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

As Enacted ( Federal Register)

Cited authorities 34

Cited in

Federal Register, Volume 80 Issue 212 (Tuesday, November 3, 2015)

Federal Register Volume 80, Number 212 (Tuesday, November 3, 2015)

Rules and Regulations

Pages 67837-67903

From the Federal Register Online via the Government Publishing Office www.gpo.gov

FR Doc No: 2015-25663

Page 67837

Vol. 80

Tuesday,

No. 212

November 3, 2015

Part II

Environmental Protection Agency

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40 CFR Part 423

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

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 423

EPA-HQ-OW-2009-0819; FRL-9930-48-OW

RIN 2040-AF14

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

AGENCY: Environmental Protection Agency.

ACTION: Final rule.

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

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

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

2426.

FOR FURTHER INFORMATION CONTACT: For technical information, contact Ronald Jordan, Engineering and Analysis Division, Telephone: 202-566-

1003; Email: jordan.ronald@epa.gov. For economic information, contact James Covington, Engineering and Analysis Division, Telephone: 202-566-

1034; Email: covington.james@epa.gov.

SUPPLEMENTARY INFORMATION:

Organization of This Preamble

Table of Contents

Regulated Entities and Supporting Documentation

A. Regulated Entities

B. Supporting Documentation
Legal Authority for This Action
Executive Summary

A. Purpose of the Rule

B. Summary of Final Rule

C. Summary of Costs and Benefits
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
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
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
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)
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
Non-Chemical Metal Cleaning Wastes

J. Best Management Practices
Costs and Economic Impact

A. Plant-Specific and Industry Total Costs

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B. Social Costs

C. Economic Impacts

1. Summary of Economic Impacts for Existing Sources

2. Summary of Economic Impacts for New Sources
Pollutant Reductions
Development of Effluent Limitations and Standards
Non-Water Quality Environmental Impacts
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
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
Cost-Effectiveness Analysis

A. Methodology

B. Results
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
Related Acts of Congress, Executive Orders, and Agency Initiatives

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

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

D. Unfunded Mandates Reform Act

E. Executive Order 13132: Federalism

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

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

H. Executive Order 13211: Actions That Significantly Affect Energy Supply, Distribution, or Use
National Technology Transfer and Advancement Act

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

K. Congressional Review Act (CRA)

Appendix A to the Preamble: Definitions, Acronyms, and Abbreviations Used in This Preamble
Regulated Entities and Supporting Documentation

A. Regulated Entities

Entities potentially regulated by this action include:

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North American

Industry

Category Example of regulated Classification

entity System (NAICS)

Code

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Industry...................... Electric Power 22111

Generation

Facilities--Electric

Power Generation.

Electric Power 221112

Generation

Facilities--Fossil

Fuel Electric Power

Generation.

Electric Power 221113

Generation

Facilities--Nuclear

Electric Power

Generation.

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This section is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely regulated by this action. Other types of entities that do not meet the above criteria could also be regulated. To determine whether your facility is regulated by this action, you should carefully examine the applicability criteria listed in 40 CFR 423.10 and the definitions in 40 CFR 423.11 of the rule. If you still have questions regarding the applicability of this action to a particular entity, consult the person listed for technical information in the preceding FOR FURTHER INFORMATION CONTACT section.

B. Supporting Documentation

This rule is supported, in part, by the following documents:

Technical Development Document for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (TDD), Document No. EPA-821-R-15-007.

Environmental Assessment for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (EA), Document No. EPA-821-R-15-006.

Benefits and Cost Analysis for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (BCA), Document No. EPA-821-R-15-005.

Regulatory Impact Analysis for the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (RIA), Document No. EPA-821-R-15-004.

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

A. Purpose of the Rule

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

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waters by all industrial categories regulated under the CWA.\2\ The electric power industry has made great strides to reduce air pollutant emissions under Clean Air Act programs. Yet many of these pollutants are transferred to the wastewater as plants employ technologies to reduce air pollution. The pollutants in steam electric power plant wastewater discharges present a serious public health concern and cause severe ecological damage, as demonstrated by numerous documented impacts, scientific modeling, and other studies. When toxic metals such as mercury, arsenic, lead, and selenium accumulate in fish or contaminate drinking water, they can cause adverse effects in people who consume the fish or water. These effects can include cancer, cardiovascular disease, neurological disorders, kidney and liver damage, and lowered IQs in children.

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\1\ The steam electric power plants covered by the ELGs use nuclear or fossil fuels, such as coal, oil, or natural gas, to heat water in boilers, which generate steam. This rule does not apply to plants that use non-fossil fuel or non-nuclear fuel or other energy sources, such as biomass or solar thermal energy. The steam is used to drive turbines connected to electric generators. The plants generate wastewater composed of chemical pollutants and thermal pollution (heated water) from their wastewater treatment, power cycle, ash handling and air pollution control systems, as well as from coal piles, yard and floor drainage, and other plant processes.

\2\ Although the way electricity is generated in this country is changing, EPA projects that, without this final rule, steam electric power plant discharges would likely continue to account, over the foreseeable future, for about thirty percent of all toxic pollutants discharged into surface waters by all industrial categories regulated under the CWA.

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There are, however, affordable technologies that are widely available, and already in place at some plants, which are capable of reducing or eliminating steam electric power plant discharges. In the several decades since the steam electric ELGs were last revised, such technologies have increasingly been used at plants. This final rule is the first to ensure that plants in the steam electric industry employ technologies designed to reduce discharges of toxic metals and other harmful pollutants discharged in the plants' largest sources of wastewater.

Steam electric power plant discharges occur in proximity to nearly 100 public drinking water intakes and more than 1,500 public wells across the nation, and recent studies indicate that steam electric power plant discharges can adversely affect surface waters used as drinking water supplies. One study found that arsenic in ash and flue gas desulfurization (FGD) wastewater discharges from four steam electric power plants exceeded Safe Drinking Water Act (SDWA) Maximum Contaminant Levels (MCLS) in the waterbodies into which they discharged, indicating that these contaminants are present in surface waters, and at levels above standards used to protect drinking water. See DCN SE01984. A second, more recent study found increased levels of bromide in rivers used as drinking water after FGD systems were installed at upstream steam electric power plants. The study showed an increase in bromides at four drinking water utilities' intakes after wastewater from these FGD systems began to be discharged to the rivers, whereas prior to the FGD wastewater discharges, bromides were not a problem in the intake waters of the utilities. With bromides present in their drinking water source waters at increased levels, carcinogenic disinfection by-products (brominated DBPs, in particular trihalomethanes (THMs)) began forming, and at one drinking water utility, violations of the THM MCL began occurring. See DCN SE04503.

Nitrogen discharged by steam electric power plants can also impact drinking water sources by contributing to harmful algal blooms in reservoirs and lakes that are used as drinking water sources. Ground water contamination from surface impoundments (ash ponds) containing steam electric power plant wastewater also threatens drinking water, as evidenced by more than 30 documented cases. See EA Section 3.3.

Steam electric power plant discharges also adversely affect the quality of fish that people eat. Water quality modeling shows that about half of waterbodies that receive steam electric power plant discharges exhibit health risks to people consuming fish from those waters (primarily from mercury). Nearly half of waterbodies that receive steam electric power plant discharges exhibit pollutant levels for one or more steam electric power plant pollutants in excess of human health water quality criteria (WQC).\3\ See EA Section 4. People who eat large amounts of fish from lakes and rivers contaminated by mercury, lead, and arsenic are particularly at risk, and consumption of such fish poses additional risk to the fetuses of pregnant women. Compared to the general public, minority and low-income communities have greater exposure to, and are therefore at greater risk from, pollutants in steam electric power plant discharges, due to their closer proximity to the discharges and greater consumption of fish from contaminated waters. See Section XVII.J.

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\3\ WQCs are established by states to protect beneficial uses of waterbodies, such as the support of aquatic life and provision of fishing and swimming.

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Steam electric power plant discharges adversely affect our nation's waters and their ecology. Pollutants in such discharges, particularly mercury and selenium, bioaccumulate in fish and wildlife, and they accumulate in the sediments of lakes and reservoirs, remaining there for decades. Documented adverse impacts include the near eradication of an entire fish population in the late 1970s in Belews Lake, North Carolina, due to selenium discharges from a steam electric power plant (DCN SE01842); a series of fish kills in the 1970s in Martin Lake, Texas, also due to selenium discharges from a steam electric power plant (elevated selenium levels and deformities persisted for at least eight years after the plant ceased discharging) (DCN SE01861); reproductive impairment and deformities in fish and birds from selenium discharges (DCN SE04519); and other forms of impacts to surface waters, as documented by numerous other damage cases associated with discharges from surface impoundments containing steam electric power plant wastewater. See EA Section 3.3.

Waterbodies receiving steam electric power plant discharges have routinely exhibited pollutant levels routinely in excess of state WQC for pollutants found in the plant discharges. This includes pollutants such as selenium, arsenic, and cadmium. Nutrients in steam electric power plant discharges can cause over-enrichment of receiving waters, resulting in water quality problems, such as low oxygen levels and loss of critical submerged aquatic vegetation, further impairing beneficial uses such as fishing. EPA's modeling corroborates such documented impacts, revealing that nearly one fifth of waterbodies receiving steam electric power plant discharges exceed WQC for protection of aquatic life and nearly one third of such receiving waters pose potential reproductive risks to birds that prey on fish.

The steam electric ELGs that EPA promulgated and revised in 1974, 1977, and 1982 are out of date. They do not adequately control the pollutants (toxic metals and other) discharged by this industry, nor do they reflect relevant process and technology advances that have occurred in the last 30-plus years. The rise of new processes for generating electric power (e.g. coal gasification) and the widespread implementation of air pollution controls (e.g., FGD and flue gas mercury control (FGMC)) have altered existing wastestreams and created new types of wastewater at many steam electric power plants, particularly coal-fired plants. The processes employed and pollutants discharged by the industry look very different today than they did in 1982. Many plants, nonetheless, still treat their wastewater using only surface impoundments, which are largely ineffective at controlling discharges of toxic pollutants and nutrients. This final rule addresses an outstanding public health and environmental problem by

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

B. Summary of Final Rule

To further its ultimate objective to ``restore and maintain the chemical, physical, and biological integrity of the Nation's waters,'' the CWA authorizes EPA to establish national technology-based effluent limitations guidelines and new source performance standards for discharges from categories of point sources that occur directly into waters of the U.S. The CWA also authorizes EPA to promulgate nationally applicable pretreatment standards that control pollutant discharges from existing and new sources that discharge wastewater indirectly to waters of the U.S. through sewers flowing to publicly owned treatment works (POTWs). EPA establishes ELGs based on the performance of well-

designed and well-operated control and treatment technologies.

EPA completed a study of the steam electric category in 2009 and proposed the ELG rule in June 2013. The public comment period extended for more than three months. This final rule reflects the statutory factors outlined in the CWA, as well as EPA's full consideration of the comments received and updated analytical results.

Existing Sources--Direct Discharges. For existing sources that discharge directly to surface water, with the exception of oil-fired generating units and small generating units (those with a nameplate capacity of 50 megawatts (MW) or less), the final rule establishes effluent limitations based on Best Available Technology Economically Achievable (BAT). BAT is based on technological availability, economic achievability, and other statutory factors and is intended to reflect the highest performance in the industry (see Section IV.B.3). The final rule establishes BAT limitations as follows: \4\

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

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For fly ash transport water, bottom ash transport water, and FGMC wastewater, there are two sets of BAT limitations. The first set of BAT limitations is a numeric effluent limitation on Total Suspended Solids (TSS) in the discharge of these wastewaters (these limitations are equal to the TSS limitations in the previously established Best Practicable Control Technology Currently Available (BPT) regulations). The second set of BAT limitations is a zero discharge limitation for all pollutants in these wastewaters.\5\

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\5\ When fly ash transport water or bottom ash transport water is used in the FGD scrubber, the applicable limitations are those established for FGD wastewater on mercury, arsenic, selenium and nitrate/nitrite as N.

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For FGD wastewater, there are two sets of BAT limitations. The first set of limitations is a numeric effluent limitation on TSS in the discharge of FGD wastewater (these limitations are equal to the TSS limitations in the previously established BPT regulations). The second set of BAT limitations is numeric effluent limitations on mercury, arsenic, selenium, and nitrate/nitrite as N in the discharge of FGD wastewater.\6\

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\6\ For plants that opt into the voluntary incentives program, the second set of BAT limitations is numeric effluent limitations on mercury, arsenic, selenium, and TDS in the discharge of FGD wastewater.

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For gasification wastewater, there are two sets of BAT limitations. The first set of limitations is a numeric effluent limitation on TSS in the discharge of gasification wastewater (this limitation is equal to the TSS limitation in the previously established BPT regulations). The second set of BAT limitations is numeric effluent limitations on mercury, arsenic, selenium, and total dissolved solids (TDS) in the discharge of gasification wastewater.

A numeric effluent limitation on TSS in the discharge of combustion residual leachate from landfills and surface impoundments. This limitation is equal to the TSS limitation in the previously established BPT regulations.

For oil-fired generating units and small generating units (50 MW or smaller), the final rule establishes BAT limitations on TSS in the discharge of fly ash transport water, bottom ash transport water, FGMC wastewater, FGD wastewater, and gasification wastewater. These limitations are equal to the TSS limitations in the existing BPT regulations.

New Sources--Direct Discharges. The CWA mandates that new source performance standards (NSPS) reflect the greatest degree of effluent reduction that is achievable, including, where practicable, a standard permitting no discharge of pollutants (see Section IV.B.4). NSPS represent the most stringent controls attainable, taking into consideration the cost of achieving the effluent reduction and any non-

water quality environmental impacts and energy requirements. For direct discharges to surface waters from new sources, including discharges from oil-fired generating units and small generating units, the final rule establishes NSPS as follows:

A zero discharge standard for all pollutants in fly ash transport water, bottom ash transport water, and FGMC wastewater.

Numeric standards on mercury, arsenic, selenium, and TDS in the discharge of FGD wastewater.

Numeric standards on mercury and arsenic in the discharge of combustion residual leachate.

Existing Sources--Discharges to POTWs. Pretreatment Standards for Existing Sources (PSES) are designed to prevent the discharge of pollutants that pass through, interfere with, or are otherwise incompatible with the operation of POTWs. PSES are analogous to BAT effluent limitations for direct dischargers and are generally based on the same factors (see Section IV.B.5). The final rule establishes PSES as follows: \7\

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

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A zero discharge standard for all pollutants in fly ash transport water, bottom ash transport water, and FGMC wastewater.\8\

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\8\ When fly ash transport water or bottom ash transport water is used in the FGD scrubber, the applicable standards are those established for FGD wastewater on mercury, arsenic, selenium and nitrate/nitrite as N.

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Numeric standards on mercury, arsenic, selenium, and nitrate/nitrite as N in the discharge of FGD wastewater.

Numeric standards on mercury, arsenic, selenium and TDS in the discharge of gasification wastewater.

New Sources--Discharges to POTWs. Pretreatment standards for new sources (PSNS) are also designed to prevent the discharge of any pollutant into a POTW that interferes with, passes through, or is otherwise incompatible with the POTW. PSNS are analogous to NSPS for direct dischargers, and EPA generally considers the same factors for both sets of standards (see Section IV.B.6). The final rule establishes PSNS that are the same as the rule's NSPS.

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C. Summary of Costs and Benefits

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

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\10\ EPA estimates that the population of steam electric power plants is about 1080.

Table III-1--Total Monetized Annualized Benefits and Costs of the Final Rule

Millions; 2013$

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Total monetized social benefits Total social costs

Discount rate -------------------------------------------------------------------

3% 7% 3% 7%

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Final Rule.................................. $451 to $566 $387 to $478 $480 $471

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

effectiveness analysis, and Section XVI provides information regarding implementation of the rule.
Background

A. Clean Water Act

Congress passed the CWA to ``restore and maintain the chemical, physical, and biological integrity of the Nation's waters.'' 33 U.S.C. 1251(a). In order to achieve this objective, the Act has, as a national goal, the elimination of the discharge of all pollutants into the nation's waters. 33 U.S.C. 1251(a)(1). The CWA establishes a comprehensive program for protecting our nation's waters. Among its core provisions, the CWA prohibits the discharge of pollutants from a point source to waters of the U.S., except as authorized under the CWA. Under section 402 of the CWA, 33 U.S.C. 1342, discharges may be authorized through a National Pollutant Discharge Elimination System (NPDES) permit. The CWA establishes a dual approach for these permits, technology-based controls that establish a floor of performance for all dischargers, and water quality-based effluent limitations, where the technology-based effluent limitations are insufficient to meet applicable WQS. To serve as the basis for the technology-based controls, the CWA authorizes EPA to establish national technology-based effluent limitations guidelines and new source performance standards for discharges from categories of point sources (such as industrial, commercial, and public sources) that occur directly into waters of the U.S.

The CWA also authorizes EPA to promulgate nationally applicable pretreatment standards that control pollutant discharges from sources that discharge wastewater indirectly to waters of the U.S., through sewers flowing to POTWs, as outlined in sections 307(b) and (c) of the CWA, 33 U.S.C. 1317(b) and (c). EPA establishes national pretreatment standards for those pollutants in wastewater from indirect dischargers that pass through, interfere with, or are otherwise incompatible with POTW operations. Generally, pretreatment standards are designed to ensure that wastewaters from direct and indirect industrial dischargers are subject to similar levels of treatment. See CWA section 301(b), 33 U.S.C. 1311(b). In addition, POTWs are required to implement local treatment limits applicable to their industrial indirect dischargers to satisfy any local requirements. See 40 CFR 403.5.

Direct dischargers (those discharging directly to surface waters) must comply with effluent limitations in NPDES permits. Indirect dischargers, who discharge through POTWs, must comply with pretreatment standards. Technology-based effluent limitations and standards in NPDES permits are derived from effluent limitations guidelines (CWA sections 301 and 304, 33 U.S.C. 1311 and 1314) and new source performance standards (CWA section 306, 33 U.S.C. 1316) promulgated by EPA, or based on best professional judgment (BPJ) where EPA has not promulgated an applicable effluent limitation guideline or new source performance standard (CWA section 402(a)(1)(B), 33 U.S.C. 1342(a)(1)(B)). Additional limitations are also required in the permit where necessary to meet WQS. CWA section 301(b)(1)(C), 33 U.S.C. 1311(b)(1)(C). The ELGs are established by EPA regulation for categories of industrial dischargers and are based on the degree of control that can be achieved using various levels of pollution control technology, as specified in the Act (e.g., BPT, BCT, BAT; see below).

EPA promulgates national ELGs for major industrial categories for three classes of pollutants: (1) Conventional pollutants (TSS, oil and grease, biochemical oxygen demand (BOD5), fecal coliform, and pH), as outlined in

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

B. Effluent Guidelines Program

EPA establishes ELGs based on the performance of well-designed and well-operated control and treatment technologies. The legislative history of CWA section 304(b), which is the heart of the effluent guidelines program, describes the need to press toward higher levels of control through research and development of new processes, modifications, replacement of obsolete plants and processes, and other improvements in technology, taking into account the cost of controls. Congress has also stated that EPA need not consider water quality impacts on individual water bodies as the guidelines are developed; see Statement of Senator Muskie (principal author) (October 4, 1972), reprinted in Legislative History of the Water Pollution Control Act Amendments of 1972, at 170. (U.S. Senate, Committee on Public Works, Serial No. 93-1, January 1973).

There are four types of standards applicable to direct dischargers, and two types of standards applicable to indirect dischargers, described in detail below.

1. Best Practicable Control Technology Currently Available

Traditionally, EPA establishes effluent limitations based on BPT by reference to the average of the best performances of facilities within the industry, grouped to reflect various ages, sizes, processes, or other common characteristics. EPA can promulgate BPT effluent limitations for conventional, toxic, and nonconventional pollutants. In specifying BPT, EPA looks at a number of factors. EPA first considers the cost of achieving effluent reductions in relation to the effluent reduction benefits. The Agency also considers the age of equipment and facilities, the processes employed, engineering aspects of the control technologies, any required process changes, non-water quality environmental impacts (including energy requirements), and such other factors as the Administrator deems appropriate. See CWA section 304(b)(1)(B), 33 U.S.C. 1314(b)(1)(B). If, however, existing performance is uniformly inadequate, EPA may establish limitations based on higher levels of control than what is currently in place in an industrial category, when based on an Agency determination that the technology is available in another category or subcategory and can be practically applied.

2. Best Conventional Pollutant Control Technology

The 1977 amendments to the CWA require EPA to identify additional levels of effluent reduction for conventional pollutants associated with Best Conventional Pollutant Control Technology (BCT) for discharges from existing industrial point sources. In addition to other factors specified in section 304(b)(4)(B), 33 U.S.C. 1314(b)(4)(B), the CWA requires that EPA establish BCT limitations after consideration of a two-part ``cost reasonableness'' test. EPA explained its methodology for the development of BCT limitations on July 9, 1986 (51 FR 24974). Section 304(a)(4) designates the following as conventional pollutants: BOD5, TSS, fecal coliform, pH, and any additional pollutants defined by the Administrator as conventional. The Administrator designated oil and grease as a conventional pollutant on July 30, 1979 (44 FR 44501; 40 CFR 401.16).

3. Best Available Technology Economically Achievable

BAT represents the second level of stringency for controlling direct discharges of toxic and nonconventional pollutants. As the statutory phrase intends, EPA considers the technological availability and the economic achievability in determining what level of control represents BAT. CWA section 301(b)(2)(A), 33 U.S.C. 1311(b)(2)(A). Other statutory factors that EPA considers in assessing BAT are the cost of achieving BAT effluent reductions, the age of equipment and facilities involved, the process employed, potential process changes, non-water quality environmental impacts (including energy requirements), and such other factors as the Administrator deems appropriate. The Agency retains considerable discretion in assigning the weight to be accorded these factors. Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1045 (D.C. Cir. 1978). Generally, EPA determines economic achievability based on the effect of the cost of compliance with BAT limitations on overall industry and subcategory (if applicable) financial conditions. BAT is intended to reflect the highest performance in the industry, and it may reflect a higher level of performance than is currently being achieved based on technology transferred from a different subcategory or category, bench scale or pilot studies, or foreign plants. Am. Paper Inst. v. Train, 543 F.2d 328, 353 (D.C. Cir. 1976); Am. Frozen Food Inst. v. Train, 539 F.2d 107, 132 (D.C. Cir. 1976). BAT may be based upon process changes or internal controls, even when these technologies are not common industry practice. See Am. Frozen Food Inst., 539 F.2d at 132, 140; Reynolds Metals Co. v. EPA, 760 F.2d 549, 562 (4th Cir. 1985); Cal. & Hawaiian Sugar Co. v. EPA, 553 F.2d 280, 285-88 (2nd Cir. 1977).

4. Best Available Demonstrated Control Technology/New Source Performance Standards

NSPS reflect ``the greatest degree of effluent reduction'' that is achievable based on the ``best available demonstrated control technology'' (BADCT), ``including, where practicable, a standard permitting no discharge of pollutants.'' CWA section 306(a)(1), 33 U.S.C. 1316(a)(1). Owners of new facilities have the opportunity to install the best and most efficient production processes and wastewater treatment technologies. As a result, NSPS generally represent the most stringent controls attainable through the application of BADCT for all pollutants (that is, conventional, nonconventional, and toxic pollutants). In establishing NSPS, EPA is directed to take into consideration the cost of achieving the effluent reduction and any non-

water quality environmental impacts and energy requirements. CWA section 306(b)(1)(B), 33 U.S.C. 1316(b)(1)(B).

5. Pretreatment Standards for Existing Sources

Section 307(b) of the CWA, 33 U.S.C. 1317(b), authorizes EPA to promulgate pretreatment standards for discharges of pollutants to POTWs. PSES are designed to prevent the discharge of pollutants that pass through, interfere with, or are otherwise incompatible with the operation of POTWs. Categorical pretreatment standards are technology-

based and are analogous to BPT and BAT effluent limitations guidelines, and thus the Agency typically considers the same factors in promulgating PSES as it considers in promulgating BAT. Congress intended for the combination of pretreatment and treatment by the POTW to achieve the level of treatment that would be required if the industrial source were making a direct discharge. Conf. Rep. No. 95-

830, at 87 (1977), reprinted in U.S. Congress. Senate Committee on Public Works (1978), A

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Legislative History of the CWA of 1977, Serial No. 95-14 at 271 (1978). The General Pretreatment Regulations, which set forth the framework for the implementation of categorical pretreatment standards, are found at 40 CFR part 403. These regulations establish pretreatment standards that apply to all non-domestic dischargers. See 52 FR 1586 (January 14, 1987).

6. Pretreatment Standards for New Sources

Section 307(c) of the CWA, 33 U.S.C. 1317(c), authorizes EPA to promulgate PSNS at the same time it promulgates NSPS. As is the case for PSES, PSNS are designed to prevent the discharge of any pollutant into a POTW that interferes with, passes through, or is otherwise incompatible with the POTW. In selecting the PSNS technology basis, the Agency generally considers the same factors it considers in establishing NSPS, along with the results of a pass-through analysis. Like new sources of direct discharges, new sources of indirect discharges have the opportunity to incorporate into their operations the best available demonstrated technologies. As a result, EPA typically promulgates pretreatment standards for new sources based on best available demonstrated control technology for new sources. See Nat'l Ass'n of Metal Finishers v. EPA, 719 F.2d 624, 634 (3rd Cir. 1983).

C. Steam Electric Effluent Guidelines Rulemaking History

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

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

A. Industry Profile Changes Due to Retirements and Conversions

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

B. EPA Consideration of Other Federal Rules

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

C. Advancements in Technologies

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

The biological treatment technology that serves as part of the basis for the final requirements for FGD wastewater

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discharged from existing sources has been tested at power plants for more than ten years and demonstrated in full-scale systems for more than seven years. As this technology has matured, new vendors have emerged to provide expertise in applying it to steam electric power plants. In addition, other advanced technologies that plants may use to achieve the effluent limitations and standards for FGD wastewater in the final rule are now entering the marketplace, such as lower-cost biological treatment systems that utilize a modular-based bioreactor, which is prefabricated and can be delivered directly to the site. Another advancement related to evaporation and crystallization technology, operating at low temperatures to crystallize dissolved solids, requires no chemical treatment of the wastewater and generates no additional sludge for disposal, resulting in a simpler and more economical application for treatment of both FGD wastewater and gasification wastewater. Another development concerning the evaporation system (which is the basis for the BAT limitations for FGD wastewater in the voluntary incentives program, as well as the basis for the NSPS for FGD wastewater) is a process that generates a pozzolanic material instead of crystallized salts as a solid waste product of the treatment system; although the pozzolanic material is expected to require landfill disposal since it likely would not be a marketable material, the capital and operating cost of the overall evaporation treatment process would be reduced.

Zero valent iron (ZVI) cementation, sorption media, ion exchange, and electrocoagulation are also examples of emerging treatment technologies that are being developed to treat FGD wastewater, and they could be used to achieve the limitations in the final rule. See TDD Section 7 for a more detailed discussion.

The technologies used as the basis for the final requirements for ash transport water (dry handling and closed-loop systems) have been in operation at power plants for more than 20 years and are amply demonstrated by the record supporting the final rule. Recent advancements related to bottom ash handling technologies have focused on providing more flexible retrofit solutions and improving the thermal efficiency of the boiler operation. These advancements result in additional savings related to electricity use, operation and maintenance, water costs, and thermal energy recovery.

In sum, the record demonstrates that there have been significant advancements in relevant treatment technologies since proposal, and EPA expects that the advancements will continue as this rule is implemented by the industry.

D. Engineering Costs

For the final rule, EPA updated its cost estimates to account for public comments. The following list summarizes the main adjustments EPA made to its cost estimates for the final rule:

Adjustment of population of generating units and changes in wastewater treatment or ash handling practices to account for company-announced generating unit retirements/repowerings and conversions of ash handling systems (see Section IV.A);

Adjustment of population of generating units and changes in wastewater treatment or ash handling practices to account for implementation of the CCR rule and CPP rule (see Section IV.B);

Adjustments to the direct capital costs factors to better reflect all associated installation costs;

Adjustments to the indirect capital cost factors to account for appropriate engineering and contingency costs;

Adjustment to plant population receiving one-time bottom ash management costs;

Addition of costs for denitrification pretreatment prior to biological treatment of FGD wastewater (for certain plants);

Updates to costing inputs to account for costs of additional redundancy for the fly ash dry handling system;

Addition of tank rental costs for surge capacity during certain bottom ash handling system maintenance;

Addition of building costs for certain bottom ash and FGD wastewater systems; and

Addition of costs for equipment that can be used to mitigate high oxidation-reduction potential (ORP) levels in FGD wastewater.

See Section 9 of the TDD for additional information on the plant-

specific compliance cost estimates for the final rule.

E. Economic Impact Analysis

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

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\11\ For details on the industry survey, see TDD Section 3 and 78 FR 34432; June 7, 2013).

\12\ EIA-860: Annual Electric Generator Report; EIA-861: Annual Electric Power Industry Database; EIA-923: Utility, Non-Utility, and Combined Heat & Power Plant Database (monthly). The most current EIA data at the time of the analysis was for the year 2012.

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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\

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

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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 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.
Industry Description

A. General Description of Industry

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

B. Steam Electric Process Wastewater and Control Technologies

While almost all steam electric power plants generate certain wastewater, like cooling water and boiler blowdown, the presence of other wastestreams depends on the type of fuel burned. Coal- and petroleum coke-fired generating units, and to a lesser degree oil-fired generating units, generate a flue gas stream that contains large quantities of particulate matter, sulfur dioxide, and nitrogen oxides, which would be emitted to the atmosphere if they were not cleaned from the flue gas prior to emission. Therefore, many of these generating units are outfitted with air pollution control systems (e.g., particulate removal systems, FGD systems, nitrogen oxide (NOX)-removal systems, and mercury control systems). Gas-

fired generating units generate fewer emissions of particulate matter, sulfur dioxide, and nitrogen oxides than coal- or oil-fired generating units, and therefore do not typically operate air pollution control systems to control emissions from their flue gas. In addition, coal-, oil-, and petroleum coke-fired generating units create fly and/or bottom ash as a result of coal combustion. The wastewaters associated with ash transport and air pollution control systems contain large quantities of metals (e.g., arsenic, mercury, and selenium).

See TDD Sections 4, 6, and 7 for details on these systems, the wastewaters they generate, the number of facilities that operate the systems and generate wastewater, and the control technologies used for wastewater treatment prior to discharge.

1. FGD Wastewater

FGD systems are used to remove sulfur dioxide from the flue gas so that it is not emitted into the air. Dry FGD systems spray a sorbent slurry into a reactor vessel so that the droplets dry as they contact the hot flue gas. Although dry FGD scrubbers use water in their operation, the water in most systems evaporates and they generally do not discharge wastewater. Wet FGD systems contact the sorbent slurry with flue gas in a reactor vessel producing a wastewater stream.

Treatment technologies for FGD wastewater include chemical precipitation, biological treatment, and evaporation. At some plants, this wastewater is handled in surface impoundments, constructed wetlands, or through practices achieving zero discharge. As described above in Section V.C and TDD section 7, EPA identified other technologies that have been evaluated or are being developed to treat FGD wastewater, including iron cementation, ZVI cementation, reverse osmosis, absorption or adsorption media, ion exchange, and electrocoagulation.

2. Fly Ash Transport Water

Plants use particulate removal systems to collect fly ash and other particulates from the flue gas in hoppers located underneath the equipment. Of the coal-, petroleum coke-, and oil-fired steam electric power plants that generate fly ash, most of them transport fly ash pneumatically from the hoppers to temporary storage silos, thereby not generating any transport water. Some plants, however, use water to transport (sluice) the fly ash from the hoppers to a surface impoundment. The water used to transport the fly ash to the surface impoundment is usually discharged to surface water as overflow from the impoundment after the fly ash has settled to the bottom.

3. Bottom Ash Transport Water

Bottom ash consists of heavier ash particles that are not entrained in the flue gas and fall to the bottom of the furnace. In most furnaces, the hot bottom ash is quenched in a water-filled hopper. For purposes of this rule, boiler slag is considered bottom ash. Boiler slag is the molten bottom ash collected at the base of the furnace that is quenched with water. Most plants use water to transport (sluice) the bottom ash from the hopper to an impoundment or dewatering bins. The ash sent to a dewatering bin is separated from the transport water and then disposed. For both of these systems, the water used to transport the bottom ash to the impoundment or dewatering bins is usually discharged to surface water as overflow from the systems, after the bottom ash has settled to the bottom.

Of the coal-, petroleum coke-, and oil-fired steam electric power plants that generate bottom ash, most operate wet sluicing handling systems. There are two types of bottom ash handling technologies that can meet zero discharge requirements: (1) Dry handling technologies that do not use any water, including systems such as dry vacuum or pressure systems, dry mechanical conveyor systems, and vibratory belt systems; and (2) wet systems that do not generate or discharge ash transport water, including mechanical drag systems (MDS), remote MDS, and complete-recycle systems.

4. FGMC Wastewater

FGMC systems remove mercury from the flue gas, so that it is not emitted into

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the air. There are two types of systems used to control flue gas mercury emissions: (1) Addition of oxidizing agents to the coal prior to combustion; and (2) injection of activated carbon into the flue gas after combustion. Addition of oxidizing agents to the coal prior to combustion does not generate a new wastewater stream; it can, however, increase the mercury concentration in the FGD wastewater because the oxidized mercury is more easily removed by the FGD system. Injection of activated carbon into the flue gas does have the potential to generate a new wastestream at a plant, depending on the location of the injection. If the injection occurs upstream of the primary particulate removal system, then the mercury-containing carbon (FGMC waste) is collected and handled the same way as, and together with, the fly ash. Therefore, if the fly ash is wet sluiced, then the FGMC wastes are also wet sluiced and likely sent to the same surface impoundment. In this case, adding the FGMC waste to the fly ash can increase the amount of mercury in the fly ash transport water. If the injection occurs downstream of the primary particulate removal system, the plant will need a secondary particulate removal system (typically a fabric filter) to capture the FGMC wastes.

Of the current or planned activated carbon injection systems, most operate upstream injection. However, plants that wish to market their fly ash will typically inject the activated carbon downstream of the primary particulate removal system to prevent contaminating the fly ash with carbon. For plants operating downstream injection, the FGMC wastes, which would be collected with some carry-over fly ash, could be handled separately from fly ash in either a wet or dry handling system.

5. Combustion Residual Leachate From Landfills and Surface Impoundments

Combustion residuals comprise a variety of wastes from the combustion process, which are generally collected by or generated from air pollution control technologies. These combustion residuals can be stored at the plant in on-site landfills or surface impoundments. Leachate includes liquid, including any suspended or dissolved constituents in the liquid, that has percolated through or drained from waste or other materials placed in a landfill, or that passes through the containment structure (e.g., bottom, dikes, berms) of a surface impoundment. Based on data from the industry survey, most landfills and some impoundments have a system to collect the leachate.

In a lined landfill or impoundment, the combustion residual leachate collected in the liner is typically transported to an impoundment (e.g., collection pond). Some plants discharge the effluent from these impoundments containing combustion residual leachate directly to receiving waters, while other plants first send the impoundment effluent to another impoundment handling the ash transport water or other treatment system (e.g., constructed wetlands) prior to discharge. Unlined impoundments and landfills usually do not collect leachate, which would allow the leachate to potentially migrate to nearby ground waters, drinking water wells, or surface waters.

Using data from the industry survey and site visits, surface impoundments are the most widely used systems to treat combustion residual leachate. EPA also identified different management practices, with approximately one-third of plants collecting the combustion residual leachate from impoundments and recycling it back to the impoundment from which it was collected. Some plants use their collected leachate as water for moisture conditioning of dry fly ash prior to disposal or for dust control around dry unloading areas and landfills.

6. Gasification Wastewater

Integrated Gasification Combined Cycle (IGCC) plants use a carbon-

based feedstock (e.g., coal or petroleum coke) and subject it to high temperature and pressure to produce a synthetic gas (syngas), which is used as the fuel for a combined cycle generating unit. After the syngas is produced, it undergoes cleaning prior to combustion. The wastewater generated by these cleaning processes, along with any condensate generated in flash tanks, slag handling water, or wastewater generated from the production of sulfuric acid, is referred to as ``grey water'' or ``sour water,'' and is generally treated prior to reuse or discharge.

EPA is aware of three plants that operate IGCC units in the U.S. All three plants currently treat their gasification wastewater with vapor-compression evaporation systems. One of these plants also includes a cyanide destruction stage as part of the treatment system.
Selection of Regulated Pollutants

A. Identifying the Pollutants of Concern

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

B. Selection of Pollutants for Regulation Under BAT/NSPS

For wastestreams where the final rule establishes numeric effluent limitations or standards, effluent limitations or standards for all POCs are not necessary to ensure that the pollutants are adequately controlled because many of the pollutants originate from similar sources, have similar treatability, and are removed by similar mechanisms. Because of this, it is sufficient to establish effluent limitations or standards for one or more indicator pollutants, which will ensure the removal of other POCs. For wastestreams where the final rule establishes zero discharge limitations or standards, all POCs are directly regulated.

For wastestreams where the final rule establishes numeric effluent limitations or standards, EPA selected a subset of pollutants as indicators for all regulated pollutants upon consideration of the following factors:

EPA did not set limitations or standards for pollutants associated with treatment system additives because regulating these pollutants could interfere with efforts to optimize treatment system operation.

EPA did not set limitations or standards for pollutants for which the treatment technology was ineffective

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(e.g., pollutant concentrations remained approximately unchanged or increased across the treatment system).

EPA did not set limitations or standards for pollutants that are adequately controlled through the regulation of another indicator pollutant because they have similar properties and are treated by similar mechanisms as a regulated pollutant.

See TDD Section 11 for additional detail on EPA's analysis and rationale for selecting the regulated pollutants.

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

Before establishing PSES/PSNS for a pollutant, EPA examines whether the pollutant ``passes through'' a POTW to waters of the U.S. or interferes with the POTW operation or sludge disposal practices. In determining whether a pollutant passes through POTWs for these purposes, EPA generally compares the percentage of a pollutant removed by well-operated POTWs performing secondary treatment to the percentage removed by the BAT/NSPS technology basis. A pollutant is determined to pass through POTWs when the median percentage removed nationwide by well-operated POTWs is less than the median percentage removed by the BAT/NSPS technology basis. Pretreatment standards are established for those pollutants regulated under BAT/NSPS that pass through POTWs.

Under this rule, for those wastestreams regulated with a zero discharge limitation or standard, EPA set the percentage removed by the technology basis at 100 percent. Because a POTW would not be able to achieve 100 percent removal of wastewater pollutants, it is appropriate to set PSES at zero discharge, otherwise pollutants would pass through the POTW.

For wastestreams for which the final rule establishes numeric limitations and standards, EPA determined the pollutant percentage removed by the rule's technology basis using the same data sources used to determine the long-term averages for each set of limitations and standards (see TDD Section 13). As it has done for other rulemakings, EPA determined the nationwide percentage removed by well-operated POTWs performing secondary treatment using one of two data sources:

Fate of Priority Pollutants in Publicly Owned Treatment Works, September 1982, EPA 440/1-82/303 (50 POTW Study); or

National Risk Management Research Laboratory Treatability Database, Version 5.0, February 2004 (formerly called the Risk Reduction Engineering Laboratory database).

With a few exceptions, EPA performs a POTW pass-through analysis for pollutants selected for regulation for BAT/NSPS for each wastestream of concern. The exception is for conventional pollutants such as BOD5, TSS, and oil and grease. POTWs are designed to treat these conventional pollutants; therefore, they are not considered to pass through.

Section VIII, below, summarizes the results of the pass-through analysis. EPA found that all of the pollutants considered for regulation under BAT/NSPS pass through and, therefore, also selected them for regulation under PSES/PSNS. For a more detailed discussion of how EPA performed its pass-through analysis, see TDD Section 11.
The Final Rule

A. BPT

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

B. BAT/NSPS/PSES/PSNS Options

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

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

TABLE VIII-1--Final Rule: Steam Electric Main Regulatory Options

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Technology basis for the main BAT/NSPS/PSES/PSNS regulatory options

Wastestreams -----------------------------------------------------------------------------------------------------------------------

A B C D E F

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FGD Wastewater.................. Chemical Chemical Chemical Chemical Chemical Evaporation.

Precipitation. Precipitation + Precipitation + Precipitation + Precipitation +

Biological Biological Biological Biological

Treatment. Treatment. Treatment. Treatment.

Fly Ash Transport Water......... Dry handling...... Dry handling...... Dry handling...... Dry handling...... Dry handling...... Dry handling.

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Bottom Ash Transport Water...... Impoundment (Equal Impoundment (Equal Dry handling/ Dry handling/ Dry handling/ Dry handling/

to BPT). to BPT). Closed loop (for Closed loop. Closed loop. Closed loop.

units >400 MW);

Impoundment

(Equal to

BPT)(for units

2) and other pollutants per MW of electricity generated. On an annual basis, EPA calculated significant fuel savings and reduced air emissions from such systems, the value of which EPA estimates to be $41 million to $117 million per year.\25\ See DCN SE05980.

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\25\ Neither these savings nor the fuel and emissions reductions have been incorporated into EPA's analyses for this final rule.

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EPA did not identify surface impoundments as BAT for bottom ash transport water for the same reasons (where applicable) that it did not identify surface impoundments as BAT for FGD wastewater (see Section VIII.C.1). Moreover, because the estimated overall cost of the rule has decreased since proposal (see Section IX), EPA also decided that establishing different bottom ash transport water limitations for generating units of and below a certain size (other than 50 MW, as described in Section VIII.C.12), as in Option C, was not warranted.

At proposal and for the final rule, EPA considered an option that would have established differentiated bottom ash transport water requirements for units below 400 MW (Option C). Some public commenters stated that EPA's record does not support differentiated requirements for bottom ash transport water. They stated that BAT should be established at a level at which the costs are affordable to the industry as a whole, and that the cost to a unit in terms of dollars per amount of energy produced (in MW) is not a relevant factor. They cited EPA's record, which demonstrates that units of all sizes have installed dry handling and closed-loop systems, as well as EPA's economic achievability analysis, which does not show that units of 400 MW or less are especially likely to shut down if faced with a zero discharge requirement. Other commenters supported EPA's consideration of the relative magnitude of costs per amount of energy produced for units below or equal to 400 MW, as compared to larger units, as well as differentiated bottom ash transport water requirements for these units.

EPA reviewed its record and re-evaluated whether it would be appropriate to establish differentiated requirements for discharges of bottom ash transport water from existing sources based on unit size, in light of comments and the key changes since proposal discussed in Section V. Annualized cost per amount of energy produced increases along a smooth curve moving from the very largest units to the smallest units. See DCN SE05813. That, however, is expected due to economies of scale. There is no clear breaking point at which to establish a size threshold for purposes of differentiated requirements for bottom ash transport water.\26\ Furthermore, EPA collected information in the industry survey that found that units of all sizes, including those less than 400 MW, have installed dry handling and closed-loop systems. And, as further described below, EPA projects a net retirement of only 843 MW under the final rule. This suggests that, as a group, units of 400 MW or less do not face particularly unique hardships under the final rule with respect to the industry as a whole. For these reasons, the final rule does not establish differentiated bottom ash transport water requirements for units equal to or below 400 MW (or for units equal to or below any other size threshold, other than 50 MW, as explained in Section VIII.C.12).

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\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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4. FGMC Wastewater

This rule identifies dry handling as the BAT technology basis for the control of pollutants in FGMC wastewater. More specifically, the technology basis for BAT is a dry vacuum system that employs a mechanical exhauster to convey the FGMC waste (via a change in air pressure) from hoppers directly to a silo. Dry handling of FGMC waste is available and well demonstrated in the industry; indeed, nearly all plants with FGMC systems use dry handling systems. Plants using sorbent injection systems (e.g., activated carbon injection) to reduce mercury emissions from the flue gas typically handle the spent sorbent in the same manner as their fly ash (see Section VI.B.4 and TDD Section 7.5). As of 2009, 92 percent of the industry generating FGMC waste uses dry handling to manage it. Only a few plants use wet systems to transport the spent sorbent to disposal in surface impoundments. Based on the industry survey, the plants using wet handling systems operate them as closed-loop systems and do not discharge FGMC wastewater, or they already have a dry handling system that is capable of achieving zero discharge. Under the zero discharge limitation, these plants could choose to continue to operate their wet systems as closed-loop systems, or they could convert to dry handling technologies by managing the fly ash and spent sorbent together in a retrofitted dry system (rather than an impoundment) or by installing dedicated dry handling equipment for the FGMC waste similar to the equipment used for fly ash.

EPA decided that it would not be appropriate to establish BAT limitations for FGMC wastewater based on surface impoundments for the same reasons (where applicable) that it did not identify surface impoundments as BAT for FGD wastewater (see Section VIII.C.1).

5. Gasification Wastewater

This rule identifies evaporation as the BAT technology basis for the control of pollutants in gasification wastewater. More specifically, the technology basis for BAT is an evaporation system using a falling-film evaporator (or brine concentrator) to produce a concentrated wastewater stream (brine) and a reusable distillate stream. This evaporation technology is available and well demonstrated in the industry for treatment of gasification wastewater. All three IGCC plants now operating in the U.S. (the only existing sources of gasification wastewater) use evaporation technology to treat their gasification wastewater.

EPA did not identify surface impoundments as BAT for gasification wastewater for the same reasons (where applicable) that it did not identify surface impoundments as BAT for FGD wastewater (see Section VIII.C.1). In addition, one existing IGCC plant previously used a surface impoundment to treat its gasification wastewater, and the impoundment effluent repeatedly exceeded its NPDES permit effluent limitations necessary to meet applicable WQS. Because of the demonstrated inability of surface impoundments to remove the pollutants of concern, and given that current industry practice is treatment of gasification wastewater using evaporation, EPA concluded that surface impoundments do not represent BAT for gasification wastewater.

EPA also considered including cyanide treatment as part of the technology basis for BAT (as well as NSPS, PSES, and PSNS) for gasification wastewater. EPA is aware that the Edwardsport IGCC plant, which began commercial operation in June 2013, includes cyanide destruction as one step

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in the treatment process for gasification wastewater. EPA, however, does not currently have sufficient data with which to calculate possible ELGs for cyanide. Thus, EPA decided not to establish cyanide limitations or standards for gasification wastewater in this rule. This decision does not preclude permitting authorities from setting more stringent effluent limitations where necessary to meet WQS. In those cases, plants may elect to install additional treatment, like cyanide destruction, to meet water quality-based effluent limitations.

6. Combustion Residual Leachate

EPA received public comments expressing concern that the proposed definition of combustion residual leachate would apply to contaminated stormwater. Although this was not the Agency's intention, for the final rule, EPA revised the definition to make it clear that contaminated stormwater does not fall within the final definition of combustion residual leachate. This rule identifies surface impoundments as the BAT technology basis for control of pollutants in combustion residual leachate. Based on surface impoundments, which relies on gravity to remove particulates, this rule establishes a BAT limitation on TSS in combustion residual leachate equal to the previously promulgated BPT limitation on TSS in low volume waste sources. Few steam electric power plants currently employ technologies other than surface impoundments for treatment of combustion residual leachate. Throughout the development of this rule, EPA considered whether technologies in place for treatment of other wastestreams at steam electric power plants and wastestreams generated by other industries, including chemical precipitation, could be used for combustion residual leachate. At proposal, noting the small amount of pollutants in combustion residual leachate relative to other significant wastestreams at steam electric power plants, and that this was an area ripe for innovation, EPA requested additional information related to cost, pollutant reduction, and effectiveness of chemical precipitation and alternative approaches to treat combustion residual leachate. Commenters did not provide information that EPA could use to establish BAT limitations. Thus, EPA decided not to finalize BAT limitations for combustion residual leachate based on chemical precipitation (Option E). The record demonstrates that the amount of pollutants collectively discharged in combustion residual leachate by steam electric power plants is a very small portion of the pollutants discharged collectively by all steam electric power plants (approximately 3 percent of baseline loadings, on a toxic-weighted basis). Given this, and the fact that this rule regulates the wastestreams representing the three largest sources of pollutants from steam electric power plants (including by setting a zero discharge standard for two out of the three wastestreams), EPA decided that this rule already represents reasonable further progress toward the CWA's goals. The final rule, therefore, establishes BAT limitations for combustion residual leachate equal to the BPT limitation on TSS for low volume waste sources.

7. Timing

As part of the consideration of the technological availability and economic achievability of the BAT limitations in the rule, EPA considered the magnitude and complexity of process changes and new equipment installations that would be required at facilities to meet the rule's requirements. As described in greater detail in Section XVI.A.1, where BAT limitations in this rule are more stringent than previously established BPT limitations, those limitations do not apply until a date determined by the permitting authority that is as soon as possible beginning November 1, 2018 (approximately three years following promulgation of this rule), but that is also no later than December 31, 2023 (approximately eight years following promulgation).

Consistent with the proposal and supported by many commenters, the final rule takes this approach in order to provide the time that many facilities need to raise capital, plan and design systems, procure equipment, and construct and then test systems. It also allows for consideration of plant changes being made in response to other Agency rules affecting the steam electric industry (see Section V.B). Moreover, it enables facilities to take advantage of planned shutdown or maintenance periods to install new pollution control technologies.\27\ EPA's decision is also designed to allow, more broadly, for the coordination of generating unit outages in order to maintain grid reliability and prevent any potential impacts on electricity availability, something that public commenters urged EPA to consider. In addition, as requested by industry and states, this final rule and preamble clarify how the ``as soon as possible date'' is determined and implemented for steam electric power plants. The final rule specifies the factors that the permitting authority must consider in determining the ``as soon as possible'' date, and Section XVI.A.1 provides guidance on implementation with respect to timing. In addition, the rule includes a ``no later than'' date of December 31, 2023, for implementation because, as public commenters pointed out, without such a date, implementation could be substantially delayed, and a firm ``no later than'' date creates a more level playing field across the industry. EPA's economic analysis assumes prompt renewal of permits (no permits will be administratively continued) and, thus, that the requirements of the rule will be fully implemented by 2023. While some commenters requested that EPA give permitting authorities the ability to extend the implementation period beyond December 31, 2023, in light of public comments received on the proposal, and the fact that plants can reasonably be expected to meet the new ELGs by December 31, 2023, this timeframe is appropriate given the CWA's pollutant discharge elimination goals (see CWA section 101(a)).

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\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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8. Legacy Wastewater

For purposes of the BAT limitations in this rule, this preamble uses the term ``legacy wastewater'' to refer to FGD wastewater, fly ash transport water, bottom ash transport water, FGMC wastewater, or gasification wastewater generated prior to the date determined by the permitting authority that is as soon as possible beginning November 1, 2018, but no later than December 31, 2023 (see Section VIII.C.7). Under this rule, legacy wastewater must comply with specific BAT limitations, which EPA is setting equal to the previously promulgated BPT limitations on TSS in the discharge of fly ash transport water, bottom ash transport water, and low volume waste sources.

EPA did not establish zero discharge BAT limitations for legacy wastewater because technologies that can achieve zero discharge (such as the ones on which the final BAT requirements discussed in Sections VIII.C.2, 3, and 4, above, are based) are not shown to be available for legacy wastewater. Legacy wastewater already exists in wet form, and thus dry handling could not be used eliminate its discharge. Furthermore, EPA lacks data to show that legacy wastewater could be reliably incorporated into a closed-loop process that eliminates discharges, given the variation in operating practices among

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surface impoundments containing legacy wastewater.

EPA also decided not to establish BAT limitations for legacy wastewater based on a technology other than surface impoundments (chemical precipitation, chemical precipitation plus biological treatment, evaporation) because it does not have the data to do so. Data are not available because of the way that legacy wastewater is currently handled at plants.

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

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\28\ For example, there are 65 plants for which EPA estimated FGD wastewater compliance costs and that use an impoundment as part of their treatment system. For 54 of the 65 plants (83 percent), the FGD wastewater is commingled with, at least, fly and/or bottom ash transport water, and for another eight of the 65 plants (12 percent), the FGD wastewater is commingled with non-ash wastewater, such as cooling tower blowdown or low volume waste sources. DCN SE05875.

\29\ For example, no plant uses biological treatment or evaporation to treat its legacy fly ash transport water or legacy bottom ash transport water contained in an impoundment, including any impoundment that may contain only legacy fly ash transport water or only legacy bottom ash transport water. Although EPA identified fewer than ten plants that use chemical precipitation to treat wastewater that contains, among other things, ash transport water, EPA does not have any data to characterize the effluent from these systems. Thus, no steam electric industry data exist to establish BAT limitations for possible ``fly ash-only'' impoundments or ``bottom ash-only'' impoundments based on these technologies.

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Finally, while there are a few plants that discharge from an impoundment containing only legacy FGD wastewater,\30\ EPA rejected establishing requirements for such legacy FGD wastewater based on a technology other than surface impoundments. EPA determined that, while it could be possible for plants to treat the legacy FGD wastewater with the same technology used to treat FGD wastewater subject to the BAT limitations described in Section VIII.C.1 (because their characteristics could be similar), establishing requirements based on any technology more advanced than surface impoundments for these legacy ``FGD-only'' wastewater impoundments could encourage plants to alter their operations prior to the date that the final limitations apply in order to avoid the new requirements. Likely, a plant would begin commingling other process wastewater with their legacy FGD wastewater in the impoundment so that any legacy ``FGD-only'' wastewater requirements would no longer apply. Alternatively, plants might choose to pump the legacy FGD wastewater out of the impoundment on an accelerated schedule and prior to the date that the final limitations apply. In this case, the more rapid discharge of the wastewater could result in temporary increases in environmental impacts (e.g., exceedances of WQC for acute impacts to aquatic life). EPA wanted to avoid creating such incentives in this rule, and it therefore decided to establish BAT limitations for discharges of legacy FGD wastewater based on the previously promulgated BPT limitations on TSS for low volume waste sources. Finally, EPA notes that, as a result of the zero discharge requirements for discharges of all pollutants in three wastestreams (fly ash transport water, bottom ash transport water, and flue gas mercury control wastewater), this rule provides strong incentives for steam electric power plants to greatly reduce, if not completely eliminate, the disposal and treatment of their major sources of ash-containing wastewater in surface impoundments. As a result, EPA anticipates that overall volumes of legacy wastewater will continue to decrease dramatically over time, as this rule becomes fully implemented.

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\30\ EPA determined that there are three plants that are estimated to incur FGD wastewater compliance costs and that use an impoundment as part of the treatment system, but where the FGD wastewater is not commingled with other process wastewaters in the impoundment. There are no plants that discharge from an impoundment containing only gasification wastewater.

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9. Economic Achievability

EPA's analysis for the final BAT limitations demonstrates that they are economically achievable for the steam electric industry as a whole, as required by CWA section 301(b)(2)(A). EPA performed cost and economic impact assessments using the Integrated Planning Model (IPM) using a baseline that reflects impacts from other relevant environmental regulations (see RIA).\31\ For the final rule, the model showed very small additional effects on the electricity market, on both a national and regional sub-market basis. Based on the results of these analyses, EPA estimated that the requirements associated with the final rule would result in a net reduction of 843 MW in steam electric generating capacity as of the model year 2030, reflecting full compliance by all plants. This capacity reduction corresponds to a net effect of two unit closures or, when aggregating to the level of steam electric generating plants, and net plant closure.\32\ These IPM results support EPA's conclusion that the final rule is economically achievable.

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\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 Requirements \33\

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\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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The final BAT effluent limitations have acceptable non-water quality

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environmental impacts, including energy requirements. Section XII describes in more detail EPA's analysis of non-water quality environmental impacts and energy requirements. EPA estimates that by year 2023, under the final rule and reflecting full compliance, energy consumption increases by less than 0.01 percent of the total electricity generated by power plants. EPA also estimates that the amount of fuel consumed by increased operation of motor vehicles (e.g., for transporting fly ash) increases by approximately 0.002 percent of total fuel consumption by all motor vehicles.

EPA also evaluated the effect of the BAT effluent limitations on air emissions generated by all electric power plants (NOX, sulfur oxides (SOX), and CO2), solid waste generation, and water usage. Under the final rule, NOX emissions are projected to decrease by 1.16 percent, SOX emissions are projected to increase by 0.04 percent, and CO2 emissions are projected to decrease by 0.106 percent due to changes in the mix of electricity generation (e.g., less electricity from coal-

fired steam electric generating units and more electricity from natural gas-fired steam electric generating units). Moreover, solid waste generation is projected to increase by less than 0.001 percent of total solid waste generated by all electric power plants. Finally, EPA estimates that the final rule has a positive impact on water withdrawal, with steam electric power plants reducing the amount of water they withdraw by 57 billion gallons per year (155 million gallons per day).

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

EPA examined the effects of the final rule on consumers as an additional factor that might be appropriate when considering what level of control represents BAT. If all annualized compliance costs were passed on to residential consumers of electricity, instead of being borne by the operators and owners of power plants (a very conservative assumption), the average monthly increase in electricity bill for a typical household would be no more than $0.12 under the final rule.

EPA also considered the effect of the rule on minority and low-

income populations. As explained in Section XVII.J, using demographic data regarding who resides closest to steam electric power plant discharges and who consumes the most fish from waters receiving power plant discharges, EPA concluded that low-income and minority populations benefit to an even greater degree than the general population from the reductions in discharges associated with the final rule.

12. Existing Oil-Fired and Small Generating Units

EPA considered whether subcategorization of the ELGs was warranted based on the factors specified in CWA section 304(b)(2)(B) (see Section IV.B.3 and TDD Section 5). Ultimately, EPA concluded that it would be appropriate to set different limitations for existing small generating units (50 MW or less) and existing oil-fired generating units. No other, different requirements were warranted for this rule under the factors considered.

Oil-Fired Generating Units. For oil-fired generating units, the final rule establishes BAT effluent limitations for FGD wastewater, fly ash transport water, bottom ash transport water, FGMC wastewater, and gasification wastewater equal to previously established BPT limitations on TSS in fly ash transport water, bottom ash transport water, and low volume waste sources. As defined in the rule, oil-fired generating units refer to those that use oil as either the primary or secondary fuel and do not burn coal or petroleum coke. Units that use only oil during startup or for flame stabilization are not considered oil-fired generating units.

EPA decided to finalize these limitations for oil-fired generating units because EPA's record demonstrates that, in comparison to coal- and petroleum coke-fired units, oil-fired units generate substantially fewer pollutants, are generally older and operate less frequently, and in many cases are more susceptible to early retirement when faced with compliance costs attributable to the final rule.

The amount of ash generated by oil-fired units is a small fraction of the amount produced by coal-fired units. Coal-fired units generate hundreds to thousands of tons of ash each day, with some plants generating more than 2,000 tons per day of ash. In contrast, oil-fired units generate less than ten tons of ash per day. This disparity is also apparent when comparing the ash tonnage to the amount of power generated, with coal-fired units producing nearly 1,800 times more ash than oil-fired units (0.6 tons per MW-hour on average for coal units; 0.000319 tons per MW-hour on average for oil units). The amount of pollutants discharged to surface waters is roughly correlated to the amount of ash wastewater discharged; thus, oil-fired generating units discharge substantially fewer pollutants to surface waters than coal-

fired units, even when generating the same amount of electricity. EPA estimates that the amount of pollutants discharged collectively by all oil-fired generating units is a very small portion of the pollutants discharged collectively by all steam electric power plants (less than one percent, on a toxic-weighted basis).

Oil-fired generating units are generally among the oldest steam electric units in the industry. Eighty-seven percent of the units are more than 25 years old. In fact, more than a quarter of the units began operation more than 50 years ago. Based on responses to the industry survey, fewer than 20 oil-fired generating units discharged fly ash or bottom ash transport water in 2009. This is likely because only about 20 percent of oil-fired generating units operate as baseload units; the rest are either cycling/intermediate units (about 45 percent) or peaking units (about 35 percent). These units also have notably low capacity utilization. While about 30 percent of the baseload units report capacity utilization greater than 75 percent, almost half report a capacity utilization of less than 25 percent. Eighty percent of the cycling/intermediate units and all peaking units also report capacity utilization less than 25 percent. Thirty-five percent of oil-fired generating units operated for more than six months in 2009; nearly half of the units operated for fewer than 30 days.

While these older and generally intermittently operated oil-fired generating units are capable of installing and operating the treatment technologies that form the bases for this rule, and the costs would be affordable for most plants, EPA concludes that, due to the factors described here, companies may choose to shut down these oil-fired units instead of making new investments to comply with the rule. If these units shut down, EPA is concerned about resulting reductions in the flexibility that grid operators have during peak demand due to less reserve generating capacity to draw upon. But, more importantly, maintaining a diverse fleet of generating units that includes a variety of fuel sources is important to the nation's energy security. Because the supply/delivery network for oil is different from other fuel sources, maintaining the existence of oil-fired generating units helps ensure reliable electric power generation, as commenters confirmed. EPA considered these potential impacts on electric grid reliability and the nation's energy security, under CWA section 304(b)(2)(B), in its decision to establish

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different BAT limitations for oil-fired generating units.

Small Generating Units. The final rule also establishes BAT effluent limitations for FGD wastewater, fly ash transport water, bottom ash transport water, FGMC wastewater, and gasification water at small generating units equal to previously established BPT limitations on TSS for fly ash transport water, bottom ash transport water, and low volume waste sources. For purposes of this rule, small generating units refer to those units with a total nameplate generating capacity of 50 MW or less. EPA decided to establish these different BAT limitations for small units because they are more likely to incur compliance costs that are significantly and disproportionately higher per amount of energy produced (dollars per MW) than those incurred by larger units.

Some commenters stated that the cost to a unit in terms of dollars per MW is not relevant because BAT should be established at a level at which the costs are affordable to the industry as a whole. They noted that EPA's IPM analysis demonstrates that the most stringent proposed regulatory option is economically achievable for all units above 50 MW. Other commenters supported EPA's consideration of the relative magnitude of costs for smaller units compared to larger units, and some suggested EPA should increase the size threshold to 100 MW because those units also have disproportionate costs per amount of energy produced, and they collectively discharge a small fraction of the total pollutants discharged by all steam electric power plants.

EPA reviewed the record and re-evaluated the threshold for small units in light of comments and the key changes since proposal discussed in Section V. EPA considered establishing no threshold, as well as several different size thresholds, for small units. The Agency looked closely at establishing a threshold at 50 MW or 100 MW. While the total amount of pollutants discharged by units at these thresholds is relatively small in comparison to those discharged by all steam electric power plants, the amount of pollutants discharged by units smaller than or equal to 100 MW is almost double the amount of pollutants discharged by units smaller than or equal to 50 MW. See DCN SE05813 for specific information on these pollutant discharges. The record indicates that the cost per unit of energy produced increases as the size of the generating unit decreases, and while there is no clear ``knee of the curve'' at which to establish a size threshold, there is a difference between units at 50 MW and below compared to those above 50 MW. Figure VIII-1, below, shows the annualized cost per amount of energy produced for existing units under Regulatory Option D. Figure VIII-1 shows that the cost per amount of energy produced increases as the size of the generating unit decreases. Annualized cost per amount of energy produced increases gradually as one moves from the very largest units down to 100 MW, and then the cost per amount of energy produced begins to increase more rapidly as one moves from 100 MW down to 50 MW, until it increases very rapidly for units at 50MW and below. Additionally, Figure VIII-1 shows that nearly all of the ratios of cost to amount of energy produced for units smaller than or equal to 50 MW are above those for the entire population of remaining units. The same cannot be said of the ratio for units smaller than or equal to 100 MW.

GRAPHIC TIFF OMITTED TR03NO15.221

Page 67858

In light of the fact that the costs per amount of energy produced are significantly and disproportionately higher for units smaller than or equal to 50 MW compared to larger units, and in light of the very small fraction of pollutants discharged by units smaller than or equal to 50 MW, EPA ultimately decided to establish different requirements for units at this threshold. Keeping in mind the statutory directive to set effluent limitations that result in reasonable further progress toward the national goal of eliminating the discharge of all pollutants (CWA section 301(b)(2)(A)), EPA used its best judgment to balance the competing interests. EPA recognizes that any attempt to establish a size threshold for generating units will be imperfect due to individual differences across units and firms. EPA concludes, however, that a threshold of 50 MW or less reasonably and effectively targets those generating units that should receive different treatment based on the considerations described above, while advancing the CWA's goals. Furthermore, as shown in Section IX.C, EPA's analysis demonstrates that the final rule, with a threshold established at 50 MW, is economically achievable.

13. Voluntary Incentives Program

As part of the BAT for existing sources, the final rule establishes a voluntary incentives program that provides the certainty of more time (until December 31, 2023) for plants to implement new BAT requirements, if they adopt additional process changes and controls that achieve limitations on mercury, arsenic, selenium, and TDS in FGD wastewater, based on evaporation technology (see Section VIII.C.1 for a more complete description of the evaporation technology basis). This optional program offers significant environmental protections beyond those achieved by the final BAT limitations for FGD wastewater based on chemical precipitation plus biological treatment because evaporation technology is capable of achieving significant removals of toxic metals, as well as TDS.\34\

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

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EPA's proposal included a voluntary incentives program that contained, as one element, incentives in the form of additional implementation time for plants that eliminate the discharge of all process wastewater (except cooling water). Public commenters urged EPA to consider establishing, instead, a program that provided incentives for plants that go further than the rule's requirements to reduce discharges from individual wastestreams. Because the final rule already contains zero discharge limitations for several key wastestreams, EPA decided that the voluntary incentives program should focus on FGD wastewater.

EPA concluded that additional pollutant reductions could be achieved under a voluntary incentives program because there are certain reasons a plant might opt to treat its FGD wastewater using evaporation rather than chemical precipitation plus biological treatment. One such reason is the possibility that a plant's NPDES permit may need more stringent limitations necessary to meet applicable WQS. For example, some power plant discharges containing TDS (including bromide) that occur upstream of drinking water treatment plants can negatively impact treatment of source waters at the drinking water treatment plants. A recent study identified four drinking water treatment plants that experienced increased levels of bromide in their source water, and corresponding increases in the formation of carcinogenic disinfection by-products (brominated DPBs) in the finished drinking water, after the installation of wet FGD scrubbers at upstream steam electric power plants (DCN SE04503).

Furthermore, based on trends in the industry and experience with this and other industries, EPA expects that, over time, the costs of evaporation (and other technologies that could achieve the limitations in the voluntary incentives program, including zero discharge practices) will decrease so as to make it an even more attractive option for plants. EPA understands that vendors are already working on changes to this technology to reduce the costs, reduce the amount of solids generated, and improve the solids handling. See TDD Section 7.1.4.

The technology on which the BAT limitations in the voluntary incentives program are based, evaporation, is available to steam electric power plants. EPA identified three plants in the U.S. that have installed, and one plant that is in the process of installing, evaporation systems to treat their FGD wastewater. Four coal-fired power plants in Italy treat FGD wastewater using evaporation. See TDD Section 7. Furthermore, the voluntary program is economically achievable because only those plants that opt to be subject to the BAT limitations based on evaporation, rather than the BAT limitations based on chemical precipitation plus biological treatment, must achieve them. Therefore, any plant that chooses to be subject to the more stringent limitations has determined for itself, in light of its own financial information and economic outlook, that such limitations are economically achievable. Finally, EPA analyzed the non-water quality environmental impacts and energy requirements associated with the voluntary incentives program, and it found them acceptable. See DCN SE05574.

The development of this voluntary incentives program furthers the CWA's ultimate goal of eliminating the discharge of pollutants into the Nation's waters. See CWA section 101(a)(1) and section 301(b)(2)(A) (specifying that BAT will result in ``reasonable further progress toward the national goal of eliminating the discharge of pollutants''). While the final rule's BAT limitations based on chemical precipitation plus biological treatment represent ``reasonable further progress,'' the voluntary incentives program is designed to press further toward achieving the national goal of the Act, as wastewater that has been treated properly using evaporation has very low pollutant concentrations (also making it possible to reuse the wastewater and completely eliminate the discharge of any pollutants). In addition, CWA section 104(a)(1) gives the Administrator authority to establish national programs for the prevention, reduction, and elimination of pollution, and it provides that such programs shall promote the acceleration of research, experiments, and demonstrations relating to the prevention, reduction, and elimination of pollution. EPA anticipates that the voluntary incentives program will effectively accelerate the research into and demonstration of controls and processes intended to prevent, reduce, and eliminate pollution because, under it, plants will opt to employ control and treatment strategies to significantly reduce discharges of pollutants found in FGD wastewater.

Steam electric power plants agreeing to meet BAT limitations for FGD wastewater based on evaporation must comply with those limitations on arsenic, mercury, selenium, and TDS in FGD wastewater.\35\ For such plants, the BAT limitations based on evaporation apply as of December 31, 2023, to FGD wastewater generated on and after December 31, 2023. Plants opting to participate in the voluntary program can use the period in advance of this date to research, engineer, design, procure, construct, and optimize systems capable

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of meeting the limitations based on evaporation.

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\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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For purposes of the voluntary incentives program BAT limitations, legacy FGD wastewater is FGD wastewater generated prior to December 31, 2023. For such legacy FGD wastewater, the final rule establishes BAT limitations on TSS in discharges of FGD wastewater that are equal to BPT limitations for low volume waste sources.

EPA decided not to make the voluntary incentives program available to plants that send their FGD wastewater to POTWs. Under CWA section 307(b)(1), PSES must specify a time for compliance that does not exceed three years from the date of promulgation, and thus the additional time of up to 2023 cannot be given to indirect dischargers. Of course, nothing prohibits an indirect discharger from using any technology, including evaporation, to comply with the final PSES and PSNS.

EPA expects that any plant interested in the voluntary incentives program would indicate their intent to opt into the program prior to issuance of its next NPDES permit, following the effective date of this rule. A plant can indicate its intent to opt into the voluntary program on its permit application or through separate correspondence to the NPDES Director, as long as the signatory requirements of 40 CFR 122.22 are met.

D. Best Available Demonstrated Control Technology/NSPS

After considering all of the technologies described in this preamble and TDD Section 7, as well as public comments, and in light of the factors specified in CWA section 306 (see Section IV.B.4), EPA concluded that the technologies described in Option F represent BADCT for steam electric power plants, and the final rule promulgates NSPS based on that option. Thus, the final NSPS establish: (1) Standards on arsenic, mercury, selenium, and TDS in FGD wastewater, based on evaporation (same basis as for BAT limitations in voluntary incentives program); (2) a zero discharge standard on all pollutants in bottom ash transport water, based on dry handling or closed-loop systems (same bases as for BAT limitations); (3) a zero discharge standard on all pollutants in FGMC wastewater, based on dry handling (same basis as for BAT limitations); (4) standards on mercury, arsenic, selenium, and TDS in gasification wastewater, based on evaporation technology (same basis as for BAT limitations); and (5) standards on mercury and arsenic in discharges of combustion residual leachate, based on chemical precipitation (more specifically, the technology basis is a chemical precipitation system that employs hydroxide precipitation, sulfide precipitation, and iron coprecipitation to remove heavy metals). The final rule also maintains the previously established zero discharge NSPS on discharges of fly ash transport water, based on dry handling.

The record indicates that the technologies that serve as the bases for the final NSPS are well demonstrated based on the performance of plants using the technologies. For example, new steam electric power generating sources have been meeting the previously established zero discharge standard for fly ash transport water since 1982, predominantly through the use of dry handling technologies. Moreover, as described in Section VIII.C.13, three plants in the U.S. and four plants in Italy use evaporation technology to treat their FGD wastewater, and another U.S. plant is in the process of installing such technology for that purpose. Of the approximately 50 coal-fired generating units that were built within the last 20 years, most (83 percent) manage their bottom ash without using water to transport the ash and, as a result, do not discharge bottom ash transport water. The technology basis identified as BAT technology for gasification wastewater represents current industry practice. Every IGCC power plant currently in operation uses evaporation to treat their gasification wastewater, even when the wastewater is not discharged and is instead reused at the plant. In the case of FGMC wastewater, every plant currently using post-combustion sorbent injection (e.g., activated carbon injection) either handles the captured spent sorbent with a dry process or manages the FGMC wastewater so that it is not discharged to surface waters (or has the capability to do so). For combustion residual leachate, chemical precipitation is a well-demonstrated technology for removing metals and other pollutants from a variety of industrial wastewaters, including leachate from landfills not located at power plants. Chemical precipitation is also well demonstrated at steam electric power plants for treatment of FGD wastewater that contains the pollutants in combustion residual leachate.

The NSPS in the final rule pose no barrier to entry. The cost to install technologies at new units is typically less than the cost to retrofit existing units. For example, the cost differential between Options B, C, and D for existing sources is mostly associated with retrofitting controls for bottom ash handling systems. For new sources, however, NSPS based on Option F do not present plants with the same choice of retrofit versus modification of existing processes. This is because every new generating unit must install some type of bottom ash handling system as the unit is constructed. Establishing a zero discharge standard for all pollutants in bottom ash transport water as part of the NSPS means that power plants will install a dry bottom ash handling system during construction instead of installing a wet-

sluicing system.

Moreover, EPA assessed the possible impacts of the final NSPS on new sources by comparing the incremental costs of the Option F technologies to the costs of hypothetical new generating units. EPA is not able to predict which plants might construct new units or the exact characteristics of such units. Instead, EPA calculated and analyzed compliance costs for a variety of plant and unit configurations. EPA developed NSPS compliance costs for new sources using a methodology similar to the one used to develop compliance costs for existing sources. EPA's estimates for compliance costs for new sources are based on the net difference in costs between wastewater treatment system technologies that would likely have been implemented at new sources under the previously established regulatory requirements, and those that would likely be implemented under the final rule. EPA estimated that the incremental compliance costs for a new generating unit (capital and O&M) represent approximately 3.3 percent of the annualized cost of building and operating a new 1,300 MW coal-fired plant, with capital costs representing 0.3 to 2.8 percent of the overnight construction costs, and annual O&M costs representing 0.3 to 3.9 percent of the fuel and other O&M cost of operating a new plant.

Finally, EPA analyzed the non-water quality environmental impacts and energy requirements associated with Option F for both existing and new sources. See DCN SE05952 and DCN SE05951. Since there is nothing inherently different between an existing and new source, EPA's analysis with respect to existing sources is instructive. Using both of these analyses, EPA determined that NSPS based on the Option F technologies have acceptable non-water quality environmental impacts and energy requirements.

In contrast to the BAT effluent limitations, this rule establishes the same NSPS for oil-fired generating units and small generating units as for all

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other new sources. A key factor that affects compliance costs for existing sources is the need to retrofit new pollution controls to replace existing pollution controls. New sources do not incur retrofit costs because the pollution controls (process operations or treatment technology) are installed at the time of construction. Thus the costs for new sources are lower, even if the pollution controls are identical.

For each of the wastestreams except combustion residual leachate, EPA rejected establishing NSPS based on surface impoundments for the same reasons it rejected establishing BAT based on surface impoundments. For FGD wastewater, EPA also did not establish NSPS based on chemical precipitation for the same reasons it rejected establishing BAT based on that technology. In particular, these other technologies would not achieve as much pollutant reduction as the technology bases in Option F--which is technologically available and economically achievable with acceptable non-water quality environmental impacts and energy requirements--and thus do not represent best available demonstrated control technology.

EPA did not select surface impoundments as the basis for NSPS for combustion residual leachate because, unlike BAT, NSPS represent the ``greatest degree of effluent reduction . . . achievable'' (CWA section 306), and (besides ``cost'' and ``any non-water quality environmental impact and energy requirements,'' discussed above) EPA does not consider ``other factors'' in establishing NSPS. When used to treat combustion residual leachate, chemical precipitation can achieve substantial pollutant reductions as compared to surface impoundments. Thus, EPA has determined that NSPS for leachate based on chemical precipitation achieve the ``greatest degree of effluent reduction'' as that term is used in CWA section 306.

Similarly, EPA did not select chemical precipitation plus biological treatment as the basis for NSPS for FGD wastewater because, under CWA section 306, NSPS reflect ``the greatest degree of effluent reduction . . . achievable.'' Evaporation systems are capable of achieving extremely low pollutant discharge levels, and in fact can be the basis for a plant completely eliminating all discharges associated with FGD wastewater. Moreover, unlike EPA's decision not to identify evaporation as the technology basis for FGD wastewater discharges from all existing sources due to the large associated cost, establishing NSPS for FGD wastewater based on evaporation does not add to the overall estimated cost of the rule because EPA does not predict any new coal-fired generating units will be installed in the foreseeable future. As explained above, however, in the event that a new unit is installed, EPA determined that the NSPS compliance costs would not present a barrier to entry.

E. PSES

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

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

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

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Technology basis/Wastewater Pass through? (yes/

stream Pollutant no)

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Chemical Precipitation for Arsenic........... Yes.

Combustion Residual Leachate Mercury........... Yes.

(only for NSPS).

Chemical Precipitation plus Arsenic........... Yes.

Biological Treatment for FGD Mercury........... Yes.

Wastewater. Nitrate/Nitrite as Yes.

N. Yes.

Selenium..........

Evaporation for FGD wastewater Arsenic........... Yes.

(only for NSPS). Mercury........... Yes.

Selenium.......... Yes.

TDS............... Yes.

Evaporation for Gasification Arsenic........... Yes.

Wastewater. Mercury........... Yes.

Selenium.......... Yes.

TDS............... Yes.

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After considering all of the relevant factors and technology options in this preamble and in the TDD, as well as public comments, as is the case with BAT, EPA decided to establish PSES based on the technologies described in Option D. For PSES, the final rule establishes: (1) Standards on arsenic, mercury, selenium and nitrate/

nitrite as N in FGD wastewater; (2) a zero discharge standard on all pollutants in fly ash transport water; (3) a zero discharge standard on all pollutants in bottom ash transport water; (4) a zero discharge standard on all pollutants in FGMC wastewater; (5) standards on mercury, arsenic, selenium, and TDS in gasification wastewater. All of the technology bases for the final PSES are the same as those described for the final BAT limitations. The final rule does not establish PSES for combustion residual leachate because TSS does not pass through POTWs.

EPA selected the Option D technologies as the bases for PSES for the same reasons that EPA selected the Option D technologies as the bases for BAT. EPA's analysis shows that, for both direct and indirect dischargers, the Option D technologies are available and economically achievable, and Option D has acceptable non-water quality environmental impacts, including energy requirements (see Sections IX and XII). EPA rejected other options for

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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.

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\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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As with the final BAT effluent limitations, in considering the availability and achievability of the final PSES, EPA concluded that existing indirect dischargers need some time to achieve the final standards, in part to avoid forced outages (see Section VIII.C.7). However, in contrast to the BAT limitations (which apply on a date determined by the permitting authority that is as soon as possible beginning November 1, 2018, but no later than December 31, 2023), the new PSES apply as of November 1, 2018. Under CWA section 307(b)(1), pretreatment standards shall specify a time for compliance not to exceed three years from the date of promulgation, so EPA cannot establish a longer implementation period. Moreover, unlike requirements on direct discharges, requirements on indirect discharges are not implemented through an NPDES permit and thus are not subject to awaiting the next permit issuance before the limitations are specified clearly for the discharger. EPA has determined that all of the existing indirect dischargers can meet the standards by November 1, 2018, and because there are a handful of indirect dischargers (who would have approximately three years from the date of promulgation to achieve the standards), implementation of the standards by that date would not lead to electricity availability concerns. See RIA.

For purposes of the PSES in this rule, this preamble uses the term ``legacy wastewater'' to refer to FGD wastewater, fly ash transport water, bottom ash transport water, FGMC wastewater, or gasification wastewater generated prior to November 1, 2018. For the same reasons that EPA decided to establish BAT limitations on TSS in discharges of legacy wastewater equal to BPT limitations for fly ash transport water, bottom ash transport water, and low volume waste sources, the final rule does not establish PSES for legacy wastewater (see Section VIII.C.8). TSS and the pollutants it represents are effectively treated by, and thus do not pass through, POTWs.

F. PSNS

After considering all of the relevant factors and technology options described in this preamble and TDD Section 7, as well as public comments, as was the case for NSPS, EPA selected the Option F technologies as the bases for PSNS in this rule. As a result, the final PSNS establish: (1) Standards on arsenic, mercury, selenium, and TDS in FGD wastewater; (2) a zero discharge standard on all pollutants in bottom ash transport water; (3) a zero discharge standard on all pollutants in FGMC wastewater; (4) standards on mercury, arsenic, selenium, and TDS in gasification wastewater; and (5) standards on mercury and arsenic in combustion residual leachate. All the technology bases for the final PSNS are the same as those described for the final NSPS. The final rule also maintains the previously established zero discharge PSNS on discharges of fly ash transport water. As with the final NSPS, this rule establishes the same PSNS for oil-fired generating units and small generating units as for all other new sources.

EPA selected the Option F technologies as the bases for PSNS for the same reasons that EPA selected the Option F technologies as the bases for NSPS (see Section VIII.D). EPA's record demonstrates that the technologies described in Option F are available and demonstrated, and Option F does not pose a barrier to entry and has acceptable non-water quality environmental impacts, including energy requirements (see Sections IX and XII). EPA rejected other options for PSNS for the same reasons that the Agency rejected other options for NSPS. And, as with the final PSES, EPA determined that the final PSNS prevent pass through of pollutants from POTWs into receiving streams and also help control contamination of POTW sludge.

G. Anti-Circumvention Provision

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

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

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

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subsequently reused as makeup water would no longer be needed to sluice the ash and could instead be directly used as makeup water for the cooling water system or other processes. Because of this, the zero discharge limitations in this rule will not lead to a net increase at the plant and in fact could result in a decrease in water withdrawal. Lastly, a plant is free to reuse ash transport water, and would be in compliance with the anti-circumvention provision, so long as it is used in a process that does not ultimately result in a discharge.

There is one particular type of plant practice that the final rule's anti-circumvention provision does not apply to. Many industry commenters noted that they use ash transport water in their FGD scrubber. They stated that this practice is preferable to using a fresh water source and allows for an overall reduction in source water withdrawals. They further stated that, under the final rule, any wastewater that passes through the scrubber would undergo significant treatment in order to meet the final FGD wastewater limitations and standards. EPA agrees, in part, with these comments. As explained above, EPA does not agree that using wastewater from one industrial process as makeup water in another industrial process necessarily results in a net reduction in water withdrawals. EPA does agree, however, that using wastewater from an industrial process as makeup water in another industrial process may be preferable to using a fresh water source. EPA is mindful of the CWA's pollutant discharge elimination goal, but also wants to promote opportunities for water reuse. Furthermore, as explained in Section V, EPA recognizes the extensive changes in this industry, and it wants to provide flexibility to plants in managing their wastewater and operations, as well as preserve the ability of plants to retain existing approaches where it is consistent with the CWA's goals. While EPA would not choose to promote these considerations where it resulted in no further progress toward the pollutant discharge elimination goal of the Act, in the case of using ash transport water in an FGD scrubber, since any resulting wastewater discharges would still be required to meet BAT or PSES requirements based on either chemical precipitation plus biological treatment or chemical precipitation plus evaporation under this final rule, EPA decided not to apply the anti-circumvention provision to this particular practice.

The final rule does not establish an anti-circumvention provision that would have required internal monitoring to demonstrate compliance with certain numeric limitations and standards. Some public commenters argued that the proposed provision was unduly restrictive, and they stated that EPA already has authority to accomplish the goal of this particular provision, which is to ensure that wastestreams are being treated rather than simply diluted. EPA agrees with these commenters and thus decided that existing rules, along with the guidance in Section XVI.A.4 of this preamble and TDD Section 14, provide appropriate flexibility to steam electric power plants to combine wastestreams with similar pollutants and treatability, while adequately addressing EPA's concern that plants meet the effluent limitations and standards in this rule through treatment and control strategies, rather than through dilution. Furthermore, some commenters raised concerns that the proposed provision would be a disincentive for plants to internally re-use the treated wastewater within the plant, particularly when the re-use eliminates the discharge of the wastewater. For example, they stated that some steam electric power plants might opt to use a wet scrubber's FGD wastewater as reagent make-up for a new dry scrubber in an integrated design which would essentially evaporate the wet FGD wastewater. EPA notes that plants that internally reuse wastestreams for which EPA is establishing numeric limitations and standards (e.g., FGD wastewater) in a way that completely prevents discharge of that wastestream would not be subject to the numeric limitations and standards because they do not discharge the wastewater. EPA is aware of at least one plant that elected to take such an approach as an alternative to meeting NPDES permit limitations by installing wastewater treatment technology. See DCN SE06338. In general, EPA supports such approaches because they result in further progress towards achieving the pollutant discharge elimination goal of the CWA. Moreover, such approaches are favored because they reduce overall water intake needs.

The final rule also does not establish an anti-circumvention provision that would have required permittees to use EPA-approved analytical methods that are sufficiently sensitive to provide reliable, quantified results at levels necessary to demonstrate compliance with the final effluent limitations and standards because another recently promulgated rule already accomplishes this. As public commenters pointed out, EPA was conducting a rulemaking on that topic; and, in August 2014, EPA published a rule requiring the use of sufficiently sensitive analytical test methods when completing any NPDES permit application. Moreover, the NPDES permit authority must prescribe that only sufficiently sensitive methods be used for analyses of pollutants or pollutant parameters under an NPDES permit where EPA has promulgated a CWA method for analysis of that pollutant. That rule clarifies that NPDES applicants and permittees must use EPA-approved analytical methods that are capable of detecting and measuring the pollutants at, or below, the applicable water quality criteria or permit limits.

H. Other Revisions

1. Correction of Typographical Error for PSNS

As EPA proposed to do, the final rule corrects a typographical error in the previously established PSNS for cooling tower blowdown. As is clear from the development document for the 1982 rulemaking, as well as the previously promulgated NSPS for cooling tower blowdown, EPA inadvertently omitted a footnote in the table that appeared in 40 CFR 423.17(d)(1). The footnote reads ``No detectable amount,'' and it applies to the effluent standard for 124 of the 126 priority pollutants contained in chemicals added for cooling tower maintenance. See ``Development Document for Final Effluent Guidelines, New Source Performance Standards and Pretreatment Standards for the Steam Electric Power Generating Point Source Category,'' Document No. EPA 440/1-82/

029. November 1982.

2. Clarification of Applicability

In addition, the final rule contains three minor modifications to the wording of the applicability provision in the steam electric power generating ELGs to reflect EPA's longstanding interpretation and implementation of the rule. These revisions do not alter the universe of generating units regulated by the ELGs, nor do they impose compliance costs on the industry. Instead, they remove potential ambiguity in the regulations by revising the text to more clearly reflect EPA's longstanding interpretation.

First, the applicability provision in the previous ELGs stated, in part, that the ELGs apply to ``an establishment primarily engaged in the generation of electricity for distribution and sale. . . .'' 40 CFR 423.10. The final rule revises that phrase to read ``an establishment whose generation of electricity is the predominant source of revenue or principal reason for operation. . . .'' The final rule thus

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clarifies that certain facilities, such as generating units owned and operated by industrial facilities in other sectors (e.g., petroleum refineries, pulp and paper mills) that have not traditionally been regulated by the steam electric ELGs, are not within the scope of the ELGs. In addition, the final rule clarifies that certain municipally owned facilities that generate and distribute electricity within a service area (such as distributing electric power to municipal-owned buildings), but use accounting practices that are not commonly thought of as a ``sale,'' are subject to the ELGs. Such facilities have traditionally been regulated by the steam electric ELGs.

Second, the final rule clarifies that fuels derived from fossil fuel are within the scope of the ELGs. The previous ELGs stated, in part, that they apply to discharges resulting from the generation of electricity ``which results primarily from a process utilizing fossil-

type fuels (coal, oil, or gas) or nuclear fuel. . . .'' 40 CFR 423.10. Because a number of fuel types are derived from fossil fuels, and thus are fossil fuels themselves, the final rule explicitly mentions and gives examples of such fuels. Thus, the rule reads that the ELGs apply to discharges resulting from the operation of a generating unit ``whose generation results primarily from a process utilizing fossil-type fuel (coal, oil, or gas), fuel derived from fossil fuel (e.g., petroleum coke, synthesis gas), or nuclear fuel. . . .''

Third, the final rule clarifies the applicability provision to reflect the current interpretation that combined cycle systems are subject to the ELGs. The ELGs apply to electric generation processes that utilize ``a thermal cycle employing the steam water system as the thermodynamic medium.'' 40 CFR 423.10. EPA's longstanding interpretation is that the ELGs apply to discharges from all electric generation processes with at least one prime mover that utilizes steam (and that meet the other applicability factors in 40 CFR 423.10). Combined cycle systems, which are generating units composed of one or more combustion turbines operating in conjunction with one or more steam turbines, are subject to the ELGs. The combustion turbines for a combined cycle system operate in tandem with the steam turbines; therefore, the ELGs apply to wastewater discharges associated with both the combustion turbine and steam turbine portions of the combined cycle system. The final rule, therefore, clarifies that ``this part applies to discharges associated with both the combustion turbine and steam turbine portions of a combined cycle generating unit.''
Non-Chemical Metal Cleaning Waste

EPA proposed to establish BAT/NSPS/PSES/PSNS requirements for non-

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

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\39\ Under the structure of the previously promulgated regulations, non-chemical metal cleaning wastes are a subset of metal cleaning wastes.

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

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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.
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

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

A. Plant-Specific and Industry Total Costs

EPA first estimated plant-specific costs to control discharges at existing generating units at steam electric power plants to which the final ELGs apply (existing sources). For all applicable wastestreams, EPA assessed the operations and treatment system components in place at a given unit in the baseline (or expected to be in place given other existing rules), identified equipment and process changes that the plant would likely make to meet the final ELGs, and estimated the cost to implement those changes. As explained in Section V, since proposal, EPA accounted for additional announced unit retirements, conversions, and relevant operational changes, as well as changes plants are likely to make in response to the CCR and CPP rules. As a result, the number of plants projected to incur non-zero compliance costs is about 50 percent less than that estimated at proposal. As appropriate, EPA also accounted for cost savings associated with these equipment and process changes (e.g., avoided costs to manage surface impoundments). EPA thus derived capital and O&M costs at the plant level for control of each wastestream using the technologies that form the bases for the final rule for existing sources. See the TDD Section 9 for a more detailed description of the methodology EPA used to estimate plant-level costs.

EPA annualized one-time costs and costs recurring on other than an annual basis over a specific useful life, implementation, and/or event recurrence period, using a rate of seven percent. For capital costs and initial one-time costs, EPA used 20 years. For O&M costs incurred at intervals greater than one year, EPA used the interval as the annualization period (3 years, 5 years, 6 years, 10 years). EPA added annualized capital, initial one-time costs, and the non-annual portion of O&M costs to annual O&M costs to derive total annualized plant costs.

EPA calculated total industry costs by applying survey weights to the plant-specific annualized costs and summing them. For the assessment of industry costs, EPA considered costs on both a pre-tax and after-tax basis. Pre-tax annualized costs provide insight on the total expenditure as incurred, while after-tax annualized costs are a more meaningful measure of impact on privately owned for-profit plants, and incorporate approximate capital depreciation and other relevant tax treatments in the analysis. EPA uses pre- and/or after-tax costs in different analyses, depending on the concept appropriate to each analysis (e.g., social costs discussed in Section IX.B are calculated using pre-tax costs whereas cost-to-revenue screening-level analyses discussed in Section IX.C are conducted using after-tax costs). See Table IX-1 for estimates of pre- and post-tax industry costs.

Table IX-1--Total Annualized Industry Costs

In millions, 2013$, 7% Discount Rate

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

Pre-tax After-tax

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

Total Annualized Industry $496.2 $339.6

Costs......................

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

B. Social Costs

Social costs are the costs of the rule from the viewpoint of society as a whole, rather than regulated facilities only. In calculating social costs, EPA tabulated the pre-tax costs in the year when they are estimated to be incurred. EPA assumed that all plants upgrading their systems in order to meet the effluent limitations and standards would do so sometime over a five-year period, during the implementation period for this rule. Given the implementation dates in this rule, and the fact that permitting authorities have to incorporate the final effluent limitations into NPDES permits (which have five-year terms) before they become applicable, this assumption is a reasonable estimate.

EPA performed the social cost analysis over a 24-year analysis period, which combines the length of the period during which plants are anticipated to install the control technologies and the useful life of the longest-lived technology installed at any facility (20 years). EPA calculated social cost of the final rule for existing generating units at steam electric power plants using both a three percent discount rate and an alternative discount rate of seven percent.\41\

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\41\ 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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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.

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Table IX-2--Total Annualized Social Costs

In millions, 2013$

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

3% Discount rate 7% Discount rate

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

Total Annualized Social $479.5 $471.2

Costs......................

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

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

C. Economic Impacts

EPA assessed the economic impacts of this rule in two ways: (1) A screening-level assessment of the cost impacts on existing generating units at steam electric power plants units and the entities that own those plants, based on comparison of costs to revenue; and (2) an assessment of the impact of this rule within the context of the broader electricity market, which includes an assessment of incremental plant closures attributable to this rule.

The following sections summarize the findings for these analyses. The RIA discusses the methods and results in greater detail.

1. Summary of Economic Impacts for Existing Sources

The first set of cost and economic impact analyses--including entity-level impacts at both the steam electric power plant and parent company levels--reflects baseline operating characteristics of steam electric power plants incurring costs and assumes no changes in those baseline operating characteristics (e.g., level of electricity generation and revenue) as a result of the final rule. They provide screening-level indicators of the relative cost of the ELGs to plants, owning entities, or consumers.

The second set of analyses look at broader electricity market impacts taking into account the interconnection of regional and national electricity markets. It also looks at the distribution of impacts at the plant level. This second set of analyses provides insight on the impacts of the final rule on steam electric power plants, as well as the electricity market as a whole, including generation capacity closure and changes in generation and wholesale electricity prices.

As noted in the introduction to this section, EPA used results from the screening analysis of plant- and entity-level impacts, together with projected capacity closure from the market model, to determine that the final rule is economically achievable.

a. Screening-Level Assessment of Impacts on Existing Units at Steam Electric Power Plants and Parent Entities

EPA conducted a screening-level analysis of the rule's potential impact to existing generating units at steam electric power plants and parent entities based on cost-to-revenue ratios. For each of the two levels of analysis (plant and parent entity), the Agency assumed, for analytic convenience and as a worst-case scenario, that none of the costs would be passed on to consumers through electricity rate increases and would instead be absorbed by the steam electric power plants and their parent entities. This assumption overstates the impacts of the final rule since steam electric power plants that operate in a regulated market may be able to recover some of the increased production costs to consumers through increased electricity prices. It is, however, an appropriate assumption for a screening-

level, upper-bound estimate of the potential cost impacts.

Plant-Level Cost-to-Revenue Analysis. EPA developed revenue estimates for this analysis using EIA data. EPA then calculated the annualized after-tax costs of the final rule as a percent of baseline annual revenues. See Chapter 4 of the RIA report for a more detailed discussion of the methodology used for the plant-level cost-to-revenue analysis.

Table IX-3 summarizes the plant-level cost-to-revenue analysis results for the final rule. The cost-to-revenue ratios provide screening-level indicators of potential economic impacts. Plants incurring costs below one percent of revenue are unlikely to face economic impacts, while plants with costs between one percent and three percent of revenue have a higher chance of facing economic impacts, and plants incurring costs above three percent of revenue have a still higher probability of economic impacts. EPA estimates that the vast majority of steam electric power plants (1,034 plants or 96 percent of the universe) to which the final rule apply will incur annualized costs amounting to less than one percent of revenue. In fact, most of these plants will incur no cost at all. Only four percent of plants have costs between one percent and three percent of revenue (38 plants), and less than one percent of plants have costs above three percent of revenue (8 plants). The small fractions of steam electric power plants with costs to revenue ratios exceeding the one percent and three percent thresholds suggest that the final limitations and standards are economically achievable for the industry as a whole.

Table IX-3--Plant-Level Cost-to-Revenue Analysis Results a

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

Number and fraction of existing steam electric power plants with cost-to-revenue ratio of

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

0% 0-1% 1-3% >3%

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

% # % # % # %

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

Count or Percent of Plants.............. 946 88 88 8 38 4 8 1

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

\a\ This analysis makes a counterfactual, conservative assumption of zero cost pass through. Plant counts are

weighted estimates.

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

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defined as that entity with the largest ownership share in the plant.

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

Table IX-4 summarizes the results of the entity-level analysis of the final rule for the two analytic cases.

Table IX-4--Parent Entity-Level After-Tax Annual Costs as a Percentage of Revenue a

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

Not analyzed Number and percentage with after tax annual costs/annual

due to lack of revenue of:

revenue ---------------------------------------------------------------

Total number of entities information 0% 0-1% 1-3% 3% or greater

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

% # % # % # % # %

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

Case 1: Lower-bound estimate of number of entities owning steam electric power plants (which also provides an

upper-bound estimate of total costs that an entity may incur)

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

243............................. 14 6 166 68 53 22 8 3 2 1

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

Case 2: Upper-bound estimate of number of entities owning steam electric power plants (which also provides a

lower-bound estimate of total costs that an entity may incur)

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

507............................. 30 6 414 82 53 10 8 2 2 2 emission rates arising from State Implementation Plans (SIP); Acid Rain Program established under Title IV of the Clean Air Act Amendments; NOX SIP Call trading program for Rhode Island; Clean Air Act Reasonable Available Control Technology requirements and Title IV unit specific rate limits for NOX; the Regional Greenhouse Gas Initiative; Renewable Portfolio Standards; New Source Review Settlements; and several state-level regulations affecting emissions of SO2, NOX, and mercury that are already in place or expected to come into force by 2017.

\43\ EPA typically includes only final rules in its base case for its IPM analyses. However, at the time EPA performed the IPM analyses for this rule, it did not have details of the final CPP rule. EPA therefore used information from the proposed CPP rule as a proxy for purposes of the ELG analyses.

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In contrast to the screening-level analyses, which are static analyses and do not account for interdependence of electric generating units in supplying power to the electric transmission grid, IPM accounts for potential changes in the generation profile of steam electric and other units and consequent changes in market-level generation costs, as the electric power market responds to higher generation costs for steam electric units due to the ELGs. Additionally, in contrast to the screening-level analyses in which EPA assumed no cost pass through of the final rule costs, IPM depicts production activity in wholesale electricity markets where some recovery of compliance costs through increased electricity prices is possible but not guaranteed.

In analyzing the final ELGs, EPA specified additional fixed and variable costs that are expected to be incurred by specific steam electric power plants and generating units to comply with the ELGs (the costs discussed in Section IX.A). EPA then ran IPM including these additional costs to determine the dispatch of electric generating units that would meet projected demand at the lowest costs, subject to the same constraints as those present in the analysis baseline. The estimated changes in plant-specific and unit-specific production levels and costs--and, in turn, changes in total electric power sector costs and production profile--are key data elements in evaluating the expected national and regional effects of the ELGs, including closures of steam electric generating units.

EPA considered impact metrics of interest at three levels of aggregation: (1) Impact on national and regional electricity markets (all electric power generation, including steam and non-steam electric power plants), (2) impact on steam electric power plants as a group, and (3) impact on individual steam electric power plants incurring costs. Chapter 5 of the RIA discusses the first analysis. The sections below summarize the two analyses focusing on steam electric power plants, which are further described in Chapter 5 of the RIA.

All results presented below are representative of modeled market conditions in the years 2028-2033, by which time all plants will meet the effluent limitations and standards. Costs are reflective of costs in the modeled years.\44\

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

year period of analysis, as of 2015.

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Impact on Existing Steam Electric Power Plants. EPA used IPM V5.13 results for 2030 to assess the potential impact of the final rule on existing generating units at steam electric power plants. The purpose of this analysis is to assess impacts on existing generating units at steam electric power plants specifically. EPA used this information in determining whether the ELGs are economically achievable by the steam electric power generating industry as a whole.

Table IX-5 reports results for existing generating units at steam electric power plants, as a group. EPA looked at the following metrics: (1) Incremental early retirements and capacity closures, calculated as the difference between capacity under the ELGs and capacity under the baseline, which includes both full plant closures and partial plant closures (unit closures) in aggregate capacity terms; (2) incremental capacity closures as a percentage of baseline capacity; (3) post-

compliance change in electricity generation; (4) post-compliance changes in variable production costs per MWh, calculated as the sum of total fuel and variable O&M costs divided by net generation; and (5) changes in annual costs (fuel, variable O&M, fixed O&M, and capital). Items (1) and (2) provide important insight for determining the economic achievability of the ELGs.

Table IX-5--Impact of Final ELGs on Steam Electric Power Plants as a Group at the Year 2030

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

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

Incremental early retirements

closures \a\

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

Change in

Change in total

variable

Change in

Region Baseline % of generation

production cost

annual costs

capacity Capacity baseline (GWh or % of

(2013$/MWh or %

(million 2013$

(MW) (MW) capacity baseline)

of baseline)

or % of baseline)

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

Total U.S......................... 359,982 843 0.2% -3,179 -0.2% $0.10 0.3% $496 0.6%

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

\a\ Values for incremental early retirements or closures represent change relative to the baseline run. IPM may show partial (unit) or full plant early

retirements (closures). It may also show avoided closures (negative closure values) in which a unit or plant that is projected to close in the

baseline is estimated to continue operating in the post-compliance case. Avoided closures may occur among plants that incur no compliance costs or for

which compliance costs are low relative to other steam electric power plants.

Under the final rule, variable production costs at steam electric power plants increase by approximately 0.3 percent at the national level. The resulting net change in total capacity for steam electric power plants is very small. For the group of steam electric power plants, total capacity decreases by 843 MW or approximately 0.2 percent of the 359,982 MW baseline capacity, corresponding to a net closure of two units, or when aggregating to the level of steam electric generating plants, one net plant closure.

The change in total generation is an indicator of how steam electric power plants fare, relative to the rest of the electricity market. While at the market level there is essentially no projected change in total electricity generation,\45\

Page 67868

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

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

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These findings of very small national effects (and similarly very small regional effects, as described in Chapter 5 of the RIA) in these impact metrics support EPA's conclusion that the final rule will have little economic consequence for the steam electric power generating industry and the electricity market and is, therefore, economically achievable.

Impact on Individual Steam Electric Power Plants Incurring Costs under this Rulemaking. To assess potential plant-level effects, EPA also analyzed plant-specific changes between the base case and the post-compliance cases for the following metrics: (1) Capacity utilization (defined as annual generation (in MWh) divided by capacity (MW) times 8,760 hours) (2) electricity generation, and (3) variable production costs per MWh, defined as variable O&M cost plus fuel cost divided by net generation.

The analysis of changes in individual plants as a result of the final rule is detailed in Chapter 5 of the RIA. The results indicate that steam electric plants experience only slight effects--no change, or less than a one percent reduction or one percent increase. See Table 5-4 in the RIA. Only 17 plants see their capacity utilization reduced by more than one percent, while 25 plants increase their capacity utilization by more than one percent. The estimated change in variable production costs is higher; 43 plants have an increase in variable production costs exceeding one percent; for seven of these plants, this increase exceeds three percent, but again the vast majority of plants experience a less than one percent increase in variable production costs. Results for the subset of plants incurring costs further support the conclusion that the effects of the final rule on the steam electric industry will be small.

2. Summary of Economic Impacts for New Sources

EPA also evaluated the expected costs of meeting the final standards for new sources. The incremental cost associated with complying with the final NSPS and PSNS varies depending on the types of processes, wastestreams, and waste management systems that the plant would have installed in the absence of the new source requirements. EPA estimated capital and O&M costs for several scenarios that represent the different types of operations present at existing steam electric power plants or typically included at new steam electric power plants. These scenarios capture differences in the plant status (building a generating unit at a new location versus adding a new generating unit at an existing power plant), presence of on-site impoundments or landfills, type of ash handling, type of FGD systems in service, and type of leachate collection and handling.

EPA assessed the possible impact of this final rule on new units by comparing the incremental costs for new units to the overall cost of building and operating new scrubbed coal units, on an annualized basis.

EPA estimated costs of a new coal unit using the overnight \46\ capital and O&M costs of building and operating a new scrubbed coal unit from the EIA's Annual Energy Outlook 2014. For purposes of this analysis, EPA assumed a new dual-unit plant with a total generation capacity of 1,300 MW. Table IX-6 shows capital and O&M costs of building and operating a new coal unit and contrasts these costs with the incremental costs associated with the final NSPS/PSNS.

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

Table IX-6--Comparison of Incremental Compliance Costs With Costs for New Coal-Fired Steam Electric Units

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

Costs of new Incremental

Cost component coal generation compliance costs % of new

($2013/MW) \a\ ($2013/MW) \b\ generation cost

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

Capital................................................... $3,058,861 $8,328-$87,085 0.3-2.8

Annual Non-Fuel O&M....................................... 69,630 620-8,828 0.3-3.9

Annual Fuel \c\........................................... 157,737

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

Total Annualized Costs................................ 497,213 1,354-16,511 0.3-3.3

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

\a\ Source: New unit total cost value from Table 8.2 EIA NEMS Electricity Market Module. AEO 2014 Documentation.

Available at http://www.eia.gov/forecasts/aeo/assumptions/pdf/electricity.pdf. Capital costs are based on the

total overnight costs for new scrubbed coal dual-unit plant, 1,300 MW capacity, coming online in 2017. EPA

restated costs in 2013 dollars using the construction cost index. Total annual O&M costs assume 90% capacity

utilization.

\b\ Incremental costs for new 1300 MW unit for Option F. Range represents the costs for a new unit at a newly

constructed plant (lower bound) and new unit at an existing plant, with evaporation technology (upper bound).

\c\ Fuel costs estimated assuming heat rate of 8,800 Btu/kWh (AEO 2014) and coal price delivered to the power

sector of 2.27 $/Mbtu (AEO 2015, projected costs in 2017 in 2013$).

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

EPA took a similar approach to the one described above for plant-

specific costs in estimating pollutant reductions associated with the final rule. For each wastestream \47\ and each POC, EPA first estimated--on an annual, per plant basis--plant-specific baseline pollutant

Page 67869

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

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\47\ EPA estimated pollutant reductions for wastestreams with numeric and zero pollutant discharge limitations and standards. The reductions reflect a reduction in the mass of pollutant discharged.

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

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

Table X-1 presents estimated industry-level pollutant reductions for the final rule.

Table X-1--Total Annualized Pollutant Loading Reductions

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

Pollutant reductions (pounds per year)

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

Analysis baseline Conventional Priority Nonconventional

pollutants \a\ pollutants pollutants \b\

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

Final Rule................................................ 13,400,000 410,000 371,000,000

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

\a\ The loadings reduction for conventional pollutants includes BOD and TSS.

\b\ The loadings reduction for nonconventional pollutants excludes TDS and COD to avoid double counting removals

for certain pollutants that would also be measured by these bulk parameters (e.g., sodium, magnesium).
Development of Effluent Limitations and Standards

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

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

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EPA developed the new numeric effluent limitations and standards in this final rule using long-term average effluent values and variability factors that account for variation in performance at well-operated facilities that employ the technologies that constitute the bases for control. EPA's methodology for derivation of limitations in ELGs is longstanding and has been upheld in court. See, e.g., Chem. Mfrs. Ass'n v. EPA, 870 F.2d 177 (5th Cir. 1989); Nat'l Wildlife Fed'n v. EPA, 286 F.3d 554 (D.C. Cir. 2002). EPA establishes the final effluent limitations and standards as ``daily maximums'' and ``maximums for monthly averages.'' Definitions provided in 40 CFR 122.2 state that the daily maximum limitation is the ``highest allowable `daily discharge' '' and the maximum for monthly average limitation is the ``highest allowable average of `daily discharges' over a calendar month, calculated as the sum of all `daily discharges' measured during a calendar month divided by the number of `daily discharges' measured during that month.'' Daily discharges are defined to be the `` `discharge of a pollutant' measured during a calendar day or any 24-

hour period that reasonably represents the calendar day for purposes of sampling.''

EPA's objective in establishing daily maximum limitations is to restrict the discharges on a daily basis at a level that is achievable for a plant that targets its treatment at the long-term average. EPA acknowledges that variability around the long-term average occurs during normal operations. This variability means that plants occasionally may discharge at a level that is higher (or lower) than the long-term average. To allow for these possibly higher daily discharges and provide an upper bound for the allowable concentration of pollutants that may be discharged, while still targeting achievement of the long-term average, EPA has established the daily maximum limitation. A plant that consistently discharges at a level near the daily maximum limitation would not be operating its treatment to achieve the long-term average. Targeting treatment to achieve the daily limitation, rather than the long-term average, may result in values that frequently exceed the limitations due to routine variability in treated effluent.

EPA's objective in establishing monthly average limitations is to provide an additional restriction to help ensure that plants target their average discharges to achieve the long-term average. The monthly average limitation requires dischargers to provide ongoing control, on a monthly basis, that supplements controls imposed by the daily maximum limitation. In order to meet the monthly average limitation, a plant must counterbalance a value near the daily maximum limitation with one or more values well below the daily maximum limitation.

The TDD provides a detailed description of the data and methodology used to develop long-term averages, variability factors, and limitations and standards for the final rule. As a result of public comments, EPA expanded the data set used to calculate the BAT/PSES effluent limitations and standards for discharges of FGD wastewater from existing sources. Largely, this expanded data set includes additional self-monitoring data from plants operating

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the selected technology basis. EPA also expanded the data set by including treatment performance data from another plant that, upon review of comments, EPA determined would be appropriate to use to calculate the effluent limitations in this rule. The combination of EPA sampling data (both EPA-collected and CWA section 308 samples collected by plants for analysis by EPA) and plant self-monitoring data results in data sets characterizing the treatment system performance over several years at each of the plants used to develop effluent limitations and standards for FGD wastewater.

EPA identified certain data that warranted exclusion from the calculations of the limitations and standards because: (1) The samples were analyzed using an analytical method that is not approved in 40 CFR part 136 for NPDES permit purposes; (2) the samples were analyzed using an insufficiently sensitive analytical method (e.g., use of EPA Method 245.1 to measure the concentration of mercury in effluent samples); (3) the samples were analyzed in a manner which resulted in an unacceptable level of analytical interferences; (4) the samples were collected during the initial commissioning period for the wastewater treatment system or the plant decommissioning period and do not represent BAT/

NSPS level of performance; (5) the analytical results were identified as questionable due to quality control issues, abnormal conditions or treatment system upsets, or were analytical anomalies; (6) the samples were collected from a location that is not representative of treated effluent; or (7) the treatment system was operating in a manner that does not represent BAT/NSPS level of performance. The results of EPA's evaluation of the data and reasons for any data exclusions are summarized in DCN SE05733.

Tables XI-1 and XI-2 present the effluent limitations and standards for FGD wastewater, gasification wastewater, and combustion residual leachate. For comparison, the tables also present the long-term average treatment performance calculated for these wastestreams. Due to routine variability in treated effluent, a power plant that targets discharging its wastewater at a level near the values of the daily maximum limitation or the monthly average limitation may experience frequent values exceeding the limitations. For this reason, EPA recommends that plants design and operate the treatment system to achieve the long-term average for the model technology. In doing so, a system that is designed to represent the BAT/NSPS level of control would be expected to meet the limitations.

EPA expects that plants will be able to meet their effluent limitations or standards at all times. If an exceedance is caused by an upset condition, the plant would have an affirmative defense to an enforcement action if the requirements of 40 CFR 122.41(n) are met. Exceedances caused by a design or operational deficiency, however, are indications that the plant's performance does not represent the appropriate level of control. For these final limitations and standards, EPA determined that such exceedances can be controlled by diligent process and wastewater treatment system operational practices, such as regular monitoring of influent and effluent wastewater characteristics and adjusting dosage rates for chemical additives to target effluent performance for regulated pollutants at the long-term average concentration for the BAT/NSPS technology. Additionally, some plants may need to upgrade or replace existing treatment systems to ensure that the treatment system is designed to achieve performance that targets the effluent concentrations at the long-term average. This is consistent with EPA's costing approach and its engineering judgment developed over years of evaluating wastewater treatment processes for steam electric power plants and other industrial sectors. EPA recognizes that, as a result of the final rule, some dischargers, including those that are operating technologies representing the technology bases for the final rule, may need to improve their treatment systems, process controls, and/or treatment system operations in order to consistently meet the effluent limitations and standards. This is consistent with the CWA, which requires that discharge limitations and standards reflect the best available technology economically achievable or the best available demonstrated control technology.

See DCN SE05733 for details of the calculation of the limitations and standards presented in the tables below.

Table XI-1--Long-Term Averages and Effluent Limitations and Standards for FGD Wastewater and Gasification

Wastewater for Existing Sources

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

Daily Monthly

Wastestream Pollutant Long-term maximum average

average limitation limitation

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

FGD Wastewater (BAT & PSES)............... Arsenic (microg/L)......... 5.98 11 8

Mercury (ng/L)............... 159 788 356

Nitrate/nitrite as N (mg/L).. 1.3 17.0 4.4

Selenium (microg/L)........ 7.5 23 12

Voluntary Incentives Program for FGD Arsenic (microg/L)......... \a\ 4.0 \b\ 4 (\c\)

Wastewater (BAT only). Mercury (ng/L)............... 17.8 39 24

Selenium (microg/L)........ \a\ 5.0 \b\ 5 (\c\)

TDS (mg/L)................... 14.9 50 24

Gasification Wastewater (BAT & PSES)...... Arsenic (microg/L)......... \a\ 4.0 \b\ 4 (\c\)

Mercury (ng/L)............... 1.08 1.8 1.3

Selenium (microg/L)........ 147 453 227

TDS (mg/L)................... 15.2 38 22

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

\a\ Long-term average is the arithmetic mean of the quantitation limits since all observations were not

detected.

\b\ Limitation is set equal to the quantitation limit.

\c\ Monthly average limitation is not established when the daily maximum limitation is based on the quantitation

limit.

Page 67871

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

Residual Leachate for New Sources

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

Daily Monthly

Wastestream Pollutant Long-term maximum average

average limitation limitation

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

FGD Wastewater (NSPS & PSNS).............. Arsenic (microg/L)......... \a\ 4.0 \b\ 4 (\c\)

Mercury (ng/L)............... 17.8 39 24

Selenium (microg/L)........ \a\ 5.0 \b\ 5 (\c\)

TDS (mg/L)................... 14.9 50 24

Gasification Wastewater (NSPS & PSNS)..... Arsenic (microg/L)......... \a\ 4.0 \b\ 4 (\c\)

Mercury (ng/L)............... 1.08 1.8 1.3

Selenium (microg/L)........ 147 453 227

TDS (mg/L)................... 15.2 38 22

Combustion Residual Leachate (NSPS & PSNS) Arsenic (microg/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.
Non-Water Quality Environmental Impacts

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

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

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

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

Table XII-1--Industry-Level Energy Requirements for the Final Rule

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

Final

Non-water quality environmental impact rule

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

Electrical Energy Usage (MWh)................................. 237,000

Fuel (GPY).................................................... 556,000

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

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

Table XII-2--Air Emissions Associated With BAT/PSES for Final Rule

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

Change in air

2009 emissions emissions Increase in

Non-water quality environmental impact by electric associated with emissions for

power industry final rule final rule (%)

(million tons) (million tons)

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

NOX.................................................... 1 -0.0114 -1.16

SOX.................................................... 6 0.00243 0.0406

CO2.................................................... 2,403 -2.58 -0.107

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

EPA compared the estimated increase in solid waste generation to the amount of solids generated in a year by electric power plants throughout the U.S.--approximately 134 billion tons. The increase in solid waste generation associated with the final rule is less than 0.001 percent of the total solid waste generated by all electric power plants.

EPA estimates that, under the final rule, steam electric power plants will reduce their water withdrawal by 57 billion gallons per year (155 million gallons per day). See TDD Section 12.

Based on these analyses, EPA determined that the final BAT effluent limitations and PSES have acceptable non-water quality environmental impacts, including energy impacts.
Environmental Assessment

A. Introduction

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

Page 67872

conducted modeling to determine the cumulative impacts of pollution from the universe of steam electric power plants to which the final rule applies. EPA modeled both the impacts of steam electric power plant discharges at baseline conditions (pre-rule conditions) and the improvements that will likely result after implementation of the rule.

EPA's review of the scientific literature; documented cases of the extensive impacts of steam electric power plant wastewater discharges on human health and the environment; and a full description of EPA's modeling methodology and results are provided in the EA.

B. Summary of Human Health and Environmental Impacts

As discussed in the environmental assessment and proposed rule, current scientific literature indicates that steam electric power plant wastewaters such as fly ash transport water, bottom ash transport water, FGD wastewater, and combustion residual leachate contain large amounts of a wide range of harmful pollutants, some of which are toxic and bioaccumulative, and which cause significant, widespread detrimental environmental and human health impacts.

Discharges of steam electric power plant wastewaters present a serious public health concern due to the potential human exposure to toxic pollutants through consumption of contaminated fish and drinking water. Toxic pollutants that detrimentally affect human health that are commonly found in steam electric power plant wastewater discharges include mercury, lead, arsenic, cadmium, thallium, and selenium, along with numerous others (see EA Section 3). These pollutants are associated with a variety of documented adverse human health impacts. For example, human exposure to elevated levels of mercury for relatively short periods of time can result in kidney and brain damage. Pregnant women who are exposed to mercury can pass the contaminant to their developing fetus, leading to possible toxic injury of the fetal brain and damage to other parts of the nervous system. Human exposure to elevated levels of lead can cause serious damage to the brain, kidneys, nervous system, and red blood cells, especially in children. Arsenic is associated with an increased risk of liver and bladder cancer in humans, as well as non-cancer impacts including dermal, cardiovascular, respiratory, and reproductive effects such as excess incidences of miscarriages, stillbirths, preterm births, and low birth weights. Chronic exposure to cadmium, a probable carcinogen, can lead to kidney failure, lung damage, and weakened bones. Human exposure to elevated levels of thallium can lead to neurological symptoms, hair loss, gastrointestinal effects, liver and kidney damage, and reproductive and developmental damage. Long-term exposure to selenium can damage the kidney, liver, and nervous and circulatory systems.

The pollutants in steam electric power plant wastewater can bioaccumulate within fish and other aquatic wildlife in the receiving waters and subsequently be transferred to recreational and subsistence fishers who consume these contaminated fish, potentially resulting in the acute and chronic health impacts described above. Certain populations are particularly at risk, including women who are pregnant, nursing, or may become pregnant, and communities relying on consumption of fish from contaminated waters as a major food source.

Discharges of steam electric power plant pollutants to surface waters also have the potential to contaminate drinking water sources, causing potential problems for drinking water systems and, if left untreated, potential adverse health effects. A recent study indicates that pollutants in ash and FGD wastewater discharges exceeded MCLs in every surface water that was monitored in North Carolina during the study (see DCN SE01984). Nitrogen discharges from steam electric power plants can contribute, along with other sources, to harmful algal blooms. Harmful algal blooms can affect drinking water sources, such as the recent incident in Toledo, Ohio (see DCN SE04517).

Bromide discharges from steam electric power plants can contribute to the formation of carcinogenic DBPs in public drinking water systems. A recent study identified four drinking water treatment plants that experienced increased levels of bromide in their source water, and in some, a corresponding increase in the formation of brominated DBPs in the drinking water system, after the installation of wet FGD scrubbers at upstream steam electric power plants (see DCN SE04503).

Although not directly addressed by this final rule, ground water contamination from surface impoundments containing steam electric power plant wastewater also threatens drinking water sources. EPA identified more than 30 documented cases where ground water contamination from surface impoundments extended beyond the plant boundaries, illustrating the threat to ground water drinking water sources (see DCN SE04518). Where this final rule helps to reduce or eliminate the continued disposal or storage of steam electric power plant wastewater pollutants in unlined or leaking surface impoundments, potential impacts to ground water will also be reduced or eliminated.

The ecological impacts of steam electric power plant wastewater pollutants include both acute (e.g., fish kills) and chronic effects (e.g., reproductive failure, malformations, and metabolic, hormonal, and behavioral disorders) upon biota within the receiving water and the surrounding environment. Recovery of aquatic environments from exposure to these steam electric power plant pollutants can be extremely slow due to the accumulation and continued cycling of the pollutants within ecosystems, resulting in the potential to alter ecological processes such as population diversity and community dynamics. Furthermore, many steam electric power plants discharge pollutants to sensitive environments such as the Great Lakes, valuable estuaries such as the Chesapeake Bay, 303(d) listed impaired waters, and waters with fish consumption advisories. EPA identified 69 steam electric power plants with documented adverse environmental impacts on surface waters (see DCN SE04518).

C. Environmental Assessment Methodology

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

Page 67873

that EPA anticipates, given other existing rules, primarily the CCR and CPP rules.

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

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

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

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

Additionally, for the final rule, EPA updated and improved several input parameters for the IRW model, including fish consumption rates for recreational and subsistence fishers, the bioconcentration factor for copper, and benchmarks for assessing the potential for impacts to benthic communities in receiving waters.

The case-study modeling for the final rule is based on EPA's Water Quality Analysis Simulation Program (WASP), which accounts for fluctuations in receiving water flow rates by using daily stream flow monitoring data instead of one annual average flow rate for the receiving water, as used in the IRW. The case-study modeling accounts for pollutant transport and accumulation within receiving water reaches that are downstream from the discharge location, allowing for an assessment of environmental impacts over a larger portion of the receiving waterbody. The case study modeling also accounts for pollutant contributions from other point, nonpoint, and background sources, to the extent practical, using available data sources. EPA used the water quality results of the case-study modeling to supplement the results of the IRW model (see EA Section 8).

EPA improved its selenium bioaccumulation modeling for impacts on wildlife by developing and using an ecological risk model that predicts the risk of reproductive impacts among fish and waterfowl exposed to selenium from steam electric power plant wastewater discharges. The ecological risk model accounts for the bioaccumulation of selenium in aquatic organisms through dietary exposure (the food web), as contrasted with exposure only to dissolved selenium in the water column. Dietary exposure plays a more significant role in determining the extent of selenium bioaccumulation in aquatic organisms. The ecological risk model also accounts for the higher rates of selenium bioaccumulation that can occur in slow-flowing aquatic systems such as lakes and reservoirs, and the risk model translates selenium tissue concentrations into the predicted risk of adverse reproductive effects (e.g., reduced egg hatchability, larval mortality, and deformities that affect survival) among exposed fish and waterfowl. EPA applied the ecological risk model to the water quality outputs from both the national-scale IRW model and the case-study models. See EA Section 5.2 for a more detailed discussion.

D. Outputs From the Environmental Assessment

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

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

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

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

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

Table XIII-1--Key Environmental Improvements Within Modeled Immediate

Receiving Waters Under the Final Rule 53

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

Will improve under the final

Criteria evaluated for exceedances rule?

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

Freshwater Acute National Recommended WQC. YES

Freshwater Chronic National Recommended YES

WQC.

Human Health Water and Organism National YES

Recommended WQC.

Human Health Organism Only National YES

Recommended WQC.

Drinking Water MCL........................ YES

Fish Ingestion NEHC for Mink.............. YES

Fish Ingestion NEHC for Eagles............ YES

Adverse Reproductive Effects in Fish due YES

to Selenium.

Adverse Reproductive Effects in Mallards YES

due to Selenium.

Non-Cancer Reference Dose for Child YES

(Recreational and Subsistence fishers).

Non-Cancer Reference Dose for Adult YES

(Recreational and Subsistence fishers).

Arsenic Cancer Risk for Child YES

(Recreational and Subsistence fishers).

Arsenic Cancer Risk for Adult YES

(Recreational and Subsistence fishers).

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

Acronyms: MCL (Maximum Contaminant Level); NEHC (No Effect Hazard

Concentration); WQC (Water Quality Criteria).

\a\ The IRW model encompasses a total of 163 immediate receiving waters

(144 rivers and streams; 19 lakes, ponds, and reservoirs) and loadings

from 143 steam electric power plants.

1. Improvements in Surface Water and Ground Water Quality

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

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

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

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

cancer human health effects, (e) reduction in nutrient impacts, (f) reduction in other environmental impacts, and (g) other unquantified environmental improvements.

Page 67874

EPA expects significantly reduced contamination levels in surface waters and sediments under the final rule. EPA estimates that reduced pollutant loadings to surface waters will significantly improve water quality by reducing pollutant concentrations by an average of 56 percent within the immediate receiving waters of steam electric power plants where additional treatment technologies are installed as a result of this final rule. Based on the water quality component of the IRW model, which compares modeled receiving water concentrations to national recommended WQC and MCLs to assess changes in receiving water quality, the pollutants with the greatest number of water quality standard exceedances under baseline pollutant loadings include: Total arsenic, total thallium, total selenium, and dissolved cadmium. EPA estimates that almost half of the immediate receiving waters exceed a water quality standard under baseline loadings. EPA estimates that the number of immediate receiving waters with aquatic life exceedances, which are driven by high total selenium and dissolved cadmium concentrations, will be reduced under the final rule. EPA also estimates that the number of immediate receiving waters with human health water quality standards exceedances, primarily driven by high total arsenic and total thallium concentrations, will be reduced under the final rule.

Selenium is one of the primary pollutants documented in the literature as causing environmental impacts to fish and wildlife. EPA calculates that total selenium receiving water concentrations will be reduced by two-thirds under the final rule, leading to a reduction in the number of immediate receiving waters exceeding the freshwater chronic criteria for selenium.

While the case-study models and IRW model produced generally similar results for the five receiving waters included in both analyses, the case-study model reveals additional potential for baseline impacts to water quality, aquatic life, and human health that are not reflected in the IRW model. Case-study modeling also reveals that these potential impacts can extend beyond the immediate receiving water and into downstream waters, leading to the potential for more widespread environmental and human health effects than those shown with the IRW model. This is particularly true regarding water quality standard exceedances; in four of the five receiving waters included in both analyses, the case-study model indicates that the final rule will result in further reductions in water quality standard exceedances beyond those reflected in the IRW model.

As discussed in the EA, the RSEI modeling indicates that surface waters downstream from steam electric power plant wastewater discharges will also achieve water quality improvements under the final rule.

This final rule will also potentially help to both reduce ground water contamination and improve the availability of ground water resources by complementing the CCR rule. This rule provides strong incentives for plants to greatly reduce, if not entirely eliminate, disposal and treatment of steam electric power plant wastewater in unlined surface impoundments.

2. Reduced Impacts to Wildlife

EPA expects that once the rule is implemented the number of immediate receiving waterbodies with potential impacts to wildlife will begin to be reduced by more than a half compared to baseline conditions under the final rule.

EPA determined that steam electric power plant wastewater discharges into lakes pose the greatest risk to piscivorous (fish eating) wildlife, with almost a half of lakes exceeding a protective benchmark for minks or eagles under baseline pollutant loadings (compared to about a third of rivers). Mercury and selenium are the primary pollutants with the greatest number of receiving waters with benchmark exceedances. EPA estimates that this rule will reduce the number of immediate receiving waters exceeding the benchmark for minks and eagles by approximately half for mercury and selenium. Additionally, as discussed in the EA, the downstream RSEI modeling indicates that surface waters downstream from steam electric power plant wastewater discharges will also achieve improvements in these wildlife benchmarks under the final rule.

For the final rule, EPA also performed modeling to estimate the risk of adverse reproductive effects among fish (e.g., reduced larvae survival) and waterfowl (e.g., reduced egg hatchability) with dietary exposure to selenium from steam electric power plant wastewater. Based on the water quality output from the IRW model, EPA determined that approximately 15 percent of immediate receiving waters contain selenium concentrations that present at least a ten percent risk of adverse reproductive effects among fish or waterfowl that consume prey from those waterbodies. Under the final rule, EPA estimates that the count of immediate receiving waters presenting these reproductive risks will be reduced by more than half. This indicates that the final rule will reduce the long-term bioaccumulative impact of selenium (and possibly other bioaccumulative pollutants) throughout aquatic ecosystems.

In addition, EPA estimates that the improvements to water quality, discussed above, will improve aquatic and wildlife habitats in the immediate and downstream receiving waters from steam electric power plant discharges. EPA determined that these water quality and habitat improvements will enhance efforts to protect threatened and endangered species. EPA identified four species with a high vulnerability to changes in water quality whose recovery will be enhanced by the pollutant reductions associated with the final rule.

3. Reduced Human Health Cancer Risk

EPA estimates that reductions in arsenic loadings from the final rule will result in a reduction in potential cancer risks to humans that consume fish exposed to steam electric power plant discharges. In addition, based on the downstream RSEI modeling, EPA estimates that numerous river miles downstream from steam electric discharges contain fish contaminated with inorganic arsenic that present cancer risks to at least one of the evaluated cohorts. The final rule substantially reduces this number of miles.

4. Reduced Threat of Non-Cancer Human Health Effects

Exposure to toxic bioaccumulative pollutants poses risk of systemic and other effects to humans, including effects on the circulatory, respiratory, or digestive systems, and neurological and developmental effects. EPA estimates the final rule will significantly reduce the number of receiving waters with the potential to cause non-cancer health effects in humans who consume fish exposed to steam electric power plant pollutants.

Under baseline pollutant loadings, EPA determined that about half of immediate receiving waters present non-cancer health risks for one or more of the human cohorts due to elevated pollutant levels in fish. The final rule, once implemented, will begin to reduce this amount by approximately 50 percent for all the human cohorts that were evaluated. Non-cancer risks are caused primarily by mercury (as methylmercury), total thallium, and total selenium, and to a lesser degree, total cadmium pollutant loadings. Additionally, as discussed in the EA, the downstream RSEI modeling indicates that the final rule substantially

Page 67875

reduces the prevalence of downstream waters with contaminated fish that present non-cancer health risks to at least one of the human cohorts.

In addition to the assessment of non-cancer impacts described above, EPA also evaluated the adverse health effects to children who consume fish contaminated with lead from steam electric power plant wastewater. EPA estimates that the final rule will significantly reduce the associated IQ loss among children who live in recreational angler and subsistence fisher households. The final rule will also reduce the incidence of other health effects associated with lead exposure among children, including slowed or delayed growth, delinquent and anti-

social behavior, metabolic effects, impaired heme synthesis, anemia, and impaired hearing. The final rule will also reduce IQ loss among children exposed in utero to mercury from maternal fish consumption. Section XIV.B.1 provides additional details on the benefits analysis of these reduced IQ losses.

The final rule will also result in additional non-cancer human health improvements beyond those discussed above, including reduced health hazards due to exposure to contaminants in waters that are used for recreational purposes (e.g., swimming).

5. Reduced Nutrient Impacts

The primary concern with nutrients (nitrogen and phosphorus) in steam electric power plant discharges is the potential for contributing to adverse impacts in waterbodies that receive nutrient discharges from multiple sources. Excessive nutrient loadings to receiving waters can significantly affect the ecological stability of freshwater and saltwater aquatic ecosystems and pose health threats to humans from the generation of toxins by cyanobacteria, which can thrive in nitrogen driven algal blooms (DCN SE04505).

Nine percent of surface waters receiving steam electric power plant wastewater discharges are impaired for nutrients. Although the concentration of nitrogen present in steam electric power plant discharges from any individual power plant is relatively low, the total nitrogen loadings from a single plant can be significant due to large wastewater discharge flow rates.

EPA projects that the final rule will reduce total nutrient loadings by steam electric power plants in their immediately downstream receiving waters by more than 99 percent. Section XIV provides additional details on the water quality benefits analysis of nutrient reductions, as determined using the SPARROW (Spatially Referenced Regressions On Watershed attributes) model.

E. Unquantified Environmental and Human Health Improvements

The environmental assessment focused primarily on the quantification of environmental improvements within rivers and lakes from post-compliance pollutant reductions for toxic bioaccumulative pollutants and excessive nutrients. While extensive, the environmental improvements quantified do not encompass the full range of improvements anticipated to result from the final rule simply because some of the improvements have no method for measuring a quantifiable or monetizable improvement. EPA estimates post-compliance pollutant reductions from the final rule to result in much greater improvements than those quantified for wildlife, human health and the environment by:

Reducing loadings of bioaccumulative pollutants to the broader ecosystem, resulting in the reduction of long-term exposures and sub-lethal ecological effects;

Reducing sub-lethal chronic effects of toxic pollutants on aquatic life not captured by the national recommended WQC;

Reducing loadings of pollutants for which EPA did not perform water quality modeling in support of the environmental assessment (e.g., boron, manganese, aluminum, vanadium, and iron);

Mitigating impacts to aquatic and aquatic-dependent wildlife population diversity and community structures;

Reducing exposure of wildlife to pollutants through direct contact with combustion residual surface impoundments and constructed wetlands built as treatment systems at steam electric power plants; and

Reducing the potential for the formation of harmful algal blooms.

Data and analytical limitations prevent modeling the scale and complexity of the ecosystem processes potentially impacted by steam electric power plant wastewater, resulting in the inability to quantify all potential improvements. However, documented site-specific impacts in the literature reinforce that these impacts are common in the environments surrounding steam electric power plants and fully support the conclusion that reducing pollutant loadings will further reduce risks to human health and wildlife and prevent damage to the environment.

Although the environmental assessment quantifies impacts to wildlife that consume fish contaminated with pollutants from steam electric power plant wastewater, it does not capture the full range of exposure pathways through which bioaccumulative pollutants can enter the surrounding food web. Wildlife can encounter toxic bioaccumulative pollutants from discharges of the evaluated wastestreams through a variety of exposure pathways such as direct exposure, drinking water, consumption of contaminated vegetation, and consumption of contaminated prey other than fish and invertebrates. Therefore, the quantified improvements underestimate the complete loadings of bioaccumulative pollutants that can impact wildlife in the ecosystem. The final rule will lower the total amount of toxic bioaccumulative pollutants entering the food web near steam electric power plants.

EPA also estimates that reductions in pollutant loadings will lower the occurrence of sub-lethal effects associated with many of the pollutants in steam electric power plant wastewater that are not captured by comparisons with national recommended WQC for aquatic life. Chronic effects such as decreased reproductive success, changes in metabolic rates, decreased growth rates, changes in morphology (e.g., fin erosion, oral deformities), and changes in behavior (e.g., swimming ability, ability to catch prey, ability to escape from predators) that can negatively affect long-term survival, are well documented in the literature as occurring in aquatic environments near steam electric power plants. Reductions in organism survival rates from chronic effects such as abnormalities can alter interspecies relationships (e.g., declines in the abundance or quality of prey) and prolong ecosystem recovery. Additionally, EPA was unable to quantify changes to aquatic and wildlife population diversity and community dynamics; however, population effects (decline in number and type of organisms present) caused by exposure to steam electric power plant wastewater are well documented in the literature. Changes in aquatic populations can alter the structure and function of aquatic communities and cause cascading effects within the food web that result in long-term impacts to ecosystem dynamics. EPA estimates that post-compliance pollutant loading reductions associated with the final rule will lower the stressors that can cause alterations in population and community dynamics and improve the overall function of ecosystems

Page 67876

surrounding steam electric power plants, as well as help resolve issues faced in other national ecosystem protection programs such as the Great Lakes program, the National Estuaries program, and the 303(d) impaired waters program.

The post-compliance pollutant reductions associated with the final rule will also decrease the environmental impacts to wildlife exposed to pollutants through direct contact with surface impoundments and constructed wetlands at steam electric power plants. Documented site-

specific impacts demonstrate that wildlife living in close proximity to combustion residual impoundments exhibit elevated levels of arsenic, cadmium, chromium, lead, mercury, selenium, and vanadium. Multiple studies have linked these ``attractive nuisance'' areas (contaminated impoundments at a steam electric power plant that attract wildlife for nesting or feeding) to diminished reproductive success. EPA estimates that the post-compliance pollutant reductions will decrease the exposure of wildlife populations to toxic pollutants and reduce the risks for impacts on reproductive success.

F. Other Improvements

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

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

A. Categories of Benefits Analyzed

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

TABLE XIV-1--Benefit Categories Associated With Final Rule

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

Neither

Benefit category Quantified and Quantified but quantified nor

monetized not monetized monetized

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

1. Human Health Benefits from Surface Water Quality Improvements

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

Reduced incidence of cancer from arsenic exposure via fish X

consumption.................................................

Reduced incidence of cardiovascular disease from arsenic X

exposure via fish consumption...............................

Reduced incidence of cardiovascular disease from lead X \a\

exposure via fish consumption...............................

Reduced incidence of other cancer and non-cancer adverse X

health effects (e.g., reproductive, immunological,

neurological, circulatory, or respiratory toxicity) due to

exposure to arsenic, lead, cadmium, and other toxics from

fish consumption............................................

Reduced IQ loss in children from lead exposure via fish X

consumption.................................................

Reduced need for specialized education for children from lead X

exposure via fish consumption...............................

Reduced in utero mercury exposure via maternal fish X

consumption.................................................

Reduced health hazards from exposure to pollutants in waters X

used recreationally (e.g., swimming)........................

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

2. Ecological Conditions and Recreational Use Benefits from Surface Water Quality Improvements

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

Benefits from improvements in surface water quality, X

including: Improved aquatic and wildlife habitat; enhanced

water-based recreation, including fishing, swimming,

boating, and near-water activities; increased aesthetic

benefits, such as enhancement of adjoining site amenities

(e.g., residing, working, traveling, and owning property

near the water \b\; and non-use value (existence, option,

and bequest value from improved ecosystem health) \b\.......

Benefits from improved protection of threatened and X

endangered species..........................................

Reduced sediment contamination............................... X

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

3. Market and Productivity Benefits

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

Reduced impoundment failures (monetized benefits include X X

avoided cleanup costs, transaction costs, and environmental

damages; non-quantified benefits include avoided injury)....

Reduced water treatment costs for municipal drinking water, X

irrigation water, and industrial process....................

Improved commercial fisheries yields......................... X

Increased tourism and participation in water-based recreation X

Increased property values from water quality improvements.... X

Increased ability to market coal combustion byproducts....... X \a\

Page 67877

Reduced maintenance dredging in navigational waterways and X \a\

reservoirs from reduction in sediment discharges............

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

4. Air-Related Benefits

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

Human health benefits from reduced morbidity and mortality X

from exposure to NOX, SO2 and particulate matter (PM2.5)....

Avoided climate change impacts from CO2 emissions............ X

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

5. Benefits from Reduced Water Withdrawals

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

Increased availability of ground water resources............. X

Reduced impingement and entrainment of aquatic organisms..... X

Reduced susceptibility to drought............................ X

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

\a\ Monetized benefit category added for the final rule.

\b\ These values are implicit in the total willingness to pay (WTP) for water quality improvements.

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

B. Quantification and Monetization of Benefits

1. Human Health Benefits From Surface Water Quality Improvements

Reduced pollutant discharges from steam electric power plants generate human health benefits in a number of ways. As described in Section XIII, exposure to pollutants in steam electric power plant discharges via consumption of fish from affected waters can cause a wide variety of adverse health effects, including cancer, kidney damage, nervous system damage, fatigue, irritability, liver damage, circulatory damage, vomiting, diarrhea, brain damage, IQ loss, and many others. Because the final rule will reduce discharges of steam electric pollutants into waterbodies that receive, or are downstream from, these discharges, it is likely to result in decreased incidences of associated illnesses.

Due to data limitations and uncertainties, EPA is able to monetize only a subset of the health benefits associated with reductions in pollutant discharges from steam electric power plants. EPA analyzed the following measures of human health-related benefits: Reduced lead-

related IQ loss in children aged zero to seven from fish consumption; reduced cardiovascular disease in adults from lead and arsenic exposure from fish consumption; reduced mercury-related IQ loss in children exposed in utero due to maternal fish consumption; and reduced cancer risk in adults due to arsenic exposure from fish consumption. EPA monetized these human health benefits by estimating the change in the expected number of individuals experiencing adverse human health effects in the populations exposed to steam electric discharges and/or reduced exposure levels, and valuing these changes using a variety of monetization approaches.

These are not the only human health benefits expected to result from the final rule. EPA also estimated additional human health benefits derived from changes in air emissions. These additional benefits are discussed separately in Section XIV.B.4.

a. Monetized Human Health Benefits From Surface Water Quality Improvements

EPA estimated health risks from the consumption of contaminated fish from waterbodies within 50 miles of households. EPA used Census Block population data, state-specific average fishing rates, and data on fish consumption advisories to estimate the exposed population. EPA used cohort-specific fish consumption rates and waterbody-specific fish tissue concentration estimates to calculate exposure to steam electric pollutants. Cohorts were defined by age, sex, race/ethnicity, and fishing mode (recreational/subsistence). EPA used these data to quantify and monetize the following six categories of human health benefits, which are further detailed in the BCA Report:

Benefits from Reduced IQ Loss in Children from Lead Exposure via Fish Consumption.

Benefits from Reduced Need for Specialized Education for Children from Lead Exposure via Fish Consumption.

Benefits from Reduced Incidence of Cardiovascular Disease from Lead Exposure via Fish Consumption.

Benefits of Reduced In Utero Mercury Exposure via Maternal Fish Consumption.

Benefits from Reduced Incidence of Cancer from Arsenic Exposure via Fish Consumption.

Benefits from Reduced Incidence of Cardiovascular Disease from Arsenic Exposure via Fish Consumption.

Table XIV-2 summarizes monetized human health benefits from surface water quality improvements. EPA estimates that the final rule will provide human health benefits valued at $16.5 to $17.9 million annually, using a three percent discount rate, and $11.3 to $11.6 million, using a seven percent discount rate. In addition, EPA estimated health benefits associated with changes in air emissions, as discussed in Section XIV.B.4.

Page 67878

TABLE XIV-2--Human Health Benefits From Surface Water Quality

Improvements

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

Benefit category Annualized benefits (million 2013$)

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

3% Discount Rate

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

Benefits from Reduced IQ Loss in $1.0

Children from Lead Exposure via ($0.8 to $1.1)

Fish Consumption \a\.

Benefits from Reduced Need for X, SO2, and CO2. NOX and SOX are known precursors to fine particles (PM2.5), a criteria air pollutant that has been associated with a variety of adverse health effects--most notably, premature mortality, non-fatal heart attacks, hospital admissions, emergency department visits, upper and lower respiratory symptoms, acute bronchitis, aggravated asthma, lost work days, and acute respiratory symptoms. CO2 is a key greenhouse gas that is linked to a wide range of climate change effects.

EPA used average benefit-per-ton estimates to value benefits of changes in NOX and SO2 emissions, and social cost of carbon (SCC) estimates to value benefits of changes in CO2 emissions. The calculations are based on the net changes in air emissions and reflect the net reductions in CO2 and NOX emissions during the entire period of analysis, and the net increase in SO2 emissions in 2023-2027, and net decline in SO2 emissions during the rest of the period. The values are specific to the years 2016, 2020, 2025, and 2030. Because they are almost linear as a function of year, EPA interpolated benefits per ton values for the intermediate years (e.g., between 2020 and 2025) and projected values for the years from 2031 through 2042 by linear regression. While extrapolating introduces some uncertainty, as it does not account for meteorological and air quality changes over time, this approach is a reasonable one, given available information.

Chapter 7 of the BCA Report provides the details of this analysis. As shown in Table XIV-3, EPA estimates that the final rule will provide human health benefits valued at $144.7 million using a three percent discount rate, and $108.8 million using a seven percent discount rate. The rule is expected to provide air-related benefits from changes in CO2 emissions valued at $139.8 million, using a three percent discount rate.

Table XIV-3--Annualized Benefits of Changes in NOX, SO2, and CO2 Air

Emissions

Million 2013$a

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

7 Percent

Benefit category 3 Percent discount rate

discount rate b

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

Human health benefits from reduced $144.7 $108.8

morbidity and mortality from exposure

to NOX, SO2 and particulate matter

(PM2.5)................................

Avoided climate change impacts from CO2 $139.8 $139.8

emissions \b\..........................

Total............................... $284.5 $248.6

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

a Consistent with the assumptions used for the IPM analyses described in

Section IX.C, EPA estimated the benefits relative to a baseline that

includes the CPP rule.

b EPA used the SCC based on a three percent discount rate to estimate

values presented for the seven percent discount rate. EPA uses three

percent to discount CO2-related benefits and seven percent to discount

benefits from changes in NOX and SO2 emissions. See Section 7.1 of the

BCA for details on the methodology.

5. Benefits From Reduced Water Withdrawals (Increased Availability of Ground Water Resources)

Steam electric power plants use water for handling waste (e.g., fly ash, bottom ash) and for operating wet FGD scrubbers. By eliminating or reducing water used in sluicing operations or prompting the recycling of water in FGD wastewater treatment systems, the ELGs are expected to reduce water withdrawals from surface waters and reduce demand on aquifers, in the case of plants that rely on ground water sources.

EPA estimated the benefits of reduced ground water withdrawals based on avoided costs of ground water supply. For each relevant plant, EPA multiplied the reduction in ground water withdrawal (in gallons per year) by water costs of about $1,231 per acre-foot. Chapter 8 of the BCA Report provides the details of this analysis. EPA estimates the annualized benefits of reduced ground water withdrawals are less than $0.1 million annually. Due to data limitations, EPA was not able to monetize the benefits from reduced surface water withdrawals. Chapter 8 of the BCA Report provides additional detail on benefits from reducing surface water withdrawals.

C. Total Monetized Benefits

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

Table XIV-4--Summary of Total Annualized Monetized Benefits of Final

Rule

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

Annualized

monetized

Benefit category benefits (million

2013$)

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

3 Percent Discount Rate

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

Human Health Benefits from Surface Water $16.5 to $17.9

Improvements a d...................................

Page 67881

Improved Ecological Conditions and Recreational Uses $23.3 to $129.5

a b d..............................................

Market and Productivity Benefits (impoundment $126.4 to $133.7

failure and ash marketing).........................

Human Health Benefits from Air Quality Improvements. $144.7

Other Air-Related Benefits (climate change)......... $139.8

Reduced Water Withdrawals........................... 0.010 mg/L for bromate due to increased cancer risk from long-term exposure;

0.060 for HAAs due to increased cancer risk from long-term exposure; and

0.080 mg/L for TTHMs due to increased cancer risk and liver, kidney or central nervous system problems from long-term exposure (see DCN SE01909).

The record indicates that steam electric power plant FGD wastewater discharges occur near more than 100 public drinking water intakes on rivers and other waterbodies, and there is evidence that these discharges are already having adverse effects on the quality of drinking water sources. A 2014 study by McTigue et. al. identified four drinking water treatment plants that experienced increased levels of bromide in their source water, and corresponding increases in the formation of brominated DBPs, after the installation of wet FGD scrubbers at upstream steam electric power plants (see DCN SE04503).

Drinking water utilities are concerned as well, noting that the bromide concentrations have made it increasingly difficult for them to meet SDWA requirements for total trihalomethanes (TTHMs) (see DCN SE01949). And, bromide loadings into surface waters from coal-fired steam electric power plants could potentially increase in the future as more plant operators use bromide addition to improve the control of mercury emissions. The American Water Works Association requested that EPA ``instruct NPDES permit writers to adequately consider downstream drinking water supplies in establishing permit requirements for power plant discharges'' and take other steps to limit adverse consequences for downstream drinking water treatment plants. EPA agrees that permitting authorities should carefully consider whether water quality-

based effluent limitations on bromide or TDS would be appropriate for FGD wastewater discharges from steam electric power plants upstream of drinking water intakes.

Page 67887

EPA regulations at 40 CFR 122.44(d)(1) require that each NPDES permit shall include any requirements, in addition to or more stringent than effluent limitations guidelines or standards promulgated pursuant to sections 301, 304, 306, 307, 318 and 405 of the CWA, necessary to achieve water quality standards established under section 303 of the CWA, including state narrative criteria for water quality. Furthermore, those same regulations require that limitations must control all pollutants, or pollutant parameters (either conventional, nonconventional, or toxic pollutants) which the Director determines are or may be discharged at a level which will cause, have the reasonable potential to cause, or contribute to an excursion above any state water quality standard, including state narrative criteria for water quality.

Where the DBP problem described above may be present, water quality-based effluent limitations for steam electric power plant discharges may be required under the regulations at 40 CFR 122.44(d)(1), where necessary to meet either numeric criteria (e.g., for bromide, TDS or conductivity) or narrative criteria in state water quality standards. All states have narrative water quality criteria that are designed to prevent contamination and other adverse impacts to the states' surface waters. These are often referred to as ``free from'' standards. For example, a state narrative water quality criterion for protecting drinking water sources may require discharges to protect people from adverse exposure to chemicals via drinking water. These narrative criteria may be used to develop water quality-

based effluent limitations on a site-specific basis for the discharge of pollutants that impact drinking water sources, such as bromide.

To translate state narrative water quality criteria and inform the development of a water quality-based limitation for bromide, it may be appropriate for permitting authorities to use EPA's established MCLs for DBPs in drinking water because the presence of bromides in drinking water can result in exceedances of drinking water MCLs as a result of interactions during drinking water treatment and disinfection processes. The limitation would be developed for the purpose of attaining and maintaining the state's applicable narrative water quality criterion or criteria and protecting the state's designated use(s), including the protection of human health. See 40 CFR 122.44(d)(1)(vi).

For the reasons described above, during development of the NPDES permit for the steam electric power plant, the permitting authority should provide notification to any downstream drinking water treatment plants of the discharge of bromide. EPA recommends that the permitting authority collaborate with drinking water utilities and their regulators to determine what concentration of bromides at the PWS intake is needed to ensure that levels of bromate and DPBs do not exceed applicable MCLs. The maximum level of bromide in source waters at the intake that does not result in an exceedance of the MCL for DBPs is the numeric interpretation of the narrative criterion for protection of human health and may vary depending on the treatment processes employed at the drinking water treatment facility. The permitting authority would then determine the level of bromide that may be discharged from the steam electric power plant, taking into account other sources of bromide that may occur, such that the level of bromide downstream at the intake to the drinking water utility is below a level that would result in an exceedances of the applicable MCLs for DBPs. In addition, applicants for NPDES permits must, as part of their permit application, indicate whether they know or have reason to believe that conventional and/or nonconventional pollutants listed in Table IV of Appendix D to 40 CFR part 122, (which includes bromide), are discharged from each outfall. For every pollutant in Table IV of Appendix D discharged which is not limited in an applicable effluent limitations guideline, the applicant must either report quantitative data or briefly describe the reasons the pollutant is expected to be discharged as set forth in 40 CFR 122.2l(g)(7)(vi)(A), made applicable to the States at 40 CFR 123.25(a)(4).

In addition to requiring the permit applicant to provide a complete application, including proper wastewater characterization, when issuing the permit, the permitting authority can incorporate appropriate monitoring and reporting requirements, as authorized under section 402(a)(2), 33 U.S.C. 1342(a)(2), and implementing regulations at 40 CFR 122.48, 122.44(i), 122.43 and 122.41(1)(4). These requirements apply to all dischargers and include plants that have identified the presence of bromide in effluent in significant quantities and that are in proximity to downstream water treatment plants.
Related Acts of Congress, Executive Orders, and Agency Initiatives

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

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

Table XVII-1 (drawn from Table 13-1 of the BCA Report) provides the results of the benefit-cost analysis with both costs and benefits annualized over 24 years and discounted using a three percent discount rate.

Table XVII-1--Total Monetized Annualized Benefits and Costs of the Final

BAT and PSES

Millions, 2013$, three percent discount rate \a\

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

Total social costs Total monetized

\b\ benefits

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

Annualized Value................ $479.5 $450.6 to $565.6

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

\a\ All costs and benefits were annualized over 24 years and using a

three percent discount rate.

\b\ Total social costs include compliance costs to facilities.

B. Paperwork Reduction Act

OMB has previously approved the information collection requirements contained in the existing regulations 40 CFR part 423 under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control number 2040-0281. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9.

Page 67888

EPA estimated small changes in monitoring costs at steam electric power plants for metals in the final rule; EPA accounted for these costs as part of its analysis of the economic impacts. Plants, however, will also realize certain savings by no longer monitoring effluent that would cease to exist under the final rule. The net changes in monitoring and reporting are expected to be minimal, and EPA determined that the existing burden estimates appropriately reflect any final rule burden associated with monitoring.

Based on the information in its record, EPA does not expect the final rule to increase costs to permitting authorities. The rule will not change permit application requirements or the associated review; it will not increase the number of permits issued to steam electric power plants; nor does it increase the efforts involved in developing or reviewing such permits. In fact, the final rule will reduce the burden to permitting authorities. In the absence of nationally applicable BAT requirements, as appropriate, permitting authorities must establish technology-based effluent limitations using BPJ to establish site-

specific requirements based on information submitted by the discharger. Permitting authorities that establish technology-based effluent limitations on a BPJ basis often spend significant time, effort, and resources doing so, and dischargers may expend significant resources providing associated data and information. Establishing nationally applicable BAT requirements that eliminate the need to develop BPJ-

based limitations makes permitting easier and less costly in this respect.

As explained in Section XVI.A, under this rule, after the permitting authority receives information from the discharger, it must determine, on a facility-specific basis, what date is ``as soon as possible'' during the period beginning November 1, 2018, and ending December 31, 2023. This one-time burden to the discharger and the permitting authority, however, is no more excessive than the existing burden associated with developing technology-based effluent limitations on a BPJ basis; in fact, it is very likely less burdensome. Nevertheless, EPA conservatively estimated no net change (increase or decrease) in the cost burden to federal or state governments or dischargers associated with this final rule.

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice-and-comment rulemaking requirements under the Administrative Procedure Act or any other statute, unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities. Small entities include small businesses, small organizations, and small governmental jurisdictions.

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

Table XVII-2--Number of Entities Owning Steam Electric Power Plants by Sector and Size

Assuming two different ownership cases \a\

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

Lower bound estimate of number of Upper bound estimate of number of

entities owning steam electric entities owning steam electric

Ownership type power plants \b\ power plants \b\

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

Total Small \c\ % Small Total Small \c\ % Small

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

Investor-Owned Utilities................ 97 28 28.9 244 66 27.1

Nonutilities............................ 36 19 52.8 77 35 46.1

Cooperatives............................ 29 26 89.7 49 46 93.9

Municipality............................ 65 36 55.4 101 43 42.1

Other Political Subdivision............. 12 1 8.3 30 1 3.3

Federal................................. 0 0 N/A 0 0 N/A

State................................... 2 0 0.0 2 0 0.0

Tribal.................................. 0 0 N/A 0 0 N/A

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

All Entity Types.................... 243 110 45.3 507 191 37.6

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

\a\ In 19 instances, a plant is owned by a joint venture of two entities; in one instance, the plant is owned by

a joint venture of three entities.

\b\ Of these, 75 entities, 21 of which are small, own steam electric power plants that are expected to incur

compliance costs under the final rule under both Case 1 and Case 2.

\c\ EPA was unable to determine size for 16 parent entities; for this analysis, these entities are assumed to be

small.

To assess whether small entities' compliance costs might constitute a significant impact, EPA summed annualized compliance costs for the steam electric power plants determined to be owned by a given small entity and calculated these costs as a percentage of entity revenue (cost-to-revenue test). EPA compared the resulting percentages to impact criteria of one percent and three percent of revenue. Small entities estimated to incur compliance costs exceeding one or more of the one percent and three percent impact thresholds were identified as potentially incurring a significant impact.

EPA notes that setting the BAT limitations for FGD wastewater, fly ash transport water, bottom ash transport water, FGMC wastewater, and gasification wastewater equal to the BPT limitations on TSS in fly ash transport water, bottom ash transport water, and low volume waste sources at existing generating units with a total nameplate generating capacity of 50 MW or less (as discussed in Section VIII.C.12) reduces the potential impacts of the rule on small entities and municipalities. The rulemaking record indicates that establishing a size threshold of 50 MW or less preferentially minimizes some of the expected economic impacts on municipalities and small entities.

Table XVII-3 presents the estimated numbers of small entities incurring costs exceeding one percent and three percent of revenue, by ownership type.

Page 67889

Table XVII-3--Estimated Cost-to-Revenue Impact on Small Entities Owning Steam Electric Power Plants, by Ownership Type

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

Lower bound estimate of number of entities owning Upper bound estimate of number of entities owning

steam electric power plants steam electric power plants

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

Cost >=1% of revenue Cost >=3% of revenue Cost >=1% of revenue Cost >=3% of revenue

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

% of small Number of % of small % of small Number of % of small

Number of affected small affected Number of affected small affected

small entities entities entities small entities entities entities

entities \b\ \a\ \b\ entities \b\ \a\ \b\

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

Ownership Type.................................. Out of total 110 small entities

Out of total 191 small entities

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

Cooperative..................................... 1 3.8 0 0.0 1 2.2 0 0.0

Investor-Owned.................................. 0 0.0 0 0.0 0 0.0 0 0.0

Municipality.................................... 4 11.1 1 2.8 4 9.4 1 2.3

Nonutility...................................... 1 5.3 0 0.0 1 2.8 0 0.0

Other Political Subdivision..................... 0 0.0 0 0.0 0 0.0 0 0.0

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

Total....................................... 6 5.5 1 0.9 6 3.1 1 0.5

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

\a\ The number of entities with cost-to-revenue ratios exceeding three percent is a subset of the number of entities with such ratios exceeding one

percent.

\b\ Percentage values were calculated relative to the total of 110 (Case 1) and 191 (Case 2) small entities owning steam electric power plants. EPA

expects that Case 2 is a more likely ownership scenario for small entities (e.g., small municipalities) as small entities may be less likely to own

multiple non-surveyed steam electric power plants. See RIA Chapter 8 for details.

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

D. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 1531-1538, requires federal agencies, unless otherwise prohibited by law, to assess the effects of their regulatory actions on state, local, and tribal governments and the private sector. This action contains a federal mandate that may result in expenditures of $100 million or more (annually, adjusted for inflation) for state, local, and tribal governments, in the aggregate, or the private sector in any one year ($141 million in 2013). Accordingly, EPA prepared a written statement required under section 202 of UMRA. The statement is included in the docket for this action (see Chapter 9 in the RIA report) and briefly summarized here.

Consistent with the intergovernmental consultation provisions of UMRA section 204, EPA consulted with governmental entities affected by this rule. EPA described the government-to-government dialogue leading to the proposed rule in its preamble to the proposed rulemaking. EPA received comments from state and local government representatives in response to the proposed rule and considered this input in developing the final rule.

Consistent with UMRA section 205, EPA identified and analyzed a reasonable number of regulatory alternatives to determine BAT/BADCT. Section VIII of this preamble describes the options.

This action is not subject to the requirements of UMRA section 203 because it contains no regulatory requirements that might significantly or uniquely affect small governments. For its assessment of the impact of compliance requirements on small governments (governments for populations of less than 50,000), EPA compared total costs and costs per plant estimated to be incurred by small governments with the costs estimated to be incurred by large governments. EPA also compared costs for small government-owned plants with those of non-government-owned facilities. The Agency evaluated both the average and maximum annualized cost per plant. Chapter 9 of the RIA report provides details of these analyses. In all of these comparisons, both for the cost totals and, in particular, for the average and maximum cost per plant, the costs for small government-owned facilities were less than those for large government-owned facilities and for small non-government-

owned facilities. On this basis, EPA concluded that the final rule does not significantly or uniquely affect small governments.

E. Executive Order 13132: Federalism

Under Executive Order (E.O.) 13132, EPA may not issue an action that has federalism implications, that imposes substantial direct compliance costs, and that is not required by statute, unless the federal government provides the funds necessary to pay the direct compliance costs incurred by state and local governments or EPA consults with state and local officials early in the process of developing the action.

This action has federalism implications because it may impose substantial direct compliance costs on state or local governments, and the federal government will not provide the funds necessary to pay those costs.

EPA anticipates that this final rule will not impose incremental administrative burden on states from issuing, reviewing, and overseeing compliance with discharge requirements. However, EPA has identified 168 steam electric power plants owned by state or local government entities, out of which 16 plants are estimated to incur costs to meet the limitations. EPA estimates that the maximum aggregate compliance cost in any one year to governments (excluding the federal government) is $171.4 million (see Chapter 9 of the RIA report for details). Based on this information, this action may impose substantial direct compliance costs on state or local governments. Accordingly, EPA provides the following federalism summary impact statement as required by section 6(b) of E.O. 13132.

Page 67890

EPA consulted with elected state and local officials or their representative national organizations early in the process of developing the rule to ensure their meaningful and timely input into its development. The preamble to the proposed rule described these consultations, which included a briefing on October 11, 2011, attended by representatives from the National League of Cities, the National Conference of State Legislatures, the National Association of Counties, the National Association of Towns and Townships, the U.S. Conference of Mayors, the Council of State Governments, the County Executives of America, and the Environmental Council of the States. Policy and professional groups such as the National Rural Electric Cooperative Association, America's Clean Water Agencies, and the American Public Power Association also participated in the briefing, as did environmental and natural resource policy staff representing nine state agencies and approximately 25 local governments and/or utilities. The participants asked questions and raised comments during the meeting. In response to the Agency's request for pre-proposal written submittals within eight weeks of the briefing, EPA received separate written submittals regarding the technology options, pollutant removal effectiveness, costs of specific technologies and overall costs, impacts on small generating units and on small governments, among others. EPA carefully considered these comments in developing the proposed rule.

EPA received comment on the proposed ELGs from 31 state and local officials or their representatives. Some state and local officials expressed concerns EPA had underestimated the costs and overstated the pollutant removals of the technology options. They stated that the ELGs would impose significant costs on small entities, and would result in electricity rate increases that are unaffordable for households. They also stated that small municipal systems typically operate smaller units with disproportionally greater compliance costs as compared to larger units. Commenters also expressed concern about coordination of the CCR and ELG rules, the potential premature retirement of coal-fired units with limited remaining life, and potential downtime during retrofits. Finally, some commenters asked that EPA allow more time to phase-in the requirements. Other state and local officials supported revisions of the ELGs and generally opposed reliance on BPJ as a basis for establishing limitations for FGD wastewater. EPA considered these comments in developing the final rule. A list of the state and local government commenters has been provided to OMB and has been placed in the docket for this rulemaking. In addition, the detailed response to comments from these entities is contained in EPA's response to comments document on this final rulemaking, which has also been placed in the docket for this rulemaking.

As explained in Section VIII, the final rule establishes different BAT/PSES requirements for oil-fired generating units and units of 50 MW or less. These different requirements alleviate some of the concerns raised by state and local government representatives by reducing the number of government entities incurring costs to meet the ELG requirements. The implementation schedule described in Section XVI gives time to facilities to make changes to their operations to meet the final effluent limitations. Moreover, the rule does not rely on BPJ determinations for establishment of FGD wastewater limitations or standards. Finally, as explained in Section IX, EPA's analysis demonstrates that the requirements are economically achievable for the steam electric industry as a whole, including plants owned by state or local government entities.

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

This action does not have tribal implications, as specified in E.O. 13175 (65 FR 67249, November 9, 2000). It will not have substantial direct effects on tribal governments, on the relationship between the federal government and the Indian tribes, or on the distribution of power and responsibilities between the Federal government and Indian tribes, as specified in E.O. 13175. EPA's analyses show that tribal governments do not own any facility to which the ELGs apply. Thus, E.O. 13175 does not apply to this action.

Although E.O. 13175 does not apply to this action, EPA consulted with federally recognized tribal officials under EPA's Policy on Consultation and Coordination with Indian tribes early in the process of developing this rule to enable them to have meaningful and timely input into its development. EPA initiated consultation and coordination with federally recognized tribal governments in August 2011. EPA shared information about the steam electric effluent guidelines rulemaking in discussions with the National Tribal Caucus and the National Tribal Water Council. EPA continued this government-to-government dialogue by mailing a consultation notification letter to tribal leaders, and on March 28, 2012, held a tribal consultation conference call with tribal representatives about the rulemaking process and objectives, with a focus on identifying specific ways that the rulemaking may affect tribes. Representatives from one tribe provided input to the rule. EPA considered input from tribal representatives in developing this final rule.

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

This action is not subject to E.O. 13045 (62 FR 19885, April 23, 1997) because the EPA does not expect that the environmental health risks or safety risks addressed by this action present a disproportionate risk to children. This action's health and risk assessments are contained in Chapter 3 of the BCA Report and summarized below.

As described in Section XIV.B.1, EPA assessed whether the final rule will benefit children by reducing health risk from exposure to steam electric pollutants from consumption of contaminated fish and improving recreational opportunities. The Agency was able to quantify two categories of benefits specific to children: (1) Avoided neurological damage to preschool age children from reduced exposure to lead and (2) avoided neurological damages from in utero exposure to mercury.

This analysis considered several measures of children's health benefits associated with lead exposure for children up to age six. Avoided neurological and cognitive damages were expressed as changes in three metrics: (1) Overall IQ levels; (2) the incidence of low IQ scores (2/steam stripper wastewater; sulfur recovery unit blowdown, and wastewater resulting from slag handling or fly ash handling, particulate removal, halogen removal, or trace organic removal. Air separation unit blowdown, noncontact cooling water, and runoff from fuel and/or byproduct piles are not considered gasification wastewater. Wastewater that is collected intermittently in floor drains in the gasification process areas from leaks, spills and cleaning occurring during normal operation of the gasification operation is not considered gasification wastewater.

Ground water. Water that is found in the saturated part of the ground underneath the land surface.

IGCC. Integrated gasification combined cycle.

Indirect discharge. Wastewater discharged or otherwise introduced to a POTW.

IPM. Integrated Planning Model.

Landfill. A disposal facility or part of a facility where solid waste, sludges, or other process residuals are placed in or on any natural or manmade formation in the earth for disposal and which is not a storage pile, a land treatment facility, a surface impoundment, an underground injection well, a salt dome or salt bed formation, an underground mine, a cave, or a corrective action management unit.

Low Volume Waste Sources. Taken collectively as if from one source, wastewater from all sources except those for which specific limitations or standards are otherwise established in this part. Low volume waste sources include, but are not limited to, the following: Wastewaters from ion exchange water treatment systems, water treatment evaporator blowdown, laboratory and sampling streams, boiler blowdown, floor drains, cooling tower basin cleaning wastes, recirculating house service water systems, and wet scrubber air pollution control systems whose primary purpose is particulate removal. Sanitary wastes, air conditioning wastes, and wastewater from carbon capture or sequestration systems are not included in this definition.

MDS. Mechanical drag system.

Mechanical drag system. Bottom ash handling system that collects bottom ash from the bottom of the boiler in a water-filled trough. The water bath in the trough quenches the hot bottom ash as it falls from the boiler and seals the boiler gases. A drag chain operates in a continuous loop to drag bottom ash from the water trough up an incline, which dewaters the bottom ash by gravity, draining the water back to the trough as the bottom ash moves upward. The dewatered bottom ash is often conveyed to a nearby collection area, such as a small bunker outside the boiler building, from which it is loaded onto trucks and either sold or transported to a landfill. The MDS is considered a dry bottom ash handling system because the ash transport mechanism is mechanical removal by the drag chain, not the water.

Metal cleaning wastes. Any wastewater resulting from cleaning with or without chemical cleaning compounds any metal process equipment including, but not limited to, boiler tube cleaning, boiler fireside cleaning, and air preheater cleaning.

Mortality. Death rate or proportion of deaths in a population.

NAICS. North American Industry Classification System.

NPDES. National Pollutant Discharge Elimination System.

NSPS. New Source Performance Standards.

Oil-fired unit. A generating unit that uses oil as the primary or secondary fuel source and does not use a gasification process or any coal or petroleum coke as a fuel source. This definition does not include units that use oil only for start up or flame-

stabilization purposes.

ORCR. Office of Resource Conservation and Recovery.

Point source. Any discernable, confined, and discrete conveyance, including but not limited to, any pipe, ditch, channel, tunnel, conduit, well, discrete fissure, container, rolling stock, concentrated animal feeding operation, or vessel or other floating craft from which pollutants are or may be discharged. The term does not include agricultural stormwater discharges or return flows from irrigated agriculture. See CWA section 502(14), 33 U.S.C. 1362(14); 40 CFR 122.2.

POTW. Publicly owned treatment works. See CWA section 212, 33 U.S.C. 1292; 40 CFR 122.2, 403.3

Primary particulate collection system. The first place in the process where fly ash is collected, such as collection at an ESP or

Page 67893

baghouse. For example, a coal combustion particulate collection system may include multiple steps including a primary particulate collection step such as ESP followed by other processes such as a fabric filter which would constitute a secondary particulate collection system.

PSES. Pretreatment Standards for Existing Sources.

PSNS. Pretreatment Standards for New Sources.

Publicly Owned Treatment Works. Any device or system, owned by a state or municipality, used in the treatment (including recycling and reclamation) of municipal sewage or industrial wastes of a liquid nature that is owned by a state or municipality. This includes sewers, pipes, or other conveyances only if they convey wastewater to a POTW providing treatment. See CWA section 212, 33 U.S.C. 1292; 40 CFR 122.2, 403.3.

RCRA. The Resource Conservation and Recovery Act of 1976, 42 U.S.C. 6901 et seq.

Remote MDS. Bottom ash handling system that collects bottom ash at the bottom of the boiler, then uses transport water to sluice the ash to a remote MDS that dewaters bottom ash using a similar configuration as the MDS. The remote MDS is considered a wet bottom ash handling system because the ash transport mechanism is water.

RFA. Regulatory Flexibility Act.

SBA. Small Business Administration.

Sediment. Particulate matter lying below water.

Steam electric power plant wastewater. Wastewaters associated with or resulting from the combustion process, including ash transport water from coal-, petroleum coke-, or oil-fired units; air pollution control wastewater (e.g., FGD wastewater, FGMC wastewater, carbon capture wastewater); and leachate from landfills or surface impoundments containing combustion residuals.

Surface water. All waters of the United States, including rivers, streams, lakes, reservoirs, and seas.

Toxic pollutants. As identified under the CWA, 65 pollutants and classes of pollutants, of which 126 specific substances have been designated priority toxic pollutants. See appendix A to 40 CFR part 423.

Transport water. Wastewater that is used to convey fly ash, bottom ash, or economizer ash from the ash collection or storage equipment, or boiler, and has direct contact with the ash. Transport water does not include low volume, short duration discharges of wastewater from minor leaks (e.g., leaks from valve packing, pipe flanges, or piping) or minor maintenance events (e.g., replacement of valves or pipe sections).

UMRA. Unfunded Mandates Reform Act.

Wet bottom ash handling system. A system in which bottom ash is conveyed away from the boiler using water as a transport medium. Wet bottom ash systems typically send the ash slurry to dewatering bins or a surface impoundment. Wet bottom ash handling systems include systems that operate in conjunction with a traditional wet sluicing system to recycle all bottom ash transport water (remote MDS or complete recycle system).

Wet FGD system. Wet FGD systems capture sulfur dioxide from the flue gas using a sorbent that has mixed with water to form a wet slurry, and that generates a water stream that exits the FGD scrubber absorber.

Wet fly ash handling system. A system that conveys fly ash away from particulate removal equipment using water as a transport medium. Wet fly ash systems typically dispose of the ash slurry in a surface impoundment.

List of Subjects in 40 CFR Part 423

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

Dated: September 30, 2015.

Gina McCarthy,

Administrator.

Therefore, 40 CFR Chapter I is amended as follows:

PART 423--STEAM ELECTRIC POWER GENERATING POINT SOURCE CATEGORY

0

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

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

0

2. Section 423.10 is revised as follows:

Sec. 423.10 Applicability.

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

0

3. Section 423.11 is amended by:

0

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

0

b. Adding paragraphs (n) through (t).

The revisions and additions read as follows:

Sec. 423.11 Specialized definitions.

* * * * *

(b) The term low volume waste sources means, taken collectively as if from one source, wastewater from all sources except those for which specific limitations or standards are otherwise established in this part. Low volume waste sources include, but are not limited to, the following: Wastewaters from ion exchange water treatment systems, water treatment evaporator blowdown, laboratory and sampling streams, boiler blowdown, floor drains, cooling tower basin cleaning wastes, recirculating house service water systems, and wet scrubber air pollution control systems whose primary purpose is particulate removal. Sanitary wastes, air conditioning wastes, and wastewater from carbon capture or sequestration systems are not included in this definition.

* * * * *

(e) The term fly ash means the ash that is carried out of the furnace by a gas stream and collected by a capture device such as a mechanical precipitator, electrostatic precipitator, or fabric filter. Economizer ash is included in this definition when it is collected with fly ash. Ash is not included in this definition when it is collected in wet scrubber air pollution control systems whose primary purpose is particulate removal.

(f) The term bottom ash means the ash, including boiler slag, which settles in the furnace or is dislodged from furnace walls. Economizer ash is included in this definition when it is collected with bottom ash.

* * * * *

(n) The term flue gas desulfurization (FGD) wastewater means any wastewater generated specifically from the wet flue gas desulfurization scrubber system that comes into contact with the flue gas or the FGD solids, including but not limited to, the blowdown from the FGD scrubber system, overflow or underflow from the solids separation process, FGD solids wash water, and the filtrate from the solids dewatering process. Wastewater generated from cleaning the FGD scrubber, cleaning FGD solids separation equipment, cleaning FGD solids dewatering equipment, or that is collected in floor drains in the FGD process area is not considered FGD wastewater.

(o) The term flue gas mercury control wastewater means any wastewater generated from an air pollution control system installed or operated for the purpose of removing mercury from flue gas. This includes fly ash collection systems when the particulate control system follows sorbent injection or other controls to remove mercury from flue gas. FGD wastewater generated at plants using oxidizing agents to remove mercury in the FGD system and not in a separate FGMC system is not included in this definition.

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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 dissolved constituents in the liquid, that has percolated through waste or other materials emplaced in a landfill, or that passes through the surface impoundment's containment structure (e.g., bottom, dikes, berms). Combustion residual leachate includes seepage and/or leakage from a combustion residual landfill or impoundment unit. Combustion residual leachate includes wastewater from landfills and surface impoundments located on non-adjoining property when under the operational control of the permitted facility.

(s) The term oil-fired unit means a generating unit that uses oil as the primary or secondary fuel source and does not use a gasification process or any coal or petroleum coke as a fuel source. This definition does not include units that use oil only for start up or flame-

stabilization purposes.

(t) The phrase ``as soon as possible'' means November 1, 2018, unless the permitting authority establishes a later date, after receiving information from the discharger, which reflects a consideration of the following factors:

(1) Time to expeditiously plan (including to raise capital), design, procure, and install equipment to comply with the requirements of this part.

(2) Changes being made or planned at the plant in response to:

(i) New source performance standards for greenhouse gases from new fossil fuel-fired electric generating units, under sections 111, 301, 302, and 307(d)(1)(C) of the Clean Air Act, as amended, 42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C);

(ii) Emission guidelines for greenhouse gases from existing fossil fuel-fired electric generating units, under sections 111, 301, 302, and 307(d) of the Clean Air Act, as amended, 42 U.S.C. 7411, 7601, 7602, 7607(d); or

(iii) Regulations that address the disposal of coal combustion residuals as solid waste, under sections 1006(b), 1008(a), 2002(a), 3001, 4004, and 4005(a) of the Solid Waste Disposal Act of 1970, as amended by the Resource Conservation and Recovery Act of 1976, as amended by the Hazardous and Solid Waste Amendments of 1984, 42 U.S.C. 6906(b), 6907(a), 6912(a), 6944, and 6945(a).

(3) For FGD wastewater requirements only, an initial commissioning period for the treatment system to optimize the installed equipment.

0

(4) Other factors as appropriate.

0

4. Section 423.12 is amended by:

0

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

0

b. Adding paragraph (b)(13).

The revisions and addition read as follows:

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

* * * * *

(b) * * *

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

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

BPT Effluent limitations

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day (mg/ consecutive days

l) shall not exceed

(mg/l)

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

TSS................................. 100.0 30.0

Oil and grease...................... 20.0 15.0

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

(12) At the permitting authority's discretion, the quantity of pollutant allowed to be discharged may be expressed as a concentration limitation instead of the mass-based limitations specified in paragraphs (b)(3) through (b)(7), and (b)(11), of this section. Concentration limitations shall be those concentrations specified in this section.

(13) In the event that wastestreams from various sources are combined for treatment or discharge, the quantity of each pollutant or pollutant property controlled in paragraphs (b)(1) through (b)(12) of this section attributable to each controlled waste source shall not exceed the specified limitations for that waste source.

0

5. Section 423.13 is amended by:

0

a. Revising paragraphs (g) and (h).

0

b. Adding paragraphs (i) through (n).

The revisions and additions read as follows:

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

* * * * *

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

Page 67895

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

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

BAT Effluent limitations

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day consecutive days

shall not exceed

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

Arsenic, total (ug/L)............... 11 8

Mercury, total (ng/L)............... 788 356

Selenium, total (ug/L).............. 23 12

Nitrate/nitrite as N (mg/L)......... 17.0 4.4

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

(ii) For FGD wastewater generated before the date determined by the permitting authority, as specified in paragraph (g)(1)(i), the quantity of pollutants discharged in FGD wastewater shall not exceed the quantity determined by multiplying the flow of FGD wastewater times the concentration listed for TSS in Sec. 423.12(b)(11).

(2) For any electric generating unit with a total nameplate capacity of less than or equal to 50 megawatts or that is an oil-fired unit, the quantity of pollutants discharged in FGD wastewater shall not exceed the quantity determined by multiplying the flow of FGD wastewater times the concentration listed for TSS in Sec. 423.12(b)(11).

(3)(i) For dischargers who voluntarily choose to meet the effluent limitations for FGD wastewater in this paragraph, the quantity of pollutants in FGD wastewater shall not exceed the quantity determined by multiplying the flow of FGD wastewater times the concentration listed in the table following this paragraph (g)(3)(i). Dischargers who choose to meet the effluent limitations for FGD wastewater in this paragraph must meet such limitations by December 31, 2023. These effluent limitations apply to the discharge of FGD wastewater generated on and after December 31, 2023.

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

BAT Effluent limitations

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day consecutive days

shall not exceed

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

Arsenic, total (ug/L)............... 4 ..................

Mercury, total (ng/L)............... 39 24

Selenium, total (ug/L).............. 5 ..................

TDS (mg/L).......................... 50 24

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

(ii) For discharges of FGD wastewater generated before December 31, 2023, the quantity of pollutants discharged in FGD wastewater shall not exceed the quantity determined by multiplying the flow of FGD wastewater times the concentration listed for TSS in Sec. 423.12(b)(11).

(h)(1)(i) Fly ash transport water. Except for those discharges to which paragraph (h)(2) of this section applies, or when the fly ash transport water is used in the FGD scrubber, there shall be no discharge of pollutants in fly ash transport water. Dischargers must meet the discharge limitation in this paragraph by a date determined by the permitting authority that is as soon as possible beginning November 1, 2018, but no later than December 31, 2023. This limitation applies to the discharge of fly ash transport water generated on and after the date determined by the permitting authority for meeting the discharge limitation, as specified in this paragraph. Whenever fly ash transport water is used in any other plant process or is sent to a treatment system at the plant (except when it is used in the FGD scrubber), the resulting effluent must comply with the discharge limitation in this paragraph. When the fly ash transport water is used in the FGD scrubber, the quantity of pollutants in fly ash transport water shall not exceed the quantity determined by multiplying the flow of fly ash transport water times the concentration listed in the table in paragraph (g)(1)(i) of this section.

(ii) For discharges of fly ash transport water generated before the date determined by the permitting authority, as specified in paragraph (h)(1)(i) of this section, the quantity of pollutants discharged in fly ash transport water shall not exceed the quantity determined by multiplying the flow of fly ash transport water times the concentration listed for TSS in Sec. 423.12(b)(4).

(2) For any electric generating unit with a total nameplate generating capacity of less than or equal to 50 megawatts or that is an oil-fired unit, the quantity of pollutants discharged in fly ash transport water shall not exceed the quantity determined by multiplying the flow of fly ash transport water times the concentration listed for TSS in Sec. 423.12(b)(4).

(i)(1)(i) Flue gas mercury control wastewater. Except for those discharges to which paragraph (i)(2) of this section applies, there shall be no discharge of pollutants in flue gas mercury control wastewater. Dischargers must meet the discharge limitation in this paragraph by a date determined by the permitting authority that is as soon as possible beginning November 1, 2018, but no later than December 31, 2023. This limitation applies to the discharge of flue gas mercury control wastewater generated on and after the date determined by the permitting authority for meeting the discharge limitation, as specified in this paragraph. Whenever flue gas mercury control wastewater is

Page 67896

used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge limitation in this paragraph.

(ii) For discharges of flue gas mercury control wastewater generated before the date determined by the permitting authority, as specified in paragraph (i)(1)(i) of this section, the quantity of pollutants discharged in flue gas mercury control wastewater shall not exceed the quantity determined by multiplying the flow of flue gas mercury control wastewater times the concentration for TSS listed in Sec. 423.12(b)(11).

(2) For any electric generating unit with a total nameplate generating capacity of less than or equal to 50 megawatts or that is an oil-fired unit, the quantity of pollutants discharged in flue gas mercury control wastewater shall not exceed the quantity determined by multiplying the flow of flue gas mercury control wastewater times the concentration for TSS listed in Sec. 423.12(b)(11).

(j)(1)(i) Gasification wastewater. Except for those discharges to which paragraph (j)(2) of this section applies, the quantity of pollutants in gasification wastewater shall not exceed the quantity determined by multiplying the flow of gasification wastewater times the concentration listed in the table following this paragraph (j)(1)(i). Dischargers must meet the effluent limitations in this paragraph by a date determined by the permitting authority that is as soon as possible beginning November 1, 2018, but no later than December 31, 2023. These effluent limitations apply to the discharge of gasification wastewater generated on and after the date determined by the permitting authority for meeting the effluent limitations, as specified in this paragraph.

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

BAT Effluent limitations

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day consecutive days

shall not exceed

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

Arsenic, total (ug/L)............... 4 ..................

Mercury, total (ng/L)............... 1.8 1.3

Selenium, total (ug/L).............. 453 227

Total dissolved solids (mg/L)....... 38 22

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

(ii) For discharges of gasification wastewater generated before the date determined by the permitting authority, as specified in paragraph (j)(1)(i) of this section, the quantity of pollutants discharged in gasification wastewater shall not exceed the quantity determined by multiplying the flow of gasification wastewater times the concentration for TSS listed in Sec. 423.12(b)(11).

(2) For any electric generating unit with a total nameplate generating capacity of less than or equal to 50 megawatts or that is an oil-fired unit, the quantity of pollutants discharged in gasification wastewater shall not exceed the quantity determined by multiplying the flow of gasification wastewater times the concentration listed for TSS in Sec. 423.12(b)(11).

(k)(1)(i) Bottom ash transport water. Except for those discharges to which paragraph (k)(2) of this section applies, or when the bottom ash transport water is used in the FGD scrubber, there shall be no discharge of pollutants in bottom ash transport water. Dischargers must meet the discharge limitation in this paragraph by a date determined by the permitting authority that is as soon as possible beginning November 1, 2018, but no later than December 31, 2023. This limitation applies to the discharge of bottom ash transport water generated on and after the date determined by the permitting authority for meeting the discharge limitation, as specified in this paragraph. Whenever bottom ash transport water is used in any other plant process or is sent to a treatment system at the plant (except when it is used in the FGD scrubber), the resulting effluent must comply with the discharge limitation in this paragraph. When the bottom ash transport water is used in the FGD scrubber, the quantity of pollutants in bottom ash transport water shall not exceed the quantity determined by multiplying the flow of bottom ash transport water times the concentration listed in the table in paragraph (g)(1)(i) of this section.

(ii) For discharges of bottom ash transport water generated before the date determined by the permitting authority, as specified in paragraph (k)(1)(i) of this section, the quantity of pollutants discharged in bottom ash transport water shall not exceed the quantity determined by multiplying the flow of bottom ash transport water times the concentration for TSS listed in Sec. 423.12(b)(4).

(2) For any electric generating unit with a total nameplate generating capacity of less than or equal to 50 megawatts or that is an oil-fired unit, the quantity of pollutants discharged in bottom ash transport water shall not exceed the quantity determined by multiplying the flow of the applicable wastewater times the concentration for TSS listed in Sec. 423.12(b)(4).

(l) Combustion residual leachate. The quantity of pollutants discharged in combustion residual leachate shall not exceed the quantity determined by multiplying the flow of combustion residual leachate times the concentration for TSS listed in Sec. 423.12(b)(11).

(m) At the permitting authority's discretion, the quantity of pollutant allowed to be discharged may be expressed as a concentration limitation instead of any mass based limitations specified in paragraphs (b) through (l) of this section. Concentration limitations shall be those concentrations specified in this section.

(n) In the event that wastestreams from various sources are combined for treatment or discharge, the quantity of each pollutant or pollutant property controlled in paragraphs (a) through (m) of this section attributable to each controlled waste source shall not exceed the specified limitation for that waste source.

0

6. Section 423.15 is revised to read as follows:

Sec. 423.15 New source performance standards (NSPS).

(a) 1982 NSPS. Any new source as of November 19, 1982, subject to paragraph (a) of this section, must achieve the following new source performance standards, in addition to the limitations in Sec. 423.13 of this part, established on November 3, 2015. In the case of conflict, the more stringent requirements apply:

(1) pH. The pH of all discharges, except once through cooling water, shall be within the range of 6.0-9.0.

Page 67897

(2) PCBs. There shall be no discharge of polychlorinated biphenyl compounds such as those commonly used for transformer fluid.

(3) Low volume waste sources, FGD wastewater, flue gas mercury control wastewater, combustion residual leachate, and gasification wastewater. The quantity of pollutants discharged in low volume waste sources, FGD wastewater, flue gas mercury control wastewater, combustion residual leachate, and gasification wastewater shall not exceed the quantity determined by multiplying the flow of low volume waste sources times the concentration listed in the following table:

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

NSPS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day (mg/ consecutive days

l) shall not exceed

(mg/l)

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

TSS................................. 100.0 30.0

Oil and grease...................... 20.0 15.0

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

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

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

NSPS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day (mg/ consecutive days

l) shall not exceed

(mg/l)

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

TSS................................. 100.0 30.0

Oil and grease...................... 20.0 15.0

Copper, total....................... 1.0 1.0

Iron, total......................... 1.0 1.0

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

(5) Reserved

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

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

NSPS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day (mg/ consecutive days

l) shall not exceed

(mg/l)

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

TSS................................. 100.0 30.0

Oil and grease...................... 20.0 15.0

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

(7) Fly ash transport water. There shall be no discharge of pollutants in fly ash transport water.

(8)(i) Once through cooling water. For any plant with a total rated electric generating capacity of 25 or more megawatts, the quantity of pollutants discharged in once through cooling water from each discharge point shall not exceed the quantity determined by multiplying the flow of once through cooling water from each discharge point times the concentration listed in the following table:

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

NSPS

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

Pollutant or pollutant property Maximum concentrations (mg/

l)

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

Total residual chlorine.................. 0.20

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

(ii) Total residual chlorine may only be discharged from any single generating unit for more than two hours per day when the discharger demonstrates to the permitting authority that discharge for more than two hours is required for macroinvertebrate control. Simultaneous multi-unit chlorination is permitted.

(9)(i) Once through cooling water. For any plant with a total rated generating capacity of less than 25 megawatts, the quantity of pollutants discharged in once through cooling water shall not exceed the quantity determined by multiplying the flow of once through cooling water sources times the

Page 67898

concentration listed in the following table:

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

NSPS

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

Pollutant or pollutant property Maximum concentration (mg/ Average concentration (mg/

l) l)

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

Free available chlorine................................. 0.5 0.2

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

(ii) Neither free available chlorine nor total residual chlorine may be discharged from any unit for more than two hours in any one day and not more than one unit in any plant may discharge free available or total residual chlorine at any one time unless the utility can demonstrate to the Regional Administrator or state, if the state has NPDES permit issuing authority, that the units in a particular location cannot operate at or below this level of chlorination.

(10)(i) Cooling tower blowdown. The quantity of pollutants discharged in cooling tower blowdown shall not exceed the quantity determined by multiplying the flow of cooling tower blowdown times the concentration listed below:

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

NSPS

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

Pollutant or pollutant property Maximum concentration (mg/ Average concentration (mg/

l) l)

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

Free available chlorine................................. 0.5 0.2

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

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

NSPS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day (mg/ consecutive days

l) shall not exceed

(mg/l)

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

The 126 priority pollutants (\1\) (\1\)

(appendix A) contained in chemicals

added for cooling tower

maintenance, except:...............

Chromium, total................. 0.2 0.2

zinc, total..................... 1.0 1.0

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

\1\ No detectable amount.

(ii) Neither free available chlorine nor total residual chlorine may be discharged from any unit for more than two hours in any one day and not more than one unit in any plant may discharge free available or total residual chlorine at any one time unless the utility can demonstrate to the Regional Administrator or state, if the state has NPDES permit issuing authority, that the units in a particular location cannot operate at or below this level of chlorination.

(iii) At the permitting authority's discretion, instead of the monitoring in 40 CFR 122.11(b), compliance with the standards for the 126 priority pollutants in paragraph (a)(10)(i) of this section may be determined by engineering calculations which demonstrate that the regulated pollutants are not detectable in the final discharge by the analytical methods in 40 CFR part 136.

(11) Coal pile runoff. Subject to the provisions of paragraph (a)(12) of this section, the quantity or quality of pollutants or pollutant parameters discharged in coal pile runoff shall not exceed the standards specified below:

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

Pollutant or pollutant property NSPS for any time

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

TSS....................................... not to exceed 50 mg/l.

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

(12) Coal pile runoff. Any untreated overflow from facilities designed, constructed, and operated to treat the coal pile runoff which results from a 10 year, 24 hour rainfall event shall not be subject to the standards in paragraph (a)(11) of this section.

(13) At the permitting authority's discretion, the quantity of pollutant allowed to be discharged may be expressed as a concentration limitation instead of any mass based limitations specified in paragraphs (a)(3) through (10) of this section. Concentration limits shall be based on the concentrations specified in this section.

(14) In the event that wastestreams from various sources are combined for treatment or discharge, the quantity of each pollutant or pollutant property controlled in paragraphs (a)(1) through (13) of this section attributable to each controlled waste source shall not exceed the specified limitation for that waste source.

(b) 2015 NSPS. Any new source as of November 17, 2015, subject to paragraph (b) of this section, must achieve the following new source performance standards:

(1) pH. The pH of all discharges, except once through cooling water, shall be within the range of 6.0-9.0.

(2) PCBs. There shall be no discharge of polychlorinated biphenyl compounds such as those commonly used for transformer fluid.

(3) Low volume waste sources. The quantity of pollutants discharged from low volume waste sources shall not exceed the quantity determined by multiplying the flow of low volume waste sources times the concentration listed in the following table:

Page 67899

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

NSPS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day (mg/ consecutive days

l) shall not exceed

(mg/l)

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

TSS................................. 100.0 30.0

Oil and grease...................... 20.0 15.0

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

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

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

NSPS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day (mg/ consecutive days

l) shall not exceed

(mg/l)

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

TSS................................. 100.0 30.0

Oil and grease...................... 20.0 15.0

Copper, total....................... 1.0 1.0

Iron, total......................... 1.0 1.0

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

(5) Reserved

(6) Bottom ash transport water. There shall be no discharge of pollutants in bottom ash transport water. Whenever bottom ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge standard in this paragraph.

(7) Fly ash transport water. There shall be no discharge of pollutants in fly ash transport water. Whenever fly ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge standard in this paragraph.

(8)(i) Once through cooling water. For any plant with a total rated electric generating capacity of 25 or more megawatts, the quantity of pollutants discharged in once through cooling water from each discharge point shall not exceed the quantity determined by multiplying the flow of once through cooling water from each discharge point times the concentration listed in the following table:

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

NSPS

Pollutant or pollutant property ------------------------------

Maximum concentration (mg/l)

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

Total residual chlorine.................. 0.20

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

(ii) Total residual chlorine may only be discharged from any single generating unit for more than two hours per day when the discharger demonstrates to the permitting authority that discharge for more than two hours is required for macroinvertebrate control. Simultaneous multi-unit chlorination is permitted.

(9)(i) Once through cooling water. For any plant with a total rated generating capacity of less than 25 megawatts, the quantity of pollutants discharged in once through cooling water shall not exceed the quantity determined by multiplying the flow of once through cooling water sources times the concentration listed in the following table:

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

NSPS

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

Pollutant or pollutant property Maximum concentration (mg/ Average concentration (mg/

l) l)

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

Free available chlorine................................. 0.5 0.2

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

(ii) Neither free available chlorine nor total residual chlorine may be discharged from any unit for more than two hours in any one day and not more than one unit in any plant may discharge free available or total residual chlorine at any one time unless the utility can demonstrate to the Regional Administrator or state, if the state has NPDES permit issuing authority, that the units in a particular location cannot operate at or below this level of chlorination.

(10)(i) Cooling tower blowdown. The quantity of pollutants discharged in cooling tower blowdown shall not exceed the quantity determined by multiplying the flow of cooling tower blowdown times the concentration listed below:

Page 67900

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

NSPS

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

Pollutant or pollutant property Maximum concentration (mg/ Average concentration (mg/

l) l)

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

Free available chlorine................................. 0.5 0.2

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

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

NSPS

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

Pollutant or pollutant property Average of daily values

Maximum for any 1 day (mg/ for 30 consecutive days

l) shall not exceed (mg/l)

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

The 126 priority pollutants (appendix A) contained in (\1\) (\1\)

chemicals added for cooling tower maintenance, except:.

Chromium, total..................................... 0.2 0.2

zinc, total......................................... 1.0 1.0

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

\1\ No detectable amount.

(ii) Neither free available chlorine nor total residual chlorine may be discharged from any unit for more than two hours in any one day and not more than one unit in any plant may discharge free available or total residual chlorine at any one time unless the utility can demonstrate to the Regional Administrator or state, if the state has NPDES permit issuing authority, that the units in a particular location cannot operate at or below this level of chlorination.

(iii) At the permitting authority's discretion, instead of the monitoring in 40 CFR 122.11(b), compliance with the standards for the 126 priority pollutants in paragraph (b)(10)(i) of this section may be determined by engineering calculations demonstrating that the regulated pollutants are not detectable in the final discharge by the analytical methods in 40 CFR part 136.

(11) Coal pile runoff. Subject to the provisions of paragraph (b)(12) of this section, the quantity or quality of pollutants or pollutant parameters discharged in coal pile runoff shall not exceed the standards specified below:

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

Pollutant or pollutant property NSPS for any time

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

TSS....................................... not to exceed 50 mg/l.

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

(12) Coal pile runoff. Any untreated overflow from facilities designed, constructed, and operated to treat the coal pile runoff which results from a 10 year, 24 hour rainfall event shall not be subject to the standards in paragraph (b)(11) of this section.

(13) FGD wastewater. The quantity of pollutants discharged in FGD wastewater shall not exceed the quantity determined by multiplying the flow of FGD wastewater times the concentration listed in the following table:

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

NSPS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day consecutive days

shall not exceed

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

Arsenic, total (ug/L)............... 4 ..................

Mercury, total (ng/L)............... 39 24

Selenium, total (ug/L).............. 5 ..................

TDS (mg/L).......................... 50 24

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

(14) Flue gas mercury control wastewater. There shall be no discharge of pollutants in flue gas mercury control wastewater. Whenever flue gas mercury control wastewater is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge standard in this paragraph.

(15) Gasification wastewater. The quantity of pollutants discharged in gasification wastewater shall not exceed the quantity determined by multiplying the flow of gasification wastewater times the concentration listed in the following table:

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

NSPS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day consecutive days

shall not exceed

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

Arsenic, total (ug/L)............... 4 ..................

Mercury, total (ng/L)............... 1.8 1.3

Selenium, total (ug/L).............. 453 227

Total dissolved solids (mg/L)....... 38 22

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

Page 67901

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

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

NSPS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day consecutive days

shall not exceed

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

Arsenic, total (ug/L)............... 11 8

Mercury, total (ng/L)............... 788 356

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

(17) At the permitting authority's discretion, the quantity of pollutant allowed to be discharged may be expressed as a concentration limitation instead of any mass based limitations specified in paragraphs (b)(3) through (16) of this section. Concentration limits shall be based on the concentrations specified in this section.

(18) In the event that wastestreams from various sources are combined for treatment or discharge, the quantity of each pollutant or pollutant property controlled in paragraphs (b)(1) through (16) of this section attributable to each controlled waste source shall not exceed the specified limitation for that waste source.

(The information collection requirements contained in paragraphs (a)(8)(ii), (a)(9)(ii), and (a)(10)(ii), (b)(8)(ii), (b)(9)(ii), and (b)(10)(ii) were approved by the Office of Management and Budget under control number 2040-0040. The information collection requirements contained in paragraphs (a)(10)(iii) and (b)(10)(iii) were approved under control number 2040-0033.)

0

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

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

* * * * *

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

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

PSES

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day consecutive days

shall not exceed

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

Arsenic, total (ug/L)............... 11 8

Mercury, total (ng/L)............... 788 356

Selenium, total (ug/L).............. 23 12

Nitrate/nitrite as N (mg/L)......... 17.0 4.4

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

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

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

(h) Flue gas mercury control wastewater. For any electric generating unit with a total nameplate generating capacity of more than 50 megawatts and that is not an oil-fired unit, there shall be no discharge of pollutants in flue gas mercury control wastewater. This standard applies to the discharge of flue gas mercury control wastewater generated on and after November 1, 2018. Whenever flue gas mercury control wastewater is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge standard in this paragraph.

(i) Gasification wastewater. For any electric generating unit with a total nameplate generating capacity of more than 50 megawatts and that is not an oil-fired unit, the quantity of pollutants in gasification wastewater shall not exceed

Page 67902

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

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

PSES

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day consecutive days

shall not exceed

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

Arsenic, total (mug/L)............ 4 ..................

Mercury, total (ng/L)............... 1.8 1.3

Selenium, total (mug/L)........... 453 227

Total dissolved solids (mg/L)....... 38 22

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

0

8. Section 423.17 is revised to read as follows:

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

(a) 1982 PSNS. Except as provided in 40 CFR 403.7, any new source as of October 14, 1980, subject to paragraph (a) of this section, which introduces pollutants into a publicly owned treatment works, must comply with 40 CFR part 403, the following pretreatment standards for new sources, and the PSES in Sec. 423.16, established on November 3, 2015. In the case of conflict, the more stringent standards apply:

(1) PCBs. There shall be no discharge of polychlorinated biphenyl compounds such as those used for transformer fluid.

(2) Chemical metal cleaning wastes. The pollutants discharged in chemical metal cleaning wastes shall not exceed the concentration listed in the following table:

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

PSNS

Pollutant or pollutant property ------------------------------

Maximum for any 1 day (mg/L)

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

Copper, total............................ 1.0

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

(3) Reserved

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

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

PSNS

Pollutant or pollutant property ------------------------------

Maximum for any time (mg/L)

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

The 126 priority pollutants (appendix A) (\1\)

contained in chemicals added for cooling

tower maintenance, except:..............

Chromium, total...................... 0.2

zinc, total.......................... 1.0

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

\1\ No detectable amount.

(ii) At the permitting authority's discretion, instead of the monitoring in 40 CFR 122.11(b), compliance with the standards for the 126 priority pollutants in paragraph (a)(4)(i) of this section may be determined by engineering calculations which demonstrate that the regulated pollutants are not detectable in the final discharge by the analytical methods in 40 CFR part 136.

(5) Fly ash transport water. There shall be no discharge of wastewater pollutants from fly ash transport water.

(b) 2015 PSNS. Except as provided in 40 CFR 403.7, any new source as of June 7, 2013, subject to this paragraph (b), which introduces pollutants into a publicly owned treatment works must comply with 40 CFR part 403 and the following pretreatment standards for new sources:

(1) PCBs. There shall be no discharge of polychlorinated biphenyl compounds such as those used for transformer fluid.

(2) Chemical metal cleaning wastes. The pollutants discharged in chemical metal cleaning wastes shall not exceed the concentration listed in the following table:

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

PSNS

Pollutant or pollutant property ------------------------------

Maximum for 1 day (mg/L)

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

Copper, total............................ 1.0

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

(3) Reserved

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

Page 67903

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

PSNS

Pollutant or pollutant property ------------------------------

Maximum for any time (mg/L)

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

The 126 priority pollutants (appendix A) (\1\)

contained in chemicals added for cooling

tower maintenance, except:..............

Chromium, total...................... 0.2

zinc, total.......................... 1.0

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

\1\ No detectable amount.

(ii) At the permitting authority's discretion, instead of the monitoring in 40 CFR 122.11(b), compliance with the standards for the 126 priority pollutants in paragraph (b)(4)(i) of this section may be determined by engineering calculations which demonstrate that the regulated pollutants are not detectable in the final discharge by the analytical methods in 40 CFR part 136.

(5) Fly ash transport water. There shall be no discharge of pollutants in fly ash transport water. Whenever fly ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge standard in this paragraph.

(6) FGD wastewater. The quantity of pollutants discharged in FGD wastewater shall not exceed the quantity determined by multiplying the flow of FGD wastewater times the concentration listed in the following table:

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

PSNS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day consecutive days

shall not exceed

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

Arsenic, total (mug/L)............ 4 ..................

Mercury, total (ng/L)............... 39 24

Selenium, total (mug/L)........... 5 ..................

TDS (mg/L).......................... 50 24

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

(7) Flue gas mercury control wastewater. There shall be no discharge of pollutants in flue gas mercury control wastewater. Whenever flue gas mercury control wastewater is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge standard in this paragraph.

(8) Bottom ash transport water. There shall be no discharge of pollutants in bottom ash transport water. Whenever bottom ash transport water is used in any other plant process or is sent to a treatment system at the plant, the resulting effluent must comply with the discharge standard in this paragraph.

(9) Gasification wastewater. The quantity of pollutants discharged in gasification wastewater shall not exceed the quantity determined by multiplying the flow of gasification wastewater times the concentration listed in the following table:

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

PSNS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day consecutive days

shall not exceed

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

Arsenic, total (mug/L)............ 4 ..................

Mercury, total (ng/L)............... 1.8 1.3

Selenium, total (mug/L)........... 453 227

Total dissolved solids (mg/L)....... 38 22

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

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

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

PSNS

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

Average of daily

Pollutant or pollutant property Maximum for values for 30

any 1 day consecutive days

shall not exceed

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

Arsenic, total (mug/L)............ 11 8

Mercury, total (ng/L)............... 788 356

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

FR Doc. 2015-25663 Filed 11-2-15; 8:45 am

BILLING CODE 6560-50-P

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

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