast majority of plants combine some of their legacy wastewater
with each other and with other wastestreams, including cooling water,
coal pile runoff, metal cleaning wastes, and low volume waste sources
in surface impoundments.\28\ Once combined in surface impoundments, the
legacy wastewater no longer has the same characteristics that it did
when it was first generated. For example, the addition of cooling water
can dilute legacy wastewater to a point where the pollutants are no
longer present at treatable levels. Additionally, some wastestreams
have significant variations in flow, such as metal cleaning wastes,
which are generally infrequently generated, or coal pile runoff, which
is generated during precipitation events. Because surface impoundments
are typically open, with no cover, they also receive direct
precipitation. As a result of all of this, the characteristics of
legacy wastewater contained in surface impoundments (flow rate and
pollutant concentrations) vary at both any given plant, as well as
across plants nationwide. Furthermore, EPA generally would like to have
enough performance data at a well-designed, well-operated plant or
plants to derive limitations and standards using its well-established
and judicially upheld statistical methodology. In this case, except in
limited circumstances, plants do not treat the legacy wastewater that
they send to an impoundment using anything beyond the surface
impoundment itself.\29\ Thus, the final rule establishes BAT
limitations for legacy wastewater equal to the previously promulgated
BPT limitations on TSS in discharges of fly ash transport water, bottom
ash transport water, and low volume waste sources.
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    \28\ For example, there are 65 plants for which EPA estimated
FGD wastewater compliance costs and that use an impoundment as part
of their treatment system. For 54 of the 65 plants (83 percent), the
FGD wastewater is commingled with, at least, fly and/or bottom ash
transport water, and for another eight of the 65 plants (12
percent), the FGD wastewater is commingled with non-ash wastewater,
such as cooling tower blowdown or low volume waste sources. DCN
SE05875.
    \29\ For example, no plant uses biological treatment or
evaporation to treat its legacy fly ash transport water or legacy
bottom ash transport water contained in an impoundment, including
any impoundment that may contain only legacy fly ash transport water
or only legacy bottom ash transport water. Although EPA identified
fewer than ten plants that use chemical precipitation to treat
wastewater that contains, among other things, ash transport water,
EPA does not have any data to characterize the effluent from these
systems. Thus, no steam electric industry data exist to establish
BAT limitations for possible ``fly ash-only'' impoundments or
``bottom ash-only'' impoundments based on these technologies.
---------------------------------------------------------------------------

    Finally, while there are a few plants that discharge from an
impoundment containing only legacy FGD wastewater,\30\ EPA rejected
establishing requirements for such legacy FGD wastewater based on a
technology other than surface impoundments. EPA determined that, while
it could be possible for plants to treat the legacy FGD wastewater with
the same technology used to treat FGD wastewater subject to the BAT
limitations described in Section VIII.C.1 (because their
characteristics could be similar), establishing requirements based on
any technology more advanced than surface impoundments for these legacy
``FGD-only'' wastewater impoundments could encourage plants to alter
their operations prior to the date that the final limitations apply in
order to avoid the new requirements. Likely, a plant would begin
commingling other process wastewater with their legacy FGD wastewater
in the impoundment so that any legacy ``FGD-only'' wastewater
requirements would no longer apply. Alternatively, plants might choose
to pump the legacy FGD wastewater out of the impoundment on an
accelerated schedule and prior to the date that the final limitations
apply. In this case, the more rapid discharge of the wastewater could
result in temporary increases in environmental impacts (e.g.,
exceedances of WQC for acute impacts to aquatic life). EPA wanted to
avoid creating such incentives in this rule, and it therefore decided
to establish BAT limitations for discharges of legacy FGD wastewater
based on the previously promulgated BPT limitations on TSS for low
volume waste sources. Finally, EPA notes that, as a result of the zero
discharge requirements for discharges of all pollutants in three
wastestreams (fly ash transport water, bottom ash transport water, and
flue gas mercury control wastewater), this rule provides strong
incentives for steam electric power plants to greatly reduce, if not
completely eliminate, the disposal and treatment of their major sources
of ash-containing wastewater in surface impoundments. As a result, EPA
anticipates that overall volumes of legacy wastewater will continue to
decrease dramatically over time, as this rule becomes fully
implemented.
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    \30\ EPA determined that there are three plants that are
estimated to incur FGD wastewater compliance costs and that use an
impoundment as part of the treatment system, but where the FGD
wastewater is not commingled with other process wastewaters in the
impoundment. There are no plants that discharge from an impoundment
containing only gasification wastewater.
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9. Economic Achievability
    EPA's analysis for the final BAT limitations demonstrates that they
are economically achievable for the steam electric industry as a whole,
as required by CWA section 301(b)(2)(A). EPA performed cost and
economic impact assessments using the Integrated Planning Model (IPM)
using a baseline that reflects impacts from other relevant
environmental regulations (see RIA).\31\ For the final rule, the model
showed very small additional effects on the electricity market, on both
a national and regional sub-market basis. Based on the results of these
analyses, EPA estimated that the requirements associated with the final
rule would result in a net reduction of 843 MW in steam electric
generating capacity as of the model year 2030, reflecting full
compliance by all plants. This capacity reduction corresponds to a net
effect of two unit closures or, when aggregating to the level of steam
electric generating plants, and net plant closure.\32\ These IPM
results support EPA's conclusion that the final rule is economically
achievable.
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    \31\ IPM is a comprehensive electricity market optimization
model that can evaluate such impacts within the context of regional
and national electricity markets. See Section IX for additional
discussion.
    \32\ Given the design of IPM, unit-level and thereby plant-level
projections are presented as an indicator of overall regulatory
impact rather than a precise prediction of future unit-level or
plant-specific compliance actions.
---------------------------------------------------------------------------

10. Non-Water Quality Environmental Impacts, Including Energy
Requirements \33\
---------------------------------------------------------------------------

    \33\ As described in Section VIII.C.13, this rule includes a
voluntary incentives program that provides the certainty of more
time for plants to implement new BAT requirements, if they adopt
additional process changes and controls that achieve limitations on
mercury, arsenic, selenium, and TDS in FGD wastewater, based on
evaporation technology. The information presented in this section
assumes plants will choose to comply with BAT limitations for FGD
wastewater based on chemical precipitation and biological treatment.
EPA does not know how many plants will opt into the voluntary
incentives program. Therefore, EPA also calculated non-water quality
environmental impacts assuming all plants will elect to comply with
the voluntary incentives program and similarly found these impacts
to be acceptable. See DCN SE05051.
---------------------------------------------------------------------------

    The final BAT effluent limitations have acceptable non-water
quality

environmental impacts, including energy requirements. Section XII
describes in more detail EPA's analysis of non-water quality
environmental impacts and energy requirements. EPA estimates that by
year 2023, under the final rule and reflecting full compliance, energy
consumption increases by less than 0.01 percent of the total
electricity generated by power plants. EPA also estimates that the
amount of fuel consumed by increased operation of motor vehicles (e.g.,
for transporting fly ash) increases by approximately 0.002 percent of
total fuel consumption by all motor vehicles.
    EPA also evaluated the effect of the BAT effluent limitations on
air emissions generated by all electric power plants (NOX,
sulfur oxides (SOX), and CO2), solid waste
generation, and water usage. Under the final rule, NOX
emissions are projected to decrease by 1.16 percent, SOX
emissions are projected to increase by 0.04 percent, and CO2
emissions are projected to decrease by 0.106 percent due to changes in
the mix of electricity generation (e.g., less electricity from coal-
fired steam electric generating units and more electricity from natural
gas-fired steam electric generating units). Moreover, solid waste
generation is projected to increase by less than 0.001 percent of total
solid waste generated by all electric power plants. Finally, EPA
estimates that the final rule has a positive impact on water
withdrawal, with steam electric power plants reducing the amount of
water they withdraw by 57 billion gallons per year (155 million gallons
per day).
11. Impacts on Residential Electricity Prices and Low-Income and
Minority Populations
    EPA examined the effects of the final rule on consumers as an
additional factor that might be appropriate when considering what level
of control represents BAT. If all annualized compliance costs were
passed on to residential consumers of electricity, instead of being
borne by the operators and owners of power plants (a very conservative
assumption), the average monthly increase in electricity bill for a
typical household would be no more than $0.12 under the final rule.
    EPA also considered the effect of the rule on minority and low-
income populations. As explained in Section XVII.J, using demographic
data regarding who resides closest to steam electric power plant
discharges and who consumes the most fish from waters receiving power
plant discharges, EPA concluded that low-income and minority
populations benefit to an even greater degree than the general
population from the reductions in discharges associated with the final
rule.
12. Existing Oil-Fired and Small Generating Units
    EPA considered whether subcategorization of the ELGs was warranted
based on the factors specified in CWA section 304(b)(2)(B) (see Section
IV.B.3 and TDD Section 5). Ultimately, EPA concluded that it would be
appropriate to set different limitations for existing small generating
units (50 MW or less) and existing oil-fired generating units. No
other, different requirements were warranted for this rule under the
factors considered.
    Oil-Fired Generating Units. For oil-fired generating units, the
final rule establishes BAT effluent limitations for FGD wastewater, fly
ash transport water, bottom ash transport water, FGMC wastewater, and
gasification wastewater equal to previously established BPT limitations
on TSS in fly ash transport water, bottom ash transport water, and low
volume waste sources. As defined in the rule, oil-fired generating
units refer to those that use oil as either the primary or secondary
fuel and do not burn coal or petroleum coke. Units that use only oil
during startup or for flame stabilization are not considered oil-fired
generating units.
    EPA decided to finalize these limitations for oil-fired generating
units because EPA's record demonstrates that, 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 final rule.
    The amount of ash generated by oil-fired units is a small fraction
of the amount produced by coal-fired units. Coal-fired units generate
hundreds to thousands of tons of ash each day, with some plants
generating more than 2,000 tons per day of ash. In contrast, oil-fired
units generate less than ten tons 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 1,800 times more ash
than oil-fired units (0.6 tons per MW-hour on average for coal units;
0.000319 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 generating units
discharge substantially fewer pollutants to surface waters than coal-
fired units, even when generating the same amount of electricity. EPA
estimates that the amount of pollutants discharged collectively by all
oil-fired generating units is a very small portion of the pollutants
discharged collectively by all steam electric power plants (less than
one percent, on a toxic-weighted basis).
    Oil-fired generating 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, fewer than 20 oil-fired generating units discharged fly ash or
bottom ash transport water in 2009. This is likely because only about
20 percent of oil-fired generating units operate as baseload units; the
rest are either cycling/intermediate units (about 45 percent) or
peaking units (about 35 percent). These units also have notably low
capacity utilization. While about 30 percent of the baseload units
report capacity utilization greater than 75 percent, almost half 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
generating units operated for more than six months in 2009; nearly half
of the units operated for fewer than 30 days.
    While these older and generally intermittently operated oil-fired
generating units are capable of installing and operating the treatment
technologies that form the bases for this rule, and the costs would be
affordable for most plants, EPA concludes 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, EPA is concerned about resulting reductions in the
flexibility that grid operators have during peak demand due to 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 important 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, as commenters confirmed. EPA
considered these potential impacts on electric grid reliability and the
nation's energy security, under CWA section 304(b)(2)(B), in its
decision to establish

different BAT limitations for oil-fired generating units.
    Small Generating Units. The final rule also establishes BAT
effluent limitations for FGD wastewater, fly ash transport water,
bottom ash transport water, FGMC wastewater, and gasification water at
small generating units equal to previously established BPT limitations
on TSS for fly ash transport water, bottom ash transport water, and low
volume waste sources. For purposes of this rule, small generating units
refer to those units with a total nameplate generating capacity of 50
MW or less. EPA decided to establish these different BAT limitations
for small units because they are more likely to incur compliance costs
that are significantly and disproportionately higher per amount of
energy produced (dollars per MW) than those incurred by larger units.
    Some commenters stated that the cost to a unit in terms of dollars
per MW is not relevant because BAT should be established at a level at
which the costs are affordable to the industry as a whole. They noted
that EPA's IPM analysis demonstrates that the most stringent proposed
regulatory option is economically achievable for all units above 50 MW.
Other commenters supported EPA's consideration of the relative
magnitude of costs for smaller units compared to larger units, and some
suggested EPA should increase the size threshold to 100 MW because
those units also have disproportionate costs per amount of energy
produced, and they collectively discharge a small fraction of the total
pollutants discharged by all steam electric power plants.
    EPA reviewed the record and re-evaluated the threshold for small
units in light of comments and the key changes since proposal discussed
in Section V. EPA considered establishing no threshold, as well as
several different size thresholds, for small units. The Agency looked
closely at establishing a threshold at 50 MW or 100 MW. While the total
amount of pollutants discharged by units at these thresholds is
relatively small in comparison to those discharged by all steam
electric power plants, the amount of pollutants discharged by units
smaller than or equal to 100 MW is almost double the amount of
pollutants discharged by units smaller than or equal to 50 MW. See DCN
SE05813 for specific information on these pollutant discharges. The
record indicates that the cost per unit of energy produced increases as
the size of the generating unit decreases, and while there is no clear
``knee of the curve'' at which to establish a size threshold, there is
a difference between units at 50 MW and below compared to those above
50 MW. Figure VIII-1, below, shows the annualized cost per amount of
energy produced for existing units under Regulatory Option D. Figure
VIII-1 shows that the cost per amount of energy produced increases as
the size of the generating unit decreases. Annualized cost per amount
of energy produced increases gradually as one moves from the very
largest units down to 100 MW, and then the cost per amount of energy
produced begins to increase more rapidly as one moves from 100 MW down
to 50 MW, until it increases very rapidly for units at 50MW and below.
Additionally, Figure VIII-1 shows that nearly all of the ratios of cost
to amount of energy produced for units smaller than or equal to 50 MW
are above those for the entire population of remaining units. The same
cannot be said of the ratio for units smaller than or equal to 100 MW.
[GRAPHIC] [TIFF OMITTED] TR03NO15.221

    In light of the fact that the costs per amount of energy produced
are significantly and disproportionately higher for units smaller than
or equal to 50 MW compared to larger units, and in light of the very
small fraction of pollutants discharged by units smaller than or equal
to 50 MW, EPA ultimately decided to establish different requirements
for units at this threshold. Keeping in mind the statutory directive to
set effluent limitations that result in reasonable further progress
toward the national goal of eliminating the discharge of all pollutants
(CWA section 301(b)(2)(A)), EPA used its best judgment to balance the
competing interests. EPA recognizes that any attempt to establish a
size threshold for generating units will be imperfect due to individual
differences across units and firms. EPA concludes, however, 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, while advancing the CWA's goals.
Furthermore, as shown in Section IX.C, EPA's analysis demonstrates that
the final rule, with a threshold established at 50 MW, is economically
achievable.
13. Voluntary Incentives Program
    As part of the BAT for existing sources, the final rule establishes
a voluntary incentives program that provides the certainty of more time
(until December 31, 2023) for plants to implement new BAT requirements,
if they adopt additional process changes and controls that achieve
limitations on mercury, arsenic, selenium, and TDS in FGD wastewater,
based on evaporation technology (see Section VIII.C.1 for a more
complete description of the evaporation technology basis). This
optional program offers significant environmental protections beyond
those achieved by the final BAT limitations for FGD wastewater based on
chemical precipitation plus biological treatment because evaporation
technology is capable of achieving significant removals of toxic
metals, as well as TDS.\34\
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    \34\ Properly operated evaporation systems are also capable of
achieving the BAT limitations based on chemical precipitation plus
biological treatment.
---------------------------------------------------------------------------

    EPA's proposal included a voluntary incentives program that
contained, as one element, incentives in the form of additional
implementation time for plants that eliminate the discharge of all
process wastewater (except cooling water). Public commenters urged EPA
to consider establishing, instead, a program that provided incentives
for plants that go further than the rule's requirements to reduce
discharges from individual wastestreams. Because the final rule already
contains zero discharge limitations for several key wastestreams, EPA
decided that the voluntary incentives program should focus on FGD
wastewater.
    EPA concluded that additional pollutant reductions could be
achieved under a voluntary incentives program because there are certain
reasons a plant might opt to treat its FGD wastewater using evaporation
rather than chemical precipitation plus biological treatment. One such
reason is the possibility that a plant's NPDES permit may need more
stringent limitations necessary to meet applicable WQS. For example,
some power plant discharges containing TDS (including bromide) that
occur upstream of drinking water treatment plants can negatively impact
treatment of source waters at the drinking water treatment plants. A
recent study identified four drinking water treatment plants that
experienced increased levels of bromide in their source water, and
corresponding increases in the formation of carcinogenic disinfection
by-products (brominated DPBs) in the finished drinking water, after the
installation of wet FGD scrubbers at upstream steam electric power
plants (DCN SE04503).
    Furthermore, based on trends in the industry and experience with
this and other industries, EPA expects that, over time, the costs of
evaporation (and other technologies that could achieve the limitations
in the voluntary incentives program, including zero discharge
practices) will decrease so as to make it an even more attractive
option for plants. EPA understands that vendors are already working on
changes to this technology to reduce the costs, reduce the amount of
solids generated, and improve the solids handling. See TDD Section
7.1.4.
    The technology on which the BAT limitations in the voluntary
incentives program are based, evaporation, is available to steam
electric power plants. EPA identified three plants in the U.S. that
have installed, and one plant that is in the process of installing,
evaporation systems to treat their FGD wastewater. Four coal-fired
power plants in Italy treat FGD wastewater using evaporation. See TDD
Section 7. Furthermore, the voluntary program is economically
achievable because only those plants that opt to be subject to the BAT
limitations based on evaporation, rather than the BAT limitations based
on chemical precipitation plus biological treatment, must achieve them.
Therefore, any plant that chooses to be subject to the more stringent
limitations has determined for itself, in light of its own financial
information and economic outlook, that such limitations are
economically achievable. Finally, EPA analyzed the non-water quality
environmental impacts and energy requirements associated with the
voluntary incentives program, and it found them acceptable. See DCN
SE05574.
    The development of this voluntary incentives program furthers the
CWA's ultimate goal of eliminating the discharge of pollutants into the
Nation's waters. See CWA section 101(a)(1) and section 301(b)(2)(A)
(specifying that BAT will result in ``reasonable further progress
toward the national goal of eliminating the discharge of pollutants'').
While the final rule's BAT limitations based on chemical precipitation
plus biological treatment represent ``reasonable further progress,''
the voluntary incentives program is designed to press further toward
achieving the national goal of the Act, as wastewater that has been
treated properly using evaporation has very low pollutant
concentrations (also making it possible to reuse the wastewater and
completely eliminate the discharge of any pollutants). In addition, CWA
section 104(a)(1) 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. EPA
anticipates that the voluntary incentives program will effectively
accelerate the research into and demonstration of controls and
processes intended to prevent, reduce, and eliminate pollution because,
under it, plants will opt to employ control and treatment strategies to
significantly reduce discharges of pollutants found in FGD wastewater.
    Steam electric power plants agreeing to meet BAT limitations for
FGD wastewater based on evaporation must comply with those limitations
on arsenic, mercury, selenium, and TDS in FGD wastewater.\35\ For such
plants, the BAT limitations based on evaporation apply as of December
31, 2023, to FGD wastewater generated on and after December 31, 2023.
Plants opting to participate in the voluntary program can use the
period in advance of this date to research, engineer, design, procure,
construct, and optimize systems capable

of meeting the limitations based on evaporation.
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    \35\ For some plants, proper pretreatment such as softening or
chemical precipitation is likely appropriate to ensure effective and
efficient operation of evaporation systems.
---------------------------------------------------------------------------

    For purposes of the voluntary incentives program BAT limitations,
legacy FGD wastewater is FGD wastewater generated prior to December 31,
2023. For such legacy FGD wastewater, the final rule establishes BAT
limitations on TSS in discharges of FGD wastewater that are equal to
BPT limitations for low volume waste sources.
    EPA decided not to make the voluntary incentives program available
to plants that send their FGD wastewater to POTWs. Under CWA section
307(b)(1), PSES must specify a time for compliance that does not exceed
three years from the date of promulgation, and thus the additional time
of up to 2023 cannot be given to indirect dischargers. Of course,
nothing prohibits an indirect discharger from using any technology,
including evaporation, to comply with the final PSES and PSNS.
    EPA expects that any plant interested in the voluntary incentives
program would indicate their intent to opt into the program prior to
issuance of its next NPDES permit, following the effective date of this
rule. A plant can indicate its intent to opt into the voluntary program
on its permit application or through separate correspondence to the
NPDES Director, as long as the signatory requirements of 40 CFR 122.22
are met.

D. Best Available Demonstrated Control Technology/NSPS

    After considering all of the technologies described in this
preamble and TDD Section 7, as well as public comments, and in light of
the factors specified in CWA section 306 (see Section IV.B.4), EPA
concluded that the technologies described in Option F represent BADCT
for steam electric power plants, and the final rule promulgates NSPS
based on that option. Thus, the final NSPS establish: (1) Standards on
arsenic, mercury, selenium, and TDS in FGD wastewater, based on
evaporation (same basis as for BAT limitations in voluntary incentives
program); (2) a zero discharge standard on all pollutants in bottom ash
transport water, based on dry handling or closed-loop systems (same
bases as for BAT limitations); (3) a zero discharge standard on all
pollutants in FGMC wastewater, based on dry handling (same basis as for
BAT limitations); (4) standards on mercury, arsenic, selenium, and TDS
in gasification wastewater, based on evaporation technology (same basis
as for BAT limitations); and (5) standards on mercury and arsenic in
discharges of combustion residual leachate, based on chemical
precipitation (more specifically, the technology basis is a chemical
precipitation system that employs hydroxide precipitation, sulfide
precipitation, and iron coprecipitation to remove heavy metals). The
final rule also maintains the previously established zero discharge
NSPS on discharges of fly ash transport water, based on dry handling.
    The record indicates that the technologies that serve as the bases
for the final NSPS are well demonstrated based on the performance of
plants using the technologies. For example, new steam electric power
generating sources have been meeting the previously established zero
discharge standard for fly ash transport water since 1982,
predominantly through the use of dry handling technologies. Moreover,
as described in Section VIII.C.13, three plants in the U.S. and four
plants in Italy use evaporation technology to treat their FGD
wastewater, and another U.S. plant is in the process of installing such
technology for that purpose. Of the approximately 50 coal-fired
generating units that were built within the last 20 years, 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
technology basis identified as BAT technology for gasification
wastewater represents current industry practice. Every IGCC power plant
currently in operation uses evaporation to treat their 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 combustion
residual leachate, chemical precipitation is a well-demonstrated
technology for removing metals and other pollutants from a variety of
industrial wastewaters, including leachate from landfills not located
at power plants. Chemical precipitation is also well demonstrated at
steam electric power plants for treatment of FGD wastewater that
contains the pollutants in combustion residual leachate.
    The NSPS in the final rule pose no barrier to entry. The cost to
install technologies at new units is typically less than the cost to
retrofit existing units. For example, the cost differential between
Options B, C, and D for existing sources is mostly associated with
retrofitting controls for bottom ash handling systems. For new sources,
however, NSPS based on Option F do not present plants with the same
choice of retrofit versus modification of existing processes. This is
because every new generating unit must install some type of bottom ash
handling system as the unit is constructed. Establishing a zero
discharge standard for all 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.
    Moreover, EPA assessed the possible impacts of the final NSPS on
new sources by comparing the incremental costs of the Option F
technologies to the costs of hypothetical new generating units. EPA is
not able to predict which plants might construct new units or the exact
characteristics of such units. Instead, EPA calculated and analyzed
compliance costs for a variety of plant and unit configurations. EPA
developed NSPS compliance costs for new sources using a methodology
similar to the one used to develop compliance costs for existing
sources. EPA's estimates for compliance costs for new sources are based
on the net difference in costs between wastewater treatment system
technologies that would likely have been implemented at new sources
under the previously established regulatory requirements, and those
that would likely be implemented under the final rule. EPA estimated
that the incremental compliance costs for a new generating unit
(capital and O&M) represent approximately 3.3 percent of the annualized
cost of building and operating a new 1,300 MW coal-fired plant, with
capital costs representing 0.3 to 2.8 percent of the overnight
construction costs, and annual O&M costs representing 0.3 to 3.9
percent of the fuel and other O&M cost of operating a new plant.
    Finally, EPA analyzed the non-water quality environmental impacts
and energy requirements associated with Option F for both existing and
new sources. See DCN SE05952 and DCN SE05951. Since there is nothing
inherently different between an existing and new source, EPA's analysis
with respect to existing sources is instructive. Using both of these
analyses, EPA determined that NSPS based on the Option F technologies
have acceptable non-water quality environmental impacts and energy
requirements.
    In contrast to the BAT effluent limitations, this rule establishes
the same NSPS for oil-fired generating units and small generating units
as 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 incur retrofit
costs because the pollution controls (process operations or treatment
technology) are installed at the time of construction. Thus the costs
for new sources are lower, even if the pollution controls are
identical.
    For each of the wastestreams except combustion residual leachate,
EPA rejected establishing NSPS based on surface impoundments for the
same reasons it rejected establishing BAT based on surface
impoundments. For FGD wastewater, EPA also did not establish NSPS based
on chemical precipitation for the same reasons it rejected establishing
BAT based on that technology. In particular, these other technologies
would not achieve as much pollutant reduction as the technology bases
in Option F--which is technologically available and economically
achievable with acceptable non-water quality environmental impacts and
energy requirements--and thus do not represent best available
demonstrated control technology.
    EPA did not select surface impoundments as the basis for NSPS for
combustion residual leachate because, unlike BAT, NSPS represent the
``greatest degree of effluent reduction . . . achievable'' (CWA section
306), and (besides ``cost'' and ``any non-water quality environmental
impact and energy requirements,'' discussed above) EPA does not
consider ``other factors'' in establishing NSPS. When used to treat
combustion residual leachate, chemical precipitation can achieve
substantial pollutant reductions as compared to surface impoundments.
Thus, EPA has determined that NSPS for leachate based on chemical
precipitation achieve the ``greatest degree of effluent reduction'' as
that term is used in CWA section 306.
    Similarly, EPA did not select chemical precipitation plus
biological treatment as the basis for NSPS for FGD wastewater because,
under CWA section 306, NSPS reflect ``the greatest degree of effluent
reduction . . . achievable.'' Evaporation systems are capable of
achieving extremely low pollutant discharge levels, and in fact can be
the basis for a plant completely eliminating all discharges associated
with FGD wastewater. Moreover, unlike EPA's decision not to identify
evaporation as the technology basis for FGD wastewater discharges from
all existing sources due to the large associated cost, establishing
NSPS for FGD wastewater based on evaporation does not add to the
overall estimated cost of the rule because EPA does not predict any new
coal-fired generating units will be installed in the foreseeable
future. As explained above, however, in the event that a new unit is
installed, EPA determined that the NSPS compliance costs would not
present a barrier to entry.

E. PSES

    Table VIII-2 summarizes the results of EPA's pass-through analysis
for the regulated pollutants (with numeric limitations) in each
wastestream, as controlled by the relevant BAT and NSPS technology
bases.\36\ As explained in Section VII.C, EPA did not conduct its
traditional pass-through analysis for wastestreams with zero discharge
limitations or standards. Zero discharge limitations and standards
achieve 100 percent removal of pollutants; therefore, all pollutants in
those wastestreams pass through the POTW. As shown in the table, all of
the pollutants regulated under BAT/NSPS pass through secondary
treatment by a POTW.
---------------------------------------------------------------------------

    \36\ The regulation of TSS in combustion residual leachate
(based on surface impoundments) under the final BAT limitations is
not represented here because TSS is a conventional pollutant that is
effectively treated by POTWs (it does not pass through).

         Table VIII-2--Summary of Pass-Through Analysis Results
------------------------------------------------------------------------
   Technology basis/Wastewater                        Pass through? (yes/
             stream                    Pollutant              no)
------------------------------------------------------------------------
Chemical Precipitation for        Arsenic...........  Yes.
 Combustion Residual Leachate     Mercury...........  Yes.
 (only for NSPS).
Chemical Precipitation plus       Arsenic...........  Yes.
 Biological Treatment for FGD     Mercury...........  Yes.
 Wastewater.                      Nitrate/Nitrite as  Yes.
                                   N.                 Yes.
                                  Selenium..........
Evaporation for FGD wastewater    Arsenic...........  Yes.
 (only for NSPS).                 Mercury...........  Yes.
                                  Selenium..........  Yes.
                                  TDS...............  Yes.
Evaporation for Gasification      Arsenic...........  Yes.
 Wastewater.                      Mercury...........  Yes.
                                  Selenium..........  Yes.
                                  TDS...............  Yes.
------------------------------------------------------------------------

    After considering all of the relevant factors and technology
options in this preamble and in the TDD, as well as public comments, as
is the case with BAT, EPA decided to establish PSES based on the
technologies described in Option D. For PSES, the final rule
establishes: (1) Standards on arsenic, mercury, selenium and nitrate/
nitrite as N in FGD wastewater; (2) a zero discharge standard on all
pollutants in fly ash transport water; (3) a zero discharge standard on
all pollutants in bottom ash transport water; (4) a zero discharge
standard on all pollutants in FGMC wastewater; (5) standards on
mercury, arsenic, selenium, and TDS in gasification wastewater. All of
the technology bases for the final PSES are the same as those described
for the final BAT limitations. The final rule does not establish PSES
for combustion residual leachate because TSS does not pass through
POTWs.
    EPA selected the Option D technologies as the bases for PSES for
the same reasons that EPA selected the Option D technologies as the
bases for BAT. EPA's analysis shows that, for both direct and indirect
dischargers, the Option D technologies are available and economically
achievable, and Option D has acceptable non-water quality environmental
impacts, including energy requirements (see Sections IX and XII). EPA
rejected other options for

PSES for the same reasons that the Agency rejected other options for
BAT. Furthermore, for the same reasons that apply to EPA's final BAT
limitations for oil-fired generating units and small generating units,
and described in Section VIII.C.12, the final rule does not establish
PSES that apply to oil-fired generating units and small generating
units (50 MW or smaller).\37\ Finally, EPA determined that the final
PSES prevent pass through of pollutants from POTWs into receiving
streams and also help control contamination of POTW sludge.
---------------------------------------------------------------------------

    \37\ Whereas the final rule establishes BAT limitations on TSS
in fly ash and bottom ash transport water, FGMC wastewater, FGD
wastewater, and gasification wastewater for small generating units
and oil-fired generating units, TSS and the pollutants that they
represent do not pass through POTWs.
---------------------------------------------------------------------------

    As with the final BAT effluent limitations, in considering the
availability and achievability of the final PSES, EPA concluded that
existing indirect dischargers need some time to achieve the final
standards, in part to avoid forced outages (see Section VIII.C.7).
However, in contrast to the BAT limitations (which apply on a date
determined by the permitting authority that is as soon as possible
beginning November 1, 2018, but no later than December 31, 2023), the
new PSES apply as of November 1, 2018. Under CWA section 307(b)(1),
pretreatment standards shall specify a time for compliance not to
exceed three years from the date of promulgation, so EPA cannot
establish a longer implementation period. Moreover, unlike requirements
on direct discharges, requirements on indirect discharges are not
implemented through an NPDES permit and thus are not subject to
awaiting the next permit issuance before the limitations are specified
clearly for the discharger. EPA has determined that all of the existing
indirect dischargers can meet the standards by November 1, 2018, and
because there are a handful of indirect dischargers (who would have
approximately three years from the date of promulgation to achieve the
standards), implementation of the standards by that date would not lead
to electricity availability concerns. See RIA.
    For purposes of the PSES in this rule, this preamble uses the term
``legacy wastewater'' to refer to FGD wastewater, fly ash transport
water, bottom ash transport water, FGMC wastewater, or gasification
wastewater generated prior to November 1, 2018. For the same reasons
that EPA decided to establish BAT limitations on TSS in discharges of
legacy wastewater equal to BPT limitations for fly ash transport water,
bottom ash transport water, and low volume waste sources, the final
rule does not establish PSES for legacy wastewater (see Section
VIII.C.8). TSS and the pollutants it represents are effectively treated
by, and thus do not pass through, POTWs.

F. PSNS

    After considering all of the relevant factors and technology
options described in this preamble and TDD Section 7, as well as public
comments, as was the case for NSPS, EPA selected the Option F
technologies as the bases for PSNS in this rule. As a result, the final
PSNS establish: (1) Standards on arsenic, mercury, selenium, and TDS in
FGD wastewater; (2) a zero discharge standard on all pollutants in
bottom ash transport water; (3) a zero discharge standard on all
pollutants in FGMC wastewater; (4) standards on mercury, arsenic,
selenium, and TDS in gasification wastewater; and (5) standards on
mercury and arsenic in combustion residual leachate. All the technology
bases for the final PSNS are the same as those described for the final
NSPS. The final rule also maintains the previously established zero
discharge PSNS on discharges of fly ash transport water. As with the
final NSPS, this rule establishes the same PSNS for oil-fired
generating units and small generating units as for all other new
sources.
    EPA selected the Option F technologies as the bases for PSNS for
the same reasons that EPA selected the Option F technologies as the
bases for NSPS (see Section VIII.D). EPA's record demonstrates that the
technologies described in Option F are available and demonstrated, and
Option F does not pose a barrier to entry and has acceptable non-water
quality environmental impacts, including energy requirements (see
Sections IX and XII). EPA rejected other options for PSNS for the same
reasons that the Agency rejected other options for NSPS. And, as with
the final PSES, EPA determined that the final PSNS prevent pass through
of pollutants from POTWs into receiving streams and also help control
contamination of POTW sludge.

G. Anti-Circumvention Provision

    The final rule establishes one of the three anti-circumvention
provisions that EPA proposed. The one anti-circumvention provision that
EPA decided to establish applies only for existing sources to those
wastestreams for which this rule established zero discharge limitations
or standards. In general, this provision prevents steam electric power
plants from circumventing the final rule by moving effluent produced by
a process operation for which there is an applicable zero discharge
effluent limitation or standard to another plant process operation for
discharge.\38\ EPA determined it was appropriate to include this
provision in the final rule to make clear that, just because a
wastestream that is subject to a zero discharge limitation or standard
is moved to another plant process, it does not mean that the
wastestream ceases being subject to the applicable zero discharge
limitation or standard. For example, using fly ash or bottom ash
transport water as makeup water for a cooling tower does not relieve a
plant of having to meet the zero discharge limitations and standards
for fly ash and bottom ash transport water. EPA encourages the reuse of
wastewater where appropriate, but not to the extent that it undermines
the zero discharge effluent limitations and standards in this rule.
Plants are free to reuse their wastewater, so long as the wastewater
ultimately complies with the final limitations and standards.
---------------------------------------------------------------------------

    \38\ The anti-circumvention provision applies only to
limitations and standards established in this final rule. It does
not apply to limitations and standards promulgated previously.
---------------------------------------------------------------------------

    Some public commenters stated that zero discharge effluent
limitations and standards for fly ash and bottom ash transport water,
together with this anti-circumvention provision, would prohibit water
reuse and prevent water withdrawal reduction at steam electric power
plants. In general, EPA disagrees with these commenters. Most plants
will choose to comply with the requirements for ash transport water by
operating either a dry or closed-loop wet-sluicing system to handle
their fly and bottom ash, which will eliminate or substantially reduce
the amount of water they currently use in the traditional wet-sluicing
system. To the extent that a plant currently uses (or was considering
using) ash transport water, such as the effluent from an impoundment,
as makeup water for processes such as make-up cooling water and would
be precluded from doing so because of the anti-circumvention provision
in this rule, the plant could merely switch to an alternate source for
the makeup water, such as the water that was (prior to implementing the
zero discharge requirement for ash transport water) used to sluice fly
ash or bottom ash to the impoundment. In other words, the volume of
water that is currently used to sluice ash to an impoundment and

subsequently reused as makeup water would no longer be needed to sluice
the ash and could instead be directly used as makeup water for the
cooling water system or other processes. Because of this, the zero
discharge limitations in this rule will not lead to a net increase at
the plant and in fact could result in a decrease in water withdrawal.
Lastly, a plant is free to reuse ash transport water, and would be in
compliance with the anti-circumvention provision, so long as it is used
in a process that does not ultimately result in a discharge.
    There is one particular type of plant practice that the final
rule's anti-circumvention provision does not apply to. Many industry
commenters noted that they use ash transport water in their FGD
scrubber. They stated that this practice is preferable to using a fresh
water source and allows for an overall reduction in source water
withdrawals. They further stated that, under the final rule, any
wastewater that passes through the scrubber would undergo significant
treatment in order to meet the final FGD wastewater limitations and
standards. EPA agrees, in part, with these comments. As explained
above, EPA does not agree that using wastewater from one industrial
process as makeup water in another industrial process necessarily
results in a net reduction in water withdrawals. EPA does agree,
however, that using wastewater from an industrial process as makeup
water in another industrial process may be preferable to using a fresh
water source. EPA is mindful of the CWA's pollutant discharge
elimination goal, but also wants to promote opportunities for water
reuse. Furthermore, as explained in Section V, EPA recognizes the
extensive changes in this industry, and it wants to provide flexibility
to plants in managing their wastewater and operations, as well as
preserve the ability of plants to retain existing approaches where it
is consistent with the CWA's goals. While EPA would not choose to
promote these considerations where it resulted in no further progress
toward the pollutant discharge elimination goal of the Act, in the case
of using ash transport water in an FGD scrubber, since any resulting
wastewater discharges would still be required to meet BAT or PSES
requirements based on either chemical precipitation plus biological
treatment or chemical precipitation plus evaporation under this final
rule, EPA decided not to apply the anti-circumvention provision to this
particular practice.
    The final rule does not establish an anti-circumvention provision
that would have required internal monitoring to demonstrate compliance
with certain numeric limitations and standards. Some public commenters
argued that the proposed provision was unduly restrictive, and they
stated that EPA already has authority to accomplish the goal of this
particular provision, which is to ensure that wastestreams are being
treated rather than simply diluted. EPA agrees with these commenters
and thus decided that existing rules, along with the guidance in
Section XVI.A.4 of this preamble and TDD Section 14, provide
appropriate flexibility to steam electric power plants to combine
wastestreams with similar pollutants and treatability, while adequately
addressing EPA's concern that plants meet the effluent limitations and
standards in this rule through treatment and control strategies, rather
than through dilution. Furthermore, some commenters raised concerns
that the proposed provision would be a disincentive for plants to
internally re-use the treated wastewater within the plant, particularly
when the re-use eliminates the discharge of the wastewater. For
example, they stated that some steam electric power plants might opt to
use a wet scrubber's FGD wastewater as reagent make-up for a new dry
scrubber in an integrated design which would essentially evaporate the
wet FGD wastewater. EPA notes that plants that internally reuse
wastestreams for which EPA is establishing numeric limitations and
standards (e.g., FGD wastewater) in a way that completely prevents
discharge of that wastestream would not be subject to the numeric
limitations and standards because they do not discharge the wastewater.
EPA is aware of at least one plant that elected to take such an
approach as an alternative to meeting NPDES permit limitations by
installing wastewater treatment technology. See DCN SE06338. In
general, EPA supports such approaches because they result in further
progress towards achieving the pollutant discharge elimination goal of
the CWA. Moreover, such approaches are favored because they reduce
overall water intake needs.
    The final rule also does not establish an anti-circumvention
provision that would have required permittees to use EPA-approved
analytical methods that are sufficiently sensitive to provide reliable,
quantified results at levels necessary to demonstrate compliance with
the final effluent limitations and standards because another recently
promulgated rule already accomplishes this. As public commenters
pointed out, EPA was conducting a rulemaking on that topic; and, in
August 2014, EPA published a rule requiring the use of sufficiently
sensitive analytical test methods when completing any NPDES permit
application. Moreover, the NPDES permit authority must prescribe that
only sufficiently sensitive methods be used for analyses of pollutants
or pollutant parameters under an NPDES permit where EPA has promulgated
a CWA method for analysis of that pollutant. That rule clarifies that
NPDES applicants and permittees must use EPA-approved analytical
methods that are capable of detecting and measuring the pollutants at,
or below, the applicable water quality criteria or permit limits.

H. Other Revisions

1. Correction of Typographical Error for PSNS
    As EPA proposed to do, the final rule corrects a typographical
error in the previously established PSNS for cooling tower blowdown. As
is clear from the development document for the 1982 rulemaking, as well
as the previously promulgated NSPS for cooling tower blowdown, EPA
inadvertently omitted a footnote in the table that appeared in 40 CFR
423.17(d)(1). The footnote reads ``No detectable amount,'' and it
applies to the effluent standard for 124 of the 126 priority pollutants
contained in chemicals added for cooling tower maintenance. See
``Development Document for Final Effluent Guidelines, New Source
Performance Standards and Pretreatment Standards for the Steam Electric
Power Generating Point Source Category,'' Document No. EPA 440/1-82/
029. November 1982.
2. Clarification of Applicability
    In addition, the final rule contains three minor modifications to
the wording of the applicability provision in the steam electric power
generating ELGs to reflect EPA's longstanding interpretation and
implementation of the rule. These revisions do not alter the universe
of generating units regulated by the ELGs, nor do they impose
compliance costs on the industry. Instead, they remove potential
ambiguity in the regulations by revising the text to more clearly
reflect EPA's longstanding interpretation.
    First, the applicability provision in the previous ELGs stated, in
part, that the ELGs apply to ``an establishment primarily engaged in
the generation of electricity for distribution and sale. . . .'' 40 CFR
423.10. The final rule revises that phrase to read ``an establishment
whose generation of electricity is the predominant source of revenue or
principal reason for operation. . . .'' The final rule thus

clarifies that certain facilities, such as generating units owned and
operated by industrial facilities in other sectors (e.g., petroleum
refineries, pulp and paper mills) that have not traditionally been
regulated by the steam electric ELGs, are not within the scope of the
ELGs. In addition, the final rule clarifies that certain municipally
owned facilities that generate and distribute electricity within a
service area (such as distributing electric power to municipal-owned
buildings), but use accounting practices that are not commonly thought
of as a ``sale,'' are subject to the ELGs. Such facilities have
traditionally been regulated by the steam electric ELGs.
    Second, the final rule clarifies that fuels derived from fossil
fuel are within the scope of the ELGs. The previous ELGs stated, in
part, that they apply to discharges resulting from the generation of
electricity ``which results primarily from a process utilizing fossil-
type fuels (coal, oil, or gas) or nuclear fuel. . . .'' 40 CFR 423.10.
Because a number of fuel types are derived from fossil fuels, and thus
are fossil fuels themselves, the final rule explicitly mentions and
gives examples of such fuels. Thus, the rule reads that the ELGs apply
to discharges resulting from the operation of a generating unit ``whose
generation results primarily from a process utilizing fossil-type fuel
(coal, oil, or gas), fuel derived from fossil fuel (e.g., petroleum
coke, synthesis gas), or nuclear fuel. . . .''
    Third, the final rule clarifies the applicability provision to
reflect the current interpretation that combined cycle systems are
subject to the ELGs. The ELGs apply to electric generation processes
that utilize ``a thermal cycle employing the steam water system as the
thermodynamic medium.'' 40 CFR 423.10. EPA's longstanding
interpretation is that the ELGs apply to discharges from all electric
generation processes with at least one prime mover that utilizes steam
(and that meet the other applicability factors in 40 CFR 423.10).
Combined cycle systems, which are generating units composed of one or
more combustion turbines operating in conjunction with one or more
steam turbines, are subject to the ELGs. The combustion turbines for a
combined cycle system operate in tandem with the steam turbines;
therefore, the ELGs apply to wastewater discharges associated with both
the combustion turbine and steam turbine portions of the combined cycle
system. The final rule, therefore, clarifies that ``[t]his part applies
to discharges associated with both the combustion turbine and steam
turbine portions of a combined cycle generating unit.''

I. Non-Chemical Metal Cleaning Waste

    EPA proposed to establish BAT/NSPS/PSES/PSNS requirements for non-
chemical metal cleaning wastes equal to previously established BPT
limitations for metal cleaning wastes.\39\ EPA based the proposal on
EPA's understanding, from industry survey responses, that most steam
electric power plants manage their chemical and non-chemical metal
cleaning wastes in the same manner. Since then, based in part on public
comments submitted by industry groups, the Agency has learned that
plants refer to the same operation using different terminology; some
classify non-chemical metal cleaning waste as such, while others
classify it as low volume waste sources. Because the survey responses
reflect each plant's individual nomenclature, the survey results for
non-chemical metal cleaning wastes are skewed. Furthermore, EPA does
not know the nomenclature each plant used in responding to the survey,
so it has no way to adjust the results to account for this.
Consequently, EPA does not have sufficient information on the extent to
which discharges of non-chemical metal cleaning wastes occur, or on the
ways that industry manages their non-chemical metal cleaning wastes.
Moreover, EPA also does not have information on potential best
available technologies or best available demonstrated control
technologies, or the potential costs to industry to comply with any new
requirements. Due to incomplete data, some public commenters urged EPA
not to establish BAT limitations for non-chemical metal cleaning wastes
in this final rule. Ultimately, EPA decided that it does not have
enough information on a national basis to establish BAT/NSPS/PSES/PSNS
requirements for non-chemical metal cleaning wastes. The final rule,
therefore, continues to ``reserve'' BAT/NSPS/PSES/PSNS for non-chemical
metal cleaning wastes, as the previously promulgated regulations
did.\40\
---------------------------------------------------------------------------

    \39\ Under the structure of the previously promulgated
regulations, non-chemical metal cleaning wastes are a subset of
metal cleaning wastes.
    \40\ As part of its proposal to establish new BAT/PSES/NSPS/PSNS
requirements for non-chemical metal cleaning waste equal to BPT
limitations for metal cleaning waste, EPA also proposed an exemption
for certain discharges of non-chemical metal cleaning waste, which
would be treated as low volume waste sources. Because the final rule
does not establish these new requirements, EPA also did not finalize
the proposed exemption.
---------------------------------------------------------------------------

    By reserving limitations and standards for non-chemical metal
cleaning waste in the final rule, the permitting authority must
establish such requirements based on BPJ for any steam electric power
plant discharged non-chemical metal cleaning wastes. As part of this
determination, EPA expects that the permitting authority would examine
the historical permitting record for the particular plant to determine
how discharges of non-chemical metal cleaning waste had been permitted
in the past, including whether such discharges had been treated as low
volume waste sources or metal cleaning waste. See Section XVI.

J. Best Management Practices

    EPA proposed to include BMPs in the ELGs that would require plant
operators to conduct periodic inspections of active and inactive
surface impoundments to ensure their structural integrity and to take
corrective actions where warranted. The proposed BMPs were largely
similar to those proposed for the CCR rule, except for the closure
requirements. EPA took comments on whether establishment of BMPs was
more appropriate under the authority of the Resource Conservation and
Recovery Act (RCRA) or the CWA. While some commenters asked EPA to
establish BMPs in the final rule, many others urged EPA not to do so,
arguing that BMPs are better suited for the CCR rule. Because EPA
promulgated BMPs in the CCR rule, to avoid unnecessary duplication,
this rule does not establish BMPs.

IX. Costs and Economic Impact

    EPA evaluated the costs and associated impacts of the ELGs on
existing generating units at steam electric power plants, and on new
sources to which the ELGs may apply in the future. See TDD Section 9.
This section provides an overview of the methodology EPA used to assess
the costs and the economic impacts of the final ELGs and summarizes the
results of these analyses. See the RIA for additional detail.
    EPA used certain indicators to assess the economic achievability of
the ELGs for the steam electric industry as a whole, as required by CWA
section 301(b)(2)(A). These values were compared to a baseline
described elsewhere in this document. For existing sources, EPA
considered the number of generating units and plants expected to close
due to the ELGs, and their generating capacity relative to total
capacity (see Section IX.C.1.b). Although not used as the sole
criterion to determine economic achievability, EPA also analyzed the
ratio of compliance costs to revenue to estimate the number of plants
and their owning

entities that exceed set thresholds indicating potential financial
strain; large numbers of such plants or owning entities could suggest
that the ELGs may not be economically achievable by the industry (see
Section IX.C.1.a). For new sources, EPA considered the magnitude of
compliance costs relative to the costs of constructing and operating
new coal-fired generating units (Section IX.C.2). In addition to the
analyses used to determine economic achievability, EPA conducted other
analyses to characterize the potential broader economic impacts of the
ELGs (e.g., on entities that own steam electric power plants,
electricity rates, employment) and to enable the Agency to meet its
requirements under Executive Orders or other statutes (e.g., Executive
Order 12866, Regulatory Flexibility Act, Unfunded Mandates Reform Act).

A. Plant-Specific and Industry Total Costs

    EPA first estimated plant-specific costs to control discharges at
existing generating units at steam electric power plants to which the
final ELGs apply (existing sources). For all applicable wastestreams,
EPA assessed the operations and treatment system components in place at
a given unit in the baseline (or expected to be in place given other
existing rules), identified equipment and process changes that the
plant would likely make to meet the final ELGs, and estimated the cost
to implement those changes. As explained in Section V, since proposal,
EPA accounted for additional announced unit retirements, conversions,
and relevant operational changes, as well as changes plants are likely
to make in response to the CCR and CPP rules. As a result, the number
of plants projected to incur non-zero compliance costs is about 50
percent less than that estimated at proposal. As appropriate, EPA also
accounted for cost savings associated with these equipment and process
changes (e.g., avoided costs to manage surface impoundments). EPA thus
derived capital and O&M costs at the plant level for control of each
wastestream using the technologies that form the bases for the final
rule for existing sources. See the TDD Section 9 for a more detailed
description of the methodology EPA used to estimate plant-level costs.
    EPA annualized one-time costs and costs recurring on other than an
annual basis over a specific useful life, implementation, and/or event
recurrence period, using a rate of seven percent. For capital costs and
initial one-time costs, EPA used 20 years. For O&M costs incurred at
intervals greater than one year, EPA used the interval as the
annualization period (3 years, 5 years, 6 years, 10 years). EPA added
annualized capital, initial one-time costs, and the non-annual portion
of O&M costs to annual O&M costs to derive total annualized plant
costs.
    EPA calculated total industry costs by applying survey weights to
the plant-specific annualized costs and summing them. For the
assessment of industry costs, EPA considered costs on both a pre-tax
and after-tax basis. Pre-tax annualized costs provide insight on the
total expenditure as incurred, while after-tax annualized costs are a
more meaningful measure of impact on privately owned for-profit plants,
and incorporate approximate capital depreciation and other relevant tax
treatments in the analysis. EPA uses pre- and/or after-tax costs in
different analyses, depending on the concept appropriate to each
analysis (e.g., social costs discussed in Section IX.B are calculated
using pre-tax costs whereas cost-to-revenue screening-level analyses
discussed in Section IX.C are conducted using after-tax costs). See
Table IX-1 for estimates of pre- and post-tax industry costs.

               Table IX-1--Total Annualized Industry Costs
                 [In millions, 2013$], 7% Discount Rate
------------------------------------------------------------------------
                                     Pre-tax              After-tax
------------------------------------------------------------------------
Total Annualized Industry                  $496.2                $339.6
 Costs......................
------------------------------------------------------------------------

B. Social Costs

    Social costs are the costs of the rule from the viewpoint of
society as a whole, rather than regulated facilities only. In
calculating social costs, EPA tabulated the pre-tax costs in the year
when they are estimated to be incurred. EPA assumed that all plants
upgrading their systems in order to meet the effluent limitations and
standards would do so sometime over a five-year period, during the
implementation period for this rule. Given the implementation dates in
this rule, and the fact that permitting authorities have to incorporate
the final effluent limitations into NPDES permits (which have five-year
terms) before they become applicable, this assumption is a reasonable
estimate.
    EPA performed the social cost analysis over a 24-year analysis
period, which combines the length of the period during which plants are
anticipated to install the control technologies and the useful life of
the longest-lived technology installed at any facility (20 years). EPA
calculated social cost of the final rule for existing generating units
at steam electric power plants using both a three percent discount rate
and an alternative discount rate of seven percent.\41\
---------------------------------------------------------------------------

    \41\ These discount rate values follow guidance from the Office
of Management and Budget (OMB) regulatory analysis guidance
document, Circular A-4 (OMB, 2003).
---------------------------------------------------------------------------

    Social costs include costs incurred by both private entities and
the government (e.g., in implementing the regulation). As described in
Section XVII.B, EPA estimates that the final rule will not lead to
additional costs to permitting authorities. Consequently, the only
category of costs necessary to calculate social costs are those
estimated for steam electric power plants.
    Table IX-2 presents the total annualized social cost of the final
ELGs on existing generating units at seam electric power plants,
calculated using three percent and seven percent discount rates.

                Table IX-2--Total Annualized Social Costs
                          [In millions, 2013$]
------------------------------------------------------------------------
                                3% Discount rate      7% Discount rate
------------------------------------------------------------------------
Total Annualized Social                    $479.5                $471.2
 Costs......................
------------------------------------------------------------------------

    The value presented in Table IX-2 for the seven percent discount
rate is slightly lower than the comparable industry costs (pre-tax) in
Table IX-1 (e.g., $471.2 million versus $496.2 million) due to the
inclusion of the timing of expenditures in the annualized social costs
calculations.

C. Economic Impacts

    EPA assessed the economic impacts of this rule in two ways: (1) A
screening-level assessment of the cost impacts on existing generating
units at steam electric power plants units and the entities that own
those plants, based on comparison of costs to revenue; and (2) an
assessment of the impact of this rule within the context of the broader
electricity market, which includes an assessment of incremental plant
closures attributable to this rule.
    The following sections summarize the findings for these analyses.
The RIA discusses the methods and results in greater detail.
1. Summary of Economic Impacts for Existing Sources
    The first set of cost and economic impact analyses--including
entity-level impacts at both the steam electric power plant and parent
company levels--reflects baseline operating characteristics of steam
electric power plants incurring costs and assumes no changes in those
baseline operating characteristics (e.g., level of electricity
generation and revenue) as a result of the final rule. They provide
screening-level indicators of the relative cost of the ELGs to plants,
owning entities, or consumers.
    The second set of analyses look at broader electricity market
impacts taking into account the interconnection of regional and
national electricity markets. It also looks at the distribution of
impacts at the plant level. This second set of analyses provides
insight on the impacts of the final rule on steam electric power
plants, as well as the electricity market as a whole, including
generation capacity closure and changes in generation and wholesale
electricity prices.
    As noted in the introduction to this section, EPA used results from
the screening analysis of plant- and entity-level impacts, together
with projected capacity closure from the market model, to determine
that the final rule is economically achievable.
a. Screening-Level Assessment of Impacts on Existing Units at Steam
Electric Power Plants and Parent Entities
    EPA conducted a screening-level analysis of the rule's potential
impact to existing generating units at steam electric power plants and
parent entities based on cost-to-revenue ratios. For each of the two
levels of analysis (plant and parent entity), the Agency assumed, for
analytic convenience and as a worst-case scenario, that none of the
costs would be passed on to consumers through electricity rate
increases and would instead be absorbed by the steam electric power
plants and their parent entities. This assumption overstates the
impacts of the final rule since steam electric power plants that
operate in a regulated market may be able to recover some of the
increased production costs to consumers through increased electricity
prices. It is, however, an appropriate assumption for a screening-
level, upper-bound estimate of the potential cost impacts.
    Plant-Level Cost-to-Revenue Analysis. EPA developed revenue
estimates for this analysis using EIA data. EPA then calculated the
annualized after-tax costs of the final rule as a percent of baseline
annual revenues. See Chapter 4 of the RIA report for a more detailed
discussion of the methodology used for the plant-level cost-to-revenue
analysis.
    Table IX-3 summarizes the plant-level cost-to-revenue analysis
results for the final rule. The cost-to-revenue ratios provide
screening-level indicators of potential economic impacts. Plants
incurring costs below one percent of revenue are unlikely to face
economic impacts, while plants with costs between one percent and three
percent of revenue have a higher chance of facing economic impacts, and
plants incurring costs above three percent of revenue have a still
higher probability of economic impacts. EPA estimates that the vast
majority of steam electric power plants (1,034 plants or 96 percent of
the universe) to which the final rule apply will incur annualized costs
amounting to less than one percent of revenue. In fact, most of these
plants will incur no cost at all. Only four percent of plants have
costs between one percent and three percent of revenue (38 plants), and
less than one percent of plants have costs above three percent of
revenue (8 plants). The small fractions of steam electric power plants
with costs to revenue ratios exceeding the one percent and three
percent thresholds suggest that the final limitations and standards are
economically achievable for the industry as a whole.

                           Table IX-3--Plant-Level Cost-to-Revenue Analysis Results a
----------------------------------------------------------------------------------------------------------------
            Number and fraction of existing steam electric power plants with cost-to-revenue ratio of
-----------------------------------------------------------------------------------------------------------------
                                                 0%               0-1%              1-3%               >3%
                                         -----------------------------------------------------------------------
                                             #        %        #        %        #        %        #        %
----------------------------------------------------------------------------------------------------------------
Count or Percent of Plants..............     946       88       88        8       38        4        8        1
----------------------------------------------------------------------------------------------------------------
\a\ This analysis makes a counterfactual, conservative assumption of zero cost pass through. Plant counts are
  weighted estimates.

    Parent Entity-Level Cost-to-Revenue Analysis. EPA also assessed the
economic impact of the final rule at the parent entity level. The
screening-level cost-to-revenue analysis at the parent entity level
provides insight on the impact of the final rule on those entities that
own existing generating units at steam electric power plants. In this
analysis, the domestic parent entity associated with any given plant is

defined as that entity with the largest ownership share in the plant.
    For each parent entity, EPA compared the total annualized after-tax
costs and the total revenue for the entity (see Chapter 4 of the RIA
report for details). EPA considered two approximate bounding cases to
analyze costs and revenue for the owners of all existing units at steam
electric power plants, based on the weights developed from the industry
survey. These cases, which are described in more detail in Chapter 4 of
the RIA, provide a range of estimates for the number of entities
incurring costs and the costs incurred by any entity owning an existing
generating unit at a steam electric power plant.
    Table IX-4 summarizes the results of the entity-level analysis of
the final rule for the two analytic cases.

               Table IX-4--Parent Entity-Level After-Tax Annual Costs as a Percentage of Revenue a
----------------------------------------------------------------------------------------------------------------
                                   Not analyzed      Number and percentage with after tax annual costs/annual
                                  due to lack of                            revenue of:
                                      revenue    ---------------------------------------------------------------
    Total number of entities        information         0%             0-1%            1-3%        3% or greater
                                 -------------------------------------------------------------------------------
                                     #       %       #       %       #       %       #       %       #       %
----------------------------------------------------------------------------------------------------------------
Case 1: Lower-bound estimate of number of entities owning steam electric power plants (which also provides an
 upper-bound estimate of total costs that an entity may incur)
----------------------------------------------------------------------------------------------------------------
243.............................     14       6     166      68      53      22       8       3       2       1
----------------------------------------------------------------------------------------------------------------
Case 2: Upper-bound estimate of number of entities owning steam electric power plants (which also provides a
 lower-bound estimate of total costs that an entity may incur)
----------------------------------------------------------------------------------------------------------------
507.............................     30       6     414      82      53      10       8       2       2      <1
----------------------------------------------------------------------------------------------------------------
# equals the number of entities.
\a\ This analysis makes a counterfactual, conservative assumption of zero cost pass-through.

    Similar to the plant-level analysis above, cost-to-revenue ratios
provide screening-level indicators of potential economic impacts, this
time to the owning entities; higher ratios suggest a higher probability
of economic impacts. As presented in Table IX-4, EPA estimated that the
number of entities owning existing generating units at steam electric
power plants ranges from 243 (lower-bound estimate) to 507 (upper-bound
estimate), depending on the assumed ownership structure of plants not
surveyed. EPA estimates that 90 percent to 92 percent of parent
entities will either incur no costs or the annualized cost they incur
to meet the final limitations and standards will represent less than
one percent of their revenues, under the lower- and upper-bound cases,
respectively.
    Overall, this screening-level analysis shows that the entity-level
costs are low in comparison to the entity-level revenues; very few
entities are likely to face economic impacts at any level. This finding
supports EPA's determination that the final rule is economically
achievable by the steam electric power generation industry as a whole.
b. Assessment of Impacts in the Context of the Electricity Market
    In analyzing the impacts of regulatory actions affecting the
electric power sector, EPA has used IPM, a comprehensive electricity
market optimization model that can evaluate such impacts within the
context of regional and national electricity markets. The model is
designed to evaluate the effects of changes in generating unit-level
electric generation costs on the total cost of electricity supply,
subject to specified demand and emissions constraints.
    Use of a comprehensive, market analysis system is important in
assessing the potential impact of the regulation because of the
interdependence of electric generating units in supplying power to the
electric transmission grid. Increases in electricity production costs
at some generating units can have a range of broader market impacts
affecting other generating units, including the likelihood that various
units are dispatched, on average. The analysis also provides important
insight on steam electric capacity closures (e.g., retirements of
generating units that become uneconomical relative to other generating
units), based on a more detailed analysis of market factors than in the
screening-level analyses above, and it further informs EPA's
determination of whether the final ELGs are economically achievable by
the industry as a whole.
    EPA used version 5.13 of IPM to analyze the impacts of the final
rule. IPM V5.13 is based on an inventory of U.S. utility- and non-
utility-owned boilers and generators that provide power to the
integrated electric transmission grid, including plants to which the
ELGs apply. IPM V5.13 embeds a baseline energy demand forecast that is
derived from DOE's ``Annual Energy Outlook 2013'' (AEO 2013). IPM V5.13
also incorporates in its analytic baseline the expected compliance
response to existing regulatory requirements for air regulations
affecting the power sector.\42\ In addition, the Base Case for IPM
analyses of the final ELGs accounts for the effects of the final CWIS
rule and CCR rule, as well as the CPP rule.\43\ As explained in Section
V, because of the short time between finalizing the CPP rule and this
final rule, EPA's IPM analysis for this final rule incorporates the
proposed CPP rule in the baseline. EPA concludes the proposed and final
CPP specifications are similar enough that using the proposed rather
than the final CPP will not bias the results of the

analysis for this rule. This conclusion is based on a careful
evaluation of whether the population of steam electricity generating
units that would incur costs under the ELGs in the final CPP differs
meaningfully from the proposed CPP baseline. The analyses led us to
conclude that using the proposed CPP baseline in lieu of the final CPP
baseline is acceptable because (1) the number of steam electric
generating units that would incur costs under the ELGs is very similar
on either baseline, and (2) where the populations differ, the net
number of steam electric generating units that are in one baseline and
not the other is small relative to the total population of steam
electric generating units that would incur costs under the ELGs in
either baseline. See the RIA for additional details.
---------------------------------------------------------------------------

    \42\ The Base Case includes the following regulations: Clean Air
Interstate Rule (CAIR); Mercury and Air Toxics Standards (MATS)
rule; regulatory SO2 emission rates arising from State
Implementation Plans (SIP); Acid Rain Program established under
Title IV of the Clean Air Act Amendments; NOX SIP Call
trading program for Rhode Island; Clean Air Act Reasonable Available
Control Technology requirements and Title IV unit specific rate
limits for NOX; the Regional Greenhouse Gas Initiative;
Renewable Portfolio Standards; New Source Review Settlements; and
several state-level regulations affecting emissions of
SO2, NOX, and mercury that are already in
place or expected to come into force by 2017.
    \43\ EPA typically includes only final rules in its base case
for its IPM analyses. However, at the time EPA performed the IPM
analyses for this rule, it did not have details of the final CPP
rule. EPA therefore used information from the proposed CPP rule as a
proxy for purposes of the ELG analyses.
---------------------------------------------------------------------------

    In contrast to the screening-level analyses, which are static
analyses and do not account for interdependence of electric generating
units in supplying power to the electric transmission grid, IPM
accounts for potential changes in the generation profile of steam
electric and other units and consequent changes in market-level
generation costs, as the electric power market responds to higher
generation costs for steam electric units due to the ELGs.
Additionally, in contrast to the screening-level analyses in which EPA
assumed no cost pass through of the final rule costs, IPM depicts
production activity in wholesale electricity markets where some
recovery of compliance costs through increased electricity prices is
possible but not guaranteed.
    In analyzing the final ELGs, EPA specified additional fixed and
variable costs that are expected to be incurred by specific steam
electric power plants and generating units to comply with the ELGs (the
costs discussed in Section IX.A). EPA then ran IPM including these
additional costs to determine the dispatch of electric generating units
that would meet projected demand at the lowest costs, subject to the
same constraints as those present in the analysis baseline. The
estimated changes in plant-specific and unit-specific production levels
and costs--and, in turn, changes in total electric power sector costs
and production profile--are key data elements in evaluating the
expected national and regional effects of the ELGs, including closures
of steam electric generating units.
    EPA considered impact metrics of interest at three levels of
aggregation: (1) Impact on national and regional electricity markets
(all electric power generation, including steam and non-steam electric
power plants), (2) impact on steam electric power plants as a group,
and (3) impact on individual steam electric power plants incurring
costs. Chapter 5 of the RIA discusses the first analysis. The sections
below summarize the two analyses focusing on steam electric power
plants, which are further described in Chapter 5 of the RIA.
    All results presented below are representative of modeled market
conditions in the years 2028-2033, by which time all plants will meet
the effluent limitations and standards. Costs are reflective of costs
in the modeled years.\44\
---------------------------------------------------------------------------

    \44\ In contrast, the social costs estimated in Section IX.B
reflect the discounted value of compliance costs over the entire 24-
year period of analysis, as of 2015.
---------------------------------------------------------------------------

    Impact on Existing Steam Electric Power Plants. EPA used IPM V5.13
results for 2030 to assess the potential impact of the final rule on
existing generating units at steam electric power plants. The purpose
of this analysis is to assess impacts on existing generating units at
steam electric power plants specifically. EPA used this information in
determining whether the ELGs are economically achievable by the steam
electric power generating industry as a whole.
    Table IX-5 reports results for existing generating units at steam
electric power plants, as a group. EPA looked at the following metrics:
(1) Incremental early retirements and capacity closures, calculated as
the difference between capacity under the ELGs and capacity under the
baseline, which includes both full plant closures and partial plant
closures (unit closures) in aggregate capacity terms; (2) incremental
capacity closures as a percentage of baseline capacity; (3) post-
compliance change in electricity generation; (4) post-compliance
changes in variable production costs per MWh, calculated as the sum of
total fuel and variable O&M costs divided by net generation; and (5)
changes in annual costs (fuel, variable O&M, fixed O&M, and capital).
Items (1) and (2) provide important insight for determining the
economic achievability of the ELGs.

                               Table IX-5--Impact of Final ELGs on Steam Electric Power Plants as a Group at the Year 2030
--------------------------------------------------------------------------------------------------------------------------------------------------------

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                  Incremental early retirements
                                                          closures \a\

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

                                             Change in

                                                                                Change in total
                                              variable
                                             Change in
              Region                 Baseline                              % of         generation
                                          production cost
                                            annual costs
                                     capacity                 Capacity baseline        (GWh or % of
                                          (2013$/MWh or %
                                           (million 2013$
                                         (MW)             (MW)         capacity          baseline)
                                            of baseline)
                                         or % of baseline)

--------------------------------------------------------------------------------------------------------------------------------------------------------
Total U.S.........................    359,982              843             0.2%      -3,179       -0.2%       $0.10        0.3%        $496        0.6%
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values for incremental early retirements or closures represent change relative to the baseline run. IPM may show partial (unit) or full plant early
  retirements (closures). It may also show avoided closures (negative closure values) in which a unit or plant that is projected to close in the
  baseline is estimated to continue operating in the post-compliance case. Avoided closures may occur among plants that incur no compliance costs or for
  which compliance costs are low relative to other steam electric power plants.

    Under the final rule, variable production costs at steam electric
power plants increase by approximately 0.3 percent at the national
level. The resulting net change in total capacity for steam electric
power plants is very small. For the group of steam electric power
plants, total capacity decreases by 843 MW or approximately 0.2 percent
of the 359,982 MW baseline capacity, corresponding to a net closure of
two units, or when aggregating to the level of steam electric
generating plants, one net plant closure.
    The change in total generation is an indicator of how steam
electric power plants fare, relative to the rest of the electricity
market. While at the market level there is essentially no projected
change in total electricity generation,\45\

for steam electric power plants, total available capacity and
electricity generation at the national level are projected to fall by
approximately 0.2 percent.
---------------------------------------------------------------------------

    \45\ As discussed in the RIA, at the national level, the demand
for electricity does not change between the baseline and the
analyzed regulatory options (generation within the regions is
allowed to vary) because meeting demand is an exogenous constraint
imposed by the model.
---------------------------------------------------------------------------

    These findings of very small national effects (and similarly very
small regional effects, as described in Chapter 5 of the RIA) in these
impact metrics support EPA's conclusion that the final rule will have
little economic consequence for the steam electric power generating
industry and the electricity market and is, therefore, economically
achievable.
    Impact on Individual Steam Electric Power Plants Incurring Costs
under this Rulemaking. To assess potential plant-level effects, EPA
also analyzed plant-specific changes between the base case and the
post-compliance cases for the following metrics: (1) Capacity
utilization (defined as annual generation (in MWh) divided by [capacity
(MW) times 8,760 hours]) (2) electricity generation, and (3) variable
production costs per MWh, defined as variable O&M cost plus fuel cost
divided by net generation.
    The analysis of changes in individual plants as a result of the
final rule is detailed in Chapter 5 of the RIA. The results indicate
that steam electric plants experience only slight effects--no change,
or less than a one percent reduction or one percent increase. See Table
5-4 in the RIA. Only 17 plants see their capacity utilization reduced
by more than one percent, while 25 plants increase their capacity
utilization by more than one percent. The estimated change in variable
production costs is higher; 43 plants have an increase in variable
production costs exceeding one percent; for seven of these plants, this
increase exceeds three percent, but again the vast majority of plants
experience a less than one percent increase in variable production
costs. Results for the subset of plants incurring costs further support
the conclusion that the effects of the final rule on the steam electric
industry will be small.
2. Summary of Economic Impacts for New Sources
    EPA also evaluated the expected costs of meeting the final
standards for new sources. The incremental cost associated with
complying with the final NSPS and PSNS varies depending on the types of
processes, wastestreams, and waste management systems that the plant
would have installed in the absence of the new source requirements. EPA
estimated capital and O&M costs for several scenarios that represent
the different types of operations present at existing steam electric
power plants or typically included at new steam electric power plants.
These scenarios capture differences in the plant status (building a
generating unit at a new location versus adding a new generating unit
at an existing power plant), presence of on-site impoundments or
landfills, type of ash handling, type of FGD systems in service, and
type of leachate collection and handling.
    EPA assessed the possible impact of this final rule on new units by
comparing the incremental costs for new units to the overall cost of
building and operating new scrubbed coal units, on an annualized basis.
    EPA estimated costs of a new coal unit using the overnight \46\
capital and O&M costs of building and operating a new scrubbed coal
unit from the EIA's Annual Energy Outlook 2014. For purposes of this
analysis, EPA assumed a new dual-unit plant with a total generation
capacity of 1,300 MW. Table IX-6 shows capital and O&M costs of
building and operating a new coal unit and contrasts these costs with
the incremental costs associated with the final NSPS/PSNS.
---------------------------------------------------------------------------

    \46\ As defined by the EIA, ``overnight cost'' is an estimate of
the cost at which a plant could be constructed assuming that the
entire process from planning through completion could be
accomplished in a single day. This concept is useful to avoid any
impact of project delays and of financing issues and assumptions on
estimated costs.

    Table IX-6--Comparison of Incremental Compliance Costs With Costs for New Coal-Fired Steam Electric Units
----------------------------------------------------------------------------------------------------------------
                                                              Costs of  new      Incremental
                      Cost component                         coal generation  compliance costs      % of new
                                                             ($2013/MW) \a\     ($2013/MW) \b\   generation cost
----------------------------------------------------------------------------------------------------------------
Capital...................................................        $3,058,861    $8,328-$87,085           0.3-2.8
Annual Non-Fuel O&M.......................................            69,630         620-8,828           0.3-3.9
Annual Fuel \c\...........................................           157,737
                                                           -----------------------------------------------------
    Total Annualized Costs................................           497,213      1,354-16,511           0.3-3.3
----------------------------------------------------------------------------------------------------------------
\a\ Source: New unit total cost value from Table 8.2 EIA NEMS Electricity Market Module. AEO 2014 Documentation.
  Available at http://www.eia.gov/forecasts/aeo/assumptions/pdf/electricity.pdf. Capital costs are based on the
  total overnight costs for new scrubbed coal dual-unit plant, 1,300 MW capacity, coming online in 2017. EPA
  restated costs in 2013 dollars using the construction cost index. Total annual O&M costs assume 90% capacity
  utilization.
\b\ Incremental costs for new 1300 MW unit for Option F. Range represents the costs for a new unit at a newly
  constructed plant (lower bound) and new unit at an existing plant, with evaporation technology (upper bound).
\c\ Fuel costs estimated assuming heat rate of 8,800 Btu/kWh (AEO 2014) and coal price delivered to the power
  sector of 2.27 $/Mbtu (AEO 2015, projected costs in 2017 in 2013$).

    The comparison suggests that costs associated with meeting the
final NSPS/PSNS represent a relatively small fraction of overnight
capital costs of a new unit (less than one percent) and a similarly
small fraction of non-fuel O&M and fuel costs (less than one percent).
On an annualized basis, costs for meeting standards specified in the
final rule are 0.3 to 3.3 percent of annualized costs for new coal
generating capacity. Based on this assessment, EPA concludes that the
final rule does not present a barrier to entry.

X. Pollutant Reductions

    EPA took a similar approach to the one described above for plant-
specific costs in estimating pollutant reductions associated with the
final rule. For each wastestream \47\ and each POC, EPA first
estimated--on an annual, per plant basis--plant-specific baseline
pollutant

loadings taking into account components in place at the plant (or
expected to be in place given other existing rules \48\) and, where
appropriate, pollutant removals at the POTW, since these removals
result in reduced discharges to receiving waters. EPA similarly
estimated plant-specific post-compliance pollutant loadings using the
mean concentrations associated with the final limitations and
standards. In cases where a plant had already implemented approaches
that would allow them to comply with the final rule, the baseline and
post-compliance pollutant loadings are equivalent. EPA then calculated
the pollutant reduction as the difference between the estimated
baseline and post-compliance discharge loadings. For each wastestream,
EPA then calculated total industry pollutant reductions by applying
survey weights to the plant-specific pollutant reductions and summing
them.
---------------------------------------------------------------------------

    \47\ EPA estimated pollutant reductions for wastestreams with
numeric and zero pollutant discharge limitations and standards. The
reductions reflect a reduction in the mass of pollutant discharged.
    \48\ As explained elsewhere in this preamble, for this final
rule, EPA adjusted its estimates to, among other things, account for
known generating unit closures and conversions and known operating
changes, including those associated with the CCR rule, expected to
occur prior to the time in which the limitations and standards in
this rule would apply. As such, baseline loadings in this final rule
reflect closures, conversions, and operational changes that will
take place prior to implementation of the rule in NPDES permits,
rather than the industry survey baseline year of 2009 used in the
proposed rule.
---------------------------------------------------------------------------

    While plants are not required to implement the specific
technologies that form the bases for the final limitations and
standards, EPA calculated the pollutant loadings for plants that
implement these technologies to estimate the pollutant reductions
associated with the rule. See TDD Section 10 for a detailed discussion
of EPA's pollutant loadings and reductions methodologies.
    Table X-1 presents estimated industry-level pollutant reductions
for the final rule.

                            Table X-1--Total Annualized Pollutant Loading Reductions
----------------------------------------------------------------------------------------------------------------
                                                                   Pollutant reductions  (pounds per year)
                                                           -----------------------------------------------------
                     Analysis baseline                        Conventional       Priority       Nonconventional
                                                             pollutants \a\     pollutants      pollutants \b\
----------------------------------------------------------------------------------------------------------------
Final Rule................................................      13,400,000          410,000         371,000,000
----------------------------------------------------------------------------------------------------------------
\a\ The loadings reduction for conventional pollutants includes BOD and TSS.
\b\ The loadings reduction for nonconventional pollutants excludes TDS and COD to avoid double counting removals
  for certain pollutants that would also be measured by these bulk parameters (e.g., sodium, magnesium).

XI. Development of Effluent Limitations and Standards

    The final rule establishes a zero discharge limitation and standard
applicable to all pollutants in fly ash transport water, bottom ash
transport water, and FGMC wastewater; therefore, no effluent
concentration data were used to set the limitations and standards for
these wastestreams. The final rule contains new numeric effluent
limitations and standards that apply to discharges of FGD wastewater
and gasification wastewater at new and existing sources, and to
discharges of combustion residual leachate at new sources.\49\
---------------------------------------------------------------------------

    \49\ Effluent limitations and standards based on the previously
established BPT limitations on TSS are not discussed in this
section.
---------------------------------------------------------------------------

    EPA developed the new numeric effluent limitations and standards in
this final rule using long-term average effluent values and variability
factors that account for variation in performance at well-operated
facilities that employ the technologies that constitute the bases for
control. EPA's methodology for derivation of limitations in ELGs is
longstanding and has been upheld in court. See, e.g., Chem. Mfrs. Ass'n
v. EPA, 870 F.2d 177 (5th Cir. 1989); Nat'l Wildlife Fed'n v. EPA, 286
F.3d 554 (D.C. Cir. 2002). EPA establishes the final effluent
limitations and standards as ``daily maximums'' and ``maximums for
monthly averages.'' Definitions provided in 40 CFR 122.2 state that the
daily maximum limitation is the ``highest allowable `daily discharge'
'' and the maximum for monthly average limitation is the ``highest
allowable average of `daily discharges' over a calendar month,
calculated as the sum of all `daily discharges' measured during a
calendar month divided by the number of `daily discharges' measured
during that month.'' Daily discharges are defined to be the ``
`discharge of a pollutant' measured during a calendar day or any 24-
hour period that reasonably represents the calendar day for purposes of
sampling.''
    EPA's objective in establishing daily maximum limitations is to
restrict the discharges on a daily basis at a level that is achievable
for a plant that targets its treatment at the long-term average. EPA
acknowledges that variability around the long-term average occurs
during normal operations. This variability means that plants
occasionally may discharge at a level that is higher (or lower) than
the long-term average. To allow for these possibly higher daily
discharges and provide an upper bound for the allowable concentration
of pollutants that may be discharged, while still targeting achievement
of the long-term average, EPA has established the daily maximum
limitation. A plant that consistently discharges at a level near the
daily maximum limitation would not be operating its treatment to
achieve the long-term average. Targeting treatment to achieve the daily
limitation, rather than the long-term average, may result in values
that frequently exceed the limitations due to routine variability in
treated effluent.
    EPA's objective in establishing monthly average limitations is to
provide an additional restriction to help ensure that plants target
their average discharges to achieve the long-term average. The monthly
average limitation requires dischargers to provide ongoing control, on
a monthly basis, that supplements controls imposed by the daily maximum
limitation. In order to meet the monthly average limitation, a plant
must counterbalance a value near the daily maximum limitation with one
or more values well below the daily maximum limitation.
    The TDD provides a detailed description of the data and methodology
used to develop long-term averages, variability factors, and
limitations and standards for the final rule. As a result of public
comments, EPA expanded the data set used to calculate the BAT/PSES
effluent limitations and standards for discharges of FGD wastewater
from existing sources. Largely, this expanded data set includes
additional self-monitoring data from plants operating

the selected technology basis. EPA also expanded the data set by
including treatment performance data from another plant that, upon
review of comments, EPA determined would be appropriate to use to
calculate the effluent limitations in this rule. The combination of EPA
sampling data (both EPA-collected and CWA section 308 samples collected
by plants for analysis by EPA) and plant self-monitoring data results
in data sets characterizing the treatment system performance over
several years at each of the plants used to develop effluent
limitations and standards for FGD wastewater.
    EPA identified certain data that warranted exclusion from the
calculations of the limitations and standards because: (1) The samples
were analyzed using an analytical method that is not approved in 40 CFR
part 136 for NPDES permit purposes; (2) the samples were analyzed using
an insufficiently sensitive analytical method (e.g., use of EPA Method
245.1 to measure the concentration of mercury in effluent samples); (3)
the samples were analyzed in a manner which resulted in an unacceptable
level of analytical interferences; (4) the samples were collected
during the initial commissioning period for the wastewater treatment
system or the plant decommissioning period and do not represent BAT/
NSPS level of performance; (5) the analytical results were identified
as questionable due to quality control issues, abnormal conditions or
treatment system upsets, or were analytical anomalies; (6) the samples
were collected from a location that is not representative of treated
effluent; or (7) the treatment system was operating in a manner that
does not represent BAT/NSPS level of performance. The results of EPA's
evaluation of the data and reasons for any data exclusions are
summarized in DCN SE05733.
    Tables XI-1 and XI-2 present the effluent limitations and standards
for FGD wastewater, gasification wastewater, and combustion residual
leachate. For comparison, the tables also present the long-term average
treatment performance calculated for these wastestreams. Due to routine
variability in treated effluent, a power plant that targets discharging
its wastewater at a level near the values of the daily maximum
limitation or the monthly average limitation may experience frequent
values exceeding the limitations. For this reason, EPA recommends that
plants design and operate the treatment system to achieve the long-term
average for the model technology. In doing so, a system that is
designed to represent the BAT/NSPS level of control would be expected
to meet the limitations.
    EPA expects that plants will be able to meet their effluent
limitations or standards at all times. If an exceedance is caused by an
upset condition, the plant would have an affirmative defense to an
enforcement action if the requirements of 40 CFR 122.41(n) are met.
Exceedances caused by a design or operational deficiency, however, are
indications that the plant's performance does not represent the
appropriate level of control. For these final limitations and
standards, EPA determined that such exceedances can be controlled by
diligent process and wastewater treatment system operational practices,
such as regular monitoring of influent and effluent wastewater
characteristics and adjusting dosage rates for chemical additives to
target effluent performance for regulated pollutants at the long-term
average concentration for the BAT/NSPS technology. Additionally, some
plants may need to upgrade or replace existing treatment systems to
ensure that the treatment system is designed to achieve performance
that targets the effluent concentrations at the long-term average. This
is consistent with EPA's costing approach and its engineering judgment
developed over years of evaluating wastewater treatment processes for
steam electric power plants and other industrial sectors. EPA
recognizes that, as a result of the final rule, some dischargers,
including those that are operating technologies representing the
technology bases for the final rule, may need to improve their
treatment systems, process controls, and/or treatment system operations
in order to consistently meet the effluent limitations and standards.
This is consistent with the CWA, which requires that discharge
limitations and standards reflect the best available technology
economically achievable or the best available demonstrated control
technology.
    See DCN SE05733 for details of the calculation of the limitations
and standards presented in the tables below.

    Table XI-1--Long-Term Averages and Effluent Limitations and Standards for FGD Wastewater and Gasification
                                         Wastewater for Existing Sources
----------------------------------------------------------------------------------------------------------------
                                                                                Daily       Monthly
                Wastestream                           Pollutant             Long-term     maximum      average
                                                                             average     limitation   limitation
----------------------------------------------------------------------------------------------------------------
FGD Wastewater (BAT & PSES)...............  Arsenic ([micro]g/L).........         5.98           11            8
                                            Mercury (ng/L)...............          159          788          356
                                            Nitrate/nitrite as N (mg/L)..          1.3         17.0          4.4
                                            Selenium ([micro]g/L)........          7.5           23           12
Voluntary Incentives Program for FGD        Arsenic ([micro]g/L).........      \a\ 4.0        \b\ 4        (\c\)
 Wastewater (BAT only).                     Mercury (ng/L)...............         17.8           39           24
                                            Selenium ([micro]g/L)........      \a\ 5.0        \b\ 5        (\c\)
                                            TDS (mg/L)...................         14.9           50           24
Gasification Wastewater (BAT & PSES)......  Arsenic ([micro]g/L).........      \a\ 4.0        \b\ 4        (\c\)
                                            Mercury (ng/L)...............         1.08          1.8          1.3
                                            Selenium ([micro]g/L)........          147          453          227
                                            TDS (mg/L)...................         15.2           38           22
----------------------------------------------------------------------------------------------------------------
\a\ Long-term average is the arithmetic mean of the quantitation limits since all observations were not
  detected.
\b\ Limitation is set equal to the quantitation limit.
\c\ Monthly average limitation is not established when the daily maximum limitation is based on the quantitation
  limit.

    Table XI-2--Long-Term Averages and Standards for FGD Wastewater, Gasification Wastewater, and Combustion
                                        Residual Leachate for New Sources
----------------------------------------------------------------------------------------------------------------
                                                                                Daily       Monthly
                Wastestream                           Pollutant             Long-term     maximum      average
                                                                             average     limitation   limitation
----------------------------------------------------------------------------------------------------------------
FGD Wastewater (NSPS & PSNS)..............  Arsenic ([micro]g/L).........      \a\ 4.0        \b\ 4        (\c\)
                                            Mercury (ng/L)...............         17.8           39           24
                                            Selenium ([micro]g/L)........      \a\ 5.0        \b\ 5        (\c\)
                                            TDS (mg/L)...................         14.9           50           24
Gasification Wastewater (NSPS & PSNS).....  Arsenic ([micro]g/L).........      \a\ 4.0        \b\ 4        (\c\)
                                            Mercury (ng/L)...............         1.08          1.8          1.3
                                            Selenium ([micro]g/L)........          147          453          227
                                            TDS (mg/L)...................         15.2           38           22
Combustion Residual Leachate (NSPS & PSNS)  Arsenic ([micro]g/L) \d\.....         5.98           11            8
                                            Mercury (ng/L) \d\...........          159          788          356
----------------------------------------------------------------------------------------------------------------
\a\ Long-term average is the arithmetic mean of the quantitation limits since all observations were not
  detected.
\b\ Limitation is set equal to the quantitation limit.
\c\ Monthly average limitation is not established when the daily maximum limitation is based on the quantitation
  limit.
\d\ Long-term average and standards were transferred from performance of chemical precipitation in treating FGD
  wastewater.

XII. Non-Water Quality Environmental Impacts

    The elimination or reduction of one form of pollution can create or
aggravate other environmental problems. Therefore, CWA sections 304(b)
and 306 require EPA to consider non-water quality environmental impacts
(including energy requirements) associated with ELGs. Accordingly, EPA
considered the potential impact of this rule on energy consumption, air
emissions, and solid waste generation.\50\ In addition, EPA evaluated
the effects associated with water withdrawal. For information on the
methodologies EPA used to estimate the non-water quality environmental
impacts, see TDD Section 12.
---------------------------------------------------------------------------

    \50\ Because EPA does not project any new coal or oil-fired
generating units, the results presented in this section reflect
existing generating units. Because EPA expects non-water quality
environmental impacts for new generating units to be similar to or
the same as existing generating units, EPA determined that in the
event a new generating unit is built, the non-water quality
environmental impacts associated with NSPS/PSNS would be acceptable.
For EPA's analysis of non-water quality impacts for existing
generating units for Option F, see Section 12 of the TDD.
---------------------------------------------------------------------------

    Table XII-1 presents the net increases in energy requirements for
the final rule. EPA estimates that energy increases associated with
this rule are less than 0.01 percent of the total electricity generated
by all electric power plants and the fuel consumption increase is 0.002
percent of total fuel consumption by all motor vehicles in the U.S.

   Table XII-1--Industry-Level Energy Requirements for the Final Rule
------------------------------------------------------------------------
                                                                  Final
            Non-water quality environmental impact                rule
------------------------------------------------------------------------
Electrical Energy Usage (MWh).................................   237,000
Fuel (GPY)....................................................   556,000
------------------------------------------------------------------------

    Table XII-2 presents the estimated net change in air emissions for
the final rule. Table XII-2 shows that the estimated air emission
increases are less than 0.04 percent of the total air emissions
generated in 2009 by the electric power industry for the three
pollutants evaluated.

                       Table XII-2--Air Emissions Associated With BAT/PSES for Final Rule
----------------------------------------------------------------------------------------------------------------
                                                                              Change in air
                                                           2009 emissions       emissions         Increase in
         Non-water quality environmental impact             by electric      associated with     emissions for
                                                           power industry       final rule       final rule (%)
                                                           (million tons)     (million tons)
----------------------------------------------------------------------------------------------------------------
NOX....................................................                  1            -0.0114              -1.16
SOX....................................................                  6            0.00243             0.0406
CO2....................................................              2,403              -2.58             -0.107
----------------------------------------------------------------------------------------------------------------

    EPA compared the estimated increase in solid waste generation to
the amount of solids generated in a year by electric power plants
throughout the U.S.--approximately 134 billion tons. The increase in
solid waste generation associated with the final rule is less than
0.001 percent of the total solid waste generated by all electric power
plants.
    EPA estimates that, under the final rule, steam electric power
plants will reduce their water withdrawal by 57 billion gallons per
year (155 million gallons per day). See TDD Section 12.
    Based on these analyses, EPA determined that the final BAT effluent
limitations and PSES have acceptable non-water quality environmental
impacts, including energy impacts.

XIII. Environmental Assessment

A. Introduction

    Although not required to do so, EPA conducted an environmental
assessment for the final rule, as it did for the proposed rule. The
environmental assessment for the final rule reviewed currently
available literature on the documented environmental and human health
impacts of steam electric power plant wastewater discharges and

conducted modeling to determine the cumulative impacts of pollution
from the universe of steam electric power plants to which the final
rule applies. EPA modeled both the impacts of steam electric power
plant discharges at baseline conditions (pre-rule conditions) and the
improvements that will likely result after implementation of the rule.
    EPA's review of the scientific literature; documented cases of the
extensive impacts of steam electric power plant wastewater discharges
on human health and the environment; and a full description of EPA's
modeling methodology and results are provided in the EA.

B. Summary of Human Health and Environmental Impacts

    As discussed in the environmental assessment and proposed rule,
current scientific literature indicates that steam electric power plant
wastewaters such as fly ash transport water, bottom ash transport
water, FGD wastewater, and combustion residual leachate contain large
amounts of a wide range of harmful pollutants, some of which are toxic
and bioaccumulative, and which cause significant, widespread
detrimental environmental and human health impacts.
    Discharges of steam electric power plant wastewaters present a
serious public health concern due to the potential human exposure to
toxic pollutants through consumption of contaminated fish and drinking
water. Toxic pollutants that detrimentally affect human health that are