based and thermal treatment technologies, FGD wastewater may be
amenable to treatment with membrane filtration technologies in at least
some circumstances. Thus, EPA's conclusion that membranes are not
available nationwide, as required under the CWA, does not conflict with
EPA's finding that membrane filtration may be available at specific
sites for purposes of the VIP.
---------------------------------------------------------------------------

    \49\ While one membrane vendor commented that FGD wastewater is
no different than any other industrial wastewater, it did not
provide any data or analysis to support this statement.
---------------------------------------------------------------------------

    EPA also rejects membranes as the technology basis for BAT for all
existing plants because it could discourage more valuable forms of
beneficial reuse of FA (such as replacing Portland cement in concrete),
causing more FA to be disposed of as waste.\50\ While EPA agrees with
comments that there may be several alternative ways to treat or dispose
of the brine generated by membrane filtration, as discussed further
below, plants are most likely to encapsulate the brine with FA and lime
and dispose of the resulting solid in a landfill.
---------------------------------------------------------------------------

    \50\ While EPA considers FA use for waste solidification and
stabilization as beneficial use, the CCR waste being solidified or
stabilized must still be disposed of in accordance with 40 CFR 257.
---------------------------------------------------------------------------

    In concluding that the selection of membranes as BAT would result
in unacceptable non-water quality environmental impacts, EPA evaluated
brine management alternatives that were discussed with domestic plants
employing thermal systems, foreign plants employing membrane filtration
systems, and domestic plants in other industries employing membrane
filtration systems.\51\ EPA also evaluated whether FA is being disposed
of or is being sold and productively reused. After careful review of
the information in the record for this rulemaking, EPA projects that,
in the United States, the least cost option if membrane filtration were
selected would be encapsulation with FA and lime and disposal of the
resulting solid in a landfill. The following paragraphs summarize the
evaluations which led to EPA's conclusion that there is an unacceptable
non-water quality environmental impact in selecting membrane filtration
systems as BAT.
---------------------------------------------------------------------------

    \51\ EPA did not evaluate alternatives which would not be
available to the industry (e.g., unlike offshore oil and gas
facilities, ocean discharge would not be available to inland power
plants).
---------------------------------------------------------------------------

    There are no domestic plants operating membrane filtration systems
for EPA to contact. EPA therefore contacted two domestic plants
operating thermal FGD systems and examined information submitted to
EPA's Region 1 regarding a third thermal FGD system. Thermal and
membrane filtration systems generate similar brines, as both increase
the concentration of TDS in FGD wastewater by removal of ``clean''
water. For the three domestic thermal systems treating FGD wastewater,
the resultant brine is either used to condition (i.e., wet) ash for
disposal without encapsulation\52\ or is crystallized and sent to a
landfill. Thus, encapsulation of the brine using FA at these three
plants is unnecessary. When asked about the availability of FA for
sale, one of the three plants indicated that its particular market for
FA is flush, and that plant was no longer able to maintain contracts
for the sale of its FA, which would make it available for the plant to
use to encapsulate the thermal system brine. In contrast, two of the
plants with which EPA discussed possible future installations of
membrane filtration systems stated that they sell 100 percent of the FA
generated for beneficial reuse. Although some commenters suggested that
there is more than sufficient FA available for reuse, the EPA's
rulemaking record contains information to the contrary. According to
2017 and 2018 EIA data, the median percentage of FA that was sold for
beneficial use by plants with wet FGD systems was approximately 14
percent, with some plants selling all of their fly ash and some plants
selling none. Furthermore, these EIA estimates may be low, as one
plant's staff represented that they were beneficially using 100 percent
of their FA rather than the amount reported in the EIA data.\53\ A
quantitative comparison of EIA data for plants with FGD wastewater
indicates that if plants currently disposing of their FA installed
membrane filtration, they may have enough FA to encapsulate the
quantities of brine produced by membrane filtration. Two assumptions
underly EPA's comparison of EIA FA beneficial use and disposal data to
FGD brine encapsulation. First, EPA assumes that the fraction of brine
generated from all FGD wastewaters is the same at all plants that would
install a membrane system. Second, it assumes that all plants that
would install a membrane system would be able to make use of similar
encapsulation blends as the bids and pilots which EPA reviewed. In
practice, EPA expects the percent of brine generated by membrane
systems to differ from plant to plant, based on FGD wastewater
characteristics. EPA also expects the encapsulation blend to differ
from plant to plant based on both the brine characteristics and the fly
ash characteristics. This is consistent with public comments EPA
received on the proposal. Thus, while EPA's assumption of a typical
blend is reasonable for a nationwide assessment, the Agency anticipates
that there will be sites where non-water quality environmental impacts
are particularly unacceptable.\54\
---------------------------------------------------------------------------

    \52\ Ash conditioning with water or surfactants is a standard
industry practice to control fugitive dust emissions, and also a
standard component of fugitive dust plans required under the CCR
rule.
    \53\ EPA was unable to resolve the conflicting company-stated
beneficial use rates at this plant with the plant-specific EIA data.
    \54\ While there may be some sites where these non-water quality
environmental impacts are acceptable, the Agency has not identified
either information or a consistent basis upon which to subcategorize
these plants. In any case, such a subcategorization approach may
still not address the availability concerns raised in the discussion
above.
---------------------------------------------------------------------------

    But, while these assumptions are appropriate for nationwide cost
estimates which are needed to demonstrate economic achievability for
the industry as a whole, this does not necessarily mean that these
assumptions should be used for analyzing the non-water quality
environmental impacts associated with the resultant brine from membrane
use, and in particular, estimating what plants are likely to do with
this by-product in relation to available FA. Whether sufficient FA is
present on site or available in the local market is a site-specific
question. Should plants generate more brine than EPA estimated in its
analysis, or should plants not have the quality of FA (e.g., class C,
class F) necessary for the

assumed blend, those plants would need to reduce the quantity of ash
beneficially reused or acquire a substitute to encapsulate the brine
byproduct of an installed membrane system.
    Based on the limited available information, EPA understands that at
least two foreign plants operating full-scale membrane systems send the
resulting brine to a crystallizer to generate and sell a 95 percent
high-purity industrial salt. However, there are too many uncertainties
for EPA to estimate with confidence how many plants in the United
States might be able do the same. EPA understands that these foreign
plants engaged in negotiations with end-users prior to commissioning
their membrane systems. At one example system, the plant generates and
sells approximately 10,000 tons of industrial-grade salt per year.
While a crystallizer would be a more expensive option than ash
conditioning practiced at no-discharge plants in the U.S., the sale of
industrial salt could generate additional revenue to offset those
additional costs. Without salt revenue data from China, it is not
possible to compare these specific scenarios either in terms of costs
or non-water quality environmental impacts and any conclusions would be
speculative and lack factual support in this rulemaking record.
Furthermore, EPA cannot evaluate the practicality of such sales in the
U.S. because the Agency does not know which industries are purchasing
these salts, if these industries operate in the U.S., if they would be
willing to purchase salts from the U.S., or what the specifications are
for the salt product.
    Finally, EPA examined brine management in other industries. In both
the mining industry and in oil and gas, brine is managed through
evaporation (including evaporation impoundments), deep well injection,
and ocean discharge. Most steam electric power plants are not near
enough to an ocean for ocean discharge to be a feasible alternative.
Evaporation is more consistent with disposal methods at the domestic
thermal and foreign membrane filtration plants discussed above. The use
of evaporation impoundments is generally dependent upon climate and
plant space, so not all steam electric power plants may be able to
employ evaporation impoundments as is done at some mining and oil and
gas establishments. However, crystallization is an evaporation means
that is employed at some domestic and foreign plants to manage FGD
wastewater brine. Finally, deep well injection is not known to be used
at any steam electric power plants to manage FGD wastewater brine.
    After consideration of the information above, EPA evaluated
membrane filtration with three representative brine management
alternatives to determine which could most likely represent future
brine management. First, as it did for the proposed rule, EPA evaluated
brine encapsulation with FA and lime, in a blend representative of the
information in EPA's record.\55\ Second, EPA conducted a sensitivity
analysis which examined crystallization and disposal of the resultant
salt.\56\ Finally, EPA conducted a sensitivity analysis which examined
deep well injection. While EPA received comments that the brine might
be sold to oil and gas companies, commenters did not provide any
examples where this is currently occurring, nor is the Agency aware of
any. Thus, as it did for ocean discharge (see above), EPA concluded
that direct sale of brine to oil and gas companies would not be
representative of potential brine management in the steam electric
power generating industry.
---------------------------------------------------------------------------

    \55\ This scenario is representative not only of that blend, but
also of blends that would use more or less fly ash and/or lime, as
well as less expensive ash conditioning, in which ash is wetted just
with the brine (in lieu of other water or surfactants) prior to
disposal.
    \56\ This scenario could also be representative of
crystallization with sale of the resultant salt; however, EPA's
rulemaking record lacks information with which to analyze potential
sales.
---------------------------------------------------------------------------

    After conducting these three representative brine management
analyses, EPA concludes that the method most likely to be employed by
steam electric power plants using membrane filtration to treat FGD
wastewater would be encapsulation with FA and lime for disposal of the
resulting solid in a landfill. This brine management alternative was
the least cost solution in the bids and engineering documents examined,
was the least cost solution in EPA's own cost estimates, and is the
disposal approach discussed by both Georgia Power \57\ and GenOn \58\
as their most likely procedure if theyose ultimately choose to
participate in the VIP and install membrane filtration systems by the
2028 compliance date.
---------------------------------------------------------------------------

    \57\ In discussions about the potential for Plant Scherer to
install a membrane filtration technology under the proposed VIP,
Georgia Power staff indicated that should such an installation
occur, it would make use of a paste landfill where encapsulation of
brine would occur.
    \58\ GenOn indicated that plans for Chalk Point and Morgantown
included off-site disposal without FA from those plants because so
much of that FA is already beneficially used.
---------------------------------------------------------------------------

    As described in the proposal, landfilling an encapsulated material
raises challenges. For instance, comingling encapsulated material with
other landfill refuse could result in a leachate blowout. The King
County Landfill in Virginia experienced a leachate blowout when compact
CCR materials with a low infiltration rate were layered with normal
municipal solid waste having a higher infiltration rate. Similarly, in
the case of encapsulated brine paste, the paste would set and
thereafter achieve a very low infiltration rate. When comingled with
CCR having a higher infiltration rate, this would lead to layers with
disparate infiltration rates akin to those experienced in the King
County scenario. Thus, segregation of low infiltration rate
encapsulated brine in a landfill cell separate from other, higher
infiltration wastes could be necessary to prevent this layering and a
potential leachate blowout. Such dedicated landfill cells do not exist
today and would require time to permit and construct.\59\
---------------------------------------------------------------------------

    \59\ EPA also estimates that the volume of waste requiring
disposal if membrane filtration was selected is 10 times the volume
of waste estimated under the selected LRTR technology.
---------------------------------------------------------------------------

    Moreover, instead of disposing of their FA, plants can sell it for
beneficial use. As stated in the 2015 CCR rule:

    The beneficial use of CCR is a primary alternative to current
disposal methods. And as EPA has repeatedly concluded, it is a
method that, when performed correctly, can offer significant
environmental benefits, including greenhouse gas (GHG) reduction,
energy conservation, reduction in land disposal (along with the
corresponding avoidance of potential CCR disposal impacts), and
reduction in the need to mine and process virgin materials and the
associated environmental impacts.\60\
---------------------------------------------------------------------------

    \60\ 80 FR 21329 (April 17, 2015).

    Specifically, the Agency estimated (U.S. EPA 2011) that each ton of
FA used as a substitute for Portland cement would avoid the use of
5,400 megajoules of nonrenewable energy, 690 liters of water use,
1,000,000 grams (g) of CO2 emissions, 840 g of methane
emissions, 1,400 g of CO emissions, 2,700 g of NOX
emissions, 2,500 g of SOX emissions, 2,400 g of PM, 0.08 g
of Hg, 490 g of TSS discharge, 23 g of BOD discharge, and 46 g of COD
discharge.\61\ After considering these cross-program environmental
impacts, EPA finds that discouraging this beneficial use of FA on a
nationwide basis would result in unacceptable non-water-quality

environmental impacts.\62\ As discussed below in connection with the
VIP, however, EPA finds that, based on site-specific circumstances, the
non-water quality environmental impacts identified on a nationwide
basis could exist to a lesser extent (thereby not resulting in
unacceptable non-water quality environmental impacts).\63\
---------------------------------------------------------------------------

    \61\ U.S. EPA (Environmental Protection Agency). 2011. Waste and
Materials--Flow Benchmark Sector Report: Beneficial Use of Secondary
Materials--Coal Combustion Products. Office of Solid Waste and
Emergency Response. Washington, DC 20460. April.
    \62\ Although EPA evaluated FA and lime encapsulation as the
least-cost nationally available brine disposal alternative, other
alternatives with higher costs may also have adverse non-water
quality environmental impacts. For example, if a plant chose to
crystallize the resulting brine to continue selling its FA, this
thermal crystallization process could have a higher cost and
parasitic energy load.
    \63\ The same would be true for other VIP-compliant technologies
(e.g., thermal) that might be installed.
---------------------------------------------------------------------------

    While EPA views the foregoing reasoning as sufficient to find that
membrane filtration is not BAT for existing sources, EPA notes that
membrane filtration is projected to cost industry 26 percent more than
estimated at proposal. As identified by commenters, the data used to
establish limitations for membrane filtration for the proposed rule
included pilots that preceded membrane filtration with chemical
precipitation, while the cost estimates were based only on
microfiltration as pretreatment. EPA agrees. Where EPA has information
on pretreatment at foreign plants, none of those plants relies on
microfiltration alone. To correct this inconsistency, in the final
rule, EPA included the cost of chemical precipitation as the
pretreatment method for the membrane filtration cost estimates and
adjusted the set of data used to establish effluent limitations. For
the final rule, both effluent limitations and cost estimates reflect
data for systems using chemical precipitation as pretreatment before
membrane filtration. EPA disagrees with comments that suggested the
costs were not estimated correctly due to the use of incorrect flows
and FA consumption rates. For a more detailed discussion of the
membrane filtration public comments and responses, see DCN SE08615.
    In addition to the estimated pretreatment costs, plants will also
incur costs to dispose of the resulting brine. Some plants that may
otherwise sell their FA may choose to use their FA to encapsulate the
brine, thereby foregoing revenue from FA sales. Other plants that
choose to continue to sell their FA will need to dispose of the brine
using another disposal alternative, such as crystallization, at an
additional cost. Costs are a separate statutory factor that EPA
considers in selecting BAT (see, for example, BP Exploration & Oil,
Inc. v. EPA, 66 F.3d 784, 796 (6th Cir. 1996)). Here, while these costs
do not make the membrane filtration option economically unachievable
across the point source category as a whole,\64\ these estimated
increased costs do weigh against selecting membranes as BAT.
---------------------------------------------------------------------------

    \64\ See, e.g., Texas Oil and Gas Ass'n et al. v. EPA, 161 F.3d
923, 927 (5th Cir. 1998).
---------------------------------------------------------------------------

b. Other Technologies Evaluated for BAT Limitations
    As described further below, EPA is also not establishing BAT
limitations based on other technologies evaluated in the 2019 proposed
rule and 2015 rule.
    First, except for the permanent cessation of coal combustion and
low-utilization subcategories discussed below, EPA is not establishing
BAT limitations based on surface impoundments. One commenter suggested
that EPA should adopt a high recycle rate system for FGD wastewater if
the purge from such a system would receive BAT limitations equal to BPT
limitations. The commenter relied on EPA's proposed BAT for BA
transport water for this suggestion. Even for the purged wastewater
from a high recycle rate BA transport water system, however, the final
rule does not establish BAT limitations equal to BPT limitations.
Instead, EPA leaves the BAT limitations to be determined by the
permitting authority on a case-by-case basis, subject to BPJ. Such a
case-by-case determination is not warranted for FGD wastewater because
EPA has determined that CP+LRTR is available and economically
achievable for treatment of FGD wastewater. Furthermore, EPA confirms
its previous findings that surface impoundments are not as effective at
controlling pollutants (such as dissolved metals and nutrients) as
available and achievable technologies like CP+LRTR; however, as
described in Section X below, other statutory factors and EPA's
rulemaking record support the use of surface impoundments for two
subcategories.
    Second, except for the low utilization EGU subcategory discussed
below, the final rule does not establish BAT limitations or PSES based
on chemical precipitation alone. As EPA noted during the development of
the 2015 rule, chemical precipitation is effective at removing mercury,
arsenic, and certain other heavy metals. This technology alone does not
remove nitrogen, nor does it remove the majority of selenium.
Furthermore, the data in EPA's rulemaking record demonstrate that both
LRTR and HRTR remove approximately 90 percent of the mercury remaining
in the effluent from chemical precipitation treatment.\65\ Because the
combination of chemical precipitation with LRTR provides substantial
further reductions in the discharge of pollutants industry-wide, EPA
has established BAT based on CP+LRTR.
---------------------------------------------------------------------------

    \65\ Recall that the FGD mercury and arsenic limitations in the
2015 rule were based on chemical precipitation data alone because
the plants operating biological systems were not using all of the
chemical precipitation additives in the technology basis.
---------------------------------------------------------------------------

    Third, the final rule does not establish BAT limitations based on
thermal technologies, such as chemical precipitation (including
softening) followed by a falling film evaporator, based on the
statutory factors of total costs to industry and non-water quality
environmental impacts. EPA received comments stating that thermal
technologies are available, are unavailable, are economically
achievable, and are not economically achievable. EPA agrees that these
technologies are available but disagrees that these technologies are
economically achievable. Although commenters arguing against
availability raise a number of arguments, these arguments were
considered and rejected in the 2015 rule, and no new information has
been provided that warrants revisiting those findings. Since the 2015
rule, EPA has collected additional information on full-scale
installations and pilots of thermal technologies to treat FGD
wastewater. EPA's rulemaking record includes information about nine
pilot studies conducted in the United States, providing performance
data for five different thermal technologies. In addition, full-scale
installations are operating at six domestic plants,\66\ and a seventh
purchased thermal equipment, but elected not to install it.\67\ EPA is
also now aware of seven foreign installations in Italy and China, five
more foreign installations than at the time of the 2015 rule.
---------------------------------------------------------------------------

    \66\ One of these plants successfully ran three different
thermal systems to treat its wastewater, transitioning from a
falling film evaporator to a direct-contact evaporator, which mixes
hot gases in a high turbulence evaporation chamber, and finally to a
spray dryer evaporator.
    \67\ This plant purchased a falling film evaporator for the
purpose of meeting water quality-based effluent limitations for
boron, but then elected to instead pay approximately $1 million per
year to send its wastewater to a local POTW.
---------------------------------------------------------------------------

    With respect to economic achievability, in the 2015 rule EPA
rejected thermal technology as a basis for BAT limitations due to high
costs to industry. New thermal technologies have been pilot tested and
used at full scale since the 2015 rule, and related

cost information demonstrates that thermal technologies are now less
costly than when estimated for the 2015 rule. Nevertheless, the thermal
costs evaluated in EPA's memorandum FGD Thermal Evaporation Cost
Methodology (DCN SE08631) are still 2.4 times higher than the CP+LRTR
technology selected as BAT, and 1.04 times higher than the membrane
filtration costs in Option C. As authorized by section 304(b) of the
CWA, which requires EPA to consider costs, as well as the discretion
that the statute gives EPA to weigh the statutory factors, the Agency
finds that, for this final rule, thermal technologies are not BAT due
to the unreasonably high costs to industry.\68\ Given the high costs
associated with thermal technology, and the fact that the steam
electric power generating industry continues to face costs associated
with several other rules, in addition to this rule, EPA is not
establishing BAT limitations for FGD wastewater based on thermal
technologies.
---------------------------------------------------------------------------

    \68\ Some industry comments asserted that EPA underestimated the
cost for thermal technologies and that more accurate costs would
make these technologies economically unachievable. However, as
described above, EPA need not adjust its cost assumptions because
the Agency's own cost estimates result in unreasonably high costs.
---------------------------------------------------------------------------

    In addition to the unreasonably high costs, thermal technologies
have unacceptable non-water quality environmental impacts associated
with management of the resultant brine. Thermal technologies generate a
brine similar to membrane filtration technologies. For this reason,
portions of the discussion of membrane filtration brine above are based
on brine management at plants with thermal systems. EPA also concludes
that thermal technologies have unacceptable non-water quality
environmental impacts. The reasoning is the same as for membrane
filtration--unacceptable non-water quality environmental impacts would
occur as a result of discouraging the beneficial use of FA, and
additional disposal requirements would result from the production of a
brine byproduct.
    Furthermore, since the membrane filtration technologies evaluated
in Option C appear to achieve similar pollutant removals at lower costs
than thermal, as discussed later in this section, EPA is revising the
basis for the VIP limitations adopted in the 2015 rule to membrane
filtration, instead of thermal technologies.\69\
---------------------------------------------------------------------------

    \69\ EPA notes that thermal technologies could continue to be
used to meet the voluntary incentives program limitations based on
membrane filtration.
---------------------------------------------------------------------------

    Finally, EPA is declining to establish BAT limitations for FGD
wastewater as a case-by-case determination to be made by the permitting
authority using BPJ. EPA explained in the 2015 rule why BPJ
determinations would not be appropriate for FGD wastewater,
particularly given the availability of several other technologies, and
nothing in EPA's record would alter the Agency's previous conclusion.
2. BA Transport Water
    Under the final rule, EPA has selected high recycle rate systems as
the technology basis for establishing the BAT requirements to control
pollutants discharged in BA transport water. EPA determines that this
technology is available and economically achievable after evaluating
the factors specified in CWA section 304(b)(2)(B). In the 2015 rule,
EPA selected dry BA handling or closed-loop wet ash handling systems as
the technology basis for the no-discharge BAT requirements for BA
transport water. EPA established no discharge effluent limitations
based on these technologies, while also creating a limited allowance
for pollutant discharges associated with leaks and certain maintenance
activities.\70\
---------------------------------------------------------------------------

    \70\ See 40 CFR 423.11(p).
---------------------------------------------------------------------------

    At the time of the 2015 rule, EPA estimated that more than 50
percent of plants already employed dry handling systems or wet sluicing
systems designed to operate closed-loop, or had announced plans to
switch to such systems in the near future. Based on new information
collected since the 2015 rule, EPA now estimates that number to be over
75 percent of the industry. However, since the 2015 rule, EPA's
understanding has changed regarding the types of available dry systems,
and the ability of wet systems to operate a true closed-loop system (or
to achieve complete recycle) has changed.
    EPA is aware of advances in dry BA handling systems since the 2015
rule.\71\ For example, in addition to under-EGU mechanical drag chain
systems (described in the 2015 rule), pneumatic systems and compact
submerged conveyors (CSCs, which are referred to in the proposed rule
and in many public comments as submerged grinder conveyors, the
appellation of the most commonly sold system) are now in use at some
plants. EPA received comments that it failed to consider whether plants
could retrofit their operation using CSC systems, and that EPA should
retain the zero discharge limitations established in the 2015 rule. EPA
also received comments that CSCs could be more costly than other
technologies and that CSCs are not available. These included comments
that CSCs are not demonstrated, that CSCs cannot handle the high ash
loading rates of larger EGUs, and that retrofit with CSCs are not
feasible for EGUs below grade or with space constraints leaving the
EGU.
---------------------------------------------------------------------------

    \71\ The term ``dry handling'' is used to refer to ash handling
systems that do not use water as the transport medium for conveying
ash away from the EGU. Such systems include pneumatic and mechanical
processes (some mechanical processes use water to cool the BA or
create a water seal between the EGU and ash hoppers, but the water
does not act as the transport medium).
---------------------------------------------------------------------------

    EPA disagrees with commenters who asserted that it failed to
consider zero discharge requirements for BA transport water. While the
Agency acknowledges that it did not identify technologies that could
achieve zero discharge of BA transport water among its ``main''
regulatory options at proposal, the 2015 rule required zero discharge,
and EPA described the technologies forming the basis for the 2015 rule
and considered them and others, including CSCs, in this rulemaking.
    With respect to costs, since the proposal, EPA has conducted
conference calls with two plants, one of which operates a vacuum system
and one that operates a CSC. The Agency acknowledges that, at proposal,
it did not estimate costs of installing pneumatic systems (which
include both dry vacuum or pressure systems) or CSCs. In the case of
pneumatic systems, these systems tend to be more expensive than
alternatives, and third party EPCs have indicated that the decision to
install such systems is often driven by a combination of space
constraints and limitations on water withdrawals. EPA continues to view
pneumatic systems as more expensive than alternatives. With respect to
CSCs, the Agency did not have cost data at proposal to conduct a cost
analysis; however, since proposal the Agency has obtained CSC cost
information from one plant, which demonstrates that for that plant it
was the least-cost technology alternative. The costs for this plant are
comparable to other technologies that EPA evaluated, and this finding
is consistent with the representations of electric utilities, vendors,
and third-party EPC firms, which have found that, on a plant-specific
basis, CSCs may be the least costly bottom ash conversion option.
However, because CSCs serve only an individual EGU, the more EGUs a
plant has, the less economical this technology becomes. One vendor
suggested that plants with three or more EGUs would generally find
remote MDSs to be a least-cost alternative.
    With respect to availability, commenters disputed that CSCs are
demonstrated, but did not make the

same claim for pneumatic systems. Two full-scale CSCs became
operational in 2019,\72\ while 50 plants employing pneumatic systems
are currently operating, with retrofits dating back to 1992. EPA is
aware of only two CSCs in operation domestically today; however, the
Agency has identified three additional CSCs currently being installed.
Furthermore, in a conference call with one plant, it appears that,
while there were some challenges, especially during installation, this
particular system has operated successfully since its commissioning.
However, this plant did not experience the same space constraints
discussed below. Similarly, commenters raised issues with the ability
of CSCs to handle high ash loading rates. While staff at one plant
indicated that they successfully ramped up the speed of their CSC to
handle more tons of ash per hour, and constructed a 100 percent
redundant system, AEP submitted comments that the installation of CSCs
at a larger lignite EGU with high ash loading rates would be considered
high ``application risk.'' \73\ Specifically, the lignite coal burned
in this EGU has a much higher ash content, and its bottom ash tends to
be more abrasive, relative to the typical bituminous coals burned and
bottom ash produced at other AEP EGUs. As a result, 100 percent
redundant systems would be required, which would eliminate the cost
savings potential of the CSC system.\74\ In contrast, no commenters
claimed that pneumatic systems had loading rate constraints. Finally,
industry engineers, third-party EPC firms, and vendors have indicated
that pneumatic systems and CSCs can be installed at plants that are
constrained from retrofitting the larger under-EGU MDS due to
insufficient vertical space under the EGU. EPA has identified five EGUs
at three plants where MDS installation is precluded due to insufficient
vertical space. Commenters stated that CSCs, while smaller, could not
be installed at these space-constrained plants where MDS installation
is precluded without dismantling and excavating beneath the EGU, and
EPA finds that, at a minimum, these five EGUs could face such
limitations. AEP additionally described EGUs where space constraints
would not preclude installation of a single CSC, but would preclude the
installation of AEP's required 100 percent redundant design basis.\75\
Commenters did not argue that space constraints would preclude
pneumatic systems.
---------------------------------------------------------------------------

    \72\ EPA only had a conference call with one of these two plants
because the second plant did not respond to EPA outreach.
    \73\ AEP indicated that the vendor had found this application to
be high risk as well.
    \74\ See DCNs SE08695 and SE08695A1.
    \75\ See DCNs SE08695 and SE08695A1.
---------------------------------------------------------------------------

    With respect to wet BA handling systems, in their petitions for
reconsideration and in recent meetings with EPA, utilities and trade
associations informed EPA that many existing remote wet systems are, in
reality, ``partially closed'' rather than fully closed-loop, as assumed
by EPA in the 2015 rule. Utilities and trade associations informed EPA
that these systems operate partially closed, rather than closed, due to
small discharges associated with: (1) Additional maintenance and repair
activities not accounted for in the 2015 maintenance allowances; \76\
(2) water imbalances within the system, such as those associated with
stormwater; \77\ and (3) water chemistry imbalances, including acidity
and corrosiveness, scaling, and fines buildup. While some plants have
controlled or eliminated these challenges with relatively
straightforward steps (See DCNs SE08179 and SE06963), others require
more extensive process changes and associated increased costs or find
them difficult to resolve (See DCNs SE08188, SE08180, and SE06920).
---------------------------------------------------------------------------

    \76\ The 2015 rule maintenance discharges were characterized as
not a significant portion of the system volume, compared to, for
example, potential discharges resulting from maintenance of the
remote MDS tank or the conveyor itself. Such maintenance could
require draining the entire system, which would not be permissible
under the 2015 rule maintenance discharge allowance.
    \77\ The 2015 rule provided no exemption or allowance for
discharges due to precipitation events. While systems are often
engineered with extra capacity to handle rainfall and runoff from a
certain size precipitation event, these events may occur back-to-
back, or plants may receive events with higher rates of accumulation
beyond what the plant was designed to handle.
---------------------------------------------------------------------------

    EPA agrees that the new information indicates that some plants with
wet ash removal systems can operate as zero discharge systems, but in
many cases must operate as high recycle rate systems. While some plants
currently handle the challenges discussed above by discharging some
portion of their BA transport water, the record demonstrates that
plants can likely eliminate such discharges with additional process
changes and expenditures. For the 2015 rule, EPA estimated costs of
chemical additions to manage scaling. Now, companies could be adding
additional treatment chemicals (caustic) to manage acidity or other
chemicals to control alkalinity, using reverse osmosis filters to
remove dissolved solids from a slipstream of the recycled water, adding
polymer to enhance settling and removal of fine particulates
(``fines''), and building storage tanks to hold water during infrequent
maintenance or precipitation events. Industry-wide, EPA conservatively
estimates the costs of the additional measures needed to achieve and
maintain a truly closed-loop system to be $63 million per year in
after-tax costs, beyond the costs of the systems
themselves.78 79 These additional costs and process changes
were not accounted for in the 2015 rule; however, as discussed in
Section 5.3.3 of the Supplemental TDD, EPA has accounted for these
costs in estimating the baseline costs of the BA limitations in the
2015 rule. Some commenters argued that EPA's costs were too
conservative and asserted that these costs would not be necessary at
most sites. While EPA agrees that it is not likely that all plants
would incur these additional costs, EPA had no means to predict which
plants would ultimately incur these additional costs, and thus the
Agency reasonably assumed, for purposes of its economic achievability
analysis, that each plant would incur these costs--in order to ensure
that the costs upon which economic achievability are based are not
underestimated. However, to the extent that necessary purges are
smaller than this upper bound, EPA evaluated an alternate scenario in a
Bottom Ash Alternate Purge Sensitivity Analysis (DCN SE09073). These
lower costs were considered in addition to the costs presented above
and would not change EPA's conclusion that high recycle rate systems,
rather than closed-loop systems, are BAT. For further discussion of
public comments and responses about closed loop and high recycle rate
systems, see DCN SE08615.
---------------------------------------------------------------------------

    \78\ Due to the final rule's changed compliance dates this
estimate also includes discounting, which may overstate the savings.
    \79\ Utilities and EPC firms have discussed the availability of
new dry systems, such as the CSC or pressure systems, which at some
plants would have costs similar to recirculating wet systems (which
would require a purge). Because EPA did not have cost information to
determine the subset of plants for which new dry systems might be
least costly, some portion of the costs estimated for this rule may
be based on selecting recirculating wet systems at plants that could
ultimately choose to install dry handling technologies. Thus, EPA
may overestimate costs or underestimate pollutant removals at the
subset of plants where such a dry system would be selected.
---------------------------------------------------------------------------

    EPA also recognizes the need for plants to consider their ability
to comply with multiple environmental regulations simultaneously. As
discussed in Section IV above, EPA has recently finalized the CCR Part
A rule, requiring plants to cease receipt of waste in unlined surface
impoundments by April 11, 2021 (with certain

exceptions).\80\ The challenges of operating a truly closed-loop
system, discussed above, are compounded by the requirements of the CCR
rule. Plants often send various CCR and non-CCR wastestreams, such as
coal mill rejects, economizer ash, etc., with BA transport water into
their surface impoundments. According to reports provided to EPA and
conversations with electric utilities, several plants have already
begun (or even completed) the transition away from impoundments and use
the BA treatment system for some of their non-CCR (i.e., non-FA, BA, or
FGD) wastewaters.\81\ This can be beneficial where it reduces the
discharge of the non-CCR wastewaters, which might otherwise be
discharged subject only to the TSS limitations applicable to low volume
wastewater. At the same time, however, doing so can lead to or
exacerbate scaling, corrosion, or plugging of equipment, all of which
require process changes and additional expense to address, thereby
complicating establishment of a closed-loop system. These problems
could be avoided by purging the system from time to time, as necessary.
Fewer than 25 percent of plants have not yet installed a BA transport
water technology beyond surface impoundments and could potentially
employ a dry system. However, due to the fast approaching cease-
receipt-of-waste date under the CCR rule, it is probable that the
majority of these plants have already begun their conversions to wet
ash handling systems, which makes switching to a wholly different BA
handling technology infeasible so late into the process.\82\ For EPA to
not allow a purge may encourage more of the non-CCR wastewaters
mentioned above to be discharged as low volume waste. In order to
accommodate both compliance with this rule and the CCR Part A rule, EPA
finds it necessary for the permitting authority to allow for a high
recycle rate system with some purge rather than a truly closed-loop
system.
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    \80\ As mentioned in Section IV of this preamble, further
information about this proposal is available at http://www.regulations.gov, Docket EPA-HQ-OLEM-2019-0172.
    \81\ In some cases, the treatment system predated even the
proposed CCR rule.
    \82\ The CCR Part A rule acknowledges that a subset of plants
which were lined or met the groundwater monitoring requirements and
location restrictions may not yet have taken steps to convert their
systems.
---------------------------------------------------------------------------

    Furthermore, to the extent that plants had not designed, planned,
procured, or commissioned segregated non-CCR wastewater treatment
systems yet, requiring a plant to close the loop where closed loop
operation would require wastewater segregation may force those plants
to continue to send the non-CCR wastewater to their existing surface
impoundments, thus extending their surface impoundment operations until
new non-CCR wastewater systems can be commissioned. Some comments point
to CCR rule requirements and Duke Energy's installation of lined
retention basins in an attempt to demonstrate that non-CCR wastewaters
can be managed separately within the 2015 rule time frames. EPA
disagrees in both instances. While it might be possible for the
retention basins being installed by Duke Energy to handle redirection
of all of these non-CCR wastewaters, Duke Energy itself did not design
for this, and instead designed and currently operates at least some of
its high recycle rate systems to handle non-CCR wastewaters.\83\ The
CCR Part A rule generally requires plants to cease receiving waste in
unlined surface impoundments no later than April 2021. Nevertheless, in
cases where alternative capacity is not available, plants may request a
site-specific alternative closure extension to operate that surface
impoundment until 2023 or 2024. Thus, if the final rule were to require
complete recycling of BA transport water, and this could only be
accomplished by segregating wastewaters, at least some plants that
might currently be able to meet the CCR Part A rule's April 2021 cease-
receipt-of-waste date would instead be forced to request a site-
specific alternative closure extension and continue operating the
existing, unlined surface impoundment while they developed alternative
disposal capacity to manage these newly segregated wastestreams.
---------------------------------------------------------------------------

    \83\ For example, Duke Energy's Belews Creek plant manages its
coal mill rejects wastestream in its recently commissioned remote
mechanical drag system.
---------------------------------------------------------------------------

    In light of the foregoing process changes and associated
engineering challenges facing plants needing to implement a true zero
discharge BA transport water limitation in combination with the CCR
rule, and to give plants flexibilities that will facilitate orderly
compliance with the fast-approaching CCR rule deadlines, EPA determines
that the basis of the BA transport water BAT limitations is the use of
high recycle rate systems rather than dry handling or closed-loop
systems, which were the technologies on which the zero discharge BAT
limitation (adopted in the 2015 rule) were based. EPA's conclusion is
based on its discretion to give particular weight to the CWA Section
304(b) statutory factor of ``process changes.'' Process changes to
existing high recycle rate, non-closed loop systems made to comply with
this rule in conjunction with the CCR rule, as discussed above, could
be more challenging without a further discharge allowance, and in some
plants could also prolong use of unlined surface impoundments.
    EPA concludes that the factors discussed above are sufficient to
support the Agency's decision not to select dry handling or closed-loop
systems as BAT for BA transport water. EPA also notes that cost is a
statutory factor that it must consider when establishing BAT, and that
closed-loop systems cost more than high recycle rate systems for
treatment of BA transport water. Some commenters stated that high
recycle rate systems cannot be selected solely on the basis of higher
costs when those costs are economically achievable. While EPA does not
find the estimated additional cost to industry would result in plant
closures, cost is a statutory factor that EPA must consider under
section 304(b) of the CWA, and EPA has discretion in weighing the
statutory factors, see, e.g., BP Exploration & Oil Inc. v. EPA, 66 F.3d
784, 799-800 (6th Cir. 1995) (citation omitted)). EPA views the higher
cost of fully closed-loop systems as an additional factor supporting
EPA's decision to reject closed-loop systems as BAT for treating BA
transport water.
    Some commenters argued that the proposed BAT based on high recycle
rate systems is not warranted because that technology basis does not
represent what is achieved by the single best performing plant, and
even went so far as to say that this standard reflected the worst
performing plant. EPA disagrees with these commenters. Some companies
began proactive fleetwide conversions either before the effective dates
of the 2015 rule or in some cases before the 2015 rule was signed. Many
of these fleetwide conversions were to the remote MDS, a specific type
of high recycle rate system that formed the ``closed-loop'' part of the
2015 rule BA transport water BAT technology basis. As discussed above,
these systems do not all operate 100 percent closed-loop, as EPA
assumed they did when finalizing the 2015 rule. Based on actual,
measured purge rates in EPRI (2016), however, the Agency estimates that
actual purge rates necessary on a day-to-day basis may be less than one
percent of the system's volume, with higher purges necessary at less
frequent intervals due to precipitation and maintenance. Furthermore,
while surface impoundments can cover dozens of acres and contain
volumes in the billions of gallons, typical high

recycle rate systems have volumes closer to one-half million gallons
(\1/2\ million). Thus, even assuming the proposed maximum allowable
purge of 10 percent is necessary for a unit, the average gallons per
day released by high recycle rate systems will be two percent of the
average gallons per day released by surface impoundments, and therefore
will also be 1.5 percent of the pollutant releases expected from
surface impoundments. Industry-wide, EPA estimates this combination of
reduced volume and increased recycling reduces discharges by 366
million pounds of pollutants per year, and thus makes reasonable
further progress toward the CWA goal to eliminate the discharge of
pollutants. See 33 U.S.C. 1251(a), 1311(b)(2)(A). Therefore, it is the
combination of the reduced system volume and high capacity to recycle
BA transport water that supports EPA's basis for high recycle rate
systems as BAT.
    The Agency also received comments that a generic 10 percent purge
was not justified and that tighter limitations could be applied in some
cases. One state commenter argued that it should be permissible for a
permitting authority to continue to set zero discharge requirements.
EPA has considered these comments and made modifications to improve the
final rule. EPA is finalizing the site-specific alternative for which
it solicited comment. Under the final rule, EPA establishes that the
NPDES permitting authority will determine on a case-by-case basis the
purge allowance (not to exceed 10 percent) necessary at a particular
plant with a wet transport system.\84\
---------------------------------------------------------------------------

    \84\ While this could include a purge of zero percent, EPA
believes that such a determination could only occur in those cases
where the system is designed to function, and is demonstrated to
successfully perform, as a zero discharge system.
---------------------------------------------------------------------------

    As with the proposal, this site-specific purge could in no case
exceed 10 percent of the system volume per day on a 30-day rolling
average. EPA concludes that the maximum purge volume would more than
account for the challenges identified above, including infrequent large
precipitation and maintenance events. EPA defines the term ``30-day
rolling average'' to mean the series of averages using the measured
values of the preceding 30 days for each average in the series. The
purge volume is more appropriately determined on a case-by-case basis
because these plants vary so much with regard to what purge is needed
to maintain the wastewater treatment system versus the tradeoffs at
each site regarding what options are available for the non-CCR
wastewater, Thus, this option is designed to provide flexibility if and
when needed to address site-specific challenges of operating the
recirculating ash system (for more on implementation, see Section XIV
of this preamble).\85\
---------------------------------------------------------------------------

    \85\ EPA's pollutant loading analyses provided in Section IX.B
of this preamble and described in detail in the BCA Report and
Supplemental TDD, were based on an assumed 10 percent purge at each
affected plant, and therefore overestimates pollutant discharges
associated with the BAT for BA transport water.
---------------------------------------------------------------------------

    Some commenters suggested that EPA establish a BMP plan rather than
a 10 percent purge. Commenters seemed to misunderstand the 10 percent
purge in relation to BAT. When EPA establishes BAT, it selects a
technology that is available nationally and economically achievable
industry-wide. EPA then calculates the effluent limitations expected
from the performance of the selected technology. Only after
establishing those limitations might EPA impose an additional BMP plan
under section 304(e) of the CWA. Here, BAT is high recycle rate
systems, and based on the available data, EPA has established
limitations that such systems can achieve.
    Under the final rule's site-specific requirement for determining
discharge allowances there may be wastewater from whatever is purged by
the high recycle rate system, and plants may wish to discharge this
wastewater. At proposal, EPA solicited comment on whether specific
technologies should be selected as BAT for the purged wastewater. Some
commenters suggested that surface impoundments should be selected
because the high recycle rate systems already make reasonable forward
progress. While EPA agrees that high recycle rate systems make
reasonable forward progress in accordance with the CWA, the Agency must
still consider any available treatment alternatives for the purged
wastewater. Two considerations make determining a nationwide BAT for
these discharges challenging and site-specific. First, in the case of
precipitation or maintenance-related purges, such purges could be large
volumes at infrequent intervals.\86\ Each plant necessarily has
different climates and maintenance needs that make selecting a uniform
treatment system more difficult. Second, utilities have stated that
discharges of wastewater associated with high recycle rate systems are
sent to low volume wastewater treatment systems, which are typically
dewatering basins or surface impoundments. Many of these systems are in
transition as a result of the CCR rule. New wastewater treatment
systems installed for low volume wastewater and other wastestreams
(which could be used to treat the wastewater purged from a high recycle
rate system), as well as the types of wastestreams combined in such
systems, are likely to vary across plants. For further purge-related
public comments and responses see DCN SE08615.
---------------------------------------------------------------------------

    \86\ For example, rainfall exceeding a 10 year, 24-hour event
would only be expected to occur twice during the 20-year lifetime of
the equipment.
---------------------------------------------------------------------------

    In light of the information discussed above, and EPA's authority
under section 304(b) to consider both the process employed (for
maintenance needs) and process changes (for new treatment systems
installed to comply with the CCR rule), EPA concluded that BAT
limitations for any wastewater that is purged from a high recycle rate
system and then discharged, should be established by the NPDES
permitting authority on a case-by-case basis using BPJ. EPA concludes
that permitting authorities are in a better position than EPA to
examine site-specific climate and maintenance factors, especially since
the permitting authority will already be determining the allowable
volume of purge, up to a maximum of 10 percent of the system's volume.
Permitting authorities will also be in a better position than EPA to
account for site-specific treatment technologies and their
configurations already installed or being installed to comp0ly with the
CCR rule and other regulations which could accommodate the volumes of,
and successfully treat, any discharges of wastewater from a high
recycle rate system associated with the proposed allowance.
    EPA is not identifying surface impoundments as BAT for BA transport
water because surface impoundments are not as effective at removing
dissolved metals as available and achievable technologies, such as high
recycle rate systems. Furthermore, the record since the 2015 rule shows
that plants have continued to convert away from surface impoundments to
the types of technologies described above, either voluntarily or due to
the CCR rule, and in 2018, the U.S. Court of Appeals for the District
of Columbia vacated that portion of the 2015 CCR rule that allowed both
unlined and clay-lined surface impoundments to continue operating.
USWAG v. EPA, No. 15-1219 (D.C. Cir. 2018). Since very few CCR surface
impoundments are composite-lined, the practical effect of this ruling
is that many plants with operating impoundments likely will cease
sluicing waste to these impoundments in the near future. In the 2015
CCR rule, EPA estimated that it would be less costly for plants to
install under-EGU or remote

drag chain systems and send BA to landfills rather than continue to wet
sluice BA and replace unlined impoundments with composite lined
impoundments. This supports the suggestion that surface impoundments
are not BAT for all plants; however, EPA is identifying surface
impoundments as BAT for two subcategories, as discussed later in this
section. In addition, EPA is defining a new wastestream, BA purge
water, which is a more accurate term than the proposed ``maintenance
purge water.'' BA purge water consists of the water permissibly purged
from a high recycle rate system. This wastestream is no longer defined
as BA transport water; therefore EPA is making conforming changes to
the BPT regulations to make clear that the BPT limitations based on
surface impoundments for TSS and oil and grease, which are applicable
to BA transport water, also continue to be applicable to BA purge
water. Effluent limitations for BA purge water are to be established by
the permitting authority based on BPJ.
3. Voluntary Incentives Program (VIP)
    The final rule includes a VIP that provides the certainty of more
time (until December 31, 2028, instead of a date determined by the
permitting authority that is as soon as possible beginning October 13,
2021) for plants to implement new BAT limitations if they adopt
additional process changes and controls that achieve limitations on
mercury, arsenic, selenium, nitrate-nitrite, bromide, and TDS in FGD
wastewater, based on membrane plus pretreatment technology. The 2015
rule included a similar VIP that was based on thermal evaporation
technology and that would extend the compliance deadline for VIP
participants by five years. See Section VIII(C)(13) of the 2015 rule
preamble for a more complete description of the selection of the
thermal technology basis, chemical precipitation (with softening)
followed by a falling film evaporator. As in the 2015 rule, EPA expects
the additional time to achieve compliance, combined with other factors
(such as the possibility that a plant's NPDES permit may need more
stringent limitations to meet applicable water quality standards), may
lead some plants to choose this option for future implementation by
incorporating the VIP limitations into their permit when applying.
    Some commenters argued that EPA lacks authority under the CWA to
establish a VIP with compliance deadlines beyond three years from the
date of promulgation of the final rule. EPA disagrees. The VIP program
established in the 2015 rule was not challenged in court (and also not
challenged by these particular commenters who challenged other aspects
of the 2015 rule). The statute is silent with respect to BAT effluent
limitations established after 1989. As the U.S. Court of Appeals for
the Fifth Circuit recently held, the CWA's requirement in 33 U.S.C.
1311(b)(2)(C), (D), and (F) that effluent limitations be met no later
than three years after promulgation plainly applies only to initial BAT
limitations, not revisions of such effluent limitations. Clean Water
Action v. Pruitt, 936 F.3d 308, 316 (5th Cir. 2018). The compliance
deadlines in Sections 301(b)(2)(C), (D), and (F) of the CWA only apply
to effluent limitation guidelines that were established prior to the
outside dates specified in those provisions. They do not apply to
effluent limitations guidelines established in 2020. For further
discussion, see DCN SE08615.
    New information in several utilities' internal analyses and
contractor reports provided to EPA since the 2015 rule, as well as
information EPA gathered in meetings with utilities, EPC firms, and
vendors, indicates that plant decisions to install the more expensive
thermal systems both prior to and following the 2015 rule were driven
by water-quality-based effluent limitations imposed by the NPDES
permitting authority. These documents and meetings also revealed that
several plants considered installing membrane filtration technologies
under the 2015 rule VIP as well, and EPA is aware of one company,
GenOn, that has plants that opted into the 2015 VIP with plans to use
membrane filtration technologies to meet the VIP limitations. Despite
membrane filters not being available nationwide and not being
appropriate for all facilities, due to electric utilities' continued
interest in this technology, EPA evaluated membrane filtration as an
alternative basis for the VIP limitations.
    Under the final rule, EPA establishes VIP limitations based on
membrane filtration, replacing the 2015 rule VIP limitations based on
thermal technology, because EPA estimates that membrane filtration
systems are less costly than thermal systems and have comparable
pollutant removal performance. Membrane filtration achieves pollutant
removals comparable to thermal systems in situations where the thermal
system would discharge, which the VIP in the 2015 authorized. Due to
the significantly higher costs of thermal systems compared to chemical
precipitation followed by LRTR, EPA does not expect that many plants
would install a new thermal system under a VIP program as the least
cost technology, though some might install it to comply with water
quality-based effluent limitations established by their permitting
authority.\87\ As authorized by section 304(b) of the CWA, which allows
EPA to consider costs, EPA is selecting membrane filtration as the
technology basis for the VIP limitations, with limitations for mercury,
arsenic, selenium, nitrate-nitrite, bromide, and TDS.\88\
---------------------------------------------------------------------------

    \87\ See, e.g., https://www.powermag.com/how-low-temperature-evaporation-treats-fgd-wastewater/ (DCN SE09091).
    \88\ Note that the 2015 rule VIP did not include limitations for
nitrate/nitrite or bromide.
---------------------------------------------------------------------------

    Also, as authorized by section 304(b) of the CWA, which allows EPA
to consider process changes and non-water quality environmental
impacts, EPA is revising the compliance date for the VIP limitations to
December 31, 2028. That is the date EPA has determined that the
membrane filtration technology will likely be available for full-scale
implementation at those plants that choose to adopt it. EPA proposed to
conclude that membrane technology would be nationally available in
2028. Some commenters asserted that it is inappropriate for EPA to
predict a date in the future when a technology will become nationally
available for CWA purposes. EPA agrees with these commenters and in the
final rule concludes only that membrane technology will likely be
available by 2028 on a site-specific basis. Although EPA will continue
investigating the availability and economic achievability of this
technology, EPA cannot predict with certainty that the technology will
be nationally available in 2028.
    The 2028 time frame is based on the time necessary to pilot,
design, procure, and install both the membrane filtration systems and
the brine management systems, including disposal capacity. Additional
time is also often necessary to complete the permitting process. This
time frame should also be adequate for alternative VIP-compliant
technologies, such as thermal systems. Because EPA establishes BAT
effluent limitations based on a specific technology's performance, but
does not require a specific technology for compliance, thermal systems
would still be allowable under the final rule VIP program, as would
alternative non-membrane technologies that meet the limitations.
    Some commenters argued that the 2028 deadline for the VIP is too
long, citing shorter construction time frames and an email from one
electric utility

suggesting a VIP deadline of 2026 would be feasible.\89\ While EPA
agrees that some plants opting into the VIP may be able to install the
technology sooner, part of the incentive for the program, which is
expected to result in substantial additional pollutant removals from
plants opting in, is the extra time provided to achieve compliance.
Finally, EPA notes that this time frame is also similar to the eight-
year period between promulgation of the 2015 rule and the 2023 deadline
for the 2015 rule's VIP. For a further discussion of VIP timing in
public comments and responses, see DCN SE08615.
---------------------------------------------------------------------------

    \89\ This company appears to be retiring its coal-fired EGUs
from service, and therefore EPA does not project that it would use
the VIP whether the deadline is 2026 or 2028.
---------------------------------------------------------------------------

    EPA finds that using membrane filtration as the technology basis
for the VIP does not result in the same non-water quality environmental
impacts that informed the Agency's decision not to select membranes as
BAT for the entire industry. First, participation in the VIP is
voluntary and EPA would expect it to be selected only by plants for
which it presents the least cost option, accounting for particular FA
production, use, disposal and market availability. Where plants have
limited FA markets and already dispose of their ash, they could dispose
of the brine using encapsulation or ash conditioning without reducing
beneficial use of FA. EPA understands that this is the case at Duke's
Mayo Plant. Other plants may have sufficient external sources of FA and
landfill space to dispose of an encapsulated material. EPA understands
that this is the case at GenOn's two remaining Maryland plants. Of
course, brine disposal options are not the only considerations for
plants deciding whether to participate in the VIP. As noted above,
GenOn indicated that final plans for treatment technology for both
units will depend on the standards of this final rule, and for one of
its units, changing electricity demand.
    Finally, forthcoming changes in membrane filtration brine disposal
options may reduce the non-water quality environmental impacts
associated with encapsulation, as discussed in Section VII(b)(i) above.
Through discussions with several utilities and EPRI, EPA learned that a
developing ``paste'' technology may allow plants to mix the brine with
lower quantities of FA and lime and pump the resulting paste via pipes
to an onsite landfill where the paste would self-level prior to setting
as an encapsulated material. According to these discussions, such a
process may be less costly than current brine disposal alternatives.
This process could also reduce non-water quality environmental impacts
by reducing the amount of FA used, decreasing air emissions and fuel
use associated with trucking and spreading, and, where FA is already
being disposed of, reduce the volumes and pollutant concentrations in
leachate.90 91 EPA is aware that part of Plant Scherer's
current, long-term pilot study is intended to evaluate this very
process.
---------------------------------------------------------------------------

    \90\ Sniderman, Debbie. 2017. From Power Plant to Landfill:
Encapsulation. Innovative Technology Offers Elegant Solution for
Disposing of Multiple Types of Waste. EPRI Journal. September 19.
Available online at: http://eprijournal.com/from-power-plant-to-landfill-encapsulation/ (DCN SE09092).
    \91\ Although EPA is not establishing BAT for leachate in the
current rulemaking, the vacatur and remand of BAT for leachate in
Southwestern Electric Power Co., et al. v. EPA means that decreasing
volumes of leachate and the concentration of pollutants in that
leachate might make more technologies available in a future BAT
rulemaking.
---------------------------------------------------------------------------

    Two additional challenges were identified for the membrane
filtration technology or the paste technology described above. The
first challenge regarding the paste alternative is developing
approaches to manage wastes (e.g., flush water) from periodic cleaning
of the paste transportation piping, where such piping is used.\92\
Consistent with the proposal, and as authorized by section 304(b) of
the CWA, which allows EPA to consider the process employed, EPA is
finalizing a modification of the definition of FGD wastewater and ash
transport water to explicitly exclude water used to clean FGD paste
piping. This enables plants using paste piping for brine encapsulation
and disposal in an on-site landfill to clean residual paste from pipes
and other equipment more easily.
---------------------------------------------------------------------------

    \92\ Utilities described this process as water pushing a ball
through the paste piping when not in use, based on cleaning done of
concrete pipes at construction sites. While the ball would clean out
the majority of the paste, water would still contact incidental
amounts of ash and FGD materials, thus potentially subjecting it to
regulations for those wastewaters.
---------------------------------------------------------------------------

    The second challenge is that some plants that might want to re-use
the first stage, membrane-treated FGD wastewater without a polishing RO
stage as EGU makeup water could be discouraged from doing so. As
discussed in Section VII(B)(1) above, RO is the standard treatment for
source water (e.g., groundwater and surface water) used in the EGU to
generate steam. These existing systems must ensure sufficiently low
levels of pollutants (such as TDS) to prevent corrosion, fouling,
foaming, scale deposits, and loss of heat transfer efficiency within
the EGU. This extremely clean water is turned into steam at the EGU and
is used to turn the blades of the turbine to generate electricity
before being condensed back into water at the cooling towers and
returned to the EGU. Some plants that participate in the VIP and
install a membrane filtration system to treat their FGD wastewater by
the 2028 compliance date might find it advantageous to direct their
partially treated FGD wastewater through their EGU makeup water RO
system, instead of employing a second stage RO treatment to meet the
membrane filtration-based limitations in this rule. In these cases, it
is unlikely that the FGD wastewater treated using the first stage of
the membrane filtration treatment system alone would meet the final
membrane-based limitations (i.e., an internal limitation could not be
met), and after mixing with other source water (e.g., river water or
groundwater) at the EGU makeup water RO treatment system, it could be
infeasible to demonstrate compliance based on existing methods.\93\
Small amounts of EGU water are handled as EGU blowdown, which is sent
to flash tanks where most will turn to steam. While some of the rest
can be recycled, at times it is necessary to discharge this water,
subject to existing limitations for low volume waste (as the existing
regulatory definition of low volume wastes includes EGU blowdown). This
could occur where the EGU is emptied for maintenance (e.g., to repair
tube leaks) or shut down (e.g., during outages). Reduced water
withdrawals are a non-water quality environmental impact that not only
saves plants money to withdraw and treat significant volumes of water,
but would also reduce impingement and entrainment. EPA projects that
the final rule VIP will result in 292,000 gallons per day of reduced
water withdrawals at eight plants. While some of these reduced water
withdrawals may be due to increased recycling within the FGD system, at
least a portion of these reduced withdrawals would be expected where a
plant used the permeate as EGU makeup water. Therefore, to encourage
this practice where EGU makeup water is ultimately discharged as EGU
blowdown, the EPA is making a change from proposal by clarifying that
membrane permeate and thermal

distillate used as EGU makeup water is not considered FGD wastewater,
and is thus removing them from the definition of FGD wastewater at
423.11(n).
---------------------------------------------------------------------------

    \93\ As discussed in Section XIII of this preamble, the data
points used for developing limitations of three constituents in the
VIP included too many non-detect values to develop a monthly limit,
and these data points did not include dilution water, as would be
the case here.
---------------------------------------------------------------------------

    A compliance date of December 31, 2028 for the VIP allows time for
further development of this paste technology, increasing its
availability to plants, and giving plants more time to acquire any
necessary permits for landfill cells for brine encapsulated with FA and
lime if needed; allowing plants time to conduct pilot testing,
demonstrations, and further analyses to identify and implement process
changes associated with membrane filtration; and assessing the long-
term performance of the technology for treatment of FGD wastewaster.
    Taken together, EPA's final VIP gives plants greater flexibility
when choosing a technology to achieve the established VIP pollutant
limitations, resulting in pollutant reductions beyond the BAT
limitations that are generally applicable to the industry. Under the
proposal, EPA estimated that 18 plants may opt into the VIP program.
Based on public comments and cost estimate revisions, under the final
rule, EPA now estimates that eight plants (13 percent of plants
estimated to incur FGD compliance costs) may opt into the VIP program.
    EPA is not finalizing the VIP for PSES for several reasons. First,
the CWA dictates that plants subject to PSES comply within three years
after the limitations are promulgated. Thus, the statute does not allow
for additional time to implement VIP limitations. Second, there are
only two plants with indirect discharges of FGD wastewater. One of
these plants has announced its retirement, and EPA expects that plant
to participate in the subcategory for EGUs permanently ceasing the
combustion of coal. The other plant has a water quality-based effluent
limitation that would already call for the use of a technology that
could meet the VIP limitations. Since a PSES VIP would not grant any
additional time or flexibility, EPA determines that such a provision is
not justified.

C. Additional Subcategories

    In the 2015 rule, EPA established subcategories for small EGUs
(less than or equal to 50 MW nameplate capacity) and oil-fired units.
EPA subcategorized small EGUs due to disproportionate costs when
compared to the rest of the industry and subcategorized oil-fired units
both because they generated substantially fewer pollutants and are
generally older \94\ (and more susceptible to early retirement). In the
2015 rule, EPA stated:
---------------------------------------------------------------------------

    \94\ Age is a statutory factor for BAT. CWA section 304(b), 33
U.S.C. 1304(b).

    ``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.'' \95\
---------------------------------------------------------------------------

    \95\ 80 FR 67856 (November 3, 2015).

    For these subcategorized units in the 2015 rule, EPA established
differentiated limitations based on surface impoundments (i.e., setting
BAT limitations equal to BPT limitations on TSS).
    EPA did not propose, and is not changing in this final rule, the
2015 rule subcategorization of small EGUs and oil-fired units. The
final rule does, however, incorporate and expand on EPA's previous
analysis of characteristics and differences within the industry. EPA
has authority in a national rulemaking to establish different limits
for different plants after considering the statutory factors listed in
section 304(b). See Texas Oil & Gas Ass'n v. EPA, 161 F.3d 923, 938
(5th Cir. 1998) (``We find nothing in the text of the CWA indicating
that Congress intended to prohibit the promulgation of different
effluent limits within a single subcategory of point sources . . . .
The fact that EPA must promulgate rules for classes of polluters rather
than individual polluters does not mean that EPA is required to treat
all polluters within each class identically. The phrases `for
categories and classes' and `within such categories or classes' simply
do not, by their terms, exclude a rule allowing less than perfect
uniformity within a category or subcategory.). The final rule includes
subcategories applicable to FGD wastewater and BA transport water for
EGUs with low utilization and EGUs permanently ceasing the combustion
of coal. In addition, the final rule includes a subcategory applicable
to FGD wastewater for power plants with high FGD flows. These
subcategories are discussed below.
1. Plants With High FGD Flows
    Consistent with the proposal, EPA is finalizing a subcategory for
plants with high FGD flows based on the statutory factor of cost.
Specifically, this subcategory faces a disproportionately higher
capital cost than other plants in the industry. The 2015 rule discussed
the ability of high flow plants to recycle FGD wastewater back into the
air pollution control system to decrease FGD wastewater flows and
treatment costs. After the 2015 rule, the Tennessee Valley Authority
(TVA) submitted a request seeking a fundamentally different factors
(FDF) variance for its Cumberland power plant.\96\ This variance
request relied primarily on two facts. First, TVA stated that
Cumberland's FGD wastewater flow volumes are several million gallons
per day,\97\ approximately an order of magnitude higher than many other
plants with comparable generation capacity, and millions of gallons per
day higher than the next highest flow rate in the entire industry.\98\
TVA further stated that the FGD system at Cumberland is constructed of
a steel alloy that is susceptible to chloride corrosion. Based on the
typical chloride concentrations in the FGD scrubber, the plant would be
able to recycle little, if any, of the wastewater back to the scrubber
as a means for reducing the flow volume sent to a treatment system.\99\
Second, as a result of the inability to recycle these high FGD flows,
TVA stated that the cost of a biological treatment system would be
high.
---------------------------------------------------------------------------

    \96\ Tennessee Valley Authority (TVA)--Cumberland Fossil Plant--
NPDES Permit No. TN0005789--TVA Request for Alternative Effluent
Limitations for Wet FGD System Discharges Based on Fundamentally
Different Factors Pursuant to 33 U.S.C. 1311(n). April 28, 2016.
    \97\ In the FDF variance, TVA cites to a hypothetical maximum
flow of 9 MGD; however, based on survey responses and discussions
with TVA staff, the company has never approached this flow rate and
does not expect to.
    \98\ Cumberland accounts for approximately one-seventh to one-
sixth of all industry FGD wastewater flows.
    \99\ Reducing the volume purged from the FGD system or recycling
FGD wastewater back to the FGD system can be used to reduce the
volume of wastewater requiring treatment, and thus reduce the cost
of treating the wastes. However, reducing the flow sent to treatment
also has the effect of increasing the concentration of chlorides in
the wastewater, and FGD system metallurgy can impose constraints on
the degree of recycle that is possible.
---------------------------------------------------------------------------

    The final rule subcategorizes plants with FGD purge flows of
greater than four million gallons per day, after accounting for that
plant's ability to recycle the wastewater to the maximum limitations
for the FGD system materials of construction, to avoid placing a
disproportionate cost on such plants. Such a flow reflects the
reasonably predictable flow associated with actual and expected FGD
operations.
    According to TVA's analysis, chemical precipitation plus biological
treatment at that high flow plant would result in a capital cost of
$171 million,

and an O&M cost of approximately $20 million per year.\100\ EPA's cost
estimates are higher than TVA's, a $235 million dollar capital cost
plus $21 million per year in O&M. EPA proposed to find that these costs
are disproportionate, and thus proposed to subcategorize the Cumberland
plant and any other plant with similarly high flows.
---------------------------------------------------------------------------

    \100\ Email to Anna Wildeman. November 13, 2018.
---------------------------------------------------------------------------

    Some commenters argued that EPA cannot legally create a subcategory
of one plant. These commenters suggest that EPA must issue a
fundamentally different factors (FDF) variance rather than create a
subcategory. Other commenters argued that EPA cannot create a
subcategory based on costs alone and that EPA had overestimated costs.
Finally, commenters claimed that EPA reversed previous findings about
the ability to recycle within the Cumberland FGD system without
sufficient explanation.
    With respect to subcategory size, EPA does not agree that the CWA
prohibits the creation of the subcategory for plants with high flows,
and EPA discussed its CWA authority earlier in this section. Here, EPA
has determined that plants that have particularly high FGD flows are
different from other plants in the industry with respect to the
compliance costs they would incur if they were expected to achieve the
otherwise applicable limits based on CP+LRTR. While EPA is currently
aware of only one plant that operates with flows at this high level,
any plant in the industry that operates with these flow levels would
qualify for the different limitations established in this subcategory.
    With respect to FDF variances, EPA does not agree that CWA section
301(n) somehow restricts EPA's authority to establish subcategories.
Rather, section 301(n) provides an ``acceptable alternative to
subcategorizing an industry to account for plant-specific
characteristics.'' Chem. Mfrs. Ass'n v. EPA, 870 F.2d 177, 221 (5th
Cir. 1989) (citation omitted). While EPA is ``not required to establish
separate subcategories for single plants,'' Chem. Mfrs. Ass'n v. EPA,
870 F.2d at 239, it is not prohibited from doing so. Furthermore, FDFs
are different from subcategories in important ways because they
typically are based on information that EPA did not have a chance to
consider in the national rulemaking. See 40 CFR 125.31(a)(2) (a request
for establishment of effluent limitations based on fundamentally
different factors shall be approved only if the factors are
``fundamentally different from those considered by EPA in establishing
the national limitations'').
    With respect to establishing a subcategory based on costs, EPA is
required to consider ``cost'' under the statute, and that includes
consideration of costs for a subcategory. See Chem. Mfrs. Ass'n v. EPA,
870 F.2d 177, 239 (5th Cir. 1989). EPA has broad discretion in deciding
how to account for the consideration factors and the weight to be
accorded to each factor. See Weyerhaeuser Co. v. Costle, 590 F.2d 1011,
1045 (D.C. Cir. 1978); Chem. Mfrs. Ass'n v. EPA, 870 F.2d at 214; Texas
Oil & Gas Ass'n v. EPA, 161 F.3d 923, 928 (5th Cir. 1998). Here, EPA
has determined that total capital costs are a reasonable way to
consider cost in this scenario because they demonstrate the significant
up-front disparity created just to install the system. EPA acknowledges
that the capital cost estimates developed by the Agency at proposal
were, and continue to be for the final rule, higher than TVA's
estimates, but notes that the O&M costs are nearly identical. EPA's
estimated capital costs for Cumberland amount to one quarter of the
total capital costs to the entire industry for treating FGD wastewater
with CP+LRTR, but they would still amount to approximately one fifth if
TVA's estimated capital costs were used. Both instances represent
disproportionately high costs, as compared to the rest of the industry.
Furthermore, while the baseline IPM run discussed below used costs of
the 2015 rule (i.e., CP+HRTR), which are somewhat higher than those for
this final rule, these costs were projected to result in reduction of
Cumberland's operations by 96 percent and partial retirement of the
plant in order to meet the 2015 rule requirements.
    With respect to recycling within the FGD scrubber system, EPA has
not reversed any previous findings. At proposal, EPA found that, based
on the maximum chlorides concentrations allowable in ``once through''
FGD systems, many of these systems could still employ some recycling of
FGD water within the scrubber. For plants like Cumberland, this was
true in 2015 and is true today. The amount of recycling EPA estimated
for Cumberland, however, is small relative to its flows. This recycling
is explicitly accounted for in the 2019 proposal, and now in the final
rule analysis of O&M costs. For further public comments and responses
on the propriety of this subcategory, see DCN SE08615.
    As authorized by section 304(b) of the CWA, which allows EPA to
consider costs, EPA is finalizing a new subcategory for FGD wastewater
based on these unacceptable disparate costs. EPA finds that chemical
precipitation does not impose the same unacceptable disparate costs.
Therefore, the subcategory BAT is based on chemical precipitation, with
effluent limitations for mercury and arsenic.
2. Low Utilization EGUs
    EPA is establishing a new subcategory for EGUs with low utilization
(i.e., peaking EGUs) based on the statutory factors of cost, non-water
quality environmental impacts (including energy requirements), and
other factors the Administrator deems appropriate (i.e., harmonization
with Clean Air Act and CWA regulations which apply to electric
utilities). Low natural gas prices and other factors have led to a
decline in capacity utilization for the majority of coal-fired EGUs.
According to EIA 923 data,\101\ overall coal-fired production for 2017-
2018 was approximately one-third lower than in 2009, with the majority
of EGUs decreasing utilization, some of them significantly. While the
majority of EGUs were base load in 2009, coal-fired EGUs today often
operate as cycling or peaking EGUs, responding to changes in load
demand.\102\
---------------------------------------------------------------------------

    \101\ https://www.eia.gov/electricity/data/eia923/
    \102\ In meetings and conference calls with electric utilities
and trade organizations, several examples were provided of former
base load plants that have since modified operations to be load-
following, or that no longer produce at all except for peak days in
summer or winter. These discussions tracked closely with changes in
production reported in the EIA 923 data.
---------------------------------------------------------------------------

    In light of these industry changes, EPA examined the costs of the
2019 proposed BAT limitations and pretreatment standards for FGD
wastewater and BA transport water on the basis of MWh produced, rather
than the nameplate capacity (which was used to subcategorize EGUs with
50 MW capacity or less in the 2015 rule). Specifically, the Agency
proposed a subcategorization for plants producing less than 876,000 MWh
per year on a rolling two-year basis. EPA received many comments on
this subcategory, including some that suggested different MWh
utilization thresholds or tiering with different limitations for
different thresholds. Some commenters argued that the proposed cutoff
was not based on utilization at all, and that it could apply to very
high utilization EGUs that just happened to have a smaller nameplate
capacity, or recommended that EPA consider other utilization measures
such as the eight percent CUR threshold used in the 2012 Mercury and
Air Toxics Standards rule (77 FR 9304, February 16, 2012). EPA agrees
with the latter comments and has made changes

in the final rule to ensure that this subcategory is focused on low
utilization EGUs and better reflect the intent of this subcategory,
which its name makes apparent. Specifically, EPA has changed how it
determines low utilization from a method which was based on MWh/yr (a
production metric) to one based on utilization as measured by CUR.
    Similar to EPA's finding regarding small units in the 2015 rule,
the record indicates that disparate costs to meet the proposed FGD
wastewater and BA transport water BAT limitations and pretreatment
standards are imposed on EGUs with low capacity utilization.
Specifically, EPA focused its analysis on annualized capital costs as
opposed to O&M costs because O&M costs are often tied to CUR, a measure
of how frequently and to what extent an EGU is generating electricity:
The more an EGU runs, the higher the CUR, and the more residuals it
generates and must pay to dispose of.\103\ In contrast to O&M costs
which correlate to how much an EGU is operating, capital costs do not
vary with generation as they correspond to the original design of a
system that can handle the maximum FGD scrubber purge flow and ash
generation rate such that the system can handle a high-end/peaking
power demand scenario (typically the EGU's nameplate capacity which
would result in a CUR of 100%) and still meet the limitations. Thus, as
utilization decreases, O&M costs are expected to decrease
proportionally, while capital costs are not.
---------------------------------------------------------------------------

    \103\ Unlike residuals, wastewater volumes need not always vary
directly with utilization due to flexibility in how the system is
operated and timing of the generation of wastewater.
---------------------------------------------------------------------------

    Of the EGUs which EPA estimates have production lower than the
proposed rule's 876,000 MWh/yr threshold, nearly two-thirds have a CUR
over 25 percent. This confirms that the subcategory as proposed was
more indicative of low production rather than low utilization. Thus, to
properly evaluate low utilization, EPA compared costs on a CUR basis.
Figure VIII-1 below presents annualized capital costs per MWh produced
versus CUR. These are the costs of Option B (i.e., no
subcategorization) as measured against the status quo, rather than
against the 2015 rule baseline. This figure shows that four to six EGUs
with a CUR between 0 percent and 16 percent have disparately higher
capital costs per MWh produced than facilities with a higher CUR.
[GRAPHIC] [TIFF OMITTED] TR13OC20.002

    Some commenters argued that the CWA does not allow
subcategorization based on costs. Some commenters also argued that
costs should properly be compared on a plant basis, and that costs are
not disparate on a plant basis. EPA disagrees with these comments. See
the discussion in the introduction of this subcategorization section.
EPA also notes that it subcategorized units with a 50 MW nameplate
capacity or less based on disparate costs alone in the 2015 rule, and
that provision of the 2015 rule was not challenged. With respect to
commenters' arguments that the relevant metric is plant costs rather
than unit costs, EPA finds that many decisions to retire, repower, or
upgrade treatment are made at the EGU level, and many other EPA
regulations are tied to EGUs, as discussed below. Thus, an EGU-level
comparison is appropriate when examining disparate costs of this rule.
    In addition to disparate costs, EPA considered non-water quality
environmental impacts (including energy requirements). Because CUR is a
reflection of the frequency and extent of an EGU's generation, LUEGUs
necessarily operate much less frequently, delivering electricity only
during peak loading. For example, EGUs operating for approximately one
month out of the year would have a CUR just over eight percent, but
their continued operation is useful, if not necessary, for ensuring
electricity reliability in the near term. Some commenters disagreed
that electricity reliability is a concern, and they pointed to excess
reserve margins in some regions of the country. EPA acknowledges that
electricity reliability may not be a concern everywhere in the U.S.,
nor will it be a concern in all seasons. For instance, the most recent
NERC winter reliability assessment states, ``Anticipated

resources in all assessment areas meet or exceed their respective
Reference Margin Levels for the upcoming winter period.'' \104\ In
contrast, Figure VIII-2 below presents the most recent (summer 2019)
anticipated reserve margins as well as the reference margin designed to
ensure electric reliability. As seen in that figure, the most recent
summer assessment showed one region (ERCOT) that was not anticipated to
meet its reference margin, and another (MISO) which was anticipated to
be very close to its reference margin (19 percent vs.17 percent).
---------------------------------------------------------------------------

    \104\ NERC (North America Electric Reliability Corporation).
2019. 2019-2020 Winter Reliability Assessment. November. Available
online at: https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC%20WRA%202019_2020.pdf (DCN
SE09093).
[GRAPHIC] [TIFF OMITTED] TR13OC20.003

    The figure above also does not present NERC sub-regions or local
distribution, which may present additional reliability challenges. For
example, one trade association commenter provided an example in
Southeast Michigan where a natural gas distribution system caught fire
during the winter of 2019. The temporary shortage caused by the fire
and cold temperatures caused local auto and semiconductor manufacturers
to shut down or cut production and put Michigan residents at risk of
service interruptions.\105\ To the extent that LUEGUs are able to
remain in service, they would be available to help alleviate these
types of short-term localized shortages and outages.
---------------------------------------------------------------------------

    \105\ U.S. News. 2019. Bitter Cold and Natural Gas Shortages
Shutter Auto Plants. DCN SE08655A081.
---------------------------------------------------------------------------

    Finally, EPA considered an ``other factor[ ]'' the Administrator
deems appropriate,\106\ which is the harmonization of regulations. DOE/
EIA does not define what a peaking unit is, nor do the CAA or CWA.
Nevertheless, EPA has grappled with this issue in previous regulations
under these two statutes. A discussion of these regulatory examples is
provided in Steam Electric Effluent Guidelines Reconsideration--
Evaluation of Final Rule Subcategories (DCN SE09071). These regulations
have in some cases specified a 10 percent CUR, an eight percent CUR, or
have allowed for consideration of CUR in site-specific decisions. This
provides some flexibility in implementing these rules, including
reduced monitoring, different recordkeeping, and alternative compliance
technologies for units meeting the relevant CUR threshold. As is clear
in these examples, EPA has long considered certain low CUR EGUs as
important to local reliability and resiliency of the power grid.
Various definitions of low CUR have been used by EPA programs to
identify where regulatory requirements should be different. While in
all of these example regulations EPA concluded that additional
flexibility was warranted for EGUs based on CUR, EPA did not define
peaking EGUs, nor is the Agency defining peaking EGUs in this final
ELG.
---------------------------------------------------------------------------

    \106\ 33 U.S.C. 1314(b)(1)(B).
---------------------------------------------------------------------------

    EPA has consistently given more flexibility to EGUs operating at
the margins of the electric grid. While EPA has not consistently
implemented the same CUR for all of its regulations, in practice the
difference between eight percent and 10 percent CUR is minor,
approximately one week of operations. Furthermore, while the
subcategory is not limited to EGUs that already operate at these
levels, EPA estimates that only one EGU that will incur costs under
this final rule falls between eight and 10 percent CUR, based on EIA
data from 2017-2018. In light of the range of CURs over which there
appear to be disparate costs, the potential to contribute to reserve
margins or provide local flexibility in case of unexpected capacity
disruption, and the desire to harmonize with the range of CURs that
have been provided additional flexibilities in other EPA rules, the
final rule establishes a subcategory for LUEGUs with an average annual
CUR of less than 10 percent per year averaged over 24 months. For
further public comments and responses on the propriety of this
subcategory, see DCN SE08615.
    Consistent with the proposal, for this low utilization subcategory,
EPA selected chemical precipitation as the technology basis for BAT
limitations and PSES for FGD wastewater, with effluent limitations for
mercury and arsenic. Also, for this subcategory EPA selected composite
lined surface impoundments as the BAT technology basis for BA transport
water and established limitations for TSS based on surface impoundments
in combination with a BMP plan under section 304(e) of the CWA. For
example, surface impoundments that meet the

engineering and design requirements in 40 CFR 257.71 would comply with
this requirement. While EPA projects that some plants in this
subcategory with unlined surface impoundments are likely to meet these
TSS limitations using technologies other than surface impoundments once
they have closed any unlined surface impoundments under the CCR rule,
EPA projects that two plants will continue to operate lined surface
impoundments.\107\
---------------------------------------------------------------------------

    \107\ Furthermore, EPA notes that plants may choose to retrofit
a surface impoundment or construct a new lined surface impoundment
under the CCR rule.
---------------------------------------------------------------------------

    As authorized by section 304(b) of the CWA, which allows EPA to
consider costs, non-water quality environmental impacts (including
energy requirements), and other factors the Administrator deems
appropriate, EPA explicitly finds that additional technologies are not
BAT for this subcategory. Some commenters argued that the technologies
identified for this subcategory do not represent the single best plant
within the subcategory. To an extent, commenters were correct in
identifying more advanced technologies (e.g., biological treatment) in
use within the LUEGU subcategory as it was proposed. However, those
technologies were typically installed when the EGU had been operated at
a much higher utilization rate. Thus, it is not appropriate to draw
conclusions about what BAT for LUEGUs is today based on what might have
been available and economically achievable when these EGUs operated at
greater capacity utilization rates (and would therefore not have
qualified as LUEGUs). In addition, the LUEGU subcategory in the final
rule is narrower than the subcategory EPA proposed, with fewer plants
eligible and fewer plants with advanced technologies in place.
    Other commenters took a different view, suggesting that, for
LUEGUs, BAT should be set equal to BPT. EPA disagrees with these
commenters and declines to set BAT equal to BPT. In this final rule,
EPA finds that chemical precipitation for treatment of FGD wastewater,
by itself, does not impose on LUEGUs the same disproportionate costs as
CP + LRTR and that chemical precipitation is technologically available
and economically achievable. Similarly, the requirement of a BMP plan
to recycle what water can be recycled in a BA transport water system
does not impose on LUEGUs the same disproportionate costs as
installation of a high recycle rate system and is technologically
available and economically achievable. Plants that can achieve some
level of recycle, but not 90 percent, are required to do just that.
While this may still be significant due to changes occurring under the
CCR rule, the fact that significant reductions might occur at little
cost does not make the BMP requirement so burdensome as to warrant
defaulting to BPT.
    In light of the foregoing discussion, EPA finds that chemical
precipitation for FGD wastewater and surface impoundments for BA
transport water, along with a requirement to prepare and implement a
BMP plan under section 304(e) of the Act to reduce pollutant discharges
from BA transport water, are the only technologies that would not
impose disproportionate costs or cause unacceptable non-water quality
environmental impacts for this subcategory. While the Fifth Circuit in
Southwestern Electric Power Company v. EPA, 920 F.3d 999, 1018 n.20
(5th Cir. 2019), found EPA's use of surface impoundments as the
technology basis for effluent limitations on legacy wastewater to be
arbitrary and capricious, the Court left open the possibility that
surface impoundments could be used as the basis for BAT effluent
limitations so long as the Agency identifies a statutory factor, such
as cost, in its rationale for selecting surface impoundments.
    Finally, EPA rejects setting BAT limitations for BA transport water
in this subcategory on a case-by-case basis using BPJ because the
technologies a permitting authority would necessarily consider are the
same dry handling and high recycle rate systems that result in
unacceptable disproportionate costs per MWh and unacceptable non-water
quality environmental impacts, according to EPA's analysis above. For
further public comments and responses on the appropriate BAT for this
subcategory, see DCN SE08615.
3. EGUs Permanently Ceasing Coal Combustion by 2028
    Under the final rule, EPA establishes a subcategory for EGUs
permanently ceasing the combustion of coal by 2028, based on the
statutory factors of cost, the age of the equipment and plants
involved, non-water quality environmental impacts (including energy
requirements), and other factors as the Administrator deems appropriate
(harmonization with the CCR rule alternative closure provisions).
    Some commenters argued that EPA does not have authority to
establish a subcategory for EGUs that are projected to retire because
the CWA does not give it authority to establish a subcategory to
``avoid premature closures'' of plants. EPA disagrees that it lacks
authority to establish the subcategory for EGUs that will cease
combustion of coal by 2028. While it may be true, as commenters
suggested, that Congress contemplated that marginal plants may close
under a BAT standard, it required that EPA consider specific factors in
devising a nationally applicable ELG rule: ``Factors relating to the
assessment of best available technology shall take into account the age
of equipment and facilities involved, the process employed, the
engineering aspects of the application of various types of control
techniques, process changes, the cost of achieving such effluent
reduction, non-water quality environmental impact (including energy
requirements), and such other factors as the Administrator deems
appropriate.'' 33 U.S.C. 1314(b)(2)(B)). And, as stated previously in
this preamble, EPA has considerable discretion in deciding how to
account for the statutory factors and the weight to be accorded to each
factor. See Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1045 (D.C. Cir.
1978); Chem. Mfrs. Ass'n v. EPA, 870 F.2d at 214; Texas Oil & Gas Ass'n
v. EPA, 161 F.3d 923, 928 (5th Cir. 1998). Based on the consideration
of the statutory factors presented below, EPA is within its statutory
authority to establish different limitations for such plants to help
avoid unacceptable impacts.\108\
---------------------------------------------------------------------------

    \108\ It is of no moment that, in 2015, EPA declined to
establish different limits for plants that might soon retire. EPA is
free to change its mind as a matter of policy, so long as it
explains its decision. FCC v. Fox Television Stations, Inc., 556
U.S. 502, 515 (2009); Motor Vehicle Mfrs. Ass'n v. State Farm Mutual
Auto. Ins. Co., 463 U.S. 29, 42 (1983). That one EPA Administrator
may weigh the statutory consideration factors differently from a
previous one does not make the decision arbitrary, particularly
where courts have long held that the Administrator has considerable
discretion in weighing the factors. See also Nat'l Ass'n of Home
Builders v. EPA, 682 F.3d 1032, 1038 & 1043 (D.C. Cir. 2012) (a
revised rulemaking based ``on a reevaluation of which policy would
be better in light of the facts'' is ``well within an agency's
discretion,'' and `` `[a] change in administration brought about by
the people casting their votes is a perfectly reasonable basis for
an executive agency's reappraisal' '' of its policy choices)
(citations omitted).
---------------------------------------------------------------------------

    EPA proposed to include only retiring EGUs in this subcategory but
solicited comment on the inclusion of repowering EGUs. Electric utility
commenters across the board suggested that EPA include all EGUs that
would cease the combustion of coal, and thus the generation of the
wastewaters regulated under this final rule. EPA agrees with these
comments. EGUs that are repowering cease generation of BA transport
water and FGD wastewater, just as retiring EGUs do. Furthermore,
inclusion of repowering EGUs will enhance harmonization of the rules

applicable to this industry and give greater clarity to the regulated
community. As discussed in the CCR Part A final rule, the alternative
closure provisions for surface impoundments where there is ``permanent
cessation of the coal fired boiler'' in Section 257.103(f)(2) includes
surface impoundments at EGUs that convert to natural gas or other
fuels. The final subcategory in this ELG final rule adopts nearly
identical terminology as the language in Section 257.103(f)(2) of CCR
Part A. EPA believes the phrase used in Sec.  423.11(w) of this rule
``permanent cessation of coal combustion'' will avoid confusion over
the intent to include repowering EGUs, and is intended to parallel the
EGUs that would be able to satisfy Section 257.103 of the CCR rule.
Thus, adopting the same approach for these ELGs will create consistency
and certainty for the regulated community. Furthermore, not treating
repowering as equivalent to closure could create an unfavorable
incentive for a plant that desires to continue operating to, instead of
repowering, retire and construct a new EGU on a greenfield, rather than
use existing infrastructure. It would be better environmentally for the
plant to use existing transmission and distribution infrastructure
where possible to limit potential new impacts from greenfield project
development. Therefore, as described below, this subcategory includes
repowering EGUs.
    EPA has continued to gather information about plant and EGU
retirements, deactivations, and fuel conversions since the 2015 rule
from company announcements, industry public comments, and government
databases as discussed in Changes to Industry Profile for Coal-Fired
Generating Units for the Steam Electric Effluent Guidelines Final Rule
memorandum (DCN SE08688). In the 2019 proposed rule, EPA identified 107
plants which had announced, commenced or completed such actions since
the development of the 2015 rule record, the most frequently stated
reason in these public statements or filings being market forces, such
as the continued low price of natural gas (49 plants).\109\ This was
followed by other reasons (46),110 111 environmental
regulations (33),\112\ and consent decrees (10). The fact that
environmental regulations were listed in these public statements or
filings by nearly one-third of these plants and that ELGs were
specifically listed by some respondents suggests that additional
flexibility may help to avoid premature closures of some plants and/or
EGUs. As presented in Figure VIII-2 and section VII.C.2 of the preamble
above, the most recent summer assessment showed one region (ERCOT) that
was not anticipated to meet its reference margin, and another (MISO)
which was anticipated to be very close to its reference margin (19
percent vs.17 percent). Thus, EPA concludes that premature closure of
some plants and/or EGUs is an unacceptable non-water quality
environmental impact because it could impact reliability. Therefore the
avoidance of these premature closures weighs in favor of
subcategorization.
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    \109\ This is consistent with recent analyses of the costs of
coal-fired electric power generation versus other sources. Examples
include: (1) https://www.bloomberg.com/news/articles/2018-03-26/half-of-all-u-s-coal-plants-would-lose-money-without-regulation;
(DCN SE09094). (2) https://insideclimatenews.org/news/25032019/coal-energy-costs-analysis-wind-solar-power-cheaper-ohio-valley-southeast-colorado (DCN SE09095).
    \110\ Announcements for some power plants cited several
rationales, hence the numbers do not add to 107.
    \111\ ``Other'' includes age, reliability of the plant, emission
reduction goals, decreased local electricity demand, plant site
limitations, and company goals to invest in clean/renewable energy.
    \112\ Approximately 31 percent of the facilities identified
specific environmental regulations affecting their decision-making.
Specific environmental regulations, when mentioned, included CPP,
MATS, ELGs, CCR Rule, and Regional Haze Rules.
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    Some commenters took issue with EPA's analysis of a hypothetical
plant (see 84 FR 64640, November 22, 2019) and suggested that EPA
should have evaluated the costs and pollutant loadings of EGUs that
fall into this subcategory. EPA agrees with the latter suggestion, and
the final rule thus includes in the baseline all EGUs retiring and
repowering after 2023 (the latest compliance deadlines in the 2015
rule). For those EGUs that would be subcategorized as permanently
ceasing coal combustion by 2028, EPA evaluated the changes in costs and
pollutant loads under regulatory Option A.
    As noted above, EPA gathered readily available information from
publicly available sources, company announcements, industry public
comments, and government databases to identify EGUs. A list of EGUs EPA
believes to be retiring or repowering between 2024 and 2028 is
presented in Changes to Industry Profile for Coal-Fired Generating
Units for the Steam Electric Effluent Guidelines Final Rule memorandum
(DCN SE08688). Twenty-three EGUs at 12 plants may incur costs under the
final rule absent a subcategory for units ceasing coal combustion by
2028.\113\ Under Option B, these EGUs combined have estimated capital
costs of $209 million and estimated O&M costs of $21 million per year,
leading to combined annualized costs as high as $63 million per
year.\114\ When compared to the costs per MWh for EGUs not ceasing coal
combustion by 2028, the shorter amortization periods for these LUEGUs
lead to much higher costs per MWh in some cases. For example, while
Winyah Unit 2 and Will County Unit 4 have approximate costs of $6/MWh
under a normal 20-year amortization period, over the shortened
amortization period these costs jump to over $10/MWh. These costs would
both be among the highest, if not the highest, costs absent a
subcategory for units ceasing coal combustion by 2028.
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    \113\ Three EGUs at two plants are expected to retire or cease
burning coal between permit renewal and the no later than compliance
date.
    \114\ This upper bound assumes costs are all incurred between
2021 and the announced year of closure or conversion to a different
fuel source.
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    EPA received comments that the compliance deadline for this
subcategory should be different. Commenters suggesting a longer time
frame proposed site-specific extensions past 2028, or later dates for
LUEGUs. Some commenters also suggested that this time frame was too
long for a variety of reasons. With respect to comments that the time
frame should be shortened, EPA received comments presenting the time
frame for building replacement capacity. One example provided by
Southern Company demonstrated a real-world case where the construction
of the natural gas replacement EGUs took eight years from the initial
coal EGU retirement decision.\115\ Furthermore, as presented above, EPA
has demonstrated that costs are disparate over these shorter time
frames. Even if commenters disagree with EPA's characterization of
these time frames as short, compressing cost recovery into these
smaller amortization periods does result in disproportionate costs.
Responding to comments that the time frame should be lengthened, EPA
further examined the 24 EGUs that have announced retirement or fuel
conversion after 2028 presented in Steam Electric Effluent Guidelines
Reconsideration--Evaluation of Final Rule Subcategories (DCN SE09071).
Of these 24 EGUs, only four EGUs at two plants are projected to incur
costs under a final ELG rule. These EGUs will continue burning coal
until 2033 and 2035, meaning that they will be able to

amortize their costs over a time frame closer to the estimated 20-year
amortization period used for the industry as a whole. Unlike the EGUs
ceasing coal combustion by 2028, the costs per MWh of these four EGUs
do not increase significantly when evaluated with a shortened
amortization period, and appear to fall in the range of the rest of the
industry. Thus, changes to the latest year for permanent cessation of
coal combustion is not justified based on disparate costs.\116\
Finally, with respect to both sets of comments suggesting longer and
shorter time frames, changing the time frames would eliminate
harmonization with the CCR rule. The CCR Part A rule finalized
alternative closure provisions under 257.103(f) for coal-fired EGUs
that permanently cease by 2028. For EPA to have requirements with that
date under the CCR rule and a different date (earlier or later) for
requirements under the ELGs would introduce unnecessary confusion and
potentially limit the flexibilities deliberately afforded to the
regulated community under one or both regulations. In meetings with
EPA, utilities expressed two other concerns related to retiring or
repowering units which would support this subcategory and the
associated time frames. First, several utilities discussed the
possibility that public utility commissions (PUC) would not allow cost
recovery for equipment purchased near the end of a plant's useful life,
resulting in stranded assets. Although the utilities indicated that
PUCs have historically allowed for cost recovery even after the
retirement of an EGU, they provided recent examples of PUCs rejecting
cost recovery, which makes the prospect of continued recovery after
retirement less certain. Second, utilities expressed the need for
sufficient time to plan, construct, and obtain necessary permits and
approvals for replacement generating capacity. In discussions of
example Integrated Resource Plans (IRPs) and the associated process,
utilities suggested timelines that would extend for five to eight years
or longer.\117\
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    \115\ While replacement capacity may not be necessary in all
cases, the Agency believes that it should not tie the hands of
electric utilities by foreclosing the possibility.
    \116\ While it is possible additional plants might choose to
retire or repower soon after 2028 and have not yet announced their
intent to do so, it is not possible to predict such possibilities.
    \117\ Utilities also shared instances of very quick turnaround
in some cases.
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    Finally, the North American Electric Reliability Corporation (NERC)
recently conducted an aggressive stress test scenario identifying the
reliability risks if large baseload coal and nuclear plants were to
bring their projected retirement dates forward.\118\ That report found
that if retirements happen faster than the system can respond (by
constructing new base load, e.g.), significant reliability problems
could occur. NERC cautions that, though this stress test is not a
predictive forecast,\119\ the findings are consistent with the concern
that electric utilities conveyed to EPA, viz., that the well-planned
construction of new generation capacity and orderly retirement of older
plants are vital to ensuring electricity reliability. While EPA
received comments that the scenarios that EPA evaluated at proposal did
not result in the same level of retirements as the NERC stress test,
any retirements caused by EPA, including under this regulation, could
contribute to such a scenario. Furthermore, as presented in the
discussion of LUEGUs above, inadequate reserve margins in some regions
and commenter-provided examples of electricity upsets support EPA's
view that marginal plants should not be forced into retirement while
they still have a useful role to play in ensuring electric reliability.
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    \118\ North American Electric Reliability Corporation (NERC).
2018. Special Reliability Assessment: Generation Retirement
Scenario. Atlanta, GA 30326. December 18. Available online at:
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_Retirements_Report_2018_Final.pdf. (DCN SE09096)
    \119\ ``NERC's stress-test scenario is not a prediction of
future generation retirements nor does it evaluate how states,
provinces, or market operators are managing this transition.
Instead, the scenario constitutes an extreme stress-test to allow
for the analysis and understanding of potential future reliability
risks that could arise from an unmanaged or poorly managed
transition.''
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    In light of the information discussed above, and EPA's authority
under section 304(b) to consider cost, the age of equipment and plants
involved, non-water quality environmental impacts (including energy
requirements), and other factors that the Administrator deems
appropriate, EPA is establishing a new subcategory for EGUs that plan
to permanently cease combustion of coal no later than December 31,
2028, subject to a certification requirement (described in Section
XIV). For this subcategory, EPA is establishing BAT limitations for TSS
for both FGD wastewater and BA transport water based on surface
impoundments as the selected technology basis.\120\ Some commenters
disputed EPA's selected technology basis for EGUs in this subcategory.
Comments argued that EPA cannot legally select surface impoundments for
this subcategory, failed to base BAT on the best performing plant in
the subcategory, and failed to consider that units in this subcategory
could lease rather than purchase equipment to help meet the final
limitations. As mentioned above, the Fifth Circuit's decision in
Southwestern Electric Power Company v. EPA left open the possibility
that surface impoundments could be used as the basis for BAT effluent
limitations, so long as the Agency identifies a statutory factor, such
as cost, in its rationale for selecting surface impoundments. For
further public comments and responses on this subcategory, see DCN
SE08615.
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    \120\ EPA is not specifying that the BAT technology basis is
composite lined impoundments here, as it did for the low utilization
subcategory, because under the CCR rule, plants must cease receiving
waste in their unlined surface impoundments by April 11, 2020, but
plants that need additional time to develop alternate capacity to
manage their wastestreams may continue to use their unlined surface
impoundments under the alternative closure provisions of 40
CFR257.103(f)(1) or (2). Units falling within the alternative
closure provision of (f)(2) must both complete closure of their
unlined surface impoundments and permanently cease combustion of
coal by 2023 or 2028 (depending on size of the impoundment). Thus,
use of unlined surface impoundments under the ELG up to that date
would be compatible with the CCR rule, and nothing in this final ELG
would authorize the use of an unlined surface impoundment outside of
these CCR Part A rule flexibilities.
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    Next EPA examined the treatment technologies employed at plants
that have units that qualify for this subcategory. Four of the 12
plants retiring or repowering between 2024 and 2028 are projected to
incur FGD wastewater costs. Of these, two have chemical precipitation,
one has chemical precipitation plus biological treatment, and the
remaining plant has physical settling via surface impoundments. The one
plant with biological treatment is Duke Energy's Allen Steam Station,
which installed an HRTR system more than 10 years ago. Thus, unlike
other plants with no current treatment, this plant has had sufficient
time to amortize its costs. The fact that a plant could absorb the
costs of an advanced wastewater treatment technology a decade ago when
it operated at a much higher utilization does not demonstrate that,
moving forward, plants already planning to retire could absorb such
costs. For BA transport water, nine of the 12 plants will incur BA
transport water costs under this final rule. Four of these plants
already operate high recycle rate systems, while the remaining five
plants only have wet sluice of their ash to surface impoundments.
Again, the fact that a plant could easily absorb the costs of such
systems previously, does not indicate that such systems are BAT moving
forward.
    Finally, although EPA agrees with commenters that a wide variety of

wastewater treatment systems are available to lease, availability alone
does not eliminate the issues already identified. Commenters provided
information that systems were available for lease but did not provide
information that leasing a treatment system would be less costly than
the alternative. In contrast, during one of the conference calls
identified above, EPA learned that one utility had conducted an
evaluation of leasing equipment for one of its plants. At that plant,
the leasing option was not less costly than purchasing and installing
the same equipment. Data in the record regarding costs of leasing FGD
wastewater treatment systems is limited. EPA had meetings or conference
calls with several vendors and plants regarding leasing treatment
equipment, but only obtained specific cost data for a single plant. EPA
used the information provided about this plant to evaluate leasing in
Cost to Lease Flue Gas Desulfurization Wastewater Treatment memorandum
(DCN SE08633). For further public comments and responses on the issue
of costs associated with leasing FGD wastewater treatment systems, see
DCN SE08615.
    After considering the information above, EPA finds that additional
technologies such as chemical precipitation, CP+LRTR, CP+HRTR, membrane
filtration, or thermal technologies for FGD wastewater, and the dry
handling/closed-loop technologies or high recycle rate BA transport
water technologies are not BAT for this subcategory due to the
unacceptable disproportionate costs they would impose; the potential of
such costs to accelerate retirements of EGUs at this age of their
useful life; the resulting increase in the risk of electricity
reliability problems due to those accelerated retirements; and the
harmonization with the CCR rule. EPA finds that surface impoundments
are the only technology that would not impose such disproportionate
costs on this subcategory of EGUs. Establishing surface impoundments as
BAT for this subcategory alleviates the choice for these plants to
either pass on disparately high capital costs over a shorter useful
life or risk the possibility that post-retirement rate recovery would
be denied for the significant capital and operating costs associated
with the final rule. This subcategory also allows electric utilities to