population growth because of the proposed ELGs, EPA calculated benefits
using the weighted population growth assumptions under each analytic
scenario (regulatory option and population increase assumption). For
states with more than one T&E species estimated to see population
growth, EPA only monetized the value for the species projected to see
the greatest proportional population increase. Because population
growth was calculated at the state level, EPA was unable to calculate
benefits based on when each steam electric plant is assumed to install
control technologies to comply with the proposed ELGs. EPA therefore
assumed that benefits begin accruing in 2019 for all states because
this is the midpoint of the compliance period used in other cost and
benefit analyses and thus provides a reasonable assumption.
    There may be some overlap between WTP estimates for T&E species and
the WTP estimates for improvements in water quality; however, the
magnitude of this overlap is likely to be minimal because none of the
studies in EPA's meta-analysis of WTP for water quality improvements
specifically mentioned or otherwise prompted respondents to include
benefits to T&E species populations.
    Table XIV-3 summarizes the results of EPA's analysis of benefits
from improved ecological conditions and recreational uses for five of
the eight regulatory options. EPA did not estimate the benefits of
Options 3a, 3b and 4a. As for the other benefit categories, however,
the Agency expects the benefits of Option 4a to be between those of
Options 3 and 4 (i.e., between $59.9 million and $116.1 million
annually, at 3 percent discount rate).

                                      Table XIV-3--Annualized Ecological Conditions and Recreational Uses Benefits
                                                                   [Million 2010$] \e\
--------------------------------------------------------------------------------------------------------------------------------------------------------
        Benefit category                 Option 1                Option 2                Option 3                Option 4                Option 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    3% Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Improved Surface Water Quality    $8.3..................  $38.0.................  $49.9.................  $82.8.................  $81.9
 \a\.                             ($2.0 to $22.4).......  ($7.1 to $107.1)......  ($10.2 to $137.6).....  ($19.6 to $215.8).....  ($19.3 to $214.1)
                                 -----------------------------------------------------------------------------------------------------------------------
Benefits to E&T Species \b\.....  $7.0..................  $7.0..................  $10.0.................  $33.3.................  $33.3
                                  ($3.9 to $10.0).......  ($3.9 to $10.0).......  ($5.5 to $14.2).......  ($18.2 to $47.3)......  ($18.2 to $47.3)
                                 -----------------------------------------------------------------------------------------------------------------------
    Total Ecological and          $15.3.................  $45.0.................  $59.9.................  $116.1................  $115.2
     Recreational Uses Benefits   ($5.8 to $32.4).......  ($11.0 to $117.7).....  ($15.7 to $151.8).....  ($37.8 to $263.1).....  ($37.5 to $261.4)
     \d\.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    7% Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Improved Surface Water Quality    $6.9..................  $31.7.................  $41.7.................  $69.2.................  $68.5
 \a\.                             ($1.6 to $18.7).......  ($6.0 to $48.3).......  ($8.5 to $115.0)......  ($16.4 to $180.3).....  ($16.1 to $178.9)
                                 -----------------------------------------------------------------------------------------------------------------------
Benefits to E&T Species \b\.....  $5.9..................  $5.9..................  $8.4..................  $27.8.................  $27.8
                                  ($3.2 to $8.4)........  ($3.2 to $8.4)........  ($4.6 to $11.9).......  ($15.2 to $39.5)......  ($15.2 to $39.5)
                                 -----------------------------------------------------------------------------------------------------------------------
    Total Ecological and          $12.8.................  $37.6.................  $50.1.................  $97.0.................  $96.2
     Recreational Uses Benefits   ($4.8 to $27.0).......  ($9.1 to $56.6).......  ($13.1 to $126.9).....  ($31.6 to $219.8).....  ($31.3 to $218.4)
     \d\.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values represent partial benefits only for reaches that receive direct discharges from steam electric plants. Range in parenthesis represents the
  5th and 95th percentile of the WTP distribution.
\b\ Range in parenthesis provides the low and high bound estimates.
\c\ Range in parenthesis provides the 5th and 95th percentile of the WTP distribution incorporating minimum and maximum flow reduction assumptions.
\d\ Totals may not add up due to independent rounding.
\e\ EPA did not estimate the benefits of Options 3a, 3b and 4a. EPA expects the benefits of Option 4a to be between those of Options 3 and 4.

3. Groundwater Quality Benefits From Reduced Groundwater Contamination
    EPA expects that some of the regulatory options will eliminate the
future leaching of steam electric pollutants from steam electric
impoundments to groundwater aquifers. The Agency monetized the
associated benefits to households using private drinking wells in the
vicinity of steam electric plants based on a benefits transfer from
groundwater valuation studies. Specifically, EPA used existing
groundwater valuation studies to derive household WTP estimates for two
categorical improvements in groundwater quality: (1) ``greatly
improved'' and (2) ``improved.''
    EPA identified the exposed population as the number of households
using private drinking water wells in the vicinity of steam electric
impoundments. EPA then modeled pollutant concentrations in the affected
aquifers and determined which aquifers exceed maximum contaminant
levels (MCLs) for steam electric pollutants under the baseline. EPA
assumed that if a plant ceases to use impoundments to handle combustion
waste because of the proposed ELGs, these aquifers would improve, with
an average household WTP of $450. For impoundments that continue to
receive combustion wastes but in smaller amounts, EPA assumed that the
plant-specific benefits would be proportional to the reduction in
wastewater flows going to the impoundment, and scaled the benefits
accordingly.
    Table XIV-4 summarizes the results of EPA's analysis of the
groundwater benefits. As for other benefit categories, EPA did not
analyze the benefits of Options 3a, 3b and 4a. EPA expects the benefits
of Option 4a to be between those of Options 3 and 4 (i.e., $1.6 million
to $6.5 million annually, at 3 percent discount rate).

                                                  Table XIV-4--Annualized Groundwater Quality Benefits
                                                                     [Million 2010$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                         Discount rate                              Option 1          Option 2          Option 3          Option 4          Option 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% Discount Rate..............................................              $0.7              $0.7              $1.6              $6.5              $6.5
7% Discount Rate..............................................               0.6               0.6               1.4               5.5               5.5
--------------------------------------------------------------------------------------------------------------------------------------------------------

4. Market and Productivity Benefits (Benefits From Reduced Impoundment
Failures)
    Operational changes prompted by compliance with the proposed ELGs
may cause some plant owners to reduce their reliance on impoundments to
handle their waste. EPA expects these changes to reduce future impacts
from impoundment failures.
    To assess the benefits associated with changes in impoundment use,
EPA estimated the costs associated with expected failures for baseline
conditions (assuming no change in operations) and for projected
reductions in the amount of CCR waste managed by impoundments for five
of the eight regulatory options (Options 1, 2, 3, 4, and 5). EPA
performed the calculations for each of the 1,070 impoundments
identified at steam electric plants, and for each year between 2014 and
2040. EPA then calculated benefits as the difference between expected
failure costs for a regulatory option and expected failure costs under
baseline conditions.
    To estimate the number of structural failure events that may be
avoided as a result of the proposed ELGs, EPA used data on historical
impoundment failures collected by EPA's Office of Resource Conservation
and Recovery (ORCR) for its Regulatory Impact Analysis for EPA's
Proposed Regulation of Coal Combustion Residues Generated by the
Electric Utility Industry (Proposed CCR Rule; U.S. EPA 2010). Based on
historical data, EPA estimated an average failure rate of 0.58 percent
per impoundment per year and used this average failure rate to
calculate the expected number of failure events in the baseline and
under each of the regulatory options.\86\ EPA also used data on
historical failure events to develop average cleanup, natural resource
damages,\87\ and litigation costs \88\ per event. As detailed in
Chapter 7 of the BCA, EPA used average total costs of $0.06 per gallon
of impoundment capacity to estimate the expected costs of an
impoundment failure.\89\ EPA did not calculate benefits for years 2014
through 2018 because EPA conducted surface impoundment integrity site
assessments in 2009 through 2012 and expects the assessments and the
recommended ``action plan'' improvements to impoundment structures will
prevent all failures for the first five years after improvement are
completed (i.e., 2014 through 2018).
---------------------------------------------------------------------------

    \86\ EPA also estimated benefits using a best-fit regression
equation developed based on the historical data that relates the
probability of impoundment failure to impoundment capacity. For
details, see Appendix G of the BCA.
    \87\ Natural resource damages do not include cleanup costs (or
legal costs) but include only the resource restoration and
compensation values. For example, in one case, Israel (2006) found
that ``In total, the State's claim was $764 million, $342 million of
which was restoration cost damages, $410 million of which was
compensable value damages, and $12 million of which was assessment
and legal costs.'' For this case, EPA used the sum of $342 million
and $410 million (excluded legal costs) as the value of natural
resource damages.
    \88\ For this analysis, litigation costs include the costs
associated with negotiating NRD, determining responsibility among
potentially responsible parties, and litigating details regarding
settlements and remediation. These activities involve services,
whether performed by the complying entity or other parties that EPA
expects would be required in the absence of this regulation in the
event of an impoundment failure. Note that the litigation costs do
not include fines, cleanup costs, damages, or other costs that
constitute transfers or are already accounted for in the other
categories analyzed separately.
    \89\ This estimate assumes that each failure results in a
spilled volume equal to 6.45 percent of the impoundment capacity,
based on the average ratio of spill volume to impoundment capacity
for 15 releases for which ORCR obtained both spill volume and
capacity data.
---------------------------------------------------------------------------

    Table XIV-5 presents the analysis results. Depending on the
regulatory option, annual benefits range from $62.1 million to $295.1
million (at 3 percent discount rate), with Option 3 having expected
benefits of $114.8 million per year. EPA did not estimate the benefits
of Options 3a, 3b and 4a; the Agency expects the benefits of Option 4a
to be between those of Options 3 and 4 (i.e., $114.8 million to $295.1
million, at 3 percent discount rate). Note that these benefits do not
include the effects of BMPs that may reduce the probability of failures
and therefore would be expected to increase the benefits of the
proposed ELGs. EPA will continue to seek ways to quantify and monetize
BMP-related benefits in analyses for the final rule, should EPA
ultimately include such BMPs as part of the final ELGs.

                                            Table XIV-5--Annualized Benefits of Reduced Impoundment Failures
                                                                     [Million 2010$]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                         Discount rate                              Option 1          Option 2          Option 3          Option 4          Option 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
3% Discount Rate..............................................             $62.1             $62.1            $114.8            $295.1            $295.1
7% Discount Rate..............................................              52.2              52.2              95.9             245.9             245.9
--------------------------------------------------------------------------------------------------------------------------------------------------------

5. Air-Related Benefits (Reduced Mortality and Avoided Climate Change
Impacts)
    The proposed ELGs are expected to affect air pollution through
three main mechanisms: 1) additional auxiliary electricity use by steam
electric plants to operate wastewater treatment, ash handling, and
other systems needed to comply with the new effluent limitations and
standards; 2) additional transportation-related emissions due to the
increased trucking of CCR waste to landfills; and 3) the change in the
profile of electricity generation due to the relatively higher cost to
generate electricity at plants incurring compliance costs for the
proposed ELGs. Changes in the profile of generation can result in lower
or higher air pollutant emissions because of variability in emission
factors for different types of electricity generating units. For this
analysis, the changes in air emissions are based on the change in
dispatch of generation units projected by IPM as a result of overlaying
the costs of the proposed ELGs onto steam electric units production
costs.
    In this analysis, EPA estimated the human health and other benefits
resulting from net changes in air emissions of three pollutants:
nitrogen oxides (NOX), sulfur dioxide (SO2), and
carbon dioxide (CO2). NOX and SOX are
known precursors to fine particles (PM2.5), a criteria air
pollutant that has been associated with a variety of adverse health
effects--most notably, premature mortality. CO2 is an
important greenhouse gas that is linked to a wide range of climate
change effects.
    EPA used average benefit-per-ton (BPT) estimates to value benefits
of changes in NOX and SO2 emissions, and social
cost of carbon (SCC) estimates to value benefits of changes in
CO2 emissions. Because the analysis relies in part on
estimates of air emissions obtained from IPM, EPA estimated air-related
benefits for Options 3 and 4 only, as these are the two options
analyzed in IPM. Table XIV-6

summarizes the annualized benefits associated with changes in air
pollutant emissions. Chapter 8 in the BCA report provides the details
of this analysis.

  Table XIV-6--Annualized Benefits of Changes in NOX, SO2, and CO2 Air
                                Emissions
                           [Million 2010$] \c\
------------------------------------------------------------------------
            Discount rate                 Option 3          Option 4
------------------------------------------------------------------------
3% Discount Rate (for NOX, SO2, and             $127.6            $170.5
 CO2-related benefits)..............
7% Discount Rate (for NOX, SO2, and               82.3              74.6
 CO2-related benefits) a b..........
------------------------------------------------------------------------
\a\ Because SCC values are not available for the 7 percent discount
  rate, EPA used the SCC based on a 5 percent discount rate to estimate
  values presented for the 7 percent discount rate. EPA uses 5 percent
  to discount CO2-related benefits and 7 percent to discount benefits
  from changes in NOX and SO2 emissions.
\b\ Air benefits for Option 4 at the 7 percent discount rate are lower
  than benefits estimated for Option 3 due to (1) smaller SO2 emissions
  reductions projected by IPM for Option 4 than Option 3 in early years
  and (2) differences in source- and discount-specific BPT and SCC
  values.
\c\ EPA did not estimate the benefits of Options 3a, 1, 2, 3b, 4a and 5.
  EPA expects the benefits of Option 4a to be between those of Options 3
  and 4.

6. Benefits From Reduced Water Withdrawals (Increased Availability of
Groundwater Resources)
    Steam electric plants use water for handling solid waste (e.g., fly
ash, bottom ash) and for operating wet FGD scrubbers. By eliminating or
reducing water used in sluicing operations or prompting the recycling
of water in FGD wastewater treatment systems, the proposed ELGs are
expected to reduce water withdrawals from surface waterbodies and
reduce demand on aquifers, in the case of plants that rely on
groundwater sources.
    EPA estimated the benefits of reduced groundwater withdrawals based
on avoided costs of groundwater supply. For each affected facility and
regulatory option, EPA multiplied the reduction in groundwater
withdrawal (in gallons per year) by water costs ranging between $150
and $500 per acre-foot.
    Table XIV-7 summarizes the annualized benefits associated with
changes in water use by steam electric plants for five of the eight
options. Chapter 9 in the BCA report provides the details of this
analysis. While EPA did not estimate benefits of Options 3a, 3b and 4a,
the Agency expects the benefits of Option 4a to be between those of
Options 3 and 4.

                            Table XIV-7--Annualized Monetized Benefits of Reduced Water Withdrawals by Steam Electric Plants
                                                                   [Million 2010$] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                       Benefit category                             Option 1          Option 2          Option 3          Option 4          Option 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    3% Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Avoided groundwater withdrawals...............................              $0.0              $0.0             <$0.1              $0.1              $0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    7% Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Avoided groundwater withdrawals...............................               0.0               0.0              <0.1               0.1              0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ EPA did not estimate the benefits of Options 3a and 4a. EPA expects the benefits of Option 4a to be between those of Options 3 and 4.

C. Total Monetized Benefits

    Using the analysis approach described above, EPA estimates annual
total benefits for the six monetized categories at approximately $82
million to $605.5 million (at 3 percent discount rate), depending on
the option and based on EPA's analysis of five of the eight regulatory
options (Table XIV-8). BAT and PSES option 3 has annual total benefits
estimated at $311.7 million (at 3 percent discount rate). While EPA did
not quantify the benefits of the other three preferred BAT and PSES
Options (Option 3a, Option 3b and Option 4a), EPA expects the annual
total benefits of Option 4a to be between those of Option 3 and 4
(i.e., $311.7 million to $605.5 million at 3 percent discount rate).
    The monetized benefits of this proposed rule do not account for all
benefits because, as described above, EPA is unable to monetize some
categories. Examples of benefit categories not reflected in these
estimates include non-cancer health benefits (other than IQ benefits
from reduced childhood exposure to lead and in-utero exposure to
mercury) and reduced cost of drinking water treatment for the
pollutants with drinking water criteria. In addition, EPA's analysis of
human health benefits associated with water quality improvements
includes only partial benefits for directly receiving reaches.
    EPA will continue to seek ways to monetize benefit categories not
monetized in this proposal in order to provide a more accurate
representation of benefits of the proposed rule.

                                      Table XIV-8--Summary of Total Annualized Monetized Benefits of Proposed ELGs
                                                                   [Million 2010$] \f\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                       Benefit category                             Option 1          Option 2          Option 3          Option 4          Option 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                3 Percent Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Human Health Benefits a c.....................................              $3.9              $4.0              $7.7             $17.2             $17.2

Improved Ecological Conditions and Recreational Uses a b......              15.3              45.0              59.9             116.1             115.2
Groundwater Quality Benefits..................................               0.7               0.7               1.6               6.5               6.5
Market and Productivity Benefits..............................              62.1              62.1             114.8             295.1             295.1
Air-Related Benefits \d\......................................                NE                NE             127.6             170.5                NE
Reduced Water Withdrawals.....................................               0.0               0.0             <=0.1               0.1               0.1
Total benefits, Excluding Air-Related Benefits................              82.0             111.7             184.1             435.0             434.1
                                                               -----------------------------------------------------------------------------------------
    Total Benefits (Including Air-related Benefits) \a\.......  ................  ................             311.7             605.5  ................
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                7 Percent Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Human Health Benefits a c.....................................               0.4               0.4               0.7               1.6               1.6
Improved Ecological Conditions and Recreational Uses a b......              12.8              37.6              50.1              97.0              96.2
Groundwater Quality Benefits..................................               0.6               0.6               1.4               5.5               5.5
Market and Productivity Benefits..............................              52.2              52.2              95.9             245.9             245.9
Air-Related Benefits d e......................................                NE                NE              82.3              74.5                NE
Reduced Water Withdrawals.....................................               0.0               0.0               0.0               0.1               0.1
                                                               -----------------------------------------------------------------------------------------
    Total benefits, Excluding Air-Related Benefits............              65.9              90.7             148.1             350.2             349.4
                                                               -----------------------------------------------------------------------------------------
    Total Benefits (Including Air-related Benefits) \a\.......  ................  ................             230.4             424.8  ................
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values represent mean benefit estimates. Totals may not add up due to independent rounding. Option 5 results in slightly lower benefits because,
  under Option 4, EPA assumes that plants with both leachate and FGD waste streams implement chemical precipitation and biological treatment for the
  combined streams. Under Option 5, EPA assumes that plants treat the two streams separately: FGD wastewater by evaporation and leachate using chemical
  precipitation (which removes less pollutant load than biological treatment).
\b\ There may be some overlap between the willingness-to-pay (WTP) for surface water quality improvements and WTP for benefits to threatened and
  endangered species.
\c\ Values represent partial human health benefits only for reaches that receive direct discharges from steam electric plants.
\d\ EPA estimated air-related benefits for Options 3 and 4 only because these benefits were estimated as part of the Agency's analysis using IPM. Total
  benefits for Options 1, 2, and 5 are therefore understated. Air benefits for Option 4 at the 7 percent discount rate are lower than benefits estimated
  for Option 3 due to (1) smaller SO2 emissions reductions projected by IPM for Option 4 than Option 3 in early years and (2) differences in source- and
  discount-specific BPT and SCC values.
\e\ Because SCC values are not available for the 7 percent discount rate, EPA used the SCC based on a 5 percent discount rate and discounted CO2-related
  benefits using a 5 percent discount rate, as compared to benefits in other categories, which are discounted using the 7 percent discount rate.
\f\ EPA did not estimate benefits for Options 3a, 3b and 4a, but expects the benefits of Option 4a to be between those of Options 3 and 4.

    Further, as noted earlier in this section, EPA calculated benefits
for some of the options considered for this proposal. Benefits for
these options, however, provide information relevant to understanding
the potential magnitude of benefits under all proposed options,
including Options 3a, 3b, and 4a. As explained earlier in this
preamble, the facilities affected by Option 3a are a subset of Option 3
facilities; Option 3 benefit estimates therefore provide an upper bound
estimate of benefits anticipated under Options 3a and 3b. In a similar
way, EPA expects Option 4 to provide an upper bound estimate of
benefits anticipated under Option 4a. As an illustrative analysis, EPA
inferred the potential benefits associated with Options 3a and 3b by
subtracting the benefits for Option 2 (scaled up to include a rough
estimate of air emissions benefits) from the benefits for Option 3,
because Option 3 includes a combination of the wastestreams and control
technologies in Options 3a and 2. EPA inferred the potential benefits
associated with Option 3b based on the pollutant loading reductions
(pounds) projected for Option 3b relative to pollutant loading
reductions projected for Option 2 (plus the fly ash dry handling
benefits of Option 3a) because Option 3b includes both fly ash
requirements and the Option 2 FGD wastewater treatment requirements for
a subset of facilities. Specifically, EPA inferred the benefits of
Options 3a and 3b by multiplying the FGD benefits estimated for Option
2 by the ratio of pollutant loads removed by 3b over Option 2, and then
adding in the fly ash benefits that are also included in Option 3b.
Similarly, EPA inferred the potential benefits associated with Option
4a based on the bottom ash pollutant loading reductions projected for
this option, relative to bottom ash pollutant loading reductions
projected for Option 4, plus the benefits of Option 3, because Option
4a includes all of the requirements of option 3 plus the bottom ash
requirements of Option 4 for a subset of facilities.
    Table XIV-9 summarizes total annualized benefits estimated (or
inferred using the calculations described above) for the eight options
discussed in this proposal. Note that there is significant uncertainty
in values inferred because the methodology used does not account for
differences in the pollutants, receiving waterbodies, and exposed
populations between the options.

                           Table XIV-9--Total Monetized Benefits for the Proposed Rule
                                                [Millions; 2010]
----------------------------------------------------------------------------------------------------------------
                                                                               Total monetized   Total monetized
              Regulatory option                           Method                benefits  3%      benefits  7%
----------------------------------------------------------------------------------------------------------------
Option 1....................................  Estimate \a\..................             $82.0             $65.9
Option 3a...................................  Inference \b\.................             139.4             104.8
Option 2....................................  Estimate \a\..................             111.7              90.7
Option 3b...................................  Inference \b\.................             205.5             153.0
Option 3....................................  Estimate......................             311.7             230.4
Option 4a...................................  Inference \b\.................             482.5             343.4
Option 4....................................  Estimate......................             605.5             424.8
Option 5....................................  Estimate \a\..................             434.1            349.4
----------------------------------------------------------------------------------------------------------------
\a\ Total benefits for Options 1, 2, and 5 do not include air-related benefits (see Table XIV-8).
\b\ EPA did not estimate benefits for Options 3a, 3b and 4a. EPA inferred benefits for Options 3a, 3b, and 4a
  for illustrative purposes using elements of the more rigorous analysis done to estimate benefits for Options 3
  and 4.

D. Children's Environmental Health

    As described in Section XIV.B.1, EPA assessed whether these
proposed ELGs will benefit children by reducing health risk from
exposure to steam electric pollutants from consumption of contaminated
fish tissue and improving recreational opportunities. The Agency was
able to quantify two categories of benefits specific to children: (1)
Avoided neurological damage to pre-school age children from reduced
exposure to lead and (2) avoided neurological damages from in-utero
exposure to mercury.
    This analysis considered several measures of children's health
benefits associated with lead exposure for children up to age six.
Avoided neurological and cognitive damages were expressed as changes in
three metrics: (1) Overall IQ levels; (2) the incidence of low IQ
scores (<70); and (3) the incidence of blood-lead levels above 20 mg/
dL. EPA's methodology for assessing lead-related benefits to children
is presented in Chapter 3 of the BCA report. EPA analysis shows that
benefits to children from reduced lead discharges range from $0.1
million to $6.8 million (at 3 percent discount), depending on the
regulatory option; annual benefits for Option 3 are estimated at $2.7
million (at 3 percent discount rate). EPA did not quantify the benefits
to children of Options 3a, 3b and 4a; however, the Agency expects the
annual benefits of Option 4a to be between those of Options 3 and 4
(i.e., between $2.7 million and $6.8 million).
    Children over the age of seven are also likely to benefit from
reduced exposure to lead and the resultant neurological and cognitive
damages, even though EPA did not quantify these benefits in its
analysis of the proposed ELGs. Giedd et al. (1999) studied brain
development among 10- to 18-year-old children and found substantial
growth in brain development, mainly during early teenage years. This
research suggests that older children may be hypersensitive to lead
exposure, as are children aged 0 to 7.
    Additional benefits to children from reduced exposure to lead not
quantified in this analysis may include prevention of the following
adverse health effects: slowed or delayed growth, delinquent and anti-
social behavior, metabolic effects, impaired heme synthesis, anemia,
impaired hearing, and cancer.
    EPA also estimated the IQ-related benefits associated with reduced
in-utero mercury exposure from maternal fish consumption in exposed
populations. Chapter 3 of the BCA report presents EPA's methodology for
assessing mercury-related benefits to children. Among approximately
1,932 babies born per year who are potentially exposed to discharges of
mercury from steam electric plants, the proposed ELGs reduce total IQ
point losses over the period of 2017 through 2040 by about 9,000 to
24,000 points, depending on the regulatory option. The monetary
benefits associated with the avoided IQ point losses range from $3.8
million and $10.2 million per year (mean estimate, at 3 percent
discount rate), across the five options EPA analyzed. Option 3 is
estimated to avoid the loss of about 12,000 IQ points in exposed
infants over the 24-year period. The benefits associated with these
avoided IQ point losses are estimated at $5.0 million per year. EPA did
not quantify the benefits to children of Options 3a, 3b and 4a; for
Option 4a, however, EPA expects the annual benefits to be between those
of Options 3 and 4 (i.e., $5.0 million to $10.2 million).

XV. Non-Water Quality Environmental Impacts

    The elimination or reduction of one form of pollution may create or
aggravate other environmental problems. Therefore, Sections 304(b) and
306 of the Act require EPA to consider non-water quality environmental
impacts (including energy impacts) associated with ELGs. Accordingly,
EPA has considered the potential impact of the regulatory options on
air emissions, solid waste generation, and energy consumption.

A. Energy Requirements

    Steam electric power plants use energy when transporting ash and
other solids on or off site, operating wastewater treatment systems
(e.g., chemical precipitation, biological treatment), operating ash
handling systems, or operating water trucks for dust suppression. For
those facilities that it projected would incur costs to comply with
these regulatory options, EPA considered whether or not there would be
an associated incremental energy need. That need varies depending on
the regulatory option evaluated and the current operations of the
facility. Therefore, as applicable, EPA estimated the additional energy
usage in megawatt hours (MWh) for equipment added to the plant systems
or in consumed fuel (gallons) for transportation/operating equipment.
Similarly, as applicable, EPA also estimated the decrease in energy
requirements resulting from the reduction in wet sluicing operations
and use of earth moving equipment. EPA scaled the facility-specific
estimate to calculate the net increase in energy requirements for the
regulatory options discussed in this rulemaking.
    To determine potential increases in electrical energy use, EPA
estimated the amount of energy needed to operate wastewater treatment
systems and ash handling systems based on the horsepower rating of the
pumps and other equipment. To determine potential decreases in
electrical energy use, EPA estimated the amount of

energy saved from reducing wet sluice pumping operations based on the
horsepower rating of the pumps. See DCN SE01957 (Incremental Costs and
Pollutant Removals for Proposed Effluent Limitations Guidelines and
Standards for the Steam Electric Generating Point Source Category) for
more information on the specific calculations used to estimate changes
in energy use. Table XV-1 shows the net change in annual electrical
energy usage associated with the proposed regulation.
    Energy usage also includes the fuel consumption associated with
transportation. EPA estimated the need for increased transportation of
solid waste and combustion residuals (e.g., ash) at steam electric
power plants to on-site or off-site landfills using open dump trucks.
The frequency and distance of transport depends on a plant's operation
and configuration. For example, the volume of waste generated per day
determines the frequency with which trucks will be travelling to and
from the storage sites. The availability of either an on-site or off-
site non-hazardous landfill and its distance from the plant determines
the length of travel time. EPA also estimated the energy usage
associated with the dust suppression water trucks and earth moving
equipment based on specific plant operations. For example, EPA
calculated earth moving equipment energy usage only if the plant
operates an impoundment. To determine the potential decrease in fuel
consumption, EPA estimated the amount of fuel saved by reducing the
number of backhoes needed to dredge solids from ash impoundments, due
to the reduction of wet sluice operations. See DCN SE01957 (Incremental
Costs and Pollutant Removals for Proposed Effluent Limitations
Guidelines and Standards for the Steam Electric Generating Point Source
Category) for more information on the specific calculations used to
estimate transportation fuel usage. Table XV-1 shows the net change in
annual fuel consumption associated with the preferred BAT and PSES
regulatory options (Options 3a, 3b, 3, and 4a).
    To provide some perspective on the potential increase in annual
electric energy consumption associated with the preferred regulatory
options, EPA compared the estimated increase in energy usage (MWh) to
the net amount of electricity generated in a year by all electric power
plants throughout the United States. According to EPA's Emissions &
Generation Resource Integrated Database (eGRID), the power plant
industry generated approximately 3,951 million MWh of energy in 2009.
EPA estimates that energy increases associated with the preferred BAT
and PSES regulatory options range from less than 0.003 percent (Option
3a) to 0.012 percent (Option 4a) of the total electricity generated by
all electric power plants.
    Similarly, EPA compared the additional fuel consumption (gallons)
estimated for the preferred BAT and PSES regulatory options to national
fuel consumption estimates for motor vehicles in the United States.
According to the EIA, on-highway vehicles, which include automobiles,
trucks, and buses, consumed approximately 34 billion gallons of
distillate fuel oil in 2009. EPA estimates that the fuel consumption
increase associated with the proposed Option 3a for BAT and PSES will
be 0.008 percent of total fuel consumption by all motor vehicles. Fuel
consumption is estimated to increase by less than 0.009 percent under
Options 3b and Option 3, and less than 0.014 percent under Option 4a.

                      Table XV-1--Energy Use Associated With ELG Options 3a, 3b, 3, and 4a
----------------------------------------------------------------------------------------------------------------
                                                             Energy use associated with proposed rule
            Non-water quality impact             ---------------------------------------------------------------
                                                     Option 3a       Option 3b       Option 3        Option 4a
----------------------------------------------------------------------------------------------------------------
Electrical Energy Usage (MWh)...................         112,000         160,753         303,300         472,369
Fuel (Thousand Gallons).........................           2,867           2,903           3,040           4,618
----------------------------------------------------------------------------------------------------------------

B. Air Pollution

    The proposed ELGs are expected to affect air pollution through
three main mechanisms: (1) Additional auxiliary electricity use by
steam electric plants to operate wastewater treatment, ash handling,
and other systems needed to comply with the new effluent limitations
and standards; (2) additional transportation-related emissions due to
the increased trucking of CCR waste to landfills; and (3) the change in
the profile of electricity generation due to relatively higher cost to
generate electricity at plants incurring compliance costs for the
proposed ELGs. This section provides greater detail on air emission
changes associated with the first two mechanisms and presents the
estimated net change in air emissions that take all three mechanisms
into account. See Section XIV for additional discussion of the third
mechanism.
    Air pollution is generated when fossil fuels are combusted. In
addition, steam electric power plants generate air emissions from
operating transport vehicles, such as dump and vacuum trucks, dust
suppression water trucks, and earth-moving equipment, which release
criteria air pollutants and greenhouse gases when operated. Similarly,
a decrease in energy use or vehicle operation will result in decreased
air pollution.
    To estimate the net air emissions associated with increased
electrical energy use, EPA combined the energy usage estimates with air
emission factors associated with electricity production to calculate
air emissions associated with the incremental energy requirements for
each of the proposed regulatory options. EPA used emission factors
projected by IPM (ton/MWh) for nitrogen oxides, sulfur dioxide, and
carbon dioxide to generate estimates of increased air emissions
associated with increased energy production.
    To estimate net air emissions associated with increased operation
of transport vehicles, EPA used the MOBILE6.2 model and the California
Climate Action Registry, General Reporting Protocol, Version 2.2 to
identify air emission factors (gram per mile) for the air pollutants of
interest. EPA assumed the general input parameters such as the year of
the vehicle and the annual mileage accumulation by vehicle class to
develop these factors. EPA estimated the annual number of miles that
dump or vacuum trucks moving ash or wastewater treatment solids to on-
or offsite landfills would travel to comply with limits established by
the proposed regulatory options. In addition to the trucks transporting
the additional solid waste, EPA also estimated the annual number of
miles that water trucks spraying water around landfills and ash
unloading areas to control dust would travel. EPA used these estimates
to calculate the net change in air emissions for this rulemaking.
    EPA's analyses using IPM also predict changes in air emissions. The
modeled

output from IPM predicts changes in electricity generation due to
compliance costs attributable to the proposed regulatory options. These
changes in electricity generation are, in turn, predicted to affect the
air emissions from steam electric power plants.
    The net change in air emissions associated with the preferred BAT/
PSES regulatory options (Options 3a, 3b, 3, and 4a) are shown in Tables
XV-2 through XV-5. To provide some perspective on the potential changes
in annual air emissions, EPA compared the estimated change in air
emissions to the net amount of air emissions generated in a year by all
electric power plants throughout the United States. Tables XV-2 through
XV-4 present the estimated changes in air emissions based on the
regulatory options, the total emissions generated by the electric power
industry in 2009, based on eGRID, and the percent change in emissions
associated with Options 3a, 3b, 3, and 4a. See DCN SE02025 (Steam
Electric Effluent Guidelines Non-Water Quality Impacts) in the record
for this rulemaking for more information.

                          Table XV-2--Air Emissions Associated With BAT/PSES Option 3a
----------------------------------------------------------------------------------------------------------------
                                                                        2009 Emissions by
                                                  Value associated       electric power          Increase in
           Non-water quality impact                with option 3a      industry  (million      emissions  (%)
                                                   (million tons)             tons)
----------------------------------------------------------------------------------------------------------------
NOX...........................................  \a\ 0.000088-0.00109                     1          0.0088-0.109
SOX...........................................         \b\ <0.000084                     6               <0.0014
CO2...........................................            \b\ <0.130                 2,403               <0.0054
----------------------------------------------------------------------------------------------------------------
\a\ EPA quantified the air emissions associated with additional electricity and additional transportation for
  Option 3a. Based on the values quantified for Option 3 for changes to air emissions projected by IPM, EPA
  calculated the range of emissions for NOX. The lower end of the range represents the emissions only associated
  with additional electricity and transportation. The upper end of the range also includes the changes to air
  emissions projected by IPM (based on Option 3), which are larger than would be expected for Option 3a.
\b\ EPA quantified the air emissions associated with additional electricity and additional transportation for
  Option 3a. Based on the values quantified for Option 3 for changes to air emissions projected by IPM, which
  were negative, EPA decided not to include these IPM air emission changes in the calculated SOx and CO2
  emissions for Option 3a. These SOX and CO2 emissions are considered maximum values because EPA expects that
  the air emission changes projected by IPM for Option 3a will also be negative (as they are for Options 3 and
  4).

                          Table XV-3--Air Emissions Associated With BAT/PSES Option 3b
----------------------------------------------------------------------------------------------------------------
                                                                        2009 Emissions by
                                                  Value associated       electric power          Increase in
           Non-water quality impact                with option 3b      industry  (million      emissions  (%)
                                                   (million tons)             tons)
----------------------------------------------------------------------------------------------------------------
NOX...........................................   \a\ 0.00011-0.00111                     1           0.011-0.111
SOX...........................................          \b\ <0.00013                     6               <0.0021
CO2...........................................            \b\ <0.149                 2,403               <0.0062
----------------------------------------------------------------------------------------------------------------
\a\ EPA quantified the air emissions associated with additional electricity and additional transportation for
  Option 3b. Based on the values quantified for Option 3 for changes to air emissions projected by IPM, EPA
  calculated the range of emissions for NOX. The lower end of the range represents the emissions only associated
  with additional electricity and transportation. The upper end of the range also includes the changes to air
  emissions projected by IPM (based on Option 3), which are larger than would be expected for Option 3b.
\b\ EPA quantified the air emissions associated with additional electricity and additional transportation for
  Option 3b. Based on the values quantified for Option 3 for changes to air emissions projected IPM, which were
  negative, EPA decided not to include these IPM air emission changes in the calculated SOX and CO2 emissions
  for Option 3b. These SOX and CO2 emissions are considered maximum values because EPA expects that the air
  emission changes projected for IPM for Option 3b will also be negative (as they are for Options 3 and 4).

                           Table XV-4--Air Emissions Associated With BAT/PSES Option 3
----------------------------------------------------------------------------------------------------------------
                                                                        2009 Emissions by
                                                  Value associated       electric power          Increase in
           Non-water quality impact                 with option 3      industry  (million      emissions  (%)
                                                   (million tons)             tons)
----------------------------------------------------------------------------------------------------------------
NOX...........................................               0.00121                     1                 0.121
SOX...........................................              -0.00273                     6                -0.045
CO2...........................................                -1.282                 2,403                -0.053
----------------------------------------------------------------------------------------------------------------

                          Table XV-5--Air Emissions Associated With BAT/PSES Option 4a
----------------------------------------------------------------------------------------------------------------
                                                                        2009 Emissions by
                                                  Value associated       electric power          Increase in
           Non-water quality impact                with option 4a      industry  (million      emissions  (%)
                                                   (million tons)             tons)
----------------------------------------------------------------------------------------------------------------
NOX...........................................           \a\ 0.00132                     1                 0.132
SOX...........................................         \a\ <-0.00258                     6               <-0.043
CO2...........................................           \a\ <-1.106                 2,403               <-0.046
----------------------------------------------------------------------------------------------------------------
\a\ EPA quantified the air emissions associated with additional electricity and additional transportation for
  Option 4a. To estimate the total emissions for Option 4a, EPA added the changes to air emissions projected by
  IPM for Options 3 because they are more conservative (i.e., they overestimate the emissions). The contribution
  of NOX is unchanged compared to Option 3 and 4; therefore, EPA assumed this would also be the contribution for
  Option 4a. For SOX and CO2, the contribution associated with Option 4 are lower (i.e., more negative);
  therefore, because EPA used the Option 3 values, the values presented in the table are maximum values.

C. Solid Waste Generation

    Steam electric power plants generate solid waste associated with
sludge from wastewater treatment systems (e.g., chemical precipitation,
biological treatment). The regulatory options evaluated would increase
the amount of solid waste generated from FGD wastewater treatment,
including sludge from chemical precipitation, biological treatment, and
vapor compression evaporation technologies. EPA estimated the amount of
solid waste generated from each technology for each plant and estimates
that the preferred BAT/PSES regulatory options (Options 3a, 3b, 3, and
4a) would increase solids generated annually from treatment. Fly and
bottom ash are also solid wastes generated at steam electric power
plants. The preferred regulatory options for BAT and PSES are, however,
not expected to alter the amount of ash or other combustion residuals
generated. See DCN SE02025 (Steam Electric Effluent Guidelines Non-
Water Quality Impacts) in the record for this rulemaking for more
information.
    To provide some perspective on the potential increase in annual
solid waste generation associated with the preferred BAT/PSES
regulatory options, EPA compared the estimated increase in solid waste
generation for Options 3b, 3, and 4a \90\ to the amount of solids
generated in a year by electric power plants throughout the United
States--approximately 134 billion tons. The increase in solid waste
generation associated with Options 3b, 3 and 4a for BAT and PSES will
be less than 0.001 percent of the total solid waste generated by all
electric power plants.
---------------------------------------------------------------------------

    \90\ As described previously, the preferred regulatory options
for BAT and PSES for fly ash and bottom ash transport water are not
expected to alter the amount of ash or other combustion residuals
generated. Therefore, there is no increase for Option 3a and the
increase for Option 4a is equal to the increase for Option 3.
---------------------------------------------------------------------------

D. Reductions in Water Use

    Steam electric power plants generally use water for handling solid
waste, including ash, and for operating wet FGD scrubbers. The
technology options for fly and bottom ash will eliminate or reduce
water use associated with current wet sluicing operating systems. EPA
estimated the reductions in water use based on the amount of sluice
water discharged by each plant, multiplied by the percentage of intake
water identified as make-up in the survey. The memorandum entitled
Steam Electric Effluent Guidelines Non-Water Quality Impacts, located
in the record for this rulemaking, provides more information.
    The technology basis for the preferred regulatory option with
respect to FGD wastewater discharges (e.g., chemical precipitation,
biological treatment) would not be expected to reduce the amount of
water used unless plants recycle FGD wastewater as part of their
treatment system. EPA estimated that five plants would be able to
incorporate recycling within their FGD systems based on the maximum
operating chlorides concentration compared to the design maximum
chlorides concentration. Based on this comparison, EPA estimated the
reduction in intake water at a plant level based on the amount of water
that could be recycled by the FGD system and multiplying by the
percentage of intake water identified as make-up water in the industry
survey. EPA's report entitled Incremental Costs and Pollutant Removals
for Proposed Effluent Limitations Guidelines and Standards for the
Steam Electric Generating Point Source Category, located in the record
for this rulemaking, provides more information.
    EPA estimates that power plants would reduce the use of water by 50
billion gallons per year (136 million gallons per day) under Option 3a,
by 52 billion gallons per year (143 million gallons per day) under
Option 3b, by 53 billion gallons per year (144 million gallons per day)
under Option 3, and by 103 billion gallons per year (282 million
gallons per day) under Option 4a.

XVI. Regulatory Implementation

A. Implementation of the Limitations and Standards

    Effluent guidelines limitations and standards act as a primary
mechanism to control the discharge of pollutants to waters of the
United States. This proposed rule would be applied to steam electric
wastewater discharges through incorporation into NPDES permits issued
by the EPA or states under Section 402 of the Act and through local
pretreatment programs under Section 307 of the Act.
    The Agency has developed the limitations and standards for this
proposed rule to control the discharge of pollutants from the steam
electric power generating point source category. Once promulgated,
those permits or control mechanisms issued after this rule's effective
date would be required to incorporate the effluent limitations
guidelines and standards, as applicable. Also, under section 510 of the
CWA, states may require effluent limitations under state law as long as
they are no less stringent than the requirements of this rule. Finally,
in addition to requiring application of the technology-based effluent
limitations guidelines and standards in this rule, section 301(b)(1)(C)
of CWA requires the permitting authority to impose more stringent
effluent limitations on discharges as necessary to meet applicable
water quality standards.
1. Timing
    For the reasons explained in Section VIII, EPA proposes that
certain limitations and standards based on any of the eight main
regulatory options being proposed today for existing direct and
indirect dischargers do not apply until July 1, 2017 (approximately
three years from the effective date of this rule). EPA finds this is
appropriate for any proposed BAT and PSES for FGD wastewater,
gasification wastewater, fly ash transport water, flue gas mercury
control wastewater, bottom ash transport water, or combustion residual
leachate where EPA is not proposing to establish BAT limitations that
are equal to BPT limitations. For those plants and wastestreams where
EPA is proposing to establish BAT equal to the current BPT effluent
limitations, the revised BAT requirements would be applicable on the
effective date of the final rule. See Section VIII.B for additional
discussion regarding the implementation timing for the proposed BAT and
PSES requirements.
    The proposed requirements for new direct and indirect dischargers
(NSPS and PSNS) and the proposed requirements for existing sources
where BAT is set equal to BPT would be applicable as of the effective
date of the final rule.
2. Applicability of NSPS/PSNS
    In 1982, EPA promulgated NSPS/PSNS for certain discharges from new
units. Regardless of the outcome of the current rulemaking, those units
that are currently subject to the 1982 NSPS/PSNS will continue to be
subject to such standards. In addition, EPA is proposing to clarify in
the text of the regulation that, assuming the Agency promulgates BAT/
PSES requirements as part of the current rulemaking, units to which the
1982 NSPS/PSNS apply will also be subject to any newly promulgated BAT/
PSES requirements because they will be existing sources with respect to
such new requirements.
3. Legacy Wastes
    For the reasons explained in Section VIII, EPA is proposing that
certain BAT and PSES requirements for existing sources based on any of
the eight main regulatory options would apply to discharges of FGD
wastewater, fly ash

transport water, bottom ash transport water, FGMC wastewater,
combustion residual leachate, and gasification wastewater generated on
or after the date established by the permitting authority that is as
soon as possible after July 1, 2017.\91\ As proposed today, for direct
dischargers such wastewater generated prior to that date (i.e.,
``legacy'' wastewater) would remain subject to the existing BPT
effluent limits. EPA is also considering establishing BAT effluent
limitations for legacy wastewater (except gasification wastewater) that
would be equal to the existing BPT effluent limits.
---------------------------------------------------------------------------

    \91\ Except where BAT is equivalent to BPT.
---------------------------------------------------------------------------

4. Compliance Monitoring
    Working in conjunction with the effluent limitations guidelines and
standards are the monitoring conditions set out in a NPDES discharge
permit or POTW control mechanism. An integral part of the monitoring
conditions is the monitoring point. The point at which a sample is
collected can have a dramatic effect on the monitoring results for that
facility. Therefore, it may be necessary to require internal monitoring
points in order to assure compliance. Authority to address internal
wastestreams is provided in 40 CFR 122.44(i)(1)(iii) and 122.45(h).
    EPA is proposing that dischargers demonstrate compliance with the
proposed effluent limitations and standards applicable to a particular
wastestream prior to mixing the treated wastestream with other
wastestreams, as described below. Therefore, with the exception of the
cases where BAT limitations are equivalent to BPT limitations, any
final limitations or standards (except pH) based on any of the eight
main regulatory options in this proposed rule could require internal
monitoring points. Section 14 of the TDD provides detailed discussion
for various types of configurations. The following provides selected
information from the TDD:
     FGD wastewater: Where an option proposes BAT/NSPS
limitations for FGD wastewater that are not equal to existing BPT
limitations,\92\ EPA is also proposing to require monitoring for
compliance with the proposed effluent limitations and standards prior
to use of the FGD wastewater in any other non-FGD plant process or
commingling of the FGD wastewater with any water or other process
wastewater. This monitoring requirement would not, however, apply prior
to commingling of FGD wastewater with combustion residual leachate
(including legacy leachate) or legacy FGD wastewater that is treated to
achieve pollutant removals equivalent to or greater than achieved by
the BAT/NSPS technology that serves as the basis for the effluent
limitations and standards proposed today.
---------------------------------------------------------------------------

    \92\ Similarly applies to PSES and PSNS.
---------------------------------------------------------------------------

    For example, many plants currently treat their FGD wastewater and
leachate in onsite surface impoundments. EPA envisions that, under this
proposed Option 3 requirements, some of these plants may choose to
install tank-based FGD wastewater treatment systems for their newly
generated FGD wastewater. Such a plant may chose to discharge the
effluent from its new treatment system directly or may wish to
discharge it to the existing surface impoundment containing legacy
wastewaters. In this case, the plant would be required to demonstrate
compliance with the proposed effluent limitations and standards for the
newly generated FGD wastewater at the effluent from the tank-based FGD
wastewater treatment system, and compliance with the BPT requirements
for the commingled new/legacy FGD wastewater at the point of discharge
from the FGD wastewater impoundment. The same plant may also configure
its system so that the impoundment (which also contains legacy FGD
wastewater)is used for equalization, with the impoundment effluent sent
to the tank-based treatment system. In this case, both the newly
generated FGD wastewater and the legacy FGD wastewater would be treated
by the tank-based treatment system and an appropriate compliance
monitoring point would be the treatment system effluent. Under such a
scenario, commingling of FGD wastewater generated at any date may occur
as long as such combined wastewater meets the effluent limitations or
standards prior to use of the treated commingled new/legacy FGD
wastewater in any other plant process, or combining the FGD wastewater
with any water or other process wastewater.
     Ash transport water and FGMC wastewater: EPA is proposing
to specify that whenever ash transport water or flue gas mercury
control wastewater generated from a generating unit that must comply
with the ``zero discharge'' standard is used in any other plant process
or is sent to a treatment system at the plant, the resulting effluent
must comply with the proposed discharge prohibition for the pollutants
in such wastewater.
    For example, many plants currently treat their fly ash transport
water in an onsite fly ash impoundment. In this case, under any
proposed ``no discharge'' requirements, EPA envisions that such plants
may convert their fly ash handling to a dry system, and no longer
generate fly ash transport water. In such cases, the plant could
demonstrate compliance with the proposed zero discharge requirement by
showing that no fly ash transport water is generated after the date on
which the new, proposed standards apply and by monitoring for
compliance with the BPT requirements at the discharge from the legacy
fly ash impoundment. Under EPA's proposal, the plant could not
demonstrate compliance with the applicable discharge prohibition by
simply using the fly ash transport water in another plant process that
ultimately discharges because the prohibition on the discharge of
pollutants in ash transport water and FGMC wastewater is also
applicable to the discharge of wastewater from plant processes that use
these wastewaters.
     Gasification wastewater: EPA is proposing to require
monitoring for compliance prior to use of the gasification wastewater
in any other plant process or commingling of the gasification
wastewater with water or any other process wastewater. As an example,
EPA envisions gasification plants would show compliance with the
proposed BAT or PSES requirements directly following gasification
wastewater treatment (however, there would be no need to demonstrate
compliance if the gasification wastewater is completely reused within
the gasification process). Combustion Residual Leachate: Under Option 4
and 5, EPA is proposing to require monitoring for compliance prior to
use of leachate in any other plant process or commingling of the
leachate with water or any other process wastewater. This monitoring
requirement would not, however, apply prior to commingling of
combustion residual leachate with FGD wastewater (including legacy FGD
wastewater) or legacy combustion residual leachate that is treated to
achieve pollutant removals equivalent to or greater than that achieved
by the BAT/NSPS technology that serves as the basis for the effluent
limitations and standards proposed today. For example, many plants
currently treat their leachate in onsite surface impoundments. EPA
envisions that, under the proposed requirements, some plants may choose
to install a tank-based leachate treatment system so that the
impoundment (which also contains legacy combustion residual leachate)
is used for equalization, with the impoundment effluent ultimately sent
to the tank-based treatment system. In this case, both the newly
generated leachate and the legacy leachate would

be treated by the tank-based treatment system and an appropriate
compliance monitoring point would be the treatment system effluent.
Under such a scenario, commingling of combustion residual leachate
generated at any date may occur as long as such combined wastewater
meets the effluent limitations or standards prior to use of the treated
commingled new/legacy leachate in any other plant process, or combining
the leachate with any water or other process wastewater. (If the
combustion residual leachate is commingled with FGD wastewater, the
facility will also have to demonstrate compliance with the applicable
FGD wastewater effluent limitations and standards.) Conversely, under
the proposed requirements, EPA envisions some plants may choose to
install tank-based leachate treatment systems whose effluent is
discharged to the impoundment containing the legacy leachate. In this
case, the plant would be required to demonstrate compliance with the
proposed effluent limitations and standards for the newly generated
combustion residual leachate at the effluent from the tank-based
leachate treatment system and compliance with the BPT requirements for
the commingled new/legacy leachate at the discharge from the
impoundment.

B. Analytical Methods

    Section 304(h) of the CWA directs the EPA to promulgate guidelines
establishing test procedures (methods) for the analysis of pollutants.
These methods are used to determine the presence and concentration of
pollutants in wastewater and for compliance monitoring. They are also
used for filing applications for the National Pollutant Discharge
Elimination System (NPDES) permit program under 40 CFR 122.41(j)(4) and
122.21(g)(7), and under 40 CFR 403.7(d) for the pretreatment program.
The EPA has promulgated analytical methods for monitoring discharges to
surface water at 40 CFR part 136 for the pollutants proposed for
regulation in this notice. EPA is providing notice of standard
operating procedures (SOPs) for the analysis of FGD wastewater using
collision cell technology in conjunction with EPA Method 200.8. EPA
Method 200.8 has been promulgated under 40 CFR part 136 and is an
approved method for use in NPDES compliance monitoring. Also, the use
of collision cell technology is an approved modification allowed under
40 CFR part 136.6. See DCN SE03835 and DCN SE03868 for the SOPs and
information on EPA's development of the SOPs.
    In addition, as explained in Section VIII, with the exception of
the cases where BAT limitations are equivalent to BPT limitations, EPA
is proposing that compliance with any final limitations or standards
(except pH) based on any of the eight main regulatory options in this
proposed rule reflects results obtained from sufficiently sensitive
analytical methods. Where EPA has approved more than one analytical
method for a pollutant, the Agency expects that permittees would select
methods that are able to quantify the presence of pollutants in a given
discharge at concentrations that are low enough to determine compliance
with effluent limits. For purposes of the proposed anti-circumvention
provisions, a method is ``sufficiently sensitive'' when the sample-
specific quantitation level \93\ for the wastewater matrix being
analyzed is at or below the level of the effluent limit.
---------------------------------------------------------------------------

    \93\ For the purposes of this rulemaking, EPA is considering the
following terms related to analytical method sensitivity to be
synonymous: ``quantitation limit,'' ``reporting limit,'' ``level of
quantitation,'' and ``minimum level.''
---------------------------------------------------------------------------

C. Upset and Bypass Provisions

    A ``bypass'' is an intentional diversion of wastestreams from any
portion of a treatment facility. An ``upset'' is an exceptional
incident in which there is unintentional and temporary noncompliance
with technology-based permit effluent limitations because of factors
beyond the reasonable control of the permittee. EPA's regulations
concerning bypasses and upsets for direct dischargers are set forth at
40 CFR 122.41(m) and (n) and for indirect dischargers at 40 CFR 403.16
and 403.17.

D. Variances and Modifications

    The CWA requires application of effluent limitations established
pursuant to Section 301 or the pretreatment standards of Section 307 to
all direct and indirect dischargers. However, the statute provides for
the modification of these national requirements in a limited number of
circumstances. The Agency has established administrative mechanisms to
provide an opportunity for relief from the application of the national
effluent limitations guidelines for categories of existing sources for
toxic, conventional, and nonconventional pollutants.
1. Fundamentally Different Factors (FDF) Variance
    As explained above, the CWA requires application of the effluent
limitations established pursuant to Section 301 or the pretreatment
standards of Section 307 to all direct and indirect dischargers.
However, the statute provides for the modification of these national
requirements in a limited number of circumstances. Moreover, the Agency
has established administrative mechanisms to provide an opportunity for
relief from the application of national effluent limitations guidelines
and pretreatment standards for categories of existing sources for
priority, conventional, and nonconventional pollutants.
    EPA may develop, with the concurrence of the state, effluent
limitations or standards different from the otherwise applicable
requirements for an individual existing discharger if it is
fundamentally different with respect to factors considered in
establishing the effluent limitations or standards applicable to the
individual discharger. Such a modification is known as an FDF variance.
    EPA, in its initial implementation of the effluent guidelines
program, provided for the FDF modifications in regulations, which were
variances from the BPT effluent limitations, BAT limitations for toxic
and nonconventional pollutants, and BCT limitations for conventional
pollutants for direct dischargers. FDF variances for toxic pollutants
were challenged judicially and ultimately sustained by the Supreme
Court in Chemical Manufacturers Association v. Natural Resources
Defense Council, 470 U.S. 116, 124 (1985).
    Subsequently, in the Water Quality Act of 1987, Congress added a
new section to the CWA--Section 301(n). This provision explicitly
authorizes modifications of the otherwise applicable BAT effluent
limitations, if a discharger is fundamentally different with respect to
the factors specified in CWA Section 304 (other than costs) from those
considered by EPA in establishing the effluent limitations. CWA Section
301(n) also defined the conditions under which EPA may establish
alternative requirements. Under Section 301(n), an application for
approval of a FDF variance must be based solely on (1) information
submitted during rulemaking raising the factors that are fundamentally
different or (2) information the applicant did not have an opportunity
to submit. The alternate limitation must be no less stringent than
justified by the difference and must not result in markedly more
adverse non-water quality environmental impacts than the national
limitation.
    EPA regulations at 40 CFR part 125, subpart D, authorizing the
regional administrators to establish alternative

limitations, further detail the substantive criteria used to evaluate
FDF variance requests for direct dischargers. Thus, 40 CFR 125.31(d)
identifies six factors (e.g., volume of process wastewater, age and
size of a discharger's facility) that may be considered in determining
if a discharger is fundamentally different. The Agency must determine
whether, based on one or more of these factors, the discharger in
question is fundamentally different from the dischargers and factors
considered by EPA in developing the nationally applicable effluent
guidelines. The regulation also lists four other factors (e.g.,
inability to install equipment within the time allowed or a
discharger's ability to pay) that may not provide a basis for an FDF
variance. In addition, under 40 CFR 125.31(b)(3), a request for
limitations less stringent than the national limitation may be approved
only if compliance with the national limitations would result in either
(a) a removal cost wholly out of proportion to the removal cost
considered during development of the national limitations, or (b) a
non-water quality environmental impact (including energy requirements)
fundamentally more adverse than the impact considered during
development of the national limits. The legislative history of Section
301(n) underscores the necessity for the FDF variance applicant to
establish eligibility for the variance. EPA's regulations at 40 CFR
125.32(b)(1) impose this burden upon the applicant. The applicant must
show that the factors relating to the discharge controlled by the
applicant's permit that are claimed to be fundamentally different are,
in fact, fundamentally different from those factors considered by EPA
in establishing the applicable guidelines. In practice, very few FDF
variances have been granted for past ELGs. An FDF variance is not
available to a new source subject to NSPS. DuPont v. Train, 430 U.S.
112 (1977).
2. Economic Variances
    Section 301(c) of the CWA authorizes a variance from the otherwise
applicable BAT effluent guidelines for nonconventional pollutants due
to economic factors. The request for a variance from effluent
limitations developed from BAT guidelines must normally be filed by the
discharger during the public notice period for the draft permit. Other
filing periods may apply, as specified in 40 CFR 122.21(m)(2). Specific
guidance for this type of variance is provided in ``Draft Guidance for
Application and Review of Section 301(c) Variance Requests,'' dated
August 21, 1984, available on EPA's Web site at http://www.epa.gov/npdes/pubs/OWM0469.pdf.
3. Water Quality Variances
    Section 301(g) of the CWA authorizes a variance from BAT effluent
guidelines for certain nonconventional pollutants due to localized
environmental factors. These pollutants include ammonia, chlorine,
color, iron, and total phenols. As this proposed rule would not
establish limitations or standards for any of these pollutants, this
variance would not be applicable to this particular rule.
4. Removal Credits
    Section 307(b)(1) of the CWA establishes a discretionary program
for POTWs to grant ``removal credits'' to their indirect dischargers.
Removal credits are a regulatory mechanism by which industrial users
may discharge a pollutant in quantities that exceed what would
otherwise be allowed under an applicable categorical pretreatment
standard because it has been determined that the POTW to which the
industrial user discharges consistently treats the pollutant. EPA has
promulgated removal credit regulations as part of its pretreatment
regulations. See 40 CFR 403.7. These regulations provide that a POTW
may give removal credits if prescribed requirements are met. The POTW
must apply to and receive authorization from the Approval Authority. To
obtain authorization, the POTW must demonstrate consistent removal of
the pollutant for which approval authority is sought. Furthermore, the
POTW must have an approved pretreatment program. Finally, the POTW must
demonstrate that granting removal credits will not cause the POTW to
violate applicable federal, state, or local sewage sludge requirements.
40 CFR 403.7(a)(3).
    The United States Court of Appeals for the Third Circuit
interpreted the CWA as requiring EPA to promulgate the comprehensive
sewage sludge regulations pursuant to CWA Section 405(d)(2)(A)(ii)
before any removal credits could be authorized. See NRDC v. EPA, 790
F.2d 289, 292 (3d Cir., 1986); cert. denied., 479 U.S. 1084 (1987).
Congress made this explicit in the Water Quality Act of 1987, which
provided that EPA could not authorize any removal credits until it
issued the sewage sludge use and disposal regulations. On February 19,
1993, EPA promulgated Standards for the Use or Disposal of Sewage
Sludge, which are codified at 40 CFR part 503 (58 FR 9248). EPA
interprets the Court's decision in NRDC v. EPA as only allowing removal
credits for a pollutant if EPA has either regulated the pollutant in
part 503 or established a concentration of the pollutant in sewage
sludge below which public health and the environment are protected when
sewage sludge is used or disposed.
    The part 503 sewage sludge regulations allow four options for
sewage sludge disposal: (1) Land application for beneficial use, (2)
placement on a surface disposal unit, (3) firing in a sewage sludge
incinerator, and (4) disposal in a landfill which complies with the
municipal solid waste landfill criteria in 40 CFR part 258. Because
pollutants in sewage sludge are regulated differently depending upon
the use or disposal method selected, under EPA's pretreatment
regulations the availability of a removal credit for a particular
pollutant is linked to the POTW's method of using or disposing of its
sewage sludge. The regulations provide that removal credits may be
potentially available for the following pollutants:
    (1) If POTW applies its sewage sludge to the land for beneficial
uses, disposes of it in a surface disposal unit, or incinerates it in a
sewage sludge incinerator, removal credits may be available for the
pollutants for which EPA has established limits in 40 CFR part 503. EPA
has set ceiling limitations for nine metals in sludge that is land
applied, three metals in sludge that is placed on a surface disposal
unit, and seven metals and 57 organic pollutants in sludge that is
incinerated in a sewage sludge incinerator. 40 CFR 403.7(a)(3)(iv)(A).
    (2) Additional removal credits may be available for sewage sludge
that is land applied, placed in a surface disposal unit, or incinerated
in a sewage sludge incinerator, so long as the concentration of these
pollutants in sludge do not exceed concentration levels established in
part 403, Appendix G, Table II. For sewage sludge that is land applied,
removal credits may be available for an additional two metals and 14
organic pollutants. For sewage sludge that is placed on a surface
disposal unit, removal credits may be available for an additional seven
metals and 13 organic pollutants. For sewage sludge that is incinerated
in a sewage sludge incinerator, removal credits may be available for
three other metals 40 CFR 403.7(a)(3)(iv)(B).
    (3) When a POTW disposes of its sewage sludge in a municipal solid
waste landfill that meets the criteria of 40 CFR part 258, removal
credits may be available for any pollutant in the POTW's sewage sludge.
40 CFR 403.7(a)(3)(iv)(C).

XVII. Related Acts of Congress, Executive Orders, and Agency
Initiatives

A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review

    Under Section 3(f)(1) of Executive Order (EO) 12866 (58 FR 51735,
October 4, 1993), this action is an ``economically significant
regulatory action'' because it is likely to have an annual effect on
the economy of $100 million or more. Accordingly, EPA submitted this
action to the Office of Management and Budget (OMB) for review under
Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any
changes made in response to OMB recommendations have been documented in
the docket for this action.
    In addition, EPA prepared an analysis of the potential costs and
benefits associated with this action. This analysis is contained in
Chapter 12 of the BCA report. A copy of the analysis is available in
the docket for this action and the analysis is briefly summarized here.
    Table XVII-1 (drawn from Table 12-1 of the BCA report) provides the
results of the benefit-cost analysis with both costs and benefits
annualized over 24 years and discounted using a 3 percent discount
rate. The table lists the eight options in order of increasing total
social costs.

 Table XVII-1--Total Monetized Annualized Benefits and Costs of the BAT
                       and PSES Regulatory Options
             [Millions 2010 $, 3 percent discount rate] \a\
------------------------------------------------------------------------
                                                                Total
                                                   Total      monetized
              Regulatory  option                   social      benefits
                                                 costs \b\   \c\ \d\ \e\
------------------------------------------------------------------------
Option 3a.....................................       $185.2        (\e\)
Option 1......................................        268.3        $82.0
Option 3b.....................................        281.4        (\e\)
Option 2......................................        386.8        111.7
Option 3......................................        572.0        311.7
Option 4a.....................................        954.1        (\e\)
Option 4......................................      1,381.2        605.5
Option 5......................................      2,328.8        434.1
------------------------------------------------------------------------
\a\ All costs and benefits were annualized over 24 years and using a 3
  percent discount rate.
\b\ Total social costs include compliance costs to facilities.
\c\ Mean benefit estimates. Values include partial human health benefits
  only for reaches that receive direct discharges from steam electric
  plants. Values for Options 1, 2, and 5 do not include air-related
  benefits.
\d\ EPA estimated certain benefits for Options 3 and 4 only. Total
  benefits for Options 1, 2, and 5 are therefore understated. See
  Section XIV and Table XIV-8.
\e\ EPA did not estimate benefits for Options 3a, 3b and 4a. The
  benefits of Option 4a are expected to be between those of Options 3
  and 4.

    EPA also analyzed the employment effects of the proposed ELGs. The
results of that analysis are summarized in Section XI.E.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden.
However, the Office of Management and Budget (OMB) has previously
approved the information collection requirements contained in the
existing regulations 40 CFR part 423 under the provisions of the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB
control number 2040-0281. The OMB control numbers for EPA's regulations
in 40 CFR are listed in 40 CFR part 9.
    EPA estimated small changes in monitoring costs due to additional
metals for which EPA is proposing limits and standards; the Agency
accounted for these costs as part of its analysis of the economic
impacts of the proposed ELGs. However, plants will also realize certain
savings by no longer monitoring effluent that would cease to exist
under the proposed ELGs. The net changes in monitoring and reporting
are expected to be minimal, and EPA consequently did not revise its
information collection burden estimate.
    EPA does not believe that the proposed rule would lead to
additional costs to permitting authorities. The proposed rule would not
change permit application requirements or the associated review, it
would not increase the number of permits issued to steam electric
plants, and nor it increase the efforts involved in developing or
reviewing such permits. In the absence of nationally applicable BAT
requirements, as appropriate, permitting authorities are directed to
establish technology-based effluent limitations using their use best
professional judgment (BPJ) to establish site-specific requirements.
EPA has data that demonstrates that permitting authorities that
establish technology-based effluent limitations on a BPJ basis based on
site-specific conditions can spend significant time effort and
resources doing so. Establishing nationally applicable BAT requirements
that eliminate the need to develop BPJ-based limitations would make
permitting easier and less costly in this respect. As explained in
Section XVI, under this rule, permitting authorities would be required
to determine, for one permit cycle, on a facility-specific basis, what
date is ``as soon as possible.'' This one-time burden, however, would
be no more excessive than the existing burden to develop technology-
based effluent limitations on a BPJ basis; in fact, it would likely be
less burdensome. Nevertheless, EPA conservatively estimated no net
change (i.e., increase or decrease) in the cost burden to federal or
state governments associated with this proposal.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice-and-comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
1. Definition of Small Entities and Estimation of the Number of Small
Entities Subject to These Proposed ELGs
    For purposes of assessing the impacts of this proposed rule on
small entities, small entity is defined as either a: (1) A small
business as defined by the Small Business Administration's (SBA)
regulations at 13 CFR 121.201; (2) a small governmental jurisdiction
that is a government of a city, county, town, school district or
special district with a population of less than 50,000; or (3) a small
organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field. In
reaching entity size determinations, EPA assumed that all federal or
state entities owning steam electric plants affected by this rulemaking
are not small entities.
    The SBA criteria for identifying small, non-government entities in
the electric power industry are as follows:
     For non-government entities with electric power generation
as a primary business, small entities are those with total annual
electric output less than 4 million MWh;
     For non-federal or state jurisdictions, small entities are
those with a population of less than 50,000.
     For entities with a primary business other than electric
power generation, the relevant size criteria are based on revenue or
number of employees by NAICS sector (see Table XVII-2).

    Table XVII-2--NAICS Codes and SBA Entity Size Standards for Steam
  Electric Generators with a Primary Business Other Than Electric Power
                              Generation a
------------------------------------------------------------------------
                                                      SBA size standard
    NAICS Code             NAICS description                 \b\
------------------------------------------------------------------------
211111............  Crude Petroleum and Natural     500 Employees.
                     Gas Extraction.
212111............  Bituminous Coal and Lignite     500 Employees.
                     Surface Mining.
213112............  Support Activities for Oil and  $7 million in
                     Gas Operations.                 revenue.
221210............  Natural Gas Distribution......  500 Employees.
221310............  Water Supply and Irrigation     $7 million in
                     Systems.                        revenue.
221330............  Steam and                       $12.5 million in
                     Air[dash]Conditioning Supply.   revenue.
237130............  Power and Communication Line    $33.5 million in
                     and Related Structures          revenue.
                     Construction.
324110............  Petroleum Refineries..........  1,500 Employees.
332410............  Power Boiler and Heat           500 Employees.
                     Exchanger Manufacturing.
333611............  Turbine and Turbine Generator   1,000 Employees.
                     Set Unit Manufacturing.
423510............  Metal Service Centers and       100 Employees.
                     Other Metal Merchant
                     Wholesalers.
486110............  Pipeline Transportation of      1,500 Employees.
                     Crude Oil.
522110............  Commercial Banking............  $175 million in
                                                     assets.
523110............  Investment Banking and          $7 million in
                     Securities Dealing.             revenue.
523910............  Miscellaneous Intermediation..  $7 million in
                                                     revenue.
523920............  Portfolio Management..........  $7 million in
                                                     revenue.
524113............  Direct Life Insurance Carriers  $7 million in
                                                     revenue.
524126............  Direct Property and Casualty    1,500 employees.
                     Insurance Carriers.
525910............  Open[dash]End Investment Funds  $7 million in
                                                     revenue.
541614............  Process, Physical Distribution  $14 million in
                     and Logistics Consulting        revenue.
                     Services.
541690............  Other Scientific and Technical  $14 million in
                     Consulting Services.            revenue.
551111............  Offices of Bank Holding         $7 million in
                     Companies.                      revenue.
551112............  Offices of Other Holding        $7 million in
                     Companies.                      revenue.
562219............  Other Nonhazardous Waste        $12.5 million in
                     Treatment and Disposal.         revenue.\c\
------------------------------------------------------------------------
\a\ Certain plants affected by this rulemaking are owned by non-
  government entities whose primary business is not electric power
  generation.
\b\ Based on size standards effective at the time EPA conducted this
  analysis (SBA size standards, effective October 1, 2012).
\c\ EPA is aware that SBA revised the size standard applicable to this
  sector, effective January 7, 2013 (from $12.5 million in revenue to
  $35.5 million in revenue); EPA used the size standards effective at
  the time the analyses were completed and will update the size
  standards as part of revisions to support final rulemaking.

    EPA identified the domestic parent entity of each steam electric
plant and obtained the entity's revenue from the Steam Electric
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. To determine whether these entities are small entities based on
the size criteria outlined above, EPA compared the relevant measure for
the identified parent entities to the appropriate SBA size criterion.
    EPA used alternative sample-weighting approaches, which provide a
range of estimates of the numbers of small entities and affected plants
owned by these small entities (see Chapter 8 in the RIA for details of
methodology used to develop weighted estimates). The results of this
analysis using both weighting approaches are summarized below.
    EPA estimates that 243 to 507 entities own steam electric plants
subject to this proposal. Applying the small entity identification
criteria, EPA estimates that 97 to 170 of these entities are small (see
Table XVII-3). Municipalities make up the largest number of small
entities owning steam electric plants under the lower bound estimate
(37 out of 97) and are also a significant fraction of small entities
under the upper bound estimate (46 out of 170). Small entities owning
steam electric plants as a percentage of total entities range, by
ownership category, from 14 to 17 percent for other political
subdivision, to 47 to 51 percent for nonutility and 45 to 57 percent
for municipality.
    EPA determined that 14 small entities own steam electric plants
expected to incur compliance costs under at least one of the eight
regulatory options, for either of the two bounding cases.

                                    Table XVII-3--Number of Entities Owning Steam Electric Plants by Sector and Size
                                                      [Assuming two different ownership cases] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Lower bound estimate of number of entities      Upper bound estimate of number of entities
                                                                 owning steam electric plants \b\                owning steam electric plants \b\
                     Ownership type                      -----------------------------------------------------------------------------------------------
                                                               Total         Small \c\        % Small          Total         Small \c\        % Small
--------------------------------------------------------------------------------------------------------------------------------------------------------
Investor-Owned Utilities................................              97              27            27.8             244              64            26.3
Nonutilities............................................              35              18            51.4              73              34            46.8
Rural Electric Cooperatives.............................              30              13            43.3              52              21            40.7
Municipality............................................              65              37            56.9             101              46            45.3
Other Political Subdivision.............................              12               2            16.7              30               4            14.2
Federal \a\.............................................               2               0             0.0               4               0             0.0
State \a\...............................................               2               0             0.0               2               0            0.0%
Tribal..................................................               0               0             N/A               0               0             N/A
All Entity Types........................................             243              97            39.9             507             170           33.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ In 19 instances, a plant is owned by a joint venture of two entities; in one instance, the plant is owned by a joint venture of three entities.

\b\ Of these, 92 entities, 14 of which are small, own steam electric plants that are expected to incur compliance costs under at least one regulatory
  option under both Case 1 and Case 2.
\c\ EPA was unable to determine size for 10 parent entities; for this analysis, these entities are assumed to be small.

    In total, small entities own a total of 189 steam electric plants,
or 18 percent of the total universe of 1,079 steam electric plants. Of
these, EPA determined that 14 plants may incur compliance costs under
at least one of the eight regulatory options.
    EPA notes that its proposal (discussed in Section VIII) to set the
BAT equal to BPT for existing generating units with a total nameplate
generating capacity of 50 MW or less for all of the eight proposed
regulatory options will reduce the potential impacts of the proposed
rule on small entities and municipalities. The rulemaking record
indicates that establishing a size threshold for the BAT would
preferentially minimize some of the economic impacts expected on
municipalities and small entities. This is the result, in particular,
of the fact that 37 percent of small entities own a steam electric
generating unit with a capacity of 50 MW or smaller. This stands in
contrast to the 22 percent of all firms (both large and small entities)
that own such a unit and the 18 percent of large entities that own one.
Moreover, more than half (54 percent) of generating units owned by
small entities are 50 MW or smaller. In contrast, only seven percent of
generating units owned by large entities are 50 MW or smaller.
Municipalities also tend to own smaller generating units, with 30
percent of municipalities and 42 percent of municipal-owned units being
affected by the 50 MW size threshold.
    EPA requests comment on the proposed 50 MW threshold applicable to
discharges of the wastestreams described under each of the preferred
options, and as well as other possible thresholds for small units.
2. Statement of Basis
    As described above, EPA began its assessment of the impact of
regulatory options on small entities by first estimating the number of
small entities owning Steam Electric plants that would be subject to
these proposed ELGs. EPA then assessed whether these small entities
would be expected to incur costs that constitute a significant impact;
and whether the number of those small entities estimated to incur a
significant impact represent a substantial number of small entities.
    To assess whether small entities' compliance costs might constitute
a significant impact, EPA summed annualized compliance costs for the
steam electric plants determined to be owned by a given small entity
and calculated these costs as a percentage of entity revenue (cost-to-
revenue test). EPA compared the resulting percentages to impact
criteria of 1 percent and 3 percent of revenue. Small entities
estimated to incur compliance costs exceeding one or more of the 1
percent and 3 percent impact thresholds were identified as potentially
incurring a significant impact.
    EPA used alternative sample-weighting approaches, which provide a
range of estimates of the numbers of small entities and steam electric
plants owned by these small entities. The results of this analysis
using both weighting approaches are summarized below. Table XVII-4
presents the estimated numbers of small entities incurring costs
exceeding 1 percent and 3 percent of revenue. For more information on
this analysis in general and the weighting approaches in particular,
see Chapter 7 in the RIA report.

  Table XVII-4--Estimated Cost-to-Revenue Impact on Small Entities Owning Steam Electric Plants Subject to This
                                                  Proposed Rule
                                   [Excluding those below the size threshold]
----------------------------------------------------------------------------------------------------------------
                                                 Cost >=1% of revenue                Cost >=3% of revenue
                                         -----------------------------------------------------------------------
            Regulatory option                                  % of small                          % of small
                                           Number of small      affected       Number of small      affected
                                              entities        entities \b\      entities \a\      entities \b\
----------------------------------------------------------------------------------------------------------------
                     Lower bound estimate of number of entities owning steam electric plants
----------------------------------------------------------------------------------------------------------------
Option 3a...............................                 0               0.0                 0               0.0
Option 3b...............................                 0               0.0                 0               0.0
Option 1................................                 3               3.1                 3               3.1
Option 2................................                 5               5.2                 3               3.1
Option 3................................                 5               5.2                 3               3.1
Option 4a...............................                 6               6.2                 4               4.1
Option 4................................                12              12.4                 4               4.1
Option 5................................                12              12.4                 7               7.2
----------------------------------------------------------------------------------------------------------------
                     Upper bound estimate of number of entities owning steam electric plants
----------------------------------------------------------------------------------------------------------------
Option 3a...............................                 0               0.0                 0               0.0
Option 3b...............................                 0               0.0                 0               0.0
Option 1................................                 3               1.8                 3               1.8
Option 2................................                 5               2.9                 3               1.8
Option 3................................                 5               2.9                 3               1.8
Option 4a...............................                 6               3.5                 4               2.4
Option 4................................                12               7.1                 4               2.4
Option 5................................                12               7.1                 7               4.1
----------------------------------------------------------------------------------------------------------------
\a\ The number of entities with cost-to-revenue ratios exceeding 3 percent is a subset of the number of entities
  with such ratios exceeding 1 percent.
\b\ Percentage values were calculated relative to the total of 97 (Case 1) and 170 (Case 2) small entities
  owning steam electric plants.

    As reported in Table XVII-4, EPA estimates that between 0 and 12
small entities owning steam electric plants will incur costs exceeding
1 percent of revenue, and that between 0 and 7 small entities owning
steam electric plants will incur costs exceeding 3 percent of revenue,
depending on the regulatory option. This is out of an estimated total
of 97 to 170 small entities owning steam electric plants. The impact
findings in terms of numbers of entities affected at different levels,
and the percentage of small entities by ownership category vary by
regulatory option. Overall across entity types, no small entity is
estimated to have costs exceeding 1 percent of revenue under Options 3a
and 3b. Under Option 3, 5 small entities are estimated to have costs
exceeding 1 percent of revenue, and 3 small entities have costs
exceeding 3 percent of revenue. Under Option 4a, 6 small entities are
estimated to have costs 1 percent of revenue or higher under Option 3,
and 4 small entities have costs 3 percent of revenue or higher. Table
XVII-5 presents the distribution of these entities by ownership type
for Options 3 and 4a (Options 3a and 3b are not included in the table
since no small entity has costs 1 percent of revenue or higher under
these two options). As shown in the table, small entities with costs 1
percent of revenue or greater under Option 3 include 2 cooperatives and
3 municipalities. Under Option 4a, 2 cooperatives and 4 municipalities
have costs 1 percent of revenue or greater. The cost-to-revenue test is
one of several metrics EPA used to determine the impacts of the
proposed ELGs. As discussed in Section XI.D, EPA also looked at impacts
in the context of the electricity market-level effects to assess
economic achievability.

  Table XVII-5--Estimated Cost-to-Revenue Impact on Small Entities Owning Steam Electric Plants Under the Preferred BAT and PSES Options (Options 3 and
                                           4a), by Ownership Type (Excluding Those Below the Size Threshold) a
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                            Lower bound estimate of number  of entities owning      Upper bound estimate  of number of entities owning
                                                          steam  electric plants                                  steam  electric plants
                                        ----------------------------------------------------------------------------------------------------------------
                                            Cost >=1% of revenue         Cost >=3% of revenue        Cost >=1% of revenue        Cost >=3% of revenue
           Regulatory option            ----------------------------------------------------------------------------------------------------------------
                                           Number of    % of small     Number of     % of small     Number of    % of small     Number of    % of small
                                             small       affected        small        affected        small       affected        small       affected
                                           entities    entities \c\  entities \b\   entities \c\    entities    entities \c\  entities \b\  entities \c\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3:
    Cooperative........................             2          15.4             2          15.4              2           9.4             2           9.4
    Investor-Owned.....................             0           0.0             0           0.00             0           0.0             0           0.0
    Municipality.......................             3           8.1             1           2.7              3           6.5             1           2.2
    Nonutility.........................             0           0.0             0           0.0              0           0.0             0           0.0
    Other Political Subdivision........             0           0.0             0           0.0              0           0.0             0           0.0
                                        ----------------------------------------------------------------------------------------------------------------
        Total..........................             5           5.2             3           3.1              5           2.9             3           1.8
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 4a:
    Cooperative........................             2          15.4             2          15.4              2           9.4             2           9.4
    Investor-Owned.....................             0           0.0             0           0.0              0           0.0             0           0.0
    Municipality.......................             4          10.8             2           5.4              4           8.7             2           4.4
    Nonutility.........................             0           0.0             0           0.0              0           0.0             0           0.0
    Other Political Subdivision........             0           0.0             0           0.0              0           0.0             0           0.0
                                        ----------------------------------------------------------------------------------------------------------------
        Total..........................             6           6.2             4           4.1              6           3.5             4           2.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Options 3a and 3b are not included in the table since no small entity has costs 1 percent of revenue or higher under these two preferred options.
\b\ The number of entities with cost-to-revenue ratios exceeding 3 percent is a subset of the number of entities with such ratios exceeding 1 percent.
\c\ Percentage values were calculated relative to the total of 97 (Case 1) and 170 (Case 2) small entities owning steam electric plants. EPA expects
  that Case 2 is a more likely ownership scenario for small entities (e.g., small municipalities) as small entities may be less likely to own multiple
  non-surveyed steam electric plants. See RIA Chapter 8 for details.

    Based on this analysis, EPA determines that the small entity impact
levels for the preferred BAT and PSES options (Options 3a, 3b, 3 and
4a) support a finding of no significant impact on a substantial number
of small entities (No SISNOSE). Where not zero altogether, the numbers
of small entities incurring costs exceeding either the 1 or 3 percent
of revenue impact threshold are small in the absolute and represent
small percentages of the total estimated number of small entities (see
Table XVII-5). For more details on this

analysis, see Chapter 8 of the RIA report.
3. Certification Statement
    After considering the economic impacts of these proposed ELGs on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. EPA bases
its finding on the low number of small entities estimated to incur
costs exceeding one and/or three percent of revenue, and the small
percentage that these entities represent within the total of small
entities owning steam electric plants. EPA continues to be interested
in the potential impacts of the proposed rule on small entities and
welcomes comments on issues related to potential impacts.

D. Unfunded Mandates Reform Act (UMRA)

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2
U.S.C. 1531-1538, requires federal agencies, unless otherwise
prohibited by law, to assess the effects of their regulatory actions on
State, local, and tribal governments and the private sector. This rule
contains a federal mandate that may result in expenditures of $100
million or more for State, local, and tribal governments, in the
aggregate, or the private sector in any one year. Accordingly, EPA has
prepared under Section 202 of the UMRA a written statement, which is
summarized below (see Chapter 9 in the RIA report for more details).
    Consistent with the intergovernmental consultation provisions of
Section 204 of the UMRA EPA has initiated consultations with
governmental entities affected by this rule. As described in Sections
XVII.E, EPA held consultation meetings with elected officials or their
designated employees in October 2011 to ensure their meaningful and
timely input into the proposed ELGs development. EPA also conducted
outreach with several intergovernmental associations representing
elected officials. As described in Section XVII.F, EPA also initiated
consultation and coordination with federally-recognized tribal
governments in August 2011 and continued this government-to-government
dialogue in March 2012.
    Consistent with Section 205, EPA has identified and considered a
reasonable number of regulatory alternatives. EPA considered and
analyzed several alternative regulatory options to determine BAT/BADCT.
These regulatory options are discussed in Section VIII of this
preamble. These options included a range of technology-based
approaches. As discussed in detail in Section VIII, EPA is proposing
Options 3a, 3b, 3 and 4a as the preferred BAT and PSES options because
they are technologically available, economically achievable, and have
acceptable non-water quality environmental impacts. EPA is proposing
Option 4 as the preferred NSPS and PSNS option because it is
technologically available and demonstrated, poses no barrier to entry,
and has acceptable non-water quality environmental impacts.
    This rule is not subject to the requirements of Section 203 of UMRA
because it contains no regulatory requirements that might significantly
or uniquely affect small governments. For its assessment of the impact
of compliance requirements on small governments (i.e., governments with
a population of less than 50,000), EPA compared total costs and costs
per plant estimated to be incurred by small governments with the costs
estimated to be incurred by large governments. EPA also compared costs
for small government-owned plants with those of non-government-owned
facilities. The Agency evaluated both the average and maximum
annualized cost per plant. Chapter 9 of the RIA report provides details
of these analyses. In all of these comparisons, both for the cost
totals and, in particular, for the average and maximum cost per plant,
the costs for small government-owned facilities were less than those
for large government-owned facilities or for small non-government-owned
facilities. On this basis, EPA concludes that the compliance cost
requirements of the proposed Steam Electric ELGs would not
significantly or uniquely affect small governments.

E. Executive Order 13132: Federalism

    Under Executive Order 13132, EPA may not issue an action that has
federalism implications, that imposes substantial direct compliance
costs, and that is not required by statute, unless the Federal
government provides the funds necessary to pay the direct compliance
costs incurred by State and local governments, or EPA consults with
state and local officials early in the process of developing the
proposed action.
    EPA has concluded that this action may have federalism
implications, because it may impose substantial direct compliance costs
on state or local governments, and the federal government will not
provide the funds necessary to pay those costs.
    As discussed in Section XI, EPA anticipates that this proposed
action will not impose incremental administrative burden on states from
issuing, reviewing, and overseeing compliance with discharge
requirements. However, EPA has identified 168 steam electric plants
owned by state or local government entities, out of which less than 10
percent may incur costs under one of the preferred regulatory Options.
Specifically, EPA projects that five government-owned plants incur
compliance costs under BAT/PSES regulatory Option 3a, six plants incur
compliance costs under Option 3b, 14 plants incur compliance costs
under Option 3, and 15 plants incur compliance costs under Option 4a.
EPA estimates that the maximum compliance cost in any one year to
governments (excluding federal government) for the eight regulatory
options ranges from $13.8 million under Option 3a to $406.2 million
under Option 5. Options 3b, 3 and 4a have maximum compliance costs in
any one year to governments of $31.9 million, $109.5 million and $141.8
million, respectively (see Chapter 9 of the RIA report for details).
From these cost values, EPA determined that the proposed ELGs contain a
federal mandate that may result in expenditures of $100 million or more
for state, local, and tribal governments, in the aggregate, in any one
year. Based on this information, EPA finds that the action may impose
substantial direct compliance costs on state or local governments.
Accordingly, EPA provides the following federalism summary impact
statement as required by Section 6(b) of Executive Order 13132.
    EPA consulted with elected officials or their representative
national organizations early in the process of developing the proposed
action to permit them to have meaningful and timely input into its
development.
    EPA invited government officials to a consultation meeting held on
October 11, 2011. EPA conducted outreach with several intergovernmental
associations representing elected officials and encouraged their
members to participate in the meeting, including the National Governors
Association, the National Conference of State Legislatures, the Council
of State Governments, the National Association of Counties, the
National League of Cities, the U.S. Conference of Mayors, the County
Executives of America and the National Associations of Towns and
Townships.
    Over 50 participants attended the consultation by phone and another
20 attended the meeting in person. EPA representatives were also
present. Participants raised concerns during the meeting and in written
comments

regarding the technology options, pollutant removal effectiveness,
costs of specific technologies and overall costs, impacts on small
generating units and on small governments, and generally requested more
detailed information. They also expressed their concern with regulating
the industry at this time given the difficult economic conditions.
    As explained in Section VIII, under all eight proposed regulatory
options, EPA is proposing differentiated requirements for oil-fired
generating units and units 50 MW or less. EPA believes these
differentiated requirements will alleviate some of the concerns raised
above. Further, as explained in Section XI, EPA's analysis demonstrates
that the proposed requirements are economically achievable for the
steam electric industry as a whole and for plants owned by state or
local government entities. EPA is including in the docket for this
action a memorandum that provides a response to the comments it
received through this consultation. In the spirit of Executive Order
13132, and consistent with EPA policy to promote communications between
EPA and State and local governments, EPA specifically solicits comment
on the proposed ELGs from State and local officials.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It would not
have substantial direct effects on tribal governments, on the
relationship between the federal government and the Indian tribes, or
the distribution of power and responsibilities between the Federal
government and Indian tribes as specified in Executive Order 13175.
EPA's analyses show that no facility subject to these proposed ELGs is
owned by tribal governments. Thus, Executive Order 13175 does not apply
to this action.
    Although Executive Order 13175 does not apply to this action, EPA
consulted with tribal officials in developing this action. EPA
initiated consultation and coordination with federally recognized
tribal governments in August 2011, sharing information about the steam
electric effluent guidelines rulemaking with the National Tribal Caucus
and the National Tribal Water Council. EPA continued this government-
to-government dialogue and, in March 2012, invited tribal
representatives to participate in further discussions about the
rulemaking process and objectives, with a focus on identifying specific
ways that the rulemaking may affect tribes. EPA mailed an invitation
letter directly to those tribes that were preliminarily identified as
potentially affected by the rulemaking, as well extended the invitation
via email to all federally-recognized tribal governments encouraging
their participation in the consultation process. The consultation
process ended on April 17, 2012 and no comments were received from any
tribal representative. For further information regarding the
consultation process and supplemental materials provided to tribal
representatives please go to the steam electric power generating
effluent guidelines Web site at this link: http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm#point8. EPA specifically
solicits additional comment on this proposed action from tribal
officials.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    This action is not subject to Executive Order 13045 (62 FR 19885,
April 23, 1997) because the Agency does not believe the environmental
health risks or safety risks addressed by this action present a
disproportionate risk to children. This proposed action's health and
risk assessments are summarized in Section XIV.D.

H. Executive Order 13211: Actions That Significantly Affect Energy