purge rate of 10 percent that can be adjusted upward or downward based
on site-specific operating data. Finally, the EPA solicits comment on
whether these discharges should be capped at a specific flow. The EPA
requests commenters identify and include available data or information
to support their recommended approach.
---------------------------------------------------------------------------

    \44\ The 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 facility.
---------------------------------------------------------------------------

    Under either option discussed above for determining discharge
allowances (10 percent 30-day rolling average or site-specific), there
may be wastewater from whatever is purged by the high recycle rate
system, and plants may wish to discharge this wastewater. Two
considerations make determining a nationwide BAT for these discharges
challenging and fact-specific. First, in the case of precipitation or
maintenance-related purges, such purges would be potentially large
volumes at infrequent intervals.\45\ Each facility necessarily has
different climates and maintenance needs that could make selecting a
uniform treatment system more difficult. Second, utilities have stated
that discharges of wastewater associated with high rate recycle 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 facilities.
---------------------------------------------------------------------------

    \45\ In the case of precipitation, rainfall exceeding a 25 year,
24-hour event may only happen once during the 20-year lifetime of
the equipment, if at all.
---------------------------------------------------------------------------

    In light of the information discussed above, and the 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), the EPA proposes that BAT
limitations for any wastewater that is purged from a high recycle rate
system and then discharged be established by the permitting authority
on a case-by-case basis using BPJ. The EPA assumes permitting
authorities will be in a better position than the EPA to examine site-
specific climate and maintenance factors for infrequent events.
Permitting authorities will also be in a better position than the EPA
to account for site-specific treatment technologies and their
configurations already installed or being installed to comply 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. The EPA
also solicits comment on technologies that could serve as the basis for
BAT for this discharge and what technologies state permitting
authorities may consider as BPJ. For example, the EPA solicits comment
on whether surface impoundments could be selected as BAT based on high
costs to control the purge with other technologies. The EPA further
solicits comment on whether delaying the selection of appropriate
treatment technology though the BPJ process masks the true cost of this
proposed rule for both the regulated entity and the regulatory agency
that must undertake the evaluation and ultimately establish BPJ. The
EPA also solicits comment on whether the EPA should constrain BPJ by
precluding the consideration of some technologies (e.g., zero
discharge) using nationwide application of the statutory factors. The
EPA solicits any data, information or methodologies that may be useful
in evaluating the potential costs of establishing and complying with as
yet undetermined BPJ requirements.
    The EPA is not proposing to identify surface impoundments as BAT
for BA transport water except for BATW purge 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
facilities 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 the majority of facilities with operating ponds likely will
cease sluicing waste to their ponds in the near future. In the 2015 CCR
rule, the EPA estimated that it would be less costly for facilities to
install under-boiler or remote drag chain systems and send BA to
landfills rather than continue to wet sluice BA and replace unlined
ponds with composite lined ponds. This supports the suggestion that
surface impoundments are not BAT for all facilities. However, the EPA
proposes to identify surface impoundments as BAT for two subcategories,
as discussed later in this section.
3. Rationale for Voluntary Incentives Program (VIP)
    As part of the BAT for existing sources, the 2015 rule established
a VIP that provided the certainty of more time (until December 31, 2023
instead of a date determined by the permitting authority that is as
soon as possible beginning November 1, 2018) for facilities to
implement new BAT limitations if they adopted additional process
changes and controls that achieve limitations on mercury, arsenic,
selenium and TDS in FGD wastewater, based on thermal evaporation
technology. 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. The EPA expected this additional time, combined with
other factors (such as the possibility that a facility's NPDES

permit may need more stringent limitations to meet applicable water
quality standards), would lead some facilities to choose this option
for future implementation by incorporating the VIP limits into their
permit during the permit application process. New information in
several utilities' internal analyses and contractor reports provided to
the EPA since the 2015 rule, as well as meetings with utilities, EPC
firms, and vendors indicates that facility decisions to install the
more expensive thermal systems were driven by water quality-based
effluent limitations imposed by the NPDES permitting authority.
Furthermore, such documents and meetings also show that several
facilities considered installing membrane filtration technologies under
the 2015 rule VIP as well, and thus the EPA evaluated membrane
filtration as an alternative basis for VIP.
    The EPA proposes to revise the VIP limitations established in the
2015 rule using membrane filtration as the technology basis because it
costs less than half the cost of thermal technology and has comparable
pollutant removal performance. Membrane filtration achieves pollutant
removals comparable to thermal systems in situations where the thermal
system would discharge. Engineering documents for some individual
facilities evaluated this technology as a zero liquid discharge system
which would recycle permeate into the plant. Due to the higher costs of
thermal systems compared to chemical precipitation followed by LRTR,
the EPA does not expect that any facility would install a new thermal
system under the 2015 rule VIP as the least cost technology. As
authorized by section 304(b) of the CWA, which allows the EPA to
consider costs, the EPA proposes membrane filtration as the technology
basis for the VIP BAT limitations, with limitations for mercury,
arsenic, selenium, nitrate-nitrite, bromide, and TDS.\46\
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    \46\ Note that the 2015 rule did not include limitations for
nitrate/nitrite or bromide.
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    Second, as authorized by section 304(b) of the CWA, which allows
the EPA to consider process changes and non-water quality environmental
impacts, the EPA proposes to revise the compliance date for the VIP
limitations to December 31, 2028. That is the date the EPA has
determined that the membrane filtration technology will be available
nationwide, as that term is used in the CWA, for those facilities who
choose to adopt it. This timeframe is based on the amount of time
necessary to pilot, design, procure, and install both the membrane
filtration systems and the brine management systems. The EPA notes that
this is similar to the eight-year period between promulgation of the
2015 rule and the 2023 deadline for the current voluntary incentives
program. The EPA proposes to find that forthcoming changes in membrane
filtration brine disposal options may significantly reduce the non-
water quality environmental impacts associated with encapsulation,
discussed in Section VII(b)(i) above. Through discussions with several
utilities and EPRI, the EPA learned that a forthcoming paste technology
may allow facilities 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 existing 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, could reduce the volumes and pollutant concentrations in
leachate.47 48 A compliance date of December 31, 2028, would
have the advantage of allowing this forthcoming paste technology
potentially enough time to become available, allow facilities more time
to permit landfill cells for brine encapsulated with FA and lime if
needed, and conduct pilot testing, demonstrations, and further analyses
to fully understand and incorporate the process changes associated with
membrane filtration operation, and understand the long term performance
of the technology for treatment of FGD waste.
---------------------------------------------------------------------------

    \47\ 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/.
    \48\ Although the 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.
---------------------------------------------------------------------------

    One remaining challenge identified for this paste technology is
developing approaches to manage wastes (e.g., flush water) from
periodic cleaning of the paste transportation piping, where such piping
is used.\49\ As authorized by section 304(b) of the CWA, which allows
the EPA to consider the process employed, the EPA is proposing a
modification of the definition of FGD wastewater and ash transport
water to explicitly exclude water used to clean FGD paste piping so
that facilities using paste piping for brine encapsulation and disposal
in an on-site landfill can more easily clean residual paste from pipes.
---------------------------------------------------------------------------

    \49\ 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.
---------------------------------------------------------------------------

    Taken together, the EPA's proposed changes to the VIP would give
facilities greater flexibility when choosing a technology, while
continuing to achieve pollutant reductions beyond the BAT limitations
that are generally applicable to the industry and currently available
nationwide. Under Option 2, the EPA estimated that 18 plants (27
percent of plants estimated to incur FGD compliance costs) may opt into
the VIP program and under Option 3 the number rises to 23 plants (34
percent of plants estimated to incur FGD compliance costs). The EPA
solicits comment on the accuracy of the cost estimates indicating that
these plants would opt into the revised VIP program, including data
identifying costs that may be potentially excluded from this analysis.
Specifically, the EPA solicits data and information on any potential
technology limitations, commercial availability, and other limitations
that may affect plants' ability to adopt the VIP limits by the proposed
VIP compliance date of 2028.

C. Additional Proposed Subcategories

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

    \50\ Age is a statutory factor for BAT. CWA section 304(b), 233
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. \51\
---------------------------------------------------------------------------

    \51\ 80 FR 67856.

    For these subcategorized units, in the 2015 rule the EPA
established differentiated limitations based on surface impoundments
(i.e, setting BAT equal to BPT limitations for TSS).
    As part of this proposal, the EPA is not proposing a change to the
2015 rule subcategorization of small and oil-fired boilers; therefore,
these boilers have limitations for TSS. The EPA is incorporating and
expanding on its previous analysis of characteristics and possible
differences within the industry. The EPA proposes further
subcategorization for FGD wastewater and BA transport water for boilers
with low utilization and boilers with limited remaining useful life. In
addition, for FGD wastewater, the EPA proposes to subcategorize units
with high FGD flows. These proposed subcategories are discussed below.
1. Subcategory for Facilities With High FGD Flows
    The EPA is proposing to establish a new subcategory for facilities
with high FGD flows based on the statutory factor of cost. The 2015
rule discussed the ability of high-flow facilities 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
facility.\52\ This variance request relied primarily on two facts.
First, TVA stated that Cumberland's FGD wastewater flow volumes are
several million gallons per day,\53\ approximately an order of
magnitude higher than many other units with comparable generation
capacity, and millions of gallons per day higher than the next highest
flow rate in the entire industry.\54\ 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 facility 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.\55\
Second, as a result of the inability to recycle these high flows, TVA
stated that the cost of a biological treatment system would be high.
---------------------------------------------------------------------------

    \52\ 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.
    \53\ 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.
    \54\ Cumberland accounts for approximately one-sixth to one-
seventh of all industry FGD wastewater flows.
    \55\ 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 EPA proposes to subcategorize facilities with FGD purge flows
greater than four million gallons per day, after accounting for that
facility's ability to recycle the wastewater to the maximum limits for
the FGD system materials of construction to avoid placing a
disproportionate cost on such facilities.\56\ Such a flow reflects the
reasonably predictable flow associated with actual and expected FGD
operations.
---------------------------------------------------------------------------

    \56\ Although it is theoretically possible that another coal
facility could be built, or an FGD system installed, that resulted
in flows of this volume, in practice, all FGD systems in the past
decade have been built with materials that allow for recycling of
the FGD wastewater. While facilities with these characteristics
could potentially apply for an FDF variance, the EPA is proposing to
subcategorize them instead because it currently has sufficient
information to do so and because FDF variances are governed by
strict timelines and procedural requirements set forth in 33 U.S.C.
1311(n).
---------------------------------------------------------------------------

    According to TVA's analysis, chemical precipitation plus biological
treatment would result in a capital cost of $171 million, and an O&M
cost of approximately $20 million per year.\57\ The EPA's cost
estimates are even higher than TVA's (a $256 million dollar capital
cost plus $21 million per year in O&M). These costs are five to six
times higher than comparable costs at facilities selling similar
numbers of MWh per year.\58\ Passing these disparately higher costs on
to consumers would likely put the facility at a competitive
disadvantage with other coal-fired facilities not subject to the same
capital and operating costs. As authorized by section 304(b) of the
CWA, which allows the EPA to consider costs, the EPA proposes a new
subcategory for FGD wastewater based on unacceptable disparate costs.
For such facilities, the EPA proposes to establish BAT based on
chemical precipitation alone, with effluent limitations for mercury and
arsenic.
---------------------------------------------------------------------------

    \57\ Email to Anna Wildeman. November 13, 2018.
    \58\ This would generally also hold true for the costs of other
FGD technology options at comparable facilities.
---------------------------------------------------------------------------

2. Subcategory for Boilers With Low Utilization
    The EPA is proposing to establish a new subcategory for boilers
with low utilization based on the statutory factors of cost and non-
water quality environmental impacts (including energy requirements).
Low natural gas prices and other factors have led to a decline in
capacity utilization for the majority of coal-fired boilers. According
to EIA 923 data,\59\ overall coal-fired production for 2017 decreased
by approximately one-third from 2009 levels, with the majority of
boilers decreasing utilization, sometimes significantly. While the
majority of boilers in 2009 were base load, making nameplate capacity a
good indicator of electricity production, coal-fired boilers today
often operate as cycling or peaking boilers, responding to changes in
load demand.\60\
---------------------------------------------------------------------------

    \59\ https://www.eia.gov/electricity/data/eia923/.
    \60\ In conversations with electric utilities, several examples
were given of former base load facilities which have since modified
operations to be load-following, or which no longer produce 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, the EPA examined the costs of
the proposed BAT limitations and pretreatment standards for FGD
wastewater and BA transport water on the basis of MWh produced, rather
than the nameplate capacity used to subcategorize boilers less than or
equal to 50 MW in the 2015 rule. Due to changed utilization, nameplate
capacity has become less representative of electricity production.
Nevertheless, the EPA is not proposing any changes to the 50 MW
nameplate capacity subcategory of the 2015 rule as that subcategory
applied to additional wastestreams not part of this proposal (e.g., fly
ash), and has already been implemented in some permits. Thus, the EPA
focused on MWh production for boilers greater than 50 MW nameplate
capacity, as discussed below.
    Similar to the EPA's finding regarding small boilers 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 boilers with low capacity utilization. Figure
VIII-1 below presents costs per MWh produced as measured against the
status quo, rather than against the 2015 rule baseline. As can be seen
in this figure, there is a significant difference between boilers above
and below 876,000 MWh per year.\61\ As a result of

these disparate costs, the EPA proposes an additional subcategory for
low capacity utilization boilers producing less than 876,000 MWh per
year. Many of these boilers are either close to the 50 MW nameplate
capacity of the 2015 rule (e.g., a 100 MW boiler running at 100%
capacity), or somewhat larger units that have continued to reduce
electricity generation due to market forces (e.g., a 400 MW boiler
running at 25% capacity). The latter group are expected to produce
fewer and fewer MWh per year, moving those boilers further toward the
high $/MWh costs over time. Attempting to pass on the higher costs per
MWh produced would make these boilers increasingly uncompetitive,
exacerbating the disparate cost impacts.
---------------------------------------------------------------------------

    \61\ This is the equivalent of a 100 MW boiler running at 100
percent capacity or a 400 MW boiler running at 25 percent capacity.
[GRAPHIC] [TIFF OMITTED] TP22NO19.000

    In addition to  disparate costs, the EPA considered non-water
quality environmental impacts (including energy requirements). Low
utilization boilers tend to operate only during peak loading. Thus,
their continued operation is useful, if not necessary, for ensuring
electricity reliability in the near term.
---------------------------------------------------------------------------

    \62\ While the EPA only presents the disparate costs of one
technology in this figure, a similar comparison could be made for
the technologies comprising Options 1 or 4 for a final rule. No
comparison is necessary for Option 2 as that option already
incorporates the subcategorization that eliminates these disparate
costs.
---------------------------------------------------------------------------

    In light of the information discussed above, the EPA proposes to
establish a subcategory for low utilization units producing less than
876,000 MWh per year. The EPA solicits comment on whether this
subcategory should be based on alternative utilization thresholds. For
this subcategory, the EPA proposes to select chemical precipitation as
the technology basis for BAT for FGD wastewater, with effluent
limitations for mercury and arsenic. The EPA solicits comment on
whether chemical precipitation is appropriate and economical or if
other approaches would be appropriate. The EPA requests commenters
identify and include available data or information to support their
recommended approach. Also, for this subcategory, as it did for the
subcategories established in the 2015 rule, the EPA proposes to select
surface impoundments as the BAT technology basis for BA transport water
and establish limitations for TSS based on surface impoundments in
combination with a BMP plan under section 304(e) of the Act. Although
facilities are likely to meet these TSS limits using technologies other
than surface impoundments once they have closed any unlined surface
impoundments under the CCR rule, facilities may choose to retrofit a
surface impoundment or construct a new surface impoundment. As
authorized by section 304(b) of the CWA, which allows the EPA to
consider costs, the EPA proposes to find that additional technologies
are not BAT for this subcategory due to the unacceptable
disproportionate costs per MWh those technologies would impose.
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, are the only technologies the EPA proposes to find would
not impose such disproportionate costs on this subcategory of boilers.
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, the EPA proposes to find that allowing
permitting authorities to set BAT limitations for BA transport water on
a case-by-case basis using BPJ for this subcategory would be equally
problematic. 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, according to the
EPA's analysis above. The EPA solicits comment on whether the impacts
of the proposed revisions to the CCR rule could result in a different
analysis from the disparate

costs presented above. The EPA also solicits comment on other options
to address the disproportionate impacts identified above.
3. Subcategory for Boilers Retiring by 2028
    The EPA is proposing to establish a new subcategory for boilers
retiring by 2028 based on the statutory factors of cost, the age of the
equipment and facilities involved, non-water quality environmental
impacts (including energy requirements), and other factors as the
Administrator deems appropriate. The EPA has continued to gather
information about facility and boiler retirements, deactivations, and
fuel conversions since the 2015 rule. Of the 107 facilities that the
EPA identified in Section 3 of the Supplemental TDD that have
announced, commenced or completed such actions, the most frequently
stated reason was market forces, such as the continued low price of
natural gas (49 facilities).\63\ This was followed by environmental
regulations (33),\64\ consent decrees (10), and other reasons
(46).65 66 The fact that environmental regulations were
cited by approximately one-third of these facilities and that ELGs were
specifically mentioned by some respondents suggests that additional
flexibility may help to avoid premature closures for some facilities
and/or boilers.
---------------------------------------------------------------------------

    \63\ This is consistent with recent analyses of the costs of
coal-fired electric 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;
    (2) https://insideclimatenews.org/news/25032019/coal-energy-costs-analysis-wind-solar-power-cheaper-ohio-valley-southeast-colorado.
    \64\ Approximately 31 percent of the facilities identified
specific environmental regulations affecting the decision-making
process. When specific environmental regulations were stated, they
included CPP, MATS, ELGs, CCR Rule, and Regional Haze Rules.
    \65\ Some announcements cited several rationales, hence the
numbers do not add to 107.
    \66\ ``Other'' includes age, reliability of the facility,
emission reductions goals, decreased local electricity demand,
facility site limitations, and company goals to invest in clean/
renewable energy.
---------------------------------------------------------------------------

    To further explore this, the EPA examined the cost implications of
complying with the proposed limitations and standards on a dollar-per-
MWh-produced basis under hypothetical boiler retirement scenarios. Cost
estimates for this proposal assume that facilities will amortize
capital and O&M costs across the 20-year life of the technologies (see
Section 5 of the Supplemental TDD), so the EPA only examined retirement
scenarios within the next 20 years. Furthermore, since O&M costs are
already spread out over time, the EPA focused on capital costs, which
also tended to make up a sizeable portion of costs in the EPA's
estimates. Finally, the EPA looked at both three and seven percent
discount rates. The analysis showed that a facility could be forced to
pass on capital costs per MWh 10 to 15 times higher than those passed
on with the assumed 20-year amortization in the EPA's cost estimates,
and the costs per MWh remain more than double the EPA's estimates until
amortization of six to eight years, depending on the discount rate.
    In meetings with the EPA, utilities expressed two other concerns
related to retiring units. First, several utilities discussed the
potential for stranded assets where equipment would be purchased near
the end of a facility's useful life and the public utility commission
(PUC) would not allow cost recovery. Although the utilities indicated
that PUCs have historically allowed for cost recovery even after the
retirement of a boiler, they provided recent examples of PUCs rejecting
cost recovery, which make the prospect of continued recovery after
retirement less certain. Second, the 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.\67\
---------------------------------------------------------------------------

    \67\ Utilities also shared instances of very quick turnaround in
some cases.
---------------------------------------------------------------------------

    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 facilities were to
bring their projected retirement dates forward.\68\ That report found
that if these retirements happen faster than the system can respond
(e.g., construction of new base load), significant reliability problems
could occur. NERC cautions that, though this stress test is not a
predictive forecast,\69\ the findings are consistent with the concern
that electric utilities conveyed to the EPA: That the well-planned
construction of new generation capacity and orderly retirement of older
facilities are vital to ensuring electricity reliability.
---------------------------------------------------------------------------

    \68\ 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.
    \69\ ``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.''
---------------------------------------------------------------------------

    In light of the information discussed above, and the EPA's
authority under section 304(b) to consider cost, the age of equipment
and facilities involved, non-water quality environmental impacts
(including energy requirements), and other factors that the
Administrator deems appropriate, the EPA proposes a new subcategory for
boilers with a limited remaining useful life, i.e., those intending to
close no later than December 31, 2028, subject to a certification
requirement (described in Section XIV). For this subcategory, the EPA
proposes to identify surface impoundments as the technology basis for
BAT, and establish BAT limitations for TSS for both FGD wastewater and
BA transport water. 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. The EPA
proposes to find that additional technologies such as chemical
precipitation with or without LRTR for FGD wastewater, and the 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
boilers 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 proposes to
find that surface impoundments are the only technology that would not
impose such disproportionate costs on this subcategory of boilers.
Establishing surface impoundments as BAT for this subcategory would
alleviate the choice for these facilities 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 BAT options in this
proposal. Creation of this subcategory would also allow electric
utilities to continue the organized phasing out of boilers that are no
longer economical, in favor of more efficient, newly constructed
generating stations, and would help prevent the scenario described in
the NERC stress test.

Additionally, it would ensure that facilities could make better use of
the CCR rule's alternative closure provision, by which an unlined
surface impoundment could continue to receive waste and complete
closure by 2028.\70\ The EPA notes that in order to complete closure by
2028, facilities may have to cease receiving waste well in advance of
that date; however, a 2028 date ensures that the ELG will not restrict
the use of this alternative closure provision regardless of when a
facility ultimately ceases receipt of waste. Furthermore, the EPA
proposes to find that allowing permitting authorities to set BAT
limitations for either FGD wastewater or BA transport water on a case-
by-case basis using BPJ would be problematic. The technologies a
permitting authority would necessarily consider are the same systems
that result in unacceptable disproportionate costs according to the
EPA's analysis (described above). Since these boilers are already
nearing the end of their useful life, and are susceptible to early
retirement, losing the ability to use surface impoundments for any
wastewater prior to currently planned closure dates would undermine the
flexibility of the CCR alternative closure provisions and could hasten
the retirement of units in a manner more closely resembling the
reliability stress test discussed above, which resulted in unacceptable
non-water quality environmental impacts (including energy requirements)
of compromised electric reliability.
---------------------------------------------------------------------------

    \70\ 40 CFR part 257.103(b).
---------------------------------------------------------------------------

    The EPA solicits comment on whether approaches to retirement in
other rules have worked particularly well and might be adopted here.
The EPA solicits comment on whether this subcategory would adversely
incentivize coal-fired boilers planning to retire after 2028 to
accelerate their retirement to 2028, as well as alternatives for
addressing the disproportionate costs, energy requirements, and
intersection with the CCR rule discussed above. The EPA also solicits
comment on whether this subcategory should also be available for
boilers that are planned to be repowered or replaced by 2028, not just
those planned for retirement. For example, the EPA solicits comment on
data and information demonstrating that boilers that are repowered with
gas units are unable to finance both the repowering and the FGD and BA
technology upgrades applicable to the rest of the industrial category,
and whether BAT for such units should also be established based on
surface impoundments as for retiring units described above. The EPA
solicits comment on whether 2028 is the most appropriate target date
for retirement or if a date earlier or later than 2028 would be more
appropriate. The EPA also solicits comment on whether an additional
subcategory for low utilization boilers retiring by a date certain that
is after 2028 would be warranted, and what an appropriate retirement
date might be. The EPA requests commenters identify and include
available data or information to support their recommended approach.

D. Availability Timing of New Requirements

    Where BAT limitations in the 2015 rule are more stringent than
previously established BPT limitations for FGD wastewater and BA
transport water, those limitations, under the compliance dates as
amended by the 2017 postponement rule, do not apply until a date
determined by the permitting authority that is ``as soon as possible''
beginning November 1, 2020.\71\ The rule also specifies the factors
that the permitting authority must consider in determining the ``as
soon as possible'' date.\72\ In addition, the 2017 postponement rule
did not revise the 2015 rule's ``no later than'' date of December 31,
2023, for implementation because, as public commenters pointed out,
without such a date, implementation could be substantially delayed, and
a firm ``no later than'' date creates a more level playing field across
the industry. As the EPA did in developing the 2015 rule, as part of
the consideration of the technological availability and economic
achievability of the BAT limitations in this proposal, the Agency
considered the magnitude and complexity of process changes and new
equipment installations that would be required at facilities to meet
the proposed requirements. As discussed below, the EPA is considering
availability of the technologies for FGD wastewater and BA transport
water.
---------------------------------------------------------------------------

    \71\ 40 CFR 423.11(t).
    \72\ These factors are: (a) Time to expeditiously plan
(including to raise capital), design, procure, and install equipment
to comply with the requirements of the final rule; (b) changes being
made or planned at the facility in response to greenhouse gas
regulations for new or existing fossil fuel-fired power facilities
under the Clean Air Act, as well as regulations for the disposal of
coal combustion residuals under subtitle D of the Resource
Conservation and Recovery Act; (c) for FGD wastewater requirements
only, an initial commissioning period to optimize the installed
equipment; and (d) other factors as appropriate. 40 CFR 423.11(t).
---------------------------------------------------------------------------

    In the 2015 rule, and as amended by the 2017 postponement rule, the
EPA selected the time frames described above to enable many facilities
to raise needed capital, plan and design systems, procure equipment,
and then construct and test systems. The time frames also allow for
consideration of facility changes being made in response to other
Agency rules affecting the steam electric power generating industry
(e.g., the CCR rule). The EPA understands that some facilities may have
already installed, or are now installing, technologies that could
comply with the proposed limitations. While these facilities could
therefore potentially comply with the proposed rule by the earliest
date on which the limitations may become applicable (November 1, 2020),
the EPA solicits comment on whether the earliest date on which
facilities may have to meet the proposed limitations should be later
than November 1, 2020.\73\
---------------------------------------------------------------------------

    \73\ The EPA received a request on behalf of two Maryland
facilities that the EPA issue a rule postponing the earliest
compliance date from November 1, 2020 to November 1, 2022. See Feb.
26, 2019 memorandum entitled EPA's Ongoing Reconsideration of the
Effluent Limitation Guidelines and Standards for the Steam Electric
Generating Point Source Category (the ``ELG Rule'' or ``the ELGs''),
available on EPA's Docket at No. EPA-HQ-OW-2009-0819.
---------------------------------------------------------------------------

    As described previously, the industry continues to shift away from
the use of surface impoundments for handling BA. Information collected
since the 2015 rule, as well as conversations with electric utilities,
EPA understands that facilities may be able to complete design,
procurement, installation, and operation of BA transport water
technologies by December 31, 2023.\74\ The CCR rule proposal would
require the majority of unlined surface impoundments to stop receiving
waste by August 2020. This would necessarily require installation by
August 2020 of an alternative system to meet those ELG standards. As
described earlier, because the record for the 2015 CCR rule found that
it would be less costly for facilities to install under-boiler or
remote drag chain systems and send BA to landfills rather than continue
to wet sluice BA and replace unlined ponds with composite lined ponds.
Flexibility for facilities to comply with BAT limitations for BA
transport water beyond 2023 is not necessary because the process
changes should already have occurred due to CCR rule requirements.
Therefore, for BA transport water, the EPA proposes to continue the
current timing for implementation. The EPA solicits comment on whether
these assumptions are appropriate. The EPA also solicits comment on
whether it should modify the existing language

which explicitly allows permitting authorities to consider extensions
granted under the CCR rule in establishing compliance dates for BA
transport water. The EPA requests commenters identify and include
available data or information to support their recommended approach.
---------------------------------------------------------------------------

    \74\ Information in the record indicates a typical timeframe of
15-23 months to raise capital, plan and design systems, procure
equipment, and construct a dry handling or closed-loop or high rate
recycle BA system.
---------------------------------------------------------------------------

    For FGD wastewater, the EPA proposes to continue the existing
``beginning'' date, but proposes a different ``no later than'' date.
The EPA collected updated information regarding the technical
availability of the proposed FGD BAT technology basis, including the
proposed VIP alternative. Based on the engineering dependency charts,
bids, and other analytical documents in the current record, individual
facilities may need two to three years from the effective date of any
rule to install and begin operating a treatment system to achieve
BAT.\75\ While three years may be appropriate for a facility on an
individual basis, several utilities and EPC firms pointed out
difficulties in retrofitting on a company-wide or industry-wide basis.
Moreover, the same engineers, vendors, and construction companies are
often used across facilities. As was the case with BA transport water
above, facilities with FGD wastewater have continued to convert away
from surface impoundments, and the majority of facilities with unlined
surface impoundments would have to stop receiving waste in those
unlined surface impoundments by August 2020, under the CCR proposal. To
stop receiving waste in an unlined surface impoundment, a facility
would need to construct a treatment system to meet applicable ELGs,
such as a tank-based system that meets the BPT limitations. However,
biological treatment is not necessary to remove TSS, and therefore more
time for implementation of the proposed BAT limitations will help to
accommodate the process changes necessitated by combining chemical
precipitation and LRTR, and alleviate competition for resources.
Considering all the factors described above, the EPA proposes to extend
the ``no later than'' date for compliance with BAT FGD wastewater
limitations to December 31, 2025, based on the proposed technology
basis. Thus, for FGD wastewater, where BAT limitations are more
stringent than previously established BPT limitations, BAT limitations
would not apply until a date determined by the permitting authority
that is as soon as possible beginning November 1, 2020, but no later
than December 31, 2025. The EPA solicits comment on whether these
assumptions are appropriate and whether these compliance dates should
be harmonized with the compliance dates for BA transport water. The EPA
requests commenters identify and include available data or information
to support their recommended approach.
---------------------------------------------------------------------------

    \75\ Information in the record indicates a typical time frame of
26 to 34 months to raise capital, plan and design systems (including
any necessary pilot testing), procure equipment, and construct and
then test systems (including a commissioning period for FGD
wastewater treatment systems). Many facilities have already
completed initial steps of this process, having evaluated water
balances and conducted pilot testing to prepare for implementing the
2015 rule.
---------------------------------------------------------------------------

    In addition, as discussed earlier, the EPA is proposing to give
facilities that elect to use the VIP until December 31, 2028, to meet
the VIP limitations, which are based on membrane filtration technology.
That is the date on which the EPA proposes to determine that the
membrane filtration-based limitations are ``available'' (as that term
is used in the CWA) to all plants that might choose to participate in
the voluntary incentives program. The EPA is proposing to give
facilities sufficient time to work out operational issues related to
being the first facilities in the U.S. to treat FGD wastewater using
membrane filtration at full scale, as well as having to dispose of the
resulting brine. Both issues contribute to the EPA's proposed decision
that membrane filtration is not BAT on a nationwide basis at this time.
The EPA also wants to incentivize facilities to opt into a program that
can achieve significant pollutant reductions.

E. Regulatory Sub-Options To Address Bromides

    The 2015 rule rejected thermal evaporation technology as the basis
for BAT and therefore did not establish limitations for bromides in FGD
wastewater. Section XVI.D of the preamble noted that the VIP
established in the 2015 rule would address bromide through the
limitations for TDS. The newly proposed VIP includes limits for
bromide. Because the EPA proposes to provide more flexible VIP limits
on other pollutants and more flexible VIP timing, the EPA estimates
that selecting the proposed VIP may be the least-cost option for some
facilities. The facilities that the EPA estimates VIP may be the least-
cost option range in FGD wastewater flows, nameplate capacity, capacity
utilization, and location. The EPA cost estimates for the VIP tend to
be lower at facilities where no treatment has been installed beyond
surface impoundments, however even for this group of facilities
biological systems are still often least-cost. Thus, while the EPA
estimates that the proposed revisions to the VIP may address bromide at
more facilities than the 2015 VIP, it is still a voluntary program, and
concerns about costs, availability, and disposal of the resultant brine
are still present.
    The EPA suggested in the preamble to the 2015 rule that water-
quality-based effluent limitations may be appropriate on a site-
specific basis to address the potential impacts of bromides on
downstream drinking water treatment facilities, as determined by state
permitting authorities. Since that time, few states have begun to
monitor bromide discharges and it is unclear how many have acted to
address such discharges.\76\
---------------------------------------------------------------------------

    \76\ The EPA is aware that Pennsylvania, Alabama, and North
Carolina conduct bromide monitoring at multiple facilities with FGD
discharges.
---------------------------------------------------------------------------

    On June 8, 2018, drinking water utilities sent a letter to the EPA
requesting that the Agency consider three regulatory BAT/PSES
technology options to reduce bromide discharges in FGD wastewater: (1)
Zero liquid discharge technologies (ZLD), such as membrane filtration
or thermal treatment; (2) treatment with reverse osmosis; or (3) a
requirement that facilities provide data to the state permitting
authority for use in calculating a site-specific discharge limitation.
For the reasons explained earlier in this section, the EPA is not
proposing to base BAT limitations or PSES for FGD wastewater at all
existing units based on membrane filtration or thermal treatment. The
EPA proposes a water quality-based approach as the most appropriate
approach and solicits comment on that alternative, including ways that
such an alternative could be strengthened. However, in light of the
letter from the drinking water utilities and the limited state action
since the 2015 rule to address this potential issue, the EPA is
requesting comment on three bromide-specific regulatory sub-options in
addition to the proposed approach of retaining the 2015 rule's approach
of leaving bromides to be limited by permitting authorities where
appropriate using water quality-based effluent limitations: \77\ (1) A
monitoring requirement under CWA section 308; (2) a bromide
minimization plan using narrative or non-numeric limitations under CWA
sections 301(b) and 304(b); or (3) a numeric limit under CWA sections
301(b) and 304(b) based on product substitution. Each of these are
described in more detail below.
---------------------------------------------------------------------------

    \77\ These sub-options would not be applicable to the VIP
limitations as those limitations would control bromide (and other
halogens) in FGD wastewater discharges.

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

    In the case of FGD wastewater monitoring, the EPA solicits comment
on two approaches suggested by electric utilities. Under the first
approach, bromide would be monitored monthly for two years, and
thereafter only after specific changes in facility operations that
could alter bromide concentrations in FGD wastewater. Such operational
changes could include changing to a brominated refined coal, a bromide
addition process, a coal feedstock with higher bromide levels, or use
of brominated powdered activated carbon (PAC). Under the second
approach, bromide would be monitored monthly for five years in two
locations to better capture bromide variability. The first monitoring
location would be of intake water not affected by the site's discharge
to capture what fraction of bromide is present from background surface
water. The second would be of discharge water to capture the amount of
bromide added by various wastewaters. The monitoring point for the FGD
wastewater discharge could be at the final outfall. The EPA also
solicits comment on whether monitoring should be longer or shorter
duration than proposed and if additional monitoring locations may be
appropriate to capture other operational changes that the EPA has not
identified.
    The EPA solicits comment on whether a facility should develop a
plan to minimize its use of bromide on a site-specific basis. Such a
plan could allow a facility to consider the costs of potential
approaches to minimizing bromide use in conjunction with its efforts to
meet other standards (e.g., MATS). Otherwise, facilities would minimize
the bromide in their discharges by switching to lower-bromide coals,
reducing bromide addition, and/or cutting back on refined coal use. The
EPA solicits comment on whether such a plan is appropriate for all
steam electric generators and, if so, the elements that might be
included in such a plan.
    Regarding a bromide limitation based on product substitution, the
EPA solicits comment on whether a limitation could be established that
reflects the difference in concentrations naturally occurring in coal
as opposed to levels found in refined coal or from other halogen
applications. Alternatively, the EPA solicits comment on whether
facilities could certify that they do not burn refined coal and/or use
bromide addition processes. The EPA solicits data that supports
development of a numerical bromide limitation, or that demonstrates a
specific numerical bromide limitation to be inappropriate.
    The Agency solicits input on the pros and cons of each of these
bromide sub-option approaches. Finally, the Agency solicits comment on
other pollutants, including other halides, discharged from steam
electric facilities that may impact the formation of disinfection
byproducts (DBPs).

F. Economic Achievability

    As the EPA did for the 2015 rule, the Agency performed cost and
economic impact assessments using the Integrated Planning Model (IPM)
to determine the effect of the proposed ELGs, using a baseline that
incorporates impacts from other relevant environmental regulations (see
Chapter 5 in RIA). At the time of the 2015 rule, the IPM model showed a
total incremental closure of 843 MW of coal-fired generation as a
result of the ELGs, corresponding to a net effect of two boiler
closures.\78\ However, since that time, natural gas prices have
remained low, additional coal facilities have retired or refueled, and
changes that have been proposed to several environmental regulations
have been included in those model runs. Due to these changes, the EPA
ran an updated version of IPM. (See Section VIII.C.2 for additional
discussion on these updates.) This update showed that the 2015 rule
resulted in the closure of 1.8 GW of coal-fired generation,
corresponding to a net effect of approximately four boiler closures,
based on the average capacity of coal-fired electric boilers.
---------------------------------------------------------------------------

    \78\ In meetings with EPA since the 2015 rule, electric
utilities have expressed concerns that IPM underpredicts closures by
not accounting for the ability of facilities in regulated states to
cost recover even if they would otherwise lose money or are not
economical to operate.
---------------------------------------------------------------------------

    The EPA similarly ran the IPM model to determine the effect of the
regulatory options presented in Table VII-1. Options 2 and 4 bound the
costs to industry of these four options, IPM results from these options
alone reflect the range of impacts associated with all four regulatory
options.\79\ The IPM models for these two options were run prior to
finalization of the ACE rule (the impact of ACE is analyzed in a
separate sensitivity scenario) and ranged from a total net increase of
0.7 GW to 1.1 GW in coal-fired generating capacity compared to the 2015
rule, reflecting full compliance by all facilities. This capacity
increase corresponds to a net effect of one to two boiler closures
avoided as a result of this reconsideration action. These IPM results
indicate that the proposed Option 2 is economically achievable for the
steam electric power generating industry as a whole, as required by CWA
section 301(b)(2)(A). Following the promulgation of the ACE rule, the
EPA also conducted a sensitivity analysis that includes the effects of
that rule in the ELG analytic baseline. The results of this sensitivity
analysis, which are detailed in Appendix C of the RIA, also indicate
that the proposed Option 2 is economically achievable. The EPA will use
the latest IPM baseline, including the ACE rule as part of existing
regulations, when analyzing the ELG final rulemaking.
---------------------------------------------------------------------------

    \79\ Although Option 1 includes the less stringent chemical
precipitation technology, Option 2 has a greater savings due to
subcategorization of low utilization boilers.
---------------------------------------------------------------------------

    The EPA's economic achievability analysis for this and other
options is described in Section VIII, below.

G. Non-Water Quality Environmental Impacts

    For the 2015 rule, the EPA performed an assessment of non-water
quality environmental impacts, including energy requirements, air
impacts, solid waste impacts, and changes in water use and found them
to be acceptable. The EPA has reevaluated these impacts in light of the
changed industry profile, as well as the proposed changes to BAT. Based
on the results of these analyses the EPA determined that Options 1, 2,
and 3 have acceptable non-water quality impacts. Option 4, however,
would result in unacceptable non-water quality environmental impacts
where management of the brine could divert FA that might otherwise be
sold for use in products (e.g., replacing Portland cement in concrete)
back toward placement in a landfill. See additional information in
Section 7 of the Supplemental TDD, as well as Section X of this
preamble.

H. Impacts on Residential Electricity Prices and Low-Income and
Minority Populations

    As the EPA did for the 2015 rule, the Agency examined the effects
of today's regulatory options on consumers as an additional factor that
might be appropriate when considering what level of control represents
BAT. If all annualized compliance cost savings were passed on to
residential consumers of electricity, instead of being borne by the
operators and owners of facilities, the average monthly cost savings
under any of the options would be between $0.01 and 0.04 per month as
compared to the 2015 rule.
    The EPA similarly evaluated the effect of today's regulatory
options on minority and low-income populations. As explained in Section
XII, the EPA used demographic data for populations potentially impacted
by steam electric power plant discharges due to their proximity (i.e.,
within 50 miles) to one

or more plants. For those populations, the EPA evaluated both
recreational and subsistence fisher populations. The analysis described
in Section XII indicates that absolute changes in human health impacts
are smaller than the overall impacts resulting from the 2015 rule.
However, low-income and minority populations are potentially affected
to a greater degree than the general population by discharges from
steam electric facilities and are expected to also accrue to a greater
degree than the general population the benefits of the proposed rule,
positive or negative.

I. Additional Rationale for the Proposed PSES

    The EPA is continuing to rely on the pass-through analysis as the
basis of the limitations and standards in the 2015 rule. With respect
to FGD wastewater, as discussed above, the long-term averages for low
residence time biological treatment are very similar to or lower than
those achieved with high residence time biological systems. On this
basis, the EPA proposes to conclude that mercury, arsenic, selenium,
and nitrate/nitrite pass-through POTWs, as it concluded in the 2015
rule.
    With respect to BA, the EPA notes that facilities converting to dry
handling or recycling all of their BA transport water would continue to
perform as the zero discharge systems the EPA used in its 2015 rule
pass-through analysis. As explained in Section VII.b.ii, for those
facilities using high rate recycle systems, the EPA proposes to allow a
discharge up to 10 percent of the system volume per day on a 30-day
rolling average and to subject such direct discharges to TSS
limitations of BPT. Consistent with the 2015 rule pass through
analysis, TSS is not considered to pass through and the EPA would not
establish TSS limitations under PSES.
    Thus, like BAT, the EPA proposes to establish PSES based on Option
2: PSES for FGD wastewater based on chemical precipitation plus low
hydraulic residence time biological treatment, and PSES for BA
transport water based on dry handling or high recycle rate systems.\80\
The EPA proposes these technologies as the bases for PSES for the same
reasons that the EPA proposes the technologies as the bases for BAT,
and also proposes the same subcategories proposed for BAT.\81\
---------------------------------------------------------------------------

    \80\ Only two facilities currently discharge BA transport water
to POTWs, and EPA believes that both facilities qualify for the
proposed subcategorization for low utilization boilers. Thus, this
PSES may ultimately not apply to any facilities.
    \81\ Where any of the subcategories would establish BAT based on
surface impoundments, with a restriction on TSS, there would be no
such parallel restriction for the analogous PSES subcategory because
POTWs effectively treat TSS.
---------------------------------------------------------------------------

    As with the final BAT effluent limitations, in considering the
availability and achievability of the final PSES, the EPA concluded
that existing indirect dischargers need some time to achieve the final
standards, in part to avoid forced outages (see Section VIII.C.7).
However, in contrast to the BAT limitations (which apply on a date
determined by the permitting authority that is as soon as possible
beginning November 1, 2020, but no later than December 31, 2023, for BA
transport water, and no later than December 31, 2025, for FGD
wastewater), facilities must meet the PSES no later than three years
after the effective date of any final rule. Under CWA section
307(b)(1), pretreatment standards shall specify a time for compliance
not to exceed three years from the date of promulgation, so the EPA
cannot establish a longer implementation period. Moreover, unlike
limitations on direct discharges, limitations on indirect discharges
are not implemented through an NPDES permit and thus are specified
clearly for the discharger without delay, without waiting some time for
the next permit issuance. The EPA has determined that all current
indirect dischargers can meet the standards within three years of the
effective date of any final rule (which the EPA projects will be issued
in the summer of 2020).

VIII. Costs, Economic Achievability, and Other Economic Impacts

    The EPA evaluated the costs and associated impacts of the proposed
regulatory options on existing boilers at steam electric facilities.
These costs are analyzed within the context of compounding regulations
and other industry trends that have affected steam electric facilities
profitability and generation. These include the impacts of existing
environmental regulations (e.g., Cross-State Air Pollution Rule,
Mercury and Air Toxics Standards, CWA section 316(b) rule, final CCR
rule, final ACE rule), as well as other market conditions described in
Section V.B.\82\ This section provides an overview of the methodology
the EPA used to assess the costs and the economic impacts and
summarizes the results of these analyses. See the RIA in the docket for
additional detail.
---------------------------------------------------------------------------

    \82\ As discussed above, impacts of the final ACE rule will be
incorporated into this analysis after proposal, but were not
included here as the analyses for these proposed ELGs were completed
prior to the ACE rule being finalized.
---------------------------------------------------------------------------

    In developing ELGs, and as required by CWA section 301(b)(2)(A),
the EPA evaluates the economic achievability of regulatory options to
assess the impacts of applying the limitations and standards on the
industry as a whole, which typically includes an assessment of
incremental facility closures attributable to a regulatory option. As
described in more detail below, this proposed ELG is expected to
provide cost savings when compared to the baseline. Like the prior
analysis of the 2015 rule, the cost and economic impact analysis for
this proposed rulemaking focuses on understanding the magnitude and
distribution of compliance cost savings across the industry, and the
broader market impacts.
    The EPA used certain indicators to assess the impacts of the
proposed regulatory options on the steam electric power generating
industry as a whole. These indicators are consistent with those used to
assess the economic achievability of the 2015 rule (80 FR 67838);
however, for this proposal, the EPA compared the values to a baseline
that reflects implementation of existing environmental regulations (as
of this proposal), including the 2015 rule. In the 2015 rule analysis,
the costs of achieving the 2015 rule requirements were reflected in the
policy cases analyzed rather than the baseline. Here, the baseline
appropriately includes costs for achieving the 2015 rule limitations
and standards, and the policy cases show the impacts resulting from
changes to those existing 2015 limitations and standards. More
specifically, the EPA considered the total cost to industry and change
in the number and capacity of specific boilers and facilities expected
to close under the options in this proposal (including proposed Option
2) compared to the estimated baseline costs. The EPA also analyzed the
ratio of compliance costs to revenue to see how the proposed regulatory
options change the number of facilities and their owning entities that
exceed certain thresholds indicating potential financial strain.
    In addition to the analyses supporting the economic achievability
of the regulatory options, the EPA conducted other analyses to (1)
characterize other potential impacts of the regulatory options (e.g.,
on electricity rates), and (2) to meet the requirements of Executive
Orders or other statutes (e.g., Executive Order 12866, Regulatory
Flexibility Act, Unfunded Mandates Reform Act).

A. Facility-Specific and Industry Total Costs

    The EPA estimated facility-specific costs to control FGD wastewater
and BA transport water discharges at existing boilers at steam electric
facilities to

which the ELGs apply.\83\ The EPA assessed the operations and treatment
system components currently in place at a given unit (or expected to be
in place as a result of other existing environmental regulations),
identified equipment and process changes that facilities would likely
make to meet the 2015 rule (for baseline) and each of the four
regulatory options presented in Table VII-1, and estimated the cost to
implement those changes. As explained in the Supplemental TDD, the
baseline also accounts for additional announced unit retirements,
conversions, and relevant operational changes that have occurred since
the EPA promulgated the 2015 rule. The EPA thus derived facility-level
capital and O&M costs for controlling FGD wastewater and BA transport
water using the technologies that form the bases of the 2015 rule, and
for each regulatory option presented in Table VII-1 for existing
sources. See Section 5 of the Supplemental TDD for a more detailed
description of the methodology the EPA used to estimate facility-level
costs for this proposal.
---------------------------------------------------------------------------

    \83\ The EPA did not estimate costs for other wastestreams not
in this proposal.
---------------------------------------------------------------------------

    Following the same methodology used for the 2015 rule analysis, the
EPA used a rate of seven percent to annualize one-time costs and costs
recurring on other than on an annual basis over a specific useful life,
implementation, and/or event recurrence period. For capital costs and
initial one-time costs, the EPA used 20 years. For O&M costs incurred
at intervals greater than one year, EPA used the interval as the
annualization period (3 years, 5 years, 6 years, 10 years). The EPA
added annualized capital, initial one-time costs, and the non-annual
portion of O&M costs to annual O&M costs to derive total annualized
facility costs. The EPA then calculated total industry costs by summing
facility-specific annualized costs. For the assessment of industry
costs, the EPA considered costs on both a pre-tax and after-tax basis.
Pre-tax annualized costs provide insight on the total expenditure as
incurred, while after-tax annualized costs are a more meaningful
measure of impact on privately owned for-profit facilities and
incorporate approximate capital depreciation and other relevant tax
treatments in the analysis. The EPA uses pre- and/or after-tax costs in
different analyses, depending on the concept appropriate to each
analysis (e.g., social costs are calculated using pre-tax costs whereas
cost-to-revenue screening-level analyses are conducted using after-tax
costs).
    Table VIII-1 summarizes estimates of incremental pre- and post-tax
industry costs for the four regulatory options presented in Table VII-1
as compared to the baseline. All four options provide cost savings
(negative incremental costs) as compared to the costs that the industry
would incur under the 2015 rule. Under all four options, some savings
are attributable to cheaper high recycle rate BA systems. Under Options
1, 2, and 3, additional savings are due to lower cost FGD wastewater
treatment systems (chemical precipitation and LRTR). Under Option 2,
further savings are attributable to the subcategorization of low
utilization boilers. Finally, some cost savings are due to the changes
in compliance timeframes discussed above in Section VII.D. The after-
tax savings range from approximately $26 million under Option 4 to $147
million under Option 2.\84\
---------------------------------------------------------------------------

    \84\ In response to additional information the EPA received from
a vendor showing installed costs of LRTR were lower than EPA's
predicted costs, and to account for the small difference in cost
between the sand filter and ultrafiltration polishing stage
technologies, the EPA conducted a sensitivity analysis (DCN
SE07120). Based on this analysis, the costs to install LRTR may be
approximately five percent lower than the LRTR cost estimates used
for developing the total costs presented in Table VIII-1.

         Table VIII-1--Estimated Total Annualized Industry Costs
             [Million of 2018$, seven percent discount rate]
------------------------------------------------------------------------
              Regulatory  option                  Pre-tax     After-tax
------------------------------------------------------------------------
Option 1......................................      -$165.6      -$136.6
Option 2......................................       -175.6       -146.5
Option 3......................................       -126.3       -105.9
Option 4......................................        -25.5        -26.4
------------------------------------------------------------------------

B. Social Costs

    Social costs are the costs of the proposed rule from the viewpoint
of society as a whole, rather than the viewpoint of regulated
facilities (which are private costs). In calculating social costs, the
EPA tabulated the pre-tax costs in the year when they are estimated to
be incurred. As described in Section VII.D of this preamble, the
proposed compliance deadlines and therefore the expected technology
implementation years vary across the regulatory options. The EPA
performed the social cost analysis over a 27-year analysis period of
2021-2047, which combines the length of the period during which
facilities are anticipated to install the control technologies (which
could be as late as 2028 under Option 4) and the useful life of the
longest-lived technology installed at any facility (20 years). The EPA
calculated the social cost of the proposed rule using both a three
percent discount rate and an alternative discount rate of seven
percent.
    Social costs include costs incurred by both private entities and
the government (e.g., in implementing the regulation). As described
further in Chapter 10 of the RIA, the EPA did not evaluate the
incremental increase in the cost to state governments to evaluate and
incorporate BPJ into NPDES permits. EPA solicits comments on whether
these incremental costs are significant enough to be included.
Consequently, the only category of costs used to calculate social costs
are those pre-tax costs estimated for steam electric facilities. Note
that the annualized social costs presented in Table VIII-2 for the
seven percent discount rate differ from comparable pre-tax industry
compliance costs shown in Table VIII-1. The costs in TableVIII-1
represent the annualized costs of each option if they were incurred in
2020, whereas the annualized costs in Table VIII-2 are estimated based
on the stream of future costs starting in the year that individual
facilities are projected to actually comply with the requirements of
the proposed options under the availability timing proposed in Section
VII.D.
    Table VIII-2 presents the total annualized social costs of the four
regulatory options presented in Table VII-1, compared to the baseline
and calculated using three percent and seven percent discount rates.
All four options provide cost savings (negative incremental costs)
compared to the baseline using a seven percent discount rate, and
Options 1, 2, and 3 also show cost savings using a three percent
discount rate. Option 2 has estimated annualized cost savings of $166.2
million using a seven percent discount rate and $136.3 million using a
three percent discount rate.

          Table VIII-2--Estimated Total Annualized Social Costs
        [Million of 2018$, three and seven percent discount rate]
------------------------------------------------------------------------
                                                3% Discount  7% Discount
              Regulatory  option                    rate         rate
------------------------------------------------------------------------
Option 1......................................      -$130.6      -$154.0
Option 2......................................       -136.3       -166.2
Option 3......................................        -90.1       -119.5
Option 4......................................         11.9        -27.3
------------------------------------------------------------------------

C. Economic Impacts

    The EPA assessed the economic impacts of this proposed rule in two
ways: (1) A screening-level assessment of the cost impacts on existing
boilers at steam electric facilities and the entities

that own those facilities, based on comparison of costs to revenue; and
(2) an assessment of the impact of the regulatory options presented in
Table VII-1 within the context of the broader electricity market, which
includes an assessment of changes in predicted facility closures
attributable to the options. The following sections summarize the
results of these analyses. The RIA discusses the methods and results in
greater detail.
    The first set of cost and economic impact analyses--at both the
facility and parent company levels--provide screening-level indicators
of the impacts of costs for FGD wastewater and BA transport water
controls relative to historical operating characteristics of steam
electric facilities incurring those costs (i.e., level of electricity
generation and revenue). The EPA conducted these analyses for the
baseline and for the four regulatory options presented in Table VII-1,
and then compared these impacts to understand the incremental effects
of the regulatory options in this proposal. The second set of analyses
look at broader electricity market impacts considering the
interconnection of regional and national electricity markets. It also
looks at the distribution of impacts at the facility and boiler level.
This second set of analyses provides insight on the impacts of the
regulatory options in this proposal on steam electric facilities, as
well as the electricity market as a whole, including changes in
generation capacity, generation, and wholesale electricity prices. The
market analysis compares model predictions for the options to a base
case that includes the predicted and observed economic and market
effects of the 2015 rule. The EPA used results from the screening
analysis of facility- and entity-level impacts, together with changes
in projected capacity closure from the market model, to understand the
impacts of the regulatory options in this proposal relative to the
baseline.
1. Screening-Level Assessment
    The EPA conducted a screening-level analysis of each regulatory
option's potential impact to existing boilers at steam electric
facilities and parent entities based on cost-to-revenue ratios. For
each of the two levels of analysis (facility and parent entity), the
Agency assumed, for analytic convenience and as a worst-case scenario,
that none of the compliance costs would be passed on to consumers
through electricity rate increases and would instead be absorbed by the
steam electric facilities and their parent entities. This assumption
overstates the impacts of compliance expenditures since steam electric
facilities that operate in a regulated market may be able to pass on
changes in production costs to consumers through changes in electricity
prices. It is, however, an appropriate assumption for a screening-level
estimate of the potential cost impacts.
a. Facility-Level Cost-to-Revenue Analysis
    The EPA developed revenue estimates for this analysis using EIA
data. The EPA then calculated the change in the annualized after-tax
costs of the four regulatory options presented in Table VII-1 as a
percent of baseline annual revenues. See Chapter 4 of the RIA for a
more detailed discussion of the methodology used for the facility-level
cost-to-revenue analysis.
    Cost-to-revenue ratios are used to describe impacts to entities
because they provide screening-level indicators of potential economic
impacts. Just as for the facilities owned by small entities under
guidance in U.S. EPA (2006),\85\ the full range of facilities incurring
costs below one percent of revenue are unlikely to face economic
impacts, while facilities with costs between one percent and three
percent of revenue have a higher chance of facing economic impacts, and
facilities incurring costs above three percent of revenue have a still
higher probability of economic impacts.
---------------------------------------------------------------------------

    \85\ U.S. EPA (Environmental Protection Agency). 2006. EPA's
Action Development Process: Final Guidance for EPA Rulewriters:
Regulatory Flexibility Act as amended by the Small Business
Regulatory Enforcement Fairness Act. November 2006. Available online
at: https://www.epa.gov/reg-flex/epas-action-development-process-final-guidance-epa-rulewriters-regulatory-flexibility-act.
---------------------------------------------------------------------------

    As a result of the 2015 rule (baseline), the EPA estimated that 18
facilities incur costs greater than or equal to one percent of revenue,
including six facilities that have costs greater than or equal to three
percent of revenue, and an additional 96 facilities incur costs that
are less than one percent of revenue. By contrast, the four regulatory
options the EPA analyzed for this proposal are estimated to provide
cost savings that reduce this impact to various degrees, with Option 2
showing the largest reductions in cost. Options 1, 3, and 4 show an
estimated 16 to 19 facilities with costs greater than or equal to one
percent of revenue, including four or five facilities with costs
greater than or equal to three percent of revenue. Under Option 2, the
EPA estimated that eight facilities incur costs greater than or equal
to one percent of revenue, including two facilities that have costs
greater than or equal to three percent of revenue, and an additional
100 facilities incur costs that are less than one percent of revenue.
b. Parent Entity-Level Cost-to-Revenue Analysis
    The EPA also assessed the economic impact of the regulatory options
presented in Table VII-1 at the parent entity level. The screening-
level cost-to-revenue analysis at the parent entity level provides
insight on the impact on those entities that own existing boilers at
steam electric facilities. In this analysis, the domestic parent entity
associated with a given facility is defined as that entity with the
largest ownership share in the facility. For each parent entity, the
EPA compared the incremental change in the total annualized after-tax
costs and the total revenue for the entity compared to the baseline
(see Chapter 4 of the RIA for details). Following the methodology
employed in the analyses for the 2015 rule (80 FR 67838), the EPA
considered a range of estimates for the number of entities owning an
existing boiler at a steam electric power facility to account for
partial information available for steam electric facilities that are
not expected to incur ELG compliance costs.
    Similar to the facility-level analysis above, cost-to-revenue
ratios provide screening-level indicators of potential economic
impacts, this time to the owning entities; higher ratios suggest a
higher probability of economic impacts. The EPA estimated that the
number of entities owning existing boilers at steam electric facilities
ranges from 243 (lower-bound estimate) to 478 (upper-bound estimate),
depending on the assumed ownership structure of facilities not
incurring ELG costs and not explicitly analyzed. The EPA estimates that
in the baseline 236 to 470 parent entities, respectively, would either
incur no costs or the annualized cost they incur to meet the 2015 rule
BAT limitations and pretreatment standards would represent less than
one percent of their revenues.
    Compared to the baseline, all four regulatory options reduce the
impacts on the small number of entities incurring costs. The changes
are greatest for Option 2, which has five fewer entities with costs
exceeding one percent of revenue, including one less entity with costs
exceeding three percent of revenue, with the remaining entities either
having no cost, or costs that are less than one percent of revenue.
Options 1 and 3 each have two fewer entities in the one to three
percent of revenue category, and Option 4 has

one fewer entity in the one to three percent of revenue category.
2. Electricity Market Impacts
    In analyzing the impacts of regulatory actions affecting the
electric power sector, the EPA used IPM, a comprehensive electricity
market optimization model that can evaluate such impacts within the
context of regional and national electricity markets. The model is
designed to evaluate the effects of changes in boiler-level electric
generation costs on the total cost of electricity supply, subject to
specified demand and emissions constraints. Use of a comprehensive,
market analysis system is important in assessing the potential impact
of any power facility regulation because of the interdependence of
electric boilers in supplying power to the electric transmission grid.
Changes in electricity production costs at some boilers can have a
range of broader market impacts affecting other boilers, including the
likelihood that various units are dispatched, on average. The analysis
also provides important insight on steam electric capacity closures
(e.g., retirements of boilers that become uneconomical relative to
other boilers), or avoided closures, based on a more detailed analysis
of market factors than in the screening-level analyses above. The
results further inform the EPA's understanding of the potential impacts
of the regulatory options presented in Table VII-1. For the current
analyses, the EPA used version 6 (V6) of IPM to analyze the impacts of
the regulatory options. IPM V6 is based on an inventory of U.S.
utility- and non-utility-owned boilers and generators that provide
power to the integrated electric transmission grid, including
facilities to which the ELGs apply. IPM V6 embeds an energy demand
forecast that is derived from DOE's ``Annual Energy Outlook 2018'' (AEO
2018). IPM V6 also incorporates the expected compliance response to
existing regulatory requirements for regulations affecting the power
sector (e.g., Cross-State Air Pollution Rule (CSAPR) and CSAPR Update
Rule, Mercury and Air Toxics Rule (MATS), the Cooling Water Intake
Structure (CWIS) rule, and 2015 CCR rule, as well as the 2015 rule).
Federal CO2 standards for existing sources are not modeled
in IPM V6, owing to ongoing litigation.
    The EPA analyzed proposed Option 2 and Option 4 using IPM V6. As
discussed in Section VIII.A, these two options have the greatest and
least cost savings, respectively, compared to the baseline, and
therefore reflect the full range of potential impacts from the
regulatory options in this proposal. In addition, following
promulgation of the ACE final rule, EPA also analyzed proposed Option 2
relative to a baseline that includes the ACE rule. See Appendix C in
the RIA for details of these results.
    In contrast to the screening-level analyses, which are static
analyses and do not account for interdependence of electric boilers in
supplying power to the electricity transmission grid, IPM V6 accounts
for potential changes in the generation profile of steam electric and
other boilers and consequent changes in market-level generation costs,
as the electric power market responds to changes in generation costs
for steam electric boilers due to the regulatory options. Additionally,
in contrast to the screening-level analyses, in which the EPA assumed
no cost pass through of ELG compliance costs, IPM V6 depicts production
activity in wholesale electricity markets where the specific increases
in electricity prices for individual markets would result in some
recovery of compliance costs for plants in those markets.
    In analyzing the regulatory options presented in Table VII-1, the
EPA estimated changes in fixed and variable costs for the steam
electric facilities and boilers already incurring costs in the baseline
to instead incur costs (or avoid incurring costs) to comply with Option
2 and Option 4. Because IPM is not designed to endogenously model the
selection of wastewater treatment technologies as a function of
electricity generation, effluent flows, and pollutant discharge, the
EPA estimated these costs exogenously for each steam electric
generating unit and input these costs into the IPM model as fixed and
variable O&M cost adders. The EPA then ran IPM V6 including these new
cost estimates to determine the dispatch of electric boilers that would
meet projected demand at the lowest costs, subject to the same
constraints as those present in the baseline analysis. The estimated
changes in facility- and boiler-specific production levels and costs--
and, in turn, changes in total electric power sector costs and
production profile--are key data elements in evaluating the expected
national and regional effects of the regulatory options in this
proposal, including closures or avoided closures of steam electric
boilers and facilities. The EPA considered impact metrics of interest
at three levels of aggregation: (1) Impact on national and regional
electricity markets (all electric power generation, including steam and
non-steam electric facilities); (2) impact on steam electric facilities
as a group, and (3) impact on individual steam electric facilities
incurring costs. Chapter 5 of the RIA discusses the first analysis; the
sections below summarize the last two, which are further described in
Chapter 5 and in Appendix C of the RIA. All results presented below are
representative of modeled market conditions in the years 2028-2033,
when the rule would either be implemented or plans for implementation
by the end of 2028 would be well underway at all facilities.
a. Impacts on Existing Steam Electric Facilities
    The EPA used IPM V6 results for 2030 \86\ to assess the potential
impact of the regulatory options presented in Table VII-1 on existing
boilers at steam electric facilities. The purpose of this analysis is
to assess any fleetwide changes from baseline impacts on boilers at
steam electric facilities. Table VIII-3 reports estimated results for
existing boilers at steam electric facilities, as a group. The EPA
looked at the following metrics: (1) Incremental (and avoided) early
retirements and capacity closures, calculated as the difference between
capacity under the regulatory option and capacity under the baseline;
(2) incremental capacity closures as a percentage of baseline capacity;
(3) change in electricity generation from facilities regulated by ELGs;
(4) changes in variable production costs per MWh, calculated as the sum
of total fuel and variable O&M costs divided by net generation; and (5)
changes in annual costs (fuel, variable O&M, fixed O&M, and capital).
Note that changes in electricity generation presented in Table VIII-3
are attributable both to changes in retirements, as well as changes in
capacity utilization at boilers and plants whose retirement status does
not change.
---------------------------------------------------------------------------

    \86\ IPM model year 2030 represents years 2028-2033.

             Table VIII-3--Estimated Impact on Steam Electric Facilities as a Group at the Year 2030
----------------------------------------------------------------------------------------------------------------
                                                      Change attributable to regulatory option as compared to
                                                                             baseline
                                                 ---------------------------------------------------------------
             Metric               Baseline value             Option 2                        Option 4
                                                 ---------------------------------------------------------------
                                                       Value          Percent          Value          Percent
----------------------------------------------------------------------------------------------------------------
Total capacity (MW).............         336,872           2,880             0.9           3,194             0.9
Early retirements or closures             58,192          -2,880            -4.9          -3,194            -5.5
 \a\ (MW).......................
Early retirements or closures                 79               0             0.0              -1            -1.3
 \a\ (number of plants).........
Total generation (GWh)..........       1,570,513           4,676             0.3           1,235             0.1
Variable production cost (2018$/          $26.00           $0.02             0.1           $0.05             0.2
 MWh)...........................
Annual costs (million 2018$)....         $60,298             $98             0.2            $103             0.1
----------------------------------------------------------------------------------------------------------------
\a\ Values for incremental early retirements or closures represent change relative to the baseline. IPM may show
  partial (unit) or full facility early retirements (closures). It may also show avoided closures (negative
  closure values) in which a boiler or facility that is projected to close in the baseline is estimated to
  continue operating in the policy case.

    Under proposed Option 2, generation at steam electric facilities is
projected to increase by 4,676 GWh (0.3 percent) nationally, when
compared to the baseline. IPM V6 projects a net increase in total steam
electric capacity by 2,880 MW or approximately 0.9 percent of total
baseline capacity, but no net change in the number of full facility
retirements and the net avoidance of three partial retirements (unit
closures) nationwide indicating a higher capacity utilization by these
facilities. See Section <IP_ADDRESS> in the RIA for details.
    IPM V6 projects generation at steam electric facilities increases
under Option 4 by 1,235 GWh (0.1 percent) nationally, which is smaller
in magnitude than the increase under Option 2. National level results
for steam electric facilities under Option 4 show an increase in total
steam electric capacity of 3,194 MW (0.9 percent of the baseline). At
the national level, IPM projects one net avoided full facility closure
and the same three avoided partial retirements as for Option 2. See
Section <IP_ADDRESS> in the RIA for details.
    These findings suggest that all of the regulatory options in this
proposal can be expected to have small economic consequences for the
steam electric facilities as a group. Options 2 and 4 also affect the
operating status of very few steam electric facilities, with no net
change in facility closures under Option 2, and one net avoided closure
under Option 4.\87\ For further discussion of closures and related
distributional impacts, see Chapter 5 of the RIA.
---------------------------------------------------------------------------

    \87\ The additional closure under Option 2 is not a result of
the facility incurring costs under this proposed rule. The IPM model
predicts this facility becomes uneconomical due to the increased
generation from other coal facilities in the same NERC region.
---------------------------------------------------------------------------

    Because the analysis of the proposed options discussed in the RIA
was completed before the EPA finalized the ACE rule, this analysis does
not include the projected effects of the ACE rule. Thus, the EPA
conducted a supplemental IPM run with the costs of Option 2 on a
baseline that includes the ACE illustrative case presented in the ACE
final rule (see Appendix C in RIA). A summary of these results is
presented in Table VIII-4.

 Table VIII-4--Estimated Impact of ELG Option 2 on Steam Electric Power Plants as a Group at the Year 2030, for
                                  Sensitivity Analysis Including ACE Final Rule
----------------------------------------------------------------------------------------------------------------
                                                                              Option 2 with ACE rule
                     Metric                        Baseline with -----------------------------------------------
                                                     ACE rule          Value        Difference    Percent change
----------------------------------------------------------------------------------------------------------------
Early retirements or closures \a\ (MW)..........         336,547         339,654          -3,107            -0.9
Early retirements or closures \a\ (number of                  78              79               1             1.3
 plants)........................................
Total generation (GWh)..........................       1,569,109       1,576,455           7,345             0.5
Variable production cost (2018$/MWh)............          $25.85          $25.87           $0.02             0.1
Annual costs (million 2018$)....................         $60,387         $60,578            $191             0.3
----------------------------------------------------------------------------------------------------------------
\a\ Values for incremental early retirements or closures represent change relative to the baseline. IPM may show
  partial (unit) or full facility early retirements (closures). It may also show avoided closures (negative
  closure values) in which a boiler or facility that is projected to close in the baseline is estimated to
  continue operating in the policy case.

    Examining the incremental impacts of Option 2 on a baseline
including ACE, generation at steam electric facilities is projected to
increase by 3,107 GWh (0.9 percent) nationally. IPM V6 projects a net
increase in total steam electric capacity by 7,345 MW or approximately
0.5 percent of total baseline capacity. There is one incremental full
facility retirement as well as the net avoidance of four partial
retirements (unit closures) nationwide indicating a higher capacity
utilization by these facilities. See Appendix C of the RIA for further
details.
b. Impacts on Individual Facilities Incurring Costs
    To assess potential facility-level effects, the EPA also analyzed
facility-specific changes attributable to the regulatory options in
Table VII-1 for the following metrics: (1) Capacity utilization
(defined as annual generation (in MWh) divided by [capacity (MW) times
8,760 hours]) (2) electricity generation, and (3) variable production
costs per MWh, defined as variable O&M cost plus fuel cost divided by
net generation. The analysis of changes in individual facilities is
detailed in Chapter 5 of the RIA.
    The results for both Option 2 and Option 4 show no change, or less
than a one percent reduction or one percent increase for steam electric
facilities projected to incur ELG compliance costs. For Option 2, a
greater number of facilities see improving operating

conditions (i.e., higher capacity utilization or generation, lower
variable production costs) than deteriorating conditions. Effects under
Option 4 are similar, although approximately the same number of
facilities see positive changes in operating conditions as negative
changes. Thus, the results for the subset of facilities incurring costs
further support the conclusion that the effects of any of the
regulatory options in this proposed rule on the steam electric power
generating industry will be less than that of the 2015 rule. This
conclusion holds when including the effects of the ACE final rule, as
detailed in Appendix C of the RIA for proposed Option 2.

IX. Changes to Pollutant Loadings

    In developing ELGs, the EPA typically evaluates the pollutant
loading reductions of regulatory options to assess the impacts of the
compliance requirements on discharges from the industry as a whole. In
estimating pollutant reductions associated with this proposal, the EPA
took the same approach as described above for facility-specific costs.
That is, the EPA compared the values to a baseline that reflects
implementation of existing environmental regulations, including the
2015 rule. In the 2015 rule, the baseline did not reflect pollutant
loading reductions for achieving the 2015 rule requirements as that
impact is what EPA analyzed. Here, the baseline appropriately includes
pollutant loading reductions for achieving the 2015 rule requirements
as the EPA is analyzing the impact resulting from any changes to those
requirements. More specifically, the EPA considered the change in the
pollutant loading reductions associated with the regulatory options in
this proposal to those projected under the baseline.
    The general methodology that the EPA used to calculate pollutant
loadings is the same as that described in the 2015 rule. The EPA used
data collected for the 2015 rule, as well as the data described in
Section VI, to characterize pollutant concentrations for FGD wastewater
and bottom ash transport water. The EPA evaluated these data sources to
identify analytical data that meet EPA's acceptance criteria for
inclusion in analyses for characterizing discharges of FGD wastewater
and bottom ash transport water. For each plant discharging FGD
wastewater or bottom ash transport water, the EPA used data from the
2009 survey and/or industry-submitted data to determine the discharge
flow rates for FGD wastewater and bottom ash transport water. The EPA
adjusted the discharge flow rates used in the pollutant loadings
estimates to account for retirements, fuel conversions, and other
changes in operations scheduled to occur by December 31, 2028,
described in Section 6 of the Supplemental TDD, that will eliminate or
alter the discharge of an applicable wastestream. Finally, the Agency
adjusted the discharge flow rates to account for changes in plant
operations to optimize FGD wastewater flows and to comply with the CCR
rule. For further discussion of these adjustments see Section 6.2.2 and
6.3.2 of the Supplemental TDD, respectively.
    The EPA first estimated--on an annual, per facility basis--the
pollutant discharge load for FGD wastewater and BA transport water
associated with the technology basis evaluated for facilities to comply
with the 2015 rule requirements for FGD wastewater and BA transport
water relative to the conditions currently present or planned at each
facility. The EPA similarly estimated facility-specific post-compliance
pollutant loadings associated with the technology bases for facilities
to comply with effluent limitations based on each of the regulatory
options in this proposal. For each regulatory option, the EPA then
calculated the changes in pollutant loadings at a particular facility
as the sum of the differences between the estimated baseline and post-
compliance discharge loadings for each applicable wastestream.
    For those facilities that discharge indirectly to POTWs, the EPA
adjusted the baseline and option loadings to account for pollutant
removals expected from POTWs. These adjusted pollutant loadings for
indirect dischargers therefore approximate the resulting discharges to
receiving waters. For additional details on the methodology the EPA
used to calculate pollutant loading reductions, see Section 6 of the
Supplemental TDD.

A. FGD Wastewater

    For FGD wastewater, the EPA continued to use the average pollutant
effluent concentration with facility-specific discharge flow rates to
estimate the mass pollutant discharge per facility for baseline and
each regulatory option in Table VII-1. The EPA used data compiled for
the 2015 rule as the initial basis for estimating discharge flow rates
and updated the data to reflect retirements or other relevant changes
in operation. For example, the EPA reviewed state and EIA data to
identify flow rates for new scrubbers that have come online since the
2015 rule. The EPA also accounted for increased rates of recycle
through the scrubber that would affect the discharge flow.
    The EPA assigned pollutant concentrations for each analyte based on
the operation of a treatment system designed to comply with the
baseline or the regulatory options considered. The EPA used data
compiled for the 2015 rule to characterize untreated FGD purge,
chemical precipitation effluent, and chemical precipitation plus high
hydraulic residence time biological reduction effluent. The EPA used
data provided by industry to characterize effluent quality for chemical
precipitation plus LRTR and membrane filtration effluent. In addition,
the EPA used data provided by industry and other stakeholders as
described in Section VI of this preamble to quantify bromide in FGD
wastewater under baseline conditions and for the regulatory options.

B. BA Transport Water

    The EPA estimated baseline and post-compliance loadings for each
regulatory option in Table VII-1 using pollutant concentrations for BA
transport water and facility-specific flow rates. The EPA used data
compiled for the 2015 rule as the basis for estimating BA transport
water discharge flows and updated the data set to reflect retirements
and other relevant changes in operation (e.g., ash handling
conversions, fuel conversions) that occurred after the 2015 rule data
were collected. For the high recycle rate technology option, the EPA
also estimated discharge flows associated with the purge from remote
MDS operation, based on the boiler capacity and the volume of the
remote MDS. Under the baseline, which reflects the 2015 rule limitation
of zero discharge, the EPA estimated a flow rate of zero.
    For this proposed rule, in response to the administrative petitions
discussed in Section IV of this preamble, the EPA was able to use a
revised set of the 2015 rule analytical data to characterize BA
transport water effluent from steam electric facilities. As an example,
the EPA re-evaluated and revised, as appropriate, its data sets in
light of questions petitioners raised about the inclusion and validity
of certain data due, in part, to what the petitioners assert are flaws
in data acceptance criteria, obsolete analytical methods, and the
treatment of non-detect analytical results, which petitioners believed
resulted in an overestimation of pollutant loadings resulting from
current practices for BA transport water, in turn resulting in an
overestimation of pollutant removals under the 2015 rule. The EPA also
updated the data set and incorporated BA transport water

sampling data submitted by industry during the final months of the 2015
rule and as part of a voluntary sampling program described in Section
VI of this preamble. For a detailed discussion, see Section 6 of the
Supplemental TDD.

C. Summary of Incremental Changes of Pollutant Loadings From Proposed
Regulatory Options

    Table IX-1 summarizes the net change to annual pollutant loadings,
compared to baseline, associated with each regulatory option in Table
VII-1.

  Table IX-1--Estimated Incremental Changes to Annual Pollutant Loading
for Proposed Regulatory Options 1, 2, 3, and 4 [in pounds/year] Compared
                               to Baseline
------------------------------------------------------------------------
                                                Changes in pollutant
           Regulatory option \a\                      loadings
------------------------------------------------------------------------
1.........................................                    13,400,000
2.........................................                  -104,000,000
3.........................................                  -276,000,000
4.........................................                -1,320,000,000
------------------------------------------------------------------------
Note: Changes in pollutant loadings are rounded to three significant
  figures.
\a\ Negative values represent an estimated decrease in loadings to
  surface waters compared to baseline. Positive values represent an
  estimated increase in loadings to surface waters compared to baseline.

    Compared to the 2015 rule, Options 2, 3 and 4 result in decreased
pollutant loadings to surface waters. Reductions under Options 2 and 3
would be realized to the extent that operators chose to meet the
limitations based on membrane filtration under the proposed revisions
of VIP for FGD wastewater. Under Option 2, the EPA estimated that 18
plants (27 percent of plants estimated to incur FGD compliance costs)
would opt into the VIP program and under Option 3 the number rises to
23 plants (34 percent of plants estimated to incur FGD compliance
costs).

X. Non-Water Quality Environmental Impacts

    The elimination or reduction of one form of pollution may create or
aggravate other environmental problems. Therefore, Sections 304(b) and
306 of the Act require the EPA to consider non-water quality
environmental impacts (including energy impacts) associated with ELGs.
Accordingly, the EPA has considered the potential impact of the
regulatory options in today's proposal on air emissions, solid waste
generation, and energy consumption. For the reasons described in
Section IX of this preamble, the baseline for these analyses
appropriately includes non-water quality environmental impacts
associated with achieving the 2015 rule requirements, and the EPA is
analyzing the incremental impacts resulting from the regulatory options
presented in Table VII-1 compared to those projected under the
baseline. In general, the EPA used the same methodology to conduct the
current analysis (with updated data as applicable) as it did for the
analysis supporting the 2015 rule. The following summarizes the
methodology and results. See Section 7 of the Supplemental TDD for
additional details.

A. Energy Requirements

    Steam electric facilities use energy when transporting ash and
other solids on or off site, operating wastewater treatment systems
(e.g., chemical precipitation, biological treatment), or operating ash
handling systems. For today's proposal, the EPA considered whether
there would be an associated change in the incremental energy
requirements compared to baseline. Energy requirements vary depending
on the regulatory option evaluated and the current operations of the
facility. Therefore, as applicable, the EPA estimated the increase in
energy usage in megawatt hours (MWh) for equipment added to the
facility systems or in consumed fuel (gallons) for transportation/
operating equipment for baseline and all regulatory options. The EPA
summed the facility-specific estimates to calculate the net change in
energy requirements from baseline for the regulatory options.
    The EPA estimated the amount of energy needed to operate wastewater
treatment systems and ash handling systems based on the horsepower
rating of the pumps and other equipment. The EPA also estimated the
fuel consumption associated with the changes in transportation needed
to landfill solid waste and combustion residuals (e.g., ash) at steam
electric facilities (on-site or off-site). The frequency and distance
of transport depends on a facility's operation and configuration;
specifically, the volume of waste generated and the availability of
either an on-site or off-site non-hazardous landfill and its distance
from the facility. Table X-1 shows the net change in annual electrical
energy usage associated with the regulatory options compared to
baseline, as well as the net change in annual fuel consumption
requirements associated with the regulatory options compared to
baseline.

  Table X-1--Estimated Incremental Change in Energy Requirements Associated With Regulatory Options Compared to
                                                    Baseline
----------------------------------------------------------------------------------------------------------------
                                                         Energy use associated with regulatory options \a\
            Non-water quality impact             ---------------------------------------------------------------
                                                     Option 1        Option 2        Option 3        Option 4
----------------------------------------------------------------------------------------------------------------
Electrical Energy Used (MWh)....................         -82,300         -54,570         -27,000          94,000
Fuel Used (Thousand Gallons)....................               0         -48,000          40,000         243,000
----------------------------------------------------------------------------------------------------------------
\a\ Negative values represent a decrease in energy use compared to baseline. Positive values represent an
  increase in energy use compared to baseline.

B. Air Pollution

    The regulatory options are expected to affect air pollution through
three main mechanisms: (1) Changes in auxiliary electricity use by
steam electric facilities to operate wastewater treatment, ash
handling, and other systems needed to meet regulatory standards; (2)
changes to transportation-related emissions due to the trucking of CCR
waste to landfills; and (3) the change in the profile of electricity
generation due to any regulatory requirements. This section discusses
air emission changes associated with the first two mechanisms and
presents the corresponding estimated net change in air emissions. See
Section XII of this preamble for additional discussion of the third
mechanism.
    Steam electric facilities generate air emissions from operating
transport vehicles, such as dump trucks, which release criteria air
pollutants and greenhouse gases when operated. Similarly, a decrease in
energy use or vehicle operation would result in decreased air
pollution.
    To estimate the net air emissions associated with changes in
electrical energy use projected as a result of the regulatory options
in today's proposal compared to baseline, the EPA combined the energy
usage estimates with air emission factors associated with electricity
production to calculate air emissions associated with the incremental
energy requirements. The EPA used emission factors projected by IPM V6
(ton/MWh) for nitrogen oxides, sulfur dioxide, and carbon dioxide to
generate estimates of the changes in air emissions associated with
changes in energy production for Options 2 and 4 compared to
baseline.\88\
---------------------------------------------------------------------------

    \88\ Only Options 2 and 4 were run through IPM; however,
extrapolated net benefits from air impacts for Options 1 and 3 are
available in Chapter 8 of the Benefit Cost Analysis report.
---------------------------------------------------------------------------

    To estimate net air emissions associated with the change in
operation of transport vehicles, the EPA used the MOVES2014b model to
identify air emission factors (grams per mile) for the air pollutants
of interest. The EPA estimated the annual number of miles that dump
trucks moving ash or wastewater treatment solids to on- or off-site
landfills would travel for the regulatory options. The EPA used these
estimates to calculate the net change in air emissions for the Options
2 and 4 compared to baseline. Table X-2 presents EPA's estimated net
change in air emissions associated with auxiliary electricity and
transportation.

    Table X-2--Estimated Net Change in Industry-Level Air Emissions Associated With Auxiliary Electricity and
                               Transportation for Options Compared to Baseline a b
----------------------------------------------------------------------------------------------------------------
                                                                 Change in emissions--    Change in emissions--
                   Non-water quality impact                      Option 2  (tons/year)     Option 4 (tons/year)
                                                                          \b\                      \c\
----------------------------------------------------------------------------------------------------------------
NOX...........................................................                    -32.7                     32.7
SOX...........................................................                    -54.3                     20.4
CO2...........................................................                  -44,600                   60,600
----------------------------------------------------------------------------------------------------------------
\a\ Negative values represent a decrease in energy use compared to baseline. Positive values represent an
  increase in energy use compared to baseline.
\b\ Option 2 estimates are based on the IPM sensitivity analysis scenario that includes the ACE rule in the
  baseline (IPM-ACE).
\c\ Option 4 estimates are based on IPM analysis scenario that does not include the ACE rule in the baseline.

    The modeled output from IPM V6 predicts changes in electricity
generation due to compliance costs attributable to Options 2 and 4
compared to baseline. These changes in electricity generation are, in
turn, predicted to affect the amount of NOX, SO2,
and CO2 emissions from steam electric facilities. A summary
of the net change in annual air emissions under Options 2 and 4 for all
three mechanisms is shown in Table X-3. Similar to costs, the IPM V6
results from these options reflect the range of NWQEI associated with
all four regulatory options. To provide some perspective on the
estimated changes in annual air emissions, EPA compared the estimated
change in air emissions to the net amount of air emissions generated in
a year by all electric power facilities throughout the United States.
For a more details on the sources of air emission changes, see Section
7 of the Supplemental TDD.

     Table X-3--Estimated Net Change in Industry-Level Air Emissions Associated With Changes in Electricity
                                   Generation for Options Compared to Baseline
----------------------------------------------------------------------------------------------------------------
                                                                                2016 Emissions by
                                        Change in emissions--    Change in emissions--        electric power
       Non-water quality impact        Option 2 (million tons)  Option 4 (million tons)    generating industry
                                                 \a\                      \b\                 (million tons)
----------------------------------------------------------------------------------------------------------------
NOX..................................                    0.005                    0.001                     1.47
SOX..................................                    0.005                    0.002                     1.63
CO2..................................                     5.66                     1.24                    2,030
----------------------------------------------------------------------------------------------------------------
\a\ Option 2 emissions are based on the IPM sensitivity analysis scenario that includes the ACE rule in the
  baseline.
\b\ Option 4 emissions are based on the IPM sensitivity analysis scenario that does not include the ACE rule in
  the baseline.

C. Solid Waste Generation and Beneficial Use

    Steam electric facilities generate solid waste associated with
sludge from wastewater treatment systems (e.g., chemical precipitation,
biological treatment). The EPA estimated the change in the amount of
solids generated under each regulatory option for each facility in
comparison to the baseline. For FGD wastewater treatment, Regulatory
Options 2, 3, and 4 result in an increase in the amount of solid waste
generated compared to baseline. The

solid waste generation associated with Option 1 is comparable to
baseline. While BA solids are also generated at steam electric
facilities, all of the BA solids accounted for in the waste volumes
disposed in the 2015 rule analysis were suspended solids from
combustion, and therefore the regulatory options in today's proposal do
not alter the amount of BA or other combustion residuals generated.
Table X-4 shows the net change in annual solid waste generation,
compared to baseline, associated with the proposed regulatory options.

 Table X-4--Estimated Incremental Changes to Solid Waste Generation Associated With Regulatory Options Compared
                                                   to Baseline
----------------------------------------------------------------------------------------------------------------
                                                   Solid waste generation associated with regulatory options
          Non-water quality impact           -------------------------------------------------------------------
                                                  Option 1         Option 2         Option 3         Option 4
----------------------------------------------------------------------------------------------------------------
Solids Generated (tons/year)................               0          328,000          487,000        2,326,000
----------------------------------------------------------------------------------------------------------------

    The EPA also evaluated the potential impacts of diverting FA from
current beneficial uses toward encapsulation of brine (from membrane
filtration) for disposal in landfills. According to the latest ACAA
survey,\89\ over half of the FA generated by coal-fired facilities is
being sold for beneficial uses rather than disposed of, and the
majority of this beneficially used FA is replacing Portland cement in
concrete. This also holds true for the specific facilities currently
discharging FGD wastewater, as seen by sales of FA in the 2016 EIA-923
Schedule 8A.\90\ Summary statistics of the FA beneficial use percentage
for these facilities are displayed in Table X-5 below.
---------------------------------------------------------------------------

    \89\ Available online at: https://www.acaa-usa.org/Portals/9/Files/PDFs/2016-Survey-Results.pdf.
    \90\ Available online at: https://www.eia.gov/electricity/data/eia923/.

     Table X-5--Percent of FA Sold for Beneficial Use by Facilities
                       Discharging FGD Wastewater
------------------------------------------------------------------------
                                                           Percent of FA
                        Statistic                            sold for
                                                          beneficial use
------------------------------------------------------------------------
Min.....................................................               0
10th percentile.........................................               0
25th percentile.........................................               3
Mean....................................................              48
Median..................................................              50
75th percentile.........................................              88
90th percentile.........................................              98
Max.....................................................             100
------------------------------------------------------------------------

    In the EPA's coal combustion residuals disposal rule,\91\ the EPA
noted that FA replacing Portland cement in concrete would result in
significant avoided environmental impacts to energy use, water use,
greenhouse gas emissions, air emissions, and waterborne wastes.
Although the EPA cannot tie specific facilities selling their FA to
this specific beneficial use, over half of the FA beneficially used
currently replaces Portland cement in concrete. Therefore, where sale
for this particular beneficial use occurs by facilities that may
otherwise use their fly ash to encapsulate membrane filtration brine
under Option 4, the EPA proposes to find that unacceptable air and
other non-water quality environmental impacts will result.
---------------------------------------------------------------------------

    \91\ Available online at: http://www.regulations.gov Docket ID:
EPA-HQ-RCRA-2009-0640.
---------------------------------------------------------------------------

D. Changes in Water Use

    Steam electric facilities generally use water for handling solid
waste, including ash, and for operating wet FGD scrubbers. The BA
handling technologies associated with baseline and the regulatory
options in today's proposal for BA transport water eliminate or reduce