[Federal Register Volume 80, Number 212 (Tuesday, November 3, 2015)]
[Rules and Regulations]
[Pages 67838-67903]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-25663]



[[Page 67837]]

Vol. 80

Tuesday,

No. 212

November 3, 2015

Part II





Environmental Protection Agency





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40 CFR Part 423





Effluent Limitations Guidelines and Standards for the Steam Electric 
Power Generating Point Source Category; Final Rule

Federal Register / Vol. 80 , No. 212 / Tuesday, November 3, 2015 / 
Rules and Regulations

[[Page 67838]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 423

[EPA-HQ-OW-2009-0819; FRL-9930-48-OW]
RIN 2040-AF14


Effluent Limitations Guidelines and Standards for the Steam 
Electric Power Generating Point Source Category

AGENCY: Environmental Protection Agency.

ACTION: Final rule.

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SUMMARY: This final rule, promulgated under the Clean Water Act (CWA), 
protects public health and the environment from toxic metals and other 
harmful pollutants, including nutrients, by strengthening the 
technology-based effluent limitations guidelines and standards (ELGs) 
for the steam electric power generating industry. Steam electric power 
plants contribute the greatest amount of all toxic pollutants 
discharged to surface waters by industrial categories regulated under 
the CWA. The pollutants discharged by this industry can cause severe 
health and environmental problems in the form of cancer and non-cancer 
risks in humans, lowered IQ among children, and deformities and 
reproductive harm in fish and wildlife. Many of these pollutants, once 
in the environment, remain there for years. Due to their close 
proximity to these discharges and relatively high consumption of fish, 
some minority and low-income communities have greater exposure to, and 
are therefore at greater risk from, pollutants in steam electric power 
plant discharges. The final rule establishes the first nationally 
applicable limits on the amount of toxic metals and other harmful 
pollutants that steam electric power plants are allowed to discharge in 
several of their largest sources of wastewater. On an annual basis, the 
rule reduces the amount of toxic metals, nutrients, and other 
pollutants that steam electric power plants are allowed to discharge by 
1.4 billion pounds; it reduces water withdrawal by 57 billion gallons; 
and, it has social costs of $480 million and monetized benefits of $451 
to $566 million.

DATES: The final rule is effective on January 4, 2016. In accordance 
with 40 CFR part 23, this regulation shall be considered issued for 
purposes of judicial review at 1 p.m. Eastern time on November 17, 
2015. Under section 509(b)(1) of the CWA, judicial review of this 
regulation can be had only by filing a petition for review in the U.S. 
Court of Appeals within 120 days after the regulation is considered 
issued for purposes of judicial review. Under section 509(b)(2), the 
requirements in this regulation may not be challenged later in civil or 
criminal proceedings brought by EPA to enforce these requirements.

ADDRESSES: Docket: All documents in the docket are listed in the http://www.regulations.gov index. A detailed record index, organized by 
subject, is available on EPA's Web site at http://www2.epa.gov/eg/steam-electric-power-generating-effluent-guidelines-2015-final-rule. 
Although listed in the index, some information is not publicly 
available, e.g., Confidential Business Information (CBI) or other 
information whose disclosure is restricted by statute. Certain other 
material, such as copyrighted material, will be publicly available only 
in hard copy. Publicly available docket materials are available either 
electronically in http://www.regulations.gov or in hard copy at the 
Water Docket in the EPA Docket Center, EPA/DC, EPA West, Room 3334, 
1301 Constitution Ave. NW., Washington, DC. The Public Reading Room is 
open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding 
legal holidays. The telephone number for the Public Reading Room is 
202-566-1744, and the telephone number for the Water Docket is 202-566-
2426.

FOR FURTHER INFORMATION CONTACT: For technical information, contact 
Ronald Jordan, Engineering and Analysis Division, Telephone: 202-566-
1003; Email: [email protected]. For economic information, contact 
James Covington, Engineering and Analysis Division, Telephone: 202-566-
1034; Email: [email protected].

SUPPLEMENTARY INFORMATION:

Organization of This Preamble

Table of Contents

I. Regulated Entities and Supporting Documentation
    A. Regulated Entities
    B. Supporting Documentation
II. Legal Authority for This Action
III. Executive Summary
    A. Purpose of the Rule
    B. Summary of Final Rule
    C. Summary of Costs and Benefits
IV. Background
    A. Clean Water Act
    B. Effluent Guidelines Program
    1. Best Practicable Control Technology Currently Available
    2. Best Conventional Pollutant Control Technology
    3. Best Available Technology Economically Achievable
    4. Best Available Demonstrated Control Technology/New Source 
Performance Standards
    5. Pretreatment Standards for Existing Sources
    6. Pretreatment Standards for New Sources
    C. Steam Electric Effluent Guidelines Rulemaking History
V. Key Updates Since Proposal
    A. Industry Profile Changes Due to Retirements and Conversions
    B. EPA Consideration of Other Federal Rules
    C. Advancements in Technologies
    D. Engineering Costs
    E. Economic Impact Analysis
    F. Pollutant Data
    G. Environmental Assessment Models
VI. Industry Description
    A. General Description of Industry
    B. Steam Electric Process Wastewater and Control Technologies
    1. FGD Wastewater
    2. Fly Ash Transport Water
    3. Bottom Ash Transport Water
    4. FGMC Wastewater
    5. Combustion Residual Leachate From Landfills and Surface 
Impoundments
    6. Gasification Wastewater
VII. Selection of Regulated Pollutants
    A. Identifying the Pollutants of Concern
    B. Selection of Pollutants for Regulation Under BAT/NSPS
    C. Methodology for the POTW Pass-Through Analysis (PSES/PSNS)
VIII. The Final Rule
    A. BPT
    B. BAT/NSPS/PSES/PSNS Options
    1. FGD Wastewater
    2. Fly Ash Transport Water
    3. Bottom Ash Transport Water
    4. FGMC Wastewater
    5. Gasification Wastewater
    6. Combustion Residual Leachate
    7. Non-Chemical Metal Cleaning Wastes
    C. Best Available Technology
    1. FGD Wastewater
    2. Fly Ash Transport Water
    3. Bottom Ash Transport Water
    4. FGMC Wastewater
    5. Gasification Wastewater
    6. Combustion Residual Leachate
    7. Timing
    8. Legacy Wastewater
    9. Economic Achievability
    10. Non-Water Quality Environmental Impacts, Including Energy 
Requirements
    11. Impacts on Residential Electricity Prices and Low-Income and 
Minority Populations
    12. Existing Oil-Fired and Small Generating Units
    13. Voluntary Incentives Program
    D. Best Available Demonstrated Control Technology/NSPS
    E. PSES
    F. PSNS
    G. Anti-Circumvention Provision
    H. Other Revisions
    1. Correction of Typographical Error for PSNS
    2. Clarification of Applicability
    I. Non-Chemical Metal Cleaning Wastes
    J. Best Management Practices
IX. Costs and Economic Impact
    A. Plant-Specific and Industry Total Costs

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    B. Social Costs
    C. Economic Impacts
    1. Summary of Economic Impacts for Existing Sources
    2. Summary of Economic Impacts for New Sources
X. Pollutant Reductions
XI. Development of Effluent Limitations and Standards
XII. Non-Water Quality Environmental Impacts
XIII. Environmental Assessment
    A. Introduction
    B. Summary of Human Health and Environmental Impacts
    C. Environmental Assessment Methodology
    D. Outputs From the Environmental Assessment
    1. Improvements in Surface Water and Ground Water Quality
    2. Reduced Impacts to Wildlife
    3. Reduced Human Health Cancer Risk
    4. Reduced Threat of Non-Cancer Human Health Effects
    5. Reduced Nutrient Impacts
    E. Unquantified Environmental and Human Health Improvements
    F. Other Secondary Improvements
XIV. Benefit Analysis
    A. Categories of Benefits Analyzed
    B. Quantification and Monetization of Benefits
    1. Human Health Benefits From Surface Water Quality Improvements
    2. Improved Ecological Conditions and Recreational Use Benefits 
From Surface Water Quality Improvements
    3. Market and Productivity Benefits
    4. Air-Related Benefits (Human Health and Avoided Climate Change 
Impacts)
    5. Benefits From Reduced Water Withdrawals (Increased 
Availability of Ground Water Resources)
    C. Total Monetized Benefits
    D. Other Benefits
XV. Cost-Effectiveness Analysis
    A. Methodology
    B. Results
XVI. Regulatory Implementation
    A. Implementation of the Limitations and Standards
    1. Timing
    2. Applicability of NSPS/PSNS
    3. Legacy Wastewater
    4. Combined Wastestreams
    5. Non-Chemical Metal Cleaning Wastes
    B. Upset and Bypass Provisions
    C. Variances and Modifications
    1. Fundamentally Different Factors Variance
    2. Economic Variances
    3. Water Quality Variances
    4. Removal Credits
    D. Site-Specific Water Quality-Based Effluent Limitations
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
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act (CRA)
Appendix A to the Preamble: Definitions, Acronyms, and Abbreviations 
Used in This Preamble

I. Regulated Entities and Supporting Documentation

A. Regulated Entities

    Entities potentially regulated by this action include:

------------------------------------------------------------------------
                                                         North American
                                                            Industry
           Category              Example of regulated    Classification
                                        entity           System (NAICS)
                                                              Code
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Industry......................  Electric Power          22111
                                 Generation
                                 Facilities--Electric
                                 Power Generation.
                                Electric Power          221112
                                 Generation
                                 Facilities--Fossil
                                 Fuel Electric Power
                                 Generation.
                                Electric Power          221113
                                 Generation
                                 Facilities--Nuclear
                                 Electric Power
                                 Generation.
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    This section is not intended to be exhaustive, but rather provides 
a guide for readers regarding entities likely regulated by this action. 
Other types of entities that do not meet the above criteria could also 
be regulated. To determine whether your facility is regulated by this 
action, you should carefully examine the applicability criteria listed 
in 40 CFR 423.10 and the definitions in 40 CFR 423.11 of the rule. If 
you still have questions regarding the applicability of this action to 
a particular entity, consult the person listed for technical 
information in the preceding FOR FURTHER INFORMATION CONTACT section.

B. Supporting Documentation

    This rule is supported, in part, by the following documents:
     Technical Development Document for the Effluent 
Limitations Guidelines and Standards for the Steam Electric Power 
Generating Point Source Category (TDD), Document No. EPA-821-R-15-007.
     Environmental Assessment for the Effluent Limitations 
Guidelines and Standards for the Steam Electric Power Generating Point 
Source Category (EA), Document No. EPA-821-R-15-006.
     Benefits and Cost Analysis for the Effluent Limitations 
Guidelines and Standards for the Steam Electric Power Generating Point 
Source Category (BCA), Document No. EPA-821-R-15-005.
     Regulatory Impact Analysis for the Effluent Limitations 
Guidelines and Standards for the Steam Electric Power Generating Point 
Source Category (RIA), Document No. EPA-821-R-15-004.

These documents are available in the public record for this rule and on 
EPA's Web site at http://www2.epa.gov/eg/steam-electric-power-generating-effluent-guidelines-2015-final-rule.

II. Legal Authority for This Action

    EPA promulgates this rule under the authority of sections 301, 304, 
306, 307, 308, 402, and 501 of the CWA, 33 U.S.C. 1311, 1314, 1316, 
1317, 1318, 1342, and 1361.

III. Executive Summary

A. Purpose of the Rule

    Steam electric power plants \1\ discharge large wastewater volumes, 
containing vast quantities of pollutants, into waters of the United 
States. The pollutants include both toxic and bioaccumulative 
pollutants such as arsenic, mercury, selenium, chromium, and cadmium. 
Today, these discharges account for about 30 percent of all toxic 
pollutants discharged into surface

[[Page 67840]]

waters by all industrial categories regulated under the CWA.\2\ The 
electric power industry has made great strides to reduce air pollutant 
emissions under Clean Air Act programs. Yet many of these pollutants 
are transferred to the wastewater as plants employ technologies to 
reduce air pollution. The pollutants in steam electric power plant 
wastewater discharges present a serious public health concern and cause 
severe ecological damage, as demonstrated by numerous documented 
impacts, scientific modeling, and other studies. When toxic metals such 
as mercury, arsenic, lead, and selenium accumulate in fish or 
contaminate drinking water, they can cause adverse effects in people 
who consume the fish or water. These effects can include cancer, 
cardiovascular disease, neurological disorders, kidney and liver 
damage, and lowered IQs in children.
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    \1\ The steam electric power plants covered by the ELGs use 
nuclear or fossil fuels, such as coal, oil, or natural gas, to heat 
water in boilers, which generate steam. This rule does not apply to 
plants that use non-fossil fuel or non-nuclear fuel or other energy 
sources, such as biomass or solar thermal energy. The steam is used 
to drive turbines connected to electric generators. The plants 
generate wastewater composed of chemical pollutants and thermal 
pollution (heated water) from their wastewater treatment, power 
cycle, ash handling and air pollution control systems, as well as 
from coal piles, yard and floor drainage, and other plant processes.
    \2\ Although the way electricity is generated in this country is 
changing, EPA projects that, without this final rule, steam electric 
power plant discharges would likely continue to account, over the 
foreseeable future, for about thirty percent of all toxic pollutants 
discharged into surface waters by all industrial categories 
regulated under the CWA.
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    There are, however, affordable technologies that are widely 
available, and already in place at some plants, which are capable of 
reducing or eliminating steam electric power plant discharges. In the 
several decades since the steam electric ELGs were last revised, such 
technologies have increasingly been used at plants. This final rule is 
the first to ensure that plants in the steam electric industry employ 
technologies designed to reduce discharges of toxic metals and other 
harmful pollutants discharged in the plants' largest sources of 
wastewater.
    Steam electric power plant discharges occur in proximity to nearly 
100 public drinking water intakes and more than 1,500 public wells 
across the nation, and recent studies indicate that steam electric 
power plant discharges can adversely affect surface waters used as 
drinking water supplies. One study found that arsenic in ash and flue 
gas desulfurization (FGD) wastewater discharges from four steam 
electric power plants exceeded Safe Drinking Water Act (SDWA) Maximum 
Contaminant Levels (MCLS) in the waterbodies into which they 
discharged, indicating that these contaminants are present in surface 
waters, and at levels above standards used to protect drinking water. 
See DCN SE01984. A second, more recent study found increased levels of 
bromide in rivers used as drinking water after FGD systems were 
installed at upstream steam electric power plants. The study showed an 
increase in bromides at four drinking water utilities' intakes after 
wastewater from these FGD systems began to be discharged to the rivers, 
whereas prior to the FGD wastewater discharges, bromides were not a 
problem in the intake waters of the utilities. With bromides present in 
their drinking water source waters at increased levels, carcinogenic 
disinfection by-products (brominated DBPs, in particular 
trihalomethanes (THMs)) began forming, and at one drinking water 
utility, violations of the THM MCL began occurring. See DCN SE04503.
    Nitrogen discharged by steam electric power plants can also impact 
drinking water sources by contributing to harmful algal blooms in 
reservoirs and lakes that are used as drinking water sources. Ground 
water contamination from surface impoundments (ash ponds) containing 
steam electric power plant wastewater also threatens drinking water, as 
evidenced by more than 30 documented cases. See EA Section 3.3.
    Steam electric power plant discharges also adversely affect the 
quality of fish that people eat. Water quality modeling shows that 
about half of waterbodies that receive steam electric power plant 
discharges exhibit health risks to people consuming fish from those 
waters (primarily from mercury). Nearly half of waterbodies that 
receive steam electric power plant discharges exhibit pollutant levels 
for one or more steam electric power plant pollutants in excess of 
human health water quality criteria (WQC).\3\ See EA Section 4. People 
who eat large amounts of fish from lakes and rivers contaminated by 
mercury, lead, and arsenic are particularly at risk, and consumption of 
such fish poses additional risk to the fetuses of pregnant women. 
Compared to the general public, minority and low-income communities 
have greater exposure to, and are therefore at greater risk from, 
pollutants in steam electric power plant discharges, due to their 
closer proximity to the discharges and greater consumption of fish from 
contaminated waters. See Section XVII.J.
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    \3\ WQCs are established by states to protect beneficial uses of 
waterbodies, such as the support of aquatic life and provision of 
fishing and swimming.
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    Steam electric power plant discharges adversely affect our nation's 
waters and their ecology. Pollutants in such discharges, particularly 
mercury and selenium, bioaccumulate in fish and wildlife, and they 
accumulate in the sediments of lakes and reservoirs, remaining there 
for decades. Documented adverse impacts include the near eradication of 
an entire fish population in the late 1970s in Belews Lake, North 
Carolina, due to selenium discharges from a steam electric power plant 
(DCN SE01842); a series of fish kills in the 1970s in Martin Lake, 
Texas, also due to selenium discharges from a steam electric power 
plant (elevated selenium levels and deformities persisted for at least 
eight years after the plant ceased discharging) (DCN SE01861); 
reproductive impairment and deformities in fish and birds from selenium 
discharges (DCN SE04519); and other forms of impacts to surface waters, 
as documented by numerous other damage cases associated with discharges 
from surface impoundments containing steam electric power plant 
wastewater. See EA Section 3.3.
    Waterbodies receiving steam electric power plant discharges have 
routinely exhibited pollutant levels routinely in excess of state WQC 
for pollutants found in the plant discharges. This includes pollutants 
such as selenium, arsenic, and cadmium. Nutrients in steam electric 
power plant discharges can cause over-enrichment of receiving waters, 
resulting in water quality problems, such as low oxygen levels and loss 
of critical submerged aquatic vegetation, further impairing beneficial 
uses such as fishing. EPA's modeling corroborates such documented 
impacts, revealing that nearly one fifth of waterbodies receiving steam 
electric power plant discharges exceed WQC for protection of aquatic 
life and nearly one third of such receiving waters pose potential 
reproductive risks to birds that prey on fish.
    The steam electric ELGs that EPA promulgated and revised in 1974, 
1977, and 1982 are out of date. They do not adequately control the 
pollutants (toxic metals and other) discharged by this industry, nor do 
they reflect relevant process and technology advances that have 
occurred in the last 30-plus years. The rise of new processes for 
generating electric power (e.g. coal gasification) and the widespread 
implementation of air pollution controls (e.g., FGD and flue gas 
mercury control (FGMC)) have altered existing wastestreams and created 
new types of wastewater at many steam electric power plants, 
particularly coal-fired plants. The processes employed and pollutants 
discharged by the industry look very different today than they did in 
1982. Many plants, nonetheless, still treat their wastewater using only 
surface impoundments, which are largely ineffective at controlling 
discharges of toxic pollutants and nutrients. This final rule addresses 
an outstanding public health and environmental problem by

[[Page 67841]]

revising the steam electric ELGs, as they apply to a subset of power 
plants that discharge wastestreams containing toxic and other 
pollutants. As the CWA requires, this rule is economically achievable 
(affordable for the industry as a whole) and is based on available 
technologies. On an annual basis, the rule is projected to reduce the 
amount of toxic metals, nutrients, and other pollutants that steam 
electric power plants are allowed to discharge by 1.4 billion pounds; 
reduce water withdrawal by 57 billion gallons; and, it has estimated 
social costs of $480 million. Finally, of the benefits that were able 
to be monetized, EPA projects $451 to $566 million in benefits 
associated with this rule.

B. Summary of Final Rule

    To further its ultimate objective to ``restore and maintain the 
chemical, physical, and biological integrity of the Nation's waters,'' 
the CWA authorizes EPA to establish national technology-based effluent 
limitations guidelines and new source performance standards for 
discharges from categories of point sources that occur directly into 
waters of the U.S. The CWA also authorizes EPA to promulgate nationally 
applicable pretreatment standards that control pollutant discharges 
from existing and new sources that discharge wastewater indirectly to 
waters of the U.S. through sewers flowing to publicly owned treatment 
works (POTWs). EPA establishes ELGs based on the performance of well-
designed and well-operated control and treatment technologies.
    EPA completed a study of the steam electric category in 2009 and 
proposed the ELG rule in June 2013. The public comment period extended 
for more than three months. This final rule reflects the statutory 
factors outlined in the CWA, as well as EPA's full consideration of the 
comments received and updated analytical results.
    Existing Sources--Direct Discharges. For existing sources that 
discharge directly to surface water, with the exception of oil-fired 
generating units and small generating units (those with a nameplate 
capacity of 50 megawatts (MW) or less), the final rule establishes 
effluent limitations based on Best Available Technology Economically 
Achievable (BAT). BAT is based on technological availability, economic 
achievability, and other statutory factors and is intended to reflect 
the highest performance in the industry (see Section IV.B.3). The final 
rule establishes BAT limitations as follows: \4\
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    \4\ For details on when the following BAT limitations apply, see 
Section VIII.C.
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     For fly ash transport water, bottom ash transport water, 
and FGMC wastewater, there are two sets of BAT limitations. The first 
set of BAT limitations is a numeric effluent limitation on Total 
Suspended Solids (TSS) in the discharge of these wastewaters (these 
limitations are equal to the TSS limitations in the previously 
established Best Practicable Control Technology Currently Available 
(BPT) regulations). The second set of BAT limitations is a zero 
discharge limitation for all pollutants in these wastewaters.\5\
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    \5\ When fly ash transport water or bottom ash transport water 
is used in the FGD scrubber, the applicable limitations are those 
established for FGD wastewater on mercury, arsenic, selenium and 
nitrate/nitrite as N.
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     For FGD wastewater, there are two sets of BAT limitations. 
The first set of limitations is a numeric effluent limitation on TSS in 
the discharge of FGD wastewater (these limitations are equal to the TSS 
limitations in the previously established BPT regulations). The second 
set of BAT limitations is numeric effluent limitations on mercury, 
arsenic, selenium, and nitrate/nitrite as N in the discharge of FGD 
wastewater.\6\
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    \6\ For plants that opt into the voluntary incentives program, 
the second set of BAT limitations is numeric effluent limitations on 
mercury, arsenic, selenium, and TDS in the discharge of FGD 
wastewater.
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     For gasification wastewater, there are two sets of BAT 
limitations. The first set of limitations is a numeric effluent 
limitation on TSS in the discharge of gasification wastewater (this 
limitation is equal to the TSS limitation in the previously established 
BPT regulations). The second set of BAT limitations is numeric effluent 
limitations on mercury, arsenic, selenium, and total dissolved solids 
(TDS) in the discharge of gasification wastewater.
     A numeric effluent limitation on TSS in the discharge of 
combustion residual leachate from landfills and surface impoundments. 
This limitation is equal to the TSS limitation in the previously 
established BPT regulations.
    For oil-fired generating units and small generating units (50 MW or 
smaller), the final rule establishes BAT limitations on TSS in the 
discharge of fly ash transport water, bottom ash transport water, FGMC 
wastewater, FGD wastewater, and gasification wastewater. These 
limitations are equal to the TSS limitations in the existing BPT 
regulations.
    New Sources--Direct Discharges. The CWA mandates that new source 
performance standards (NSPS) reflect the greatest degree of effluent 
reduction that is achievable, including, where practicable, a standard 
permitting no discharge of pollutants (see Section IV.B.4). NSPS 
represent the most stringent controls attainable, taking into 
consideration the cost of achieving the effluent reduction and any non-
water quality environmental impacts and energy requirements. For direct 
discharges to surface waters from new sources, including discharges 
from oil-fired generating units and small generating units, the final 
rule establishes NSPS as follows:
     A zero discharge standard for all pollutants in fly ash 
transport water, bottom ash transport water, and FGMC wastewater.
     Numeric standards on mercury, arsenic, selenium, and TDS 
in the discharge of FGD wastewater.
     Numeric standards on mercury and arsenic in the discharge 
of combustion residual leachate.
    Existing Sources--Discharges to POTWs. Pretreatment Standards for 
Existing Sources (PSES) are designed to prevent the discharge of 
pollutants that pass through, interfere with, or are otherwise 
incompatible with the operation of POTWs. PSES are analogous to BAT 
effluent limitations for direct dischargers and are generally based on 
the same factors (see Section IV.B.5). The final rule establishes PSES 
as follows: \7\
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    \7\ For details on when PSES apply, see Section VIII.E.
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     A zero discharge standard for all pollutants in fly ash 
transport water, bottom ash transport water, and FGMC wastewater.\8\
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    \8\ When fly ash transport water or bottom ash transport water 
is used in the FGD scrubber, the applicable standards are those 
established for FGD wastewater on mercury, arsenic, selenium and 
nitrate/nitrite as N.
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     Numeric standards on mercury, arsenic, selenium, and 
nitrate/nitrite as N in the discharge of FGD wastewater.
     Numeric standards on mercury, arsenic, selenium and TDS in 
the discharge of gasification wastewater.
    New Sources--Discharges to POTWs. Pretreatment standards for new 
sources (PSNS) are also designed to prevent the discharge of any 
pollutant into a POTW that interferes with, passes through, or is 
otherwise incompatible with the POTW. PSNS are analogous to NSPS for 
direct dischargers, and EPA generally considers the same factors for 
both sets of standards (see Section IV.B.6). The final rule establishes 
PSNS that are the same as the rule's NSPS.

[[Page 67842]]

C. Summary of Costs and Benefits

    Table III-1 summarizes the benefits and social costs for the final 
rule, at three percent and seven percent discount rates. EPA's analysis 
reflects the Agency's understanding of the actions steam electric power 
plants will take to meet the limitations and standards in the final 
rule. EPA based its analysis on a baseline that reflects the expected 
impacts of other environmental regulations affecting steam electric 
power plants, such as the Clean Power Plan (CPP) rule that the Agency 
finalized in July 2015 (as well as other relevant rules such as the 
Coal Combustion Residuals (CCR) rule that the Agency promulgated in 
April 2015). EPA understands that these modeled results have 
uncertainty due to the possibility of unexpected implementation 
approaches and thus that the actual costs could be somewhat higher or 
lower than estimated. The current estimate reflects the best data and 
analysis available at this time. In this preamble, EPA presents costs 
and monetized benefits accounting for these other rules.\9\ Under this 
final rule, EPA estimates that about 12 percent of steam electric power 
plants and 28 percent of coal-fired or petroleum coke-fired power 
plants will incur some costs.\10\ For additional information, see 
Sections V and IX.
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    \10\ EPA estimates that the population of steam electric power 
plants is about 1080.

                  Table III-1--Total Monetized Annualized Benefits and Costs of the Final Rule
                                                [Millions; 2013$]
----------------------------------------------------------------------------------------------------------------
                                               Total monetized social benefits         Total social costs
                Discount rate                -------------------------------------------------------------------
                                                     3%               7%               3%               7%
----------------------------------------------------------------------------------------------------------------
Final Rule..................................    $451 to $566     $387 to $478             $480             $471
----------------------------------------------------------------------------------------------------------------

    The remainder of this preamble is structured as follows. Section IV 
provides additional background on the CWA and the ELG program. Section 
V outlines key updates since the proposal, including updates to the 
industry profile, estimated costs and economic impacts, and pollutant 
data. Section VI gives an overview of the industry, and Section VII 
reviews the identification and selection of the regulated pollutants. 
Section VIII describes the final rule requirements, along with the 
bases for EPA's decisions. Section IX presents the costs and economic 
impacts, while Section X shows the accompanying pollutant reductions. 
Section XI presents the numeric limitations and standards for existing 
and new sources that are established in this final rule. Sections XII 
through XIV explain the non-water quality environmental impacts 
(including energy requirements), the environmental assessment, and the 
resulting benefits analysis. Section XV presents results of the cost-
effectiveness analysis, and Section XVI provides information regarding 
implementation of the rule.

IV. Background

A. Clean Water Act

    Congress passed the CWA to ``restore and maintain the chemical, 
physical, and biological integrity of the Nation's waters.'' 33 U.S.C. 
1251(a). In order to achieve this objective, the Act has, as a national 
goal, the elimination of the discharge of all pollutants into the 
nation's waters. 33 U.S.C. 1251(a)(1). The CWA establishes a 
comprehensive program for protecting our nation's waters. Among its 
core provisions, the CWA prohibits the discharge of pollutants from a 
point source to waters of the U.S., except as authorized under the CWA. 
Under section 402 of the CWA, 33 U.S.C. 1342, discharges may be 
authorized through a National Pollutant Discharge Elimination System 
(NPDES) permit. The CWA establishes a dual approach for these permits, 
technology-based controls that establish a floor of performance for all 
dischargers, and water quality-based effluent limitations, where the 
technology-based effluent limitations are insufficient to meet 
applicable WQS. To serve as the basis for the technology-based 
controls, the CWA authorizes EPA to establish national technology-based 
effluent limitations guidelines and new source performance standards 
for discharges from categories of point sources (such as industrial, 
commercial, and public sources) that occur directly into waters of the 
U.S.
    The CWA also authorizes EPA to promulgate nationally applicable 
pretreatment standards that control pollutant discharges from sources 
that discharge wastewater indirectly to waters of the U.S., through 
sewers flowing to POTWs, as outlined in sections 307(b) and (c) of the 
CWA, 33 U.S.C. 1317(b) and (c). EPA establishes national pretreatment 
standards for those pollutants in wastewater from indirect dischargers 
that pass through, interfere with, or are otherwise incompatible with 
POTW operations. Generally, pretreatment standards are designed to 
ensure that wastewaters from direct and indirect industrial dischargers 
are subject to similar levels of treatment. See CWA section 301(b), 33 
U.S.C. 1311(b). In addition, POTWs are required to implement local 
treatment limits applicable to their industrial indirect dischargers to 
satisfy any local requirements. See 40 CFR 403.5.
    Direct dischargers (those discharging directly to surface waters) 
must comply with effluent limitations in NPDES permits. Indirect 
dischargers, who discharge through POTWs, must comply with pretreatment 
standards. Technology-based effluent limitations and standards in NPDES 
permits are derived from effluent limitations guidelines (CWA sections 
301 and 304, 33 U.S.C. 1311 and 1314) and new source performance 
standards (CWA section 306, 33 U.S.C. 1316) promulgated by EPA, or 
based on best professional judgment (BPJ) where EPA has not promulgated 
an applicable effluent limitation guideline or new source performance 
standard (CWA section 402(a)(1)(B), 33 U.S.C. 1342(a)(1)(B)). 
Additional limitations are also required in the permit where necessary 
to meet WQS. CWA section 301(b)(1)(C), 33 U.S.C. 1311(b)(1)(C). The 
ELGs are established by EPA regulation for categories of industrial 
dischargers and are based on the degree of control that can be achieved 
using various levels of pollution control technology, as specified in 
the Act (e.g., BPT, BCT, BAT; see below).
    EPA promulgates national ELGs for major industrial categories for 
three classes of pollutants: (1) Conventional pollutants (TSS, oil and 
grease, biochemical oxygen demand (BOD5), fecal coliform, 
and pH), as outlined in

[[Page 67843]]

CWA section 304(a)(4) and 40 CFR 401.16; (2) toxic pollutants (e.g., 
toxic metals such as arsenic, mercury, selenium, and chromium; toxic 
organic pollutants such as benzene, benzo-a-pyrene, phenol, and 
naphthalene), as outlined in CWA section 307(a), 33 U.S.C. 1317(a); 40 
CFR 401.15 and 40 CFR part 423, appendix A; and (3) nonconventional 
pollutants, which are those pollutants that are not categorized as 
conventional or toxic (e.g., ammonia-N, phosphorus, and TDS).

B. Effluent Guidelines Program

    EPA establishes ELGs based on the performance of well-designed and 
well-operated control and treatment technologies. The legislative 
history of CWA section 304(b), which is the heart of the effluent 
guidelines program, describes the need to press toward higher levels of 
control through research and development of new processes, 
modifications, replacement of obsolete plants and processes, and other 
improvements in technology, taking into account the cost of controls. 
Congress has also stated that EPA need not consider water quality 
impacts on individual water bodies as the guidelines are developed; see 
Statement of Senator Muskie (principal author) (October 4, 1972), 
reprinted in Legislative History of the Water Pollution Control Act 
Amendments of 1972, at 170. (U.S. Senate, Committee on Public Works, 
Serial No. 93-1, January 1973).
    There are four types of standards applicable to direct dischargers, 
and two types of standards applicable to indirect dischargers, 
described in detail below.
1. Best Practicable Control Technology Currently Available
    Traditionally, EPA establishes effluent limitations based on BPT by 
reference to the average of the best performances of facilities within 
the industry, grouped to reflect various ages, sizes, processes, or 
other common characteristics. EPA can promulgate BPT effluent 
limitations for conventional, toxic, and nonconventional pollutants. In 
specifying BPT, EPA looks at a number of factors. EPA first considers 
the cost of achieving effluent reductions in relation to the effluent 
reduction benefits. The Agency also considers the age of equipment and 
facilities, the processes employed, engineering aspects of the control 
technologies, any required process changes, non-water quality 
environmental impacts (including energy requirements), and such other 
factors as the Administrator deems appropriate. See CWA section 
304(b)(1)(B), 33 U.S.C. 1314(b)(1)(B). If, however, existing 
performance is uniformly inadequate, EPA may establish limitations 
based on higher levels of control than what is currently in place in an 
industrial category, when based on an Agency determination that the 
technology is available in another category or subcategory and can be 
practically applied.
2. Best Conventional Pollutant Control Technology
    The 1977 amendments to the CWA require EPA to identify additional 
levels of effluent reduction for conventional pollutants associated 
with Best Conventional Pollutant Control Technology (BCT) for 
discharges from existing industrial point sources. In addition to other 
factors specified in section 304(b)(4)(B), 33 U.S.C. 1314(b)(4)(B), the 
CWA requires that EPA establish BCT limitations after consideration of 
a two-part ``cost reasonableness'' test. EPA explained its methodology 
for the development of BCT limitations on July 9, 1986 (51 FR 24974). 
Section 304(a)(4) designates the following as conventional pollutants: 
BOD5, TSS, fecal coliform, pH, and any additional pollutants 
defined by the Administrator as conventional. The Administrator 
designated oil and grease as a conventional pollutant on July 30, 1979 
(44 FR 44501; 40 CFR 401.16).
3. Best Available Technology Economically Achievable
    BAT represents the second level of stringency for controlling 
direct discharges of toxic and nonconventional pollutants. As the 
statutory phrase intends, EPA considers the technological availability 
and the economic achievability in determining what level of control 
represents BAT. CWA section 301(b)(2)(A), 33 U.S.C. 1311(b)(2)(A). 
Other statutory factors that EPA considers in assessing BAT are the 
cost of achieving BAT effluent reductions, the age of equipment and 
facilities involved, the process employed, potential process changes, 
non-water quality environmental impacts (including energy 
requirements), and such other factors as the Administrator deems 
appropriate. The Agency retains considerable discretion in assigning 
the weight to be accorded these factors. Weyerhaeuser Co. v. Costle, 
590 F.2d 1011, 1045 (D.C. Cir. 1978). Generally, EPA determines 
economic achievability based on the effect of the cost of compliance 
with BAT limitations on overall industry and subcategory (if 
applicable) financial conditions. BAT is intended to reflect the 
highest performance in the industry, and it may reflect a higher level 
of performance than is currently being achieved based on technology 
transferred from a different subcategory or category, bench scale or 
pilot studies, or foreign plants. Am. Paper Inst. v. Train, 543 F.2d 
328, 353 (D.C. Cir. 1976); Am. Frozen Food Inst. v. Train, 539 F.2d 
107, 132 (D.C. Cir. 1976). BAT may be based upon process changes or 
internal controls, even when these technologies are not common industry 
practice. See Am. Frozen Food Inst., 539 F.2d at 132, 140; Reynolds 
Metals Co. v. EPA, 760 F.2d 549, 562 (4th Cir. 1985); Cal. & Hawaiian 
Sugar Co. v. EPA, 553 F.2d 280, 285-88 (2nd Cir. 1977).
4. Best Available Demonstrated Control Technology/New Source 
Performance Standards
    NSPS reflect ``the greatest degree of effluent reduction'' that is 
achievable based on the ``best available demonstrated control 
technology'' (BADCT), ``including, where practicable, a standard 
permitting no discharge of pollutants.'' CWA section 306(a)(1), 33 
U.S.C. 1316(a)(1). Owners of new facilities have the opportunity to 
install the best and most efficient production processes and wastewater 
treatment technologies. As a result, NSPS generally represent the most 
stringent controls attainable through the application of BADCT for all 
pollutants (that is, conventional, nonconventional, and toxic 
pollutants). In establishing NSPS, EPA is directed to take into 
consideration the cost of achieving the effluent reduction and any non-
water quality environmental impacts and energy requirements. CWA 
section 306(b)(1)(B), 33 U.S.C. 1316(b)(1)(B).
5. Pretreatment Standards for Existing Sources
    Section 307(b) of the CWA, 33 U.S.C. 1317(b), authorizes EPA to 
promulgate pretreatment standards for discharges of pollutants to 
POTWs. PSES are designed to prevent the discharge of pollutants that 
pass through, interfere with, or are otherwise incompatible with the 
operation of POTWs. Categorical pretreatment standards are technology-
based and are analogous to BPT and BAT effluent limitations guidelines, 
and thus the Agency typically considers the same factors in 
promulgating PSES as it considers in promulgating BAT. Congress 
intended for the combination of pretreatment and treatment by the POTW 
to achieve the level of treatment that would be required if the 
industrial source were making a direct discharge. Conf. Rep. No. 95-
830, at 87 (1977), reprinted in U.S. Congress. Senate Committee on 
Public Works (1978), A

[[Page 67844]]

Legislative History of the CWA of 1977, Serial No. 95-14 at 271 (1978). 
The General Pretreatment Regulations, which set forth the framework for 
the implementation of categorical pretreatment standards, are found at 
40 CFR part 403. These regulations establish pretreatment standards 
that apply to all non-domestic dischargers. See 52 FR 1586 (January 14, 
1987).
6. Pretreatment Standards for New Sources
    Section 307(c) of the CWA, 33 U.S.C. 1317(c), authorizes EPA to 
promulgate PSNS at the same time it promulgates NSPS. As is the case 
for PSES, PSNS are designed to prevent the discharge of any pollutant 
into a POTW that interferes with, passes through, or is otherwise 
incompatible with the POTW. In selecting the PSNS technology basis, the 
Agency generally considers the same factors it considers in 
establishing NSPS, along with the results of a pass-through analysis. 
Like new sources of direct discharges, new sources of indirect 
discharges have the opportunity to incorporate into their operations 
the best available demonstrated technologies. As a result, EPA 
typically promulgates pretreatment standards for new sources based on 
best available demonstrated control technology for new sources. See 
Nat'l Ass'n of Metal Finishers v. EPA, 719 F.2d 624, 634 (3rd Cir. 
1983).

C. Steam Electric Effluent Guidelines Rulemaking History

    EPA provided a detailed history of the steam electric ELGs in the 
preamble for the proposed rule, including an explanation of why EPA 
initiated a steam electric ELG rulemaking following a detailed study in 
2009. EPA published the proposed rule on June 7, 2013, and took public 
comments until September 20, 2013. 78 FR 34432. During the public 
comment period, EPA received over 200,000 comments. EPA also held a 
public hearing on July 9, 2013.

V. Key Updates Since Proposal

    This section discusses key updates since EPA proposed its rule in 
June 2013, including how these updates are reflected in the final rule.

A. Industry Profile Changes Due to Retirements and Conversions

    For the final rule, EPA adjusted the population of steam electric 
power plants that will likely incur costs and the associated benefits 
as a result of this final rule based on company announcements, as of 
August 2014, regarding changes in plant operations. The steam electric 
industry is a dynamic one, influenced by many factors, including 
electricity demand, fuel prices, availability of resources, and 
regulation. Since proposal, there have been some important changes in 
the overall industry profile. Some companies have retired or announced 
plans to retire specific steam electric generating units, as well as 
converted or announced plans to convert specific units to a different 
fuel source. See DCN SE05069 for information on the data sources for 
these announced retirements and conversions. In addition to actual or 
announced retirements and fuel conversions, in some cases, plants have 
altered, or announced plans to alter, their wastewater treatment or ash 
handling practices. To the extent possible, EPA adjusted its analyses 
of costs, pollutant loadings, non-water quality environmental impacts, 
and benefits for the final rule to account for these actual and 
anticipated changes. The final rule accounts for plant retirements and 
fuel conversions, as well as changes in plants' ash handling and 
wastewater treatment practices, expected to occur by the implementation 
dates in the final rule. For more details, see TDD Section 4.5 or 
``Changes to Industry Profile for Steam Electric Generating Units for 
the Steam Electric Effluent Guidelines Final Rule,'' DCN SE05059.

B. EPA Consideration of Other Federal Rules

    EPA made every effort to appropriately account for other rules in 
its many analyses for this rule. Since proposal, EPA has promulgated 
other rules affecting the steam electric industry: the Cooling Water 
Intake Structures (CWIS) rule for existing facilities (79 FR 48300; 
Aug. 15, 2014), the CCR rule (80 FR 21302; Apr. 17, 2015), the CPP rule 
(see http://www2.epa.gov/cleanpowerplan/clean-power-plan-existing-power-plants), and the Carbon Pollution Standard for New Power Plants 
(CPS) rule (see http://www2.epa.gov/cleanpowerplan/carbon-pollution-standards-new-modified-and-reconstructed-power-plants). One result of 
taking into account these rules is a change in the population of units 
and plants that EPA estimates would incur incremental costs, as well as 
additional estimated benefits, under this final rule. In some cases, 
EPA performed two sets of parallel analyses to demonstrate how the 
other rules affected this final rule. For example, EPA conducted an 
assessment of compliance costs and pollutant loadings for this rule 
both with and without accounting for the CCR rule (this preamble only 
presents results accounting for the CCR rule). Then, using results from 
the analyses of costs and loadings accounting for the CCR rule, EPA 
also conducted an additional set of analyses of compliance costs and 
pollutant loadings accounting for the proposed CPP rule (this preamble 
only presents results accounting for the proposed CPP rule). At the 
time EPA conducted its analyses, the CPP had not yet been finalized, 
and thus EPA used the proposed CPP for its analyses. EPA concluded that 
the proposed and final CPP specifications are similar enough that using 
the proposed rather than the final CPP will not bias the results of the 
analysis for this rule. See Section IX for additional information. 
Because EPA used the proposal as a proxy for the final rule, the rest 
of the preamble simply refers to the CPP rule. Given that final CPP 
state plans have not yet been determined, EPA recognizes that the 
modeled results have uncertainty due to the possibility of unexpected 
implementation approaches and that actual market responses may be 
somewhat more or less pronounced than estimated. The current estimate 
reflects the best data and analysis available at this time. For more 
information on these federal rules, see TDD Section 1.3.3. For more 
information on how EPA accounted for the effect of these rules on its 
compliance cost, pollutant loadings estimates, and non-water quality 
environmental impacts, see TDD Sections 9, 10, and 12. See Section V.D. 
and Section IX, below, and the RIA regarding how EPA considered other 
federal rules in its economic impact analysis.

C. Advancements in Technologies

    There have been advancements in several technologies since proposal 
that reinforce EPA's decision regarding those technologies that serve 
as the appropriate basis for the final rule. For proposal, EPA 
evaluated a variety of technologies available to control and treat 
wastewater generated by the steam electric industry. The final rule is 
based on several treatment technologies discussed in depth at proposal. 
As explained then, and further discussed in Section VIII, the record 
demonstrates that the technologies that form the basis for the final 
rule are available. Moreover, the record indicates that, based on the 
emerging market for treatment technologies, plants will have many 
options to choose from when deciding how to meet the requirements of 
the final rule.
    The biological treatment technology that serves as part of the 
basis for the final requirements for FGD wastewater

[[Page 67845]]

discharged from existing sources has been tested at power plants for 
more than ten years and demonstrated in full-scale systems for more 
than seven years. As this technology has matured, new vendors have 
emerged to provide expertise in applying it to steam electric power 
plants. In addition, other advanced technologies that plants may use to 
achieve the effluent limitations and standards for FGD wastewater in 
the final rule are now entering the marketplace, such as lower-cost 
biological treatment systems that utilize a modular-based bioreactor, 
which is prefabricated and can be delivered directly to the site. 
Another advancement related to evaporation and crystallization 
technology, operating at low temperatures to crystallize dissolved 
solids, requires no chemical treatment of the wastewater and generates 
no additional sludge for disposal, resulting in a simpler and more 
economical application for treatment of both FGD wastewater and 
gasification wastewater. Another development concerning the evaporation 
system (which is the basis for the BAT limitations for FGD wastewater 
in the voluntary incentives program, as well as the basis for the NSPS 
for FGD wastewater) is a process that generates a pozzolanic material 
instead of crystallized salts as a solid waste product of the treatment 
system; although the pozzolanic material is expected to require 
landfill disposal since it likely would not be a marketable material, 
the capital and operating cost of the overall evaporation treatment 
process would be reduced.
    Zero valent iron (ZVI) cementation, sorption media, ion exchange, 
and electrocoagulation are also examples of emerging treatment 
technologies that are being developed to treat FGD wastewater, and they 
could be used to achieve the limitations in the final rule. See TDD 
Section 7 for a more detailed discussion.
    The technologies used as the basis for the final requirements for 
ash transport water (dry handling and closed-loop systems) have been in 
operation at power plants for more than 20 years and are amply 
demonstrated by the record supporting the final rule. Recent 
advancements related to bottom ash handling technologies have focused 
on providing more flexible retrofit solutions and improving the thermal 
efficiency of the boiler operation. These advancements result in 
additional savings related to electricity use, operation and 
maintenance, water costs, and thermal energy recovery.
    In sum, the record demonstrates that there have been significant 
advancements in relevant treatment technologies since proposal, and EPA 
expects that the advancements will continue as this rule is implemented 
by the industry.

D. Engineering Costs

    For the final rule, EPA updated its cost estimates to account for 
public comments. The following list summarizes the main adjustments EPA 
made to its cost estimates for the final rule:
     Adjustment of population of generating units and changes 
in wastewater treatment or ash handling practices to account for 
company-announced generating unit retirements/repowerings and 
conversions of ash handling systems (see Section IV.A);
     Adjustment of population of generating units and changes 
in wastewater treatment or ash handling practices to account for 
implementation of the CCR rule and CPP rule (see Section IV.B);
     Adjustments to the direct capital costs factors to better 
reflect all associated installation costs;
     Adjustments to the indirect capital cost factors to 
account for appropriate engineering and contingency costs;
     Adjustment to plant population receiving one-time bottom 
ash management costs;
     Addition of costs for denitrification pretreatment prior 
to biological treatment of FGD wastewater (for certain plants);
     Updates to costing inputs to account for costs of 
additional redundancy for the fly ash dry handling system;
     Addition of tank rental costs for surge capacity during 
certain bottom ash handling system maintenance;
     Addition of building costs for certain bottom ash and FGD 
wastewater systems; and
     Addition of costs for equipment that can be used to 
mitigate high oxidation-reduction potential (ORP) levels in FGD 
wastewater.
    See Section 9 of the TDD for additional information on the plant-
specific compliance cost estimates for the final rule.

E. Economic Impact Analysis

    For its analysis of the economic impact of the final rule, EPA 
began with the same financial data sources for steam electric power 
plants and their parent companies that were used and described in the 
proposed rule, primarily collected through the Questionnaire for the 
Steam Electric Power Generating Effluent Guidelines (industry survey) 
\11\ and public sources. Since proposal, EPA updated some of the 
analysis input data obtained from public sources to reflect the most 
current information about the economic/financial conditions in, and the 
regulatory environment of, the electric power industry, as well as data 
on electricity prices and electricity consumption. Thus, EPA updated 
its analysis to use the most current publicly available data from the 
following sources: The Department of Energy's Energy Information 
Administration (EIA) (in particular, the EIA 860, 861, and 906/920/923 
databases),\12\ the U.S. Small Business Administration (SBA), the 
Bureau of Labor Statistics (BLS), and the Bureau of Economic Analysis 
(BEA). As was the case for the proposed rule, EPA performed an analysis 
using the Integrated Planning Model (IPM), a comprehensive electricity 
market optimization model that can evaluate impacts within the context 
of regional and national electricity markets. For the final rule, EPA 
used an updated IPM base case (v5.13) that incorporates improvements 
and data updates to the previous version (v.4.10), notably regarding 
electricity demand forecast, generating capacity, market conditions, 
and newly promulgated environmental regulations also affecting this 
industry (see Section IX).
---------------------------------------------------------------------------

    \11\ For details on the industry survey, see TDD Section 3 and 
78 FR 34432; June 7, 2013).
    \12\ EIA-860: Annual Electric Generator Report; EIA-861: Annual 
Electric Power Industry Database; EIA-923: Utility, Non-Utility, and 
Combined Heat & Power Plant Database (monthly). The most current EIA 
data at the time of the analysis was for the year 2012.
---------------------------------------------------------------------------

F. Pollutant Data

    For the final rule, EPA incorporated data submitted by public 
commenters in its effluent limitations and standards development, 
pollutants of concern identification, and pollutant loadings estimates. 
Such data include:
     Industry-submitted data representing the FGD purge, FGD 
chemical precipitation effluent, and FGD biological treatment effluent 
for the plants identified as operating BAT systems;
     Industry-submitted ash transport water characterization 
and source water data; \13\
---------------------------------------------------------------------------

    \13\ Industry also submitted bottom ash transport water data 
approximately 14 months after the close of the public comment 
period. EPA did not incorporate these late data into its analyses, 
but it did perform a sensitivity analysis to determine how these 
late data might have impacted EPA's analyses and decisions. EPA 
concluded from the sensitivity analysis that the late bottom ash 
transport water data would not have changed EPA's ultimate decisions 
for this final rule. See DCN SE05581.

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

[[Page 67846]]

     Industry-submitted ash impoundment effluent 
concentrations; and
     Industry-submitted pilot-test data related to treatment of 
FGD wastewater.
    EPA subjected the new data to its data quality acceptance criteria 
and, as appropriate, updated its analyses accordingly. See TDD Section 
3 for additional information on the data sources used in the 
development of the final rule.

G. Environmental Assessment Models

    Although not required to do so, EPA conducted an Environmental 
Assessment for the final rule, as it did for the proposed rule. EPA 
updated the environmental assessment in several ways to respond to 
public comments, and improve the characterization of the environmental 
and human health improvements associated with the final rule. EPA 
performed dynamic water quality modeling of selected case-study 
locations to supplement the results of the national-scale Immediate 
Receiving Water (IRW) model. EPA supplemented the wildlife analysis by 
developing and using an ecological risk model that predicts the risk of 
reproductive impacts among fish and birds with dietary exposure to 
selenium from steam electric power plant wastewater discharges. EPA 
also updated and improved several input parameters for the IRW model, 
including fish consumption rates for recreational and subsistence 
fishers, the bioconcentration factor for copper, and benchmarks for 
assessing the potential for impacts to benthic communities in receiving 
waters. See Section XIII.A for additional discussion.

VI. Industry Description

A. General Description of Industry

    EPA provided a general description of the steam electric industry 
in the proposed rule and provides a complete discussion of the industry 
in TDD Section 4. As described in TDD Section 4.5 (and Section V.A, 
above), EPA considered retirements, fuel conversions, ash handling 
conversions, wastewater treatment updates, and other industry profile 
changes in the development of the final rule and supporting technical 
analyses; however, the data presented in the general industry 
description represents 2009 conditions, as the industry survey (See TDD 
Section 3) remains the best available source of information for 
characterizing operations across the industry.

B. Steam Electric Process Wastewater and Control Technologies

    While almost all steam electric power plants generate certain 
wastewater, like cooling water and boiler blowdown, the presence of 
other wastestreams depends on the type of fuel burned. Coal- and 
petroleum coke-fired generating units, and to a lesser degree oil-fired 
generating units, generate a flue gas stream that contains large 
quantities of particulate matter, sulfur dioxide, and nitrogen oxides, 
which would be emitted to the atmosphere if they were not cleaned from 
the flue gas prior to emission. Therefore, many of these generating 
units are outfitted with air pollution control systems (e.g., 
particulate removal systems, FGD systems, nitrogen oxide 
(NOX)-removal systems, and mercury control systems). Gas-
fired generating units generate fewer emissions of particulate matter, 
sulfur dioxide, and nitrogen oxides than coal- or oil-fired generating 
units, and therefore do not typically operate air pollution control 
systems to control emissions from their flue gas. In addition, coal-, 
oil-, and petroleum coke-fired generating units create fly and/or 
bottom ash as a result of coal combustion. The wastewaters associated 
with ash transport and air pollution control systems contain large 
quantities of metals (e.g., arsenic, mercury, and selenium).
    See TDD Sections 4, 6, and 7 for details on these systems, the 
wastewaters they generate, the number of facilities that operate the 
systems and generate wastewater, and the control technologies used for 
wastewater treatment prior to discharge.
1. FGD Wastewater
    FGD systems are used to remove sulfur dioxide from the flue gas so 
that it is not emitted into the air. Dry FGD systems spray a sorbent 
slurry into a reactor vessel so that the droplets dry as they contact 
the hot flue gas. Although dry FGD scrubbers use water in their 
operation, the water in most systems evaporates and they generally do 
not discharge wastewater. Wet FGD systems contact the sorbent slurry 
with flue gas in a reactor vessel producing a wastewater stream.
    Treatment technologies for FGD wastewater include chemical 
precipitation, biological treatment, and evaporation. At some plants, 
this wastewater is handled in surface impoundments, constructed 
wetlands, or through practices achieving zero discharge. As described 
above in Section V.C and TDD section 7, EPA identified other 
technologies that have been evaluated or are being developed to treat 
FGD wastewater, including iron cementation, ZVI cementation, reverse 
osmosis, absorption or adsorption media, ion exchange, and 
electrocoagulation.
2. Fly Ash Transport Water
    Plants use particulate removal systems to collect fly ash and other 
particulates from the flue gas in hoppers located underneath the 
equipment. Of the coal-, petroleum coke-, and oil-fired steam electric 
power plants that generate fly ash, most of them transport fly ash 
pneumatically from the hoppers to temporary storage silos, thereby not 
generating any transport water. Some plants, however, use water to 
transport (sluice) the fly ash from the hoppers to a surface 
impoundment. The water used to transport the fly ash to the surface 
impoundment is usually discharged to surface water as overflow from the 
impoundment after the fly ash has settled to the bottom.
3. Bottom Ash Transport Water
    Bottom ash consists of heavier ash particles that are not entrained 
in the flue gas and fall to the bottom of the furnace. In most 
furnaces, the hot bottom ash is quenched in a water-filled hopper. For 
purposes of this rule, boiler slag is considered bottom ash. Boiler 
slag is the molten bottom ash collected at the base of the furnace that 
is quenched with water. Most plants use water to transport (sluice) the 
bottom ash from the hopper to an impoundment or dewatering bins. The 
ash sent to a dewatering bin is separated from the transport water and 
then disposed. For both of these systems, the water used to transport 
the bottom ash to the impoundment or dewatering bins is usually 
discharged to surface water as overflow from the systems, after the 
bottom ash has settled to the bottom.
    Of the coal-, petroleum coke-, and oil-fired steam electric power 
plants that generate bottom ash, most operate wet sluicing handling 
systems. There are two types of bottom ash handling technologies that 
can meet zero discharge requirements: (1) Dry handling technologies 
that do not use any water, including systems such as dry vacuum or 
pressure systems, dry mechanical conveyor systems, and vibratory belt 
systems; and (2) wet systems that do not generate or discharge ash 
transport water, including mechanical drag systems (MDS), remote MDS, 
and complete-recycle systems.
4. FGMC Wastewater
    FGMC systems remove mercury from the flue gas, so that it is not 
emitted into

[[Page 67847]]

the air. There are two types of systems used to control flue gas 
mercury emissions: (1) Addition of oxidizing agents to the coal prior 
to combustion; and (2) injection of activated carbon into the flue gas 
after combustion. Addition of oxidizing agents to the coal prior to 
combustion does not generate a new wastewater stream; it can, however, 
increase the mercury concentration in the FGD wastewater because the 
oxidized mercury is more easily removed by the FGD system. Injection of 
activated carbon into the flue gas does have the potential to generate 
a new wastestream at a plant, depending on the location of the 
injection. If the injection occurs upstream of the primary particulate 
removal system, then the mercury-containing carbon (FGMC waste) is 
collected and handled the same way as, and together with, the fly ash. 
Therefore, if the fly ash is wet sluiced, then the FGMC wastes are also 
wet sluiced and likely sent to the same surface impoundment. In this 
case, adding the FGMC waste to the fly ash can increase the amount of 
mercury in the fly ash transport water. If the injection occurs 
downstream of the primary particulate removal system, the plant will 
need a secondary particulate removal system (typically a fabric filter) 
to capture the FGMC wastes.
    Of the current or planned activated carbon injection systems, most 
operate upstream injection. However, plants that wish to market their 
fly ash will typically inject the activated carbon downstream of the 
primary particulate removal system to prevent contaminating the fly ash 
with carbon. For plants operating downstream injection, the FGMC 
wastes, which would be collected with some carry-over fly ash, could be 
handled separately from fly ash in either a wet or dry handling system.
5. Combustion Residual Leachate From Landfills and Surface Impoundments
    Combustion residuals comprise a variety of wastes from the 
combustion process, which are generally collected by or generated from 
air pollution control technologies. These combustion residuals can be 
stored at the plant in on-site landfills or surface impoundments. 
Leachate includes liquid, including any suspended or dissolved 
constituents in the liquid, that has percolated through or drained from 
waste or other materials placed in a landfill, or that passes through 
the containment structure (e.g., bottom, dikes, berms) of a surface 
impoundment. Based on data from the industry survey, most landfills and 
some impoundments have a system to collect the leachate.
    In a lined landfill or impoundment, the combustion residual 
leachate collected in the liner is typically transported to an 
impoundment (e.g., collection pond). Some plants discharge the effluent 
from these impoundments containing combustion residual leachate 
directly to receiving waters, while other plants first send the 
impoundment effluent to another impoundment handling the ash transport 
water or other treatment system (e.g., constructed wetlands) prior to 
discharge. Unlined impoundments and landfills usually do not collect 
leachate, which would allow the leachate to potentially migrate to 
nearby ground waters, drinking water wells, or surface waters.
    Using data from the industry survey and site visits, surface 
impoundments are the most widely used systems to treat combustion 
residual leachate. EPA also identified different management practices, 
with approximately one-third of plants collecting the combustion 
residual leachate from impoundments and recycling it back to the 
impoundment from which it was collected. Some plants use their 
collected leachate as water for moisture conditioning of dry fly ash 
prior to disposal or for dust control around dry unloading areas and 
landfills.
6. Gasification Wastewater
    Integrated Gasification Combined Cycle (IGCC) plants use a carbon-
based feedstock (e.g., coal or petroleum coke) and subject it to high 
temperature and pressure to produce a synthetic gas (syngas), which is 
used as the fuel for a combined cycle generating unit. After the syngas 
is produced, it undergoes cleaning prior to combustion. The wastewater 
generated by these cleaning processes, along with any condensate 
generated in flash tanks, slag handling water, or wastewater generated 
from the production of sulfuric acid, is referred to as ``grey water'' 
or ``sour water,'' and is generally treated prior to reuse or 
discharge.
    EPA is aware of three plants that operate IGCC units in the U.S. 
All three plants currently treat their gasification wastewater with 
vapor-compression evaporation systems. One of these plants also 
includes a cyanide destruction stage as part of the treatment system.

VII. Selection of Regulated Pollutants

A. Identifying the Pollutants of Concern

    In determining which pollutants warrant regulation in this rule, 
EPA first evaluated the wastewater characteristics to identify 
pollutants of concern (POCs). Constituents present in steam electric 
power plant wastewater are primarily derived from the parent carbon 
feedstock (e.g., coal, petroleum coke). EPA characterized the 
wastewater generated by the industry and identified POCs (those 
pollutants commonly found) for each of the regulated wastestreams. For 
wastestreams where the final rule establishes numeric effluent 
limitations or standards, the POCs are those pollutants that have been 
quantified in a wastestream at sufficient frequency at treatable levels 
(concentrations). For wastestreams where EPA is establishing zero 
discharge limitations or standards, the POCs identified for each 
wastestream are those pollutants that are confirmed to be present at 
sufficient frequency in untreated wastewater samples of that 
wastestream. In both cases, in response to public comments, where EPA 
had available paired source water (intake water) data for a particular 
pollutant in an untreated process wastewater sample, EPA compared the 
two to confirm that the concentration in the untreated process 
wastewater sample exceeded that of the source water. See TDD Section 
6.6 for details on EPA's analysis of POCs.

B. Selection of Pollutants for Regulation Under BAT/NSPS

    For wastestreams where the final rule establishes numeric effluent 
limitations or standards, effluent limitations or standards for all 
POCs are not necessary to ensure that the pollutants are adequately 
controlled because many of the pollutants originate from similar 
sources, have similar treatability, and are removed by similar 
mechanisms. Because of this, it is sufficient to establish effluent 
limitations or standards for one or more indicator pollutants, which 
will ensure the removal of other POCs. For wastestreams where the final 
rule establishes zero discharge limitations or standards, all POCs are 
directly regulated.
    For wastestreams where the final rule establishes numeric effluent 
limitations or standards, EPA selected a subset of pollutants as 
indicators for all regulated pollutants upon consideration of the 
following factors:
     EPA did not set limitations or standards for pollutants 
associated with treatment system additives because regulating these 
pollutants could interfere with efforts to optimize treatment system 
operation.
     EPA did not set limitations or standards for pollutants 
for which the treatment technology was ineffective

[[Page 67848]]

(e.g., pollutant concentrations remained approximately unchanged or 
increased across the treatment system).
     EPA did not set limitations or standards for pollutants 
that are adequately controlled through the regulation of another 
indicator pollutant because they have similar properties and are 
treated by similar mechanisms as a regulated pollutant.
    See TDD Section 11 for additional detail on EPA's analysis and 
rationale for selecting the regulated pollutants.

C. Methodology for the POTW Pass-Through Analysis (PSES/PSNS)

    Before establishing PSES/PSNS for a pollutant, EPA examines whether 
the pollutant ``passes through'' a POTW to waters of the U.S. or 
interferes with the POTW operation or sludge disposal practices. In 
determining whether a pollutant passes through POTWs for these 
purposes, EPA generally compares the percentage of a pollutant removed 
by well-operated POTWs performing secondary treatment to the percentage 
removed by the BAT/NSPS technology basis. A pollutant is determined to 
pass through POTWs when the median percentage removed nationwide by 
well-operated POTWs is less than the median percentage removed by the 
BAT/NSPS technology basis. Pretreatment standards are established for 
those pollutants regulated under BAT/NSPS that pass through POTWs.
    Under this rule, for those wastestreams regulated with a zero 
discharge limitation or standard, EPA set the percentage removed by the 
technology basis at 100 percent. Because a POTW would not be able to 
achieve 100 percent removal of wastewater pollutants, it is appropriate 
to set PSES at zero discharge, otherwise pollutants would pass through 
the POTW.
    For wastestreams for which the final rule establishes numeric 
limitations and standards, EPA determined the pollutant percentage 
removed by the rule's technology basis using the same data sources used 
to determine the long-term averages for each set of limitations and 
standards (see TDD Section 13). As it has done for other rulemakings, 
EPA determined the nationwide percentage removed by well-operated POTWs 
performing secondary treatment using one of two data sources:
     Fate of Priority Pollutants in Publicly Owned Treatment 
Works, September 1982, EPA 440/1-82/303 (50 POTW Study); or
     National Risk Management Research Laboratory Treatability 
Database, Version 5.0, February 2004 (formerly called the Risk 
Reduction Engineering Laboratory database).
    With a few exceptions, EPA performs a POTW pass-through analysis 
for pollutants selected for regulation for BAT/NSPS for each 
wastestream of concern. The exception is for conventional pollutants 
such as BOD5, TSS, and oil and grease. POTWs are designed to 
treat these conventional pollutants; therefore, they are not considered 
to pass through.
    Section VIII, below, summarizes the results of the pass-through 
analysis. EPA found that all of the pollutants considered for 
regulation under BAT/NSPS pass through and, therefore, also selected 
them for regulation under PSES/PSNS. For a more detailed discussion of 
how EPA performed its pass-through analysis, see TDD Section 11.

VIII. The Final Rule

A. BPT

    The final rule does not revise the previously established BPT 
effluent limitations because the rule regulates the same wastestreams 
at the more stringent BAT/NSPS level of control. The rule does, 
however, make certain structural modifications to the BPT regulations 
in light of new and revised definitions. In particular, the final rule 
establishes separate definitions for FGD wastewater, FGMC wastewater, 
gasification wastewater, and combustion residual leachate, making clear 
that these four wastestreams are no longer considered low volume waste 
sources. Given these new and revised definitions, the final rule 
modifies the structure of the previously established BPT regulations so 
that they specifically identify these four wastestreams, but without 
changing their applicable BPT limitations, which are equal to those for 
low volume waste sources.

B. BAT/NSPS/PSES/PSNS Options

    EPA analyzed many regulatory options at proposal, the details of 
which were discussed fully in the document published on June 7, 2013 
(78 FR 34432). EPA proposed to regulate pollutants found in seven 
wastestreams found at steam electric power plants, each based on 
particular control technologies. Depending on the interests 
represented, public commenters supported virtually all of the 
regulatory options that EPA proposed--from the least stringent to the 
most stringent, and many options in between. For this final rule, based 
on public comments, EPA also considered a few additional regulatory 
options. None of these additional regulatory options involve regulation 
of different pollutants or wastestreams, or the application of 
different control technologies, than those explicitly considered and 
presented at proposal. Rather, they involve slight variations on the 
overall packaging of the key options presented at proposal. Thus, in 
developing this final rule, EPA named six main regulatory options, 
Options A, B, C, D, E, and F.\14\ Table VIII-1 summarizes these six 
regulatory options. In general, as one moves from Option A to Option F, 
there is a greater estimated reduction in pollutant discharges from 
steam electric power plants and a higher associated cost.
---------------------------------------------------------------------------

    \14\ Option B is equivalent to Proposed Option 3, Option C is 
equivalent to Proposed Option 4a, Option E is equivalent to Proposed 
Option 4, and Option F is equivalent to Proposed Option 5. Option A 
is a slight variant of Proposed Options 1 and 3 and Option D is a 
slight variant of Proposed Option 4.
---------------------------------------------------------------------------

    The following paragraphs describe the six options (Options A 
through F), by wastestream, including the technology bases for the 
requirements associated with each.

                                            TABLE VIII-1--Final Rule: Steam Electric Main Regulatory Options
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Technology basis for the main BAT/NSPS/PSES/PSNS regulatory options
          Wastestreams           -----------------------------------------------------------------------------------------------------------------------
                                           A                   B                   C                   D                   E                   F
--------------------------------------------------------------------------------------------------------------------------------------------------------
FGD Wastewater..................  Chemical            Chemical            Chemical            Chemical            Chemical            Evaporation.
                                   Precipitation.      Precipitation +     Precipitation +     Precipitation +     Precipitation +
                                                       Biological          Biological          Biological          Biological
                                                       Treatment.          Treatment.          Treatment.          Treatment.
Fly Ash Transport Water.........  Dry handling......  Dry handling......  Dry handling......  Dry handling......  Dry handling......  Dry handling.

[[Page 67849]]

 
Bottom Ash Transport Water......  Impoundment (Equal  Impoundment (Equal  Dry handling/       Dry handling/       Dry handling/       Dry handling/
                                   to BPT).            to BPT).            Closed loop (for    Closed loop.        Closed loop.        Closed loop.
                                                                           units >400 MW);
                                                                           Impoundment
                                                                           (Equal to
                                                                           BPT)(for units
                                                                           <=400 MW).
FGMC Wastewater.................  Dry handling......  Dry handling......  Dry handling......  Dry handling......  Dry handling......  Dry handling.
Gasification Wastewater.........  Evaporation.......  Evaporation.......  Evaporation.......  Evaporation.......  Evaporation.......  Evaporation.
Combustion Residual Leachate....  Impoundment (Equal  Impoundment (Equal  Impoundment (Equal  Impoundment (Equal  Chemical            Chemical
                                   to BPT).            to BPT).            to BPT).            to BPT).            Precipitation.      Precipitation.
Nonchemical Metal Cleaning        [Reserved]........  [Reserved]........  [Reserved]........  [Reserved]........  [Reserved]........  [Reserved].
 Wastes.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Consistent with the proposal, under all Options A through F, for 
oil-fired generating units and small generating units (50 MW or 
smaller) that are existing sources, the rule would establish BAT/PSES 
effluent limitations and standards on TSS in fly ash transport water, 
bottom ash transport water, FGD wastewater, FGMC wastewater, combustion 
residual leachate, and gasification wastewater equal to the previously 
promulgated BPT effluent limitations on TSS \15\ in fly ash transport 
water, bottom ash transport water, and low volume waste sources, where 
applicable. Under Options A through E, EPA would establish a voluntary 
incentives program for plants that choose to meet BAT limitations for 
FGD wastewater based on evaporation technology, as described in Section 
VIII.C.13. Moreover, as EPA proposed, under all Options A through F, 
the rule would establish an anti-circumvention provision designed to 
ensure that the purpose of the rule is achieved, as further described 
below, in Section VIII.G. Finally, as EPA proposed, under all Options A 
through F, the rule would correct a typographical error in the 
previously promulgated regulations, as well as make certain clarifying 
revisions to the applicability provision of the regulations, as further 
described below, in Section VIII.H.
---------------------------------------------------------------------------

    \15\ Although TSS is a conventional pollutant, whenever EPA 
would be regulating TSS in this final rule, it would be regulating 
it as an indicator pollutant for the particulate form of toxic 
metals.
---------------------------------------------------------------------------

1. FGD Wastewater
    Under Option A, EPA would establish effluent limitations and 
standards for mercury and arsenic in FGD wastewater based on treatment 
using chemical precipitation. Under Options B through E, EPA would 
establish effluent limitations and standards for mercury, arsenic, 
selenium, and nitrate/nitrite as N in FGD wastewater based on treatment 
using chemical precipitation (as under Option A) followed by biological 
treatment. Under Option F, EPA would establish effluent limitations and 
standards for mercury, arsenic, selenium, and TDS in FGD wastewater 
based on treatment using an evaporation system. Under all options, to 
facilitate implementation of the new BAT/NSPS/PSES/PSNS requirements, 
EPA would also promulgate a definition for FGD wastewater, making clear 
it would no longer be considered a low volume waste source.
2. Fly Ash Transport Water
    Under all Options A through F, EPA would establish (or in the case 
of NSPS/PSNS, maintain) zero discharge effluent limitations and 
standards for pollutants in fly ash transport water based on use of a 
dry handling system.
3. Bottom Ash Transport Water
    Under Options A and B, EPA would establish effluent limitations and 
standards for bottom ash transport water equal to the previously 
promulgated BPT limitation on TSS, which is based on the use of a 
surface impoundment. Under Options D, E, and F, EPA would establish 
zero discharge effluent limitations and standards for pollutants in 
bottom ash transport water based on one of two technologies: A dry 
handling system or a closed-loop system. Under Option C, EPA would 
establish, for bottom ash transport water, zero discharge limitations 
and standards based on dry handling or closed-loop systems only for 
generating units with a nameplate capacity of more than 400 MW. Units 
with a nameplate capacity equal to or less than 400 MW would have to 
meet new effluent limitations and standards equal to the previously 
established BPT limitation on TSS, based on surface impoundments.
4. FGMC Wastewater
    Under all Options A through F, EPA would establish zero discharge 
effluent limitations and standards for FGMC wastewater based on use of 
a dry handling system. Under all Options A through F, EPA would 
establish a separate definition for FGMC wastewater, making clear it 
would no longer be considered a low volume waste source.
5. Gasification Wastewater
    The technology basis for control of gasification wastewater under 
all Options A through F is an evaporation system. Under these options, 
EPA would establish limitations and standards on arsenic, mercury, 
selenium, and TDS in gasification wastewater. Under all Options A 
through F, EPA would establish a separate definition for gasification 
wastewater, making clear it would no longer be considered a low volume 
waste source.
6. Combustion Residual Leachate
    Under Options A through D, EPA would establish effluent limitations 
and standards for combustion residual leachate equal to the previously 
promulgated BPT limitation on TSS for low volume waste sources. Under 
Options E and F, EPA would establish additional limitations and 
standards for arsenic and mercury in combustion residual leachate based 
on treatment using a chemical precipitation system (the same technology 
basis for control of FGD wastewater under Option A). Under all Options 
A through F, EPA would establish a separate definition for combustion 
residual leachate, making

[[Page 67850]]

clear it would no longer be considered a low volume waste source.
7. Non-Chemical Metal Cleaning Wastes
    Under all Options A through F, EPA would continue to reserve BAT/
NSPS/PSES/PSNS for non-chemical metal cleaning wastes, as the 
previously established regulations do.

C. Best Available Technology

    After considering the technologies described in this preamble and 
Section 7 of the TDD, as well as public comments, and in light of the 
factors specified in CWA sections 304(b)(2)(B) and 301(b)(2)(A) (see 
Section IV.B.3), EPA decided to establish BAT effluent limitations 
based on the technologies described in Option D. Thus, for BAT, the 
final rule establishes: (1) Limitations on arsenic, mercury, selenium, 
and nitrate/nitrite as N in FGD wastewater, based on chemical 
precipitation plus biological treatment; \16\ (2) a zero discharge 
limitation for pollutants in fly ash transport water, based on dry 
handling; (3) a zero discharge limitation for pollutants in bottom ash 
transport water, based on dry handling or closed-loop systems; (4) a 
zero discharge limitation on all pollutants in FGMC wastewater, based 
on dry handling; (5) limitations on mercury, arsenic, selenium, and TDS 
in gasification wastewater, based on evaporation; \17\ and (6) a 
limitation on TSS in combustion residual leachate, based on surface 
impoundments.\18\ The final rule also establishes new definitions for 
FGD wastewater, FGMC wastewater, gasification wastewater, and 
combustion residual leachate.
---------------------------------------------------------------------------

    \16\ For those plants that choose to participate in the 
voluntary incentives program, the applicable limitations are for 
arsenic, mercury, selenium, and TDS in FGD wastewater, based on the 
use of an evaporation system (see Section VIII.C.13).
    \17\ For small (50 MW or less) generating units and oil-fired 
generating units, the final rule establishes different BAT 
limitations for FGD wastewater, fly ash transport water, bottom ash 
transport water, FGMC wastewater, and gasification wastewater (see 
Section VIII.C.12).
    \18\ The final rule also establishes BAT limitations on TSS in 
discharges of ``legacy wastewater,'' which are equal to previously 
established TSS limitations. See Section VIII.C.8.
---------------------------------------------------------------------------

1. FGD Wastewater
    This rule identifies treatment using chemical precipitation 
followed by biological treatment as the BAT technology basis for 
control of pollutants discharged in FGD wastewater. More specifically, 
the technology basis for BAT is a chemical precipitation system that 
employs hydroxide precipitation, sulfide precipitation (organosulfide), 
and iron coprecipitation, followed by an anoxic/anaerobic fixed-film 
biological treatment system designed to remove heavy metals, selenium, 
and nitrates.\19\ After accounting for industry changes described in 
Section V, forty-five percent of all steam electric power plants with 
wet scrubbers have equipment or processes in place able to meet the 
final BAT/PSES effluent limitations and standards.\20\ Many of these 
plants use FGD wastewater management approaches that eliminate the 
discharge of FGD wastewater.\21\ Other plants employ wastewater 
treatment technologies that reduce the amount of pollutants in the FGD 
wastestream. Both chemical precipitation and biological treatment are 
well-demonstrated technologies that are available to steam electric 
power plants for use in treating FGD wastewater. Based on industry 
survey responses, 39 U.S. steam electric power plants (44 percent of 
plants discharging FGD wastewater) use some form of chemical 
precipitation as part of their FGD wastewater treatment system. More 
than half of these plants (30 percent of plants discharging FGD 
wastewater) use both hydroxide and sulfide precipitation in the process 
to further reduce metals concentrations. In addition, chemical 
precipitation has been used at thousands of industrial facilities 
nationwide for the last several decades (see TDD Section 7).
---------------------------------------------------------------------------

    \19\ In estimating costs associated with this technology basis, 
EPA assumed that in order to meet the limitations and standards, 
certain plants with high FGD discharge flow rates (greater than or 
equal to 1,000 gpm) would elect to incorporate flow minimization 
into their operating practices (by reducing the FGD purge rate or 
recycling a portion of their FGD wastewater back to the FGD system), 
where the FGD system metallurgy can accommodate an increase in 
chlorides. See Section 4.5.4 of EPA's Incremental Costs and 
Pollutant Removals for the Final Effluent Limitations Guidelines and 
Standards for the Steam Electric Power Generating Point Source 
Category (DCNs SE05831 and SE05832).
    \20\ This value accounts for announced retirements, conversions, 
and changes plants are projected to make to comply with the CPP and 
CCR rules.
    \21\ A variety of approaches that depend on plant specific 
conditions are used to achieve zero pollutant discharge at these 
plants, including evaporation ponds, complete recycle, and processes 
that combine the FGD wastewater with other materials for landfill 
disposal. Although these technologies, as well as others currently 
used for achieve zero pollutant discharge, may be available for some 
plants with FGD wastewater, EPA determined they are not available 
nationally. For example, evaporation ponds are only available in 
certain climates. Similarly, complete recycle is only available at 
plants with appropriate FGD metallurgy.
---------------------------------------------------------------------------

    Biological treatment has been tested at power plants for more than 
ten years and full-scale systems have been operating at a subset of 
plants for seven years. It has been widely used in many industrial 
applications for decades, in both the U.S. and abroad, and it has been 
employed at coal mines. Currently, six U.S. steam electric power plants 
(approximately ten percent of those discharging FGD wastewater) use 
biological treatment designed to substantially reduce nitrogen 
compounds and selenium in their FGD wastewater. Other power plants are 
considering installing biological treatment to remove selenium, and at 
least one plant is scheduled to begin operating a biological treatment 
system for selenium removal soon. Four of the six plants using 
biological systems to treat their FGD wastewater precede the biological 
treatment stage with chemical precipitation; thus, the entire system is 
designed to remove suspended solids, particulate and dissolved metals 
(such as mercury and arsenic), soluble and insoluble forms of selenium, 
and nitrate and nitrite forms of nitrogen. These plants show that 
chemical precipitation followed by biological treatment is 
technologically available and demonstrated. The other two plants 
operating anoxic/anaerobic bioreactors to remove selenium precede the 
biological treatment stage with surface impoundments instead of 
chemical precipitation. The treatment systems at these two plants are 
likely to be less effective at removing metals (including many 
dissolved metals) and would likely face more operational problems than 
the plants employing chemical pretreatment, but they nevertheless show 
the efficacy and availability of biological treatment for removing 
selenium and nitrate/nitrite in FGD wastewater.
    A few commenters questioned the feasibility of biological treatment 
at some power plants. Specifically, they claimed, in part, that the 
efficacy of biological systems is unpredictable and is subject to 
temperature changes, high chloride concentrations, scaling, and high 
oxidation-reduction potential (ORP) in the absorber, which could kill 
the microorganisms in the bioreactor. EPA's record does not support 
these assertions for a well-designed and well-operated chemical 
precipitation and biological treatment system.
    EPA's record demonstrates that proper pretreatment prior to 
biological treatment and proper monitoring with adjustments to the 
treatment system as necessary are key to reducing operational concerns 
raised by commenters. Proper pretreatment includes chemical 
precipitation, which can address wastewater containing high oxidant 
loads through addition of a reducing agent in one of the treatment

[[Page 67851]]

system's reaction tanks.\22\ It also includes pretreatment of FGD 
wastewater containing exceptionally high levels of nitrates (e.g., 
greater than 100 ppm nitrate/nitrite as N) using standard 
denitrification technologies such as membrane bioreactors or stirred-
tank bioreactors. Moreover, recent pilot studies of biological 
treatment systems for FGD wastewater treatment, along with data for 
full-scale biological treatment systems, demonstrate that monitoring 
ORP, pH, and total oxidant load is essential for proper operation of 
these systems. Monitoring these parameters enables the plant to adjust 
the system as necessary. For example, plants that monitor ORP in the 
absorber or in the FGD purge will have sufficient advanced warning to 
respond to elevated ORP levels by adding a chemical reductant to the 
chemical precipitation system and/or increasing the feed rate of the 
nutrient mix in the biological reactor. EPA's cost estimates account 
for all of these pretreatment and monitoring steps. EPA's record, 
moreover, shows that the treatment systems that form the bases for the 
BAT limitations for FGD wastewater are able to effectively remove the 
regulated pollutants at varying influent concentrations. See DCN 
SE05733. Finally, as discussed in Section V.C, vendors continue to make 
improvements to these systems and to develop non-biological systems for 
selenium removal. For additional information on strategies to address 
potential operational concerns, see DCNs SE04208 and SE04222.
---------------------------------------------------------------------------

    \22\ EPA included the equipment for chemical addition of a 
reducing agent in its cost estimates for Options B through E.
---------------------------------------------------------------------------

    Some commenters also claimed that the efficacy of biological 
systems in removing selenium is subject to changes in switching from 
one coal type to another (also referred to as fuel flexing). Where EPA 
had biological treatment performance data paired with fuel type, EPA 
reviewed it and found that existing biological treatment systems 
continue to perform well during periods of fuel switching. See DCN 
SE05846. The data show that, in all cases except one, the plants met 
the selenium limitations following fuel switches. In one instance when 
a plant switched to a certain coal type, the plant exceeded the final 
daily maximum selenium limitation for one out of thirteen observations 
for the month while the average of all values for that month were below 
the final monthly selenium limitation. This plant was not subject to a 
selenium limit at the time data was collected. Moreover, EPA's record 
demonstrates that effective communication between the operator(s) of 
the generating unit and the boiler, as well as bench testing and 
monitoring the ORP, and making proper adjustments to the operation of 
the treatment system, would make it possible to prevent potential 
selenium exceedances at this plant. Data for two other plants operating 
full-scale biological treatment systems shows that fuel switches should 
not result in exceeding the effluent limitations. EPA also has data 
from a pilot project at another plant employing the same type of coal 
used by the one plant that experienced elevated selenium effluent 
concentrations following a coal switch. The data for this pilot project 
demonstrate effective selenium removal by the BAT technology basis, 
with all effluent values at concentrations below the BAT limitations 
established in this rule.
    EPA also reviewed effluent data in the record for plants operating 
combined chemical precipitation and biological treatment for FGD 
wastewater to evaluate how cycling operation (i.e., changes in 
electricity generation rate) and short or extended shutdown periods may 
affect the ability of plants to meet the BAT effluent limitations. 
These data demonstrate that cycling operations and shutdown periods, 
whether short or long in duration, are manageable and do not result in 
plants being unable to meet the ELG effluent limitations. See DCN 
SE05846.
    EPA did not select surface impoundments as the BAT technology basis 
for FGD wastewater because it would not result in reasonable further 
progress toward eliminating the discharge of all pollutants, 
particularly toxic pollutants (see CWA section 301(b)(2)(A)). Surface 
impoundments, which rely on gravity to remove particulates from 
wastewater, are the technology basis for the previously promulgated BPT 
effluent limitations for low volume waste sources. Pollutants that are 
present mostly in soluble (dissolved) form, such as selenium, boron, 
and magnesium, are not effectively and reliably removed by gravity in 
surface impoundments. For metals present in both soluble and 
particulate forms (such as mercury), gravity settling in surface 
impoundments does not effectively remove the dissolved fraction. 
Furthermore, the environment in some surface impoundments can create 
chemical conditions (e.g., low pH) that convert particulate forms of 
metals to soluble forms, which are not removed by the gravity settling 
process. Additionally, the Electric Power Research Institute (EPRI) has 
reported that adding FGD wastewater to surface impoundments used to 
treat ash transport water can reduce the settling efficiency in the 
impoundments due to gypsum particle dissolution, thus increasing the 
effluent TSS concentrations. Discharging wastewater containing elevated 
levels of TSS would likely result in also discharging other pollutants 
(e.g., metals) in higher concentrations. EPRI has also reported that 
FGD wastewater includes high loadings of volatile metals, which can 
increase the solubility of metals in surface impoundments, thereby 
leading to increased levels of dissolved metals and higher 
concentrations of metals in discharges from surface impoundments. 
Finally, as described in Section 8 of the TDD, surface impoundments are 
also subject to seasonal turnover, which adversely affects their 
efficacy. Seasonal turnover occurs when the impoundment's upper layer 
of water becomes cooler and denser, typically as the season changes 
from summer to fall. The cooler, upper layer of water then sinks and 
causes the entire volume of the impoundment to circulate, which can 
result in resuspension of solids that had settled to the bottom and a 
consequent increase in the concentrations of pollutants discharged from 
the impoundment.
    Chemical precipitation and biological treatment are more effective 
than surface impoundments at removing both soluble and particulate 
forms of metals, as well as other pollutants such as nitrogen compounds 
and TDS. Because many of the pollutants of concern in FGD wastewater 
are present in dissolved form and would not be removed by surface 
impoundments, and because of the relatively large mass loads of these 
pollutants (e.g., selenium, dissolved mercury) discharged in the FGD 
wastestream, EPA decided not to finalize BAT effluent limitations for 
FGD wastewater based on surface impoundments.
    EPA also rejected identifying chemical precipitation, alone, 
(Option A) as BAT for FGD wastewater because, while chemical 
precipitation systems are capable of achieving removals of various 
metals, the technology is not effective at removing selenium, nitrogen 
compounds, and certain metals that contribute to high concentrations of 
TDS in FGD wastewater. These pollutants of concern are discharged by 
steam electric power plants throughout the nation, causing adverse 
human health impacts and some of the most egregious environmental 
impacts (see Section XIII and EA). In light of this, and the fact that 
economically achievable technologies are available to

[[Page 67852]]

reduce these pollutants of concern, EPA determined that, by itself, 
chemical precipitation would not result in reasonable further progress 
toward the national goal of eliminating the discharge of all pollutants 
(see CWA section 301(b)(2)(A)), and rejected that technology basis as 
BAT in favor of chemical precipitation followed by anaerobic/anoxic 
biological treatment.
    EPA also decided not to establish, for all steam electric power 
plants, BAT limitations for FGD wastewater based on treatment using an 
evaporation system. In particular, this technology basis would employ a 
falling-film evaporator (also known as a brine concentrator) to produce 
a concentrated wastewater stream (brine) and a distillate stream.\23\ 
While evaporation systems are effective at removing boron and 
pollutants that contribute to high concentrations of TDS, EPA decided 
it would not be appropriate to identify evaporation as the BAT 
technology basis for FGD wastewater at all steam electric power plants 
because of the high cost of possible regulatory requirements based on 
evaporation for discharges of FGD wastewater at existing facilities. 
The annual cost to the industry of limitations based on evaporation 
would be more than 2 and \1/2\ times the cost to industry estimated for 
the final rule (after tax) (approximately $570 million more expensive 
than the final rule, on an annual basis, after tax). Given the high 
costs associated with the technology, and the fact that the steam 
electric industry is facing costs associated with several other rules 
in addition to this rule, EPA decided not to establish BAT limitations 
for FGD wastewater based on evaporation for all steam electric power 
plants. Nevertheless, as described further below, in Section VIII.C.13, 
the final rule does establish a voluntary incentives program under 
which steam electric power plants can choose to be subject to more 
stringent BAT limitations for FGD wastewater based on evaporation.
---------------------------------------------------------------------------

    \23\ This evaporation step would have been preceded by a 
chemical precipitation step using hydroxide precipitation, sulfide 
precipitation, and iron co-precipitation, as well as a softening 
step.
---------------------------------------------------------------------------

    Finally, EPA decided not to establish a requirement that would 
direct permitting authorities to establish limitations for FGD 
wastewater using site-specific BPJ. Public commenters representing 
industry, state, and environmental group interests urged EPA not to 
establish any requirement that would leave BAT effluent limitations for 
FGD wastewater to be determined on a BPJ basis. Sections 301 and 304 of 
the CWA require EPA to develop nationally applicable ELGs based on the 
best available technology economically achievable, taking certain 
factors into account. EPA decided that it would not be appropriate to 
leave FGD wastewater requirements in the final rule to be determined on 
a BPJ basis because there are sufficient data to set uniform, 
nationally applicable limitations on FGD wastewater at plants across 
the nation. Given this, BPJ permitting of FGD wastewater would place an 
unnecessary burden on permitting authorities, including state and local 
agencies, to conduct a complex technical analysis that they may not 
have the resources or expertise to complete. BPJ permitting of FGD 
wastewater would also unnecessarily burden the regulated industry 
because of associated delays and uncertainty with respect to permits.
2. Fly Ash Transport Water
    This rule identifies dry handling as the BAT technology basis for 
control of pollutants in fly ash transport water. Specifically, the 
technology basis for BAT is a dry vacuum system that employs a 
mechanical exhauster to pneumatically convey the fly ash (via a change 
in air pressure) from hoppers directly to a silo. Dry handling is 
clearly available to control the pollutants present in fly ash 
transport water. Today, the vast majority of steam electric power 
plants use dry handling techniques to manage fly ash, and by doing so 
avoid generating fly ash transport water. All new generating units 
built since the ELGs were last revised in 1982 have been subject to a 
zero discharge standard for pollutants in fly ash transport water. In 
addition, many owners and operators with generating units that are not 
subject to the previously established zero discharge NSPS for fly ash 
transport water have chosen to retrofit their units with dry fly ash 
handling technology to meet operational needs or for economic reasons. 
The trend in the industry is, moreover, toward the conversion and use 
of dry fly ash handling systems. See TDD Section 4.5. Based on data 
collected in the industry survey, EPA estimates that approximately 80 
percent of coal and petroleum coke-fired generating units operate dry 
fly ash handling systems. Since the survey, companies have continued to 
upgrade, or announce plans to upgrade, their ash handling systems at 
generating units. See TDD Section 4.5.
    Dry ash handling does not adversely affect plant operations or 
reliability, and it promotes the beneficial reuse of coal combustion 
residuals. In addition, converting to dry fly ash handling eliminates 
the need to treat fly ash transport water in a surface impoundment, and 
it reduces the amount of wastes entering surface impoundments and the 
risk and severity of structural failures and spills.
    EPA decided not to finalize a BAT limitation on fly ash transport 
water equal to the previously promulgated BPT limitation on TSS, based 
on the technology of surface impoundments, for the same reasons (where 
applicable) that EPA did not identify surface impoundments as BAT for 
FGD wastewater (see Section VIII.C.1).
3. Bottom Ash Transport Water
    This rule identifies dry handling or closed-loop systems as the BAT 
technology basis for control of pollutants in bottom ash transport 
water.\24\ More specifically, the first technology basis for BAT is a 
system in which bottom ash is collected in a water quench bath and a 
drag chain conveyor (mechanical drag system) then pulls the bottom ash 
out of the water bath on an incline to dewater the bottom ash. The 
second technology basis for BAT is a system in which the bottom ash is 
transported using the same processes as a wet-sluicing system, but 
instead of going to an impoundment, the bottom ash is sluiced to a 
remote mechanical drag system. Once there, a drag chain conveyor pulls 
the bottom ash out of the water on an incline to dewater the bottom 
ash, and the transport (sluice) water is then recycled back to the 
bottom ash collection system.
---------------------------------------------------------------------------

    \24\ EPA identified two technologies, a mechanical drag system 
or a remote mechanical drag system, as the BAT technology basis for 
bottom ash transport water because of potential space constraints at 
some plants' boilers.
---------------------------------------------------------------------------

    These technologies for control of bottom ash transport water are 
demonstrably available. Based on survey data, more than 80 percent of 
coal-fired generating units built in the last 20 years have installed 
dry bottom ash handling systems. In addition, EPA found that more than 
half of the entities that would be subject to BAT requirements for 
bottom ash transport water are already employing zero discharge 
technologies (dry handling or closed-loop wet ash handling) or planning 
to do so in the near future.
    Dry bottom ash handling does not adversely affect plant operations 
or reliability, and shifting to dry bottom ash handling offers certain 
benefits. As was the case for dry fly ash handling, shifting to dry 
bottom ash handling eliminates the need to send bottom ash transport 
water to a surface impoundment, and it reduces the

[[Page 67853]]

amount of waste entering surface impoundments and the risk and severity 
of structural failures and spills. Furthermore, one way companies may 
choose to comply with the final rule's requirements is to install a 
completely dry bottom ash system, which increases the energy efficiency 
of the boiler, thus reducing the amount of coal burned and associated 
emissions of carbon dioxide (CO2) and other pollutants per 
MW of electricity generated. On an annual basis, EPA calculated 
significant fuel savings and reduced air emissions from such systems, 
the value of which EPA estimates to be $41 million to $117 million per 
year.\25\ See DCN SE05980.
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    \25\ Neither these savings nor the fuel and emissions reductions 
have been incorporated into EPA's analyses for this final rule.
---------------------------------------------------------------------------

    EPA did not identify surface impoundments as BAT for bottom ash 
transport water for the same reasons (where applicable) that it did not 
identify surface impoundments as BAT for FGD wastewater (see Section 
VIII.C.1). Moreover, because the estimated overall cost of the rule has 
decreased since proposal (see Section IX), EPA also decided that 
establishing different bottom ash transport water limitations for 
generating units of and below a certain size (other than 50 MW, as 
described in Section VIII.C.12), as in Option C, was not warranted.
    At proposal and for the final rule, EPA considered an option that 
would have established differentiated bottom ash transport water 
requirements for units below 400 MW (Option C). Some public commenters 
stated that EPA's record does not support differentiated requirements 
for bottom ash transport water. They stated that BAT should be 
established at a level at which the costs are affordable to the 
industry as a whole, and that the cost to a unit in terms of dollars 
per amount of energy produced (in MW) is not a relevant factor. They 
cited EPA's record, which demonstrates that units of all sizes have 
installed dry handling and closed-loop systems, as well as EPA's 
economic achievability analysis, which does not show that units of 400 
MW or less are especially likely to shut down if faced with a zero 
discharge requirement. Other commenters supported EPA's consideration 
of the relative magnitude of costs per amount of energy produced for 
units below or equal to 400 MW, as compared to larger units, as well as 
differentiated bottom ash transport water requirements for these units.
    EPA reviewed its record and re-evaluated whether it would be 
appropriate to establish differentiated requirements for discharges of 
bottom ash transport water from existing sources based on unit size, in 
light of comments and the key changes since proposal discussed in 
Section V. Annualized cost per amount of energy produced increases 
along a smooth curve moving from the very largest units to the smallest 
units. See DCN SE05813. That, however, is expected due to economies of 
scale. There is no clear breaking point at which to establish a size 
threshold for purposes of differentiated requirements for bottom ash 
transport water.\26\ Furthermore, EPA collected information in the 
industry survey that found that units of all sizes, including those 
less than 400 MW, have installed dry handling and closed-loop systems. 
And, as further described below, EPA projects a net retirement of only 
843 MW under the final rule. This suggests that, as a group, units of 
400 MW or less do not face particularly unique hardships under the 
final rule with respect to the industry as a whole. For these reasons, 
the final rule does not establish differentiated bottom ash transport 
water requirements for units equal to or below 400 MW (or for units 
equal to or below any other size threshold, other than 50 MW, as 
explained in Section VIII.C.12).
---------------------------------------------------------------------------

    \26\ At the same time, costs per amount of energy produced do 
begin to increase very dramatically as one moves from units above 50 
MW to units that are equal to 50 MW and smaller, and thus for 
reasons described in Section VIII.C.12, the final rule establishes 
different requirements for units of 50 MW or less for several 
wastestreams, including bottom ash transport water.
---------------------------------------------------------------------------

4. FGMC Wastewater
    This rule identifies dry handling as the BAT technology basis for 
the control of pollutants in FGMC wastewater. More specifically, the 
technology basis for BAT is a dry vacuum system that employs a 
mechanical exhauster to convey the FGMC waste (via a change in air 
pressure) from hoppers directly to a silo. Dry handling of FGMC waste 
is available and well demonstrated in the industry; indeed, nearly all 
plants with FGMC systems use dry handling systems. Plants using sorbent 
injection systems (e.g., activated carbon injection) to reduce mercury 
emissions from the flue gas typically handle the spent sorbent in the 
same manner as their fly ash (see Section VI.B.4 and TDD Section 7.5). 
As of 2009, 92 percent of the industry generating FGMC waste uses dry 
handling to manage it. Only a few plants use wet systems to transport 
the spent sorbent to disposal in surface impoundments. Based on the 
industry survey, the plants using wet handling systems operate them as 
closed-loop systems and do not discharge FGMC wastewater, or they 
already have a dry handling system that is capable of achieving zero 
discharge. Under the zero discharge limitation, these plants could 
choose to continue to operate their wet systems as closed-loop systems, 
or they could convert to dry handling technologies by managing the fly 
ash and spent sorbent together in a retrofitted dry system (rather than 
an impoundment) or by installing dedicated dry handling equipment for 
the FGMC waste similar to the equipment used for fly ash.
    EPA decided that it would not be appropriate to establish BAT 
limitations for FGMC wastewater based on surface impoundments for the 
same reasons (where applicable) that it did not identify surface 
impoundments as BAT for FGD wastewater (see Section VIII.C.1).
5. Gasification Wastewater
    This rule identifies evaporation as the BAT technology basis for 
the control of pollutants in gasification wastewater. More 
specifically, the technology basis for BAT is an evaporation system 
using a falling-film evaporator (or brine concentrator) to produce a 
concentrated wastewater stream (brine) and a reusable distillate 
stream. This evaporation technology is available and well demonstrated 
in the industry for treatment of gasification wastewater. All three 
IGCC plants now operating in the U.S. (the only existing sources of 
gasification wastewater) use evaporation technology to treat their 
gasification wastewater.
    EPA did not identify surface impoundments as BAT for gasification 
wastewater for the same reasons (where applicable) that it did not 
identify surface impoundments as BAT for FGD wastewater (see Section 
VIII.C.1). In addition, one existing IGCC plant previously used a 
surface impoundment to treat its gasification wastewater, and the 
impoundment effluent repeatedly exceeded its NPDES permit effluent 
limitations necessary to meet applicable WQS. Because of the 
demonstrated inability of surface impoundments to remove the pollutants 
of concern, and given that current industry practice is treatment of 
gasification wastewater using evaporation, EPA concluded that surface 
impoundments do not represent BAT for gasification wastewater.
    EPA also considered including cyanide treatment as part of the 
technology basis for BAT (as well as NSPS, PSES, and PSNS) for 
gasification wastewater. EPA is aware that the Edwardsport IGCC plant, 
which began commercial operation in June 2013, includes cyanide 
destruction as one step

[[Page 67854]]

in the treatment process for gasification wastewater. EPA, however, 
does not currently have sufficient data with which to calculate 
possible ELGs for cyanide. Thus, EPA decided not to establish cyanide 
limitations or standards for gasification wastewater in this rule. This 
decision does not preclude permitting authorities from setting more 
stringent effluent limitations where necessary to meet WQS. In those 
cases, plants may elect to install additional treatment, like cyanide 
destruction, to meet water quality-based effluent limitations.
6. Combustion Residual Leachate
    EPA received public comments expressing concern that the proposed 
definition of combustion residual leachate would apply to contaminated 
stormwater. Although this was not the Agency's intention, for the final 
rule, EPA revised the definition to make it clear that contaminated 
stormwater does not fall within the final definition of combustion 
residual leachate. This rule identifies surface impoundments as the BAT 
technology basis for control of pollutants in combustion residual 
leachate. Based on surface impoundments, which relies on gravity to 
remove particulates, this rule establishes a BAT limitation on TSS in 
combustion residual leachate equal to the previously promulgated BPT 
limitation on TSS in low volume waste sources. Few steam electric power 
plants currently employ technologies other than surface impoundments 
for treatment of combustion residual leachate. Throughout the 
development of this rule, EPA considered whether technologies in place 
for treatment of other wastestreams at steam electric power plants and 
wastestreams generated by other industries, including chemical 
precipitation, could be used for combustion residual leachate. At 
proposal, noting the small amount of pollutants in combustion residual 
leachate relative to other significant wastestreams at steam electric 
power plants, and that this was an area ripe for innovation, EPA 
requested additional information related to cost, pollutant reduction, 
and effectiveness of chemical precipitation and alternative approaches 
to treat combustion residual leachate. Commenters did not provide 
information that EPA could use to establish BAT limitations. Thus, EPA 
decided not to finalize BAT limitations for combustion residual 
leachate based on chemical precipitation (Option E). The record 
demonstrates that the amount of pollutants collectively discharged in 
combustion residual leachate by steam electric power plants is a very 
small portion of the pollutants discharged collectively by all steam 
electric power plants (approximately 3 percent of baseline loadings, on 
a toxic-weighted basis). Given this, and the fact that this rule 
regulates the wastestreams representing the three largest sources of 
pollutants from steam electric power plants (including by setting a 
zero discharge standard for two out of the three wastestreams), EPA 
decided that this rule already represents reasonable further progress 
toward the CWA's goals. The final rule, therefore, establishes BAT 
limitations for combustion residual leachate equal to the BPT 
limitation on TSS for low volume waste sources.
7. Timing
    As part of the consideration of the technological availability and 
economic achievability of the BAT limitations in the rule, EPA 
considered the magnitude and complexity of process changes and new 
equipment installations that would be required at facilities to meet 
the rule's requirements. As described in greater detail in Section 
XVI.A.1, where BAT limitations in this rule are more stringent than 
previously established BPT limitations, those limitations do not apply 
until a date determined by the permitting authority that is as soon as 
possible beginning November 1, 2018 (approximately three years 
following promulgation of this rule), but that is also no later than 
December 31, 2023 (approximately eight years following promulgation).
    Consistent with the proposal and supported by many commenters, the 
final rule takes this approach in order to provide the time that many 
facilities need to raise capital, plan and design systems, procure 
equipment, and construct and then test systems. It also allows for 
consideration of plant changes being made in response to other Agency 
rules affecting the steam electric industry (see Section V.B). 
Moreover, it enables facilities to take advantage of planned shutdown 
or maintenance periods to install new pollution control 
technologies.\27\ EPA's decision is also designed to allow, more 
broadly, for the coordination of generating unit outages in order to 
maintain grid reliability and prevent any potential impacts on 
electricity availability, something that public commenters urged EPA to 
consider. In addition, as requested by industry and states, this final 
rule and preamble clarify how the ``as soon as possible date'' is 
determined and implemented for steam electric power plants. The final 
rule specifies the factors that the permitting authority must consider 
in determining the ``as soon as possible'' date, and Section XVI.A.1 
provides guidance on implementation with respect to timing. In 
addition, the rule includes a ``no later than'' date of December 31, 
2023, for implementation because, as public commenters pointed out, 
without such a date, implementation could be substantially delayed, and 
a firm ``no later than'' date creates a more level playing field across 
the industry. EPA's economic analysis assumes prompt renewal of permits 
(no permits will be administratively continued) and, thus, that the 
requirements of the rule will be fully implemented by 2023. While some 
commenters requested that EPA give permitting authorities the ability 
to extend the implementation period beyond December 31, 2023, in light 
of public comments received on the proposal, and the fact that plants 
can reasonably be expected to meet the new ELGs by December 31, 2023, 
this timeframe is appropriate given the CWA's pollutant discharge 
elimination goals (see CWA section 101(a)).
---------------------------------------------------------------------------

    \27\ EPA's record demonstrates that plants typically have one or 
two planned shut-downs annually and that the length of these 
shutdowns is more than adequate to complete installation of relevant 
treatment and control technologies.
---------------------------------------------------------------------------

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

[[Page 67855]]

surface impoundments containing legacy wastewater.
    EPA also decided not to establish BAT limitations for legacy 
wastewater based on a technology other than surface impoundments 
(chemical precipitation, chemical precipitation plus biological 
treatment, evaporation) because it does not have the data to do so. 
Data are not available because of the way that legacy wastewater is 
currently handled at plants.
    The vast majority of plants combine some of their legacy wastewater 
with each other and with other wastestreams, including cooling water, 
coal pile runoff, metal cleaning wastes, and low volume waste sources 
in surface impoundments.\28\ Once combined in surface impoundments, the 
legacy wastewater no longer has the same characteristics that it did 
when it was first generated. For example, the addition of cooling water 
can dilute legacy wastewater to a point where the pollutants are no 
longer present at treatable levels. Additionally, some wastestreams 
have significant variations in flow, such as metal cleaning wastes, 
which are generally infrequently generated, or coal pile runoff, which 
is generated during precipitation events. Because surface impoundments 
are typically open, with no cover, they also receive direct 
precipitation. As a result of all of this, the characteristics of 
legacy wastewater contained in surface impoundments (flow rate and 
pollutant concentrations) vary at both any given plant, as well as 
across plants nationwide. Furthermore, EPA generally would like to have 
enough performance data at a well-designed, well-operated plant or 
plants to derive limitations and standards using its well-established 
and judicially upheld statistical methodology. In this case, except in 
limited circumstances, plants do not treat the legacy wastewater that 
they send to an impoundment using anything beyond the surface 
impoundment itself.\29\ Thus, the final rule establishes BAT 
limitations for legacy wastewater equal to the previously promulgated 
BPT limitations on TSS in discharges of fly ash transport water, bottom 
ash transport water, and low volume waste sources.
---------------------------------------------------------------------------

    \28\ For example, there are 65 plants for which EPA estimated 
FGD wastewater compliance costs and that use an impoundment as part 
of their treatment system. For 54 of the 65 plants (83 percent), the 
FGD wastewater is commingled with, at least, fly and/or bottom ash 
transport water, and for another eight of the 65 plants (12 
percent), the FGD wastewater is commingled with non-ash wastewater, 
such as cooling tower blowdown or low volume waste sources. DCN 
SE05875.
    \29\ For example, no plant uses biological treatment or 
evaporation to treat its legacy fly ash transport water or legacy 
bottom ash transport water contained in an impoundment, including 
any impoundment that may contain only legacy fly ash transport water 
or only legacy bottom ash transport water. Although EPA identified 
fewer than ten plants that use chemical precipitation to treat 
wastewater that contains, among other things, ash transport water, 
EPA does not have any data to characterize the effluent from these 
systems. Thus, no steam electric industry data exist to establish 
BAT limitations for possible ``fly ash-only'' impoundments or 
``bottom ash-only'' impoundments based on these technologies.
---------------------------------------------------------------------------

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

    \31\ IPM is a comprehensive electricity market optimization 
model that can evaluate such impacts within the context of regional 
and national electricity markets. See Section IX for additional 
discussion.
    \32\ Given the design of IPM, unit-level and thereby plant-level 
projections are presented as an indicator of overall regulatory 
impact rather than a precise prediction of future unit-level or 
plant-specific compliance actions.
---------------------------------------------------------------------------

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

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

    The final BAT effluent limitations have acceptable non-water 
quality

[[Page 67856]]

environmental impacts, including energy requirements. Section XII 
describes in more detail EPA's analysis of non-water quality 
environmental impacts and energy requirements. EPA estimates that by 
year 2023, under the final rule and reflecting full compliance, energy 
consumption increases by less than 0.01 percent of the total 
electricity generated by power plants. EPA also estimates that the 
amount of fuel consumed by increased operation of motor vehicles (e.g., 
for transporting fly ash) increases by approximately 0.002 percent of 
total fuel consumption by all motor vehicles.
    EPA also evaluated the effect of the BAT effluent limitations on 
air emissions generated by all electric power plants (NOX, 
sulfur oxides (SOX), and CO2), solid waste 
generation, and water usage. Under the final rule, NOX 
emissions are projected to decrease by 1.16 percent, SOX 
emissions are projected to increase by 0.04 percent, and CO2 
emissions are projected to decrease by 0.106 percent due to changes in 
the mix of electricity generation (e.g., less electricity from coal-
fired steam electric generating units and more electricity from natural 
gas-fired steam electric generating units). Moreover, solid waste 
generation is projected to increase by less than 0.001 percent of total 
solid waste generated by all electric power plants. Finally, EPA 
estimates that the final rule has a positive impact on water 
withdrawal, with steam electric power plants reducing the amount of 
water they withdraw by 57 billion gallons per year (155 million gallons 
per day).
11. Impacts on Residential Electricity Prices and Low-Income and 
Minority Populations
    EPA examined the effects of the final rule on consumers as an 
additional factor that might be appropriate when considering what level 
of control represents BAT. If all annualized compliance costs were 
passed on to residential consumers of electricity, instead of being 
borne by the operators and owners of power plants (a very conservative 
assumption), the average monthly increase in electricity bill for a 
typical household would be no more than $0.12 under the final rule.
    EPA also considered the effect of the rule on minority and low-
income populations. As explained in Section XVII.J, using demographic 
data regarding who resides closest to steam electric power plant 
discharges and who consumes the most fish from waters receiving power 
plant discharges, EPA concluded that low-income and minority 
populations benefit to an even greater degree than the general 
population from the reductions in discharges associated with the final 
rule.
12. Existing Oil-Fired and Small Generating Units
    EPA considered whether subcategorization of the ELGs was warranted 
based on the factors specified in CWA section 304(b)(2)(B) (see Section 
IV.B.3 and TDD Section 5). Ultimately, EPA concluded that it would be 
appropriate to set different limitations for existing small generating 
units (50 MW or less) and existing oil-fired generating units. No 
other, different requirements were warranted for this rule under the 
factors considered.
    Oil-Fired Generating Units. For oil-fired generating units, the 
final rule establishes BAT effluent limitations for FGD wastewater, fly 
ash transport water, bottom ash transport water, FGMC wastewater, and 
gasification wastewater equal to previously established BPT limitations 
on TSS in fly ash transport water, bottom ash transport water, and low 
volume waste sources. As defined in the rule, oil-fired generating 
units refer to those that use oil as either the primary or secondary 
fuel and do not burn coal or petroleum coke. Units that use only oil 
during startup or for flame stabilization are not considered oil-fired 
generating units.
    EPA decided to finalize these limitations for oil-fired generating 
units because EPA's record demonstrates that, in comparison to coal- 
and petroleum coke-fired units, oil-fired units generate substantially 
fewer pollutants, are generally older and operate less frequently, and 
in many cases are more susceptible to early retirement when faced with 
compliance costs attributable to the final rule.
    The amount of ash generated by oil-fired units is a small fraction 
of the amount produced by coal-fired units. Coal-fired units generate 
hundreds to thousands of tons of ash each day, with some plants 
generating more than 2,000 tons per day of ash. In contrast, oil-fired 
units generate less than ten tons of ash per day. This disparity is 
also apparent when comparing the ash tonnage to the amount of power 
generated, with coal-fired units producing nearly 1,800 times more ash 
than oil-fired units (0.6 tons per MW-hour on average for coal units; 
0.000319 tons per MW-hour on average for oil units). The amount of 
pollutants discharged to surface waters is roughly correlated to the 
amount of ash wastewater discharged; thus, oil-fired generating units 
discharge substantially fewer pollutants to surface waters than coal-
fired units, even when generating the same amount of electricity. EPA 
estimates that the amount of pollutants discharged collectively by all 
oil-fired generating units is a very small portion of the pollutants 
discharged collectively by all steam electric power plants (less than 
one percent, on a toxic-weighted basis).
    Oil-fired generating units are generally among the oldest steam 
electric units in the industry. Eighty-seven percent of the units are 
more than 25 years old. In fact, more than a quarter of the units began 
operation more than 50 years ago. Based on responses to the industry 
survey, fewer than 20 oil-fired generating units discharged fly ash or 
bottom ash transport water in 2009. This is likely because only about 
20 percent of oil-fired generating units operate as baseload units; the 
rest are either cycling/intermediate units (about 45 percent) or 
peaking units (about 35 percent). These units also have notably low 
capacity utilization. While about 30 percent of the baseload units 
report capacity utilization greater than 75 percent, almost half report 
a capacity utilization of less than 25 percent. Eighty percent of the 
cycling/intermediate units and all peaking units also report capacity 
utilization less than 25 percent. Thirty-five percent of oil-fired 
generating units operated for more than six months in 2009; nearly half 
of the units operated for fewer than 30 days.
    While these older and generally intermittently operated oil-fired 
generating units are capable of installing and operating the treatment 
technologies that form the bases for this rule, and the costs would be 
affordable for most plants, EPA concludes that, due to the factors 
described here, companies may choose to shut down these oil-fired units 
instead of making new investments to comply with the rule. If these 
units shut down, EPA is concerned about resulting reductions in the 
flexibility that grid operators have during peak demand due to less 
reserve generating capacity to draw upon. But, more importantly, 
maintaining a diverse fleet of generating units that includes a variety 
of fuel sources is important to the nation's energy security. Because 
the supply/delivery network for oil is different from other fuel 
sources, maintaining the existence of oil-fired generating units helps 
ensure reliable electric power generation, as commenters confirmed. EPA 
considered these potential impacts on electric grid reliability and the 
nation's energy security, under CWA section 304(b)(2)(B), in its 
decision to establish

[[Page 67857]]

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


[[Page 67858]]


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

    \34\ Properly operated evaporation systems are also capable of 
achieving the BAT limitations based on chemical precipitation plus 
biological treatment.
---------------------------------------------------------------------------

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

[[Page 67859]]

of meeting the limitations based on evaporation.
---------------------------------------------------------------------------

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

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

D. Best Available Demonstrated Control Technology/NSPS

    After considering all of the technologies described in this 
preamble and TDD Section 7, as well as public comments, and in light of 
the factors specified in CWA section 306 (see Section IV.B.4), EPA 
concluded that the technologies described in Option F represent BADCT 
for steam electric power plants, and the final rule promulgates NSPS 
based on that option. Thus, the final NSPS establish: (1) Standards on 
arsenic, mercury, selenium, and TDS in FGD wastewater, based on 
evaporation (same basis as for BAT limitations in voluntary incentives 
program); (2) a zero discharge standard on all pollutants in bottom ash 
transport water, based on dry handling or closed-loop systems (same 
bases as for BAT limitations); (3) a zero discharge standard on all 
pollutants in FGMC wastewater, based on dry handling (same basis as for 
BAT limitations); (4) standards on mercury, arsenic, selenium, and TDS 
in gasification wastewater, based on evaporation technology (same basis 
as for BAT limitations); and (5) standards on mercury and arsenic in 
discharges of combustion residual leachate, based on chemical 
precipitation (more specifically, the technology basis is a chemical 
precipitation system that employs hydroxide precipitation, sulfide 
precipitation, and iron coprecipitation to remove heavy metals). The 
final rule also maintains the previously established zero discharge 
NSPS on discharges of fly ash transport water, based on dry handling.
    The record indicates that the technologies that serve as the bases 
for the final NSPS are well demonstrated based on the performance of 
plants using the technologies. For example, new steam electric power 
generating sources have been meeting the previously established zero 
discharge standard for fly ash transport water since 1982, 
predominantly through the use of dry handling technologies. Moreover, 
as described in Section VIII.C.13, three plants in the U.S. and four 
plants in Italy use evaporation technology to treat their FGD 
wastewater, and another U.S. plant is in the process of installing such 
technology for that purpose. Of the approximately 50 coal-fired 
generating units that were built within the last 20 years, most (83 
percent) manage their bottom ash without using water to transport the 
ash and, as a result, do not discharge bottom ash transport water. The 
technology basis identified as BAT technology for gasification 
wastewater represents current industry practice. Every IGCC power plant 
currently in operation uses evaporation to treat their gasification 
wastewater, even when the wastewater is not discharged and is instead 
reused at the plant. In the case of FGMC wastewater, every plant 
currently using post-combustion sorbent injection (e.g., activated 
carbon injection) either handles the captured spent sorbent with a dry 
process or manages the FGMC wastewater so that it is not discharged to 
surface waters (or has the capability to do so). For combustion 
residual leachate, chemical precipitation is a well-demonstrated 
technology for removing metals and other pollutants from a variety of 
industrial wastewaters, including leachate from landfills not located 
at power plants. Chemical precipitation is also well demonstrated at 
steam electric power plants for treatment of FGD wastewater that 
contains the pollutants in combustion residual leachate.
    The NSPS in the final rule pose no barrier to entry. The cost to 
install technologies at new units is typically less than the cost to 
retrofit existing units. For example, the cost differential between 
Options B, C, and D for existing sources is mostly associated with 
retrofitting controls for bottom ash handling systems. For new sources, 
however, NSPS based on Option F do not present plants with the same 
choice of retrofit versus modification of existing processes. This is 
because every new generating unit must install some type of bottom ash 
handling system as the unit is constructed. Establishing a zero 
discharge standard for all pollutants in bottom ash transport water as 
part of the NSPS means that power plants will install a dry bottom ash 
handling system during construction instead of installing a wet-
sluicing system.
    Moreover, EPA assessed the possible impacts of the final NSPS on 
new sources by comparing the incremental costs of the Option F 
technologies to the costs of hypothetical new generating units. EPA is 
not able to predict which plants might construct new units or the exact 
characteristics of such units. Instead, EPA calculated and analyzed 
compliance costs for a variety of plant and unit configurations. EPA 
developed NSPS compliance costs for new sources using a methodology 
similar to the one used to develop compliance costs for existing 
sources. EPA's estimates for compliance costs for new sources are based 
on the net difference in costs between wastewater treatment system 
technologies that would likely have been implemented at new sources 
under the previously established regulatory requirements, and those 
that would likely be implemented under the final rule. EPA estimated 
that the incremental compliance costs for a new generating unit 
(capital and O&M) represent approximately 3.3 percent of the annualized 
cost of building and operating a new 1,300 MW coal-fired plant, with 
capital costs representing 0.3 to 2.8 percent of the overnight 
construction costs, and annual O&M costs representing 0.3 to 3.9 
percent of the fuel and other O&M cost of operating a new plant.
    Finally, EPA analyzed the non-water quality environmental impacts 
and energy requirements associated with Option F for both existing and 
new sources. See DCN SE05952 and DCN SE05951. Since there is nothing 
inherently different between an existing and new source, EPA's analysis 
with respect to existing sources is instructive. Using both of these 
analyses, EPA determined that NSPS based on the Option F technologies 
have acceptable non-water quality environmental impacts and energy 
requirements.
    In contrast to the BAT effluent limitations, this rule establishes 
the same NSPS for oil-fired generating units and small generating units 
as for all

[[Page 67860]]

other new sources. A key factor that affects compliance costs for 
existing sources is the need to retrofit new pollution controls to 
replace existing pollution controls. New sources do not incur retrofit 
costs because the pollution controls (process operations or treatment 
technology) are installed at the time of construction. Thus the costs 
for new sources are lower, even if the pollution controls are 
identical.
    For each of the wastestreams except combustion residual leachate, 
EPA rejected establishing NSPS based on surface impoundments for the 
same reasons it rejected establishing BAT based on surface 
impoundments. For FGD wastewater, EPA also did not establish NSPS based 
on chemical precipitation for the same reasons it rejected establishing 
BAT based on that technology. In particular, these other technologies 
would not achieve as much pollutant reduction as the technology bases 
in Option F--which is technologically available and economically 
achievable with acceptable non-water quality environmental impacts and 
energy requirements--and thus do not represent best available 
demonstrated control technology.
    EPA did not select surface impoundments as the basis for NSPS for 
combustion residual leachate because, unlike BAT, NSPS represent the 
``greatest degree of effluent reduction . . . achievable'' (CWA section 
306), and (besides ``cost'' and ``any non-water quality environmental 
impact and energy requirements,'' discussed above) EPA does not 
consider ``other factors'' in establishing NSPS. When used to treat 
combustion residual leachate, chemical precipitation can achieve 
substantial pollutant reductions as compared to surface impoundments. 
Thus, EPA has determined that NSPS for leachate based on chemical 
precipitation achieve the ``greatest degree of effluent reduction'' as 
that term is used in CWA section 306.
    Similarly, EPA did not select chemical precipitation plus 
biological treatment as the basis for NSPS for FGD wastewater because, 
under CWA section 306, NSPS reflect ``the greatest degree of effluent 
reduction . . . achievable.'' Evaporation systems are capable of 
achieving extremely low pollutant discharge levels, and in fact can be 
the basis for a plant completely eliminating all discharges associated 
with FGD wastewater. Moreover, unlike EPA's decision not to identify 
evaporation as the technology basis for FGD wastewater discharges from 
all existing sources due to the large associated cost, establishing 
NSPS for FGD wastewater based on evaporation does not add to the 
overall estimated cost of the rule because EPA does not predict any new 
coal-fired generating units will be installed in the foreseeable 
future. As explained above, however, in the event that a new unit is 
installed, EPA determined that the NSPS compliance costs would not 
present a barrier to entry.

E. PSES

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

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

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

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

[[Page 67861]]

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

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

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

F. PSNS

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

G. Anti-Circumvention Provision

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

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

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

[[Page 67862]]

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

H. Other Revisions

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

[[Page 67863]]

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

I. Non-Chemical Metal Cleaning Waste

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

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

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

J. Best Management Practices

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

IX. Costs and Economic Impact

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

[[Page 67864]]

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

A. Plant-Specific and Industry Total Costs

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

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

B. Social Costs

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

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

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

[[Page 67865]]



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

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

C. Economic Impacts

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

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

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

[[Page 67866]]

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

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

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

[[Page 67867]]

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

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

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

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

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

                               Table IX-5--Impact of Final ELGs on Steam Electric Power Plants as a Group at the Year 2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                  Incremental early retirements
                                                          closures \a\
 
 
 
                                               ----------------------------------
 
                                             Change in
 
                                                                                      Change in total
                                              variable
                                             Change in
              Region                 Baseline                              % of         generation
                                          production cost
                                            annual costs
                                     capacity                 Capacity baseline        (GWh or % of
                                          (2013$/MWh or %
                                           (million 2013$
                                         (MW)             (MW)         capacity          baseline)
                                            of baseline)
                                         or % of baseline)
 
 
 
 
 
 
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total U.S.........................    359,982              843             0.2%      -3,179       -0.2%       $0.10        0.3%        $496        0.6%
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values for incremental early retirements or closures represent change relative to the baseline run. IPM may show partial (unit) or full plant early
  retirements (closures). It may also show avoided closures (negative closure values) in which a unit or plant that is projected to close in the
  baseline is estimated to continue operating in the post-compliance case. Avoided closures may occur among plants that incur no compliance costs or for
  which compliance costs are low relative to other steam electric power plants.

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

[[Page 67868]]

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

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

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

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

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

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

X. Pollutant Reductions

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

[[Page 67869]]

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

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

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

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

XI. Development of Effluent Limitations and Standards

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

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

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

[[Page 67870]]

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

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


[[Page 67871]]


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

XII. Non-Water Quality Environmental Impacts

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

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

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

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

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

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

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

XIII. Environmental Assessment

A. Introduction

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

[[Page 67872]]

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

B. Summary of Human Health and Environmental Impacts

    As discussed in the environmental assessment and proposed rule, 
current scientific literature indicates that steam electric power plant 
wastewaters such as fly ash transport water, bottom ash transport 
water, FGD wastewater, and combustion residual leachate contain large 
amounts of a wide range of harmful pollutants, some of which are toxic 
and bioaccumulative, and which cause significant, widespread 
detrimental environmental and human health impacts.
    Discharges of steam electric power plant wastewaters present a 
serious public health concern due to the potential human exposure to 
toxic pollutants through consumption of contaminated fish and drinking 
water. Toxic pollutants that detrimentally affect human health that are 
commonly found in steam electric power plant wastewater discharges 
include mercury, lead, arsenic, cadmium, thallium, and selenium, along 
with numerous others (see EA Section 3). These pollutants are 
associated with a variety of documented adverse human health impacts. 
For example, human exposure to elevated levels of mercury for 
relatively short periods of time can result in kidney and brain damage. 
Pregnant women who are exposed to mercury can pass the contaminant to 
their developing fetus, leading to possible toxic injury of the fetal 
brain and damage to other parts of the nervous system. Human exposure 
to elevated levels of lead can cause serious damage to the brain, 
kidneys, nervous system, and red blood cells, especially in children. 
Arsenic is associated with an increased risk of liver and bladder 
cancer in humans, as well as non-cancer impacts including dermal, 
cardiovascular, respiratory, and reproductive effects such as excess 
incidences of miscarriages, stillbirths, preterm births, and low birth 
weights. Chronic exposure to cadmium, a probable carcinogen, can lead 
to kidney failure, lung damage, and weakened bones. Human exposure to 
elevated levels of thallium can lead to neurological symptoms, hair 
loss, gastrointestinal effects, liver and kidney damage, and 
reproductive and developmental damage. Long-term exposure to selenium 
can damage the kidney, liver, and nervous and circulatory systems.
    The pollutants in steam electric power plant wastewater can 
bioaccumulate within fish and other aquatic wildlife in the receiving 
waters and subsequently be transferred to recreational and subsistence 
fishers who consume these contaminated fish, potentially resulting in 
the acute and chronic health impacts described above. Certain 
populations are particularly at risk, including women who are pregnant, 
nursing, or may become pregnant, and communities relying on consumption 
of fish from contaminated waters as a major food source.
    Discharges of steam electric power plant pollutants to surface 
waters also have the potential to contaminate drinking water sources, 
causing potential problems for drinking water systems and, if left 
untreated, potential adverse health effects. A recent study indicates 
that pollutants in ash and FGD wastewater discharges exceeded MCLs in 
every surface water that was monitored in North Carolina during the 
study (see DCN SE01984). Nitrogen discharges from steam electric power 
plants can contribute, along with other sources, to harmful algal 
blooms. Harmful algal blooms can affect drinking water sources, such as 
the recent incident in Toledo, Ohio (see DCN SE04517).
    Bromide discharges from steam electric power plants can contribute 
to the formation of carcinogenic DBPs in public drinking water systems. 
A recent study identified four drinking water treatment plants that 
experienced increased levels of bromide in their source water, and in 
some, a corresponding increase in the formation of brominated DBPs in 
the drinking water system, after the installation of wet FGD scrubbers 
at upstream steam electric power plants (see DCN SE04503).
    Although not directly addressed by this final rule, ground water 
contamination from surface impoundments containing steam electric power 
plant wastewater also threatens drinking water sources. EPA identified 
more than 30 documented cases where ground water contamination from 
surface impoundments extended beyond the plant boundaries, illustrating 
the threat to ground water drinking water sources (see DCN SE04518). 
Where this final rule helps to reduce or eliminate the continued 
disposal or storage of steam electric power plant wastewater pollutants 
in unlined or leaking surface impoundments, potential impacts to ground 
water will also be reduced or eliminated.
    The ecological impacts of steam electric power plant wastewater 
pollutants include both acute (e.g., fish kills) and chronic effects 
(e.g., reproductive failure, malformations, and metabolic, hormonal, 
and behavioral disorders) upon biota within the receiving water and the 
surrounding environment. Recovery of aquatic environments from exposure 
to these steam electric power plant pollutants can be extremely slow 
due to the accumulation and continued cycling of the pollutants within 
ecosystems, resulting in the potential to alter ecological processes 
such as population diversity and community dynamics. Furthermore, many 
steam electric power plants discharge pollutants to sensitive 
environments such as the Great Lakes, valuable estuaries such as the 
Chesapeake Bay, 303(d) listed impaired waters, and waters with fish 
consumption advisories. EPA identified 69 steam electric power plants 
with documented adverse environmental impacts on surface waters (see 
DCN SE04518).

C. Environmental Assessment Methodology

    As discussed in Section V.G, EPA updated the environmental 
assessment for the final rule to respond to public comments and to 
better characterize the environmental and human health improvements 
associated with the final rule. Although not required to do so, EPA 
conducted an environmental assessment for the final rule. The 
environmental assessment reviewed currently available literature on the 
documented environmental and human health impacts of steam electric 
power plant wastewater discharges and conducted modeling to determine 
the cumulative impacts of pollution from the universe of steam electric 
power plants to which the final rule applies. EPA modeled both of the 
impacts of steam electric power plant discharges at baseline conditions 
and the improvements that will likely result after implementation of 
this rule. The final environmental assessment also incorporates changes 
to the industry profile to account for retirements, conversions, and 
operational changes

[[Page 67873]]

that EPA anticipates, given other existing rules, primarily the CCR and 
CPP rules.
    The environmental assessment modeling for the final rule consisted 
of (1) a steady-state, national-scale immediate receiving water (IRW) 
model that evaluated the discharges from steam electric power plants 
and focused on impacts within the immediate surface water where the 
discharges occur (approximately one to 10 kilometers [km] from the 
outfall),\51\ and (2) dynamic case study models with more extensive, 
site-specific modeling of selected waterbodies that receive, or are 
downstream from, steam electric power plant discharges. EPA also 
modeled receiving water concentrations downstream from steam electric 
power plant discharges using EPA's Risk-Screening Environmental 
Indicators (RSEI) model, and improved its modeling of selenium 
bioaccumulation in fish and wildlife.
---------------------------------------------------------------------------

    \51\ The IRW model used for the final rule is substantially 
similar to the one used for the proposed rule, but with certain 
updates, as further discussed in this section.
---------------------------------------------------------------------------

    Additionally, for the final rule, EPA updated and improved several 
input parameters for the IRW model, including fish consumption rates 
for recreational and subsistence fishers, the bioconcentration factor 
for copper, and benchmarks for assessing the potential for impacts to 
benthic communities in receiving waters.
    The case-study modeling for the final rule is based on EPA's Water 
Quality Analysis Simulation Program (WASP), which accounts for 
fluctuations in receiving water flow rates by using daily stream flow 
monitoring data instead of one annual average flow rate for the 
receiving water, as used in the IRW. The case-study modeling accounts 
for pollutant transport and accumulation within receiving water reaches 
that are downstream from the discharge location, allowing for an 
assessment of environmental impacts over a larger portion of the 
receiving waterbody. The case study modeling also accounts for 
pollutant contributions from other point, nonpoint, and background 
sources, to the extent practical, using available data sources. EPA 
used the water quality results of the case-study modeling to supplement 
the results of the IRW model (see EA Section 8).
    EPA improved its selenium bioaccumulation modeling for impacts on 
wildlife by developing and using an ecological risk model that predicts 
the risk of reproductive impacts among fish and waterfowl exposed to 
selenium from steam electric power plant wastewater discharges. The 
ecological risk model accounts for the bioaccumulation of selenium in 
aquatic organisms through dietary exposure (the food web), as 
contrasted with exposure only to dissolved selenium in the water 
column. Dietary exposure plays a more significant role in determining 
the extent of selenium bioaccumulation in aquatic organisms. The 
ecological risk model also accounts for the higher rates of selenium 
bioaccumulation that can occur in slow-flowing aquatic systems such as 
lakes and reservoirs, and the risk model translates selenium tissue 
concentrations into the predicted risk of adverse reproductive effects 
(e.g., reduced egg hatchability, larval mortality, and deformities that 
affect survival) among exposed fish and waterfowl. EPA applied the 
ecological risk model to the water quality outputs from both the 
national-scale IRW model and the case-study models. See EA Section 5.2 
for a more detailed discussion.

D. Outputs From the Environmental Assessment

    EPA focused its quantitative analyses on the environmental and 
human health impacts associated with exposure to toxic bioaccumulative 
pollutants via the surface water pathway. EPA focused the modeling on 
discharges of toxic bioaccumulative pollutants from a subset of 
evaluated wastestreams from steam electric power plants (fly ash and 
bottom ash transport water, FGD wastewater, and combustion residual 
leachate) into rivers/streams and lakes/ponds (including 
reservoirs).\52\ EPA addressed environmental impacts from nutrients in 
a separate analysis discussed in Section XIII.D.5.
---------------------------------------------------------------------------

    \52\ EPA did not use the state 303d lists of impaired waters in 
order to ensure comprehensive coverage of all pollutants of concern.
---------------------------------------------------------------------------

    The environmental assessment concentrates on impacts to aquatic 
life based on changes in surface water quality; impacts to aquatic life 
based on changes in sediment quality within surface waters; impacts to 
wildlife from consumption of contaminated aquatic organisms; and 
impacts to human health from consumption of contaminated fish and 
water. Table XIII-1 presents a list of the key environmental 
improvements projected within the immediate receiving waters due to the 
pollutant loading reductions under the final rule. These improvements 
are discussed in detail, with quantified results, in the EA.

  Table XIII-1--Key Environmental Improvements Within Modeled Immediate
                Receiving Waters Under the Final Rule 53
------------------------------------------------------------------------
                                            Will improve under the final
    Criteria evaluated for exceedances                  rule?
------------------------------------------------------------------------
Freshwater Acute National Recommended WQC.  YES
Freshwater Chronic National Recommended     YES
 WQC.
Human Health Water and Organism National    YES
 Recommended WQC.
Human Health Organism Only National         YES
 Recommended WQC.
Drinking Water MCL........................  YES
Fish Ingestion NEHC for Mink..............  YES
Fish Ingestion NEHC for Eagles............  YES
Adverse Reproductive Effects in Fish due    YES
 to Selenium.
Adverse Reproductive Effects in Mallards    YES
 due to Selenium.
Non-Cancer Reference Dose for Child         YES
 (Recreational and Subsistence fishers).
Non-Cancer Reference Dose for Adult         YES
 (Recreational and Subsistence fishers).
Arsenic Cancer Risk for Child               YES
 (Recreational and Subsistence fishers).
Arsenic Cancer Risk for Adult               YES
 (Recreational and Subsistence fishers).
------------------------------------------------------------------------
Acronyms: MCL (Maximum Contaminant Level); NEHC (No Effect Hazard
  Concentration); WQC (Water Quality Criteria).
\a\ The IRW model encompasses a total of 163 immediate receiving waters
  (144 rivers and streams; 19 lakes, ponds, and reservoirs) and loadings
  from 143 steam electric power plants.

1. Improvements in Surface Water and Ground Water Quality
---------------------------------------------------------------------------

    \53\ See the EA for the details and amounts of the projected 
improvements.
---------------------------------------------------------------------------

    EPA estimates a significant number of environmental and ecological 
improvements and reduced impacts to wildlife and humans from reductions 
in pollutant loadings under the final rule. More specifically, the 
environmental assessment evaluated (a) improvements in water quality, 
(b) reduction in impacts to wildlife, (c) reduction in number of 
receiving waters with potential human health cancer risks, (d) 
reduction in number of receiving waters with potential to cause non-
cancer human health effects, (e) reduction in nutrient impacts, (f) 
reduction in other environmental impacts, and (g) other unquantified 
environmental improvements.

[[Page 67874]]

    EPA expects significantly reduced contamination levels in surface 
waters and sediments under the final rule. EPA estimates that reduced 
pollutant loadings to surface waters will significantly improve water 
quality by reducing pollutant concentrations by an average of 56 
percent within the immediate receiving waters of steam electric power 
plants where additional treatment technologies are installed as a 
result of this final rule. Based on the water quality component of the 
IRW model, which compares modeled receiving water concentrations to 
national recommended WQC and MCLs to assess changes in receiving water 
quality, the pollutants with the greatest number of water quality 
standard exceedances under baseline pollutant loadings include: Total 
arsenic, total thallium, total selenium, and dissolved cadmium. EPA 
estimates that almost half of the immediate receiving waters exceed a 
water quality standard under baseline loadings. EPA estimates that the 
number of immediate receiving waters with aquatic life exceedances, 
which are driven by high total selenium and dissolved cadmium 
concentrations, will be reduced under the final rule. EPA also 
estimates that the number of immediate receiving waters with human 
health water quality standards exceedances, primarily driven by high 
total arsenic and total thallium concentrations, will be reduced under 
the final rule.
    Selenium is one of the primary pollutants documented in the 
literature as causing environmental impacts to fish and wildlife. EPA 
calculates that total selenium receiving water concentrations will be 
reduced by two-thirds under the final rule, leading to a reduction in 
the number of immediate receiving waters exceeding the freshwater 
chronic criteria for selenium.
    While the case-study models and IRW model produced generally 
similar results for the five receiving waters included in both 
analyses, the case-study model reveals additional potential for 
baseline impacts to water quality, aquatic life, and human health that 
are not reflected in the IRW model. Case-study modeling also reveals 
that these potential impacts can extend beyond the immediate receiving 
water and into downstream waters, leading to the potential for more 
widespread environmental and human health effects than those shown with 
the IRW model. This is particularly true regarding water quality 
standard exceedances; in four of the five receiving waters included in 
both analyses, the case-study model indicates that the final rule will 
result in further reductions in water quality standard exceedances 
beyond those reflected in the IRW model.
    As discussed in the EA, the RSEI modeling indicates that surface 
waters downstream from steam electric power plant wastewater discharges 
will also achieve water quality improvements under the final rule.
    This final rule will also potentially help to both reduce ground 
water contamination and improve the availability of ground water 
resources by complementing the CCR rule. This rule provides strong 
incentives for plants to greatly reduce, if not entirely eliminate, 
disposal and treatment of steam electric power plant wastewater in 
unlined surface impoundments.
2. Reduced Impacts to Wildlife
    EPA expects that once the rule is implemented the number of 
immediate receiving waterbodies with potential impacts to wildlife will 
begin to be reduced by more than a half compared to baseline conditions 
under the final rule.
    EPA determined that steam electric power plant wastewater 
discharges into lakes pose the greatest risk to piscivorous (fish 
eating) wildlife, with almost a half of lakes exceeding a protective 
benchmark for minks or eagles under baseline pollutant loadings 
(compared to about a third of rivers). Mercury and selenium are the 
primary pollutants with the greatest number of receiving waters with 
benchmark exceedances. EPA estimates that this rule will reduce the 
number of immediate receiving waters exceeding the benchmark for minks 
and eagles by approximately half for mercury and selenium. 
Additionally, as discussed in the EA, the downstream RSEI modeling 
indicates that surface waters downstream from steam electric power 
plant wastewater discharges will also achieve improvements in these 
wildlife benchmarks under the final rule.
    For the final rule, EPA also performed modeling to estimate the 
risk of adverse reproductive effects among fish (e.g., reduced larvae 
survival) and waterfowl (e.g., reduced egg hatchability) with dietary 
exposure to selenium from steam electric power plant wastewater. Based 
on the water quality output from the IRW model, EPA determined that 
approximately 15 percent of immediate receiving waters contain selenium 
concentrations that present at least a ten percent risk of adverse 
reproductive effects among fish or waterfowl that consume prey from 
those waterbodies. Under the final rule, EPA estimates that the count 
of immediate receiving waters presenting these reproductive risks will 
be reduced by more than half. This indicates that the final rule will 
reduce the long-term bioaccumulative impact of selenium (and possibly 
other bioaccumulative pollutants) throughout aquatic ecosystems.
    In addition, EPA estimates that the improvements to water quality, 
discussed above, will improve aquatic and wildlife habitats in the 
immediate and downstream receiving waters from steam electric power 
plant discharges. EPA determined that these water quality and habitat 
improvements will enhance efforts to protect threatened and endangered 
species. EPA identified four species with a high vulnerability to 
changes in water quality whose recovery will be enhanced by the 
pollutant reductions associated with the final rule.
3. Reduced Human Health Cancer Risk
    EPA estimates that reductions in arsenic loadings from the final 
rule will result in a reduction in potential cancer risks to humans 
that consume fish exposed to steam electric power plant discharges. In 
addition, based on the downstream RSEI modeling, EPA estimates that 
numerous river miles downstream from steam electric discharges contain 
fish contaminated with inorganic arsenic that present cancer risks to 
at least one of the evaluated cohorts. The final rule substantially 
reduces this number of miles.
4. Reduced Threat of Non-Cancer Human Health Effects
    Exposure to toxic bioaccumulative pollutants poses risk of systemic 
and other effects to humans, including effects on the circulatory, 
respiratory, or digestive systems, and neurological and developmental 
effects. EPA estimates the final rule will significantly reduce the 
number of receiving waters with the potential to cause non-cancer 
health effects in humans who consume fish exposed to steam electric 
power plant pollutants.
    Under baseline pollutant loadings, EPA determined that about half 
of immediate receiving waters present non-cancer health risks for one 
or more of the human cohorts due to elevated pollutant levels in fish. 
The final rule, once implemented, will begin to reduce this amount by 
approximately 50 percent for all the human cohorts that were evaluated. 
Non-cancer risks are caused primarily by mercury (as methylmercury), 
total thallium, and total selenium, and to a lesser degree, total 
cadmium pollutant loadings. Additionally, as discussed in the EA, the 
downstream RSEI modeling indicates that the final rule substantially

[[Page 67875]]

reduces the prevalence of downstream waters with contaminated fish that 
present non-cancer health risks to at least one of the human cohorts.
    In addition to the assessment of non-cancer impacts described 
above, EPA also evaluated the adverse health effects to children who 
consume fish contaminated with lead from steam electric power plant 
wastewater. EPA estimates that the final rule will significantly reduce 
the associated IQ loss among children who live in recreational angler 
and subsistence fisher households. The final rule will also reduce the 
incidence of other health effects associated with lead exposure among 
children, including slowed or delayed growth, delinquent and anti-
social behavior, metabolic effects, impaired heme synthesis, anemia, 
and impaired hearing. The final rule will also reduce IQ loss among 
children exposed in utero to mercury from maternal fish consumption. 
Section XIV.B.1 provides additional details on the benefits analysis of 
these reduced IQ losses.
    The final rule will also result in additional non-cancer human 
health improvements beyond those discussed above, including reduced 
health hazards due to exposure to contaminants in waters that are used 
for recreational purposes (e.g., swimming).
5. Reduced Nutrient Impacts
    The primary concern with nutrients (nitrogen and phosphorus) in 
steam electric power plant discharges is the potential for contributing 
to adverse impacts in waterbodies that receive nutrient discharges from 
multiple sources. Excessive nutrient loadings to receiving waters can 
significantly affect the ecological stability of freshwater and 
saltwater aquatic ecosystems and pose health threats to humans from the 
generation of toxins by cyanobacteria, which can thrive in nitrogen 
driven algal blooms (DCN SE04505).
    Nine percent of surface waters receiving steam electric power plant 
wastewater discharges are impaired for nutrients. Although the 
concentration of nitrogen present in steam electric power plant 
discharges from any individual power plant is relatively low, the total 
nitrogen loadings from a single plant can be significant due to large 
wastewater discharge flow rates.
    EPA projects that the final rule will reduce total nutrient 
loadings by steam electric power plants in their immediately downstream 
receiving waters by more than 99 percent. Section XIV provides 
additional details on the water quality benefits analysis of nutrient 
reductions, as determined using the SPARROW (Spatially Referenced 
Regressions On Watershed attributes) model.

E. Unquantified Environmental and Human Health Improvements

    The environmental assessment focused primarily on the 
quantification of environmental improvements within rivers and lakes 
from post-compliance pollutant reductions for toxic bioaccumulative 
pollutants and excessive nutrients. While extensive, the environmental 
improvements quantified do not encompass the full range of improvements 
anticipated to result from the final rule simply because some of the 
improvements have no method for measuring a quantifiable or monetizable 
improvement. EPA estimates post-compliance pollutant reductions from 
the final rule to result in much greater improvements than those 
quantified for wildlife, human health and the environment by:
     Reducing loadings of bioaccumulative pollutants to the 
broader ecosystem, resulting in the reduction of long-term exposures 
and sub-lethal ecological effects;
     Reducing sub-lethal chronic effects of toxic pollutants on 
aquatic life not captured by the national recommended WQC;
     Reducing loadings of pollutants for which EPA did not 
perform water quality modeling in support of the environmental 
assessment (e.g., boron, manganese, aluminum, vanadium, and iron);
     Mitigating impacts to aquatic and aquatic-dependent 
wildlife population diversity and community structures;
     Reducing exposure of wildlife to pollutants through direct 
contact with combustion residual surface impoundments and constructed 
wetlands built as treatment systems at steam electric power plants; and
     Reducing the potential for the formation of harmful algal 
blooms.
    Data and analytical limitations prevent modeling the scale and 
complexity of the ecosystem processes potentially impacted by steam 
electric power plant wastewater, resulting in the inability to quantify 
all potential improvements. However, documented site-specific impacts 
in the literature reinforce that these impacts are common in the 
environments surrounding steam electric power plants and fully support 
the conclusion that reducing pollutant loadings will further reduce 
risks to human health and wildlife and prevent damage to the 
environment.
    Although the environmental assessment quantifies impacts to 
wildlife that consume fish contaminated with pollutants from steam 
electric power plant wastewater, it does not capture the full range of 
exposure pathways through which bioaccumulative pollutants can enter 
the surrounding food web. Wildlife can encounter toxic bioaccumulative 
pollutants from discharges of the evaluated wastestreams through a 
variety of exposure pathways such as direct exposure, drinking water, 
consumption of contaminated vegetation, and consumption of contaminated 
prey other than fish and invertebrates. Therefore, the quantified 
improvements underestimate the complete loadings of bioaccumulative 
pollutants that can impact wildlife in the ecosystem. The final rule 
will lower the total amount of toxic bioaccumulative pollutants 
entering the food web near steam electric power plants.
    EPA also estimates that reductions in pollutant loadings will lower 
the occurrence of sub-lethal effects associated with many of the 
pollutants in steam electric power plant wastewater that are not 
captured by comparisons with national recommended WQC for aquatic life. 
Chronic effects such as decreased reproductive success, changes in 
metabolic rates, decreased growth rates, changes in morphology (e.g., 
fin erosion, oral deformities), and changes in behavior (e.g., swimming 
ability, ability to catch prey, ability to escape from predators) that 
can negatively affect long-term survival, are well documented in the 
literature as occurring in aquatic environments near steam electric 
power plants. Reductions in organism survival rates from chronic 
effects such as abnormalities can alter interspecies relationships 
(e.g., declines in the abundance or quality of prey) and prolong 
ecosystem recovery. Additionally, EPA was unable to quantify changes to 
aquatic and wildlife population diversity and community dynamics; 
however, population effects (decline in number and type of organisms 
present) caused by exposure to steam electric power plant wastewater 
are well documented in the literature. Changes in aquatic populations 
can alter the structure and function of aquatic communities and cause 
cascading effects within the food web that result in long-term impacts 
to ecosystem dynamics. EPA estimates that post-compliance pollutant 
loading reductions associated with the final rule will lower the 
stressors that can cause alterations in population and community 
dynamics and improve the overall function of ecosystems

[[Page 67876]]

surrounding steam electric power plants, as well as help resolve issues 
faced in other national ecosystem protection programs such as the Great 
Lakes program, the National Estuaries program, and the 303(d) impaired 
waters program.
    The post-compliance pollutant reductions associated with the final 
rule will also decrease the environmental impacts to wildlife exposed 
to pollutants through direct contact with surface impoundments and 
constructed wetlands at steam electric power plants. Documented site-
specific impacts demonstrate that wildlife living in close proximity to 
combustion residual impoundments exhibit elevated levels of arsenic, 
cadmium, chromium, lead, mercury, selenium, and vanadium. Multiple 
studies have linked these ``attractive nuisance'' areas (contaminated 
impoundments at a steam electric power plant that attract wildlife for 
nesting or feeding) to diminished reproductive success. EPA estimates 
that the post-compliance pollutant reductions will decrease the 
exposure of wildlife populations to toxic pollutants and reduce the 
risks for impacts on reproductive success.

F. Other Improvements

    Other improvements will occur to other resources that are 
associated directly or indirectly with the final rule. These include 
aesthetic and recreational improvements, reduced economic impacts such 
as clean up and treatment costs in response to contamination or 
impoundment failures, reduced injury associated with pond failures, 
reduced ground water contamination, support for threatened and 
endangered species, reduced water usage and reduced air emissions. 
Section XIV provides additional details on the monetized benefits of 
these improvements.

XIV. Benefits Analysis

    This section summarizes EPA's estimates of the national 
environmental benefits expected to result from reduction in steam 
electric power plant wastewater discharges described in Section X and 
the resultant environmental effects summarized in Section XIII. The BCA 
Report provides additional details on benefits methodologies and 
analyses, including uncertainties and limitations. The analysis 
methodology is generally the same as that used by EPA for analysis of 
the proposed rule, but with revised inputs and assumptions that reflect 
updated data and address comments the Agency received on the proposed 
rule, including additional categories of benefits the Agency analyzed 
for the final rule.

A. Categories of Benefits Analyzed

    Table XIV-1 summarizes benefit categories associated with the final 
rule and notes which categories EPA was able to quantify and monetize. 
Analyzed benefits fall within five broad categories: Human health 
benefits from surface water quality improvements, ecological conditions 
and recreational use benefits from surface water quality improvements, 
market and productivity benefits, air-related benefits (which include 
both human health and climate change-related effects), and water 
withdrawal benefits. Within these broad categories, EPA was able to 
assess benefits with varying degrees of completeness and rigor. Where 
possible, EPA quantified the expected effects and estimated monetary 
values. However, data limitations and gaps in the understanding of how 
society values certain water quality changes prevent EPA from 
quantifying and/or monetizing some benefit categories.

                           TABLE XIV-1--Benefit Categories Associated With Final Rule
----------------------------------------------------------------------------------------------------------------
                                                                                                     Neither
                       Benefit category                         Quantified and   Quantified but   quantified nor
                                                                  monetized      not monetized      monetized
----------------------------------------------------------------------------------------------------------------
1. Human Health Benefits from Surface Water Quality Improvements
----------------------------------------------------------------------------------------------------------------
Reduced incidence of cancer from arsenic exposure via fish                  X
 consumption.................................................
Reduced incidence of cardiovascular disease from arsenic                                     X
 exposure via fish consumption...............................
Reduced incidence of cardiovascular disease from lead                   X \a\
 exposure via fish consumption...............................
Reduced incidence of other cancer and non-cancer adverse                                     X
 health effects (e.g., reproductive, immunological,
 neurological, circulatory, or respiratory toxicity) due to
 exposure to arsenic, lead, cadmium, and other toxics from
 fish consumption............................................
Reduced IQ loss in children from lead exposure via fish                     X
 consumption.................................................
Reduced need for specialized education for children from lead               X
 exposure via fish consumption...............................
Reduced in utero mercury exposure via maternal fish                         X
 consumption.................................................
Reduced health hazards from exposure to pollutants in waters                                                  X
 used recreationally (e.g., swimming)........................
----------------------------------------------------------------------------------------------------------------
2. Ecological Conditions and Recreational Use Benefits from Surface Water Quality Improvements
----------------------------------------------------------------------------------------------------------------
Benefits from improvements in surface water quality,                        X
 including: Improved aquatic and wildlife habitat; enhanced
 water-based recreation, including fishing, swimming,
 boating, and near-water activities; increased aesthetic
 benefits, such as enhancement of adjoining site amenities
 (e.g., residing, working, traveling, and owning property
 near the water \b\; and non-use value (existence, option,
 and bequest value from improved ecosystem health) \b\.......
Benefits from improved protection of threatened and                         X
 endangered species..........................................
Reduced sediment contamination...............................                                                 X
----------------------------------------------------------------------------------------------------------------
3. Market and Productivity Benefits
----------------------------------------------------------------------------------------------------------------
Reduced impoundment failures (monetized benefits include                    X                                 X
 avoided cleanup costs, transaction costs, and environmental
 damages; non-quantified benefits include avoided injury)....
Reduced water treatment costs for municipal drinking water,                                                   X
 irrigation water, and industrial process....................
Improved commercial fisheries yields.........................                                                 X
Increased tourism and participation in water-based recreation                                                 X
Increased property values from water quality improvements....                                                 X
Increased ability to market coal combustion byproducts.......           X \a\

[[Page 67877]]

 
Reduced maintenance dredging in navigational waterways and              X \a\
 reservoirs from reduction in sediment discharges............
----------------------------------------------------------------------------------------------------------------
4. Air-Related Benefits
----------------------------------------------------------------------------------------------------------------
Human health benefits from reduced morbidity and mortality                  X
 from exposure to NOX, SO2 and particulate matter (PM2.5)....
Avoided climate change impacts from CO2 emissions............               X
----------------------------------------------------------------------------------------------------------------
5. Benefits from Reduced Water Withdrawals
----------------------------------------------------------------------------------------------------------------
Increased availability of ground water resources.............               X
Reduced impingement and entrainment of aquatic organisms.....                                                 X
Reduced susceptibility to drought............................                                                 X
----------------------------------------------------------------------------------------------------------------
\a\ Monetized benefit category added for the final rule.
\b\ These values are implicit in the total willingness to pay (WTP) for water quality improvements.

    The following section summarizes EPA's analysis of the benefits 
that the Agency was able to quantify and monetize (identified in the 
second column of Table XIV-1). The final rule will also provide 
additional benefits that the Agency was not able to monetize. The BCA 
Report further describes some of these additional non-monetized 
benefits.

B. Quantification and Monetization of Benefits

1. Human Health Benefits From Surface Water Quality Improvements
    Reduced pollutant discharges from steam electric power plants 
generate human health benefits in a number of ways. As described in 
Section XIII, exposure to pollutants in steam electric power plant 
discharges via consumption of fish from affected waters can cause a 
wide variety of adverse health effects, including cancer, kidney 
damage, nervous system damage, fatigue, irritability, liver damage, 
circulatory damage, vomiting, diarrhea, brain damage, IQ loss, and many 
others. Because the final rule will reduce discharges of steam electric 
pollutants into waterbodies that receive, or are downstream from, these 
discharges, it is likely to result in decreased incidences of 
associated illnesses.
    Due to data limitations and uncertainties, EPA is able to monetize 
only a subset of the health benefits associated with reductions in 
pollutant discharges from steam electric power plants. EPA analyzed the 
following measures of human health-related benefits: Reduced lead-
related IQ loss in children aged zero to seven from fish consumption; 
reduced cardiovascular disease in adults from lead and arsenic exposure 
from fish consumption; reduced mercury-related IQ loss in children 
exposed in utero due to maternal fish consumption; and reduced cancer 
risk in adults due to arsenic exposure from fish consumption. EPA 
monetized these human health benefits by estimating the change in the 
expected number of individuals experiencing adverse human health 
effects in the populations exposed to steam electric discharges and/or 
reduced exposure levels, and valuing these changes using a variety of 
monetization approaches.
    These are not the only human health benefits expected to result 
from the final rule. EPA also estimated additional human health 
benefits derived from changes in air emissions. These additional 
benefits are discussed separately in Section XIV.B.4.
a. Monetized Human Health Benefits From Surface Water Quality 
Improvements
    EPA estimated health risks from the consumption of contaminated 
fish from waterbodies within 50 miles of households. EPA used Census 
Block population data, state-specific average fishing rates, and data 
on fish consumption advisories to estimate the exposed population. EPA 
used cohort-specific fish consumption rates and waterbody-specific fish 
tissue concentration estimates to calculate exposure to steam electric 
pollutants. Cohorts were defined by age, sex, race/ethnicity, and 
fishing mode (recreational/subsistence). EPA used these data to 
quantify and monetize the following six categories of human health 
benefits, which are further detailed in the BCA Report:
     Benefits from Reduced IQ Loss in Children from Lead 
Exposure via Fish Consumption.
     Benefits from Reduced Need for Specialized Education for 
Children from Lead Exposure via Fish Consumption.
     Benefits from Reduced Incidence of Cardiovascular Disease 
from Lead Exposure via Fish Consumption.
     Benefits of Reduced In Utero Mercury Exposure via Maternal 
Fish Consumption.
     Benefits from Reduced Incidence of Cancer from Arsenic 
Exposure via Fish Consumption.
     Benefits from Reduced Incidence of Cardiovascular Disease 
from Arsenic Exposure via Fish Consumption.
    Table XIV-2 summarizes monetized human health benefits from surface 
water quality improvements. EPA estimates that the final rule will 
provide human health benefits valued at $16.5 to $17.9 million 
annually, using a three percent discount rate, and $11.3 to $11.6 
million, using a seven percent discount rate. In addition, EPA 
estimated health benefits associated with changes in air emissions, as 
discussed in Section XIV.B.4.

[[Page 67878]]



      TABLE XIV-2--Human Health Benefits From Surface Water Quality
                              Improvements
------------------------------------------------------------------------
         Benefit category           Annualized benefits  (million 2013$)
------------------------------------------------------------------------
                            3% Discount Rate
------------------------------------------------------------------------
Benefits from Reduced IQ Loss in    $1.0
 Children from Lead Exposure via    ($0.8 to $1.1)
 Fish Consumption \a\.
Benefits from Reduced Need for      <0.1
 Specialized Education for
 Children from Lead Exposure via
 Fish Consumption.
Benefits from Reduced Incidence of  12.8
 Cardiovascular Disease (CVD) from
 Lead Exposure via Fish
 Consumption.
Benefits of Reduced In Utero        3.5
 Mercury Exposure via Maternal      (2.9 to 4.0)
 Fish Consumption \a\.
Benefits from Reduced Incidence of  <0.1
 Cancer from Arsenic Exposure via
 Fish Consumption.
    Subtotal \b\..................  16.5 to 17.9
                                    (15.2 to 16.7)
------------------------------------------------------------------------
                            7% Discount Rate
------------------------------------------------------------------------
Benefits from Reduced IQ Loss in    0.2
 Children from Lead Exposure via    (0.1 to 0.2)
 Fish Consumption \a\.
Benefits from Reduced Need for      <0.1
 Specialized Education for
 Children from Lead Exposure via
 Fish Consumption.
Benefits from Reduced Incidence of  10.7
 CVD from Lead Exposure via Fish
 Consumption.
Benefits of Reduced In Utero        0.6
 Mercury Exposure via Maternal      (0.5 to 0.7)
 Fish Consumption \a\.
Benefits from Reduced Incidence of  <0.1
 Cancer from Arsenic Exposure via
 Fish Consumption.
    Subtotal \b\..................  11.4
                                    (10.7 to 11.0)
------------------------------------------------------------------------
\a\ Low end is based on the assumption that the loss of one IQ point
  results in the loss of 1.76% of lifetime earnings (following Schwartz,
  1994); high end is based on the assumption that the loss of one IQ
  point results in the loss of 2.38% of lifetime earnings (following
  Salkever, 1995).
\b\ Totals may not add up due to independent rounding.

2. Improved Ecological Conditions and Recreational Use Benefits From 
Surface Water Quality Improvements
    EPA expects the final rule will provide ecological benefits by 
improving ecosystems (aquatic and terrestrial) affected by the electric 
power industry's discharges. Benefits associated with changes in 
aquatic life include restoration of sensitive species, recovery of 
diseased species, changes in taste-and odor-producing algae, changes in 
dissolved oxygen (DO), increased assimilative capacity of affected 
waters, and improved recreational activities. Activities such as 
fishing, swimming, wildlife viewing, camping, waterfowl hunting, and 
boating may be enhanced when risks to aquatic life and perceivable 
water quality effects associated with pollutants are reduced.
    EPA was able to monetize several categories of ecological benefits 
associated with this final rule, including recreational use and nonuse 
(existence, bequest, and altruistic) benefits from improvements in the 
health of aquatic environments, and nonuse benefits from increased 
populations of threatened and endangered species. As shown in Table 
XIV-1, the Agency quantified and monetized two main benefit 
subcategories, discussed below: (1) Benefits from improvements in 
surface water quality, and (2) benefits from improved protection of 
threatened and endangered (T&E) species.
a. Improvements in Surface Water Quality
    EPA expects the final rule will improve aquatic habitats and human 
welfare by reducing concentrations of harmful pollutants such as 
arsenic, cadmium, chromium, lead, mercury, selenium, nitrogen, 
phosphorus, and suspended sediment. As a result, some of the waters 
that were not usable for recreation under the baseline discharge 
conditions may become usable following the rule, thereby benefiting 
recreational users. Waters that have been used for recreation under the 
baseline conditions can become more attractive by making recreational 
trips even more enjoyable. The final rule is also expected to generate 
nonuse benefits from bequest, altruism, and existence motivations. 
Individuals may value knowing that water quality is being maintained, 
ecosystems are being protected, and species populations are healthy, 
independent of any use.
    EPA estimates that approximately 19,600 reach miles will improve as 
a result of the final rule, as indicated by a higher post-compliance 
water quality index (WQI) score. The WQI translates water quality 
measurements, gathered for multiple parameters that are indicative of 
various aspects of water quality, into a single numerical indicator 
that reflects achievement of quality consistent with the suitability 
for certain uses.
    EPA estimated monetized benefit values using a revised version of 
the meta-regression of surface water valuation studies used in the 
benefit-cost analysis of the proposed ELGs (DCN SE03172). Using a meta-
dataset of 51 studies published between 1985 and 2011, EPA developed a 
meta-regression model that predicts how marginal willingness to pay 
(WTP) for water quality improvements depends on a variety of 
methodological, population, resource, and water quality change 
characteristics. EPA developed two versions of the meta-regression 
model: The first model (Model 1) provides a central estimate of non-
market benefits, while the second model (Model 2) provides a range of 
estimates to account for uncertainty in the resulting WTP values. 
Chapter 4 of the BCA provides more details on the meta-regression 
models and analysis.
    EPA estimated economic values of water quality improvements at the 
Census block group level. Water quality improvements are measured as a 
length-weighted average of the changes in WQI for waters within 100 
miles of the center of each Census block; these waters includes both 
waters improving as a result of the final rule and waters not affected 
by steam electric plant discharges but which may be substitutes for 
improved waters.
    EPA first estimated annual household marginal WTP values for a 
given Census block group using the meta- regression

[[Page 67879]]

models (Model 1 and Model 2) and multiplied this marginal WTP by the 
annual average water quality change for the Census block group to 
obtain the annual household WTP.
    EPA then estimated total WTP values by multiplying the annual 
household WTP values by the total number of households within a Census 
block group. EPA annualized the stream of future benefits, expressed in 
2013 dollars, using both 3 and 7 percent discount rates.
    Total national benefits are the sum of estimated Census block 
group-level WTP across all block groups for which at least one 
waterbody within 100 miles is improved.
    Average annual household WTP estimates for the final ELGs range 
from $0.32 on the low end to $1.77 on the high end, with a central 
estimate of $0.45. An estimated 84.5 million households reside in 
Census block groups within 100 miles of affected reaches. The total 
annualized benefits of water quality improvements resulting from 
reduced metal, nutrient, and sediment pollution in the approximately 
19,600 reach miles improving under the final ELGs range from $23.2 
million to $129.5 million with a central estimate of $31.3 million 
using a three percent discount rate and $18.5 million to $103.4 million 
with a central estimate of $25.1 million using a seven percent discount 
rate.
b. Benefits to Threatened and Endangered Species
    To assess the potential for impacts on T&E species (both aquatic 
and terrestrial), EPA analyzed the overlap between waters currently 
exceeding wildlife-based national recommended WQC, but expected to have 
no wildlife national recommended WQC exceedances as a result of the 
final rule, and the known critical habitat locations of approximately 
631 T&E species. EPA examined the life history traits of potentially 
affected T&E species to categorize species by the potential for 
population impacts likely to occur as a result of changes in water 
quality. Chapter 5 of the BCA Report details the methodology.
    EPA determined that of 15 species whose recovery may be enhanced by 
the final rule, three fish species and one salamander species may 
experience changes in population growth rates as a result of the final 
rule. To quantify the benefits to T&E species, EPA weighted minimal 
population growth assumptions (0.5, 1, or 1.5 percent) by the percent 
of reaches used by T&E species that are expected to meet wildlife-based 
national recommended WQC because of the final rule.
    The T&E species expected to benefit from the rule include one 
species of sturgeon and two species of minnows. All of these species 
have nonuse values, including existence, bequest, altruistic, and 
ecological service values, apart from human uses or motives. EPA 
estimated the economic values of increased T&E species populations 
using a benefit function transfer approach based on a meta-analysis of 
31 stated preference studies eliciting WTP for these changes 
(Richardson and Loomis 2009). Because the underlying metadata do not 
include amphibian valuation studies, EPA was unable to monetize any 
benefits for potential population increases of Hellbender salamander. 
EPA estimates annualized benefits to T&E species of approximately $0.02 
million, using either a three percent or seven percent discount rate.
3. Market and Productivity Benefits
a. Benefits From Reduced Magnitude of Impoundment Failures
    Operational changes that plants choose to make to meet requirements 
in the final rule may cause some plants to reduce their reliance on 
impoundments to handle their waste. EPA expects these changes to reduce 
the magnitude of impoundment failures and the resulting accidental, and 
sometimes catastrophic releases, of CCRs.
    To assess the benefits associated with changes in impoundment use, 
EPA estimated the costs associated with expected releases under 
baseline conditions (assuming no change in operations relative to 
expected operations under the CCR and CPP rules) and for projected 
reductions in the amount of CCR waste managed by impoundments. EPA 
performed the calculations for each of the 883 to 925 impoundments 
identified at steam electric power plants,\54\ and for each year 
between 2016 and 2042. EPA then calculated benefits as the difference 
between expected release costs for the final rule and expected release 
costs under baseline conditions.
---------------------------------------------------------------------------

    \54\ The 883 to 925 impoundments represent the estimated number 
of impoundments expected to operate after accounting for the 
projected effects of the CCR rule and CPP rule, relative to the 
initial universe of 1,070 impoundments located at 347 plants (out of 
the total universe of 1,080 steam electric plants). The range of 
impoundments reflects different assumptions regarding the projected 
effects of the CPP rule on impoundment operations. See Chapter 6 in 
the BCA for more information.
---------------------------------------------------------------------------

    To estimate the number of release events that may be avoided as a 
result of the ELGs, EPA followed the same approach used by EPA for its 
RIA for the CCR rule. The approach relies on estimated failure rates 
and capacity factors for two different types of releases (wall breach 
and other release) and two categories of impoundments (big and small). 
For the final steam electric ELG rule analysis, EPA used baseline 
release-rate assumptions that account for changes projected to result 
from implementation of the CCR rule. As detailed in Chapter 6 of the 
BCA Report, EPA calculated the expected costs of an impoundment 
release, including cleanup, natural resource damages (NRD),\55\ and 
transaction costs.\56\
---------------------------------------------------------------------------

    \55\ NRD include only the resource restoration and compensation 
values; they do not include cleanup costs (or legal costs).
    \56\ For this analysis, transaction 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 needed in the absence of this regulation, in the 
event of an impoundment release. Note that the transaction 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.
---------------------------------------------------------------------------

    Using the approach above, EPA estimates the annualized benefits of 
the final rule are $95.6 million to $102.9 million using a three 
percent discount rate, and $77.7 million to $83.7 million using a seven 
percent discount rate.
b. Benefits From Increased Marketability of Coal Combustion Residuals
    The final rule may enhance the ability of steam electric power 
plants to market coal combustion byproducts for beneficial use by 
converting from wet to dry handling of fly ash, bottom ash and FGD 
waste. In particular, EPA evaluated the potential benefits from the 
increased marketability of fly ash as a substitute for Portland cement 
in concrete production and fly and bottom ashes as substitutes for sand 
and gravel in fill applications. Based on the change in the quantity of 
CCRs handled dry and state-level demand for beneficial use applications 
of CCRs, EPA calculated avoided disposal costs and life-cycle benefits 
from avoiding the production of virgin materials. Chapter 10 of the BCA 
Report details the methodology.
    EPA estimates the annualized benefits of the final rule at $30.8 
million using a three percent discount rate, and $31.1 million using a 
seven percent discount rate.
4. Air-Related Benefits (Human Health and Avoided Climate Change 
Impacts)
    EPA expects the final rule to affect air pollution through three 
main mechanisms: (1) Additional auxiliary electricity use by steam 
electric power

[[Page 67880]]

plants to operate wastewater treatment, ash handling, and other 
systems, which EPA predicts that plants will use to meet the new 
effluent limitations and standards; (2) additional transportation-
related air 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 final ELGs. Changes in the profile 
of generation can result in lower or higher emissions of air pollutants 
because of variability in emission factors for different types of 
electric generating units. For this analysis, the changes in air 
emissions are based on the change in dispatch of generation units 
projected by IPM V5.13, as a result of overlaying the costs of meeting 
the final ELGs onto steam electric generating units' production costs. 
As discussed in Section IX.C.1, the IPM analysis accounts for the 
effects of other regulations affecting the electric power sector.
    EPA estimated the human health and other benefits resulting from 
net changes in air emissions of three pollutants: NOX, 
SO2, and 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, non-fatal heart attacks, 
hospital admissions, emergency department visits, upper and lower 
respiratory symptoms, acute bronchitis, aggravated asthma, lost work 
days, and acute respiratory symptoms. CO2 is a key 
greenhouse gas that is linked to a wide range of climate change 
effects.
    EPA used average benefit-per-ton 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. The calculations are based on the net changes 
in air emissions and reflect the net reductions in CO2 and 
NOX emissions during the entire period of analysis, and the 
net increase in SO2 emissions in 2023-2027, and net decline 
in SO2 emissions during the rest of the period. The values 
are specific to the years 2016, 2020, 2025, and 2030. Because they are 
almost linear as a function of year, EPA interpolated benefits per ton 
values for the intermediate years (e.g., between 2020 and 2025) and 
projected values for the years from 2031 through 2042 by linear 
regression. While extrapolating introduces some uncertainty, as it does 
not account for meteorological and air quality changes over time, this 
approach is a reasonable one, given available information.
    Chapter 7 of the BCA Report provides the details of this analysis. 
As shown in Table XIV-3, EPA estimates that the final rule will provide 
human health benefits valued at $144.7 million using a three percent 
discount rate, and $108.8 million using a seven percent discount rate. 
The rule is expected to provide air-related benefits from changes in 
CO2 emissions valued at $139.8 million, using a three 
percent discount rate.

  Table XIV-3--Annualized Benefits of Changes in NOX, SO2, and CO2 Air
                                Emissions
                            [Million 2013$]a
------------------------------------------------------------------------
                                                             7 Percent
            Benefit category                 3 Percent     discount rate
                                           discount rate         b
------------------------------------------------------------------------
Human health benefits from reduced                $144.7          $108.8
 morbidity and mortality from exposure
 to NOX, SO2 and particulate matter
 (PM2.5)................................
Avoided climate change impacts from CO2           $139.8          $139.8
 emissions \b\..........................
    Total...............................          $284.5          $248.6
------------------------------------------------------------------------
a Consistent with the assumptions used for the IPM analyses described in
  Section IX.C, EPA estimated the benefits relative to a baseline that
  includes the CPP rule.
b EPA used the SCC based on a three percent discount rate to estimate
  values presented for the seven percent discount rate. EPA uses three
  percent to discount CO2-related benefits and seven percent to discount
  benefits from changes in NOX and SO2 emissions. See Section 7.1 of the
  BCA for details on the methodology.

5. Benefits From Reduced Water Withdrawals (Increased Availability of 
Ground Water Resources)
    Steam electric power plants use water for handling 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 ELGs are expected to 
reduce water withdrawals from surface waters and reduce demand on 
aquifers, in the case of plants that rely on ground water sources.
    EPA estimated the benefits of reduced ground water withdrawals 
based on avoided costs of ground water supply. For each relevant plant, 
EPA multiplied the reduction in ground water withdrawal (in gallons per 
year) by water costs of about $1,231 per acre-foot. Chapter 8 of the 
BCA Report provides the details of this analysis. EPA estimates the 
annualized benefits of reduced ground water withdrawals are less than 
$0.1 million annually. Due to data limitations, EPA was not able to 
monetize the benefits from reduced surface water withdrawals. Chapter 8 
of the BCA Report provides additional detail on benefits from reducing 
surface water withdrawals.

C. Total Monetized Benefits

    Using the analysis approach described above, EPA estimates annual 
total benefits of the final rule for the five monetized categories at 
approximately $450.6 million to $565.6 million (at a three percent 
discount rate and $387.3 million to $478.4 million at a seven percent 
discount rate) (Table XIV-4).

  Table XIV-4--Summary of Total Annualized Monetized Benefits of Final
                                  Rule
------------------------------------------------------------------------
                                                          Annualized
                                                           monetized
                  Benefit category                    benefits  (million
                                                            2013$)
------------------------------------------------------------------------
                         3 Percent Discount Rate
------------------------------------------------------------------------
Human Health Benefits from Surface Water                  $16.5 to $17.9
 Improvements a d...................................

[[Page 67881]]

 
Improved Ecological Conditions and Recreational Uses     $23.3 to $129.5
 a b d..............................................
Market and Productivity Benefits (impoundment           $126.4 to $133.7
 failure and ash marketing).........................
Human Health Benefits from Air Quality Improvements.              $144.7
Other Air-Related Benefits (climate change).........              $139.8
Reduced Water Withdrawals...........................               <$0.1
                                                     -------------------
    Total benefits..................................    $450.6 to $565.6
------------------------------------------------------------------------
                         7 Percent Discount Rate
------------------------------------------------------------------------
Human Health Benefits from Surface Water                  $11.3 to $11.6
 Improvements a.....................................
Improved Ecological Conditions and Recreational Uses     $18.6 to $103.4
 a b................................................
Market and Productivity Benefits (impoundment           $108.8 to $114.8
 failure and ash marketing).........................
Human Health Benefits from Air Quality Improvements.              $108.8
Other Air-Related Benefits c (climate change).......              $139.8
Reduced Water Withdrawals...........................               <$0.1
                                                     -------------------
    Total benefits..................................    $387.3 to $478.4
------------------------------------------------------------------------
\a\ Values represent mean benefit estimates. Totals may not add up due
  to independent rounding.
\b\ There may be some, expected to be small, overlap between the
  willingness-to-pay (WTP) for surface water quality improvements and
  WTP for benefits to threatened and endangered species.
\c\ EPA used the SCC based on a three percent discount rate and
  discounted CO2-related benefits using a three percent discount rate,
  as compared to benefits in other categories, which are discounted
  using the seven percent discount rate.
\d\ Estimates for this benefit category do not reflect revised pollutant
  loadings, which could result in lower monetized benefits. See Section
  1.4.3 of the Benefit Cost Analysis for this rule for details.

D. Other Benefits

    The monetized benefits of this final 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 other cancer and non-cancer health benefits, reduced 
cost of drinking water treatment, avoided ground water contamination 
corrective action costs, reduced vulnerability to drought, and reduced 
aquatic species mortality from reduced surface water withdrawal. The 
BCA Report discusses these benefits qualitatively, indicating their 
potential magnitude where possible.

XV. Cost-Effectiveness Analysis

    EPA often uses cost-effectiveness analysis in the development and 
revision of ELGs to evaluate the relative efficiency of alternative 
regulatory options in removing toxic pollutants from effluent 
discharges to the nation's waters. Although not required by the CWA, 
and not a determining factor for establishing BAT and PSES, cost-
effectiveness analysis can be a useful tool for describing regulatory 
options that address toxic pollutants.

A. Methodology

    The cost-effectiveness of a regulatory option is defined as the 
incremental annual cost (in 1981 constant dollars to facilitate 
comparison to ELGs for other industrial categories promulgated over 
different years) per incremental toxic-weighted pollutant removals for 
that option. This definition includes the following concepts:
    Toxic-weighted removals. The estimated reductions in pollution 
discharges, or pollutant removals, are adjusted for toxicity by 
multiplying the estimated removal quantity for each pollutant by a 
normalizing toxic weight (toxic weighting factor). The toxic weight for 
each pollutant measures its toxicity relative to copper, with more 
toxic pollutants having higher toxic weights. The use of toxic weights 
allows the removals of different pollutants to be expressed on a 
constant toxicity basis as toxic pound-equivalents (lb-eq). In the case 
of indirect dischargers, the removal also accounts for the 
effectiveness of treatment at POTWs and reflects the toxic-weighted 
pounds remaining after POTW treatment. The cost-effectiveness analysis 
does not address the removal of conventional pollutants (e.g., TSS) or 
nutrients (nitrogen, phosphorus), nor does it address the removal of 
bulk parameters, such as COD.
    Annual costs. The costs used in the cost-effectiveness analysis are 
the estimated annualized pre-tax costs described in Section IX, 
restated in 1981 dollars as a convention to allow comparisons with the 
reported cost effectiveness of other effluent guidelines.
    The result of the cost-effectiveness calculation represents the 
unit cost (in constant 1981 dollars) of removing the next pound-
equivalent of pollutants. EPA calculates cost-effectiveness separately 
for direct and indirect dischargers. EPA notes that only three steam 
electric power plants are estimated to incur costs associated with the 
final PSES requirements, as compared to 130 plants estimated to incur 
costs associated with the final BAT requirements.
    Appendix F of the RIA details the analysis.

B. Results

    Collectively, the final BAT requirements have a cost-effectiveness 
ratio of $134/lb-eq ($1981). This cost-effectiveness ratio is well 
within the range of cost-effectiveness ratios for BAT requirements in 
other industries. A review of approximately 25 of the most recently 
promulgated or revised BAT limitations shows BAT cost-effectiveness 
ranging from less than $1/lb-eq (Inorganic Chemicals) to $404/lb-eq 
(Electrical and Electronic Components), in 1981 dollars.
    Collectively, the final PSES requirements have a cost effectiveness 
of $1,228/lb-eq ($1981). This ratio is higher than the cost-
effectiveness for PSES of other industries, which range from less than 
$1/lb-eq (Inorganic Chemicals) to $380/lb-eq (Transportation Equipment 
Cleaning), in

[[Page 67882]]

1981 dollars, based on a review of approximately 25 of the most 
recently promulgated or revised categorical pretreatment standards. As 
noted above, however, very few plants (three) are indirect dischargers 
and the cost-effectiveness for one of the three indirect dischargers 
significantly elevates the value for all three combined. EPA calculated 
costs for this plant based on a full conversion of its bottom ash 
handling system to dry handling. However, it is more likely that this 
plant would choose to implement modifications that would enable it to 
completely recycle its bottom ash transport water in order to meet the 
zero discharge standard, rather than undertake a full conversion. In 
that event, the costs to this indirect discharger--and consequently the 
cost-effectiveness value for all indirect dischargers, combined--would 
be lower.
    Collectively, cost-effectiveness for the entire rule (BAT and PSES) 
is $136/lb-eq ($1981).
    For the purposes of calculating pollutant loadings under this 
action, EPA's analysis first handled non-detect values in the reported 
data by replacing them with a value of one-half of the detection level 
for the observation that yielded the non-detect. This methodology is 
standard procedure for the ELG program as well as Clean Water Act 
assessment and permitting, Safe Drinking Water Act monitoring, and 
Resource Conservation and Recovery Act and Superfund programs; and this 
approach is consistent with previous ELGs.
    In their comments on the proposed rule, commenters raised the 
concern that for some pollutants the loadings calculations 
(particularly for bottom ash) were biased high as a result of high non-
detected values in the reported data. These high non-detected values 
were the result of not using sufficiently sensitive methods. The view 
was expressed that, should the non-detects fall significantly outside 
of the range of detected values, assigning them one half of the 
detection level would not be sufficient to accurately represent 
pollutant loadings and the associated cost-effectiveness of the rule.
    To assess this concern and provide further transparency for this 
rulemaking, EPA also implemented a second method of treating non-
detects where all attributed non-detects (i.e., one-half of the 
detection limit) that exceeded the highest detected value for a 
particular pollutant were deleted. Since it is possible that a plant's 
actual loading fell outside the range of detected values of all of the 
plants, this methodology served to place an upper bound on the effect 
of non-detects on the pollutant loading and cost-effectiveness 
calculations. EPA's decision to incorporate this second approach for 
bottom ash transport water in this rulemaking reflects the exceptional 
circumstance in this case where there are so few detected observations 
in combination with wide variability in sample-specific detection 
values for the non-detected observations for 6 analytes. For a full 
discussion of the analysis method and results, see Section 10.2.2 of 
the TDD and Section F-4 of the RIA. EPA found that this second method 
of treatment of non-detects affects the averaged pollutant 
concentrations for 6 out of the 44 analytes, alters pollutant loadings 
and decreases identified TWPE loadings and removals in comparison to 
method 1. EPA also calculated the cost-effectiveness for the bottom ash 
wastestream using the averaged pollutant concentrations derived from 
method 2, and found in comparison to method 1 the method 2 analysis 
changed the cost-effectiveness value from $314/TWPE to $457/TWPE for 
this wastestream and cost-effectiveness of the full rule from $136/TWPE 
to $149/TWPE. Where appropriate in the TDD, RIA, BCA and certain other 
documents for the rule, EPA has reflected the results for pollutant 
loadings and cost effectiveness under both of these approaches. EPA's 
determination of BAT and the standards and rationale supporting that 
determination, are discussed in Section VIII; the differences in 
loadings and cost effectiveness associated with incorporating this 
second approach to addressing uncertainty related to non-detects do not 
alter that determination.

XVI. Regulatory Implementation

A. Implementation of the Limitations and Standards

    The requirements in this rule apply to discharges from steam 
electric power plants through incorporation into NPDES permits issued 
by the EPA or authorized states under Section 402 of the Act and 
through local pretreatment programs under Section 307 of the Act. 
Permits or control mechanisms issued after this rule's effective date 
must incorporate the ELGs, as applicable. Also, under CWA section 510, 
states can 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 ELGs in this 
rule, CWA section 301(b)(1)(C) requires the permitting authority to 
impose more stringent effluent limitations, as necessary, to meet 
applicable water quality standards.
1. Timing
    The direct discharge limitations in this rule apply only when 
implemented in an NPDES permit issued to a discharger after the 
effective date of this rule. Under the CWA, the permitting authority 
must incorporate these ELGs into NPDES permits as a floor or a minimum 
level of control. While the rule is effective on its effective date 
(see DATES section at the beginning of this preamble), the rule allows 
a permitting authority to determine a date when the new effluent 
limitations for FGD wastewater, fly ash transport water, bottom ash 
transport water, FGMC wastewater, and gasification wastewater apply to 
a given discharger. The permitting authority must make these final 
effluent limitations applicable on or after November 1, 2018. For any 
final effluent limitation that is specified to become applicable after 
November 1, 2018, the specified date must be as soon as possible, but 
in no case later than December 31, 2023. For dischargers in the 
voluntary incentives program choosing to meet effluent limitations for 
FGD wastewater based on use of evaporation technology, the date for 
meeting those limitations is December 31, 2023.
    For combustion residual leachate, and for certain wastestreams (FGD 
wastewater, fly ash transport water, bottom ash transport water, FGMC 
wastewater, and gasification wastewater) at oil-fired generating units 
and small generating units (50 MW or less), the final BAT limitations 
apply on the date that a permit is issued to a discharger, following 
the effective date of this rule. The rule does not build in an 
implementation period for meeting these limitations, as the BAT 
limitation on TSS is equal to the previously promulgated BPT limitation 
on TSS.
    Pretreatment standards are self-implementing, meaning they apply 
directly, without the need for a permit. In this rule, the pretreatment 
standards for existing sources must be met by November 1, 2018.
    The requirements for new source direct and indirect discharges 
(NSPS and PSNS) provide no extended implementation period. NSPS apply 
when any NPDES permit is issued to a new source direct discharger, 
following the effective date of this rule; PSNS apply to any new source 
discharging to a POTW, as of the effective date of the final rule.
    Regardless of when a plant's NPDES permit is ready for renewal, the 
plant

[[Page 67883]]

should immediately begin evaluating how it intends to comply with the 
requirements of the final ELGs. In cases where significant changes in 
operation are appropriate, the plant should discuss such changes with 
the permitting authority and evaluate appropriate steps and a timeline 
for the changes, even prior to the permit renewal process.
    In cases where a plant's final NPDES permit will be issued after 
the effective date of the final ELGs, but before November 1, 2018, the 
permitting authority should apply limitations based on the previously 
promulgated BPT limitations or the plant's other applicable permit 
limitations until at least November 1, 2018. The permitting authority 
should also determine what date represents the soonest date, beginning 
November 1, 2018, that the plant can meet the final BAT limitations in 
this rule. The permit should require compliance with the final BAT 
limitations by that date, making clear that in no case shall the 
limitations apply later than December 31, 2023. Then, for permits that 
might be administratively continued, the final date will apply, even if 
that date is at the end of the implementation period. For permits that 
are issued on or after November 1, 2018, the permitting authority 
should determine the earliest possible date that the plant can meet the 
limitations in this rule (but in no case later than December 31, 2023), 
and apply the final limitations as of that date (BPT limitations or the 
plant's other applicable permit limitations would apply until such 
date).
    As specified by the rule, the ``as soon as possible'' date 
determined by the permitting authority is November 1, 2018, unless the 
permitting authority determines another date after receiving 
information submitted by the discharger.\57\ Assuming that the 
permitting authority receives relevant information from the discharger, 
in order to determine what date is ``as soon as possible'' within the 
implementation period, the permitting authority must then consider the 
following factors:
---------------------------------------------------------------------------

    \57\ Even after the permitting authority receives information 
from the discharger, it still may be appropriate to determine that 
November 1, 2018, is ``as soon as possible'' for that discharger.
---------------------------------------------------------------------------

    (a) Time to expeditiously plan (including to raise capital), 
design, procure, and install equipment to comply with the requirements 
of the final rule;
    (b) Changes being made or planned at the plant in response to 
greenhouse gas regulations for new or existing fossil fuel-fired power 
plants under the Clean Air Act, as well as regulations for the disposal 
of coal combustion residuals under subtitle D of the Resource 
Conservation and Recovery Act;
    (c) For FGD wastewater requirements only, an initial commissioning 
period to optimize the installed equipment; and
    (d) Other factors as appropriate.
    With respect to the first factor, the permitting authority should 
evaluate what operational changes are expected at the plant to meet the 
new BAT limitations for each wastestream, including the types of new 
treatment technologies that the plant plans to install, process changes 
anticipated, and the timeframe estimated to plan, design, procure, and 
install any relevant technologies. As specified in the second factor, 
the permitting authority must also consider scheduling for installation 
of equipment, which includes a consideration of plant changes planned 
or being made to comply with certain other key rules that affect the 
steam electric power generating industry. As specified in the third 
factor, for the FGD wastewater requirements only, the permitting 
authority must consider whether it is appropriate to allow more time 
for implementation, in addition to the three years before 
implementation of the rule begins on November 1, 2018, in order to 
ensure that the plant has appropriate time to optimize any relevant 
technologies. EPA's record demonstrates that plants installing the FGD 
technology basis spent several months optimizing its operation (initial 
commissioning period). Without allowing additional time for 
optimization, the plant would likely not be able to meet the 
limitations because they are based on the operation of optimized 
systems. See TDD Section 14 for additional discussion and examples 
regarding implementation of the final ELGs into NPDES permits.
    The ``as soon as possible'' date determined by the permitting 
authority may or may not be different for each wastestream. EPA 
recommends that the permitting authority provide a well-documented 
justification of how it determined the ``as soon as possible'' date in 
the fact sheet or administrative record for the permit. If the 
permitting authority determines a date later than November 1, 2018, the 
justification should explain why allowing additional time to meet the 
limitations is appropriate, and why the discharger cannot meet the 
final effluent limitations as of November 1, 2018. In cases where the 
plant is already operating the BAT technology basis for a specific 
wastestream (e.g., dry fly ash handling system), operates the majority 
of the BAT technology basis (e.g., FGD chemical precipitation and 
biological treatment, without sulfide addition), or expects that 
relevant treatment and process changes will be in place prior to 
November 1, 2018, it would not generally be appropriate to allow 
additional time beyond that date. Regardless, in all cases, the 
permitting authority must make clear in the permit what date the plant 
must meet the limitations, and that date may be no later than December 
31, 2023.
    Where a discharger chooses to participate in the voluntary 
incentives program and be subject to effluent limitations for FGD 
wastewater based on evaporation, the permitting authority must allow 
the plant up to December 31, 2023, to meet those limitations; again, 
the permit must make clear that the plant must meet the final 
limitations by December 31, 2023.
2. Applicability of NSPS/PSNS
    In 1982, EPA promulgated NSPS/PSNS for certain discharges from new 
sources. Those sources that were subject to the 1982 NSPS/PSNS will 
continue to be subject to such standards under this final rule. In 
addition, sources to which the 1982 NSPS/PSNS apply are also subject to 
the final BAT/PSES requirements in this rule because they will be 
existing sources with respect to such new requirements. See 40 CFR 
423.15(a) and 40 CFR 423.17(a).
3. Legacy Wastewater
    For purposes of the BAT limitations in this rule, legacy wastewater 
is FGD wastewater, fly ash transport water, bottom ash transport water, 
FGMC wastewater, and gasification wastewater generated prior to the 
date established by the permitting authority that is as soon as 
possible beginning November 1, 2018, but no later than December 31, 
2023 (see Section VIII.C.7 and Section VIII.C.8).\58\ Direct discharges 
of legacy wastewater are, under this rule, subject to BAT effluent 
limitations on TSS in such wastewater, which are equal to the existing 
BPT effluent limitations on TSS in fly ash transport water, bottom ash 
transport water, and low volume waste sources.\59\ See TDD Section 14 
for additional information regarding the legacy wastewater BAT 
limitations and

[[Page 67884]]

guidance on implementing them into NPDES permits.
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    \58\ For plants in the voluntary incentives program, legacy FGD 
wastewater is FGD wastewater generated prior to December 31, 2023 
(see Section VIII.C.13).
    \59\ The final rule does not establish PSES standards for legacy 
wastewater for these wastestreams because TSS and the pollutants 
they represent are effectively treated by POTWs; and, therefore, EPA 
has determined that they do not pass through the POTW (see Section 
VIII.E).
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4. Combined Wastestreams
    Most steam electric power plants combine various wastewaters (e.g., 
FGD wastewater, fly ash and bottom ash transport water) and cooling 
water either before or after treatment. In such cases, to derive 
effluent limitations or standards at the point of discharge, the 
permitting authority typically combines the allowable pollutant 
concentrations loadings for each set of requirements to arrive at a 
specific limitation or standard, per pollutant, for the combined 
wastestream, using the building block approach or combined waste stream 
formula (CWF). See NPDES Permit Writer's Manual and 40 CFR 403.6. For 
concentration-based limitations, rather than mass-based limitations, 
the effluent limitation or standard for the mixed wastestream is a 
flow-weighted combination of the appropriate concentration-based 
limitations or standards for each applicable wastestream. Such a 
calculation is relatively straightforward if the individual 
wastestreams are subject to limitations or standards for the same 
pollutants and the flows of the wastestreams are relatively consistent. 
This, however, is not the case for all wastestreams at steam electric 
power plants.
    Because EPA anticipates that permitting authorities will apply 
concentration-based limitations or standards, rather than mass-based 
limitations or standards, in NPDES permits for steam electric power 
plants, proper application of the building block approach or CWF is 
necessary to ensure that the reduced pollutant concentrations observed 
in a combined discharge reflect proper treatment and control strategies 
rather than dilution. Where a regulated wastestream is combined with a 
well-known dilution flow, such as cooling water, uncontaminated 
stormwater, or cooling tower blowdown, the concentration-based 
limitation for the regulated wastestream is reduced by multiplying it 
by a factor.\60\ This factor is the total flow for the combined 
wastestream minus the dilution flow divided by the total flow for the 
combined wastestream. In some cases, a wastestream (e.g., FGD 
wastewater) containing a regulated pollutant (e.g., selenium or 
mercury) combines with other wastestreams that contain the same 
pollutant, but that are not regulated for that pollutant (e.g., legacy 
wastewater contained in a surface impoundment). In these cases, based 
on the information in its record, EPA strongly recommends that in 
applying the building block approach or CWF to the regulated pollutant 
(selenium or mercury, in the example above), permitting authorities 
either treat the wastestream that does not have a limitation or 
standard for the pollutant (legacy wastewater contained in a surface 
impoundment, in the example above) as a dilution flow or determine a 
concentration for that pollutant based on representative samples of 
that wastestream.\61\
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    \60\ As is the case with a single regulated wastestream, if the 
combined wastestream is not discharged, then the limitations and 
standards are not applicable.
    \61\ EPA does not recommend that the permitting authority assume 
that the pollutant is present at a significant level in the 
wastestream that does not have a relevant limitation or standard and 
just apply the same limitation or standard for the pollutant to the 
mixed wastestream. This will not ensure that treatment and control 
strategies are being employed to achieve the limitations or 
standards, rather than simply dilution.
---------------------------------------------------------------------------

    In all cases where the permitting authority is applying the 
building block approach or CWF, except where a regulated wastestream is 
mixed with a dilution wastestream, the permitting authority must also 
determine the flow rate for use in the building block approach or CWF. 
EPA strongly recommends that the permitting authority calculate the 
flow rate based on representative flow rates for each wastestream.
    EPA recommends that, where a steam electric power plant chooses to 
combine two or more wastestreams that would call for the use of the 
building block approach or CWF to determine the appropriate limitations 
or standards for the combined wastestream, the plant should be 
responsible for providing sufficient data that reflect representative 
samples of each of the individual wastestreams that make up the 
combined wastestream. EPA strongly recommends that the representative 
samples reflect a study of each of the applicable wastestreams that 
covers the full range of variability in concentration and flow for each 
wastestream.
    EPA anticipates that proper application of the building block 
approach or CWF will result in combined wastestream limitations and 
standards that will enable steam electric power plants to combine 
certain wastestreams, while also ensuring that the plant is actually 
treating its wastewater as intended by the Act and this rule, rather 
than simply diluting it. EPA's record demonstrates, however, that 
combined wastestream limitations and standards at the point of 
discharge, derived using the building block approach or CWF, may be 
impractical or infeasible for some combined wastestreams because the 
resulting limitation or standard for any of the regulated pollutants in 
the combined wastestream would fall below analytical detection levels. 
In such cases, the permitting authority should establish internal 
limitations on the regulated wastestream, prior to mixing of the 
wastestream with others, as authorized pursuant to 40 CFR 122.45(h) and 
40 CFR 403.6.\62\ See TDD Section 14 for more examples and details 
about this guidance.
---------------------------------------------------------------------------

    \62\ As described earlier for wastestreams with zero discharge 
limitations or standards, just because a wastestream with a numeric 
limitation or standard is moved, prior to discharge, for use in 
another plant process, that does not mean that the wastestream 
ceases to be subject to the applicable numeric limitation or 
standard, assuming that the wastestream is eventually discharged.
---------------------------------------------------------------------------

5. Non-Chemical Metal Cleaning Wastes
    By reserving BAT and NSPS for non-chemical metal cleaning wastes in 
this final rule, the permitting authority must continue to establish 
such requirements based on BPJ for any steam electric power plant 
discharging this wastestream. As explained in Section VIII.I, in 
permitting this wastestream, some permitting authorities have 
classified it as non-chemical metal cleaning wastes (a subset of metal 
cleaning wastes), while others have classified it as a low volume waste 
source; NPDES permit limitations for this wastestream thus reflect that 
classification. In making future BPJ BAT determinations, EPA recommends 
that the permitting authority examine the historical permitting record 
for the particular plant to determine how discharges of non-chemical 
metal cleaning wastes have been permitted in the past. Using historical 
information and its best professional judgment, the permitting 
authority could determine that the BPJ BAT limitations should be set 
equal to existing BPT limitations or it could determine that more 
stringent BPJ BAT limitations should apply. In making a BPJ 
determination for new sources, EPA recommends that the permitting 
authority consider whether it would be appropriate to base standards on 
BPT limitations for metal cleaning wastes or on a technology that 
achieves greater pollutant reductions.

B. 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

[[Page 67885]]

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.

C. Variances and Modifications

    The CWA requires application of effluent limitations or 
pretreatment standards established pursuant to CWA section 301 to all 
direct and indirect dischargers. The statute, however, 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 Variance
    EPA can develop, with the concurrence of the state, effluent 
limitations or standards different from the otherwise applicable 
requirements for an individual existing discharger if that discharger 
is fundamentally different with respect to factors considered in 
establishing the effluent limitations guidelines or standards. Such a 
modification is known as a Fundamentally Different Factors (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 Chem. Mfrs. Ass'n v. Natural Res. Def. 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 or 403 (other than costs) from 
those considered by EPA in establishing the effluent limitations and 
standards. CWA section 301(n) also defined the conditions under which 
EPA can 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 can 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 cannot 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 can be approved only if compliance with the 
national limitations will 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 CWA 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) and 40 CFR 403.13 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 and standards. 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 or PSNS. 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. See also CWA section 301(l). 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 can 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 (ammonia, chlorine, 
color, iron, and total phenols) due to localized environmental factors. 
As this final rule does not establish limitations or standards for any 
of these pollutants, this variance is not 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 
can 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 
can 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).

[[Page 67886]]

    The U.S. 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 Natural Res. Def. Council 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 Natural Res. Def. Council 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 can be 
potentially available for the following situations:
    (1) If a 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 can 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 can 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 
40 CFR part 403, appendix G, Table II. For sewage sludge that is land 
applied, removal credits can be available for an additional two metals 
and 14 organic pollutants. For sewage sludge that is placed on a 
surface disposal unit, removal credits can be available for an 
additional seven metals and 13 organic pollutants. For sewage sludge 
that is incinerated in a sewage sludge incinerator, removal credits can 
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 can be available for any pollutant in the POTW's sewage sludge. 
40 CFR 403.7(a)(3)(iv)(C).

D. Site-Specific Water Quality-Based Effluent Limitations

    Depending on site-specific conditions and applicable state water 
quality standards, it may be appropriate for permitting authorities to 
establish water quality-based effluent limitations on bromide,\63\ 
especially where steam electric power plants are located upstream from 
drinking water intakes.
---------------------------------------------------------------------------

    \63\ Some may establish limitations on TDS as an indicator of 
bromide because bromide is a component of TDS.
---------------------------------------------------------------------------

    Bromides (a component of TDS) are not directly controlled by the 
numeric effluent limitations and standards for existing sources under 
this final rule \64\ (although they would be controlled by the NSPS/
PSNS for new sources and by the BAT effluent limitations for existing 
sources who choose to participate in the voluntary program and are 
subject to the final FGD wastewater limitations based on use of 
evaporation technology).
---------------------------------------------------------------------------

    \64\ TDS, like all pollutants, are controlled where there are 
zero discharge effluent limitations and standards.
---------------------------------------------------------------------------

    Bromide discharges from coal-fired steam electric power plants can 
occur because bromide is naturally found in coal and is released as 
particulates when the coal is burned, or by the addition of bromide 
compounds to the coal prior to burning, or to the flue gas scrubbing 
process, to reduce the amount of mercury air pollution that is also 
created when coal is burned.
    While bromide itself is not thought to be toxic at levels present 
in the environment, its reaction with other constituents in water may 
be a cause for concern now and into the future. The bromide ion in 
water can form brominated DBPs when drinking water plants treat the 
incoming source water using certain disinfection processes including 
chlorination and ozonation. Bromide can react with the ozone, chlorine, 
or chlorine-based disinfectants to form bromate and brominated and 
mixed chloro-bromo DBPs, such as trihalomethanes (THMs) or haloacetic 
acids (HAAs) (see DCN SE01920). Studies indicate that exposure to THMs 
and other DBPs from chlorinated water is associated with human bladder 
cancer (see DCN SE01981 and DCN SE01983). EPA has established the 
following MCLs for DBPs:
     0.010 mg/L for bromate due to increased cancer risk from 
long-term exposure;
     0.060 for HAAs due to increased cancer risk from long-term 
exposure; and
     0.080 mg/L for TTHMs due to increased cancer risk and 
liver, kidney or central nervous system problems from long-term 
exposure (see DCN SE01909).
    The record indicates that steam electric power plant FGD wastewater 
discharges occur near more than 100 public drinking water intakes on 
rivers and other waterbodies, and there is evidence that these 
discharges are already having adverse effects on the quality of 
drinking water sources. A 2014 study by McTigue et. al. identified four 
drinking water treatment plants that experienced increased levels of 
bromide in their source water, and corresponding increases in the 
formation of brominated DBPs, after the installation of wet FGD 
scrubbers at upstream steam electric power plants (see DCN SE04503).
    Drinking water utilities are concerned as well, noting that the 
bromide concentrations have made it increasingly difficult for them to 
meet SDWA requirements for total trihalomethanes (TTHMs) (see DCN 
SE01949). And, bromide loadings into surface waters from coal-fired 
steam electric power plants could potentially increase in the future as 
more plant operators use bromide addition to improve the control of 
mercury emissions. The American Water Works Association requested that 
EPA ``instruct NPDES permit writers to adequately consider downstream 
drinking water supplies in establishing permit requirements for power 
plant discharges'' and take other steps to limit adverse consequences 
for downstream drinking water treatment plants. EPA agrees that 
permitting authorities should carefully consider whether water quality-
based effluent limitations on bromide or TDS would be appropriate for 
FGD wastewater discharges from steam electric power plants upstream of 
drinking water intakes.

[[Page 67887]]

    EPA regulations at 40 CFR 122.44(d)(1) require that each NPDES 
permit shall include any requirements, in addition to or more stringent 
than effluent limitations guidelines or standards promulgated pursuant 
to sections 301, 304, 306, 307, 318 and 405 of the CWA, necessary to 
achieve water quality standards established under section 303 of the 
CWA, including state narrative criteria for water quality. Furthermore, 
those same regulations require that limitations must control all 
pollutants, or pollutant parameters (either conventional, 
nonconventional, or toxic pollutants) which the Director determines are 
or may be discharged at a level which will cause, have the reasonable 
potential to cause, or contribute to an excursion above any state water 
quality standard, including state narrative criteria for water quality.
    Where the DBP problem described above may be present, water 
quality-based effluent limitations for steam electric power plant 
discharges may be required under the regulations at 40 CFR 
122.44(d)(1), where necessary to meet either numeric criteria (e.g., 
for bromide, TDS or conductivity) or narrative criteria in state water 
quality standards. All states have narrative water quality criteria 
that are designed to prevent contamination and other adverse impacts to 
the states' surface waters. These are often referred to as ``free 
from'' standards. For example, a state narrative water quality 
criterion for protecting drinking water sources may require discharges 
to protect people from adverse exposure to chemicals via drinking 
water. These narrative criteria may be used to develop water quality-
based effluent limitations on a site-specific basis for the discharge 
of pollutants that impact drinking water sources, such as bromide.
    To translate state narrative water quality criteria and inform the 
development of a water quality-based limitation for bromide, it may be 
appropriate for permitting authorities to use EPA's established MCLs 
for DBPs in drinking water because the presence of bromides in drinking 
water can result in exceedances of drinking water MCLs as a result of 
interactions during drinking water treatment and disinfection 
processes. The limitation would be developed for the purpose of 
attaining and maintaining the state's applicable narrative water 
quality criterion or criteria and protecting the state's designated 
use(s), including the protection of human health. See 40 CFR 
122.44(d)(1)(vi).
    For the reasons described above, during development of the NPDES 
permit for the steam electric power plant, the permitting authority 
should provide notification to any downstream drinking water treatment 
plants of the discharge of bromide. EPA recommends that the permitting 
authority collaborate with drinking water utilities and their 
regulators to determine what concentration of bromides at the PWS 
intake is needed to ensure that levels of bromate and DPBs do not 
exceed applicable MCLs. The maximum level of bromide in source waters 
at the intake that does not result in an exceedance of the MCL for DBPs 
is the numeric interpretation of the narrative criterion for protection 
of human health and may vary depending on the treatment processes 
employed at the drinking water treatment facility. The permitting 
authority would then determine the level of bromide that may be 
discharged from the steam electric power plant, taking into account 
other sources of bromide that may occur, such that the level of bromide 
downstream at the intake to the drinking water utility is below a level 
that would result in an exceedances of the applicable MCLs for DBPs. In 
addition, applicants for NPDES permits must, as part of their permit 
application, indicate whether they know or have reason to believe that 
conventional and/or nonconventional pollutants listed in Table IV of 
Appendix D to 40 CFR part 122, (which includes bromide), are discharged 
from each outfall. For every pollutant in Table IV of Appendix D 
discharged which is not limited in an applicable effluent limitations 
guideline, the applicant must either report quantitative data or 
briefly describe the reasons the pollutant is expected to be discharged 
as set forth in 40 CFR 122.2l(g)(7)(vi)(A), made applicable to the 
States at 40 CFR 123.25(a)(4).
    In addition to requiring the permit applicant to provide a complete 
application, including proper wastewater characterization, when issuing 
the permit, the permitting authority can incorporate appropriate 
monitoring and reporting requirements, as authorized under section 
402(a)(2), 33 U.S.C. 1342(a)(2), and implementing regulations at 40 CFR 
122.48, 122.44(i), 122.43 and 122.41(1)(4). These requirements apply to 
all dischargers and include plants that have identified the presence of 
bromide in effluent in significant quantities and that are in proximity 
to downstream water treatment plants.

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

    This action is an economically significant regulatory action that 
was submitted to the Office of Management and Budget (OMB) for review. 
Any changes made in response to OMB recommendations have been 
documented in the docket. EPA prepared an analysis of the potential 
costs and benefits associated with this action. This analysis is 
contained in Chapter 13 of the BCA Report, available in the docket.
    Table XVII-1 (drawn from Table 13-1 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 three percent discount 
rate.

Table XVII-1--Total Monetized Annualized Benefits and Costs of the Final
                              BAT and PSES
           [Millions, 2013$, three percent discount rate] \a\
------------------------------------------------------------------------
                                  Total social costs    Total monetized
                                          \b\              benefits
------------------------------------------------------------------------
Annualized Value................             $479.5    $450.6 to $565.6
------------------------------------------------------------------------
\a\ All costs and benefits were annualized over 24 years and using a
  three percent discount rate.
\b\ Total social costs include compliance costs to facilities.

B. Paperwork Reduction Act

    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.

[[Page 67888]]

    EPA estimated small changes in monitoring costs at steam electric 
power plants for metals in the final rule; EPA accounted for these 
costs as part of its analysis of the economic impacts. Plants, however, 
will also realize certain savings by no longer monitoring effluent that 
would cease to exist under the final rule. The net changes in 
monitoring and reporting are expected to be minimal, and EPA determined 
that the existing burden estimates appropriately reflect any final rule 
burden associated with monitoring.
    Based on the information in its record, EPA does not expect the 
final rule to increase costs to permitting authorities. The rule will 
not change permit application requirements or the associated review; it 
will not increase the number of permits issued to steam electric power 
plants; nor does it increase the efforts involved in developing or 
reviewing such permits. In fact, the final rule will reduce the burden 
to permitting authorities. In the absence of nationally applicable BAT 
requirements, as appropriate, permitting authorities must establish 
technology-based effluent limitations using BPJ to establish site-
specific requirements based on information submitted by the discharger. 
Permitting authorities that establish technology-based effluent 
limitations on a BPJ basis often spend significant time, effort, and 
resources doing so, and dischargers may expend significant resources 
providing associated data and information. Establishing nationally 
applicable BAT requirements that eliminate the need to develop BPJ-
based limitations makes permitting easier and less costly in this 
respect.
    As explained in Section XVI.A, under this rule, after the 
permitting authority receives information from the discharger, it must 
determine, on a facility-specific basis, what date is ``as soon as 
possible'' during the period beginning November 1, 2018, and ending 
December 31, 2023. This one-time burden to the discharger and the 
permitting authority, however, is no more excessive than the existing 
burden associated with developing technology-based effluent limitations 
on a BPJ basis; in fact, it is very likely less burdensome. 
Nevertheless, EPA conservatively estimated no net change (increase or 
decrease) in the cost burden to federal or state governments or 
dischargers associated with this final rule.

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.
    I certify that this action will not have a significant economic 
impact on a substantial number of small entities under the RFA. The 
basis for this finding is documented in Chapter 8 of the RIA included 
in the docket and summarized below. EPA estimates that 243 to 507 
entities own steam electric power plants to which the ELGs apply, of 
which 110 to 191 entities are small (see Table XVII-2).

             Table XVII-2--Number of Entities Owning Steam Electric Power Plants by Sector and Size
                                  [Assuming two different ownership cases] \a\
----------------------------------------------------------------------------------------------------------------
                                           Lower bound estimate of number of   Upper bound estimate of number of
                                            entities owning steam electric      entities owning steam electric
             Ownership type                        power plants \b\                    power plants \b\
                                         -----------------------------------------------------------------------
                                             Total     Small \c\    % Small      Total     Small \c\    % Small
----------------------------------------------------------------------------------------------------------------
Investor-Owned Utilities................          97          28        28.9         244          66        27.1
Nonutilities............................          36          19        52.8          77          35        46.1
Cooperatives............................          29          26        89.7          49          46        93.9
Municipality............................          65          36        55.4         101          43        42.1
Other Political Subdivision.............          12           1         8.3          30           1         3.3
Federal.................................           0           0         N/A           0           0         N/A
State...................................           2           0         0.0           2           0         0.0
Tribal..................................           0           0         N/A           0           0         N/A
                                         -----------------------------------------------------------------------
    All Entity Types....................         243         110        45.3         507         191        37.6
----------------------------------------------------------------------------------------------------------------
\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, 75 entities, 21 of which are small, own steam electric power plants that are expected to incur
  compliance costs under the final rule under both Case 1 and Case 2.
\c\ EPA was unable to determine size for 16 parent entities; for this analysis, these entities are assumed to be
  small.

    To assess whether small entities' compliance costs might constitute 
a significant impact, EPA summed annualized compliance costs for the 
steam electric power 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 one percent and three percent of revenue. Small 
entities estimated to incur compliance costs exceeding one or more of 
the one percent and three percent impact thresholds were identified as 
potentially incurring a significant impact.
    EPA notes that setting the BAT limitations for FGD wastewater, fly 
ash transport water, bottom ash transport water, FGMC wastewater, and 
gasification wastewater equal to the BPT limitations on TSS in fly ash 
transport water, bottom ash transport water, and low volume waste 
sources at existing generating units with a total nameplate generating 
capacity of 50 MW or less (as discussed in Section VIII.C.12) reduces 
the potential impacts of the rule on small entities and municipalities. 
The rulemaking record indicates that establishing a size threshold of 
50 MW or less preferentially minimizes some of the expected economic 
impacts on municipalities and small entities.
    Table XVII-3 presents the estimated numbers of small entities 
incurring costs exceeding one percent and three percent of revenue, by 
ownership type.

[[Page 67889]]



                 Table XVII-3--Estimated Cost-to-Revenue Impact on Small Entities Owning Steam Electric Power Plants, by Ownership Type
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                   Lower bound estimate of number of entities owning   Upper bound estimate of number of entities owning
                                                              steam electric power plants                         steam electric power plants
                                                 -------------------------------------------------------------------------------------------------------
                                                    Cost >=1% of revenue      Cost >=3% of revenue      Cost >=1% of revenue      Cost >=3% of revenue
                                                 -------------------------------------------------------------------------------------------------------
                                                                % of small   Number of    % of small                % of small   Number of    % of small
                                                   Number of     affected      small       affected    Number of     affected      small       affected
                                                     small       entities     entities     entities      small       entities     entities     entities
                                                    entities       \b\          \a\          \b\        entities       \b\          \a\          \b\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Ownership Type..................................            Out of total 110 small entities
                                                            Out of total 191 small entities
                                                 -------------------------------------------------------------------------------------------------------
Cooperative.....................................            1          3.8            0          0.0            1          2.2            0          0.0
Investor-Owned..................................            0          0.0            0          0.0            0          0.0            0          0.0
Municipality....................................            4         11.1            1          2.8            4          9.4            1          2.3
Nonutility......................................            1          5.3            0          0.0            1          2.8            0          0.0
Other Political Subdivision.....................            0          0.0            0          0.0            0          0.0            0          0.0
                                                 -------------------------------------------------------------------------------------------------------
    Total.......................................            6          5.5            1          0.9            6          3.1            1          0.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ The number of entities with cost-to-revenue ratios exceeding three percent is a subset of the number of entities with such ratios exceeding one
  percent.
\b\ Percentage values were calculated relative to the total of 110 (Case 1) and 191 (Case 2) small entities owning steam electric power 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 power plants. See RIA Chapter 8 for details.

    As reported in Table XVII-3, EPA estimates that six small entities 
owning steam electric power plants (one cooperative, one nonutility, 
and four municipalities) will incur costs exceeding one percent of 
revenue as a result of the final rule, and one small municipality 
owning steam electric power plants will incur costs exceeding three 
percent of revenue. The numbers of small entities incurring costs 
exceeding either the one or three percent of revenue impact threshold 
are small in the absolute and represent small percentages of the total 
estimated number of small entities, which supports EPA's finding of no 
significant impact on a substantial number of small entities (No 
SISNOSE).

D. Unfunded Mandates Reform Act

    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 
action contains a federal mandate that may result in expenditures of 
$100 million or more (annually, adjusted for inflation) for state, 
local, and tribal governments, in the aggregate, or the private sector 
in any one year ($141 million in 2013). Accordingly, EPA prepared a 
written statement required under section 202 of UMRA. The statement is 
included in the docket for this action (see Chapter 9 in the RIA 
report) and briefly summarized here.
    Consistent with the intergovernmental consultation provisions of 
UMRA section 204, EPA consulted with governmental entities affected by 
this rule. EPA described the government-to-government dialogue leading 
to the proposed rule in its preamble to the proposed rulemaking. EPA 
received comments from state and local government representatives in 
response to the proposed rule and considered this input in developing 
the final rule.
    Consistent with UMRA section 205, EPA identified and analyzed a 
reasonable number of regulatory alternatives to determine BAT/BADCT. 
Section VIII of this preamble describes the options.
    This action is not subject to the requirements of UMRA section 203 
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 (governments for 
populations 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 and for small non-government-
owned facilities. On this basis, EPA concluded that the final rule does 
not significantly or uniquely affect small governments.

E. Executive Order 13132: Federalism

    Under Executive Order (E.O.) 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 action.
    This action has 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.
    EPA anticipates that this final rule will not impose incremental 
administrative burden on states from issuing, reviewing, and overseeing 
compliance with discharge requirements. However, EPA has identified 168 
steam electric power plants owned by state or local government 
entities, out of which 16 plants are estimated to incur costs to meet 
the limitations. EPA estimates that the maximum aggregate compliance 
cost in any one year to governments (excluding the federal government) 
is $171.4 million (see Chapter 9 of the RIA report for details). Based 
on this information, this 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 E.O. 13132.

[[Page 67890]]

    EPA consulted with elected state and local officials or their 
representative national organizations early in the process of 
developing the rule to ensure their meaningful and timely input into 
its development. The preamble to the proposed rule described these 
consultations, which included a briefing on October 11, 2011, attended 
by representatives from the National League of Cities, the National 
Conference of State Legislatures, the National Association of Counties, 
the National Association of Towns and Townships, the U.S. Conference of 
Mayors, the Council of State Governments, the County Executives of 
America, and the Environmental Council of the States. Policy and 
professional groups such as the National Rural Electric Cooperative 
Association, America's Clean Water Agencies, and the American Public 
Power Association also participated in the briefing, as did 
environmental and natural resource policy staff representing nine state 
agencies and approximately 25 local governments and/or utilities. The 
participants asked questions and raised comments during the meeting. In 
response to the Agency's request for pre-proposal written submittals 
within eight weeks of the briefing, EPA received separate written 
submittals regarding the technology options, pollutant removal 
effectiveness, costs of specific technologies and overall costs, 
impacts on small generating units and on small governments, among 
others. EPA carefully considered these comments in developing the 
proposed rule.
    EPA received comment on the proposed ELGs from 31 state and local 
officials or their representatives. Some state and local officials 
expressed concerns EPA had underestimated the costs and overstated the 
pollutant removals of the technology options. They stated that the ELGs 
would impose significant costs on small entities, and would result in 
electricity rate increases that are unaffordable for households. They 
also stated that small municipal systems typically operate smaller 
units with disproportionally greater compliance costs as compared to 
larger units. Commenters also expressed concern about coordination of 
the CCR and ELG rules, the potential premature retirement of coal-fired 
units with limited remaining life, and potential downtime during 
retrofits. Finally, some commenters asked that EPA allow more time to 
phase-in the requirements. Other state and local officials supported 
revisions of the ELGs and generally opposed reliance on BPJ as a basis 
for establishing limitations for FGD wastewater. EPA considered these 
comments in developing the final rule. A list of the state and local 
government commenters has been provided to OMB and has been placed in 
the docket for this rulemaking. In addition, the detailed response to 
comments from these entities is contained in EPA's response to comments 
document on this final rulemaking, which has also been placed in the 
docket for this rulemaking.
    As explained in Section VIII, the final rule establishes different 
BAT/PSES requirements for oil-fired generating units and units of 50 MW 
or less. These different requirements alleviate some of the concerns 
raised by state and local government representatives by reducing the 
number of government entities incurring costs to meet the ELG 
requirements. The implementation schedule described in Section XVI 
gives time to facilities to make changes to their operations to meet 
the final effluent limitations. Moreover, the rule does not rely on BPJ 
determinations for establishment of FGD wastewater limitations or 
standards. Finally, as explained in Section IX, EPA's analysis 
demonstrates that the requirements are economically achievable for the 
steam electric industry as a whole, including plants owned by state or 
local government entities.

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

    This action does not have tribal implications, as specified in E.O. 
13175 (65 FR 67249, November 9, 2000). It will not have substantial 
direct effects on tribal governments, on the relationship between the 
federal government and the Indian tribes, or on the distribution of 
power and responsibilities between the Federal government and Indian 
tribes, as specified in E.O. 13175. EPA's analyses show that tribal 
governments do not own any facility to which the ELGs apply. Thus, E.O. 
13175 does not apply to this action.
    Although E.O. 13175 does not apply to this action, EPA consulted 
with federally recognized tribal officials under EPA's Policy on 
Consultation and Coordination with Indian tribes early in the process 
of developing this rule to enable them to have meaningful and timely 
input into its development. EPA initiated consultation and coordination 
with federally recognized tribal governments in August 2011. EPA shared 
information about the steam electric effluent guidelines rulemaking in 
discussions with the National Tribal Caucus and the National Tribal 
Water Council. EPA continued this government-to-government dialogue by 
mailing a consultation notification letter to tribal leaders, and on 
March 28, 2012, held a tribal consultation conference call with tribal 
representatives about the rulemaking process and objectives, with a 
focus on identifying specific ways that the rulemaking may affect 
tribes. Representatives from one tribe provided input to the rule. EPA 
considered input from tribal representatives in developing this final 
rule.

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

    This action is not subject to E.O. 13045 (62 FR 19885, April 23, 
1997) because the EPA does not expect that the environmental health 
risks or safety risks addressed by this action present a 
disproportionate risk to children. This action's health and risk 
assessments are contained in Chapter 3 of the BCA Report and summarized 
below.
    As described in Section XIV.B.1, EPA assessed whether the final 
rule will benefit children by reducing health risk from exposure to 
steam electric pollutants from consumption of contaminated fish and 
improving recreational opportunities. The Agency was able to quantify 
two categories of benefits specific to children: (1) Avoided 
neurological damage to preschool 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 levels of lead in the blood 
above 20 mg/dL.
    EPA estimated the IQ-related benefits associated with reduced in 
utero mercury exposure from maternal fish consumption in exposed 
populations. Among approximately 418,953 babies born per year who are 
potentially exposed to discharges of mercury from steam electric power 
plants, the final rule reduces total IQ point losses over the period of 
2019 through 2042 by about 7,219 points. The monetary benefits 
associated with the avoided IQ point losses are $3.5 million per year 
(mean estimate, at three percent discount rate).
    EPA's analysis also shows annualized benefits to children from 
reduced lead discharges of approximately $1.0 million (at three percent 
discount rate).
    EPA identified additional benefits to children, such as reduced 
exposure to

[[Page 67891]]

lead and the resultant neurological and cognitive damages in children 
over the age of seven, as well as other adverse health effects.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution, or Use

    This action is not a ``significant energy action,'' as defined by 
E.O. 13211 (66 FR 28355, May 22, 2001) because it is not likely to have 
a significant adverse effect on the supply, distribution, or use of 
energy.
    The Agency analyzed the potential energy effects of these ELGs. The 
potentially significant effects of this rule on energy supply, 
distribution, or use concern the electric power sector. EPA found that 
the final rule will not cause effects in the electric power sector that 
constitute a significant adverse effect under E.O. 13211. Namely, the 
Agency found that this rule does not reduce electricity production in 
excess of 1 billion kilowatt hours per year or in excess of 500 
megawatts of installed capacity, and therefore does not constitute a 
significant regulatory action under E.O. 13211.
    For more detail on the potential energy effects of this final rule, 
see Chapter 10 in the RIA report.

I. National Technology Transfer and Advancement Act

    This rulemaking does not involve technical standards.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    E.O. 12898 (59 FR 7629, Feb. 16, 1994) establishes federal 
executive policy on environmental justice. Its main provision directs 
federal agencies, to the greatest extent practicable and permitted by 
law, to make environmental justice part of their mission by identifying 
and addressing, as appropriate, disproportionately high and adverse 
human health or environmental effects of their programs, policies, and 
activities on minority populations and low-income populations in the 
U.S.
    EPA determined that the human health or environmental risk 
addressed by this action will not have potential disproportionately 
high and adverse human health or environmental effects on minority, 
low-income, or indigenous populations. The results of this evaluation 
are contained in Chapter 14 of the BCA Report, available in the docket.
    To meet the objectives of E.O. 12898, EPA examined whether the rule 
creates potential environmental justice concerns in the areas affected 
by steam electric power plant discharges. The Agency analyzed the 
demographic characteristics of the populations who live in proximity to 
steam electric power plants and who may be exposed to pollutants in 
steam electric power plant discharges (populations who consume 
recreationally caught fish from affected reaches) to determine whether 
minority and or low-income populations are subject to disproportionally 
high environmental impacts.
    EPA conducted the analysis in two ways. First, EPA compared 
demographic data for populations living in proximity to steam electric 
power plants to demographic characteristics at the state and national 
levels. This analysis focuses on the spatial distribution of minority 
and low-income groups to determine whether these groups are more or 
less represented in the populations that are expected to benefit from 
the final rule, based on their proximity to steam electric power 
plants. This analysis shows that approximately 450,000 people reside 
within one mile of a steam electric power plant currently discharging 
to surface waters and 2.7 million people reside within three miles. A 
greater fraction of the populations living in such proximity to the 
plants has income below the poverty threshold (16.4 and 15.3 percent, 
respectively for populations within one and three miles) than the 
national average (13.9 percent).
    Second, EPA conducted analyses of populations exposed to steam 
electric power plant discharges through consumption of recreationally 
caught fish by estimating exposure and health effects by demographic 
cohort. Where possible, EPA used analytic assumptions specific to the 
demographic cohorts--e.g., fish consumption rates specific to different 
racial groups. The results show that this final rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because, in fact, it 
increases the level of environmental protection (reduces adverse human 
health and environmental effects) for all affected populations, 
including minority and low-income populations. Furthermore, EPA 
estimated that minority and low-income populations will receive, 
proportionately, more of the human health benefits associated with the 
final rule.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule 
report to each House of the Congress and to the Comptroller General of 
the United States. This action is a ``major rule'' as defined by 5 
U.S.C. 804(2).

Appendix A to the Preamble: Definitions, Acronyms, and Abbreviations 
Used in This Preamble

    The following acronyms and abbreviations are used in this 
preamble.
    Administrator. The Administrator of the U.S. Environmental 
Protection Agency.
    Agency. U.S. Environmental Protection Agency.
    BAT. Best available technology economically achievable, as 
defined by CWA sections 301(b)(2)(A) and 304(b)(2)(B).
    BCT. The best conventional pollutant control technology 
applicable to discharges of conventional pollutants from existing 
industrial point sources, as defined by sections 301(b)(2)(E) and 
304(b)(4) of the CWA.
    Bioaccumulation. General term describing a process by which 
chemicals are taken up by an organism either directly from exposure 
to a contaminated medium or by consumption of food containing the 
chemical, resulting in a net accumulation of the chemical by an 
organism due to uptake from all routes of exposure.
    BMP. Best management practice.
    Bottom ash. The ash, including boiler slag, which settles in the 
furnace or is dislodged from furnace walls. Economizer ash is 
included when it is collected with bottom ash.
    BPT. The best practicable control technology currently available 
as defined by sections 301(b)(1) and 304(b)(1) of the CWA.
    CBI. Confidential Business Information.
    CCR. Coal Combustion Residuals.
    Clean Water Act (CWA). The Federal Water Pollution Control Act 
Amendments of 1972 (33 U.S.C. 1251 et seq.), as amended, e.g., by 
the Clean Water Act of 1977 (Pub. L. 95-217), and the Water Quality 
Act of 1987 (Pub. L. 100-4).
    Combustion residuals. Solid wastes associated with combustion-
related power plant processes, including fly and bottom ash from 
coal-, petroleum coke-, or oil-fired units; FGD solids; FGMC wastes; 
and other wastewater treatment solids associated with combustion 
wastewater. In addition to the residuals that are associated with 
coal combustion, this also includes residuals associated with the 
combustion of other fossil fuels.
    Combustion residual leachate. Leachate from landfills or surface 
impoundments containing combustion residuals. Leachate is composed 
of liquid, including any suspended or dissolved constituents in the 
liquid, that has percolated through waste or other materials 
emplaced in a landfill, or that passes through the surface 
impoundment's containment structure (e.g., bottom, dikes, and 
berms). Combustion residual leachate includes seepage and/or leakage 
from a combustion residual landfill or impoundment unit. Combustion 
residual

[[Page 67892]]

leachate includes wastewater from landfills and surface impoundments 
located on non-adjoining property when under the operational control 
of the permitted facility.
    Direct discharge. (a) Any addition of any ``pollutant'' or 
combination of pollutants to ``waters of the United States'' from 
any ``point source,'' or (b) any addition of any pollutant or 
combination of pollutant to waters of the ``contiguous zone'' or the 
ocean from any point source other than a vessel or other floating 
craft which is being used as a means of transportation. This 
definition includes additions of pollutants into waters of the 
United States from: Surface runoff which is collected or channeled 
by man; discharges though pipes, sewers, or other conveyances owned 
by a State, municipality, or other person which do not lead to a 
treatment works; and discharges through pipes, sewers, or other 
conveyances, leading into privately owned treatment works. This term 
does not include an addition of pollutants by any ``indirect 
discharger.''
    Direct discharger. A facility that discharges treated or 
untreated wastewaters into waters of the U.S.
    DOE. Department of Energy.
    Dry bottom ash handling system. A system that does not use water 
as the transport medium to convey bottom ash away from the boiler. 
It includes systems that collect and convey the ash without any use 
of water, as well as systems in which bottom ash is quenched in a 
water bath and then mechanically or pneumatically conveyed away from 
the boiler. Dry bottom ash handling systems do not include wet 
sluicing systems (such as remote MDS or complete recycle systems).
    Dry fly ash handling system. A system that does not use water as 
the transport medium to convey fly ash away from particulate 
collection equipment.
    Effluent limitation. Under CWA section 502(11), any restriction, 
including schedules of compliance, established by a state or the 
Administrator on quantities, rates, and concentrations of chemical, 
physical, biological, and other constituents which are discharged 
from point sources into navigable waters, the waters of the 
contiguous zone, or the ocean, including schedules of compliance.
    EIA. Energy Information Administration.
    ELGs. Effluent limitations guidelines and standards.
    EO. Executive Order.
    EPA. U.S. Environmental Protection Agency.
    ESP. Electrostatic precipitator.
    Facility. Any NPDES ``point source'' or any other facility or 
activity (including land or appurtenances thereto) that is subject 
to regulation under the NPDES program.
    FGD. Flue gas desulfurization.
    FGD Wastewater. Wastewater generated specifically from the wet 
flue gas desulfurization scrubber system that comes into contact 
with the flue gas or the FGD solids, including but not limited to, 
the blowdown or purge from the FGD scrubber system, overflow or 
underflow from the solids separation process, FGD solids wash water, 
and the filtrate from the solids dewatering process. Wastewater 
generated from cleaning the FGD scrubber, cleaning FGD solids 
separation equipment, cleaning FGD solids dewatering equipment, or 
that is collected in floor drains in the FGD process area is not 
considered FGD wastewater.
    FGD gypsum. Gypsum generated specifically from the wet FGD 
scrubber system, including any solids separation or solids 
dewatering processes.
    FGMC. Flue gas mercury control.
    FGMC System. An air pollution control system installed or 
operated for the purpose of removing mercury from flue gas.
    Flue Gas Mercury Control Wastewater. Wastewater generated from 
an air pollution control system installed or operated for the 
purpose of removing mercury from flue gas. This includes fly ash 
collection systems when the particulate control system follows 
sorbent injection or other controls to remove mercury from flue gas. 
FGD wastewater generated at plants using oxidizing agents to remove 
mercury in the FGD system and not in a separate FGMC system is not 
included in this definition.
    Fly Ash. The ash that is carried out of the furnace by a gas 
stream and collected by a capture device such as a mechanical 
precipitator, electrostatic precipitator, and/or fabric filter. 
Economizer ash is included in this definition when it is collected 
with fly ash. Ash is not included in this definition when it is 
collected in wet scrubber air pollution control systems whose 
primary purpose is particulate removal.
    Gasification Wastewater. Any wastewater generated at an 
integrated gasification combined cycle operation from the gasifier 
or the syngas cleaning, combustion, and cooling processes. 
Gasification wastewater includes, but is not limited to the 
following: Sour/grey water; CO2/steam stripper 
wastewater; sulfur recovery unit blowdown, and wastewater resulting 
from slag handling or fly ash handling, particulate removal, halogen 
removal, or trace organic removal. Air separation unit blowdown, 
noncontact cooling water, and runoff from fuel and/or byproduct 
piles are not considered gasification wastewater. Wastewater that is 
collected intermittently in floor drains in the gasification process 
areas from leaks, spills and cleaning occurring during normal 
operation of the gasification operation is not considered 
gasification wastewater.
    Ground water. Water that is found in the saturated part of the 
ground underneath the land surface.
    IGCC. Integrated gasification combined cycle.
    Indirect discharge. Wastewater discharged or otherwise 
introduced to a POTW.
    IPM. Integrated Planning Model.
    Landfill. A disposal facility or part of a facility where solid 
waste, sludges, or other process residuals are placed in or on any 
natural or manmade formation in the earth for disposal and which is 
not a storage pile, a land treatment facility, a surface 
impoundment, an underground injection well, a salt dome or salt bed 
formation, an underground mine, a cave, or a corrective action 
management unit.
    Low Volume Waste Sources. Taken collectively as if from one 
source, wastewater from all sources except those for which specific 
limitations or standards are otherwise established in this part. Low 
volume waste sources include, but are not limited to, the following: 
Wastewaters from ion exchange water treatment systems, water 
treatment evaporator blowdown, laboratory and sampling streams, 
boiler blowdown, floor drains, cooling tower basin cleaning wastes, 
recirculating house service water systems, and wet scrubber air 
pollution control systems whose primary purpose is particulate 
removal. Sanitary wastes, air conditioning wastes, and wastewater 
from carbon capture or sequestration systems are not included in 
this definition.
    MDS. Mechanical drag system.
    Mechanical drag system. Bottom ash handling system that collects 
bottom ash from the bottom of the boiler in a water-filled trough. 
The water bath in the trough quenches the hot bottom ash as it falls 
from the boiler and seals the boiler gases. A drag chain operates in 
a continuous loop to drag bottom ash from the water trough up an 
incline, which dewaters the bottom ash by gravity, draining the 
water back to the trough as the bottom ash moves upward. The 
dewatered bottom ash is often conveyed to a nearby collection area, 
such as a small bunker outside the boiler building, from which it is 
loaded onto trucks and either sold or transported to a landfill. The 
MDS is considered a dry bottom ash handling system because the ash 
transport mechanism is mechanical removal by the drag chain, not the 
water.
    Metal cleaning wastes. Any wastewater resulting from cleaning 
[with or without chemical cleaning compounds] any metal process 
equipment including, but not limited to, boiler tube cleaning, 
boiler fireside cleaning, and air preheater cleaning.
    Mortality. Death rate or proportion of deaths in a population.
    NAICS. North American Industry Classification System.
    NPDES. National Pollutant Discharge Elimination System.
    NSPS. New Source Performance Standards.
    Oil-fired unit. A generating unit that uses oil as the primary 
or secondary fuel source and does not use a gasification process or 
any coal or petroleum coke as a fuel source. This definition does 
not include units that use oil only for start up or flame-
stabilization purposes.
    ORCR. Office of Resource Conservation and Recovery.
    Point source. Any discernable, confined, and discrete 
conveyance, including but not limited to, any pipe, ditch, channel, 
tunnel, conduit, well, discrete fissure, container, rolling stock, 
concentrated animal feeding operation, or vessel or other floating 
craft from which pollutants are or may be discharged. The term does 
not include agricultural stormwater discharges or return flows from 
irrigated agriculture. See CWA section 502(14), 33 U.S.C. 1362(14); 
40 CFR 122.2.
    POTW. Publicly owned treatment works. See CWA section 212, 33 
U.S.C. 1292; 40 CFR 122.2, 403.3
    Primary particulate collection system. The first place in the 
process where fly ash is collected, such as collection at an ESP or

[[Page 67893]]

baghouse. For example, a coal combustion particulate collection 
system may include multiple steps including a primary particulate 
collection step such as ESP followed by other processes such as a 
fabric filter which would constitute a secondary particulate 
collection system.
    PSES. Pretreatment Standards for Existing Sources.
    PSNS. Pretreatment Standards for New Sources.
    Publicly Owned Treatment Works. Any device or system, owned by a 
state or municipality, used in the treatment (including recycling 
and reclamation) of municipal sewage or industrial wastes of a 
liquid nature that is owned by a state or municipality. This 
includes sewers, pipes, or other conveyances only if they convey 
wastewater to a POTW providing treatment. See CWA section 212, 33 
U.S.C. 1292; 40 CFR 122.2, 403.3.
    RCRA. The Resource Conservation and Recovery Act of 1976, 42 
U.S.C. 6901 et seq.
    Remote MDS. Bottom ash handling system that collects bottom ash 
at the bottom of the boiler, then uses transport water to sluice the 
ash to a remote MDS that dewaters bottom ash using a similar 
configuration as the MDS. The remote MDS is considered a wet bottom 
ash handling system because the ash transport mechanism is water.
    RFA. Regulatory Flexibility Act.
    SBA. Small Business Administration.
    Sediment. Particulate matter lying below water.
    Steam electric power plant wastewater. Wastewaters associated 
with or resulting from the combustion process, including ash 
transport water from coal-, petroleum coke-, or oil-fired units; air 
pollution control wastewater (e.g., FGD wastewater, FGMC wastewater, 
carbon capture wastewater); and leachate from landfills or surface 
impoundments containing combustion residuals.
    Surface water. All waters of the United States, including 
rivers, streams, lakes, reservoirs, and seas.
    Toxic pollutants. As identified under the CWA, 65 pollutants and 
classes of pollutants, of which 126 specific substances have been 
designated priority toxic pollutants. See appendix A to 40 CFR part 
423.
    Transport water. Wastewater that is used to convey fly ash, 
bottom ash, or economizer ash from the ash collection or storage 
equipment, or boiler, and has direct contact with the ash. Transport 
water does not include low volume, short duration discharges of 
wastewater from minor leaks (e.g., leaks from valve packing, pipe 
flanges, or piping) or minor maintenance events (e.g., replacement 
of valves or pipe sections).
    UMRA. Unfunded Mandates Reform Act.
    Wet bottom ash handling system. A system in which bottom ash is 
conveyed away from the boiler using water as a transport medium. Wet 
bottom ash systems typically send the ash slurry to dewatering bins 
or a surface impoundment. Wet bottom ash handling systems include 
systems that operate in conjunction with a traditional wet sluicing 
system to recycle all bottom ash transport water (remote MDS or 
complete recycle system).
    Wet FGD system. Wet FGD systems capture sulfur dioxide from the 
flue gas using a sorbent that has mixed with water to form a wet 
slurry, and that generates a water stream that exits the FGD 
scrubber absorber.
    Wet fly ash handling system. A system that conveys fly ash away 
from particulate removal equipment using water as a transport 
medium. Wet fly ash systems typically dispose of the ash slurry in a 
surface impoundment.

List of Subjects in 40 CFR Part 423

    Environmental protection, Electric power generation, Power plants, 
Waste treatment and disposal, Water pollution control.

    Dated: September 30, 2015.
Gina McCarthy,
Administrator.

    Therefore, 40 CFR Chapter I is amended as follows:

PART 423--STEAM ELECTRIC POWER GENERATING POINT SOURCE CATEGORY

0
1. The authority citation for part 423 is revised to read as follows:

    Authority: Secs. 101; 301; 304(b), (c), (e), and (g); 306; 307; 
308 and 501, Clean Water Act (Federal Water Pollution Control Act 
Amendments of 1972, as amended; 33 U.S.C. 1251; 1311; 1314(b), (c), 
(e), and (g); 1316; 1317; 1318 and 1361).


0
2. Section 423.10 is revised as follows:


Sec.  423.10  Applicability.

    The provisions of this part apply to discharges resulting from the 
operation of a generating unit by an establishment whose generation of 
electricity is the predominant source of revenue or principal reason 
for operation, and whose generation of electricity results primarily 
from a process utilizing fossil-type fuel (coal, oil, or gas), fuel 
derived from fossil fuel (e.g., petroleum coke, synthesis gas), or 
nuclear fuel in conjunction with a thermal cycle employing the steam 
water system as the thermodynamic medium. This part applies to 
discharges associated with both the combustion turbine and steam 
turbine portions of a combined cycle generating unit.

0
3. Section 423.11 is amended by:
0
a. Revising paragraphs (b), (e), and (f).
0
b. Adding paragraphs (n) through (t).
    The revisions and additions read as follows:


Sec.  423.11  Specialized definitions.

* * * * *
    (b) The term low volume waste sources means, taken collectively as 
if from one source, wastewater from all sources except those for which 
specific limitations or standards are otherwise established in this 
part. Low volume waste sources include, but are not limited to, the 
following: Wastewaters from ion exchange water treatment systems, water 
treatment evaporator blowdown, laboratory and sampling streams, boiler 
blowdown, floor drains, cooling tower basin cleaning wastes, 
recirculating house service water systems, and wet scrubber air 
pollution control systems whose primary purpose is particulate removal. 
Sanitary wastes, air conditioning wastes, and wastewater from carbon 
capture or sequestration systems are not included in this definition.
* * * * *
    (e) The term fly ash means the ash that is carried out of the 
furnace by a gas stream and collected by a capture device such as a 
mechanical precipitator, electrostatic precipitator, or fabric filter. 
Economizer ash is included in this definition when it is collected with 
fly ash. Ash is not included in this definition when it is collected in 
wet scrubber air pollution control systems whose primary purpose is 
particulate removal.
    (f) The term bottom ash means the ash, including boiler slag, which 
settles in the furnace or is dislodged from furnace walls. Economizer 
ash is included in this definition when it is collected with bottom 
ash.
* * * * *
    (n) The term flue gas desulfurization (FGD) wastewater means any 
wastewater generated specifically from the wet flue gas desulfurization 
scrubber system that comes into contact with the flue gas or the FGD 
solids, including but not limited to, the blowdown from the FGD 
scrubber system, overflow or underflow from the solids separation 
process, FGD solids wash water, and the filtrate from the solids 
dewatering process. Wastewater generated from cleaning the FGD 
scrubber, cleaning FGD solids separation equipment, cleaning FGD solids 
dewatering equipment, or that is collected in floor drains in the FGD 
process area is not considered FGD wastewater.
    (o) The term flue gas mercury control wastewater means any 
wastewater generated from an air pollution control system installed or 
operated for the purpose of removing mercury from flue gas. This 
includes fly ash collection systems when the particulate control system 
follows sorbent injection or other controls to remove mercury from flue 
gas. FGD wastewater generated at plants using oxidizing agents to 
remove mercury in the FGD system and not in a separate FGMC system is 
not included in this definition.

[[Page 67894]]

    (p) The term transport water means any wastewater that is used to 
convey fly ash, bottom ash, or economizer ash from the ash collection 
or storage equipment, or boiler, and has direct contact with the ash. 
Transport water does not include low volume, short duration discharges 
of wastewater from minor leaks (e.g., leaks from valve packing, pipe 
flanges, or piping) or minor maintenance events (e.g., replacement of 
valves or pipe sections).
    (q) The term gasification wastewater means any wastewater generated 
at an integrated gasification combined cycle operation from the 
gasifier or the syngas cleaning, combustion, and cooling processes. 
Gasification wastewater includes, but is not limited to the following: 
Sour/grey water; CO2/steam stripper wastewater; sulfur 
recovery unit blowdown, and wastewater resulting from slag handling or 
fly ash handling, particulate removal, halogen removal, or trace 
organic removal. Air separation unit blowdown, noncontact cooling 
water, and runoff from fuel and/or byproduct piles are not considered 
gasification wastewater. Wastewater that is collected intermittently in 
floor drains in the gasification process area from leaks, spills, and 
cleaning occurring during normal operation of the gasification 
operation is not considered gasification wastewater.
    (r) The term combustion residual leachate means leachate from 
landfills or surface impoundments containing combustion residuals. 
Leachate is composed of liquid, including any suspended or dissolved 
constituents in the liquid, that has percolated through waste or other 
materials emplaced in a landfill, or that passes through the surface 
impoundment's containment structure (e.g., bottom, dikes, berms). 
Combustion residual leachate includes seepage and/or leakage from a 
combustion residual landfill or impoundment unit. Combustion residual 
leachate includes wastewater from landfills and surface impoundments 
located on non-adjoining property when under the operational control of 
the permitted facility.
    (s) The term oil-fired unit means a generating unit that uses oil 
as the primary or secondary fuel source and does not use a gasification 
process or any coal or petroleum coke as a fuel source. This definition 
does not include units that use oil only for start up or flame-
stabilization purposes.
    (t) The phrase ``as soon as possible'' means November 1, 2018, 
unless the permitting authority establishes a later date, after 
receiving information from the discharger, which reflects a 
consideration of the following factors:
    (1) Time to expeditiously plan (including to raise capital), 
design, procure, and install equipment to comply with the requirements 
of this part.
    (2) Changes being made or planned at the plant in response to:
    (i) New source performance standards for greenhouse gases from new 
fossil fuel-fired electric generating units, under sections 111, 301, 
302, and 307(d)(1)(C) of the Clean Air Act, as amended, 42 U.S.C. 7411, 
7601, 7602, 7607(d)(1)(C);
    (ii) Emission guidelines for greenhouse gases from existing fossil 
fuel-fired electric generating units, under sections 111, 301, 302, and 
307(d) of the Clean Air Act, as amended, 42 U.S.C. 7411, 7601, 7602, 
7607(d); or
    (iii) Regulations that address the disposal of coal combustion 
residuals as solid waste, under sections 1006(b), 1008(a), 2002(a), 
3001, 4004, and 4005(a) of the Solid Waste Disposal Act of 1970, as 
amended by the Resource Conservation and Recovery Act of 1976, as 
amended by the Hazardous and Solid Waste Amendments of 1984, 42 U.S.C. 
6906(b), 6907(a), 6912(a), 6944, and 6945(a).
    (3) For FGD wastewater requirements only, an initial commissioning 
period for the treatment system to optimize the installed equipment.

0
(4) Other factors as appropriate.
0
4. Section 423.12 is amended by:
0
a. Revising paragraphs (b)(11) and (12).
0
b. Adding paragraph (b)(13).
    The revisions and addition read as follows:


Sec.  423.12  Effluent limitations guidelines representing the degree 
of effluent reduction attainable by the application of the best 
practicable control technology currently available (BPT).

* * * * *
    (b) * * *
    (11) The quantity of pollutants discharged in FGD wastewater, flue 
gas mercury control wastewater, combustion residual leachate, or 
gasification wastewater shall not exceed the quantity determined by 
multiplying the flow of the applicable wastewater times the 
concentration listed in the following table:

------------------------------------------------------------------------
                                           BPT Effluent limitations
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                      any 1 day  (mg/  consecutive days
                                            l)         shall not exceed
                                                            (mg/l)
------------------------------------------------------------------------
TSS.................................           100.0                30.0
Oil and grease......................            20.0                15.0
------------------------------------------------------------------------

    (12) At the permitting authority's discretion, the quantity of 
pollutant allowed to be discharged may be expressed as a concentration 
limitation instead of the mass-based limitations specified in 
paragraphs (b)(3) through (b)(7), and (b)(11), of this section. 
Concentration limitations shall be those concentrations specified in 
this section.
    (13) In the event that wastestreams from various sources are 
combined for treatment or discharge, the quantity of each pollutant or 
pollutant property controlled in paragraphs (b)(1) through (b)(12) of 
this section attributable to each controlled waste source shall not 
exceed the specified limitations for that waste source.

0
5. Section 423.13 is amended by:
0
a. Revising paragraphs (g) and (h).
0
b. Adding paragraphs (i) through (n).
    The revisions and additions read as follows:


Sec.  423.13  Effluent limitations guidelines representing the degree 
of effluent reduction attainable by the application of the best 
available technology economically achievable (BAT).

* * * * *
    (g)(1)(i) FGD wastewater. Except for those discharges to which 
paragraph (g)(2) or (g)(3) of this section applies, the quantity of 
pollutants in FGD wastewater shall not exceed the quantity determined 
by multiplying the flow of FGD wastewater times the concentration 
listed in the table

[[Page 67895]]

following this paragraph (g)(1)(i). Dischargers must meet the effluent 
limitations for FGD wastewater in this paragraph by a date determined 
by the permitting authority that is as soon as possible beginning 
November 1, 2018, but no later than December 31, 2023. These effluent 
limitations apply to the discharge of FGD wastewater generated on and 
after the date determined by the permitting authority for meeting the 
effluent limitations, as specified in this paragraph.

------------------------------------------------------------------------
                                           BAT Effluent limitations
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                         any 1 day     consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)...............              11                   8
Mercury, total (ng/L)...............             788                 356
Selenium, total (ug/L)..............              23                  12
Nitrate/nitrite as N (mg/L).........            17.0                 4.4
------------------------------------------------------------------------

    (ii) For FGD wastewater generated before the date determined by the 
permitting authority, as specified in paragraph (g)(1)(i), the quantity 
of pollutants discharged in FGD wastewater shall not exceed the 
quantity determined by multiplying the flow of FGD wastewater times the 
concentration listed for TSS in Sec.  423.12(b)(11).
    (2) For any electric generating unit with a total nameplate 
capacity of less than or equal to 50 megawatts or that is an oil-fired 
unit, the quantity of pollutants discharged in FGD wastewater shall not 
exceed the quantity determined by multiplying the flow of FGD 
wastewater times the concentration listed for TSS in Sec.  
423.12(b)(11).
    (3)(i) For dischargers who voluntarily choose to meet the effluent 
limitations for FGD wastewater in this paragraph, the quantity of 
pollutants in FGD wastewater shall not exceed the quantity determined 
by multiplying the flow of FGD wastewater times the concentration 
listed in the table following this paragraph (g)(3)(i). Dischargers who 
choose to meet the effluent limitations for FGD wastewater in this 
paragraph must meet such limitations by December 31, 2023. These 
effluent limitations apply to the discharge of FGD wastewater generated 
on and after December 31, 2023.

------------------------------------------------------------------------
                                           BAT Effluent limitations
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                         any 1 day     consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)...............               4  ..................
Mercury, total (ng/L)...............              39                  24
Selenium, total (ug/L)..............               5  ..................
TDS (mg/L)..........................              50                  24
------------------------------------------------------------------------

    (ii) For discharges of FGD wastewater generated before December 31, 
2023, the quantity of pollutants discharged in FGD wastewater shall not 
exceed the quantity determined by multiplying the flow of FGD 
wastewater times the concentration listed for TSS in Sec.  
423.12(b)(11).
    (h)(1)(i) Fly ash transport water. Except for those discharges to 
which paragraph (h)(2) of this section applies, or when the fly ash 
transport water is used in the FGD scrubber, there shall be no 
discharge of pollutants in fly ash transport water. Dischargers must 
meet the discharge limitation in this paragraph by a date determined by 
the permitting authority that is as soon as possible beginning November 
1, 2018, but no later than December 31, 2023. This limitation applies 
to the discharge of fly ash transport water generated on and after the 
date determined by the permitting authority for meeting the discharge 
limitation, as specified in this paragraph. Whenever fly ash transport 
water is used in any other plant process or is sent to a treatment 
system at the plant (except when it is used in the FGD scrubber), the 
resulting effluent must comply with the discharge limitation in this 
paragraph. When the fly ash transport water is used in the FGD 
scrubber, the quantity of pollutants in fly ash transport water shall 
not exceed the quantity determined by multiplying the flow of fly ash 
transport water times the concentration listed in the table in 
paragraph (g)(1)(i) of this section.
    (ii) For discharges of fly ash transport water generated before the 
date determined by the permitting authority, as specified in paragraph 
(h)(1)(i) of this section, the quantity of pollutants discharged in fly 
ash transport water shall not exceed the quantity determined by 
multiplying the flow of fly ash transport water times the concentration 
listed for TSS in Sec.  423.12(b)(4).
    (2) For any electric generating unit with a total nameplate 
generating capacity of less than or equal to 50 megawatts or that is an 
oil-fired unit, the quantity of pollutants discharged in fly ash 
transport water shall not exceed the quantity determined by multiplying 
the flow of fly ash transport water times the concentration listed for 
TSS in Sec.  423.12(b)(4).
    (i)(1)(i) Flue gas mercury control wastewater. Except for those 
discharges to which paragraph (i)(2) of this section applies, there 
shall be no discharge of pollutants in flue gas mercury control 
wastewater. Dischargers must meet the discharge limitation in this 
paragraph by a date determined by the permitting authority that is as 
soon as possible beginning November 1, 2018, but no later than December 
31, 2023. This limitation applies to the discharge of flue gas mercury 
control wastewater generated on and after the date determined by the 
permitting authority for meeting the discharge limitation, as specified 
in this paragraph. Whenever flue gas mercury control wastewater is

[[Page 67896]]

used in any other plant process or is sent to a treatment system at the 
plant, the resulting effluent must comply with the discharge limitation 
in this paragraph.
    (ii) For discharges of flue gas mercury control wastewater 
generated before the date determined by the permitting authority, as 
specified in paragraph (i)(1)(i) of this section, the quantity of 
pollutants discharged in flue gas mercury control wastewater shall not 
exceed the quantity determined by multiplying the flow of flue gas 
mercury control wastewater times the concentration for TSS listed in 
Sec.  423.12(b)(11).
    (2) For any electric generating unit with a total nameplate 
generating capacity of less than or equal to 50 megawatts or that is an 
oil-fired unit, the quantity of pollutants discharged in flue gas 
mercury control wastewater shall not exceed the quantity determined by 
multiplying the flow of flue gas mercury control wastewater times the 
concentration for TSS listed in Sec.  423.12(b)(11).
    (j)(1)(i) Gasification wastewater. Except for those discharges to 
which paragraph (j)(2) of this section applies, the quantity of 
pollutants in gasification wastewater shall not exceed the quantity 
determined by multiplying the flow of gasification wastewater times the 
concentration listed in the table following this paragraph (j)(1)(i). 
Dischargers must meet the effluent limitations in this paragraph by a 
date determined by the permitting authority that is as soon as possible 
beginning November 1, 2018, but no later than December 31, 2023. These 
effluent limitations apply to the discharge of gasification wastewater 
generated on and after the date determined by the permitting authority 
for meeting the effluent limitations, as specified in this paragraph.

------------------------------------------------------------------------
                                           BAT Effluent limitations
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                         any 1 day     consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)...............               4  ..................
Mercury, total (ng/L)...............             1.8                 1.3
Selenium, total (ug/L)..............             453                 227
Total dissolved solids (mg/L).......              38                  22
------------------------------------------------------------------------

    (ii) For discharges of gasification wastewater generated before the 
date determined by the permitting authority, as specified in paragraph 
(j)(1)(i) of this section, the quantity of pollutants discharged in 
gasification wastewater shall not exceed the quantity determined by 
multiplying the flow of gasification wastewater times the concentration 
for TSS listed in Sec.  423.12(b)(11).
    (2) For any electric generating unit with a total nameplate 
generating capacity of less than or equal to 50 megawatts or that is an 
oil-fired unit, the quantity of pollutants discharged in gasification 
wastewater shall not exceed the quantity determined by multiplying the 
flow of gasification wastewater times the concentration listed for TSS 
in Sec.  423.12(b)(11).
    (k)(1)(i) Bottom ash transport water. Except for those discharges 
to which paragraph (k)(2) of this section applies, or when the bottom 
ash transport water is used in the FGD scrubber, there shall be no 
discharge of pollutants in bottom ash transport water. Dischargers must 
meet the discharge limitation in this paragraph by a date determined by 
the permitting authority that is as soon as possible beginning November 
1, 2018, but no later than December 31, 2023. This limitation applies 
to the discharge of bottom ash transport water generated on and after 
the date determined by the permitting authority for meeting the 
discharge limitation, as specified in this paragraph. Whenever bottom 
ash transport water is used in any other plant process or is sent to a 
treatment system at the plant (except when it is used in the FGD 
scrubber), the resulting effluent must comply with the discharge 
limitation in this paragraph. When the bottom ash transport water is 
used in the FGD scrubber, the quantity of pollutants in bottom ash 
transport water shall not exceed the quantity determined by multiplying 
the flow of bottom ash transport water times the concentration listed 
in the table in paragraph (g)(1)(i) of this section.
    (ii) For discharges of bottom ash transport water generated before 
the date determined by the permitting authority, as specified in 
paragraph (k)(1)(i) of this section, the quantity of pollutants 
discharged in bottom ash transport water shall not exceed the quantity 
determined by multiplying the flow of bottom ash transport water times 
the concentration for TSS listed in Sec.  423.12(b)(4).
    (2) For any electric generating unit with a total nameplate 
generating capacity of less than or equal to 50 megawatts or that is an 
oil-fired unit, the quantity of pollutants discharged in bottom ash 
transport water shall not exceed the quantity determined by multiplying 
the flow of the applicable wastewater times the concentration for TSS 
listed in Sec.  423.12(b)(4).
    (l) Combustion residual leachate. The quantity of pollutants 
discharged in combustion residual leachate shall not exceed the 
quantity determined by multiplying the flow of combustion residual 
leachate times the concentration for TSS listed in Sec.  423.12(b)(11).
    (m) At the permitting authority's discretion, the quantity of 
pollutant allowed to be discharged may be expressed as a concentration 
limitation instead of any mass based limitations specified in 
paragraphs (b) through (l) of this section. Concentration limitations 
shall be those concentrations specified in this section.
    (n) In the event that wastestreams from various sources are 
combined for treatment or discharge, the quantity of each pollutant or 
pollutant property controlled in paragraphs (a) through (m) of this 
section attributable to each controlled waste source shall not exceed 
the specified limitation for that waste source.

0
6. Section 423.15 is revised to read as follows:


Sec.  423.15  New source performance standards (NSPS).

    (a) 1982 NSPS. Any new source as of November 19, 1982, subject to 
paragraph (a) of this section, must achieve the following new source 
performance standards, in addition to the limitations in Sec.  423.13 
of this part, established on November 3, 2015. In the case of conflict, 
the more stringent requirements apply:
    (1) pH. The pH of all discharges, except once through cooling 
water, shall be within the range of 6.0-9.0.

[[Page 67897]]

    (2) PCBs. There shall be no discharge of polychlorinated biphenyl 
compounds such as those commonly used for transformer fluid.
    (3) Low volume waste sources, FGD wastewater, flue gas mercury 
control wastewater, combustion residual leachate, and gasification 
wastewater. The quantity of pollutants discharged in low volume waste 
sources, FGD wastewater, flue gas mercury control wastewater, 
combustion residual leachate, and gasification wastewater shall not 
exceed the quantity determined by multiplying the flow of low volume 
waste sources times the concentration listed in the following table:

------------------------------------------------------------------------
                                                     NSPS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                      any 1 day (mg/   consecutive days
                                            l)         shall not exceed
                                                            (mg/l)
------------------------------------------------------------------------
TSS.................................           100.0                30.0
Oil and grease......................            20.0                15.0
------------------------------------------------------------------------

    (4) Chemical metal cleaning wastes. The quantity of pollutants 
discharged in chemical metal cleaning wastes shall not exceed the 
quantity determined by multiplying the flow of chemical metal cleaning 
wastes times the concentration listed in the following table:

------------------------------------------------------------------------
                                                     NSPS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                      any 1 day  (mg/  consecutive days
                                            l)         shall not exceed
                                                            (mg/l)
------------------------------------------------------------------------
TSS.................................           100.0                30.0
Oil and grease......................            20.0                15.0
Copper, total.......................             1.0                 1.0
Iron, total.........................             1.0                 1.0
------------------------------------------------------------------------

    (5) [Reserved]
    (6) Bottom ash transport water. The quantity of pollutants 
discharged in bottom ash transport water shall not exceed the quantity 
determined by multiplying the flow of the bottom ash transport water 
times the concentration listed in the following table:

------------------------------------------------------------------------
                                                     NSPS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                      any 1 day  (mg/  consecutive days
                                            l)         shall not exceed
                                                            (mg/l)
------------------------------------------------------------------------
TSS.................................           100.0                30.0
Oil and grease......................            20.0                15.0
------------------------------------------------------------------------

    (7) Fly ash transport water. There shall be no discharge of 
pollutants in fly ash transport water.
    (8)(i) Once through cooling water. For any plant with a total rated 
electric generating capacity of 25 or more megawatts, the quantity of 
pollutants discharged in once through cooling water from each discharge 
point shall not exceed the quantity determined by multiplying the flow 
of once through cooling water from each discharge point times the 
concentration listed in the following table:

------------------------------------------------------------------------
                                                        NSPS
                                          ------------------------------
     Pollutant or pollutant property        Maximum concentrations  (mg/
                                                         l)
------------------------------------------------------------------------
Total residual chlorine..................                          0.20
------------------------------------------------------------------------

    (ii) Total residual chlorine may only be discharged from any single 
generating unit for more than two hours per day when the discharger 
demonstrates to the permitting authority that discharge for more than 
two hours is required for macroinvertebrate control. Simultaneous 
multi-unit chlorination is permitted.
    (9)(i) Once through cooling water. For any plant with a total rated 
generating capacity of less than 25 megawatts, the quantity of 
pollutants discharged in once through cooling water shall not exceed 
the quantity determined by multiplying the flow of once through cooling 
water sources times the

[[Page 67898]]

concentration listed in the following table:

----------------------------------------------------------------------------------------------------------------
                                                                                   NSPS
                                                         -------------------------------------------------------
             Pollutant or pollutant property              Maximum concentration  (mg/ Average concentration  (mg/
                                                                      l)                          l)
----------------------------------------------------------------------------------------------------------------
Free available chlorine.................................                        0.5                         0.2
----------------------------------------------------------------------------------------------------------------

    (ii) Neither free available chlorine nor total residual chlorine 
may be discharged from any unit for more than two hours in any one day 
and not more than one unit in any plant may discharge free available or 
total residual chlorine at any one time unless the utility can 
demonstrate to the Regional Administrator or state, if the state has 
NPDES permit issuing authority, that the units in a particular location 
cannot operate at or below this level of chlorination.
    (10)(i) Cooling tower blowdown. The quantity of pollutants 
discharged in cooling tower blowdown shall not exceed the quantity 
determined by multiplying the flow of cooling tower blowdown times the 
concentration listed below:

----------------------------------------------------------------------------------------------------------------
                                                                                   NSPS
                                                         -------------------------------------------------------
             Pollutant or pollutant property              Maximum concentration (mg/  Average concentration (mg/
                                                                      l)                          l)
----------------------------------------------------------------------------------------------------------------
Free available chlorine.................................                        0.5                         0.2
----------------------------------------------------------------------------------------------------------------


------------------------------------------------------------------------
                                                     NSPS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                      any 1 day (mg/   consecutive days
                                            l)         shall not exceed
                                                            (mg/l)
------------------------------------------------------------------------
The 126 priority pollutants                    (\1\)               (\1\)
 (appendix A) contained in chemicals
 added for cooling tower
 maintenance, except:...............
    Chromium, total.................             0.2                 0.2
    zinc, total.....................             1.0                 1.0
------------------------------------------------------------------------
\1\ No detectable amount.

    (ii) Neither free available chlorine nor total residual chlorine 
may be discharged from any unit for more than two hours in any one day 
and not more than one unit in any plant may discharge free available or 
total residual chlorine at any one time unless the utility can 
demonstrate to the Regional Administrator or state, if the state has 
NPDES permit issuing authority, that the units in a particular location 
cannot operate at or below this level of chlorination.
    (iii) At the permitting authority's discretion, instead of the 
monitoring in 40 CFR 122.11(b), compliance with the standards for the 
126 priority pollutants in paragraph (a)(10)(i) of this section may be 
determined by engineering calculations which demonstrate that the 
regulated pollutants are not detectable in the final discharge by the 
analytical methods in 40 CFR part 136.
    (11) Coal pile runoff. Subject to the provisions of paragraph 
(a)(12) of this section, the quantity or quality of pollutants or 
pollutant parameters discharged in coal pile runoff shall not exceed 
the standards specified below:

------------------------------------------------------------------------
      Pollutant or pollutant property             NSPS for any time
------------------------------------------------------------------------
TSS.......................................  not to exceed 50 mg/l.
------------------------------------------------------------------------

    (12) Coal pile runoff. Any untreated overflow from facilities 
designed, constructed, and operated to treat the coal pile runoff which 
results from a 10 year, 24 hour rainfall event shall not be subject to 
the standards in paragraph (a)(11) of this section.
    (13) At the permitting authority's discretion, the quantity of 
pollutant allowed to be discharged may be expressed as a concentration 
limitation instead of any mass based limitations specified in 
paragraphs (a)(3) through (10) of this section. Concentration limits 
shall be based on the concentrations specified in this section.
    (14) In the event that wastestreams from various sources are 
combined for treatment or discharge, the quantity of each pollutant or 
pollutant property controlled in paragraphs (a)(1) through (13) of this 
section attributable to each controlled waste source shall not exceed 
the specified limitation for that waste source.
    (b) 2015 NSPS. Any new source as of November 17, 2015, subject to 
paragraph (b) of this section, must achieve the following new source 
performance standards:
    (1) pH. The pH of all discharges, except once through cooling 
water, shall be within the range of 6.0-9.0.
    (2) PCBs. There shall be no discharge of polychlorinated biphenyl 
compounds such as those commonly used for transformer fluid.
    (3) Low volume waste sources. The quantity of pollutants discharged 
from low volume waste sources shall not exceed the quantity determined 
by multiplying the flow of low volume waste sources times the 
concentration listed in the following table:

[[Page 67899]]



------------------------------------------------------------------------
                                                     NSPS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                      any 1 day (mg/   consecutive days
                                            l)         shall not exceed
                                                            (mg/l)
------------------------------------------------------------------------
TSS.................................           100.0                30.0
Oil and grease......................            20.0                15.0
------------------------------------------------------------------------

    (4) Chemical metal cleaning wastes. The quantity of pollutants 
discharged in chemical metal cleaning wastes shall not exceed the 
quantity determined by multiplying the flow of chemical metal cleaning 
wastes times the concentration listed in the following table:

------------------------------------------------------------------------
                                                     NSPS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                      any 1 day (mg/   consecutive days
                                            l)         shall not exceed
                                                            (mg/l)
------------------------------------------------------------------------
TSS.................................           100.0                30.0
Oil and grease......................            20.0                15.0
Copper, total.......................             1.0                 1.0
Iron, total.........................             1.0                 1.0
------------------------------------------------------------------------

    (5) [Reserved]
    (6) Bottom ash transport water. There shall be no discharge of 
pollutants in bottom ash transport water. Whenever bottom ash transport 
water is used in any other plant process or is sent to a treatment 
system at the plant, the resulting effluent must comply with the 
discharge standard in this paragraph.
    (7) Fly ash transport water. There shall be no discharge of 
pollutants in fly ash transport water. Whenever fly ash transport water 
is used in any other plant process or is sent to a treatment system at 
the plant, the resulting effluent must comply with the discharge 
standard in this paragraph.
    (8)(i) Once through cooling water. For any plant with a total rated 
electric generating capacity of 25 or more megawatts, the quantity of 
pollutants discharged in once through cooling water from each discharge 
point shall not exceed the quantity determined by multiplying the flow 
of once through cooling water from each discharge point times the 
concentration listed in the following table:

------------------------------------------------------------------------
                                                        NSPS
     Pollutant or pollutant property      ------------------------------
                                            Maximum concentration (mg/l)
------------------------------------------------------------------------
Total residual chlorine..................                          0.20
------------------------------------------------------------------------

    (ii) Total residual chlorine may only be discharged from any single 
generating unit for more than two hours per day when the discharger 
demonstrates to the permitting authority that discharge for more than 
two hours is required for macroinvertebrate control. Simultaneous 
multi-unit chlorination is permitted.
    (9)(i) Once through cooling water. For any plant with a total rated 
generating capacity of less than 25 megawatts, the quantity of 
pollutants discharged in once through cooling water shall not exceed 
the quantity determined by multiplying the flow of once through cooling 
water sources times the concentration listed in the following table:

----------------------------------------------------------------------------------------------------------------
                                                                                   NSPS
                                                         -------------------------------------------------------
             Pollutant or pollutant property              Maximum concentration (mg/  Average concentration (mg/
                                                                      l)                          l)
----------------------------------------------------------------------------------------------------------------
Free available chlorine.................................                        0.5                         0.2
----------------------------------------------------------------------------------------------------------------

    (ii) Neither free available chlorine nor total residual chlorine 
may be discharged from any unit for more than two hours in any one day 
and not more than one unit in any plant may discharge free available or 
total residual chlorine at any one time unless the utility can 
demonstrate to the Regional Administrator or state, if the state has 
NPDES permit issuing authority, that the units in a particular location 
cannot operate at or below this level of chlorination.
    (10)(i) Cooling tower blowdown. The quantity of pollutants 
discharged in cooling tower blowdown shall not exceed the quantity 
determined by multiplying the flow of cooling tower blowdown times the 
concentration listed below:

[[Page 67900]]



----------------------------------------------------------------------------------------------------------------
                                                                                   NSPS
                                                         -------------------------------------------------------
             Pollutant or pollutant property              Maximum concentration (mg/  Average concentration (mg/
                                                                      l)                          l)
----------------------------------------------------------------------------------------------------------------
Free available chlorine.................................                        0.5                         0.2
----------------------------------------------------------------------------------------------------------------


----------------------------------------------------------------------------------------------------------------
                                                                                   NSPS
                                                         -------------------------------------------------------
             Pollutant or pollutant property                                            Average of daily values
                                                          Maximum for any 1 day (mg/    for 30 consecutive days
                                                                      l)                shall not exceed (mg/l)
----------------------------------------------------------------------------------------------------------------
The 126 priority pollutants (appendix A) contained in                         (\1\)                       (\1\)
 chemicals added for cooling tower maintenance, except:.
    Chromium, total.....................................                        0.2                         0.2
    zinc, total.........................................                        1.0                         1.0
----------------------------------------------------------------------------------------------------------------
\1\ No detectable amount.

    (ii) Neither free available chlorine nor total residual chlorine 
may be discharged from any unit for more than two hours in any one day 
and not more than one unit in any plant may discharge free available or 
total residual chlorine at any one time unless the utility can 
demonstrate to the Regional Administrator or state, if the state has 
NPDES permit issuing authority, that the units in a particular location 
cannot operate at or below this level of chlorination.
    (iii) At the permitting authority's discretion, instead of the 
monitoring in 40 CFR 122.11(b), compliance with the standards for the 
126 priority pollutants in paragraph (b)(10)(i) of this section may be 
determined by engineering calculations demonstrating that the regulated 
pollutants are not detectable in the final discharge by the analytical 
methods in 40 CFR part 136.
    (11) Coal pile runoff. Subject to the provisions of paragraph 
(b)(12) of this section, the quantity or quality of pollutants or 
pollutant parameters discharged in coal pile runoff shall not exceed 
the standards specified below:

------------------------------------------------------------------------
      Pollutant or pollutant property             NSPS for any time
------------------------------------------------------------------------
TSS.......................................  not to exceed 50 mg/l.
------------------------------------------------------------------------

    (12) Coal pile runoff. Any untreated overflow from facilities 
designed, constructed, and operated to treat the coal pile runoff which 
results from a 10 year, 24 hour rainfall event shall not be subject to 
the standards in paragraph (b)(11) of this section.
    (13) FGD wastewater. The quantity of pollutants discharged in FGD 
wastewater shall not exceed the quantity determined by multiplying the 
flow of FGD wastewater times the concentration listed in the following 
table:

------------------------------------------------------------------------
                                                     NSPS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                         any 1 day     consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)...............               4  ..................
Mercury, total (ng/L)...............              39                  24
Selenium, total (ug/L)..............               5  ..................
TDS (mg/L)..........................              50                  24
------------------------------------------------------------------------

    (14) Flue gas mercury control wastewater. There shall be no 
discharge of pollutants in flue gas mercury control wastewater. 
Whenever flue gas mercury control wastewater is used in any other plant 
process or is sent to a treatment system at the plant, the resulting 
effluent must comply with the discharge standard in this paragraph.
    (15) Gasification wastewater. The quantity of pollutants discharged 
in gasification wastewater shall not exceed the quantity determined by 
multiplying the flow of gasification wastewater times the concentration 
listed in the following table:

------------------------------------------------------------------------
                                                     NSPS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                         any 1 day     consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)...............               4  ..................
Mercury, total (ng/L)...............             1.8                 1.3
Selenium, total (ug/L)..............             453                 227
Total dissolved solids (mg/L).......              38                  22
------------------------------------------------------------------------


[[Page 67901]]

    (16) Combustion residual leachate. The quantity of pollutants 
discharged in combustion residual leachate shall not exceed the 
quantity determined by multiplying the flow of combustion residual 
leachate times the concentration listed in the following table:

------------------------------------------------------------------------
                                                     NSPS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                         any 1 day     consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)...............              11                   8
Mercury, total (ng/L)...............             788                 356
------------------------------------------------------------------------

    (17) At the permitting authority's discretion, the quantity of 
pollutant allowed to be discharged may be expressed as a concentration 
limitation instead of any mass based limitations specified in 
paragraphs (b)(3) through (16) of this section. Concentration limits 
shall be based on the concentrations specified in this section.
    (18) In the event that wastestreams from various sources are 
combined for treatment or discharge, the quantity of each pollutant or 
pollutant property controlled in paragraphs (b)(1) through (16) of this 
section attributable to each controlled waste source shall not exceed 
the specified limitation for that waste source.
    (The information collection requirements contained in paragraphs 
(a)(8)(ii), (a)(9)(ii), and (a)(10)(ii), (b)(8)(ii), (b)(9)(ii), and 
(b)(10)(ii) were approved by the Office of Management and Budget under 
control number 2040-0040. The information collection requirements 
contained in paragraphs (a)(10)(iii) and (b)(10)(iii) were approved 
under control number 2040-0033.)

0
7. Section 423.16 is amended by adding paragraphs (e) through (i) to 
read as follows:


Sec.  423.16  Pretreatment standards for existing sources (PSES).

* * * * *
    (e) FGD wastewater. For any electric generating unit with a total 
nameplate generating capacity of more than 50 megawatts and that is not 
an oil-fired unit, the quantity of pollutants in FGD wastewater shall 
not exceed the quantity determined by multiplying the flow of FGD 
wastewater times the concentration listed in the table following this 
paragraph (e). Dischargers must meet the standards in this paragraph by 
November 1, 2018. These standards apply to the discharge of FGD 
wastewater generated on and after November 1, 2018.

------------------------------------------------------------------------
                                                     PSES
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                         any 1 day     consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)...............              11                   8
Mercury, total (ng/L)...............             788                 356
Selenium, total (ug/L)..............              23                  12
Nitrate/nitrite as N (mg/L).........            17.0                 4.4
------------------------------------------------------------------------

    (f) Fly ash transport water. Except when the fly ash transport 
water is used in the FGD scrubber, for any electric generating unit 
with a total nameplate generating capacity of more than 50 megawatts 
and that is not an oil-fired unit, there shall be no discharge of 
pollutants in fly ash transport water. This standard applies to the 
discharge of fly ash transport water generated on and after November 1, 
2018. Whenever fly ash transport water is used in any other plant 
process or is sent to a treatment system at the plant (except when it 
is used in the FGD scrubber), the resulting effluent must comply with 
the discharge standard in this paragraph. When the fly ash transport 
water is used in the FGD scrubber, the quantity of pollutants in fly 
ash transport water shall not exceed the quantity determined by 
multiplying the flow of fly ash transport water times the concentration 
listed in the table in paragraph (e) of this section.
    (g) Bottom ash transport water. Except when the bottom ash 
transport water is used in the FGD scrubber, for any electric 
generating unit with a total nameplate generating capacity of more than 
50 megawatts and that is not an oil-fired unit, there shall be no 
discharge of pollutants in bottom ash transport water. This standard 
applies to the discharge of bottom ash transport water generated on and 
after November 1, 2018. Whenever bottom ash transport water is used in 
any other plant process or is sent to a treatment system at the plant 
(except when it is used in the FGD scrubber), the resulting effluent 
must comply with the discharge standard in this paragraph. When the 
bottom ash transport water is used in the FGD scrubber, the quantity of 
pollutants in bottom ash transport water shall not exceed the quantity 
determined by multiplying the flow of bottom ash transport water times 
the concentration listed in the table in paragraph (e) of this section.
    (h) Flue gas mercury control wastewater. For any electric 
generating unit with a total nameplate generating capacity of more than 
50 megawatts and that is not an oil-fired unit, there shall be no 
discharge of pollutants in flue gas mercury control wastewater. This 
standard applies to the discharge of flue gas mercury control 
wastewater generated on and after November 1, 2018. Whenever flue gas 
mercury control wastewater is used in any other plant process or is 
sent to a treatment system at the plant, the resulting effluent must 
comply with the discharge standard in this paragraph.
    (i) Gasification wastewater. For any electric generating unit with 
a total nameplate generating capacity of more than 50 megawatts and 
that is not an oil-fired unit, the quantity of pollutants in 
gasification wastewater shall not exceed

[[Page 67902]]

the quantity determined by multiplying the flow of gasification 
wastewater times the concentration listed in the table following this 
paragraph (i). Dischargers must meet the standards in this paragraph by 
November 1, 2018. These standards apply to the discharge of 
gasification wastewater generated on and after November 1, 2018.

------------------------------------------------------------------------
                                                     PSES
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                         any 1 day     consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total ([mu]g/L)............               4  ..................
Mercury, total (ng/L)...............             1.8                 1.3
Selenium, total ([mu]g/L)...........             453                 227
Total dissolved solids (mg/L).......              38                  22
------------------------------------------------------------------------


0
8. Section 423.17 is revised to read as follows:


Sec.  423.17  Pretreatment standards for new sources (PSNS).

    (a) 1982 PSNS. Except as provided in 40 CFR 403.7, any new source 
as of October 14, 1980, subject to paragraph (a) of this section, which 
introduces pollutants into a publicly owned treatment works, must 
comply with 40 CFR part 403, the following pretreatment standards for 
new sources, and the PSES in Sec.  423.16, established on November 3, 
2015. In the case of conflict, the more stringent standards apply:
    (1) PCBs. There shall be no discharge of polychlorinated biphenyl 
compounds such as those used for transformer fluid.
    (2) Chemical metal cleaning wastes. The pollutants discharged in 
chemical metal cleaning wastes shall not exceed the concentration 
listed in the following table:

------------------------------------------------------------------------
                                                        PSNS
     Pollutant or pollutant property      ------------------------------
                                            Maximum for any 1 day (mg/L)
------------------------------------------------------------------------
Copper, total............................                           1.0
------------------------------------------------------------------------

    (3) [Reserved]
    (4)(i) Cooling tower blowdown. The pollutants discharged in cooling 
tower blowdown shall not exceed the concentration listed in the 
following table:

------------------------------------------------------------------------
                                                        PSNS
     Pollutant or pollutant property      ------------------------------
                                            Maximum for any time (mg/L)
------------------------------------------------------------------------
The 126 priority pollutants (appendix A)                          (\1\)
 contained in chemicals added for cooling
 tower maintenance, except:..............
    Chromium, total......................                           0.2
    zinc, total..........................                           1.0
------------------------------------------------------------------------
\1\ No detectable amount.

    (ii) At the permitting authority's discretion, instead of the 
monitoring in 40 CFR 122.11(b), compliance with the standards for the 
126 priority pollutants in paragraph (a)(4)(i) of this section may be 
determined by engineering calculations which demonstrate that the 
regulated pollutants are not detectable in the final discharge by the 
analytical methods in 40 CFR part 136.
    (5) Fly ash transport water. There shall be no discharge of 
wastewater pollutants from fly ash transport water.
    (b) 2015 PSNS. Except as provided in 40 CFR 403.7, any new source 
as of June 7, 2013, subject to this paragraph (b), which introduces 
pollutants into a publicly owned treatment works must comply with 40 
CFR part 403 and the following pretreatment standards for new sources:
    (1) PCBs. There shall be no discharge of polychlorinated biphenyl 
compounds such as those used for transformer fluid.
    (2) Chemical metal cleaning wastes. The pollutants discharged in 
chemical metal cleaning wastes shall not exceed the concentration 
listed in the following table:

------------------------------------------------------------------------
                                                        PSNS
     Pollutant or pollutant property      ------------------------------
                                              Maximum for 1 day (mg/L)
------------------------------------------------------------------------
Copper, total............................                           1.0
------------------------------------------------------------------------

    (3) [Reserved]
    (4)(i) Cooling tower blowdown. The pollutants discharged in cooling 
tower blowdown shall not exceed the concentration listed in the 
following table:

[[Page 67903]]



------------------------------------------------------------------------
                                                        PSNS
     Pollutant or pollutant property      ------------------------------
                                            Maximum for any time (mg/L)
------------------------------------------------------------------------
The 126 priority pollutants (appendix A)                          (\1\)
 contained in chemicals added for cooling
 tower maintenance, except:..............
    Chromium, total......................                           0.2
    zinc, total..........................                           1.0
------------------------------------------------------------------------
\1\ No detectable amount.

    (ii) At the permitting authority's discretion, instead of the 
monitoring in 40 CFR 122.11(b), compliance with the standards for the 
126 priority pollutants in paragraph (b)(4)(i) of this section may be 
determined by engineering calculations which demonstrate that the 
regulated pollutants are not detectable in the final discharge by the 
analytical methods in 40 CFR part 136.
    (5) Fly ash transport water. There shall be no discharge of 
pollutants in fly ash transport water. Whenever fly ash transport water 
is used in any other plant process or is sent to a treatment system at 
the plant, the resulting effluent must comply with the discharge 
standard in this paragraph.
    (6) FGD wastewater. The quantity of pollutants discharged in FGD 
wastewater shall not exceed the quantity determined by multiplying the 
flow of FGD wastewater times the concentration listed in the following 
table:

------------------------------------------------------------------------
                                                     PSNS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                         any 1 day     consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total ([mu]g/L)............               4  ..................
Mercury, total (ng/L)...............              39                  24
Selenium, total ([mu]g/L)...........               5  ..................
TDS (mg/L)..........................              50                  24
------------------------------------------------------------------------

    (7) Flue gas mercury control wastewater. There shall be no 
discharge of pollutants in flue gas mercury control wastewater. 
Whenever flue gas mercury control wastewater is used in any other plant 
process or is sent to a treatment system at the plant, the resulting 
effluent must comply with the discharge standard in this paragraph.
    (8) Bottom ash transport water. There shall be no discharge of 
pollutants in bottom ash transport water. Whenever bottom ash transport 
water is used in any other plant process or is sent to a treatment 
system at the plant, the resulting effluent must comply with the 
discharge standard in this paragraph.
    (9) Gasification wastewater. The quantity of pollutants discharged 
in gasification wastewater shall not exceed the quantity determined by 
multiplying the flow of gasification wastewater times the concentration 
listed in the following table:

------------------------------------------------------------------------
                                                     PSNS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                         any 1 day     consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total ([mu]g/L)............               4  ..................
Mercury, total (ng/L)...............             1.8                 1.3
Selenium, total ([mu]g/L)...........             453                 227
Total dissolved solids (mg/L).......              38                  22
------------------------------------------------------------------------

    (10) Combustion residual leachate. The quantity of pollutants 
discharged in combustion residual leachate shall not exceed the 
quantity determined by multiplying the flow of combustion residual 
leachate times the concentration listed in the following table:

------------------------------------------------------------------------
                                                     PSNS
                                     -----------------------------------
                                                       Average of daily
   Pollutant or pollutant property      Maximum for      values for 30
                                         any 1 day     consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total ([mu]g/L)............              11                   8
Mercury, total (ng/L)...............             788                 356
------------------------------------------------------------------------

[FR Doc. 2015-25663 Filed 11-2-15; 8:45 am]
BILLING CODE 6560-50-P