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

Federal RegisterNov 3, 2015

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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.

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

I. Regulated Entities and Supporting Documentation

A. Regulated Entities

B. Supporting Documentation

II. Legal Authority for This Action

III. Executive Summary

A. Purpose of the Rule

B. Summary of Final Rule

C. Summary of Costs and Benefits

IV. Background

A. Clean Water Act

B. Effluent Guidelines Program

1. Best Practicable Control Technology Currently Available

2. Best Conventional Pollutant Control Technology

3. Best Available Technology Economically Achievable

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

5. Pretreatment Standards for Existing Sources

6. Pretreatment Standards for New Sources

C. Steam Electric Effluent Guidelines Rulemaking History

V. Key Updates Since Proposal

A. Industry Profile Changes Due to Retirements and Conversions

B. EPA Consideration of Other Federal Rules

C. Advancements in Technologies

D. Engineering Costs

E. Economic Impact Analysis

F. Pollutant Data

G. Environmental Assessment Models

VI. Industry Description

A. General Description of Industry

B. Steam Electric Process Wastewater and Control Technologies

1. FGD Wastewater

2. Fly Ash Transport Water

3. Bottom Ash Transport Water

4. FGMC Wastewater

5. Combustion Residual Leachate From Landfills and Surface Impoundments

6. Gasification Wastewater

VII. Selection of Regulated Pollutants

A. Identifying the Pollutants of Concern

B. Selection of Pollutants for Regulation Under BAT/NSPS

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

VIII. The Final Rule

A. BPT

B. BAT/NSPS/PSES/PSNS Options

1. FGD Wastewater

2. Fly Ash Transport Water

3. Bottom Ash Transport Water

4. FGMC Wastewater

5. Gasification Wastewater

6. Combustion Residual Leachate

7. Non-Chemical Metal Cleaning Waste

C. Best Available Technology

1. FGD Wastewater

2. Fly Ash Transport Water

3. Bottom Ash Transport Water

4. FGMC Wastewater

5. Gasification Wastewater

6. Combustion Residual Leachate

7. Timing

8. Legacy Wastewater

9. Economic Achievability

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

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

12. Existing Oil-Fired and Small Generating Units

13. Voluntary Incentives Program

D. Best Available Demonstrated Control Technology/NSPS

E. PSES

F. PSNS

G. Anti-Circumvention Provision

H. Other Revisions

1. Correction of Typographical Error for PSNS

2. Clarification of Applicability

I. Non-Chemical Metal Cleaning Wastes

J. Best Management Practices

IX. Costs and Economic Impact

A. Plant-Specific and Industry Total Costs

B. Social Costs

C. Economic Impacts

1. Summary of Economic Impacts for Existing Sources

2. Summary of Economic Impacts for New Sources

X. Pollutant Reductions

XI. Development of Effluent Limitations and Standards

XII. Non-Water Quality Environmental Impacts

XIII. Environmental Assessment

A. Introduction

B. Summary of Human Health and Environmental Impacts

C. Environmental Assessment Methodology

D. Outputs From the Environmental Assessment

1. Improvements in Surface Water and Ground Water Quality

2. Reduced Impacts to Wildlife

3. Reduced Human Health Cancer Risk

4. Reduced Threat of Non-Cancer Human Health Effects

5. Reduced Nutrient Impacts

E. Unquantified Environmental and Human Health Improvements

F. Other Secondary Improvements

XIV. Benefit Analysis

A. Categories of Benefits Analyzed

B. Quantification and Monetization of Benefits

1. Human Health Benefits From Surface Water Quality Improvements

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

3. Market and Productivity Benefits

4. Air-Related Benefits (Human Health and Avoided Climate Change Impacts)

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

C. Total Monetized Benefits

D. Other Benefits

XV. Cost-Effectiveness Analysis

A. Methodology

B. Results

XVI. Regulatory Implementation

A. Implementation of the Limitations and Standards

1. Timing

2. Applicability of NSPS/PSNS

3. Legacy Wastewater

4. Combined Wastestreams

5. Non-Chemical Metal Cleaning Wastes

B. Upset and Bypass Provisions

C. Variances and Modifications

1. Fundamentally Different Factors Variance

2. Economic Variances

3. Water Quality Variances

4. Removal Credits

D. Site-Specific Water Quality-Based Effluent Limitations

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

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

B. Paperwork Reduction Act

C. Regulatory Flexibility Act

D. Unfunded Mandates Reform Act

E. Executive Order 13132: Federalism

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

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

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

I. National Technology Transfer and Advancement Act

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

K. Congressional Review Act (CRA)

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

I. Regulated Entities and Supporting Documentation

A. Regulated Entities

Entities potentially regulated by this action include:

Category

Example of regulated entity

North American Industry Classification System (NAICS) Code

Industry

Electric Power Generation Facilities—Electric Power Generation

22111

Electric Power Generation Facilities—Fossil Fuel Electric Power Generation

221112

Electric Power Generation Facilities—Nuclear Electric Power Generation

221113

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

FOR FURTHER INFORMATION CONTACT

section.

B. Supporting Documentation

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

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

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

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

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

These documents are available in the public record for this rule and on EPA's Web site at

http://www2.epa.gov/eg/steam-electric-power-generating-effluent-guidelines-2015-final-rule.

II. Legal Authority for This Action

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

III. Executive Summary

A. Purpose of the Rule

Steam electric power plants

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

waters by all industrial categories regulated under the CWA.

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.

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.

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.

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).

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.

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

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

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:

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

• 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.

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.

• 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.

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.

• 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:

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

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

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.

• 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.

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.

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.

For additional information, see Sections V and IX.

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$]

Discount rate

Total monetized social benefits

Total social costs

Final Rule

$451 to $566

$387 to $478

$480

$471

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

IV. Background

A. Clean Water Act

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

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

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

e.g.,

BPT, BCT, BAT; see below).

EPA promulgates national ELGs for major industrial categories for three classes of pollutants: (1) Conventional pollutants (TSS, oil and grease, biochemical oxygen demand (BOD

), fecal coliform, and pH), as outlined in

CWA section 304(a)(4) and 40 CFR 401.16; (2) toxic pollutants (

e.g.,

toxic metals such as arsenic, mercury, selenium, and chromium; toxic organic pollutants such as benzene, benzo-a-pyrene, phenol, and naphthalene), as outlined in CWA section 307(a), 33 U.S.C. 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: BOD

, 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.

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.

Train,

543 F.2d 328, 353 (D.C. Cir. 1976);

Am. Frozen Food Inst.

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.

EPA,

760 F.2d 549, 562 (4th Cir. 1985);

Cal. & Hawaiian Sugar Co.

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

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

EPA,

719 F.2d 624, 634 (3rd Cir. 1983).

C. Steam Electric Effluent Guidelines Rulemaking History

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

V. Key Updates Since Proposal

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

A. Industry Profile Changes Due to Retirements and Conversions

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

B. EPA Consideration of Other Federal Rules

EPA made every effort to appropriately account for other rules in its many analyses for this rule. Since proposal, EPA has promulgated other rules affecting the steam electric industry: the Cooling Water Intake Structures (CWIS) rule for existing facilities (79 FR 48300; Aug. 15, 2014), the CCR rule (80 FR 21302; Apr. 17, 2015), the CPP rule (see

http://www2.epa.gov/cleanpowerplan/clean-power-plan-existing-power-plants

), and the Carbon Pollution Standard for New Power Plants (CPS) rule (see

http://www2.epa.gov/cleanpowerplan/carbon-pollution-standards-new-modified-and-reconstructed-power-plants

). One result of taking into account these rules is a change in the population of units and plants that EPA estimates would incur incremental costs, as well as additional estimated benefits, under this final rule. In some cases, EPA performed two sets of parallel analyses to demonstrate how the other rules affected this final rule. For example, EPA conducted an assessment of compliance costs and pollutant loadings for this rule both with and without accounting for the CCR rule (this preamble only presents results accounting for the CCR rule). Then, using results from the analyses of costs and loadings accounting for the CCR rule, EPA also conducted an additional set of analyses of compliance costs and pollutant loadings accounting for the proposed CPP rule (this preamble only presents results accounting for the proposed CPP rule). At the time EPA conducted its analyses, the CPP had not yet been finalized, and thus EPA used the proposed CPP for its analyses. EPA concluded that the proposed and final CPP specifications are similar enough that using the proposed rather than the final CPP will not bias the results of the analysis for this rule. See Section IX for additional information. Because EPA used the proposal as a proxy for the final rule, the rest of the preamble simply refers to the CPP rule. Given that final CPP state plans have not yet been determined, EPA recognizes that the modeled results have uncertainty due to the possibility of unexpected implementation approaches and that actual market responses may be somewhat more or less pronounced than estimated. The current estimate reflects the best data and analysis available at this time. For more information on these federal rules, see TDD Section 1.3.3. For more information on how EPA accounted for the effect of these rules on its compliance cost, pollutant loadings estimates, and non-water quality environmental impacts, see TDD Sections 9, 10, and 12. See Section V.D. and Section IX, below, and the RIA regarding how EPA considered other federal rules in its economic impact analysis.

C. Advancements in Technologies

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

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

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)

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),

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).

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

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

F. Pollutant Data

For the final rule, EPA incorporated data submitted by public commenters in its effluent limitations and standards development, pollutants of concern identification, and pollutant loadings estimates. Such data include:

• Industry-submitted data representing the FGD purge, FGD chemical precipitation effluent, and FGD biological treatment effluent for the plants identified as operating BAT systems;

• Industry-submitted ash transport water characterization and source water data;

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.

• Industry-submitted ash impoundment effluent concentrations; and

• Industry-submitted pilot-test data related to treatment of FGD wastewater.

EPA subjected the new data to its data quality acceptance criteria and, as appropriate, updated its analyses accordingly. See TDD Section 3 for additional information on the data sources used in the development of the final rule.

G. Environmental Assessment Models

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

VI. Industry Description

A. General Description of Industry

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

B. Steam Electric Process Wastewater and Control Technologies

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

e.g.,

particulate removal systems, FGD systems, nitrogen oxide (NO

)-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

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

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

5. Combustion Residual Leachate From Landfills and Surface Impoundments

Combustion residuals comprise a variety of wastes from the combustion process, which are generally collected by or generated from air pollution control technologies. These combustion residuals can be stored at the plant in on-site landfills or surface impoundments. Leachate includes liquid, including any suspended or dissolved constituents in the liquid, that has percolated through or drained from waste or other materials placed in a landfill, or that passes through the containment structure (

e.g.,

bottom, dikes, berms) of a surface impoundment. Based on data from the industry survey, most landfills and some impoundments have a system to collect the leachate.

In a lined landfill or impoundment, the combustion residual leachate collected in the liner is typically transported to an impoundment (

e.g.,

collection pond). Some plants discharge the effluent from these impoundments containing combustion residual leachate directly to receiving waters, while other plants first send the impoundment effluent to another impoundment handling the ash transport water or other treatment system (

e.g.,

constructed wetlands) prior to discharge. Unlined impoundments and landfills usually do not collect leachate, which would allow the leachate to potentially migrate to nearby ground waters, drinking water wells, or surface waters.

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

6. Gasification Wastewater

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

e.g.,

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

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

VII. Selection of Regulated Pollutants

A. Identifying the Pollutants of Concern

In determining which pollutants warrant regulation in this rule, EPA first evaluated the wastewater characteristics to identify pollutants of concern (POCs). Constituents present in steam electric power plant wastewater are primarily derived from the parent carbon feedstock (

e.g.,

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

B. Selection of Pollutants for Regulation Under BAT/NSPS

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

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

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

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

(

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 BOD

, TSS, and oil and grease. POTWs are designed to treat these conventional pollutants; therefore, they are not considered to pass through.

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

VIII. The Final Rule

A. BPT

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

B. BAT/NSPS/PSES/PSNS Options

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

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.

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

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

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

Wastestreams

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

FGD Wastewater

Chemical Precipitation

Chemical Precipitation + Biological Treatment

Evaporation.

Fly Ash Transport Water

Dry handling

Dry handling.

Bottom Ash Transport Water

Impoundment (Equal to BPT)

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

Dry handling/ Closed loop

Dry handling/ Closed loop.

FGMC Wastewater

Dry handling

Dry handling.

Gasification Wastewater

Evaporation

Evaporation.

Combustion Residual Leachate

Impoundment (Equal to BPT)

Chemical Precipitation

Chemical Precipitation.

Nonchemical Metal Cleaning Wastes

[Reserved]

[Reserved].

Consistent with the proposal, under all Options A through F, for oil-fired generating units and small generating units (50 MW or smaller) that are existing sources, the rule would establish BAT/PSES effluent limitations and standards on TSS in fly ash transport water, bottom ash transport water, FGD wastewater, FGMC wastewater, combustion residual leachate, and gasification wastewater equal to the previously promulgated BPT effluent limitations on TSS

in fly ash transport water, bottom ash transport water, and low volume waste sources, where applicable. Under Options A through E, EPA would establish a voluntary incentives program for plants that choose to meet BAT limitations for FGD wastewater based on evaporation technology, as described in Section VIII.C.13. Moreover, as EPA proposed, under all Options A through F, the rule would establish an anti-circumvention provision designed to ensure that the purpose of the rule is achieved, as further described below, in Section VIII.G. Finally, as EPA proposed, under all Options A through F, the rule would correct a typographical error in the previously promulgated regulations, as well as make certain clarifying revisions to the applicability provision of the regulations, as further described below, in Section VIII.H.

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

1. FGD Wastewater

Under Option A, EPA would establish effluent limitations and standards for mercury and arsenic in FGD wastewater based on treatment using chemical precipitation. Under Options B through E, EPA would establish effluent limitations and standards for mercury, arsenic, selenium, and nitrate/nitrite as N in FGD wastewater based on treatment using chemical precipitation (as under Option A) followed by biological treatment. Under Option F, EPA would establish effluent limitations and standards for mercury, arsenic, selenium, and TDS in FGD wastewater based on treatment using an evaporation system. Under all options, to facilitate implementation of the new BAT/NSPS/PSES/PSNS requirements, EPA would also promulgate a definition for FGD wastewater, making clear it would no longer be considered a low volume waste source.

2. Fly Ash Transport Water

Under all Options A through F, EPA would establish (or in the case of NSPS/PSNS, maintain) zero discharge effluent limitations and standards for pollutants in fly ash transport water based on use of a dry handling system.

3. Bottom Ash Transport Water

Under Options A and B, EPA would establish effluent limitations and standards for bottom ash transport water equal to the previously promulgated BPT limitation on TSS, which is based on the use of a surface impoundment. Under Options D, E, and F, EPA would establish zero discharge effluent limitations and standards for pollutants in bottom ash transport water based on one of two technologies: A dry handling system or a closed-loop system. Under Option C, EPA would establish, for bottom ash transport water, zero discharge limitations and standards based on dry handling or closed-loop systems only for generating units with a nameplate capacity of more than 400 MW. Units with a nameplate capacity equal to or less than 400 MW would have to meet new effluent limitations and standards equal to the previously established BPT limitation on TSS, based on surface impoundments.

4. FGMC Wastewater

Under all Options A through F, EPA would establish zero discharge effluent limitations and standards for FGMC wastewater based on use of a dry handling system. Under all Options A through F, EPA would establish a separate definition for FGMC wastewater, making clear it would no longer be considered a low volume waste source.

5. Gasification Wastewater

The technology basis for control of gasification wastewater under all Options A through F is an evaporation system. Under these options, EPA would establish limitations and standards on arsenic, mercury, selenium, and TDS in gasification wastewater. Under all Options A through F, EPA would establish a separate definition for gasification wastewater, making clear it would no longer be considered a low volume waste source.

6. Combustion Residual Leachate

Under Options A through D, EPA would establish effluent limitations and standards for combustion residual leachate equal to the previously promulgated BPT limitation on TSS for low volume waste sources. Under Options E and F, EPA would establish additional limitations and standards for arsenic and mercury in combustion residual leachate based on treatment using a chemical precipitation system (the same technology basis for control of FGD wastewater under Option A). Under all Options A through F, EPA would establish a separate definition for combustion residual leachate, making

clear it would no longer be considered a low volume waste source.

7. Non-Chemical Metal Cleaning Wastes

Under all Options A through F, EPA would continue to reserve BAT/NSPS/PSES/PSNS for non-chemical metal cleaning wastes, as the previously established regulations do.

C. Best Available Technology

After considering the technologies described in this preamble and Section 7 of the TDD, as well as public comments, and in light of the factors specified in CWA sections 304(b)(2)(B) and 301(b)(2)(A) (see Section IV.B.3), EPA decided to establish BAT effluent limitations based on the technologies described in Option D. Thus, for BAT, the final rule establishes: (1) Limitations on arsenic, mercury, selenium, and nitrate/nitrite as N in FGD wastewater, based on chemical precipitation plus biological treatment;

(2) a zero discharge limitation for pollutants in fly ash transport water, based on dry handling; (3) a zero discharge limitation for pollutants in bottom ash transport water, based on dry handling or closed-loop systems; (4) a zero discharge limitation on all pollutants in FGMC wastewater, based on dry handling; (5) limitations on mercury, arsenic, selenium, and TDS in gasification wastewater, based on evaporation;

and (6) a limitation on TSS in combustion residual leachate, based on surface impoundments.

The final rule also establishes new definitions for FGD wastewater, FGMC wastewater, gasification wastewater, and combustion residual leachate.

For those plants that choose to participate in the voluntary incentives program, the applicable limitations are for arsenic, mercury, selenium, and TDS in FGD wastewater, based on the use of an evaporation system (see Section VIII.C.13).

For small (50 MW or less) generating units and oil-fired generating units, the final rule establishes different BAT limitations for FGD wastewater, fly ash transport water, bottom ash transport water, FGMC wastewater, and gasification wastewater (see Section VIII.C.12).

The final rule also establishes BAT limitations on TSS in discharges of “legacy wastewater,” which are equal to previously established TSS limitations. See Section VIII.C.8.

1. FGD Wastewater

This rule identifies treatment using chemical precipitation followed by biological treatment as the BAT technology basis for control of pollutants discharged in FGD wastewater. More specifically, the technology basis for BAT is a chemical precipitation system that employs hydroxide precipitation, sulfide precipitation (organosulfide), and iron coprecipitation, followed by an anoxic/anaerobic fixed-film biological treatment system designed to remove heavy metals, selenium, and nitrates.

After accounting for industry changes described in Section V, forty-five percent of all steam electric power plants with wet scrubbers have equipment or processes in place able to meet the final BAT/PSES effluent limitations and standards.

Many of these plants use FGD wastewater management approaches that eliminate the discharge of FGD wastewater.

Other plants employ wastewater treatment technologies that reduce the amount of pollutants in the FGD wastestream. Both chemical precipitation and biological treatment are well-demonstrated technologies that are available to steam electric power plants for use in treating FGD wastewater. Based on industry survey responses, 39 U.S. steam electric power plants (44 percent of plants discharging FGD wastewater) use some form of chemical precipitation as part of their FGD wastewater treatment system. More than half of these plants (30 percent of plants discharging FGD wastewater) use both hydroxide and sulfide precipitation in the process to further reduce metals concentrations. In addition, chemical precipitation has been used at thousands of industrial facilities nationwide for the last several decades (see TDD Section 7).

In estimating costs associated with this technology basis, EPA assumed that in order to meet the limitations and standards, certain plants with high FGD discharge flow rates (greater than or equal to 1,000 gpm) would elect to incorporate flow minimization into their operating practices (by reducing the FGD purge rate or recycling a portion of their FGD wastewater back to the FGD system), where the FGD system metallurgy can accommodate an increase in chlorides. See Section 4.5.4 of EPA's Incremental Costs and Pollutant Removals for the Final Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category (DCNs SE05831 and SE05832).

This value accounts for announced retirements, conversions, and changes plants are projected to make to comply with the CPP and CCR rules.

A variety of approaches that depend on plant specific conditions are used to achieve zero pollutant discharge at these plants, including evaporation ponds, complete recycle, and processes that combine the FGD wastewater with other materials for landfill disposal. Although these technologies, as well as others currently used for achieve zero pollutant discharge, may be available for some plants with FGD wastewater, EPA determined they are not available nationally. For example, evaporation ponds are only available in certain climates. Similarly, complete recycle is only available at plants with appropriate FGD metallurgy.

Biological treatment has been tested at power plants for more than ten years and full-scale systems have been operating at a subset of plants for seven years. It has been widely used in many industrial applications for decades, in both the U.S. and abroad, and it has been employed at coal mines. Currently, six U.S. steam electric power plants (approximately ten percent of those discharging FGD wastewater) use biological treatment designed to substantially reduce nitrogen compounds and selenium in their FGD wastewater. Other power plants are considering installing biological treatment to remove selenium, and at least one plant is scheduled to begin operating a biological treatment system for selenium removal soon. Four of the six plants using biological systems to treat their FGD wastewater precede the biological treatment stage with chemical precipitation; thus, the entire system is designed to remove suspended solids, particulate and dissolved metals (such as mercury and arsenic), soluble and insoluble forms of selenium, and nitrate and nitrite forms of nitrogen. These plants show that chemical precipitation followed by biological treatment is technologically available and demonstrated. The other two plants operating anoxic/anaerobic bioreactors to remove selenium precede the biological treatment stage with surface impoundments instead of chemical precipitation. The treatment systems at these two plants are likely to be less effective at removing metals (including many dissolved metals) and would likely face more operational problems than the plants employing chemical pretreatment, but they nevertheless show the efficacy and availability of biological treatment for removing selenium and nitrate/nitrite in FGD wastewater.

A few commenters questioned the feasibility of biological treatment at some power plants. Specifically, they claimed, in part, that the efficacy of biological systems is unpredictable and is subject to temperature changes, high chloride concentrations, scaling, and high oxidation-reduction potential (ORP) in the absorber, which could kill the microorganisms in the bioreactor. EPA's record does not support these assertions for a well-designed and well-operated chemical precipitation and biological treatment system.

EPA's record demonstrates that proper pretreatment prior to biological treatment and proper monitoring with adjustments to the treatment system as necessary are key to reducing operational concerns raised by commenters. Proper pretreatment includes chemical precipitation, which can address wastewater containing high oxidant loads through addition of a reducing agent in one of the treatment

system's reaction tanks.

It also includes pretreatment of FGD wastewater containing exceptionally high levels of nitrates (

e.g.,

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

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

Some commenters also claimed that the efficacy of biological systems in removing selenium is subject to changes in switching from one coal type to another (also referred to as fuel flexing). Where EPA had biological treatment performance data paired with fuel type, EPA reviewed it and found that existing biological treatment systems continue to perform well during periods of fuel switching. See DCN SE05846. The data show that, in all cases except one, the plants met the selenium limitations following fuel switches. In one instance when a plant switched to a certain coal type, the plant exceeded the final daily maximum selenium limitation for one out of thirteen observations for the month while the average of all values for that month were below the final monthly selenium limitation. This plant was not subject to a selenium limit at the time data was collected. Moreover, EPA's record demonstrates that effective communication between the operator(s) of the generating unit and the boiler, as well as bench testing and monitoring the ORP, and making proper adjustments to the operation of the treatment system, would make it possible to prevent potential selenium exceedances at this plant. Data for two other plants operating full-scale biological treatment systems shows that fuel switches should not result in exceeding the effluent limitations. EPA also has data from a pilot project at another plant employing the same type of coal used by the one plant that experienced elevated selenium effluent concentrations following a coal switch. The data for this pilot project demonstrate effective selenium removal by the BAT technology basis, with all effluent values at concentrations below the BAT limitations established in this rule.

EPA also reviewed effluent data in the record for plants operating combined chemical precipitation and biological treatment for FGD wastewater to evaluate how cycling operation (

i.e.,

changes in electricity generation rate) and short or extended shutdown periods may affect the ability of plants to meet the BAT effluent limitations. These data demonstrate that cycling operations and shutdown periods, whether short or long in duration, are manageable and do not result in plants being unable to meet the ELG effluent limitations. See DCN SE05846.

EPA did not select surface impoundments as the BAT technology basis for FGD wastewater because it would not result in reasonable further progress toward eliminating the discharge of all pollutants, particularly toxic pollutants (see CWA section 301(b)(2)(A)). Surface impoundments, which rely on gravity to remove particulates from wastewater, are the technology basis for the previously promulgated BPT effluent limitations for low volume waste sources. Pollutants that are present mostly in soluble (dissolved) form, such as selenium, boron, and magnesium, are not effectively and reliably removed by gravity in surface impoundments. For metals present in both soluble and particulate forms (such as mercury), gravity settling in surface impoundments does not effectively remove the dissolved fraction. Furthermore, the environment in some surface impoundments can create chemical conditions (

e.g.,

low pH) that convert particulate forms of metals to soluble forms, which are not removed by the gravity settling process. Additionally, the Electric Power Research Institute (EPRI) has reported that adding FGD wastewater to surface impoundments used to treat ash transport water can reduce the settling efficiency in the impoundments due to gypsum particle dissolution, thus increasing the effluent TSS concentrations. Discharging wastewater containing elevated levels of TSS would likely result in also discharging other pollutants (

e.g.,

metals) in higher concentrations. EPRI has also reported that FGD wastewater includes high loadings of volatile metals, which can increase the solubility of metals in surface impoundments, thereby leading to increased levels of dissolved metals and higher concentrations of metals in discharges from surface impoundments. Finally, as described in Section 8 of the TDD, surface impoundments are also subject to seasonal turnover, which adversely affects their efficacy. Seasonal turnover occurs when the impoundment's upper layer of water becomes cooler and denser, typically as the season changes from summer to fall. The cooler, upper layer of water then sinks and causes the entire volume of the impoundment to circulate, which can result in resuspension of solids that had settled to the bottom and a consequent increase in the concentrations of pollutants discharged from the impoundment.

Chemical precipitation and biological treatment are more effective than surface impoundments at removing both soluble and particulate forms of metals, as well as other pollutants such as nitrogen compounds and TDS. Because many of the pollutants of concern in FGD wastewater are present in dissolved form and would not be removed by surface impoundments, and because of the relatively large mass loads of these pollutants (

e.g.,

selenium, dissolved mercury) discharged in the FGD wastestream, EPA decided not to finalize BAT effluent limitations for FGD wastewater based on surface impoundments.

EPA also rejected identifying chemical precipitation, alone, (Option A) as BAT for FGD wastewater because, while chemical precipitation systems are capable of achieving removals of various metals, the technology is not effective at removing selenium, nitrogen compounds, and certain metals that contribute to high concentrations of TDS in FGD wastewater. These pollutants of concern are discharged by steam electric power plants throughout the nation, causing adverse human health impacts and some of the most egregious environmental impacts (see Section XIII and EA). In light of this, and the fact that economically achievable technologies are available to

reduce these pollutants of concern, EPA determined that, by itself, chemical precipitation would not result in reasonable further progress toward the national goal of eliminating the discharge of all pollutants (see CWA section 301(b)(2)(A)), and rejected that technology basis as BAT in favor of chemical precipitation followed by anaerobic/anoxic biological treatment.

EPA also decided not to establish, for all steam electric power plants, BAT limitations for FGD wastewater based on treatment using an evaporation system. In particular, this technology basis would employ a falling-film evaporator (also known as a brine concentrator) to produce a concentrated wastewater stream (brine) and a distillate stream.

While evaporation systems are effective at removing boron and pollutants that contribute to high concentrations of TDS, EPA decided it would not be appropriate to identify evaporation as the BAT technology basis for FGD wastewater at all steam electric power plants because of the high cost of possible regulatory requirements based on evaporation for discharges of FGD wastewater at existing facilities. The annual cost to the industry of limitations based on evaporation would be more than 2 and

1/2

times the cost to industry estimated for the final rule (after tax) (approximately $570 million more expensive than the final rule, on an annual basis, after tax). Given the high costs associated with the technology, and the fact that the steam electric industry is facing costs associated with several other rules in addition to this rule, EPA decided not to establish BAT limitations for FGD wastewater based on evaporation for all steam electric power plants. Nevertheless, as described further below, in Section VIII.C.13, the final rule does establish a voluntary incentives program under which steam electric power plants can choose to be subject to more stringent BAT limitations for FGD wastewater based on evaporation.

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

Finally, EPA decided not to establish a requirement that would direct permitting authorities to establish limitations for FGD wastewater using site-specific BPJ. Public commenters representing industry, state, and environmental group interests urged EPA not to establish any requirement that would leave BAT effluent limitations for FGD wastewater to be determined on a BPJ basis. Sections 301 and 304 of the CWA require EPA to develop nationally applicable ELGs based on the best available technology economically achievable, taking certain factors into account. EPA decided that it would not be appropriate to leave FGD wastewater requirements in the final rule to be determined on a BPJ basis because there are sufficient data to set uniform, nationally applicable limitations on FGD wastewater at plants across the nation. Given this, BPJ permitting of FGD wastewater would place an unnecessary burden on permitting authorities, including state and local agencies, to conduct a complex technical analysis that they may not have the resources or expertise to complete. BPJ permitting of FGD wastewater would also unnecessarily burden the regulated industry because of associated delays and uncertainty with respect to permits.

2. Fly Ash Transport Water

This rule identifies dry handling as the BAT technology basis for control of pollutants in fly ash transport water. Specifically, the technology basis for BAT is a dry vacuum system that employs a mechanical exhauster to pneumatically convey the fly ash (via a change in air pressure) from hoppers directly to a silo. Dry handling is clearly available to control the pollutants present in fly ash transport water. Today, the vast majority of steam electric power plants use dry handling techniques to manage fly ash, and by doing so avoid generating fly ash transport water. All new generating units built since the ELGs were last revised in 1982 have been subject to a zero discharge standard for pollutants in fly ash transport water. In addition, many owners and operators with generating units that are not subject to the previously established zero discharge NSPS for fly ash transport water have chosen to retrofit their units with dry fly ash handling technology to meet operational needs or for economic reasons. The trend in the industry is, moreover, toward the conversion and use of dry fly ash handling systems. See TDD Section 4.5. Based on data collected in the industry survey, EPA estimates that approximately 80 percent of coal and petroleum coke-fired generating units operate dry fly ash handling systems. Since the survey, companies have continued to upgrade, or announce plans to upgrade, their ash handling systems at generating units. See TDD Section 4.5.

Dry ash handling does not adversely affect plant operations or reliability, and it promotes the beneficial reuse of coal combustion residuals. In addition, converting to dry fly ash handling eliminates the need to treat fly ash transport water in a surface impoundment, and it reduces the amount of wastes entering surface impoundments and the risk and severity of structural failures and spills.

EPA decided not to finalize a BAT limitation on fly ash transport water equal to the previously promulgated BPT limitation on TSS, based on the technology of surface impoundments, for the same reasons (where applicable) that EPA did not identify surface impoundments as BAT for FGD wastewater (see Section VIII.C.1).

3. Bottom Ash Transport Water

This rule identifies dry handling or closed-loop systems as the BAT technology basis for control of pollutants in bottom ash transport water.

More specifically, the first technology basis for BAT is a system in which bottom ash is collected in a water quench bath and a drag chain conveyor (mechanical drag system) then pulls the bottom ash out of the water bath on an incline to dewater the bottom ash. The second technology basis for BAT is a system in which the bottom ash is transported using the same processes as a wet-sluicing system, but instead of going to an impoundment, the bottom ash is sluiced to a remote mechanical drag system. Once there, a drag chain conveyor pulls the bottom ash out of the water on an incline to dewater the bottom ash, and the transport (sluice) water is then recycled back to the bottom ash collection system.

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

These technologies for control of bottom ash transport water are demonstrably available. Based on survey data, more than 80 percent of coal-fired generating units built in the last 20 years have installed dry bottom ash handling systems. In addition, EPA found that more than half of the entities that would be subject to BAT requirements for bottom ash transport water are already employing zero discharge technologies (dry handling or closed-loop wet ash handling) or planning to do so in the near future.

Dry bottom ash handling does not adversely affect plant operations or reliability, and shifting to dry bottom ash handling offers certain benefits. As was the case for dry fly ash handling, shifting to dry bottom ash handling eliminates the need to send bottom ash transport water to a surface impoundment, and it reduces the

amount of waste entering surface impoundments and the risk and severity of structural failures and spills. Furthermore, one way companies may choose to comply with the final rule's requirements is to install a completely dry bottom ash system, which increases the energy efficiency of the boiler, thus reducing the amount of coal burned and associated emissions of carbon dioxide (CO

) 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.

See DCN SE05980.

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

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

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

EPA reviewed its record and re-evaluated whether it would be appropriate to establish differentiated requirements for discharges of bottom ash transport water from existing sources based on unit size, in light of comments and the key changes since proposal discussed in Section V. Annualized cost per amount of energy produced increases along a smooth curve moving from the very largest units to the smallest units. See DCN SE05813. That, however, is expected due to economies of scale. There is no clear breaking point at which to establish a size threshold for purposes of differentiated requirements for bottom ash transport water.

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).

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

4. FGMC Wastewater

This rule identifies dry handling as the BAT technology basis for the control of pollutants in FGMC wastewater. More specifically, the technology basis for BAT is a dry vacuum system that employs a mechanical exhauster to convey the FGMC waste (via a change in air pressure) from hoppers directly to a silo. Dry handling of FGMC waste is available and well demonstrated in the industry; indeed, nearly all plants with FGMC systems use dry handling systems. Plants using sorbent injection systems (

e.g.,

activated carbon injection) to reduce mercury emissions from the flue gas typically handle the spent sorbent in the same manner as their fly ash (see Section VI.B.4 and TDD Section 7.5). As of 2009, 92 percent of the industry generating FGMC waste uses dry handling to manage it. Only a few plants use wet systems to transport the spent sorbent to disposal in surface impoundments. Based on the industry survey, the plants using wet handling systems operate them as closed-loop systems and do not discharge FGMC wastewater, or they already have a dry handling system that is capable of achieving zero discharge. Under the zero discharge limitation, these plants could choose to continue to operate their wet systems as closed-loop systems, or they could convert to dry handling technologies by managing the fly ash and spent sorbent together in a retrofitted dry system (rather than an impoundment) or by installing dedicated dry handling equipment for the FGMC waste similar to the equipment used for fly ash.

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

5. Gasification Wastewater

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

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

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

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.

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)).

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

8. Legacy Wastewater

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

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

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.

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.

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.

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.

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

Finally, while there are a few plants that discharge from an impoundment containing only legacy FGD wastewater,

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.

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.

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).

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.

These IPM results support EPA's conclusion that the final rule is economically achievable.

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.

Given the design of IPM, unit-level and thereby plant-level projections are presented as an indicator of overall regulatory impact rather than a precise prediction of future unit-level or plant-specific compliance actions.

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

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

The final BAT effluent limitations have acceptable non-water quality

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 (NO

, sulfur oxides (SO

), and CO

), solid waste generation, and water usage. Under the final rule, NO

emissions are projected to decrease by 1.16 percent, SO

emissions are projected to increase by 0.04 percent, and CO

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

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.

ER03NO15.221

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.

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

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

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

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

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

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

Steam electric power plants agreeing to meet BAT limitations for FGD wastewater based on evaporation must comply with those limitations on arsenic, mercury, selenium, and TDS in FGD wastewater.

For such plants, the BAT limitations based on evaporation apply as of December 31, 2023, to FGD wastewater generated on and after December 31, 2023. Plants opting to participate in the voluntary program can use the period in advance of this date to research, engineer, design, procure, construct, and optimize systems capable

of meeting the limitations based on evaporation.

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

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

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

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

D. Best Available Demonstrated Control Technology/NSPS

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

The record indicates that the technologies that serve as the bases for the final NSPS are well demonstrated based on the performance of plants using the technologies. For example, new steam electric power generating sources have been meeting the previously established zero discharge standard for fly ash transport water since 1982, predominantly through the use of dry handling technologies. Moreover, as described in Section VIII.C.13, three plants in the U.S. and four plants in Italy use evaporation technology to treat their FGD wastewater, and another U.S. plant is in the process of installing such technology for that purpose. Of the approximately 50 coal-fired generating units that were built within the last 20 years, most (83 percent) manage their bottom ash without using water to transport the ash and, as a result, do not discharge bottom ash transport water. The technology basis identified as BAT technology for gasification wastewater represents current industry practice. Every IGCC power plant currently in operation uses evaporation to treat their gasification wastewater, even when the wastewater is not discharged and is instead reused at the plant. In the case of FGMC wastewater, every plant currently using post-combustion sorbent injection (

e.g.

, activated carbon injection) either handles the captured spent sorbent with a dry process or manages the FGMC wastewater so that it is not discharged to surface waters (or has the capability to do so). For combustion residual leachate, chemical precipitation is a well-demonstrated technology for removing metals and other pollutants from a variety of industrial wastewaters, including leachate from landfills not located at power plants. Chemical precipitation is also well demonstrated at steam electric power plants for treatment of FGD wastewater that contains the pollutants in combustion residual leachate.

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

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

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

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

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.

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.

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

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

Technology basis/Wastewater stream

Pollutant

Pass through?

(yes/no)

Chemical Precipitation for Combustion Residual Leachate (only for NSPS)

Arsenic

Mercury

Yes.

Chemical Precipitation plus Biological Treatment for FGD Wastewater

Arsenic

Mercury

Nitrate/Nitrite as N

Selenium

Yes.

Evaporation for FGD wastewater (only for NSPS)

Arsenic

Mercury

Selenium

TDS

Yes.

Evaporation for Gasification Wastewater

Arsenic

Mercury

Selenium

TDS

Yes.

After considering all of the relevant factors and technology options in this preamble and in the TDD, as well as public comments, as is the case with BAT, EPA decided to establish PSES based on

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