Bottom Ash Transport Water....................  Dry Bottom Ash Handling.........  .......  .......  .......  .......  .......       X        X        X
Leachate......................................  Chemical Precipitation..........  .......  .......  .......  .......  .......  .......       X        X
Gasification Wastewater.......................  Vapor-Compression Evaporation...       X        X        X        X        X        X        X        X
Flue Gas Mercury Control Wastes...............  Dry Handling....................  .......       X   .......       X        X        X        X        X
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Other Plant-Level Costs
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                Solids Transportation...........       X        X        X        X        X        X        X        X
                                                Solids Disposal.................       X        X        X        X        X        X        X        X
                                                Impoundments....................       X        X        X        X        X        X        X        X
                                                Compliance Monitoring...........       X        X        X        X        X        X        X        X
--------------------------------------------------------------------------------------------------------------------------------------------------------

 Table IX-2--Major Capital Cost Components Included in Compliance Costs
------------------------------------------------------------------------
           Technology module              Major capital cost components
------------------------------------------------------------------------
Chemical Precipitation.................   Equalization tank;
                                          Reaction tanks;
                                          Chemical feed systems;
                                          Solids contact
                                          clarifier;
                                          Sand filters;
                                          Treated wastewater
                                          tank;
                                          Sludge filter press;
                                          and
                                          Sludge holding tank.
Biological Treatment...................   Bioreactor tanks;
                                          Nutrient feed system
                                          and storage;
                                          Backwash system and
                                          backwash wastewater tank; and
                                          Heat exchangers (if
                                          needed).
Vapor-Compression Evaporation..........   Water softener;
                                          Brine concentrator;
                                          and
                                          Forced-circulation
                                          crystallizer.
Conversion of Wet Fly Ash Handling to     Conveyance Vacuum Line
 Dry Vacuum Fly Ash Handling.             Components (i.e., valves,
                                          piping, couplings);
                                          Filter-Receiver;
                                          Vacuum Pumps;
                                          Lot miscellaneous
                                          instrumentation and control;
                                          Steel or concrete
                                          silo;
                                          Silo Instrumentation
                                          and Aeration System; and
                                          Pugmill unloaders.
Conversion of Wet Bottom Ash Handling     Water bath trough;
 to Mechanical Drag System (MDS) or
 Remote MDS.
                                          Chain conveyor;
                                          Inclined conveyor;
                                          Storage silo;
                                          Remote MDS only:
                                          collection sump, chemical feed
                                          system, and recirculation
                                          pumps.
Transportation.........................   Only operating and
                                          maintenance cost components
Disposal...............................   On-Site Disposal:
                                          Landfill expansion
                                          construction
                                          Leachate treatment
                                          system
                                          Groundwater wells
                                          Closure cap
                                          Off-Site Disposal: no
                                          capital cost components
Compliance Monitoring..................   Only operating and
                                          maintenance cost components
------------------------------------------------------------------------

    For example, to comply with BAT regulatory Option 4 presented in
this proposal, EPA estimated compliance costs for a plant that
currently sluices fly ash to an ash impoundment and subsequently
discharges that fly ash transport water. In this case, EPA estimated
the cost for the plant to convert its fly ash handling system to a dry
vacuum system and assumed that certain components of its existing
system would continue to be used following the conversion.\56\ EPA also
included costs for additional equipment, such as vacuum systems and
silos, to handle and store the dry fly ash. EPA also included
additional transportation and landfill disposal costs and cost savings
for managing less waste through the ash impoundment(s).
---------------------------------------------------------------------------

    \56\ The conversion from wet to dry fly ash handling for a unit
requires new equipment to pneumatically convey the ash; however, ash
handling vendors stated that for dry vacuum retrofits, the existing
hopper equipment and branch lines can be retained and reused.
---------------------------------------------------------------------------

    As another example, EPA estimated compliance costs to comply with
BAT regulatory Option 4 for a plant that currently treats its FGD
wastewater through a chemical precipitation system prior to discharge.
In this case, EPA evaluated 1) whether the chemical precipitation
system design basis included equalization with 24-hour residence time,
2) if the plant had an equivalent number and/or type of reaction tanks,
and 3) if the plant already had components such as chemical feed
systems, solids contact clarification, sand filtration, effluent and
sludge holding tanks, sludge filter press, and pumps in place. If the
plant had any of these components in place, EPA did not include that
cost in its compliance cost estimate. EPA also evaluated whether
chemical addition costs would be required based on the plant's reported
chemical addition and dosages, and estimated the costs for installing
and operating the biological treatment stage.
    Following the evaluation of treatment in place, EPA estimated plant
and wastestream specific incremental costs using computerized design
and cost models. For the applicable wastestreams, the models provide
capital, annual O&M, one-time, and 3-, 5-, 6-, and 10-year recurring
costs for implementing and using the applicable technology basis. EPA
developed cost equations from responses to the industry survey,
published information, vendor contacts, and engineering judgment. EPA
developed the following cost modules:
     One-Stage Chemical Precipitation--calculates capital and
O&M costs associated with a one-stage chemical precipitation system;
     Biological Treatment--calculates capital and O&M costs
associated with an anoxic/anaerobic biological treatment system;
     Vapor-Compression Evaporation--calculates capital and O&M
costs associated with a vapor-compression evaporation system;
     Dry Fly Ash Handling--calculates capital, O&M, and
recurring costs associated with a dry fly ash handling system;

     Dry Bottom Ash Handling--calculates capital, O&M, and
recurring costs associated with a dry bottom ash handling system;
     Transportation--calculates O&M costs associated with
transporting FGD, ash, and/or landfill leachate solid waste to an on-
site or off-site landfill;
     Disposal--calculates capital and O&M costs associated with
disposing of FGD, ash, and/or landfill leachate solid waste in an on-
site or off-site landfill; and
     Impoundment Costs--calculates capital, O&M, and recurring
costs associated with the operation and maintenance of an on-site
impoundment.
    Ultimately, the cost model produces a plant-level summary of the
incremental technology option costs associated with each regulatory
option. Each plant incurring a cost for an evaluated wastestream is
presented in the output. To determine the total compliance cost for a
plant associated with a regulatory option, EPA calculated the various
cost components described above for each applicable wastestream. EPA
then summed the costs for each component of each wastestream to
calculate the total capital, O&M, and other recurring costs for the
plant. Section XI of this preamble and the RIA contains a more detailed
discussion of EPA's annualization of the compliance costs.
    EPA also evaluated the expected costs of compliance for new
sources. The construction of new generating units may occur at an
existing power plant or at a new plant construction site. The
incremental cost associated with complying with the proposed NSPS and
PSNS options will vary depending on the types of processes,
wastestreams, and waste management systems that the plant would have
installed in the absence of the proposed new source requirements. EPA
estimated capital and O&M costs for several scenarios that represent
the different types of operations that are present at existing units at
existing power plants or are typically included at new power plants.
These scenarios captured differences in the plant status (i.e.,
building a unit at a new location versus adding a new unit at an
existing power plant), presence of on-site impoundments or landfills,
type of ash handling, type of FGD systems in service, and type of
leachate collection and handling.
    Finally, EPA recognizes there are significant drivers including
federal, state, and local requirements for future air control
installations at existing units. As such, EPA also conducted a
sensitivity analysis that forecasts future installations of air
controls through 2020 \57\ and the associated costs of the regulatory
options discussed in this proposal. EPA estimated these installations
using data reported by individual plants in the survey regarding
planned installations, as well as analyses conducted by OAR using the
IPM, which is widely used by EPA for analysis of rules and policies
affecting electric power generating facilities. Section VIII.A.7
contains a discussion of EPA's approach for forecasting future
installations. EPA then estimated plant-specific costs for these future
installations, using the same approach as it used for current
operations.
---------------------------------------------------------------------------

    \57\ EPA expects that plants will be in compliance with new
federal and state air pollution control requirements by 2020.
---------------------------------------------------------------------------

B. Methodology for Estimating Plant-Specific Pollutant Reductions

    EPA took a similar approach to the one described above for costs in
estimating pollutant reductions associated with the limitations and
standards for the regulatory options in this proposal. That is, EPA
estimated incremental pollutant reductions for discharges of a
particular wastestream at a particular plant when its existing
practices would not lead to compliance with the option being evaluated.
In such cases, EPA estimated the annual pollutant (baseline) load
associated with the current discharge of a wastestream and the post-
compliance annual pollutant load expected after implementation of the
applicable technology basis. EPA then calculated the pollutant loading
reduction at a particular plant as the sum of the difference between
the estimated baseline and post-compliance discharge load for each
applicable wastestream.
    The following provides a brief discussion of the methodology EPA
used to estimate baseline loads discharged for the various
wastestreams. For those plants that discharge indirectly to POTWs, EPA
adjusted the baseline loads to account for pollutant removals expected
from POTWs. These adjusted pollutant reductions for indirect
dischargers reflect reductions in discharges to receiving waters.
1. FGD Wastewater
    For FGD discharges, EPA estimated baseline loadings by assigning
pollutant concentrations based on the type of treatment system
currently in place at the plant. EPA assigned treatment in place for
this wastestream to one of four classes of treatment: surface
impoundment, chemical precipitation, anaerobic/anoxic biological
treatment, and vapor-compression evaporation. EPA identified the
plant's current treatment system using data reported in the industry
survey. Of the 117 plants that discharge FGD wastewater, 40 operate
chemical precipitation systems, six operate biological treatment
systems, and two operate a vapor-compression evaporation system.\58\
All other plants are categorized in the surface impoundment class of
treatment.
---------------------------------------------------------------------------

    \58\ A third power plant is currently installing a vapor-
compression evaporation system to treat the FGD wastewater.
---------------------------------------------------------------------------

    EPA then estimated the average baseline pollutant effluent
concentration of each analyte for each class of treatment. EPA used
data collected in its sampling program to characterize effluent
concentrations from chemical precipitation, anoxic/anaerobic biological
treatment, and vapor-compression evaporation systems. Because EPA
lacked data on pollutant effluent concentrations associated with FGD
wastewater impoundments, EPA estimated that surface impoundments remove
particulate matter (including the particulate phase metals) to an
equivalent treatment level of 30 mg/L TSS (i.e., thus assuming that the
discharge would be in compliance with the current BPT effluent limits
for low-volume waste sources). EPA estimated that all dissolved metals
will pass through the surface impoundment and be discharged. Section 10
of the TDD contains more information on baseline pollutant effluent
concentrations.
    EPA then used this average baseline pollutant effluent
concentration with plant-specific discharge flow rates reported in the
industry survey to estimate the mass pollutant discharged per
plant.\59\ Section 9 of the TDD contains more details on how EPA
developed flow rates.
---------------------------------------------------------------------------

    \59\ In some cases, plant-specific discharge flow rates were not
available in the survey response. See Section 9 of the TDD for more
information on how EPA estimated flow rates.
---------------------------------------------------------------------------

    For post-compliance FGD pollutant loading concentrations, for each
pollutant, EPA used the long-term average for the technology basis for
the option being evaluated. With a few exceptions, EPA then used these
pollutant concentrations in combination with the same plant-specific
discharge flow rates it used for baseline. The exceptions are five
plants currently discharging FGD wastewater that EPA predicts will
incorporate recycle within the FGD system based on the maximum
operating chlorides concentration compared to the design maximum
chlorides concentration.

2. Fly Ash and Bottom Ash
    For baseline ash loads, EPA used publicly available data to
characterize discharges from ash impoundments, including data collected
during EPA's Detailed Study, EPRI PISCES reports, permit application
data, and the 1982 Development Document for Final Effluent Limitations
Guidelines, New Source Performance Standards, and Pretreatment
Standards for the Steam Electric Point Source Category (EPA 440-1-82-
029). EPA used the concentration data obtained from these sources to
calculate the average pollutant concentration in fly ash, bottom ash,
and combined ash impoundments. EPA then coupled these concentrations
with plant-specific ash sluice rates reported in the industry survey to
calculate baseline ash discharge loads. In cases where EPA had
available information regarding recycle associated with the impoundment
overflow, EPA adjusted the sluice rates to reflect the discharge flow
rate from the impoundment. For post-compliance pollutant loadings, EPA
assumed implementation of dry ash handling would result in a zero post-
compliance load.
3. Combustion Residual Leachate
    For baseline leachate loads, EPA used data reported in Part G of
the industry survey to calculate an average baseline pollutant
concentration for leachate. These data included responses from 22
active fuel combustion residual landfills and four inactive fuel
combustion residual landfills. EPA then used the baseline pollutant
concentrations in conjunction with leachate flow rates to calculate the
baseline pollutant loadings. Section 9 of the TDD describes how EPA
used industry survey data to estimate leachate flow rates. For post-
compliance leachate loads, EPA lacked data on effluent concentrations
from chemical precipitation or biological treatment of leachate from
combustion residual landfills or surface impoundments. EPA is proposing
the effluent limits for leachate discharges would be based on
transferring the effluent limits calculated for FGD wastewater using
the identical technology bases. Therefore, EPA estimates, based on
engineering judgment, that post-compliance effluent concentrations for
leachate would be equal to the average effluent FGD wastewater
concentrations for a similar treatment technology.
4. FGMC and Gasification Wastewaters and Nonchemical Metal Cleaning
Wastes
    FGMC wastewater originates from activated carbon injection systems.
EPA identified 73 plants with current or planned activated carbon
injection systems. Most of these plants use, or plan to use, a dry
handling system to transfer the mercury-containing carbon to silos for
temporary storage until the waste is hauled away by trucks for disposal
in a landfill. EPA identified only six plants that transport (sluice)
FGMC waste with water to a surface impoundment. However, five of these
six plants do not discharge any FGMC wastewater and the remaining plant
has the capability to handle the FGMC waste using a dry system but
sometimes uses a wet system instead. Since the current baseline
discharge of pollutants for FGMC wastewater is essentially zero, the
proposed rule would establish effluent limitations that are consistent
with the current industry practices for FGMC wastewater (i.e., zero
discharge) and therefore EPA estimates there will be no (or little)
incremental removal of pollutants relative to current practices. At the
same time, however, establishing the proposed zero discharge standard
for FGMC wastewater will ensure that future FGMC installations
implement dry waste handling practices or manage wastewater in a manner
that achieves zero discharge of pollutants.
    The two IGCC plants currently operating in the United States
already use the technology that is the basis for all eight regulatory
options for gasification wastewater. A third IGCC plant that will soon
begin commercial operation will also use this same treatment
technology. Since these plants are already operating the technology
that serves as the basis for the proposed BAT, the proposed rule would
establish effluent limitations that are consistent with the current
industry practices for gasification wastewater and, therefore, EPA
estimates there will be no incremental removal of pollutants relative
to current practices.
    The proposed ELGs for discharges of nonchemical metal cleaning
waste are equal to the current BPT effluent limits for metal cleaning
waste. The proposed requirements are based on the same technology that
was used as the basis for the current ELGs requirements for chemical
metal cleaning waste. Since, as described above in Section VIII,
nonchemical metal cleaning waste is included within the definition of
metal cleaning waste, EPA would be establishing ELGs that are equal to
the BPT limits that already apply to discharges of these wastes to
surface waters.\60\ Additionally, as described in Section VIII.A.3, EPA
is proposing to exempt from new copper and iron limitations and
standards any existing nonchemical metal cleaning wastes generated and
currently authorized for discharge without copper and iron limits. As a
result, all facilities are either already in compliance or will be
exempt from the requirements; therefore, no facilities would incur
incremental costs to comply with the proposed ELGs for these wastes,
nor would there be incremental pollutant removals associated with the
proposed ELGs.
---------------------------------------------------------------------------

    \60\ The proposed BAT would establish limits for copper and iron
equal to the existing BPT limits for these pollutants. The proposed
NSPS would establish standards for copper, iron, TSS, and oil and
grease that are equal to the BPT limits for these pollutants. The
proposed PSES and PSNS would establish standards for copper equal to
the BPT limits for copper. See Section VIII for details about the
proposed limitations for nonchemical metal cleaning wastes.
---------------------------------------------------------------------------

5. Request for Comment on Data
    While EPA is soliciting comment on all aspects of this proposal,
the Agency would like to highlight certain aspects related to the
pollutant removal estimates. EPA solicits additional data or
information on pollutant loadings in steam electric power plant
wastewater discharges that would corroborate or correct the data used
in EPA's analysis, including data or information relating to the
pollutants of concern that EPA has identified in this rulemaking. It is
important that EPA have data and information of sufficient quality in
order to incorporate the data into its analysis. If you have data or
information or you intend to collect data that you believe would be
relevant to EPA and you would like to submit the data as part of your
public comments, EPA encourages you to contact the Agency first to
ensure that the data submitted contains sufficient and relevant
information, and that it is provided in an appropriate format, such
that it can inform EPA's analyses for the final action (see points of
contact in the introduction to this preamble).
    EPA is also seeking comment related to the data used in developing
this proposed rule and how it should be analyzed: age of data,
treatment of non-detects, treatment of pollutants in the source water
and the calculation of toxic-weighted pollutant equivalents.
    Age of data. How should EPA take into account changes that may have
occurred in the industry over time and what information would be
appropriate for demonstrating that certain data for certain pollutants
or wastestreams should or should not be used? For

example, should EPA use a date cutoff for the data used and what
rationale should be used for any such cutoff? EPA encourages commenters
to submit any more recent data (but you should contact EPA first to
make sure the data you submit is usable for the analyses, see above).
    Treatment of non-detect values. How should EPA treat non-detects in
effluent data when determining baseline pollutant loadings? What other
information should inform how EPA handles the issue of non-detects,
given that in some cases, analytical methods cannot determine the
actual amount of pollutants in wastewater? Should EPA use a cutoff for
the number or percentage of non-detects in a dataset in order for EPA
to use the dataset for a specific pollutant? For example, there were
more non-detects than detected values for effluent data for sulfides.
Does this dataset provide a sufficient basis, in the absence of any
other information, for estimating pollutant loadings for sulfides?
    Treatment of pollutants in the source water. When should EPA adjust
pollutant loadings concentrations to account for contributions from a
facility's source water? Should EPA estimate pollutant loadings for
pollutants for which a certain percentage of the influent concentration
comes from source water? If EPA were to do this, what steps should the
Agency take to ensure the adjustments for source water contribution
definitively link the source water data to the influent and effluent
data?
    Calculation of toxic-weighted pollutant equivalents. Is EPA's
calculation of TWPEs appropriate? Do commenters have suggestions,
either generally or relative to specific pollutants, for how this
calculation can be improved?

C. Summary of National Engineering Costs and Pollutant Reductions for
Existing Plants

    As described above in Section VIII, EPA evaluated eight regulatory
options comprised of various combinations of the technology options
considered for each wastestream, summarized in Table VIII-1. The Agency
estimated the costs and pollutant loading reductions associated with
steam electric power plants to achieve compliance with each regulatory
option under consideration. This section summarizes the total estimated
compliance costs and pollutant reductions associated with each option
for existing plants (see Tables IX-3 and IX-4). These tables present
the capital cost, annual operating and maintenance costs, one-time
costs, and recurring costs for each regulatory option. Section XI
contains a listing of total annualized costs by regulatory option. All
cost estimates in this section are expressed in terms of pre-tax 2010
dollars. The costs shown in Section XI take into account the timeframe
proposed to meet the limits in the rule.
    Information, including plant-specific information, for EPA's
compliance cost and pollutant loading estimates and methodologies is
located in the rulemaking record. Some of the information EPA used to
estimate compliance costs and pollutant loadings was claimed by survey
respondents as CBI. Therefore, this information is not included in the
public docket. However, the public docket contains a number of
documents that set forth EPA's methodology, assumptions and rationale
for developing its cost estimates and pollutant loadings estimates, and
that also present as much data as possible by using aggregation,
summaries, and other techniques to protect CBI. EPA encourages all
interested parties to refer to the record and to provide comments where
appropriate on any aspect of the methodology or the data used to
estimate compliance costs and pollutant loadings associated with this
proposal.

                                Table IX-3--Cost of Implementation (BAT and PSES)
                                      [In millions of pre-tax 2010 dollars]
----------------------------------------------------------------------------------------------------------------
                                  Number                                              Recurring costs
       Regulatory option            of      Capital   Annual    One time ---------------------------------------
                                  plants     cost    O&M cost    costs     3-year    5-year    6-year    10-year
----------------------------------------------------------------------------------------------------------------
1..............................       116    $1,450      $194       $0          $0        $0       $10     ($33)
3a.............................        66       398       177        0           0         0         0      (21)
2..............................       116     2,499       257        0           0         0        10      (33)
3b.............................        80       998       244        0           0         0         1      (26)
3..............................       155     2,897       434        0           0         0        10      (54)
4a \a\.........................       200     5,478       689        0.3         1        38        10      (90)
4..............................       277     8,011       988        0.6        28        65        16     (137)
5..............................       277    11,755     1,753        0.6        28        65        19     (137)
----------------------------------------------------------------------------------------------------------------
\a\ EPA estimated the costs for Option 4a based on approximated plant-level bottom ash costs for those plants
  that have at least one generating unit with a nameplate capacity of 400 MW or less and at least one other
  generating unit with a nameplate capacity of greater than 400 MW. For more details on how EPA estimated these
  plant-level bottom ash costs, see the memorandum entitled ``Methodologies for Estimating Costs and Pollutant
  Removals for Steam Electric ELG Regulatory Option 4a'' (DCN SE03834).

                        Table IX-4--Estimated Pollutant Loading Reduction (BAT and PSES)
                                            [In million pounds/year]
----------------------------------------------------------------------------------------------------------------
                                                                          Pollutant removals
                                                     -----------------------------------------------------------
                  Regulatory option                      Conventional          Priority         Nonconventional
                                                        pollutants \a\        pollutants        pollutants \b\
----------------------------------------------------------------------------------------------------------------
1...................................................                 2.8                 0.5           \c\ (418)
3a..................................................                  16                 0.4                 468
2...................................................                 2.8                 0.7               1,155
3b..................................................                17.1                 0.6                 914
3...................................................                  19                 1.1               1,623
4a \d\..............................................                  28                 1.4               2,612
4...................................................                  35                 1.7               3,328

5...................................................                  36                 1.7               5,287
----------------------------------------------------------------------------------------------------------------
\a\ The loadings reduction for conventional pollutants includes BOD and TSS. Note that the BOD and TSS removals
  are not included in the total pollutant removals stated in Section II (1.63 billion pounds per year for Option
  3; 3.34 billion pounds per year for Option 4) to avoid double-counting removals for certain priority and
  nonconventional pollutants that would also be measured by these bulk parameters.
\b\ The loadings reduction for nonconventional pollutants excludes TDS and COD to avoid double-counting removals
  for certain pollutants that would also be measured by these bulk parameters (e.g., sodium, magnesium).
\c\ Option 1 shows a negative removal for nonconventional pollutants because the mass of several pollutants
  (ammonia, chromium, TKN, and BOD) are not quantified at baseline, and because some pollutant discharge
  concentrations are higher under Option 1.

    EPA estimated the pollutant removals for Option 4a based on
approximated plant-level bottom ash loadings for those plants that have
at least one generating unit with a nameplate capacity of 400 MW or
less and at least one other generating unit with a nameplate capacity
of greater than 400 MW. For more details on how EPA estimated these
plant-level bottom ash loadings, see the memorandum entitled
``Methodologies for Estimating Costs and Pollutant Removals for Steam
Electric ELG Regulatory Option 4a'' (DCN SE03834).

X. Approach To Determine Long-Term Averages, Variability Factors, and
Effluent Limitations and Standards

    This section describes the statistical methodology used to
calculate the long-term averages, variability factors, and limitations
for BAT, new source performance standards and pretreatment standards
for existing and new sources. The effluent limitations and standards
are based on long-term average effluent values and variability factors
that account for variation in treatment performance of the model
technology.
    The proposed effluent limitations and/or standards, collectively
referred to in the remainder of this section as ``limitations,'' for
pollutants for each technology option, as presented in this notice, are
provided as ``daily maximums'' and ``maximums for monthly averages.''
Definitions provided in 40 CFR 122.2 state that the daily maximum
limitation is the ``highest allowable `daily discharge,''' and the
maximum for monthly average limitation is the ``highest allowable
average of `daily discharges' over a calendar month, calculated as the
sum of all `daily discharges' measured during a calendar month divided
by the number of `daily discharges' measured during that month.'' Daily
discharges are defined to be the ```discharge of a pollutant' measured
during a calendar day or any 24-hour period that reasonably represents
the calendar day for purposes of sampling.'' In this section, the term
``option long-term average'' and ``option variability factor'' are used
to refer to the long-term averages and variability factors for
technology options for an individual wastestream rather than the
regulatory options described in Section VIII.

A. Criteria Used To Select Data as the Basis for the Limitations and
Standards

    In developing effluent limitations guidelines and standards for any
industry, EPA qualitatively reviews all the data before selecting data
that represents proper operation of the technology that forms the basis
for the limitations. EPA typically uses four criteria to assess the
data. The first criterion requires that the plants have the model
treatment technology and demonstrate consistently diligent and optimal
operation. Application of this criterion typically eliminates any plant
with treatment other than the model technology. EPA generally
determines whether a plant meets this criterion based upon site visits,
discussions with plant management, and/or comparison to the
characteristics, operation, and performance of treatment systems at
other plants. EPA often contacts plants to determine whether data
submitted were representative of normal operating conditions for the
plant and equipment. As a result of this review, EPA typically excludes
the data in developing the limitations when the plant has not optimized
the performance of its treatment system to the degree that represents
the appropriate level of control (BAT or BADCT).
    A second criterion generally requires that the influents and
effluents from the treatment components represent typical wastewater
from the industry, without incompatible wastewater from other sources.
Application of this criterion results in EPA selecting those plants
where the commingled wastewaters did not result in substantial
dilution, unequalized slug loads resulting in frequent upsets and/or
overloads, more concentrated wastewaters, or wastewaters with different
types of pollutants than those generated by the wastestream for which
EPA is proposing effluent limitations.
    A third criterion typically ensures that the pollutants are present
in the influent at sufficient concentrations to evaluate treatment
effectiveness. To evaluate whether the data meet this criterion for
inclusion as a basis of the limitations, EPA often uses the long-term
average test (or LTA test) for plants where EPA possesses paired
influent and effluent data (see Section 13 of the Technical Development
Document for details of the LTA test). The test measures the influent
concentrations to ensure a pollutant is present at a sufficient
concentration to evaluate treatment effectiveness. If a dataset for a
pollutant fails the test (i.e., pollutant not present at a treatable
concentration), EPA excludes the data for that pollutant at that plant
when calculating the limitations.
    A fourth criterion typically requires that the data are valid and
appropriate for their intended use (e.g., the data must be analyzed
with a sufficiently-sensitive method). Also, EPA does not use data
associated with periods of treatment upsets because these data would
not reflect the performance from well-designed and well-operated
treatment systems. In applying the fourth criterion, EPA may evaluate
the pollutant concentrations, analytical methods and the associated
quality control/quality assurance data, flow values, mass loading,
plant logs, and other available information. As part of this
evaluation, EPA reviews the process or treatment conditions that may
have resulted in extreme values (high and low). As a consequence of
this review, EPA may exclude data associated with certain time periods
or other data outliers that reflect poor performance or

analytical anomalies by an otherwise well-operated site.
    The fourth criterion also is applied in EPA's review of data
corresponding to the initial commissioning period for treatment
systems. Most industries incur commissioning periods during the
adjustment period associated with installing new treatment systems.
During this acclimation and optimization process, the effluent
concentration values tend to be highly variable with occasional extreme
values (high and low). This occurs because the treatment system
typically requires some ``tuning'' as the plant staff and equipment and
chemical vendors work to determine the optimum chemical addition
locations and dosages, vessel hydraulic residence times, internal
treatment system recycle flows (e.g., filter backwash frequency,
duration and flow rate, return flows between treatment system
components), and other operational conditions including clarifier
sludge wasting protocols. It may also take several weeks or months for
treatment system operators to gain expertise on operating the new
treatment system, which also contributes to treatment system
variability during the commissioning period. After this initial
adjustment period, the systems should operate at steady state with
relatively low variability around a long-term average over many years.
Because commissioning periods typically reflect one-time operating
conditions unique to the first time the treatment system begins
operation, EPA generally excludes such data in developing the
limitations.\61\
---------------------------------------------------------------------------

    \61\ Examples of conditions that are typically unique to the
initial commissioning period include operator unfamiliarity or
inexperience with the system and how to optimize its performance;
wastewater flow rates that differ significantly from engineering
design, altering hydraulic residence times, chemical contact times,
and/or clarifier overflow rates, and potentially causing large
changes in planned chemical dosage rates or the need to substitute
alternative chemical additives; equipment malfunctions; fluctuating
wastewater flow rates or other dynamic conditions (i.e., not steady
state operation); and initial purging of contaminants associated
with installation of the treatment system, such as initial leaching
from coatings, adhesives, and susceptible metal components. These
conditions differ from those associated with the restart of an
already-commissioned treatment system, such as may occur from a
treatment system that has undergone either short or extended
duration shutdown.
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B. Data Used as Basis of the Limitations and Standards

    The sections below discuss the data used as the basis for this
proposal, including data selection, the combination of data from
multiple sources within each plant, and the data exclusions made prior
to calculate the limitations.
1. Data Selection for Each Technology Option
    This section describes the data selected for use in developing the
limitations for each technology option. This section includes an
abbreviated description of the technology options. See Section VIII for
a more complete discussion of the technology basis for each of the
options considered. For fly ash transport water and FGMC wastewater,
all of the preferred regulatory options propose zero discharge of
pollutants based on dry handling technologies; therefore, no effluent
concentration data were used to set the limitations for these
wastestreams. This is also true for the options that include zero
discharge of pollutants for any set of dischargers for bottom ash.
    Except as described in Section VIII, EPA is proposing to establish
limitations for discharges of pollutants in nonchemical metal cleaning
wastes that are equal to the current BPT limitations that apply to
discharges of nonchemical metal cleaning wastes from existing sources
that are direct dischargers. No new effluent concentration data were
used to set the effluent limitations for nonchemical metal cleaning
wastes in this rulemaking, therefore the limitations for this
wastestream are not discussed in this section. See Section VIII for a
more complete discussion of the basis for the proposed limitations.
    Under some regulatory options being proposed today, EPA would
establish limitations for certain wastewater discharges that are equal
to the current BPT limitations for those discharges. No new effluent
concentration data would be used to establish BAT/NSPS limitations that
are set equal to BPT, therefore such limitations are not discussed in
this section. See Section VIII for a more complete discussion of the
basis for the proposed regulatory options. For the limitations for
combustion residual leachate (hereafter referred to in this section as
leachate) based on the chemical precipitation technology option, EPA is
proposing to transfer the limitations calculated based on the chemical
precipitation technology option for the FGD wastewater because EPA does
not have the available effluent data for leachate from plants that
employ the chemical precipitation technology. For the limitations based
on the biological treatment technology option for FGD wastewater, EPA
is proposing to transfer the limitations for two pollutants (mercury
and arsenic) calculated based on the chemical precipitation technology
option for the FGD wastewater for the reasons described below. See
Section 13 of the Technical Development Document for a detailed
discussion on the transfer of limitations for leachate and FGD
wastewater.
    EPA used specific data sources to derive limitations for pollutants
in FGD and gasification wastewater discharges based on particular
treatment technology. The data sources used to calculate limitations
for each technology option, by wastestream, are described below.
a. FGD Wastewater
    As part of the EPA sampling program and additional plant self-
monitoring data EPA obtained during the rulemaking, EPA evaluated the
performance of 10 FGD wastewater treatment systems. For seven of the 10
systems, EPA collected data representing the influent and effluent for
chemical precipitation treatment systems. EPA evaluated these seven
systems and determined that the systems operating the chemical
precipitation system with both hydroxide and sulfide precipitation
achieved better removals of mercury compared to the plants that used
only hydroxide precipitation. Therefore, EPA did not use data from the
three plants that use only hydroxide precipitation. Four of the seven
plants use hydroxide and sulfide precipitation; however, one of the
plants operates a two-stage chemical precipitation system. Because
EPA's basis for the technology option is a one-stage system, EPA did
not use the data from the two-stage system in developing the
limitations.\62\ Therefore, EPA used data from the following three
plants to develop the limitations based on treatment of FGD wastewater
using the chemical precipitation technology option (i.e., one-stage
chemical precipitation system employing both hydroxide and sulfide
precipitation and iron coprecipitation, as well as flow reduction at
plants with large FGD wastewater flow rates, hereafter referred to in
this section as ``chemical precipitation''--see Section VIII above for
a more detailed description):
---------------------------------------------------------------------------

    \62\ Based on data EPA has evaluated for the steam electric
industry and other industry sectors, two-stage chemical
precipitation systems generally achieve better pollutant removals
than one-stage systems. Since the technology basis for chemical
precipitation treatment of FGD wastewater in the proposed rule is a
one-stage system and that is the configuration used to estimate
compliance costs, EPA concluded that effluent data for the two-stage
system (Pleasant Prairie) should not be used when calculating
effluent limits for the technology option.

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     Duke Energy's Miami Fort Station (``Miami Fort'');
     RRI Energy's Keystone Generating Station (``Keystone'');
and
     Allegheny Energy's Hatfield's Ferry Power Station
(``Hatfield's Ferry'').
    For the treatment of FGD wastewater using a system that includes
biological treatment as part of the process, EPA evaluated the
treatment systems at three power plants as part of the EPA sampling
program; however, one of the biological treatment systems was not
designed for effective removal of selenium and does not represent the
model technology. The biological treatment technology option is based
on a one-stage chemical precipitation system employing both hydroxide
and sulfide precipitation and iron coprecipitation, as well as flow
reduction at plants with large FGD wastewater flow rates, followed by
anoxic/anaerobic biological treatment designed to remove selenium,
hereafter referred to in this section as ``biological treatment''--see
Section VIII above for a more detailed description. EPA used data from
the following two plants to develop the limitations for the treatment
of FGD wastewater using a one-stage chemical precipitation system
followed by biological treatment:
     Duke Energy Carolina's Belews Creek Steam Station
(``Belews Creek''); and
     Duke Energy Carolina's Allen Steam Station (``Allen'').
    While these two plants operate the biological treatment system
included as the basis for the technology option, neither of these
plants include sulfide precipitation in the upstream chemical
precipitation system and rely only on hydroxide precipitation.
Therefore, the effluent mercury and arsenic concentrations achieved by
these plants do not fully represent the effluent concentrations that
would be achieved by the system used as the design basis for the
technology option. For this reason, EPA is proposing to establish the
mercury and arsenic limitations for the biological treatment technology
option (which includes one-stage chemical precipitation as an initial
treatment stage) based on transferring the limitations that were
calculated for the chemical precipitation treatment technology option.
This is a reasonable approach for establishing mercury and arsenic
limitations for the biological treatment technology option because, in
doing so, EPA would be setting the limitations equal to the performance
that reflects the level of treatment that would be achieved by the
initial treatment stage of the wastewater treatment system.
    For the treatment of FGD wastewater using a chemical precipitation
followed by vapor-compression evaporation system hereafter referred to
in this section as ``vapor-compression evaporation'' (which is the
technology serving as the basis for regulatory Option 5, which is not a
preferred option in this proposal), EPA evaluated three systems as part
of the EPA sampling program. One plant operates a system that is
similar to the technology basis for the FGD wastewater limitations in
the proposed rule: A one-stage chemical precipitation system followed
by softening and a vapor-compression evaporation system. EPA used the
data from this plant to develop the limitations based on the vapor-
compression evaporation technology for the treatment of the FGD
wastewater. That plant is Enel's Federico II Power Plant, located in
Brindisi, Italy. EPA used data from a second plant for characterization
purposes and not for limitations development because it only collected
effluent data for one day from the plant. The third system does not
represent the technology serving as the basis for the vapor compression
evaporation option, and thus was not used for the limitations
development. This plant operates a solids removal process prior to the
vapor-compression evaporation system but does not include a full
chemical precipitation system nor a softening step. Furthermore, this
plant also operates a one-stage evaporation system and instead of
employing a second stage of evaporation to crystallize and remove salts
and other pollutants from the concentration brine, mixes the brine with
fly ash and sends it to the landfill for disposal.
b. Gasification Wastewater
    For the treatment of gasification wastewater using a vapor-
compression evaporation system, EPA evaluated systems from the
following two plants as part of the EPA sampling program:
     Tampa Electric Company's Polk Station (``Polk''); and
     Wabash Valley Power Association's Wabash River Station
(``Wabash River'').
    Both systems are representative of the system used as the basis for
the technology option and were used in calculating the limitations.
2. Combining Data From Multiple Sources Within a Plant
    Typically, if sampling data from a plant were collected over two or
more distinct time periods, EPA analyzes the data from each time period
separately. In previous effluent guidelines rulemakings, where
appropriate, EPA has analyzed the data for each time period as if each
time period represents a different plant since these data can represent
different operating conditions due to changes in management, personnel,
and procedures. On the other hand, when EPA obtains the data (such as
EPA's sampling and plant self-monitoring data) from a plant during the
same time period, EPA combines the data from these sources into a
single dataset for the plant for the statistical analysis.
    For this rulemaking, data at most selected plants came from
multiple sources (EPA's sampling, plant sampling as directed by the EPA
through 308 letters, or plant self-monitoring). For some plants, EPA
has data collected from multiple sources during overlapping time
periods. For these plants, EPA combined the multiple sources of data at
each plant into a single dataset for the plant, which provided the
basis for developing the limitations. Other plants had data collected
from multiple sources during non-overlapping time periods. However, in
these instances the time period between the non-overlapping data
collection periods was relatively small (two months). Furthermore, EPA
has no information to indicate that the data represent different
operating conditions. Thus, EPA also combined the multiple sources of
data for each of these plants into a single data set for the plant,
which provided the basis for developing the limitations. Finally, a
couple of plants had data from a single source, and for these plants it
was not necessary to combine data. For a listing of all the data and
their sampling sources for each of the plants, see DCN SE02002,
``Sampling Data Used as the Basis for Effluent Limitations for the
Steam Electric Rulemaking.''
3. Data Exclusions
    Following EPA's selection of the model plant(s), EPA applied the
criteria described above in Section A by thoroughly evaluating all
available data for each model plant. EPA identified certain data that
warranted exclusions from the calculations of the limitations because:
(i) The samples were analyzed using an insufficiently-sensitive
analytical method (i.e., use of EPA Method 245.1 instead of Method
1631E for mercury); (ii) the samples were collected during the initial
commissioning period for the treatment system; (iii) or analytical
results were identified as questionable due to quality control issues,
abnormal conditions or treatment upsets, or were analytical anomalies.
See DCN SE01999 for a detailed discussion of the data excluded.

C. Overview of the Limitations and Standards

    The sections below describe EPA's objectives for proposing the
daily maximum and monthly average limitations and the selection of
percentiles for those limitations.
1. Objective
    EPA's objective in establishing daily maximum limitations is to
restrict the discharges on a daily basis at a level that is achievable
for a plant that targets its treatment at the long-term average. EPA
acknowledges that variability around the long-term average occurs
during normal operations. This variability means that plants
occasionally may discharge at a level that is higher (or lower) than
the long-term average. To allow for these possibly higher daily
discharges, EPA has established the daily maximum limitation. A plant
that consistently discharges at a level near the daily maximum
limitation would not be operating its treatment to achieve the long-
term average. Targeting treatment to achieve the daily limitation,
rather than the long-term average, may result in values that frequently
exceed the limitations due to routine variability in treated effluent.
    EPA's objective in establishing monthly average limitations is to
provide an additional restriction to help ensure that plants target
their average discharges to achieve the long-term average. The monthly
average limitation requires dischargers to provide on-going control, on
a monthly basis, that supplements controls imposed by the daily maximum
limitation. In order to meet the monthly average limitation, a plant
must counterbalance a value near the daily maximum limitation with one
or more values well below the daily maximum limitation. To achieve
compliance, these values must result in a monthly average value at or
below the monthly average limitation.
2. Selection of Percentiles
    EPA calculates limitations based upon percentiles that should be
both high enough to accommodate reasonably anticipated variability
within control of the plant, and low enough to reflect a level of
performance consistent with the Clean Water Act requirement that these
effluent limitations be based on the ``best'' available technologies.
The daily maximum limitation is an estimate of the 99th percentile of
the distribution of the daily measurements. The monthly average
limitation is an estimate of the 95th percentile of the distribution of
the monthly averages of the daily measurements. The percentiles for
both types of limitations are estimated using the products of long-term
averages and variability factors. EPA has consistently used the 99th
percentile as the basis of the daily maximum limitation and 95th
percentile as the basis of the monthly average limitation in
establishing limitations for numerous industries and for many years and
numerous courts have upheld EPA's approach.
    EPA uses the 99th and 95th percentiles to draw a line at a definite
point in the statistical distributions that would ensure that operators
work to establish and maintain the appropriate level of control. These
percentiles reflect a longstanding Agency policy judgment about where
to draw the line. The development of the limitations takes into account
the reasonable anticipated variability in discharges that may occur at
a well-operated plant. By targeting its treatment at the long-term
average, a well-operated plant should be capable of complying with the
limitations at all times because EPA has incorporated an appropriate
allowance for variability in the limitations.
    In conjunction with setting the limitations as described above, EPA
performs an engineering review to verify that the limitations are
reasonable based upon the design and expected operation of the control
technologies and the plant process conditions. As part of the review,
for each plant EPA compared the influent and effluent measurements with
the proposed effluent limitations. See Section F below for details of
these comparisons for each pollutant at each plant, as well as a
discussion of the findings of the engineering review.

D. Calculation of the Limitations and Standards

    Effluent limitations and standards are based on a combination of
the long-term average and the appropriate variability factors. In
estimating the limitations for a pollutant, EPA first calculates an
average performance level (the option long-term average discussed
below) that a plant with well-designed and well-operated model
technologies is capable of achieving. This long-term average is
calculated using data from the plant or plants with the model
technologies for the option.
    In the second step of developing a limitation for a pollutant, EPA
determines an allowance for the variation (the option variability
factors discussed below) in pollutant concentrations for wastewater
that has been processed through well-designed and well-operated
treatment systems. This allowance for variation incorporates all
components of variability including shipping, sampling, storage, and
analytical variability. This allowance is incorporated into the
limitations through the use of the variability factors, which are
calculated from the data from the plants using the model technologies.
If a plant operates its treatment system to meet the relevant long-term
average, EPA expects the plant will be able to meet the limitations.
Variability factors ensure that normal fluctuations in a plant's
treatment are accounted for in the limitations. By accounting for these
reasonable excursions above the long-term average, EPA's use of
variability factors results in limitations that are generally well
above the long-term averages.
    The following sections describe the calculation of the option long-
term averages, option variability factors and limitations, and
adjustments for autocorrelation in calculating the limitations for each
pollutant proposed for regulation.
1. Calculation of Option Long-Term Average
    EPA calculated the option long-term average for a pollutant using
two steps. First, EPA calculated the plant-specific long-term average
for each pollutant that had enough distinct detected \63\ values by
fitting a statistical model to the daily effluent concentration values.
In cases when a dataset for a specific pollutant did not have enough
distinct detected values, then the statistical model was not used to
obtain the plant-specific long-term average. In these cases, the plant-
specific long-term average for each pollutant was the arithmetic mean
of the available daily effluent concentration values. Appendix B of the
Technical Development Document contains the required minimum number of
distinct detected observations and an overview of the statistical model
and a description of the procedures EPA used to estimate the plant-
specific long-term average.
---------------------------------------------------------------------------

    \63\ For the purpose of discussing the calculation of the long-
term averages, variability factors, and effluent limitations, the
term ``detected'' refers to analytical results measured and reported
above the sample-specific quantitation limit. Thus, values described
in this section as ``non-detected'' refers to values that are below
the method detection limit (MDL) and those measured by the
laboratory as being between the MDL and the quantitation limit (QL).
---------------------------------------------------------------------------

    Second, EPA calculated the option long-term average for a pollutant
as the median of the plant-specific long-term averages for that
pollutant. The median is the midpoint of the values when ordered (i.e.,
ranked) from smallest to largest. If there is an odd number of values,
then the value of the mth ordered observation is the median

(where m=(n+1)/2 and n=number of values). If there is an even number of
values, then the median is the average of the two values in the n/2th
and [(n/2)+1]th positions among the ordered observations.
2. Calculation of Option Variability Factors and Limitations
    The following describes the calculations performed to obtain the
option variability factors and limitations. First, EPA calculated the
plant-specific variability factors for each pollutant that had enough
distinct detected values by fitting a statistical model to the daily
effluent concentration values. Each plant-specific daily variability
factor for each pollutant is the estimated 99th percentile of the
distribution of the daily pollutant concentration values divided by the
plant-specific long-term average. Each plant-specific monthly
variability factor for each pollutant is the estimated 95th percentile
of the distribution of the 4-day average pollutant concentration values
divided by the plant-specific long-term average. The calculation of the
monthly variability factor assumes that the monthly averages are based
on the pollutant being monitored weekly (approximately four times each
month). In cases when there were not enough distinct detected values
for a specific pollutant at a plant, then the statistical model was not
used to obtain the plant-specific variability factors. In these cases,
the data for the pollutant at the plant was excluded from the
calculation of the option variability factors. Appendix B of the
Technical Development Document contains the required minimum number of
distinct detected observations and a description of the procedures used
to estimate the plant-specific daily and monthly variability factors.
    Second, EPA calculated the option variability factors. The option
daily variability factor for a pollutant was found as the mean of the
plant-specific daily variability factors for that pollutant. Similarly,
the option monthly variability factor was the mean of the plant-
specific monthly variability factors for that pollutant.
    Finally, the daily limitation for each pollutant was the product of
the option long-term average and option daily variability factor. The
monthly average limitation for each pollutant was the product of the
option long-term average and option monthly variability factor.
3. Adjustment for Autocorrelation Factors
    Effluent concentrations that are collected over time may be
autocorrelated. The data are positively autocorrelated when
measurements taken at specific time intervals, such as one or two days
apart, are similar. For example, positive autocorrelation would occur
if the effluent concentration were relatively high one day and were
likely to remain high on the next and possibly succeeding days. Because
the autocorrelated data may affect the true variability of treatment
performance EPA typically adjusts the variance estimates for the
autocorrelated data, when appropriate. For this rulemaking, whenever
there was sufficient data for a pollutant at a plant to evaluate the
autocorrelation reliably, EPA estimated the autocorrelation and
incorporated it into the calculation of the limitations. For a plant
without enough data to reliably evaluate and obtain a reliable estimate
of the autocorrelation, EPA set the autocorrelation to zero in
calculation of the limitations. EPA did so because there were not
sufficient data to reliably evaluate the autocorrelation, nor did EPA
have a valid correlation estimate available that could be transferred
from a similar technology and wastestream. See DCN SE02001 for details
of the statistical methods and procedures used to determine the
autocorrelation values, as well as a detailed discussion of the minimum
number of observations needed to obtain a reliable estimate of the
autocorrelation. Also, see Section 13 of the TDD.

E. Long-Term Average, Variability Factors, and Limitations for Each
Treatment Option

    Due to routine variability in treated effluent, a power plant that
discharges consistently at a level near the values of the daily maximum
limitation or the monthly average limitation may experience frequent
values exceeding the limitations. For this reason, EPA recommends that
power plants design and operate the treatment system to achieve the
option long-term average for the model technology. Thus, a system that
is designed to represent the BAT level of control will be capable of
complying with the limitations. The table below provides the proposed
long-term average, variability factors, and limitations for each of the
FGD, gasification, and leachate treatment technology options. See DCN
SE01999 for details of the calculation of the results presented in the
table below.

     Table X-1--Proposed Long-Term Averages, Variability Factors, and Effluent Limitations for Each of the FGD, Gasification, and Leachate Treatment
                                                                   Technology Options
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Daily          Monthly
           Treatment technology                       Pollutant             Option LTA      variability     variability        Daily          Monthly
                                                                                factor          factor      limitation \d\  limitation \d\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Chemical Precipitation for FGD............  Arsenic (ug/L)..............           4.483           1.741           1.223               8               6
                                            Mercury (ng/L)..............          75.404           3.209           1.570             242             119
Chemical Precipitation and Biological       Arsenic (ug/L)\a\...........           4.483           1.741           1.223               8               6
 Treatment for FGD.                         Mercury (ng/L)\a\...........          75.404           3.209           1.570             242             119
                                            Nitrate-nitrite (mg/L)......           0.110           1.499           1.157            0.17            0.13
                                            Selenium (ug/L).............           7.455           2.145           1.321              16              10
Chemical Precipitation and Evaporation for  Arsenic (ug/L)..............         \b\ 4.0           (\c\)           (\c\)           \e\ 4           (\f\)
 FGD.                                       Mercury (ng/L)..............          17.788           2.192           1.338              39              24
                                            Selenium (ug/L).............         \b\ 5.0           (\c\)           (\c\)           5 \e\           (\f\)
                                            TDS (mg/L)..................          14.884           3.341           1.572              50              24
Vapor-Compression Evaporation for           Arsenic (ug/L)..............         \b\ 4.0           (\c\)           (\c\)           \e\ 4           (\f\)
 Gasification.                              Mercury (ng/L)..............           1.075           1.632           1.194            1.76            1.29
                                            Selenium (ug/L).............         146.780           3.083           1.545             453             227
                                            TDS (mg/L)..................          15.209           2.483           1.389              38              22
Chemical Precipitation for Leachate.......  Arsenic (ug/L)\a\...........           4.483           1.741           1.223               8               6
                                            Mercury (ng/L)\a\...........          75.404           3.209           1.570             242             119
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Option long-term average, option variability factors, and limitations were transferred from chemical precipitation treatment technology option.
\b\ Long-term average is the arithmetic mean since all observations were non-detected.

\c\ All observations were non-detected, so the variability factors could not be calculated.
\d\ Limitations less than 1.0 are rounded up to the next highest hundredths decimal place. Limitations greater than 1.0 have been rounded upward to the
  next highest integer, except for limitations for mercury based on the vapor-compression evaporation treatment technology option for gasification
  wastewater which have been rounded up to the next highest hundredths decimal place.
\e\ Limitation is set equal to the detection limit.
\f\ Monthly average limitation is not established when the daily maximum limitation is based on the detection limit.

F. Engineering Review of Limitations and Standards

    In conjunction with the statistical methods, EPA performed an
engineering review to verify that the proposed limitations are
reasonable based upon the design and expected operation of the control
technologies. EPA performed two types of comparisons. First, EPA
compared the limitations to the effluent data used to develop the
limitations. Second, EPA compared the limitations to the influent data.
Sections below summarize the results of these comparisons. For a
detailed discussion of the results, see Section 13 of the Technical
Development Document for Proposed Effluent Limitations Guidelines and
Standards for the Steam Electric Power Generating Point Source Category
(TDD)--EPA 821-R-13.
1. Comparison of Limitations to Effluent Data Used As the Basis for the
Limitations
    As part of its data evaluations, EPA compared the limitations to
the effluent values used to calculate the limitations. This type of
comparison helps to evaluate how reasonable the proposed limitations
may be from an engineering perspective. As part of this evaluation, for
each pollutant proposed to be regulated under a technology option, EPA
first compared the daily limitations to the daily effluent values. EPA
then compared the monthly limitations to all the effluent daily values
in a month, and identified those months where at least one value
exceeded the monthly limitations.
    After thoroughly evaluating the results of the comparison between
the limitations and the effluent values used to calculate the
limitations for each treatment technology option for FGD and
gasification wastewaters, EPA determined that the statistical
distributional assumptions used to develop the limitations are
appropriate for the data, and thus the proposed limitations for each
technology option are reasonable. (This conclusion is also true for the
leachate limitations based on the chemical precipitation technology
since the leachate limitations were transferred from the FGD wastewater
technology option.) If a plant properly designs and operates its
wastewater treatment system to achieve the option long-term average for
the model technology (rather than targeting performance at the effluent
limits themselves), it will be able to comply with the limitations.
    However, EPA notes that some of the daily effluent values for the
BAT plants used to calculate the limitations were found to exceed
either the daily or monthly average effluent limitations. See Section
13.9.1 of the TDD for a detailed discussion of the comparison of the
limitations and the effluent values, including a discussion of those
effluent values that exceed the limitations. EPA solicits comment on
this evaluation and EPA's conclusion that plants with a properly
designed and operating treatment system would be able to comply with
the limitations.
2. Comparison of the Limitations to Influent Data
    In addition to comparing the proposed limitations to the data used
to develop the limitations, EPA also compared the value of the proposed
limitations to the influent concentration values. This comparison helps
evaluate whether the proposed limitations are set at a level that
ensures that treatment of the wastewater would be necessary to meet the
limitations and that the influent concentrations were generally well-
controlled by the treatment system. In doing so, EPA confirms that
treatment to remove the regulated pollutants will take place.
    For all treatment technology options for both FGD and gasification
wastewater, the minimum, average, and maximum influent concentration
values were much higher than the long-term average and proposed
limitations (see DCN SE01999). Thus, EPA determined that facilities
would need to treat the wastewater to ensure compliance with the
proposed limitations and that the proposed rule would result in
removing the regulated pollutants and other pollutants of concern.
Furthermore, in evaluating influent concentrations, EPA found that
influent concentrations were generally well-controlled by the treatment
system for all plants with model technology. In general, the treatment
systems adequately treated even the extreme influent values, and the
high effluent values did not appear to be the result of high influent
discharges.
    EPA expects that facilities will comply with their effluent
limitations at all times. If the exceedance is caused by an upset
condition, the facility would have an affirmative defense to an
enforcement action if the requirements of 40 CFR 122.41(n) are met. If
an exceedance is caused by a design or operational deficiency, then EPA
has determined that the facility's performance does not represent the
appropriate level of control. For these proposed limitations, EPA has
determined that such exceedances can be controlled by diligent process
and wastewater treatment system operational practices such as frequent
inspection and repair of equipment, use of back-up systems, and
operator training and performance evaluations. Additionally, some
facilities may need to upgrade or replace existing treatment systems to
ensure that the treatment system is designed to achieve performance to
target the effluent concentrations at the option long-term average.
This is consistent with EPA's costing approach for the ELG technology
options and its engineering judgment developed over years of evaluating
wastewater treatment processes for power plants and other industrial
sectors. EPA recognizes that, as a result of the proposed rule, some
dischargers, including those that are operating technologies
representing the ``best available'' technology, may need to improve
their treatment systems, process controls, and/or treatment system
operations in order to consistently meet the effluent limitations. EPA
believes that this is consistent with the Clean Water Act, which
requires that discharge limitations reflect the best available
technology economically achievable or the best available demonstrated
control technology.

XI. Economic Impact and Social Cost Analysis

A. Introduction

    EPA assessed the social costs and the projected economic impacts of
the eight regulatory options described in this proposal (see Section
VIII for a description of the options). This section provides an
overview of the methodology EPA used to assess the social costs (or
costs from the viewpoint of society rather than the regulated entity)
and the economic impacts of the proposed ELGs and summarizes the
results of these analyses. The Regulatory

Impact Analysis for Proposed Effluent Limitations Guidelines and
Standards for the Steam Electric Power Generating Point Source Category
(RIA)--EPA 821-R-13-005 and Benefits and Cost Analysis for the Proposed
Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category (BCA)--EPA 821-R-13-004 reports
available in the record for the rulemaking provide more details on
these analyses, including discussion of uncertainties and limitations.
    EPA estimated the costs to electric power producers--which include
steam electric plants owned by investor-owned utilities,
municipalities, states, federal authorities, cooperatives, and
nonutilities, whose primary business is electric power generation or
related electric power services--of complying with the proposed ELGs.
As described in Section VI of this preamble, EPA estimated that 1,079
power plants operated at least one steam electric generating unit
subject to the ELGs in 2009. EPA evaluated the costs and associated
impacts of this proposal on these existing plants, and on new units
that may be subject to the proposed revisions to the ELGs in the
future. Plants that EPA estimates would incur compliance costs as a
result of the proposed revisions to the ELGs are a subset of the 1,079
steam electric power plants.\64\
---------------------------------------------------------------------------

    \64\ As discussed in Section VIII, EPA is proposing different
effluent limits for existing oil-fired generating units and units
with a capacity of 50 MW or less. Because this proposed rule would
set BAT equal to BPT limits, EPA accordingly did not estimate
incremental costs for these units as a result of this proposed rule.
Many plants are comprised of multiple units, and as such, there may
be costs associated with some but not all units at a plant. The
plants may incur costs for other, larger units, however, if any such
units are also present; EPA's analysis includes costs for these
larger units.
---------------------------------------------------------------------------

B. Annualized Compliance Costs

    EPA's analyses of costs and economic impacts use the plant-level
costs described in Section IX of this preamble. As described in that
section, EPA developed plant-specific compliance costs for plants that
generate a wastestream for which EPA evaluated new limitations and
standards. Plant-specific compliance costs were developed for those
plants for which EPA obtained detailed technical data through the
industry survey. These costs consist of two principal components:
initial planning and capital costs; and recurring operating and
maintenance costs, which occur annually or according to a specified
frequency (e.g., every 3 years, 5 years, 6 years, or 10 years). EPA
applied survey weights to obtain costs for all 1,079 steam electric
plants. Since all plants incurring non-zero costs have a sample weight
of 1, the sum of costs for the surveyed plants also represents the
total costs for the entire universe of 1,079 plants.
    EPA restated compliance costs, accounting for the specific years in
which each plant is assumed to undertake compliance-related activities
and in 2010 dollars, using Construction Cost Index (CCI) from McGraw
Hill Construction, the Employment Cost Index (ECI) published by the
Bureau of Labor Statistics, and the Gross Domestic Product (GDP)
deflator index published by the U.S. Bureau of Economic Analysis (BEA).
EPA used 2010 dollars based on data available at the time the analysis
was developed. As a result, all dollar values reported in this analysis
are in constant 2010 dollars.
    EPA annualized the stream of future costs using 7 percent. The rate
of 7 percent is used in the cost impact analysis as an estimate of the
opportunity cost of capital.
    EPA annualized one-time costs and costs recurring on other than an
annual basis over a specific useful life, implementation, and/or event
recurrence period, using a rate of 7 percent. For capital costs and
initial one-time costs, EPA used 20 years. For O&M costs incurred at
intervals greater than one year, EPA used the interval as the
annualization period (i.e., 3 years, 5 years, 6 years, 10 years). EPA
added annualized capital, initial one-time costs, and the non-annual
portion of O&M costs to annual O&M costs to derive total annualized
compliance costs, where all costs are expressed on an equivalent
constantly recurring annual cost basis.
    EPA uses pre- and/or after-tax compliance costs in different
analyses, depending on the concept appropriate to each analysis (e.g.,
cost-to-revenue screening-level analyses discussed in Section XI.D are
conducted using after-tax compliance costs, whereas social costs
discussed in Section XI.C are calculated using pre-tax costs). For the
assessment of compliance costs, EPA considered costs on both a pre-tax
and after-tax basis. Pre-tax costs provide insight on the total
expenditure as incurred. After-tax costs are a more meaningful measure
of compliance impact on privately owned for-profit plants, and
incorporate approximate capital depreciation and other relevant tax
treatments in the analysis. EPA calculated the after-tax value of
compliance costs by applying combined federal and State tax rates to
the pre-tax cost values for privately owned for-profit plants. For this
adjustment, EPA used State corporate rates from the Federation of Tax
Administrators (http://www.taxadmin.org/) combined with federal
corporate tax rate schedules from the Department of the Treasury,
Internal Revenue Service.
    Table XI-1 presents the total annualized compliance costs of the
regulatory options on existing plants, estimated on a pre-tax and
after-tax base. The table lists the eight options in order of
increasing total annualized compliance costs. As shown in the table,
after-tax annualized compliance costs range between $108.4 million and
$1.55 billion for Options 3a and 5, respectively, with the preferred
BAT and PSES options estimated to have annualized industry-wide after-
tax costs of $108.4 million, $182.2 million, $389.0 million, $635.7
million (after-tax), respectively for Options3a, 3b, 3, and 4a. The
costs shown in Table XI-1 do not reflect the compliance costs for new
sources.

              Table XI-1--Total Annualized Compliance Costs
                          [In millions, 2010$]
------------------------------------------------------------------------
                 7% Discount rate                    Pre-tax   After-tax
------------------------------------------------------------------------
Option 3a.........................................     $168.1     $108.4
Option 3b.........................................      264.6      182.2
Option 1..........................................      265.9      190.6
Option 2..........................................      393.3      280.6
Option 3..........................................      561.3      389.0
Option 4a.........................................      947.8      635.7
Option 4..........................................    1,373.2      916.9
Option 5..........................................    2,277.3    1,547.9
------------------------------------------------------------------------

    The compliance costs above account for unit retirements,
repowerings and conversions that have been announced by companies and
are scheduled to occur by 2014, based on information obtained by EPA as
of August 2012. But they do not reflect additional planned unit
retirements, repowerings, and conversions that have been announced
since August 2012, nor do they reflect announced retirements,
repowerings, and conversions that are scheduled to occur by 2022. (See
DCN SE02033, ``Changes to Industry Profile for Steam Electric
Generating Units Updates''). EPA estimates that accounting for these
changes would reduce total annualized compliance costs. For example,
EPA estimated that total pre-tax annualized compliance costs for Option
3 would go from $561.3 million to $532.8 million (5 percent reduction),
whereas costs for Option 4 would go from $1,373.2 million to $1,252.9
million (9 percent reduction).

C. Social Costs

    Social costs are the costs of the rule from the viewpoint of
society as a whole, rather than regulated facilities. In calculating
social costs, EPA tabulated the pre-tax costs in the year when they are
incurred. EPA assumed that all plants subject to the proposed
regulation that would need to upgrade their systems would install
control technologies over a five-year period beginning in 2017. This
accounts for the time plants would have to implement control
technologies, as described in Section XVI. For the purpose of the
economic analyses, EPA assumed that plants would implement control
technologies 3 years after the renewal of their individual NPDES
permit, following the promulgation year, with NPDES permits assumed to
be renewed on time, following a 5-year cycle.\65\
---------------------------------------------------------------------------

    \65\ These assumed technology installation years do not
necessarily correspond to the actual years in which individual
facilities would be required to meet the effluent limits or
standards as specified in their permit, but is a reasonable
distribution of installation years for the aggregate set of steam
electric plants incurring compliance costs. These assumptions
reflect the approximate years in which technology installation would
reasonably be expected to occur, assuming that expiring permits are
renewed exactly on the 5-year mark. Note that EPA also analyzed the
effects of other technology installation periods. The results of
these analyses are detailed in Appendix B of the RIA report.
---------------------------------------------------------------------------

    EPA performed the social cost analysis over a 24-year analysis
period, which combines the length of the period during which plants are
expected to install the control technologies (five-year period
beginning in 2017) and the useful life of the longest-lived compliance
technology installed at any facility (20 years). Under this framework,
the last year for which costs (and benefits) were tallied in the
analysis is 2040. EPA calculated social cost of the eight regulatory
options for existing steam electric power plants using a 3 percent
discount rate. EPA also calculated social costs using an alternative
discount rate of 7 percent.\66\ For the analysis of social costs, EPA
discounted all costs to the beginning of 2014, which is the expected
promulgation year for the proposed rule.
---------------------------------------------------------------------------

    \66\ These discount rate values follow guidance from the Office
of Management and Budget (OMB) regulatory analysis guidance
document, Circular A-4 (OMB, 2003).
---------------------------------------------------------------------------

    As described in Section XVII.B, EPA does not believe the proposed
rule would lead to additional costs to permitting authorities.
Consequently, the only category of costs necessary to calculate social
costs are compliance costs; social costs differ from pre-tax compliance
costs due to timing of costs and discounting using a societal discount
rate.
    Table XI-2 presents the total annualized social cost of the
regulatory options on existing plants, calculated using 3 percent and 7
percent discount rates. The table lists the eight options in order of
increasing total social costs calculated using a 3 percent discount
rate.

                Table XI-2--Total Annualized Social Costs
                          [In millions, 2010$]
------------------------------------------------------------------------
                                               3% Discount   7% Discount
              Regulatory option                   rate          rate
------------------------------------------------------------------------
Option 3a...................................        $185.2        $164.5
Option 1....................................         268.3         259.2
Option 3b...................................         281.4         257.2
Option 2....................................         386.8         380.8
Option 3....................................         572.0         545.3
Option 4a...................................         954.1         914.7
Option 4....................................       1,381.2       1,323.2
Option 5....................................       2,328.8       2,209.4
------------------------------------------------------------------------

    At 3 percent discount rate, total annualized social costs for
existing plants vary from $185.2 million under Option 3a to $2.3
billion under Option 5, with the preferred BAT and PSES options having
total annualized social costs of $185.2 million, $281.4 million, $572.0
million, and $954.1 million, respectively for Options 3a, 3b, 3 and 4a.
The values presented in Table XI-2 for the 7 percent discount rate are
slightly lower than the comparable values (pre-tax) presented in Table
XI-1 due to the timing of compliance expenditures (e.g., $545.3 million
versus $561.3 million, for Option 3).
    These social costs do not reflect anticipated unit retirements and
conversions anticipated through 2024. As noted in the previous Section,
EPA anticipates that these changes would reduce total compliance costs
incurred by the Steam Electric power industry, and therefore reduce the
social costs of this action.

D. Economic Impacts

    EPA assessed the economic impacts of the regulatory options in two
ways: (1) A screening-level assessment of the impact of compliance
costs on existing plants and the entities that own those plants, based
on comparison of compliance costs to plant and entity revenue; and (2)
an assessment of the impact of the proposed regulatory options for both
existing and new plants within the context of the broader electricity
market, which includes an assessment of incremental plant closures
attributable to the proposed ELGs. EPA used the results of the
screening-level assessment to inform the selection of regulatory
options to be analyzed using the second approach.
    The following sections summarize the methods and findings for these
analyses.
1. Screening-Level Assessment of Impacts on Existing Plants and Parent
Entities Incurring Compliance Costs Associated With This Proposed Rule
    EPA conducted a screening-level analysis of the rule's potential
impact to existing steam electric plants and parent entities based on
cost-to-revenue ratios. For each of the two levels of analysis (plant
and parent entity), the Agency assumed, for analytic convenience and as
a worst-case scenario, that none of the compliance costs would be
passed onto consumers through electricity rate increases and would
instead be absorbed by complying plants and their parent entities. In
performing these and other impact analyses, EPA used the survey weights
to extrapolate impacts assessed initially for a sample of plants to all
1,079 steam electric plants and to their respective owning parent
entities.
a. Cost-to-Revenue Analysis for Plants Incurring Compliance Costs
Associated with this Proposed Rule
    EPA calculated the annualized after-tax compliance costs of the
regulatory options as a percent of baseline annual revenues.\67\
Revenue estimates used in this analysis were developed using Energy
Information Administration (EIA) data. (See Chapter 4 of the RIA report
for a more detailed discussion of the methodology used for the plant-
level cost-to-revenue analysis).\68\
---------------------------------------------------------------------------

    \67\ For private, tax-paying entities, after-tax costs are a
more relevant measure of potential cost burden than pre-tax costs.
For non tax-paying entities (e.g., State government and municipality
owners of affected plants), the estimated costs used in this
calculation include no adjustment for taxes.
    \68\ To develop the average of year-by-year revenue values over
the data years, EPA set aside from the averaging calculation,
revenue values for years that are substantially lower than the
otherwise ``steady state average''--e.g., because of a generating
unit being out of service for an extended period.
---------------------------------------------------------------------------

    Table XI-3 summarizes the screening-level plant-level cost-to-
revenue analysis results for the eight main regulatory options. EPA
estimates that the vast majority of plants subject to the proposed ELGs
will incur annualized costs amounting to less than 1 percent of revenue
for all eight regulatory options (887 to 1,051 plants, or 82 to 97
percent of the total 1,079 steam electric plants). A significant share
of these plants incur no compliance costs. For the preferred BAT and
PSES options (Options 3a, 3b, 3 and 4a), 92 percent to 97 percent of
steam electric plants have estimated costs that are less than 1 percent
of revenue. The number of plants with ratios between 1 percent and 3
percent, and above 3 percent,

generally rises when moving from Option 3a to Option 5. For the
preferred BAT and PSES options (Options 3a, 3b, 3 and 4a), two to six
percent of plants have cost-to-revenue ratios between 1 and 3 percent
and less than one percent to two percent have ratios above 3 percent.

                 Table XI-3--Plant-Level Cost-to-Revenue Analysis Results by Regulatory Option a
----------------------------------------------------------------------------------------------------------------
                                                                Number of plants with cost-to-revenue ratio of
                     Option                       No data on ---------------------------------------------------
                                                 revenue \b\       0%          0-1%         1-3%         >3%
----------------------------------------------------------------------------------------------------------------
Option 3a......................................            5        1,008           43           22            1
Option 3b......................................            5          994           54           24            2
Option 1.......................................            5          959           93           17            5
Option 2.......................................            5          959           86           18           11
Option 3.......................................            5          920          102           38           14
Option 4a......................................            5          875          114           65           20
Option 4.......................................            5          798          111          117           48
Option 5.......................................            5          798           89          115           72
----------------------------------------------------------------------------------------------------------------
\a\ This analysis makes a counterfactual, conservative assumption of zero cost pass-through. Plant counts are
  weighted estimates.
\b\ EIA does not report necessary data to estimate revenue for 5 plants.

b. Parent Entity-Level Cost-to-Revenue Analysis
    EPA also assessed the economic impact of the eight regulatory
options at the parent entity-level. The screening-level cost-to-revenue
analysis at the parent entity level provides insight on the impact of
compliance requirements on those entities that own more than one plant
incurring compliance costs associated with this proposed rule. For this
analysis, EPA identified the domestic parent entity of each plant and
obtained the entity's revenue from the industry survey or from publicly
available data sources. In this analysis, the domestic parent entity
associated with any given plant is defined as that entity that has the
largest ownership share in the plant.
    For each parent entity, EPA compared the total annualized after-tax
compliance costs, as of 2014, and the identified parent entity's total
revenue (see Chapter 4 of the RIA report for details). The total
parent-level annualized after-tax compliance costs represent total
costs for all steam electric plants in which the entity is the majority
owner.
    Compliance costs for the regulatory options were developed based on
surveyed plants (see Section XI.D.1.a). For the parent entity-level
analysis, EPA considered two approximate bounding cases to analyze the
owners of all 1,079 steam electric plants, based on the survey weights
developed from the industry survey. These cases, which are described in
more detail in Chapter 4 of the RIA, provide a range of estimates for
the number of entities incurring compliance costs and the costs
incurred by any entity owning a steam electric plant.
    Table XI-4 summarizes the results of the entity-level analysis for
the two analytic cases and the eight regulatory options.

                             Table XI-4--Parent Entity-Level After-Tax Annual Compliance Costs as a Percentage of Revenue a
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Not analyzed due      Number and percentage with after tax annual compliance costs/annual
                                                               to lack of                                     revenue of:
                                                  Total         revenue      ---------------------------------------------------------------------------
                    Option                      number of     information             0%                0-1%               1-3%          3% or Greater
                                                 entities ----------------------------------------------------------------------------------------------
                                                                %         %         %         %         %
--------------------------------------------------------------------------------------------------------------------------------------------------------
Case 1: Lower-bound estimate of number of entities owning steam electric plants; upper bound estimate of total compliance costs that an entity may incur
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3a.....................................        243        14        6       205       84        22        9         2        1         0        0
Option 3b.....................................        243        14        6       201       83        26       11         2        1         0        0
Option 1......................................        243        14        6       173       71        51       21         1       <1         4        2
Option 2......................................        243        14        6       173       71        46       19         6        2         4        2
Option 3......................................        243        14        6       168       69        49       20         7        3         5        2
Option 4a.....................................        243        14        6       157       65        55       23        11        5         6        2
Option 4......................................        243        14        6       137       56        64       26        21        9         7        3
Option 5......................................        243        14        6       137       56        57       23        20        8        15        6
--------------------------------------------------------------------------------------------------------------------------------------------------------
Case 2: Upper-bound estimate of number of entities owning steam electric plants; lower bound estimate of total compliance costs that an entity may incur
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3a.....................................        507        30        6       453       89        22        4         2       <1         0        0
Option 3b.....................................        507        30        6       449       89        26        5         2       <1         0        0
Option 1......................................        507        30        6       421       83        51       10         1       <1         4        1
Option 2......................................        507        30        6       421       83        46        9         6        1         4        1
Option 3......................................        507        30        6       416       82        49       10         7        1         5        1
Option 4a.....................................        507        30        6       405       80        55       11        11        2         6        1
Option 4......................................        507        30        6       385       76        64       13        21        4         7        1
Option 5......................................        507        30        6       385       76        57       11        20        4        15        3
--------------------------------------------------------------------------------------------------------------------------------------------------------
 equals the number of entities.

\a\ This analysis makes a counterfactual, conservative assumption of zero cost pass-through.

    The cost-to-revenue ratios provide screening-level indicators of
potential economic impacts. Entities incurring costs below 1 percent of
revenue are unlikely to face economic impacts, while entities with
costs between 1 percent and 3 percent of revenue have a higher chance
of facing economic impacts, and entities incurring costs above 3
percent of revenue have a still higher probability of economic impacts.
As presented in Table XI-4, EPA estimated that the number of entities
owning steam electric plants ranges from 243 (lower bound estimate) to
507 (upper bound estimate), depending on the assumed ownership
structure of plants not surveyed. Under the lower-bound case, EPA
estimates that the vast majority of parent entities will incur
annualized costs of less than 1 percent of revenues under all eight
analyzed regulatory Options (the shares are 93, 93, 89, and 87 percent
under Options 3a, 3 and 4a, respectively). These observations also hold
true under the upper bound case; an estimated 94, 94, 92, and 91
percent of parent entities incur annualized costs of less than 1
percent of revenue, for Options 3a, 3b, 3 and 4a, respectively.
    Overall, this screening-level analysis shows that the entity-level
compliance costs are low in comparison to the entity-level revenues;
very few entities are likely to face economic impacts at any level for
any of the four preferred BAT and PSES options (Options 3a, 3b, 3 and
4a).
2. Assessment of the Impacts in the Context of Electricity Markets
    In analyzing the impacts of regulatory actions affecting the
electric power sector, EPA has used the Integrated Planning Model
(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 production costs at the level of the individual generating
unit, on the total cost of electricity supply, subject to specified
demand and emissions constraints. To assess facility and market-level
effects of these proposed ELGs, EPA used an updated version of this
same analytic system: Integrated Planning Model Version 4.10 MATS (IPM
V4.10).
    Use of a comprehensive, market analysis system is important in
assessing the potential impact of the regulatory options because of the
interdependence of electricity generating units in supplying power to
the electric transmission grid. Increases in electricity production
costs at some plants can have a range of broader market impacts
affecting other plants, including the likelihood that various plants
are dispatched, on average.
    IPM V4.10 provides outputs for the North American Electric
Reliability Corporation (NERC) regions that lie within the continental
United States. IPM V4.10 does not analyze electric power operations in
Alaska and Hawaii because these states' electric power operations are
not connected to the continental U.S. power grid. However, none of the
steam electric plants that are estimated to incur compliance costs
associated with this proposal are located in these two regions.
    IPM V4.10 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, as recorded in EIA 860 (2006)
and EIA 767 (2005) databases.\69\ The IPM baseline universe of plants
includes nearly all of the steam electric plants that could be subject
to the proposed ELGs and are estimated to incur compliance costs.\70\
IPM Version 4.10 embeds a baseline energy demand forecast that is
derived from DOE's Annual Energy Outlook 2010 (AEO2010). IPM V4.10 also
incorporates in its analytic baseline the expected compliance response
to existing regulatory requirements for the following promulgated air
regulations affecting the power sector: the final Mercury and Air
Toxics Standards (MATS) rule; the final Cross-State Air Pollution Rule
(CSAPR) \71\; regulatory SO2 emission rates arising from
State Implementation Plans (SIP); Title IV of the Clean Air Act
Amendments; NOX SIP Call trading program; Clean Air Act
Reasonable Available Control Technology requirements and Title IV unit
specific rate limits for NOX; the Regional Greenhouse Gas
Initiative; Renewable Portfolio Standards; New Source Review
Settlements; and several state-level regulations affecting emissions of
SO2, NOX, and mercury that are already in place
or expected to come into force by 2017.
---------------------------------------------------------------------------

    \69\ In some instances, plant information has been updated to
reflect known material changes in a plant's generating capacity
since 2006.
    \70\ The IPM plant universe excludes two steam electric plants
estimated to incur compliance costs under the proposed ELG scenarios
EPA analyzed in IPM. See Chapter 5 of the RIA report for more
details.
    \71\ EPA's Cross-State Air Pollution Rule (CSAPR) was
promulgated to replace EPA's Clean Air Interstate Rule (CAIR), which
had been remanded to EPA in 2008. However, on December 30, 2011, the
U.S. Court of Appeals for the D.C. Circuit stayed CSAPR pending
judicial review and left CAIR in place. On August 21, 2012 the Court
issued an opinion vacating CSAPR and again leaving CAIR in place
pending development of a valid replacement. On March 29, 2013, the
United States filed a petition asking the Supreme Court to review
the D.C. Circuit's opinion. Nevertheless, as explained above, CAIR
remains in effect at this time. In light of the continuing
uncertainty on CAIR and CSAPR, EPA does not believe it would be
appropriate or possible at this time to adjust emission projections
on the basis of speculative alternative emission reduction
requirements in 2020. EPA expects that the decision vacating CSAPR
and leaving CAIR in place has a minimal effect on the results of the
analysis conducted in support of the proposed ELGs.
---------------------------------------------------------------------------

    In contrast to the screening-level analyses, which are static
analyses and do not account for interdependence of electric generating
units in supplying power to the electric transmission grid, IPM
accounts for potential changes in the generation profile of steam
electric and other units and consequent changes in market-level
generation costs, as the electric power market responds to higher
generation costs for steam electric units due to the proposed ELGs. IPM
is also dynamic in that it is capable of using forecasts of future
conditions to make decisions for the present. Additionally, in contrast
to the screening-level analyses in which EPA assumed no pass through of
compliance costs, IPM depicts production activity in wholesale
electricity markets where some recovery of compliance costs through
increased electricity prices is possible but not guaranteed.
    In performing analyses based on IPM V4.10, EPA used as its
baseline--i.e., reflecting the world without this proposed regulation--
a projection of electricity markets and facility operations over the
period from the expected promulgation year, 2014, through 2030. As
discussed above, this baseline accounts for compliance with the
recently promulgated federal air rules.
    As discussed in greater detail in Appendix C of the RIA, IPM
generates least-cost resource dispatch decisions based on user-
specified constraints such as environmental, demand, and other
operational constraints. In analyzing the proposed ELGs, EPA specified
additional fixed and variable costs that are expected to be incurred by
specific steam electric plants and generating units to comply with the
proposed ELGs. EPA then ran IPM including these additional costs to
determine the dispatch of electricity generating units that would meet
projected demand at

the lowest costs, subject to the same constraints as those present in
the analysis baseline. The least-cost dispatch solution for meeting
electricity supply may change as the result of the changes in fixed and
variable costs at the level of the individual plant and generating
unit, which EPA estimates would occur as a result of the proposed ELGs.
These estimated changes in plant- and unit-specific production levels
and costs--and, in turn, changes in total electric power sector costs
and production profile--are key data elements in evaluating the
expected national and regional effects of the proposed ELGs.
    EPA used the screening-level analyses described above to inform the
selection of regulatory options to be analyzed using IPM. In allocating
resources to analytical effort, EPA chose to run IPM in a phased
approach, starting with Option 3 and then Option 4, with the notion to
proceed if additional model runs were warranted.
    EPA first analyzed a scenario developed based on Option 3 but where
the total compliance costs and the set of existing plants that are
assigned costs varied slightly from those in the Option 3 discussed in
other parts of this preamble.\72\ Thus, the Option 3 scenario analyzed
using IPM and discussed below did not include small changes to the
timing of some O&M costs and to the set of plants assigned compliance
costs for this option. Because of these changes and the need to protect
data claimed as CBI by plant owners, total compliance costs for Option
3 as analyzed in IPM are approximately 10 percent lower than for the
proposed Option 3 discussed in the rest of this document. EPA also
analyzed a scenario in IPM that corresponds to BAT and PSES Option 4
discussed elsewhere in this notice.\73\ Both scenarios analyzed in IPM
included NSPS and PSNS compliance costs for new coal generation, based
on the preferred Option 4 for new sources.
---------------------------------------------------------------------------

    \72\ The costs as analyzed in IPM differ slightly from those
used in the non-IPM analyses. For more details on these differences,
see Chapter 5 of the RIA report. Note that the scenario assigns
compliance costs for existing plants based on Option 3, and
compliance costs for new capacity projected in IPM based on Option
4.
    \73\ Compliance costs differ only slightly (1 percent lower)
from costs used in other analyses, primarily to avoid disclosing
CBI. There are no differences in the set of plants estimated to
incur compliance costs or in the timing of the costs. For more
details, see Chapter 5 of the RIA report.
---------------------------------------------------------------------------

    The two scenarios analyzed in IPM provide insight on the market
impacts of the regulatory options EPA considered for this proposal.
Options 3 and 4 as analyzed in IPM are similar enough to these proposed
Options 3 and 4 to provide valuable insight on the likely impacts of
the proposed ELGs. Options 3a, 1, 2, and 3b are less stringent than
either of the two other options analyzed in IPM; as discussed further
below, the relatively small impacts observed when analyzing the Option
3 scenario suggest that the impacts of Options 3a, 1, 2 and 3b would be
less than Option 3. EPA did not analyze Option 4a due to time and
resource constraints, but expects that this option could have impacts
between those of Options 3 and 4. EPA did not analyze Option 5 based on
screening-level analysis results, which showed that compliance costs
could result in financial stress to some entities owning steam electric
plants. As shown in Section XI.D.1, under Option 5, about three times
as many entities owning steam electric plants would incur costs that
exceed 3 percent of revenue than under Options 3 (15 versus 5
entities). Twice as many entities owning steam electric power plants
are estimated to incur costs that exceed 3 percent of revenue under
Option 5, when compared to Option 4 (15 versus 7 entities). As
discussed in Section XVII.C, the potential cost impacts to small
entities are also greater under Option 5 than under Options 3 and 4.
    The IPM V4.10 runs provide analysis results for selected run-years:
2020 and 2030. These analysis years, each of which represents multiple
years, take into account the expected promulgation year for these
proposed ELGs (2014) and the years in which all plants would be
expected to install compliance technology (five-year period beginning
in 2017). In the following sections, EPA reports results for the run-
year 2030, which represents years 2025-2034, by which time all plants
subject to this rulemaking will meet the revised guidelines and
standards and all compliance costs will be reflected in production
costs (i.e., steady state of post-compliance operations). EPA
considered impact metrics of interest at three levels of aggregation:
(1) Impact on national and regional electricity markets (i.e., all
electric power generation, including steam and non-steam plants), (2)
impact on steam electric power generating plants as a group (i.e., the
1,079 plants subject to the proposed ELGs, not all of which are
projected to incur compliance costs), and (3) impact on individual
steam electric plants incurring compliance costs.
    All results presented below are representative of modeled market
conditions in the years 2025-2034. While costs are in 2010 dollars,
they are reflective of costs in the modeled years and are not
discounted to the start of EPA's analysis period of 2014.\74\
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    \74\ In contrast, the social cost estimated in Section XI.C
reflects the discounted value of compliance costs over the entire
24-year period of analysis, as of 2014. Additionally, screening-
level analyses presented in earlier sections are static analyses and
do not account for interdependence of electric generating units in
supplying power to the electric transmission grid. In contrast, IPM
accounts for potential changes in generation profile of steam
electric and other units and consequent changes in market-level
generation costs, as the electric power market responds to higher
generation costs for steam electric units due to the proposed ELG.
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a. Impact on National and Regional Electricity Markets
    For the assessment of market level electricity impacts, EPA
considered five output metrics from IPM V4.10: (1) Incremental early
retirements and capacity closures, calculated as the difference between
capacity under the regulatory options and capacity under the baseline,
which includes both full plant closures and partial plant closures
(i.e., unit closures) in aggregate capacity terms; (2) incremental
capacity closures as a percentage of baseline capacity; (3) post-
compliance changes in variable production costs per MWh, calculated as
the sum of total fuel and variable O&M costs divided by net generation;
(4) changes in annual costs (fuel, variable O&M, fixed O&M, and
capital); and (5) post-compliance changes in energy price, where
electricity prices are defined as the wholesale prices received by
plants for the sale of electricity they generate.
    Table XI-5 presents results for the two market model analysis
scenarios. The table provides the baseline capacity and the values of
each of the five metrics above, with national totals and detail at
level of regional electricity markets defined on the basis of the eight
NERC regions defined in IPM.
    Additional results are presented in Chapter 5 of the RIA report.
Chapter 5 also presents a more detailed interpretation of the results
of the market-level analysis.

                          Table XI-5--Impact of Market Model Analysis Options on National and Regional Markets at the Year 2030
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                                                                  Incremental early  retirements/       Change in         Change in         Change in
                                                                           closures \a\                 variable        annual costs       electricity
                 NERC region                      Baseline     ------------------------------------  production cost   (million 2010$   price (2010$/MWh
                                                capacity (GW)                       % of Baseline    (2010$/MWh or %       or % of           or % of
                                                                  Capacity (GW)       closures        of baseline)        baseline)         baseline)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3:
    ERCOT...................................                98                 0               0.0        $0.11 0.3%          $72 0.4%        $0.21 0.3%
    FRCC....................................                68                 0               0.0          0.14 0.3            49 0.3          0.23 0.3
    MRO.....................................                76                 0               0.0          0.02 0.1            53 0.4          0.03 0.1
    NPCC....................................                73                 0               0.0          0.06 0.2            15 0.1          0.19 0.3
    RFC.....................................               237                 0               0.0          0.12 0.5           276 0.5          0.19 0.3
    SERC....................................               274                 0               0.0          0.17 0.6           322 0.6          0.24 0.4
    SPP.....................................                59                 0              -0.7          0.08 0.3            35 0.3          0.17 0.3
    WECC....................................               220                 0               0.0          0.05 0.2            50 0.1          0.15 0.2
                                             -----------------------------------------------------------------------------------------------------------
        Total...............................             1,106                 0               0.0          0.11 0.4           872 0.4               N/A
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Option 4:
    ERCOT...................................                98                 0               0.0          0.14 0.4            85 0.5          0.07 0.1
    FRCC....................................                68                 0               0.0          0.15 0.1            33 0.2          0.09 0.1
    MRO.....................................                74                 0               0.0          0.11 0.5           134 1.0        -0.05 -0.1
    NPCC....................................                73                 0               0.6          0.03 0.1            32 0.2          0.04 0.1
    RFC.....................................               237                 1               0.3          0.29 1.1           804 1.5          0.15 0.2
    SERC....................................               274                 0               0.0          0.28 1.0           662 1.2          0.19 0.3
    SPP.....................................                60                 0              -0.6          0.15 0.5            72 0.7          0.09 0.2
    WECC....................................               220                 0               0.0          0.03 0.1            52 0.1          0.04 0.1
                                             -----------------------------------------------------------------------------------------------------------
        Total...............................             1,106                 0               0.0          0.18 0.6         1,874 0.9               N/A
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values for incremental early retirements or closures represent change relative to the baseline run. IPM may show partial (i.e., unit) or full plant
  early retirements (closures) for a given option. It may also show avoided closures (negative closure values) in which a unit or plant that is
  projected to close in the baseline, is estimated to continue operating in the post-compliance case. Avoided closures may occur among plants that incur
  no compliance costs or for which compliance costs are low relative to other steam electric plants.\75\

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    \75\ Given the design of IPM, unit-level and thereby plant-level
projections are presented as an indicator of overall regulatory
impact rather than a prediction of future unit- or plant-specific
compliance actions. ERCOT (Electric Reliability Council of Texas),
FRCC (Florida Reliability Coordinating Council), MRO (Midwest
Reliability Organization), NPCC (Northeast Power Coordination
Council), RFC (ReliabilityFirst Corporation), SERC (Southeastern
Electricity Reliability Council), SPP (Southwest Power Pool), and
WECC (Western Electricity Coordinating Council).
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    As shown in Table XI-5, the Market Model Analysis indicates that
Option 3 would have very small effects in overall electricity markets,
on both a national and regional sub-market basis, in the year 2030.
Overall at the national level, the net change in total capacity,
including reductions in capacity (which includes early retirements) and
capacity additions in new plants/units, results in approximately 1GW of
additional capacity (less than 0.05 percent total market capacity),
which is too small to appear in Table XI-5. This increase in capacity
is expected to take place entirely in the SPP NERC region (0.8 percent
of total SPP capacity) and is the result of reduction in retired
capacity (avoided capacity closures) and increase in new capacity and
capacity at existing generating units.\76\ Consequently, Option 3 is
expected to have negligible effect on capacity availability and supply
reliability at the national level. Overall impacts on electricity
prices are similarly minimal. While electricity prices are expected to
increase in all NERC regions, the magnitude of this increase varies
across regions and ranges from $0.03 per MWh (0.1 percent) in MRO to
$0.24 per MWh (0.4 percent) in SERC. Finally, at the national level,
total costs increase by approximately 0.4 percent of the baseline
value--again, a modest amount. Across regions, no NERC region records
an increase in power sector total costs exceeding 1 percent.
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    \76\ Avoided capacity closures occur when one or more generating
units that are otherwise projected to cease operations in the
baseline become more economically attractive sources of electricity
in the post-compliance case, because of relative changes in the
economics of electricity production across the full market, and thus
avoid closure.
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    The findings for Option 4 overall lie very close to those of Option
3. Similar to Option 3, the net change in total capacity under Option 4
is essentially zero, indicating that this option would be expected to
have a negligible effect on capacity availability and supply