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EO12866_SteamELG 2040-AF14 FinalRule Preamble_20150929 

6560-50-P 

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. 

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 
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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 [INSERT DATE 60 DAYS AFTER 

DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 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 [INSERT 

DATE 2 WEEKS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 

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. 
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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 website at 

http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm. 

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: jordan.ronald@epa.gov. For 

economic information, contact James Covington, Engineering and 

Analysis Division, Telephone: 202-566-1034; Email: 

covington.james@epa.gov. 

Organization of This Preamble:
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Table of Contents: 

I. Supplementary Information

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)
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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

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
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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
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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: Definitions, Acronyms, and Abbreviations Used in 

This Document

I. Supplementary Information 

A. Regulated Entities 

Entities potentially regulated by this action include: 

Category Example of Regulated 

Entity 

North American Industry 

Classification System 

(NAICS) Code 

Industry 

Electric Power Generation 

Facilities – Electric 

Power Generation 

22111 

Electric Power Generation 

Facilities – Fossil Fuel 

Electric Power Generation 

221112 

Electric Power Generation 

Facilities – Nuclear 

Electric Power Generation 

221113 

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 
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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. EPA821-R-15-007. 

 Environmental Assessment for the Effluent Limitations 

Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category (EA), Document No. EPA821-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. EPA821-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. EPA821-R-15-004. 

These documents are available in the public record for this 

rule and on EPA’s website at 

http://water.epa.gov/scitech/wastetech/guide/steam_index.cfm. 
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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 plants1 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 

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 

 

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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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. 

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) 
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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 
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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. 

Steam electric power plant discharges adversely affect our 

nation’s waters and their ecology. Pollutants in such 

discharges, particularly mercury and selenium, bioaccumulate in 

 

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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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 
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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 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 
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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. 
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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

 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 

 

4 For details on when the following BAT limitations apply, see Section VIII.C 

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 

 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 

 

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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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 oilfired 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

 A zero discharge standard for all pollutants in fly ash 

transport water, bottom ash transport water, and FGMC 

wastewater.8 

 Numeric standards on mercury, arsenic, selenium, and 

nitrate/nitrite as N in the discharge of FGD wastewater. 

 

7 For details on when PSES apply, see Section VIII.E. 

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 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. 

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 
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be somewhat higher or lower than estimated. The current estimate 

reflects the best data and analysis available at this. In this 

preamble, EPA presents costs and monetized benefits accounting 

for these other rules9. 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. 

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 

 

10 EPA estimates that the population of steam electric power plants is about 

1080. 
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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 costeffectiveness 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 
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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. 
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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 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. 
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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 welldesigned 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. 
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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 
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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, nonwater quality environmental impacts (including energy 

requirements), and such other factors as the Administrator deems 
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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 
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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 
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Public Works (1978), A 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). 
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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 
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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 

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power-plants), and the Carbon Pollution Standard for New Power 

Plants (CPS) rule (see 

http://www2.epa.gov/cleanpowerplan/carbon-pollution-standardsnew-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 
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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. 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 
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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 

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 
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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 closedloop 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. 
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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 
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 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 

 

11 For details on the industry survey, see TSS 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. 
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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). 

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 
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 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 

 

ash transport water data would not have changed EPA’s ultimate decisions for 

this final rule. See DCN SE05581. 
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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, 
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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 
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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 
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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 waterfilled 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 
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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 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 
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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. 
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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 
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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 
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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 
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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 (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 
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technology basis. A pollutant is determined to pass through 

POTWs when the median percentage removed nationwide by welloperated 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). 
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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 passthrough 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 passthrough 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 
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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, 
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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. 

The following paragraphs describe the six options (Options 

A through F), by wastestream, including the technology bases for 

the requirements associated with each.

 

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. 
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Table VIII-1 Final Rule: Steam Electric Main Regulatory Options 

Wastestreams 

T

e

c

h

n

ology

B

asis

f

o

r

the Main B

A

T/N

S

P

S/P

SES/P

SNS

Regulatory Options 

A

B

C

D

E

FGDWastewater

Chemical Precipitation 

Chemical Precipitation + Biological Treatment 

Chemical Precipitation + Biological Treatment 

Chemical Precipitation + Biological Treatment 

Chemical PrecipitatiBiological Treatment 

Fly 

Ash 

Transport 

Water

Dry handling Dry handling Dry handling Dry handling Dry handlin

Bot

t

o

m

Ash 

Transport 

Water

Impoundment (Equal to BPT) 

Impoundment (Equal to BPT) 

Dry handling/Closedloop (for units >400 MW); Impoundment (Equal to BPT)(for units ≤400 MW) 

Dry handling/ Closed loop 

Dry handlinClosed loop 

FGMCWastewater

Dry handling Dry handling Dry handling Dry handling Dry handlin

GasificationWastewater

Evaporation Evaporation Evaporation Evaporation Evaporation 

Combustion Residual Leachate

Impoundment (Equal to BPT) 

Impoundment (Equal to BPT) 

Impoundment (Equal to BPT) 

Impoundment (Equal to BPT) 

Chemical Precipitati

Nonchemical Metal 

Cleaning 

Wastes 

[Reserved] [Reserved] [Reserved] [Reserved] [Reserved] 
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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 TSS15 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 anticircumvention 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. 
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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 
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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 closedloop 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. 
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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 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 
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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. 
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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 

 

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 
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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). 

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 

 

certain climates. Similarly, complete recycle is only available at plants 

with appropriate FGD metallurgy. 
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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 
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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 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 

 

22 EPA included the equipment for chemical addition of a reducing agent in its 

cost estimates for Options B through E. 
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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. 

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 
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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 
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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 
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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 
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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 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. 
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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 

 

23 This evaporation step would have been preceded by a chemical precipitation 

step using hydroxide precipitation, sulfide precipitation, and iron coprecipitation, as well as a softening step. 
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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. 

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. 
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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 4.2.5. 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 
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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 

 

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. 
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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. 

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 amount of waste entering surface 

impoundments and the risk and severity of structural failures 
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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. 

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 

 

25 Neither these savings nor the fuel and emissions reductions have been 

incorporated into EPA’s analyses for this final rule. 
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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 
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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). 

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 

 

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. 
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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 closedloop 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). 
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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. 
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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 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 
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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 
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(approximately 3 percent of baseline loadings, on a toxicweighted 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). 
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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 

 

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. 
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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)). 

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 
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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 

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 
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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 wellestablished and judicially upheld statistical methodology. In 

this case, except in very limited circumstances, plants do not 

treat the legacy wastewater that they send to an impoundment 

 

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. 
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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. 

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 

 

29 For example, no plant uses chemical precipitation, 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. 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. 

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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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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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. 
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10. Non-Water Quality Environmental Impacts, Including Energy 

Requirements33

The final BAT effluent limitations have acceptable nonwater quality 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 

 

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. 
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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 coalfired 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 
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power plant discharges and who consumes the most fish from 

waters receiving power plant discharges, EPA concluded that lowincome 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 
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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 
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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 oilfired 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 
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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 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 
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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 
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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 
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remaining units. The same cannot be said of the ratio for units 

smaller than or equal to 100 MW. 

Figure VIII-1. Regulatory Option D Annualized Cost per MW 

Compared to Unit Capacity (MW) 

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 
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(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 
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because evaporation technology is capable of achieving 

significant removals of toxic metals, as well as TDS.34 

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 

 

34 Properly operated evaporated systems are also capable of achieving the BAT 

limitations based on chemical precipitation plus biological treatment. 
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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 
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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 
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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 of meeting the 

limitations based on evaporation. 

For purposes of the voluntary incentives program BAT 

limitations, legacy FGD wastewater is FGD wastewater generated 

 

35 For some plants, proper pretreatment such as softening or chemical 

precipitation is likely appropriate to ensure effective and efficient 

operation of evaporation systems. 
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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 
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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 
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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 
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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 
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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 
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small generating units as for all 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-
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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 
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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. 

Table VIII-2. Summary of Pass-Through Analysis Results 

Technology Basis/Wastewater Stream Pollutant Pass Through? 

(Yes/No) 

Chemical Precipitation for Combustion 

Residual Leachate (only for NSPS) 

Arsenic Yes 

Mercury Yes 

Chemical Precipitation plus Biological

Treatment for FGD Wastewater 

Arsenic Yes 

Mercury Yes 

Nitrate/ 

Nitrite as N Yes 

Selenium Yes 

Evaporation for FGD wastewater (only 

for NSPS) 

Arsenic Yes 

Mercury Yes 

Selenium Yes 

TDS Yes 

 

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). 
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Table VIII-2. Summary of Pass-Through Analysis Results 

Technology Basis/Wastewater Stream Pollutant Pass Through? 

(Yes/No) 

Evaporation for Gasification 

Wastewater 

Arsenic Yes 

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 
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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 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. 

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), 

 

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. 
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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 
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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 
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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 anticircumvention provisions that EPA proposed. The one anticircumvention provision that EPA decided to establish applies 

only to those wastestreams with 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 without any 

limitations or standards on toxic pollutants. 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 
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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. 

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 wetsluicing 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 makeup cooling water and would be precluded from doing so because of 
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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 

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 anticircumvention 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 
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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 anticircumvention provision to this particular practice. 
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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 
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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 anticircumvention 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 
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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 
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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 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 
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“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 
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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.38 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 

 

38 Under the structure of the previously promulgated regulations, non-chemical 

metal cleaning wastes are a subset of metal cleaning wastes. 
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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 nonchemical 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.39 

 

39 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 nonchemical 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. 
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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. 
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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 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 
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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 
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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 
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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 Costs $496.2 $339.6 

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. 
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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.40 

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. 

 

40 These discount rate values follow guidance from the Office of Management 

and Budget (OMB) regulatory analysis guidance document, Circular A-4 (OMB, 

2003). 
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Table IX-2. Total Annualized Social Costs (in millions, 2013$) 

 3% Discount Rate 7% Discount Rate 

Total 

Annualized 

Social Costs 

$479.5 $471.2 

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 
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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 screeninglevel 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 
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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 plantlevel 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 
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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 Resultsa

Number and Fraction of Existing Steam Electric Power Plants with CostTo-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 
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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 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 Revenuea

Total Number 

of Entities 

Not Analyzed 

Due to Lack 

of Revenue 

Information

Number and Percentage with After Tax Annual 

Costs/Annual Revenue of: 

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%
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Table IX-4. Parent Entity-Level After-Tax Annual Costs as a 

Percentage of Revenuea

Total Number 

of Entities 

Not Analyzed 

Due to Lack 

of Revenue 

Information

Number and Percentage with After Tax Annual 

Costs/Annual Revenue of: 

0% 0-1% 1-3% 

3% or 

Greater 

# % # % # % # % # %

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 
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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 
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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. utilityand 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.41 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.42 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 

 

41 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. 

42 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. 
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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 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. 

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 
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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 nonsteam electric power plants), (2) impact on steam electric power 

plants as a group, and (3) impact on individual steam electric 
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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.43 

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 

 

43 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. 
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closures) in aggregate capacity terms; (2) incremental capacity 

closures as a percentage of baseline capacity; (3) postcompliance 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 

Region 

Baselin

e 

Capacit

y (MW) 

Incremental 

Early 

Retirements / 

Closuresa Change in 

Total 

Generation 

(GWh or % of 

Baseline) 

Change in 

Variable 

Production 

Cost 

(2013$/MWh 

or % of 

Baseline) 

Change in 

Annual Costs 

(Million 

2013$ or % 

of Baseline) 

Capacit

y (MW) 

% of 

Baseli

ne 

Capaci

ty 

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 
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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,44 for steam electric power plants, total available 

capacity and electricity generation at the national level are 

projected to fall by approximately 0.2 percent. 

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 

 

44 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. 
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(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 
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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 overnight45

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 

 

45 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. 
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and contrasts these costs with the incremental costs associated 

with the final NSPS/PSNS. 

Table IX-6. Comparison of Incremental Compliance Costs with 

Costs for New Coal-fired Steam Electric Units 

Cost Component 

Costs of New 

Coal 

Generation 

($2013/MW)a

Incremental 

Compliance 

Costs 

($2013/MW)b

% of New 

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 Fuelc $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 dualunit 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. 
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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 wastestream46 and each 

POC, EPA first estimated – on an annual, per plant basis – 

plant-specific baseline pollutant loadings taking into account 

components in place at the plant (or expected to be in place 

given other existing rules47) and, where appropriate, pollutant 

removals at the POTW, since these removals result in reduced 

discharges to receiving waters. EPA similarly estimated plantspecific 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 

 

46 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. 

47 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. 
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total industry pollutant reductions by applying survey weights 

to the plant-specific pollutant reductions and summing them. 

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 

Analysis 

Baseline 

Pollutant Reductions (pounds per year) 

Conventional 

Pollutantsa 

Priority 

Pollutants 

Nonconventional 

Pollutantsb 

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 
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apply to discharges of FGD wastewater and gasification 

wastewater at new and existing sources, and to discharges of 

combustion residual leachate at new sources.48 

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 

 

48 Effluent limitations and standards based on the previously established BPT 

limitations on TSS are not discussed in this section. 
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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 
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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 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 
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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 
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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 
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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 

Wastestream Pollutant 

Long-Term 

Average 

Daily 

Maximum 

Limitation 

Monthly 

Average 

Limitation 

FGD Wastewater 

(BAT & PSES) 

Arsenic (μg/L) 5.98 11 8 

Mercury (ng/L) 159 788 356 

Nitrate/nitrite 

 as N (mg/L) 1.3 17.0 4.4 

Selenium (μg/L) 7.5 23 12 

Voluntary Incentives 

Program for FGD 

Wastewater 

(BAT only) 

Arsenic (μg/L) 4.0a 4b ---c

Mercury (ng/L) 17.8 39 24 

Selenium (μg/L) 5.0a 5b ---c

TDS (mg/L) 14.9 50 24 

Gasification Arsenic (μg/L) 4.0a 4b ---c
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Wastestream Pollutant 

Long-Term 

Average 

Daily 

Maximum 

Limitation 

Monthly 

Average 

Limitation 

Wastewater 

(BAT & PSES) 

Mercury (ng/L) 1.08 1.8 1.3 

Selenium (μg/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. 

Table XI-2. Long-Term Averages and Standards for FGD Wastewater, 

Gasification Wastewater, and Combustion Residual Leachate for 

New Sources 

Wastestream Pollutant 

Long-Term 

Average 

Daily 

Maximum 

Limitation 

Monthly 

Average 

Limitation 

FGD Wastewater 

(NSPS & PSNS) 

Arsenic (μg/L) 4.0a 4b ---c

Mercury (ng/L) 17.8 39 24 

Selenium (μg/L) 5.0a 5b ---c

TDS (mg/L) 14.9 50 24 

Gasification 

Wastewater 

(NSPS & PSNS) 

Arsenic (μg/L) 4.0a 4b ---c

Mercury (ng/L) 1.08 1.8 1.3 

Selenium (μg/L) 147 453 227 

TDS (mg/L) 15.2 38 22 

Combustion Residual 

Leachate 

(NSPS & PSNS) 

Arsenic (μg/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) 
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associated with ELGs. Accordingly, EPA considered the potential 

impact of this rule on energy consumption, air emissions, and 

solid waste generation49. 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. 

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 

Non-Water Quality Environmental 

Impact Final 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 

 

49 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 nonwater 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. 
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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) 

Non-Water Quality 

Environmental 

Impact 

2009 

Emissions 

by 

Electric 

Power 

Industry 

(Million 

Tons) 

Change in 

Air 

Emissions 

Associated 

with Final 

Rule 

(Million 

Tons) 

Increase In 

Emissions for 

Final Rule 

(%) 

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. 
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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 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 
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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 
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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 
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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. 
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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 
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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 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),50 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 

 

50 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. 
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Indicators (RSEI) model, and improved its modeling of selenium 

bioaccumulation in fish and wildlife. 

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 casestudy 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 
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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 
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electric power plants (fly ash and bottom ash transport water, 

FGD wastewater, and combustion residual leachate) into 

rivers/streams and lakes/ponds (including reservoirs)51. EPA 

addressed environmental impacts from nutrients in a separate 

analysis discussed in Section XIII.D.5. 

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 Rule52

Criteria Evaluated for Exceedances

Will 

Improve 

Under the 

Final Rule?

Freshwater Acute National Recommended WQC YES 

Freshwater Chronic National Recommended WQC YES 

Human Health Water and Organism National Recommended WQC YES 

Human Health Organism Only National Recommended WQC YES 

Drinking Water MCL YES 

Fish Ingestion NEHC for Mink YES 

 

51 EPA did not use the state 303d lists of impaired waters in order to ensure 

comprehensive coverage of all pollutants of concern. 

52 See the EA for the details and amounts of the projected improvements. 
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Criteria Evaluated for Exceedances

Will 

Improve 

Under the 

Final Rule?

Fish Ingestion NEHC for Eagles YES 

Adverse Reproductive Effects in Fish due to Selenium YES 

Adverse Reproductive Effects in Mallards due to Selenium YES 

Non-Cancer Reference Dose for Child (Recreational and 

Subsistence fishers) 

YES 

Non-Cancer Reference Dose for Adult (Recreational and 

Subsistence fishers) 

YES 

Arsenic Cancer Risk for Child (Recreational and 

Subsistence fishers) 

YES 

Arsenic Cancer Risk for Adult (Recreational and 

Subsistence fishers) 

YES 

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 

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. 
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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. 
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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. Casestudy 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 
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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 
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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 longterm 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 
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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 
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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. Noncancer 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 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 
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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. 
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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; 
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 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 
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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 
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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 longterm impacts to ecosystem dynamics. EPA estimates that postcompliance 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 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 
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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 
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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 

Benefit Category 

Quantified 

And 

Monetized 

Quantified 

But Not 

Monetized 

Neither 

Quantified 

Nor 

Monetized 
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Table XIV-1. Benefit Categories Associated with Final Rule 

Benefit Category 

Quantified 

And 

Monetized 

Quantified 

But Not 

Monetized 

Neither 

Quantified 

Nor 

Monetized 

1. Human Health Benefits from Surface Water Quality Improvements 

Reduced incidence of cancer from 

arsenic exposure via fish 

consumption 

X 

Reduced incidence of cardiovascular 

disease from arsenic exposure via 

fish consumption 

X 

Reduced incidence of cardiovascular 

disease from lead exposure via fish 

consumption 

Xa

Reduced incidence of other cancer 

and non-cancer adverse health 

effects (e.g., reproductive, 

immunological, neurological, 

circulatory, or respiratory 

toxicity) due to exposure to 

arsenic, lead, cadmium, and other 

toxics from fish consumption 

X 

Reduced IQ loss in children from 

lead exposure via fish consumption X 

Reduced need for specialized 

education for children from lead 

exposure via fish consumption 

X 

Reduced in utero mercury exposure 

via maternal fish consumption X 

Reduced health hazards from 

exposure to pollutants in waters 

used recreationally (e.g., 

swimming) 

 X 
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Table XIV-1. Benefit Categories Associated with Final Rule 

Benefit Category 

Quantified 

And 

Monetized 

Quantified 

But Not 

Monetized 

Neither 

Quantified 

Nor 

Monetized 

2.Ecological Conditions and Recreational Use Benefits from Surface 

Water Quality Improvements 

Benefits from improvements in 

surface water quality, 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 waterb; 

and non-use value (existence, 

option, and bequest value from 

improved ecosystem health)b

X 

Benefits from improved protection 

of threatened and endangered 

species 

X 

Reduced sediment contamination X 

3.Market and Productivity Benefits 

Reduced impoundment failures 

(monetized benefits include avoided 

cleanup costs, transaction costs, 

and environmental damages; nonquantified benefits include avoided 

injury) 

X X 

Reduced water treatment costs for 

municipal drinking water, irrigation 

water, and industrial process 

 X 

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 Xa 

Reduced maintenance dredging in 

navigational waterways and 

reservoirs from reduction in 

sediment discharges 

Xa 
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Table XIV-1. Benefit Categories Associated with Final Rule 

Benefit Category 

Quantified 

And 

Monetized 

Quantified 

But Not 

Monetized 

Neither 

Quantified 

Nor 

Monetized 

4.Air-Related Benefits

Human health benefits from reduced 

morbidity and mortality from 

exposure to NOX, SO2 and particulate 

matter (PM2.5) 

X 

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 
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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 healthrelated 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 
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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, statespecific average fishing rates, and data on fish consumption 

advisories to estimate the exposed population. EPA used cohortspecific 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. 
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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. 

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 Children from 

Lead Exposure via Fish Consumptiona

$1.0

($0.8 to $1.1)

Benefits from Reduced Need for Specialized 

Education for Children from Lead Exposure via 

Fish Consumption 

<$0.1

Benefits from Reduced Incidence of Cardiovascular 

Disease (CVD) from Lead Exposure via Fish 

Consumption 

$12.8

Benefits of Reduced In Utero Mercury Exposure via 

Maternal Fish Consumptiona

$3.5

($2.9 to $4.0)

Benefits from Reduced Incidence of Cancer from 

Arsenic Exposure via Fish Consumption 

<$0.1

Subtotalb $16.5 to $17.9

($15.2 to $16.7)

7% Discount Rate

Benefits from Reduced IQ Loss in Children from 

Lead Exposure via Fish Consumptiona

$0.2

($0.1 to $0.2)

Benefits from Reduced Need for Specialized 

Education for Children from Lead Exposure via 

Fish Consumption 

<$0.1

Benefits from Reduced Incidence of CVD from Lead 

Exposure via Fish Consumption 

$10.7

Benefits of Reduced In Utero Mercury Exposure via 

Maternal Fish Consumptiona

$0.6

($0.5 to $0.7)

Benefits from Reduced Incidence of Cancer from 

Arsenic Exposure via Fish Consumption 

<$0.1

Subtotalb $11.4

($10.7 to $11.0)
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Table XIV-2. Human Health Benefits from Surface Water Quality 

Improvements 

Benefit Category 

Annualized benefits 

(Million 2013$) 

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 
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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 
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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 

(U.S. EPA, 2013a). 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 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 metaregression 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 
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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 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 
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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 
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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 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 
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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,53 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. 

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 

 

53 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. 
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release, including cleanup, natural resource damages (NRD),54 and 

transaction costs.55

Using the approach above, EPA estimates the annualized 

benefits of the final rule $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 

 

54 NRD include only the resource restoration and compensation values; they do 

not include cleanup costs (or legal costs). 

55 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. 
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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 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 
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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 
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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

Benefit category 

3 percent 

discount 

rate 

7 percent 

discount 

rateb

Human health benefits from reduced morbidity 

and mortality from exposure to NOx, SO2 and 

particulate matter (PM2.5) 

$144.7 $108.8

Avoided climate change impacts from CO2

emissionsb

$139.8 $139.8

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. 
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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 
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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 

Benefit Category 

Annualized Monetized 

Benefits (Million 2013$)

3 Percent Discount Rate 

Human Health Benefits from Surface Water 

Improvementsa,d

$16.5 to $17.9 million

Improved Ecological Conditions and 

Recreational Usesa,b,d

$23.3 to $129.5

Market and Productivity Benefits (impoundment 

failure and ash marketing) 

$126.4 to 

$133.7

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 

Improvementsa 

$11.3 to $11.6

Improved Ecological Conditions and 

Recreational Usesa,b

$18.6 to $103.4

Market and Productivity Benefits (impoundment 

failure and ash marketing) 

$108.8 to $114.8

Human Health Benefits from Air Quality 

Improvements 

$108.8

Other Air-Related Benefitsc (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 willingnessto-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. 
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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 
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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 toxicweighted pounds remaining after POTW treatment. The costeffectiveness 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 
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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 costeffectiveness 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 costeffectiveness ratio of $134/lb-eq ($1981). This costeffectiveness ratio is well within the range of costeffectiveness 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 
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(Transportation Equipment Cleaning), in 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 nondetect. 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 
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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 nondetected values were the result of not using sufficiently 

sensitive methods. The view was expressed that, should the nondetects 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 
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observations in combination with wide variability in samplespecific 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 nondetects 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. 
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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 
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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 
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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 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 
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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.56 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: 

(a) Time to expeditiously plan (including to raise 

capital), design, procure, and install equipment to comply with 

the requirements of the final rule; 

 

56 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. 
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(b) Changes being made or planned at the plant in response 

to greenhouse gas regulations for new or existing fossil fuelfired 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 
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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 welldocumented 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 
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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 
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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).57 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.58 See TDD Section 14 for additional information 

regarding the legacy wastewater BAT limitations and guidance on 

implementing them into NPDES permits. 

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 

 

57 For plants in the voluntary incentives program, legacy FGD wastewater is 

FGD wastewater generated prior to December 31, 2023 (see Section VIII.C.13). 

58 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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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 wellknown dilution flow, such as cooling water, uncontaminated 

stormwater, or cooling tower blowdown, the concentration-based 

limitation for the regulated wastestream is reduced by 
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multiplying it by a factor.59 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.60 

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 

 

59 As is the case with a single regulated wastestream, if the combined 

wastestream is not discharged, then the limitations and standards are not 

applicable. 

60 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. 
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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 
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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 403.6.61 See TDD Section 14 for more 

examples and details about this guidance. 

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 

 

61 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. 
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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 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 
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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 
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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 
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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 
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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 
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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). 

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 
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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 
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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 
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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,62 especially where steam electric power 

plants are located upstream from drinking water intakes. 

Bromides (a component of TDS) are not directly controlled 

by the numeric effluent limitations and standards for existing 

sources under this final rule63 (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). 

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 

 

62 Some may establish limitations on TDS as an indicator of bromide because 

bromide is a component of TDS. 

63 TDS, like all pollutants, are controlled where there are zero discharge 

effluent limitations and standards. 
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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 chlorobromo 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 
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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. 

EPA regulations at 40 CFR 122.44(d)(1) require that each 

NPDES permit shall include any requirements, in addition to or 
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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 
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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 
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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 
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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. 
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Table XVII-1. Total Monetized Annualized Benefits and Costs of 

the Final BAT and PSES (Millions, 2013$, three percent discount 

rate)a

 Total Social Costsb

Total Monetized 

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. 

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 
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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 
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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). 
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Table XVII-2. Number of Entities Owning Steam Electric Power 

Plants by Sector and Size (Assuming Two Different Ownership 

Cases)a

Ownership Type 

Lower bound estimate of 

number of entities owning 

steam electric power 

plantsb

Upper bound estimate of 

number of entities owning 

steam electric power 

plantsb

Total Smallc % Small Total Smallc % 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 
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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. 
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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 steam electric 

power plants 

Upper bound estimate of number of 

entities owning steam electric 

power plants 

Cost 1% of 

Revenue 

Cost 3% of 

Revenue 

Cost 1% of 

Revenue 

Cost 3% of 

Revenue 

Number 

of Small 

Entities 

% of 

Small 

Affected 

Entities b

Number 

of Small 

Entities a

% of 

Small 

Affected 

Entities b

Number 

of Small 

Entities

% of 

Small 

Affected 

Entities b

Number 

of Small 

Entities a

% of 

Small 

Affected 

Entities b

Ownership 

Type Out of total 110 small entities Out of total 191 small entities

Cooperativ

e 

1 3.8% 0 0.0% 1 2.2% 0 0.0%

InvestorOwned 0 0.0% 0 0.0% 0 0.0% 0 0.0%

Municipali

ty 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 

Subdivisio

n 

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 
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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-togovernment dialogue leading to the proposed rule in its preamble 

to the proposed rulemaking. EPA received comments from state and 
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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. 
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E. Executive Order 13132: Federalism 

Under Executive Order (EO) 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 
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summary impact statement as required by section 6(b) of EO 

13132. 

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, 
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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 
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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 EO 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 
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in EO 13175. EPA’s analyses show that tribal governments do not 

own any facility to which the ELGs apply. Thus, EO 13175 does 

not apply to this action. 

Although EO 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 proposed 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. 
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G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks 

This action is not subject to EO 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 
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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 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 EO 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 
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electric power sector that constitute a significant adverse 

effect under EO 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 EO 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 

EO 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 
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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 EO 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 
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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 
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Comptroller General of the United States. This action is a 

“major rule” as defined by 5 U.S.C. 804(2). 

Appendix A: Definitions, Acronyms, and Abbreviations Used in 

This Document 

The following acronyms and abbreviations are used in this 

document. 

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. 
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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 
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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 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. 
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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. 
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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 
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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 
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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 
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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 waterfilled 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. 
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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 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 
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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, 
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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 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 
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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. 
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List of Subjects in 40 CFR Part 423 

Environmental protection, Electric power generation, Power 

plants, Waste treatment and disposal, Water pollution control. 

 

Dated: 

 

Gina McCarthy, 

Administrator 
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Therefore, 40 CFR Chapter I is amended as follows: 

PART 423--STEAM ELECTRIC POWER GENERATING POINT SOURCE CATEGORY 

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). 

2. Section 423.10 is revised as follows: 

§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. 

3. Section 423.11 is amended by: 

a. Revising paragraphs (b), (e), and (f). 

b. Adding paragraphs (n) through (t). 
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The revisions and additions read as follows: 

§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. 
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 (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. 
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(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 
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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, 
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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. 

(4) Other factors as appropriate. 

4. Section 423.12 is amended by: 

a. Revising paragraphs (b)(11) and (12). 

b. Adding paragraph (b)(13). 

The revisions and addition read as follows: 

§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) * * * 
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(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: 

Pollutant or 

pollutant property

BPT effluent limitations

Maximum for any 

1 day (mg/l)

Average of daily values for 30 

consecutive days 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. 

5. Section 423.13 is amended by: 

a. Revising paragraphs (g) and (h). 
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b. Adding paragraphs (i) through (n). 

The revisions and additions read as follows: 

§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 following table: 

Pollutant or pollutant 

property

BAT effluent limitations

Maximum 

for any 1 

day 

Average of daily values for 30 

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

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. 
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(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 

§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 oilfired 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 

§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 following table: 

Pollutant or pollutant 

property

BAT effluent limitations

Maximum 

for any 1 

day 

Average of daily values for 30 

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
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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. 

(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 §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 
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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), 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 §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 §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 
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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 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), 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 

§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 

§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 
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determined by multiplying the flow of gasification wastewater times 

the concentration listed in the following table: 

Pollutant or pollutant 

property

BAT effluent limitations

Maximum for any 

1 day 

Average of daily values for 

30 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

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. 

(ii) For discharges of gasification wastewater generated 

before the date determined by the permitting authority, as 

specified in paragraph (j)(1)(i), 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 §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 
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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 §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. 
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(ii) For discharges of bottom ash transport water generated 

before the date determined by the permitting authority, as 

specified in paragraph (k)(1)(i), 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 §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 §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 §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 
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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. 

6. Section 423.15 is amended by: 

a. Revising paragraphs (a), (b), and the OMB control number 

parenthetical approval statement at the end of §423.15. 

b. Removing paragraphs (c) through (n). 

The revisions read as follows: 

§423.15 New source performance standards (NSPS). 

(a) 1982 NSPS. Any new source as of November 19, 1982, subject 

to §423.15(a) of this part, must achieve the following new source 

performance standards, in addition to the limitations in §423.13 of 

this part, established on [INSERT DATE OF PUBLICATION IN THE 

FEDERAL REGISTER]. 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. 

(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, 
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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: 

Pollutant or 

pollutant property

NSPS

Maximum for any 

1 day (mg/l)

Average of daily values for 30 

consecutive days 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: 

Pollutant or 

pollutant property

NSPS

Maximum for any 

1 day (mg/l)

Average of daily values for 30 

consecutive days 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 – Nonchemical Metal Cleaning Wastes] 

(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 
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transport water times the concentration listed in the following 

table: 

Pollutant or 

pollutant property

NSPS

Maximum for any 

1 day (mg/l)

Average of daily values for 30 

consecutive days 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: 

Pollutant or pollutant 

property

NSPS

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. 
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(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: 

Pollutant or pollutant 

property

Maximum concentration

(mg/l)

Average concentration 

(mg/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: 

Pollutant or pollutant property

NSPS

Maximum concentration

(mg/l)

Average concentration

(mg/l)

Free available chlorine 0.5 0.2
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Pollutant or pollutant property

NSPS

Maximum for 

any 1 day 

(mg/l)

Average of daily values for 

30 consecutive days shall 

not exceed (mg/l)

The 126 priority pollutants 

(appendix A)contained in chemicals 

added for cooling tower 

maintenance, except:

(1) (1)

 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 

§423.15(a)(12), the quantity or quality of pollutants or pollutant 
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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 §423.15(a)(11). 

(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 (a)(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 

(a)(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 [INSERT DATE OF 

PUBLICATION IN THE FEDERAL REGISTER], subject to §423.15(b), must 

achieve the following new source performance standards: 
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(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: 

Pollutant or pollutant property

NSPS

Maximum for 

any 1 day 

(mg/l)

Average of daily values for 

30 consecutive days 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: 

Pollutant or pollutant property

NSPS

Maximum for 

any 1 day 

(mg/l)

Average of daily values for 

30 consecutive days shall 

not exceed (mg/l)

TSS 100.0 30.0

Oil and grease 20.0 15.0

Copper, total 1.0 1.0
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Pollutant or pollutant property

NSPS

Maximum for 

any 1 day 

(mg/l)

Average of daily values for 

30 consecutive days shall 

not exceed (mg/l)

Iron, total 1.0 1.0

(5) [Reserved – Nonchemical Metal Cleaning Wastes] 

(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: 
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Pollutant or pollutant 

property

NSPS

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: 

Pollutant or pollutant property

NSPS

Maximum concentration

(mg/l)

Average concentration

(mg/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 
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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: 

Pollutant or pollutant property

NSPS

Maximum concentration

(mg/l)

Average concentration

(mg/l)

Free available chlorine 0.5 0.2

Pollutant or pollutant property

Maximum for 

any 1 day 

(mg/l)

Average of daily values for 

30 consecutive days shall 

not exceed (mg/l)

The 126 priority pollutants 

(appendix A)contained in chemicals 

added for cooling tower 

maintenance, except:

(1) (1)

 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. 
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(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 

§423.15(b)(12), 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 §423.15(b)(11). 

(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: 

Pollutant or pollutant 

property

NSPS

Maximum 

for any 1 

day 

Average of daily values for 30 

consecutive days shall not exceed 
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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: 

Pollutant or pollutant 

property

NSPS

Maximum 

for any 

1 day 

Average of daily values for 30 

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

(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: 
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Pollutant or pollutant 

property

NSPS

Maximum 

for any 

1 day 

Average of daily values for 30 

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 (b)(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 

(b)(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.) 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release 

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Page 293 of 300 

7. Section 423.16 is amended by adding paragraphs (e) through 

(i) to read as follows: 

§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 

following table: 

Pollutant or pollutant 

property

PSES

Maximum 

for any 

1 day 

Average of daily values for 30 

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

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. 

(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 
*** E.O. 12866 Review – Draft – Do Not Cite, Quote, or Release 

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Page 294 of 300 

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 
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Page 295 of 300 

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 the quantity 

determined by multiplying the flow of gasification wastewater times 

the concentration listed in the following table: 

Pollutant or pollutant property

PSES

Maximum 

for any 

1 day 

Average of daily values for 30 

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
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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. 

8. Section 423.17 is amended by: 

a. Revising paragraphs (a) and (b). 

b. Removing paragraphs (c) through (e). 

The revisions read as follows: 

§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 §423.17(a), 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 §423.16 of this part, established 

on [INSERT DATE OF PUBLICATION IN THE FEDERAL REGISTER]. 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: 

Pollutant or pollutant 

property

PSNS

Maximum for any 1 

day (mg/L)

Copper, total 1.0

(3) [Reserved – Nonchemical Metal Cleaning Wastes] 
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(4)(i) Cooling tower blowdown. The pollutants discharged in 

cooling tower blowdown shall not exceed the concentration listed in 

the following table: 

Pollutant or pollutant property

PSNS

Maximum for any time (mg/l)

The 126 priority pollutants (appendix A) 

contained in chemicals added for cooling 

tower maintenance, except:

(1)

 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 §423.17(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. 
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(2) Chemical metal cleaning wastes. The pollutants discharged 

in chemical metal cleaning wastes shall not exceed the 

concentration listed in the following table: 

Pollutant or pollutant 

property

PSNS

Maximum for 1 day 

(mg/l)

Copper, total 1.0

(3) [Reserved – Nonchemical Metal Cleaning Wastes] 

(4)(i) Cooling tower blowdown. The pollutants discharged in 

cooling tower blowdown shall not exceed the concentration listed in 

the following table: 

Pollutant or pollutant property

PSNS

Maximum for any time (mg/l)

The 126 priority pollutants (appendix A) 

contained in chemicals added for cooling 

tower maintenance, except:

(1)

 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 
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Page 299 of 300 

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: 

Pollutant or pollutant 

property

PSNS

Maximum 

for any 1 

day 

Average of daily values for 30 

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

(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. 
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(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: 

Pollutant or pollutant property

PSNS

Maximum 

for any 

1 day 

Average of daily values for 30 

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

(10)(i) 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: 

Pollutant or pollutant 

property

PSNS

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not exceed 

Arsenic, total (ug/L) 11 8

Mercury, total (ng/L) 788 356