U.S. Environmental Protection Agency 

Documentation of OMB Review Under Executive Order 12866 

Title of Action: 

Docket#: FRL#: RIN:

This action was submitted to the Office of Management and Budget (OMB) for review under Executive Order (E.O.) 

12866, titled Regulatory Planning and Review (58 FR 51735, October 4, 1993). Whenever EPA makes publicly available 

a regulatory action that was reviewed under E.O. 12866, section 6(a)(3)(E) of the E.O. directs the Agency to also: 

(1) Make available to the public a copy of the information that was provided to OMB’s Office of Information and 

Regulatory Affairs (OIRA) for review under the E.O., i.e., the text of the draft regulatory action and, if applicable, 

an assessment of the potential costs and benefits, as well as additional information for those actions that are 

determined to be economically significant under the E.O. (Information requirements are described in sections 

6(a)(3)(B) and (C)). 

(2) Identify for the public any substantive changes between the draft submitted to OIRA and the action that was 

subsequently issued, using a method that is complete, clear, and simple. 

(3) Identify for the public those substantive changes made at the suggestion or recommendation of OIRA.

For this regulatory action, were substantive changes made to information reviewed under E.O. 

12866? [Please check the appropriate answer.]

No. [In the docket, include the information identified in item (1) below.]

Yes. [In the docket, include the information identified in items (1) – (3) below.]

Accordingly, the Agency has included this form and the following information in the public 

docket for this regulatory action: [Please check the appropriate information.]

(1) A copy of the information that was provided to OIRA for review under the E.O. 

(2) Documentation of any substantive changes made to the draft regulatory text that was 

submitted to OIRA when compared with what was subsequently made publicly available.

The documentation is provided on the pages following this form. Changes made at the 

suggestion or recommendation of OIRA, if any, are clearly identified through attribution to 

OIRA. EPA has used one or more of the following methods to note changes: [Select the 

appropriate option(s).]

(a) Redline-Strikeout – A copy of the draft regulatory action submitted, using redlinestrikeout to show the substantive changes that were made.

(b) Hand Markup – A copy of the draft regulatory action submitted, using handwritten notes 

to show the substantive changes that were made.

(c) Note to the file - A document that identifies the substantive changes that were made, 

with page and paragraph references to the draft regulatory action that was submitted.

If you have any questions about this regulatory action or this documentation, please call the 

contact:

Name: Email: Phone: 

Revised 05/05/2010 

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

EPA-HQ-OW-2009-0819 9801-6 2040-AF14

Ronald Jordan jordan.ronald@epa.gov 202-566-1003
Summary of the Substantive Changes

Made During Interagency Review Under Executive Order 12866

During the E.O. 12866 interagency review period, EPA made several revisions to the draft 

preamble and regulatory text for proposed revisions to the effluent limitations guidelines and standards 

(ELGs) for the steam electric power generating point source category. The attached “redline-strikeout” 

version of the preamble and regulatory text compares the final document to the document submitted to 

the Office of Management and Budget (OMB). The substantive changes that were made during this 

process are summarized below. Changes #1 through #9 were requested by OMB’s Office of Information 

and Regulatory Affairs (OIRA). Changes #10 through #12 were identified by EPA. (Note that EPA also 

made corresponding changes to the rulemaking support documents, including the Technical 

Development Document, Regulatory Impact Analysis report, Environmental Assessment report, and the 

Benefit and Cost Analysis report.)

1. Addition of new regulatory options (Options 3a and 3b). (Note: Also see Change #11)

2. Change in the preferred regulatory options for BAT and PSES. In the document submitted to 

OMB, Options 3 and 4 were co-proposed as preferred options for BAT and PSES. In the final 

document, Option 4 is no longer a preferred option for BAT and PSES. Option 3 remains a 

preferred option and Options 3a and 3b were also identified as preferred options for BAT and 

PSES. (Note: see Change #12 regarding Option 4a)

3. Addition of cost-effectiveness discussion in Section VIII

4. Revision to proposed BAT/PSES for nonchemical metal cleaning wastes to exclude discharges 

from certain facilities from the proposed effluent limits for copper and iron.

5. Addition of Section IX.B.5 (“Request for Comment on Data”), soliciting comment regarding the 

data used to calculate wastewater pollutant loadings.

6. Edits to the discussion of employment effects, particularly with regard to the significance of the 

employment estimates and contrasting the electric utility industry with industries examined in 

Morganstern, Pizer and Shih. 

7. Changes in the methodology for calculating monetized benefits from reduced impoundment 

failures.

8. Changes to the discussion regarding determining the value of improvements in surface water 

quality, highlighting the Carson and Mitchell (1993) stated preference valuation approach as an 

alternative to the meta-analysis of surface water valuation studies EPA used in the draft 

analysis.

9. Calculation of inferred monetized benefit values for Options 3a, 3b, and 4a.

10. Deletion of Section VIII.A.8 (“Consideration of the Proposed CCR Rule on the Analyses for the 

ELG Rulemaking”). This section was replaced with a new Section III.G.2 (“Intersection Between 

the Proposed ELG and Coal Combustion Residuals Rules”).

11. Addition of a new regulatory option (Option 4a). (Note: Also see Change #1)

12. Change in the preferred regulatory options for BAT and PSES. In the document submitted to 

OMB, Options 3 and 4 were co-proposed as preferred options for BAT and PSES. In the final 
document, Option 4 is no longer a preferred option for BAT and PSES. Option 3 remains a 

preferred option and Option 4a was also identified as a preferred option for BAT and PSES. 

(Note: see Change #2 regarding Options 3a and 3b)
*** E. O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

6560-50-P

EO12866_SteamElectricELG RIN 2040-AF14 NPRM_20130111

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 423

[EPA-HQ-OW-2009-0819. FRL-xxxx-xxxx. FRL- xx]

[EPA-HQ-RCRA-2013-0209]

RIN 2040-AF14

Effluent Limitations Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed Rule.

SUMMARY: EPA is proposing a regulation that would strengthen the 

controls on discharges from certain steam electric power plants 

by revising technology-based effluent limitations guidelines and 

standards for the steam electric power generating point source 

category. Steam electric power plants alone contribute at least 

50-60 percent of all toxic pollutants discharged to surface 

waters by all industrial categories currently regulated in the 

United States under the Clean Water Act. Furthermore, power 

plant discharges to surface waters are expected to increase as 

pollutants are increasingly captured by air pollution controls 

and transferred to wastewater discharges. Today’s proposal, if 

implemented, would significantly reduce the amount of toxic 

metals, nutrients, and other pollutants discharged to surface 

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

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waters from power plants. EPA is considering several regulatory 

options in this rulemaking and has identified twofour preferred 

alternatives. for regulation of discharges from existing 

sources. These twofour preferred alternatives differ in with 

respect to the scope of requirements that would be established 

for the discharge of applicable to existing discharges of 

pollutants found in two wastestreams from existing 

sources.generated at power plants. EPA estimates that the 

preferred options for today's proposed rule would annually 

reduce pollutant discharges by 1.630.47 billion to 3.342.62

billion pounds, reduce water use by 5450 billion to 158103

billion gallons, cost $572185 million to $1,381954 million, and 

would be economically achievable.

DATES: Comments on today’s proposed rule must be received on or 

before [insert date 60 days after publication in the Federal 

Register]. Persons wishing to request a public hearing regarding 

the proposed pretreatment standards must do so by [INSERT DATE –

APPROX 2 WKS AFTER PUBLICATION]. If a public hearing is 

requested, EPA will conduct a public hearing on the proposed 

pretreatment standards on [INSERT DATE – AT LEAST 30 DAYS AFTER 

PUBLICATION]July 9, 2013 at 9:30 a1:00 p.m. at [INSERT 

LOCATION]in the EPA East Building, Room 1153, 1201 Constitution 

Avenue, NW, Washington, DC.
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ADDRESSES: Submit your comments on the proposed rule, identified 

by Docket No. EPA-HQ-OW-2009-0819 by one of the following 

methods:

http:www.regulations.gov: Follow the on-line instructions 

for submitting comments.

Email: OW-Docket@epa.gov, Attention Docket ID No. EPA-HQOW-2009-0819.

Mail: Water Docket, U.S. Environmental Protection Agency, 

Mail code: 4203M, 1200 Pennsylvania Ave., NW., Washington, 

DC 20460. Attention Docket ID No. EPA-HQ-OW-2009-0819. 

Please include three copies. 

Hand Delivery: Water Docket, EPA Docket Center, EPA West 

Building Room 3334, 1301 Constitution Ave., NW, Washington, 

DC, Attention Docket ID No. EPA-HQ-OW-2009-0819. Such 

deliveries are only accepted during the Docket’s normal 

hours of operation, and you should make special 

arrangements for deliveries of boxed information by calling 

202-566-2426. 

ADDRESSES: Submit any comments on the Coal Combustion Residuals 

Rule issues discussed in Section III.D of this Federal Register 

Notice, identified by Docket ID No. EPA-HQ-RCRA-2013-0209, by 

one of the following methods:

http:www.regulations.gov: Follow the on-line instructions 

for submitting comments.

Email: RCRA-Docket@epa.gov, Attention Docket ID No. EPA-HQRCRA-2013-0209. In contrast to EPA’s electronic public 

docket, EPA’s e-mail system is not an ‘‘anonymous access’’ 

system. If you send an e-mail comment directly to the 

Docket without going through EPA’s electronic public 

docket, EPA’s e-mail system automatically captures your email address. E-mail addresses that are automatically 

captured by EPA’s e-mail system are included as part of the 

comment that is placed in the official public docket, and 

made available in EPA’s electronic public docket.

Fax: Comments on the CCR rule issue may be faxed to 202–

566–0272; Attention Docket ID No. EPA-HQ-RCRA-2013-0209.

Mail: Send your comments on the CCR rule issue to the 

Hazardous Waste Management System; Disposal Of Coal 
*** E. O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Combustion Residuals From Electric Utilities, Attention 

Docket ID No., EPA-HQ-RCRA-2013-0209, Environmental 

Protection Agency, Mailcode: 5305T, 1200 Pennsylvania Ave., 

NW., Washington, DC 20460. Please include a total of two 

copies.

Hand Delivery: Deliver two copies of your comments on the 

CCR rule issue discussed in this Federal Register to the 

Hazardous Waste Management System; Disposal Of Coal 

Combustion Residuals From Electric Utilities: Notice, 

Attention Docket ID No., EPA-HQ-RCRA-2013-0209, EPA/DC, EPA 

West, Room 3334, 1301 Constitution Ave., NW., Washington, 

DC 20460. Such deliveries are only accepted during the 

Docket’s normal hours of operation, and special 

arrangements should be made for deliveries of boxed 

information.

Instructions: Direct your comments to Docket No. EPA-HQ-OW2009-0819. EPA's policy is that all comments received will be 

included in the public docket without change and may be made 

available online at http://www.regulations.gov, including any 

personal information provided, unless the comment includes 

information claimed to be Confidential Business Information 

(CBI) or other information whose disclosure is restricted by 

statute. Do not submit information that you consider to be CBI 

or otherwise protected through www.regulations.gov or email. The 

www.regulations.gov website is an “anonymous access” system, 

which means EPA will not know your identity or contact 

information unless you provide it in the body of your comment. 

If you send an email comment directly to EPA without going 

through www.regulations.gov your email address will be 

automatically captured and included as part of the comment that 
*** E. O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 5 of 517

is placed in the public docket and made available on the 

Internet. If you submit an electronic comment, EPA recommends 

that you include your name and other contact information in the 

body of your comment and with any disk or CD-ROM you submit. If 

EPA cannot read your comment due to technical difficulties and 

cannot contact you for clarification, EPA may not be able to 

consider your comment. Electronic files should avoid the use of 

special characters, any form of encryption, and be free of any 

defects or viruses. 

Docket: All documents in the docket are listed in the 

www.regulations.gov index. A detailed record index, organized by 

subject, is available on EPA’s website at 

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

Although listed in the index, some information is not publicly 

available, e.g., 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 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 
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Public Reading Room is 202-566-1744, and the telephone number 

for the Water Docket is 202-566-2426.

Comments related to EPA’s current thinking, as described in 

Section III.D, regarding how a final RCRA Coal Combustion 

Residuals rule might be aligned and structured to account for 

any final requirements adopted under the ELGs for the Steam 

Electric Power Generating point source category must be 

submitted to Docket ID Number Docket ID: EPA-HQ-RCRA-2013-0209.

Pretreatment Hearing Information: If a public hearing is 

requested, EPA will conduct a public hearing on the proposed 

pretreatment standards on [INSERT DATE – AT LEAST 30 DAYS AFTER 

PUBLICATION]July 9, 2013 at 9:30 a1:00 p.m. in the EPA East 

Building, Room 1153, 1201 Constitution Avenue, NW.,, Washington, 

DC. No registration is required for this public hearing. During 

the pretreatment hearing, the public will have an opportunity to 

provide oral comment to EPA on the proposed pretreatment 

standards. EPA will not address any issues raised during the 

hearing at that time but these comments will be included in the 

public record for the rule. For security reasons, we request 

that you bring photo identification with you to the meeting. 

Also, if you let us know in advance of your plans to attend, it

will expedite the process of signing in. Seating will be 

provided on a first-come, first-served basis. Please note that

parking is very limited in downtown Washington, and use of 

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public transit is recommended. The EPA Headquarters complex is 

located near the Federal Triangle Metro station. Upon exiting 

the Metro station, walk east to 12th Street. On 12th Street, 

walk south to Constitution Avenue. At the corner, turn right 

onto Constitution Avenue and proceed to the EPA East Building

entrance.

FOR FURTHER INFORMATION CONTACT:

For further information on technical information, contact 

Jezebele Alicea-Virella, Engineering and Analysis Division, 

Telephone: 202-566-1755; Email: alicea.jezebele@epa.gov. For

further information on economic information, contact James 

Covington, Engineering and Analysis Division, Telephone: 202-

566-1034; Email: covington.james@epa.gov.

SUPPLEMENTARY INFORMATION: 

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
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This section is not intended to be exhaustive, but rather 

provides a guide for readers regarding entities likely to be 

regulated by this proposed action. Other types of entities that 

do not meet the above criteria could also be regulated. To 

determine whether your facility would be regulated by this 

proposed 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 and detailed further in Section V –

Scope/Applicability of the Proposed Rule, of this preamble. If 

you still have questions regarding the proposed applicability of 

this action to a particular entity, consult the person listed 

for technical information in the preceding FOR FURTHER 

INFORMATION CONTACT section.

How to Submit Comments

The public may submit comments in written or electronic 

form. (See the ADDRESSES section above.) Electronic comments 

must be identified by the Docket No. [EPA-HQ-OW-2009-0819] and 

must be submitted as a MS Word, WordPerfect, or ASCII text file, 

avoiding the use of special characters and any form of 

encryption. EPA requests that any graphics included in 

electronic comments also be provided in hard-copy form. EPA also 

will accept comments and data on disks in the aforementioned 

file formats. Electronic comments received on this notice may be 

Formatted: Keep with next
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filed online at many Federal Depository Libraries. No 

confidential business information (CBI) should be sent by email.

Supporting Documentation

The rule proposed today is supported by a number of 

documents including:

Technical Development Document for Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category (TDD), Document No. 

EPA-821-R-12-01213-002.

Environmental Assessment for the Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category (Environmental 

Assessment), Document No. EPA-821-R-12-01113-003.

Benefits and Cost Analysis for the Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category, Document No. EPA821-R-12-00913-004.

Regulatory Impact Analysis for Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric 

Power Generating Point Source Category (RIA), Document No. 

EPA-821-R-12-01013-005.

These documents are available in the public record for this 

rule and on EPA’s website at 

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

Overview

This preamble describes the terms, acronyms, and abbreviations 

used in this notice; the background documents that support these 

proposed regulations; the legal authority for the proposed rule; 

a summary of the options considered for the proposal; background 

information; and the technical and economic methodologies used 

by the Agency to develop these proposed regulations. In 

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addition, this preamble also solicits comment and data from the 

public. The following outline summarizes the organization of 

this document.

Table of Contents:

I. Legal Authority

II. Executive Summary of the Proposed Rule

A. Purpose of the Regulatory Action

B. Summary of Major Provisions of the Proposed Rule

C. Summary of Costs and Benefits

III. Background

A. Clean Water Act

B. Effluent Guidelines Program

1. Best Practicable Control Technology Currently Available 

(BPT)

2. Best Conventional Pollutant Control Technology (BCT)

3. Best Available Technology Economically Achievable (BAT)

4. Best Available Demonstrated Control Technology (BADCT)/New 

Source Performance Standards (NSPS)

5. Pretreatment Standards for Existing Sources (PSES)

6. Pretreatment Standards for New Sources (PSNS)

C. Steam Electric Effluent Guidelines Rulemaking History

D. Steam Electric Detailed Study

E. Clean Air Act (CAA) Rules

1. Mercury and Air Toxics Standards (MATS)

2. Cross-State Air Pollution Rule (CSAPR)

3. Greenhouse Gas Emissions for New Electric Utility 

Generating Units

F. Cooling Water Intake Structures

G. Coal Combustion Residuals (CCR) Proposed Rule

IV. Summary of Data Collection Activities

A. Questionnaire for the Steam Electric Power Generating 

Effluent Guidelines

1. Description of the Industry Survey Components

2. Identification of Potential Questionnaire Recipients

3. Questionnaire Recipient Selection

4. Questionnaire Responses

5. Questionnaire Review

B. Engineering Site Visits

C. Field Sampling Program

D. EPA and State Sources

E. Industry Data
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F. Technology Vendor Data

G. Other Sources

H. Economic Data

V. Scope/Applicability of the Proposed Rule

A. Facilities Subject to 40 CFR Part 423

B. Subcategorization

1. Age of Plant or Generating Unit

2. Geographic Location

3. Size

4. Fuel Type

VI. Industry Description

A. General Description of Industry

B. Steam Electric Process Descriptions and Wastewater Generation

1. Fly Ash and Bottom Ash Systems

2. FGD Systems

3. Flue Gas Mercury Control (FGMC) Systems

4. Combustion Residual Leachate from Surface Impoundments and 

Landfills

5. Gasification Processes

6. Metal Cleaning Wastes

7. Carbon Capture and Storage Systems

C. Control and Treatment Technologies

1. FGD Wastewater

2. Fly Ash Transport Water

3. Bottom Ash Transport Water

4. Combustion Residuals Leachate from Landfills and Surface 

Impoundments

5. Gasification Wastewater

6. Flue Gas Mercury Control (FGMC) Wastewater

7. Metal Cleaning Wastes

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. Proposed Regulation

A. Regulatory Options

1. BPT/BCT

2. Description of the BAT/NSPS/PSES/PSNS Options

3. Rationale for the Proposed Best Available Technology (BAT)

4. Rationale for the Proposed Best Available Demonstrated 

Control/NSPS Technology

5. Rationale for the Proposed PSES Technology

6. Rationale for the Proposed PSNS Technology

7. Consideration of Future FGD Installations on the Analyses 

for the ELG Rulemaking
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8. Consideration of the Proposed CCR Rule on the Analyses for 

the ELG Rulemaking

B. Timing of New Requirements

IX. Technology Costs and Pollutant Reductions

A. Methodology for Estimating Plant-Specific Costs

B. Methodology for Estimating Plant-Specific Pollutant 

Reductions

1. FGD Wastewater

2. Fly Ash and Bottom Ash

3. Combustion Residual Leachate

4. FGMC and Gasification Wastewaters and Nonchemical Metal 

Cleaning Wastes

C. Summary of National Engineering Costs and Pollutant 

Reductions for Existing Plants

X. Approach to Determine Long-Term Averages, Variability 

Factors, and Effluent Limitations and Standards

A. Criteria Used to Select Data as the Basis for the Limitations 

and Standards

B. Data Used As Basis of the Limitations and Standards

1. Data Selection for Each Technology Option

2. Combining Data from Multiple Sources Within a Plant

3. Data Exclusions

C. Overview of the Limitations and Standards

1. Objective

2. Selection of Percentiles

D. Calculation of the Limitations and Standards

1. Calculation of Option Long-Term Average

2. Calculation of Option Variability Factors and Limitations

3. Adjustment for Autocorrelation Factors

E. Long-Term Average, Variability Factors, and Limitations for 

Each Treatment Option

F. Engineering Review of Limitations and Standards

1. Comparison of Limitations to Effluent Data Used As the 

Basis for the Limitations

2. Comparison of the Limitations to Influent Data

XI. Economic Impact and Social Cost Analysis

A. Introduction

B. Annualized Compliance Costs

C. Social Costs

D. Economic Impacts

1. Screening-level Assessment of Impacts on Existing Plants 

and Parent Entities Incurring Compliance Costs 

Associated with this Proposed Rule

2. Assessment of the Impacts in the Context of Electricity 

Markets
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3. Summary of Economic Impacts for Existing Sources

4. Summary of Economic Impacts for New Sources

5. Assessment of Potential Electricity Price Effects

E. Employment Effects

1. Methodology

2. Findings

XII. Cost-Effectiveness Analysis

A. Methodology

B. Cost-Effectiveness Analysis for Direct Dischargers

C. Cost-Effectiveness Analysis for Indirect Dischargers

XIII. Environmental Assessment

A. Improvements in Surface Water and Ground Water Quality

B. Reduced Impacts to Wildlife

C. Reduced Human Health Cancer Risk

D. Reduced Threat of Non-Cancer Human Health Effects

E. Reduced Nutrient Impacts

F. Unquantified Environmental and Human Health Improvements

G. 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. Groundwater Quality Benefits From Reduced Groundwater 

Contamination

4. Market and Productivity Benefits (Benefits from Reduced 

Impoundment Failures)

5. Air-Related Benefits (Reduced Mortality and Avoided 

Climate Change Impacts)

6. Benefits from Reduced Water Withdrawals (Increased 

Availability of Groundwater Resources)

C. Total Monetized Benefits

D. Children’s Environmental Health

XV. Non-Water Quality Environmental Impacts

A. Energy Requirements

B. Air Pollution

C. Solid Waste Generation

D. Reductions in Water Use

XVI. Regulatory Implementation

A. Implementation of the Limitations and Standards

1. Timing

2. Legacy Wastes
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3. Compliance Monitoring

B. Analytical Methods

C. Upset and Bypass Provisions

D. Variances and Modifications

1. Fundamentally Different Factors (FDF) Variance

2. Economic Variances

3. Water Quality Variances

4. Removal Credits

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

1. Definition of Small Entities and Estimation of the Number 

of Small Entities Subject to Today’s Proposed ELGs

2. Statement of Basis

3. Certification Statement

D. Unfunded Mandates Reform Act (UMRA)

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

Appendix A: Definitions, Acronyms, and Abbreviations Used in 

This Notice

I. Legal Authority

EPA is proposing revisions to the effluent limitations 

guidelines and standards for the Steam Electric Power Generating 

Point Source Category (40 CFR 423) under the authority of 

Sections 301, 304, 306, 307, 308, 402, and 501 of the Clean 
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Water Act, 33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342, and 

1361.

II. Executive Summary of the Proposed Rule

A. Purpose of the Regulatory Action

The steam electric power generating point source category 

(i.e., steam electric industry) consists of plants that generate 

electricity from a process utilizing fossil or nuclear fuel in 

conjunction with a thermal cycle employing the steam/water 

system as the thermodynamic medium. The proposed regulations

would strengthen the controls on discharges from steam electric 

power plants by revising the technology-based effluent 

limitations guidelines and standards that apply to wastewater 

discharges to surface waters (i.e., direct discharges) and to 

publicly owned treatment works (i.e., indirect discharges to 

POTWs). The proposed requirements would significantly reduce the 

amount of metals, nutrients, and other pollutants discharged to 

surface waters from power plants. 

EPA is considering several options in this rulemaking and 

has identified twofour preferred alternatives. for regulation 

of discharges from existing sources. These twofour preferred 

alternatives propose the same requirements for most wastestreams 

but, as described below in Section II.B., differ in the 

requirements that would be established for the discharge 

ofdischarges associated with two wastestreams from existing 
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Page 16 of 517

sources. EPA also projects different levels of pollutant 

reduction and cost associated with these alternatives.

EPA estimates that the proposed rulepreferred regulatory 

options would reduce pollutant discharges by 1.630.47 billion to 

3.342.62 billion pounds annually, and reduce water use by 5450

billion to 158103 billion gallons per year. EPA predicts 

substantial environmental and ecological improvements would

result under the requirements being proposed todaypreferred 

regulatory options, along with reduced impacts to wildlife and 

human health.

The current regulations, which were last updated in 1982, 

do not adequately address the toxic pollutants discharged from 

the electric power industry, nor have they kept pace with 

process changes that have occurred over the last three decades. 

The development of new technologies for generating electric 

power (e.g., coal gasification) and the widespread 

implementation of air pollution controls (e.g., flue gas 

desulfurization (FGD), selective catalytic reduction (SCR), and 

flue gas mercury controls (FGMC)) have altered existing 

wastestreams or created new wastewater streams at many power 

plants. 

As a result, each year the pollutant discharges from this 

industry are increasing and alreadyin volume and total mass, and 

currently account for at least approximately 50-60 percent of 
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all toxic pollutants discharged into surface waters by all 

industrial categories currently regulated under the CWA. See 

Section 3.2.2 of the Environmental Assessment for the Proposed 

Effluent Limitations Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category (Environmental 

Assessment) – EPA 821-R-13-003. The main pollutants of concern 

for these discharges include metals (e.g., mercury, arsenic, 

selenium), nitrogen, and total dissolved solids (TDS). ThereAs 

discussed in Section XIII and the Environmental Assessment 

report, there are numerous documented instances of environmental 

impact associated with these power plant discharges, such as 

harm to human health, harm to aquatic life, contamination of 

sediment, and detrimental impacts to wildlife. Water quality 

modeling, in addition to the documented damage cases,

corroborates these impacts and indicates that the toxic 

discharges are a significant source of widespread aquatic-life 

impacts, and a source of increased cancer and non-cancer risks 

in humans, and a source of toxic metal bioaccumulation in 

wildlife. These discharges also contribute large cumulative 

nutrient pollutant loads to sensitive watersheds, upsetting the 

natural balance of such waterbodies as the Great Lakes and the 

Chesapeake Bay. 

Today’s proposed rule would reduce current toxic and 

nutrientother pollutant discharges and their associated impacts.

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In general, depending on the option, the proposed rule would 

establish new or additional requirements for wastewaters

associated with the following processes and byproducts: flue gas 

desulfurization, (FGD), fly ash, bottom ash, flue gas mercury 

control, combustion residual leachate from landfills and surface 

impoundments, nonchemical metal cleaning wastes, and 

gasification of fuels such as coal and petroleum coke. In 

addition to the proposed requirements, as part of this 

rulemaking EPA is considering establishing best management 

practices (BMP) requirements that would apply to surface 

impoundments containing coal combustion residuals (e.g., ash 

ponds, FGD ponds). EPA is also considering establishing a 

voluntary program that would provide incentives for existing 

power plants that dewater and close their surface impoundments 

containing combustion residuals, and for power plants that 

eliminate the discharge of all process wastewater (excluding 

cooling water discharges).

The major provisions of the proposed rule are summarized 

below. In addition, the proposed requirements and the 

technologies that serve as the basis for these requirements are 

explained in more detail in Section VIII of this preamble.

B. Summary of Major Provisions of the Proposed Rule

Depending on the option, EPA is proposing to revise or 

establish Best Available Technology Economically Achievable 
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(BAT), New Source Performance Standards (NSPS), Pretreatment 

Standards for Existing Sources (PSES) and Pretreatment Standards 

for New Sources (PSNS) that apply to discharges of pollutants 

found in the following wastestreams: FGD wastewater, fly ash 

transport water, bottom ash transport water, combustion residual 

leachate from landfills and surface impoundments containing CCR,

nonchemical metal cleaning wastes, and wastewater from flue gas 

mercury control (FGMC) systems and gasification systems.

EPA is proposing twohas identified four preferred 

alternatives for regulation of existing discharges in the 

proposed rule. (and it has identified one preferred alternative 

for regulation of new sources). These twofour preferred 

alternatives differ in that the second alternative would 

establish more environmentally protective BAT and PSES 

requirements for discharges of bottom ash transport water and 

combustion residual leachate from existing sources.are 

summarized below.

Discharges directly to surface water from existing facilities –-

For existing sources that discharge directly to surface water, 

with the exception of oil-fired generating units and small 

generating units (i.e., 50 MW or smaller), under the firstone

preferred alternative for BAT (referred to as Option 33a in this 

proposal) the proposed rule would establish BAT for wastestreams 

from these sources that include:

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spacing: Double

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Numeric effluent limits for mercury, arsenic, selenium, and 

nitrate-nitrite in discharges of FGD wastewater;

“Zero discharge” effluent limit for all pollutants in fly 

ash transport water and wastewater from flue gas mercury 

control systems;

Numeric effluent limits for mercury, arsenic, selenium and 

TDS in discharges of wastewater from gasification 

processes; 

Numeric effluent limits for copper and iron in discharges 

of nonchemical metal cleaning wastes1; and

Effluent limits for bottom ash transport water and 

combustion residual leachate from landfills and surface 

impoundments containing combustion residuals that are equal 

to the current Best Practicable Control Technology 

Currently Available (BPT) effluent limits for these 

discharges (i.e., numeric effluent limits for TSS and oil 

and grease)..

Under the second preferred alternative for BAT (referred to 

as Option 4Under a second preferred alternative for BAT 

(referred to as Option 3b in this proposal), the proposed rule 

would establish numeric effluent limits for mercury, arsenic, 

selenium, and nitrate-nitrite in discharges of FGD wastewater 

from certain steam electric facilities (those with a total 

plant-level wet scrubbed capacity of 2,000 MW or greater2). All 

other proposed Option 3b requirements are identical to the 

proposed 3a requirements described above.

Under a third preferred alternative for BAT (referred to as 

Option 3 in this proposal), the proposed rule would establish 

 

1 As described in Section VIII, EPA is proposing to exempt from new copper and 

iron BAT limitations any existing discharges of nonchemical metal cleaning 

wastes that are currently authorized without iron and copper limits. For 

these discharges, BAT limits would be set equal to BPT limits applicable to 

low volume wastes.

2 Total plant-level wet scrubbed capacity is calculated by summing the 

nameplate capacity for all of the units that are serviced by wet FGD systems.
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numeric effluent limits for mercury, arsenic, selenium, and 

nitrate-nitrite in discharges of FGD wastewater, with the 

exception of small generating units (i.e., 50 MW or smaller). 

All other proposed Option 3 requirements are identical to the 

proposed Option 3a requirements described above.

Under a fourth preferred alternative for BAT (referred to 

as Option 4a in this proposal), the proposed rule would 

establish “zero discharge” effluent limits for all pollutants in 

bottom ash transport water and establish numeric effluent limits 

, with the exception of all generating units with a nameplate 

capacity of 400 MW or less (for mercury and arsenic in those 

generating units that are less than or equal to 400 MW, the 

proposed rule would set BAT equal to BPT for discharges of 

combustion residuals leachate.pollutants found in the bottom ash 

transport water). All other proposed Option 44a requirements are 

identical to the proposed Option 3 requirements described above.

In addition, for oil-fired generating units and small 

generating units (i.e., 50 MW or smaller3) that are existing 

sources and discharge directly to surface waters, under boththe 

four preferred alternatives for regulation of existing sources,

the proposed rule would establish effluent limits (BAT) equal to 

 

3 As described in Section VIII, one of the preferred options would increase 

this threshold for purposes of discharges of pollutants in bottom ash 

transport water only, to 400 MW or less.
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the current BPT effluent limits for the wastestreams listed 

above. 

Discharges to POTWs from existing facilities – For 

discharges from existing sources to POTWs, EPA is proposing to 

establish PSES that are equal to the proposed BAT, with the 

following exceptions:

Under both Options 3 and 4, numericNumeric standards for 

discharges of nonchemical metal cleaning wastes would be 

established only for copper4;

Under OptionOptions 3a, 3b, and 3 for PSES, EPA is not 

proposing to establish pretreatment standards for 

discharges of bottom ash transport water. Under Option 4a, 

EPA is not proposing to establish pretreatment standards 

for discharges of bottom ash transport water and leachate 

from landfills and surface impoundments containing 

combustion residuals (under Option 4, PSES would be set

equal to the Option 4 BAT for these wastestreams);for 

generating units with a nameplate capacity of 400 MW or 

less5; and

Other than the pretreatment standards for nonchemical metal 

cleaning wastes, EPA is not proposing to establish 

pretreatment standards for existing sources for discharges 

from existing oil-fired units and small generating units 

(i.e., 50 MW or smaller).

Discharges directly to surface water from new sources – For 

all generating units that are new sources and discharge directly 

to surface waters, including oil-fired generating and small 

 

4 As described in Section VIII, EPA is proposing to exempt from new copper 

PSES standards any existing discharges of nonchemical metal cleaning wastes 

that are currently authorized without copper limits. For these discharges, 

the regulations would not specify PSES. 

5This is because, as explained in Section VII, EPA generally does not 

establish pretreatment standards for conventional pollutants (e.g., TSS and 

oil and grease) because POTWs are designed to treat these conventional 

pollutants.
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generating units, the proposed rule would establish NSPS that 

include:

Numeric standards for mercury, arsenic, selenium, and 

nitrate-nitrite in discharges of FGD wastewater;

Maintaining the current “zero discharge” standard for all 

pollutants in fly ash transport water for direct 

dischargers (NSPS);;

Establishing “zero discharge” standards for all pollutants 

in bottom ash transport water and wastewater from flue gas 

mercury control systems;

Numeric standards for mercury, arsenic, selenium, and TDS 

in discharges of wastewater from gasification processes;

Numeric standards for mercury and arsenic in discharges of 

combustion residual leachate; and

Numeric standards for TSS, oil and grease, copper, and iron 

in discharges of nonchemical metal cleaning wastes.

Discharges to POTWs from new sources – For generating units 

that are new sources and discharge to POTWs, including oil-fired 

generating and small generating units, EPA is proposing to 

establish PSNS that are equal to the proposed NSPS, except that 

the PSNS would also establish a “zero discharge” standard for 

all pollutants in fly ash transport water (the current NSPS 

already includes a zero discharge standard for pollutants in fly 

ash transport water), and the PSNS would not include numeric 

standards for TSS or, oil and grease, or iron in discharges of 

nonchemical metal cleaning wastes. The proposed PSNS would apply 

to discharges to POTWs from all generating units that are new 

sources, including oil-fired generating and small generating 

units.
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Additional details about the proposed effluent limitations 

and standards are described in Sections VIII and X of this 

preamble.

C. Summary of Costs and Benefits

Table II-1 summarizes the benefits6 and social costs for the 

twofour preferred alternatives for this proposed rule, at 3 

percent and 7 percent discount rates. Sections XI and XIV of 

this preamble provide additional information regarding the costs 

and the benefits and costs for the proposed rule. Note that 

although Table II-1 includes the costs associated with BMPs 

being considered for the proposed rule, it does not similarly 

include the benefits that would result from implementing

theassociated with these BMPs. The BMPs under consideration for 

the ELGs would reduce the probability of impoundment failures 

and therefore would be expected to increase the benefits of the 

proposed ELGs. EPA intends to include such benefits in its 

analyses for the final rule, should EPA ultimately include the 

BMPs as part of the final ELGs.

 

6EPA calculated benefits for some of the options considered for this proposal 

including Option 3 and Option 4. For others (3a, 3b, and 4a), EPA inferred 

the benefits based on the pollutant loading reductions (lbs.) relative to the 

pollutant loading reductions of Option 3 for which EPA analyzed and 

calculated benefits. See Section XIV for details.

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It is important to note that although point estimates are 

provided in this table, the benefits estimates rely on complex 

models that include a variety of assumptions, each of which 

introduces considerable uncertainty into these estimates. This 

uncertainty is discussed in the Benefits and Cost Analysis for 

the Proposed Effluent Limitations Guidelines and Standards for 

the Steam Electric Power Generating Point Source Category – EPA 

821-R-13-004 (BCA). EPA requests comment on the reasonableness 

of these assumptions, additional data that may be available to 

reduce uncertainties in these estimates, and approaches to 

characterize the remaining uncertainty.

Table II-1: Total Monetized Annualized Benefits and Costs for 

the Proposed Rule (Millions; 2010$)

Preferred 

Regulatory 

Alternatives

Total Monetized Social 

Benefits Total Social Costs

3% 7% 3% 7%

Option 3a for 

Existing Sources; 

Option 4 for New 

Sources

139.4a 104.8a $185.2 $164.5

Option 3b for 

Existing Sources; 

Option 4 for New 

Sources

205.5a 153.0a $281.4 $257.2

Option 3 for 

Existing Sources;

Option 4 for 

New Sources

$464.5311.7 $358.5230.4 $572.10 $545.3

Option 4a for 

Existing

Sources; Option 

4 for Existing 

and New Sources

$1,005.1482.5a $758.5424.8a $954.1,381.2 $1,323.2914.7

a. EPA did not estimate benefits for Options 3a, 3b and 4a. EPA inferred 

benefits for Options 3a, 3b, and 4a for illustrative purposes using 

elements of the more rigorous analysis done to estimate benefits for 

Options 3 and 4. See Section XIV for details.

Formatted Table

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III. Background

A. Clean Water Act

Congress passed the Federal Water Pollution Control Act 

Amendments of 1972, also known as the Clean Water Act (CWA), to 

“restore and maintain the chemical, physical, and biological 

integrity of the Nation’s waters.” 33 U.S.C. 1251(a). 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, discharges may be authorized through a National 

Pollutant Discharge Elimination System (NPDES) permit. The CWA 

also authorizes EPA to establish national technology-based 

effluent limitations guidelines and standards (ELGs) for 

discharges from different categories of point sources, such as 

industrial, commercial, and public sources.

The CWA authorizes EPA to promulgate nationally applicable 

pretreatment standards that restrict pollutant discharges from 

facilities that discharge wastewater indirectly through sewers 

flowing to publicly owned treatment works (POTWs), as outlined 

in sections 307(b) and (c), 33 U.S.C. 1317(b) and (c). EPA 

establishes national pretreatment standards for those pollutants 

in wastewater from indirect dischargers that may pass through, 
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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 (i.e., 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 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 guideline or new source performance standard 

(CWA section 402(a)(1)(B), 33 U.S.C. 1342(a)(1)(B)). Additional 

limitations based on water quality standards are also required 

to be included in the permit in certain circumstances. CWA 

section 301(b)(1)(C), 33 U.S.C. 1311(b)(1)(C). The ELGs are 

established by regulation for categories of industrial 
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dischargers and are based on the degree of control that can be 

achieved using various levels of pollution control technology.

EPA promulgates national ELGs for major industrial 

categories for three classes of pollutants: (1) conventional 

pollutants (i.e., total suspended solids, oil and grease, 

biochemical oxygen demand (BOD5), fecal coliform, and pH), as 

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

pollutants (e.g., toxic metals such as arsenic, mercury, 

selenium, and chromium; toxic organic pollutants such as 

benzene, benzo-a-pyrene, phenol, and naphthalene), as outlined 

in section 307(a) of the Act, 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 total dissolved solids).

B. Effluent Guidelines Program

EPA develops effluent guidelines that are technology-based 

regulations for a category of dischargers. EPA bases these 

regulations on the performance of 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 plansplants and processes, and other 

improvements in technology, taking into account the cost of 
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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 

(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 (plants that discharge directly to surface waters), 

and two standards applicable to indirect dischargers (plants 

that discharge to POTWs), described in greater detail below.

1. Best Practicable Control Technology Currently Available (BPT)

Traditionally, EPA defines BPT effluent limitations based 

on the average of the best performances of facilities within the 

industry, grouped to reflect various ages, sizes, processes, or 

other common characteristics. EPA may promulgate BPT effluent 

limits 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). 
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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 (BCT) 

The 1977 amendments to the CWA require EPA to identify 

additional levels of effluent reduction for conventional 

pollutants associated with BCT technology for discharges from 

existing industrial point sources. In addition to other factors 

specified in section 304(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 in July 9, 1986 (51 FR 

24974). Section 304(a)(4) designates the following as 

conventional pollutants: BOD5, total suspended solids (TSS), 

fecal coliform, pH, and any additional pollutants defined by the 

Administrator as conventional. The Administrator designated oil 

and grease as an additional conventional pollutant on July 30, 

1979 (44 FR 44501; 40 CFR 401.16).

3. Best Available Technology Economically Achievable (BAT) 

BAT represents the second level of stringency for 

controlling direct discharge of toxic and nonconventional 

pollutants. In general, BAT ELGs represent the best available 
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economically achievable performance of facilities in the 

industrial subcategory or category. 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, and non-water quality 

environmental impacts, including energy requirements and such 

other factors as the Administrator deems appropriate. CWA 

section 304(b)(2)(B), 33 U.S.C. 1314(b)(2)(B). The Agency 

retains considerable discretion in assigning the weight to be 

accorded these factors. Weyerhaeuser Co. v. Costle, 590 F.2d 

1011, 1045 (D.C. Cir. 1978). Generally, EPA determines economic 

achievability on the basis of the effect of the cost of 

compliance with BAT limitations on overall industry and 

subcategory financial conditions. BAT may reflect the highest 

performance in the industry and 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 plant studies, or foreign plants. American Paper 

Inst. v. Train, 543 F.2d 328, 353 (D.C. Cir. 1976); American 

Frozen Food Inst. v Train, 539 F.2d 107, 132 (D.C. Cir. 1976). 
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BAT may be based upon process changes or internal controls, even 

when these technologies are not common industry practice. See 

American Frozen Foods, 539 F.2d at 132, 140; Reynolds Metals Co. 

v. EPA, 760 F.2d 549, 562 (4th Cir. 1985); California & Hawaiian 

Sugar Co. v. EPA, 553 F.2d 280, 285-88 (2nd Cir. 1977).

4. Best Available Demonstrated Control Technology (BADCT)/New 

Source Performance Standards (NSPS)

NSPS reflect effluent reductions that are achievable based 

on the best available demonstrated control technology (BADCT). 

Owners of new facilities have the opportunity to install the 

best and most efficient production processes and wastewater 

treatment technologies. As a result, NSPS should represent the 

most stringent controls attainable through the application of 

the 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 (PSES)

Section 307(b), 33 U.S.C. 1317(b), of the Act calls for EPA 

to issue 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 
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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. 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 (PSNS)

Section 307(c), 33 U.S.C. 1317(c), of the Act calls for EPA 

to promulgate PSNS. Such pretreatment standards must prevent the 

discharge of any pollutant into a POTW that may interfere with, 

pass through, or may otherwise be incompatible with the POTW. 

EPA promulgates PSNS based on best available demonstrated 

control technology (BADCT) for new sources. New indirect 

dischargers have the opportunity to incorporate into their 

facilities the best available demonstrated technologies. The 

Agency typically considers the same factors in promulgating PSNS 

as it considers in promulgating NSPS.

C. Steam Electric Effluent Guidelines Rulemaking History

EPA promulgated BPT, BAT, NSPS, and PSNS for the steam 

electric point source category on October 8, 1974 (39 FR 36186, 

as amended at 40 FR 7095, February 19, 1975; 40 FR 23987, June 
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4, 1975) (the "1974 regulations"). The 1974 regulations 

controlled two basic kinds of discharges from power plants: (1) 

thermal discharges (discharges of heat) and (2) pollutant 

discharges (e.g., discharges of chlorine, polychlorinated 

biphenyls (PCBs), and suspended solids). EPA promulgated nonthermal pollutant limitations applicable to discharges from the 

following wastestreams: once-through cooling water, cooling 

tower blowdown, bottom ash transport water, fly ash transport 

water, boiler blowdown, metal cleaning wastes, low volume 

wastes, and material storage and construction site runoff 

(including coal pile runoff).

On July 16, 1976, the U.S. Court of Appeals for the Fourth 

Circuit remanded the following provisions of the 1974 

regulations: (1) the thermal limitations, (2) the NSPS for fly 

ash transport water, (3) the rainfall runoff limitations for 

material storage and construction site runoff, and (4) the BPT 

variance clause. All other provisions of the regulations were 

upheld. Appalachian Power v. Train, 545 F.2d 1351, 1378 (4th 

Cir. 1976). EPA repromulgated the coal pile runoff regulations 

in 1980. 45 FR 37432 (June 3, 1980).

EPA promulgated PSES on March 23, 1977 (42 FR 15695) 

applicable only to indirect discharges of copper present in 

metal cleaning wastes and PCBs and oil and grease for all 

wastestreams.
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On November 19, 1982, EPA revised and supplemented the 

effluent limitations guidelines and standards for BCT, BPT, BAT, 

BADCT/NSPS, PSES, and PSNS (47 FR 52290). Under the 1982 

revisions, EPA reserved BCT limitations for all wastestreams and 

withdrew the BAT limitations for TSS and oil and grease from all 

wastestreams because those pollutants are properly regulated 

under BCT, instead of BAT. The rule also made revisions to the 

following effluent limitations guidelines and standards: BAT and 

NSPS for once-through cooling water; BAT, NSPS, PSES, and PSNS 

for cooling tower blowdown; NSPS and PSNS for fly ash transport 

water; NSPS for bottom ash transport water; and PSES and PSNS 

for chemical metal cleaning wastes. Finally, the rule revised 

the definition of low volume wastes to include boiler blowdown 

and withdrew the separate regulation for boiler blowdown.

D. Steam Electric Detailed Study

Section 304 of the CWA requires EPA to periodically review 

all effluent limitations guidelines and standards to determine 

whether revisions are warranted. In addition, Section 304(m) of 

the CWA requires EPA to develop and publish, biennially, a plan 

that establishes a schedule for reviewing and revising

promulgated national effluent guidelines required by Section 

304(b) of the CWA. During the 2005 annual review of the existing 

effluent guidelines for all categories, EPA identified the 

regulations governing the steam electric power generating point 
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Page 36 of 517

source category for possible revision. At that time, publicly 

available data reported through the NPDES permit program and the 

Toxics Release Inventory (TRI) indicated that the industry 

ranked high in discharges of toxic and nonconventional 

pollutants. Because of these findings, EPA initiated a more 

detailed study of the category to determine if the effluent 

guidelines should be revised. (See “Steam Electric Power 

Generating Point Source Category: Final Detailed Study Report” 

(EPA 821-R-09-008) at 

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

During the detailed study, EPA collected data about the 

industry in several ways. EPA conducted site visits and sampled 

wastewater at steam electric power plants, and EPA distributed a

questionnaire to collect data from nine companies. EPA also 

reviewed numerous publicly available sources of data and 

coordinated with and solicited data from EPA program offices and

other government organizations (e.g., state groups and 

permitting authorities), as well as industry, environmental 

groups, and other stakeholders.

As part of the detailed study, EPA evaluated a range of 

wastestreams and processes associated with the industry, but it 

ultimately focused largely on discharges associated with coal 

ash handling operations and wastewater from FGD air pollution 

control systems because these sources are responsible for a 
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significant fractionthe majority of the toxic pollutants 

currently discharged by steam electric power plants. EPA also 

identified several wastestreams that are relatively new to the 

industry (e.g., carbon capture wastewater), and wastestreams for 

which there was little characterization data at the time of the 

detailed study (e.g., gasification wastewater).

During the study, EPA found that the use of wet FGD systems 

(the kind of systems that generate discharges) to control sulfur 

dioxide (SO2) air emissions has increased significantly since the 

last revision of the effluent guidelines in 1982. Moreover, 

their useMoreover, based on industry announcements and modeling 

conducted for Clean Air Act rulemakings, the use of wet FGD 

systems is projected to continue to increase in the next decade 

as power plants take steps to address federal and state air 

pollution control requirements. EPA also found that FGD 

wastewaters generally contain significant levels of metals and 

other pollutants and that treatment technologies are available 

to treat these pollutants in FGD wastewater; however, most 

plants use only surface impoundments (e.g., settling ponds)

designed primarily to remove suspended solids from FGD 

wastewater.

EPA found that technologies that do not use water to 

transport ash are available for handling the fly ash (a 

combustion residual of fine ash particles entrained in the flue 
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gases) generated at plants, and that such technologies do not 

generate nor discharge wastewater associated with handling fly 

ash (i.e., fly ash transport water). Most of these systems are 

operated at newer electric generating units because the current 

NSPS regulations, which were promulgated in 1982, prohibit the 

discharge of pollutants in fly ash transport water. Many older 

generating units have also converted to dry fly ash handling 

systems that use air (i.e., pneumatic systems that use air 

pressure and/or vacuum) to transport the fly ash to storage 

silos instead of using water to sluice the ash (i.e., pump as a 

mixture of water and ash) to surface impoundments. As a result, 

over 80 percent of existing plants use dry fly ash handling. 

For further information, see Section 4.3.1 of the Technical 

Development Document for Proposed Effluent Limitations 

Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category (TDD) – EPA 821-R-13-002.

Additionally, there are technologies available for handling 

the bottom ash (i.e., a combustion residual of heavier ash 

particles collected at the bottom of a boiler) that either do 

not use water to transport the bottom ash away from the boiler 

or that manage the transport water in a manner (i.e., closedloop) that eliminates the need to discharge bottom ash transport 

water to surface water. Neither of these approaches discharge 

wastewater associated with transporting bottom ash. In fact, 
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some of these technologies do not even generate bottom ash 

transport water. EPA estimates that by the time the final rule 

is promulgated, approximately 45 percent of plants will use dry 

bottom ash handling systems or will not discharge bottom ash 

transport water.

From information obtained during the detailed study, EPA 

found that the fly ash and bottom ash transport waters generated 

from wet systems at coal-fired power plants are created in large 

quantities and contain significant concentrations of metals, 

including arsenic, selenium and mercury. Additionally, EPA 

determined that some of the metals are present primarily in the 

dissolved phase, and generally are not removed in the surface 

impoundments that are used to treat these wastestreams to meet 

the current BPT limits for TSS and oil and grease. Based on the

record, EPA found that there are technologies readily available 

to reduce or eliminate the discharge of pollutants contained in 

fly ash and bottom ash transport water.

Finally, the information obtained during the study 

indicates that FGD and ash transport wastewaters contain 

pollutants that can have detrimental impacts to the environment. 

EPA reviewed publicly available data and found documented 

environmental impacts that were attributable to discharges from 

surface impoundments or discharges from leachate generated from 

landfills containing combustion residues. EPA found that there 
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are a number of pollutants present in wastewaters generated at 

coal-fired power plants that can impact the environment, 

including metals (e.g., arsenic, selenium, mercury), TDS, and 

nutrients. The primary routes by which combustion wastewater 

harms the environment are discharges or spills to surface 

waters, leaching to ground water, and by surface impoundments 

and constructed wetlands acting as attractive nuisances that 

increase wildlife exposure to the pollutants contained in the 

systems. The interaction of combustion wastewaters with the 

environment has caused a wide range of harm to aquatic life.

Overall, from the detailed study, EPA found that the 

industry is generating new wastestreams that during the previous 

rulemakings either were not evaluated or were evaluated to only 

a limited extent due to insufficient data. Such wastestreams 

include FGD wastewater, FGMC wastewater, carbon capture 

wastewater, and gasification wastewaters. EPA also found that 

these wastestreams, as well as other combustion-related 

wastestreams at power plants (e.g., fly ash and bottom ash 

transport water, leachate) contain pollutants in concentrations 

and mass loadings that are causing documented environmental 

impacts and that treatment technologies are available to reduce 

or eliminate the pollutant discharges. For further information, 

see Section 6 of the Steam Electric Power Generating Point 
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Source Category: Detailed Study is available online at 

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

Based on the findings from the detailed study, which EPA 

issued in 2009, EPA began taking steps to revise the steam 

electric power generating effluent limitations guidelines and 

standards. The Steam Electric Power Generating Point Source 

Category: Detailed Study is available online at 

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

E. Clean Air Act (CAA) Rules

1. Mercury and Air Toxics Standards (MATS)

When the CAA was amended in 1990, EPA was directed to 

control mercury and other hazardous air pollutants from major 

sources of emissions to the air. For power plants using fossil 

fuels, the amendments required EPA to conduct a study of 

hazardous air pollutant emissions. CAA Section 112(n)(1)(A). The 

CAA amendments also required EPA to consider the study and other 

information and to make a finding as to whether regulation was 

appropriate and necessary. In 2000, the Administrator found that 

regulation of hazardous air pollutants, including mercury, from 

coal- and oil-fired power plants was appropriate and necessary.

65 FR 79825 (Dec. 20, 2000).

EPA published the final MATS rule on February 16, 2012. 77 

FR 9304. The rule established standards that will reduce

emissions of heavy metals,hazardous air pollutants including
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metals (e.g., mercury, arsenic, chromium, and nickel,) and acid 

gases, including (e.g., hydrochloric acid and, hydrofluoric 

acid.). Steam electric power plants may use any number of 

practices, technologies, and strategies to meet the new emission 

limits, including using wet and dry scrubbers, dry sorbent 

injection systems, activated carbon injection systems, and 

fabric filters. 

2. Cross-State Air Pollution Rule (CSAPR)

On July 6, 2011, EPA promulgated the CSAPR in 2011 to

require 2728 states in the eastern half of the United States to 

significantly improve air quality by reducing power plant 

emissions of sulfur dioxide, nitrogen oxides (NOx) and/or ozoneseason NOx that cross state lines and significantly contribute 

to ground-level ozone and/or fine particle pollution problems in 

other states. Subsequently, the Agency issued a supplemental 

rule in the CSAPR ozone-season NOx program. The emissions of 

sulfur dioxide, NOx and ozone-season NOx addressed by these 

rulesthe CSAPR react in the atmosphere to form PM2.5 and groundlevel ozone and are transported long distances, making it 

difficult for a number of states to meet the national clean air 

standards that Congress directed EPA to establish to protect 

public health. The U.S. Court of Appeals for the D.C. Circuit 

stayed the CSAPR on December 30, 2011, and on August 21, 2012, 

issued an opinion vacating the rule and ordering EPA to continue 
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administering the Clean Air Interstate Rule. EME Homer City 

Generation, L.P. v. EPA, 696 F.3d 7 (D.C.Cir. 2012). On March 

29, 2013, the United States filed a petition asking the Supreme 

Court to review the D.C. Circuit decision.

3. Greenhouse Gas Emissions for New Electric Utility Generating 

Units

By notice datedOn April 13, 2012, the EPA proposed new 

source standards of performance under CAA section 111 for 

emissions of carbon dioxide for fossil-fuel-fired electricity 

generating units. 77 FR 22392. The proposed requirements, which 

apply only to new sources, would require new plants greater than 

25 megawatts (MW) to meet an output-based standard of 1,000 

pounds of carbon dioxide per MW-hour of electricity generated.

EPA based this proposed standard on the performance of natural 

gas combined cycle technology because EPA and others project 

that even without this rule, for the foreseeable future, new 

fossil-fuel-fired power plants will be built with that 

technology. New coal- or petroleum coke-fired generating units 

could meet the standard by using carbon capture and storage of 

approximately 50 percent of the carbon dioxide in the exhaust 

gas when the unit begins operating or by later installing more 

effective carbon capture and storage to meet the standard on 

average over a 30-year period. EPA is evaluating the public 

comments received on the proposal and has not determined a 
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schedule at this time for taking final action on the proposed

rule.

F. Cooling Water Intake Structures 

Section 316(b) of the CWA, 33 U.S.C. 1326(b), requires that 

standards applicable to point sources under section 301 and 306 

of the Act require that the location, design, construction, and 

capacity of cooling water intake structures reflect the best

technology available to minimize adverse environmental impacts.

Each year, these facilities withdraw large volumes of water from 

lakes, rivers, estuaries or oceans for use in their facilities.

In the process, these facilities remove billions of aquatic 

organisms from waters of the United States each year, including 

fish, fish larvae and eggs, crustaceans, shellfish, sea turtles, 

marine mammals, and other aquatic life. The most significant 

effects of these withdrawals are on early life stages of fish 

and shellfish through impingement (being pinned against intake 

screens or other parts at the facility) and entrainment (being 

drawn into cooling water systems).

In November 2001, EPA took final action on regulations for 

cooling water intake structures at new facilities withthat have

a design intake flow greater than 2 million gallons per day 

(MGD),) and that have at least one cooling water structure that 

uses at least 25 percent of which is usedthe water it withdraws

for cooling purposes. See 40 CFR 125.81. EPA’s requirements 
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provide a two-track approach. Under Track 1, the intake flow at

facilities that withdraw greater than 10 MGD is restricted to a 

level commensurate with the level that may be achieved by use of 

a closed-cycle recirculating cooling system. Facilities 

withdrawing greater than 10 MGD located in areas where fisheries 

need additional protection must also use technology or 

operational measures to further minimize impingement mortality 

and entrainment. For facilities with intakes of less than 10 

MGD, the cooling water intake structures may not exceed a fixed 

intake screen velocity and the quantity of intake is restricted. 

Under Track 2, a facility may choose to demonstrate to the 

permitting authority that other technologies will reduce the 

level of adverse environmental impacts to a level that would be 

achieved under Track 1.

In March 2011, EPA proposed standards to reduce injury and 

death of fish and other aquatic life caused by cooling water 

intake structures at existing power plants and manufacturing 

facilities. The proposed rule would subject existing power 

plants and manufacturing facilities withdrawing in excess of 2 

MGD of cooling water to an upper limit on the number of fish 

destroyed through impingement, as well as site-specific 

entrainment mortality standards. Certain plants that withdraw 

very large volumes of water would also be required to conduct 

studies for use by the permit writer in determining site-
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specific entrainment controls for such facilities. Finally, 

under the proposed rule, new generating units at existing power 

plants would be required to reduce the intake of cooling water 

associated with the new unit, to a level whichthat could be 

attained by using a closed-cycle cooling system. EPA is 

continuing analysis and is in the process of addressing comments 

and finalizing the rule. 

G. Coal Combustion Residuals (CCR) Proposed Rule

CCRs are residues from the combustion of coal in steam 

electric power plants and include materials such as coal ash 

(fly ash and bottom ash) and FGD wastes. CCRs are currently 

exempt from the requirements of Subtitle C of the Resource 

Conservation and Recovery Act (RCRA), which governs the 

disposition and management of hazardous wastes. Potential 

environmental concerns regarding the management and disposal of 

CCR include pollution leaching from surface impoundments and 

landfills contaminating ground water and natural resource 

damages and risks to human health caused by structural failures 

of surface impoundments, like that which occurred at the 

Tennessee Valley Authority’s plant in Kingston, Tennessee, in 

December 2008. The spill, which flooded more than 300 acres of 

land with CCRs and contaminated the Emory and Clinch rivers, 

emphasized the need for national standards to address risks 

associated with the disposal of CCRs.
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1. Summary of Proposed CCR Rule

On June 21, 2010, EPA co-proposed regulations that included 

two approaches to regulating the disposal of CCRs generated by 

electric utilities and independent power producers. Under one 

proposed approach, EPA would list these residuals as “special 

wastes,” when destined for disposal in landfills or surface 

impoundments, and would apply the existing regulatory 

requirements established under Subtitle C of RCRA to such 

wastes. Under the second proposed approach, EPA would establish 

new regulations applicable specifically to CCRs under subtitle D 

of RCRA, the section of the statute applicable to solid (i.e., 

non-hazardous) wastes. Under both approaches, CCRs that are 

beneficially used would remain exempt under the Bevill 

exclusion.

EPA has not yet taken final action on the proposed CCR 

regulations. Certain aspects of the CCR rulemaking are discussed 

in today’s notice for purposes of better understanding the 

analyses underlying today’s proposed revisions to the steam 

electric generating ELGs. Today’s notice is not proposing 

anything new or different with respect to the CCR rulemaking (on 

which the Agency has already solicited public comments) and,

therefore, is not opening up that rulemaking to further public 

comments.
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2. Intersection Between the Proposed ELG and Coal Combustion

Residuals Rules

This section describes EPA’s current thinking on how a 

final RCRA Coal Combustion Residuals (CCR) rule might be aligned 

and structured to account for any final requirements adopted 

under the ELGs for the Steam Electric Power Generating point 

source category. Consistent with RCRA section 1006(b), EPA seeks 

to effectively coordinate any final RCRA requirements with the 

ELG requirements, to minimize the overall complexity of these 

two regulatory structures, and facilitate implementation of 

engineering, financial and permitting activities. EPA’s approach 

would also be consistent with Executive Order 13563, “Improving 

Regulation and Regulatory Review,” issued on January 18, 2011, 

which emphasizes that some “sectors and industries face a 

significant number of regulatory requirements, some of which may 

be redundant, inconsistent, or overlapping,” and it directs 

agencies to promote “coordination, simplification, and 

harmonization.” EPA’s goal is to ensure that the two rules work 

together to effectively address the discharge of pollutants from 

steam electric generating facilities and the human health and

environmental risks associated with the disposal of CCRs, 

without creating avoidable or unnecessary burdens.

In considering how to coordinate the potential requirements 

between the two rules, EPA is guided by the following policy 
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considerations: first and foremost, EPA intends to ensure that 

its statutory responsibilities to restore and maintain water 

quality under the CWA and to protect human health and the 

environment under RCRA are fulfilled. At the same time, EPA 

would seek to minimize the potential for overlapping 

requirements to avoid imposing any unnecessary burdens on 

regulated entities and to facilitate implementation and minimize 

the overall complexity of the regulatory structure under which 

facilities must operate. Based on these considerations, EPA is 

exploring two primary means of integrating the two rules: (1) 

through coordinating the design of any final substantive CCR 

requirements regulatory requirements, and (2) through 

coordination of the timing and implementation of final rule 

requirements to provide facilities with a reasonable timeline 

for implementation that allows for coordinated planning and 

protects electricity reliability for consumers.

Coordination of CCR Substantive Requirements with ELG 

Requirements. EPA’s current thinking is to focus primarily on 

the areas in which the proposed CCR and ELG rules may regulate 

or affect the same unit or activity. The scope of the two rules 

differs; although both of these rules would affect the disposal 

(i.e., discharge) of coal combustion wastes to and from surface 

impoundments (i.e., “ponds”) at power plants, only the CCR rule 

would regulate the disposal of CCRs in landfills. Accordingly, 
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in looking at how to coordinate the requirements of the two 

rules, EPA is primarily focusing on any requirements applicable 

to surface impoundments, rather than modifications to any 

requirements applicable to CCR landfills which would be 

addressed solely under any CCR rule. 

One approach is to examine the ways in which EPA 

anticipates that facilities are likely to modify their 

operations to comply with the ELG rule, and factor the results 

of those assessments into EPA’s evaluation of whether separate 

RCRA requirements under the CCR rule are needed to ensure 

protection of human health and the environment. For example, as 

described in greater detail in this preamble, the ELG rule could 

eliminate or reduce certain discharges to surface water, 

including by controlling or eliminating wastewater that is sent 

to and discharged from surface impoundments. While the ELG would 

not compel use of a particular technology, EPA predicts that one 

possible consequence of the proposed ELG requirements is that 

some number of facilities will choose to convert their sluicing 

operations to dry ash-handling systems, and will no longer send 

such wastes to surface impoundments. EPA is considering how 

these predictions might affect any specific technical 

requirements under RCRA that could be applicable to CCR surface 

impoundments. Thus, for instance, to the extent that facilities 

would no longer need to operate surface impoundments, it is 
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possible that this might affect the time frames (or other 

requirements) necessary for closure of such impoundments. 

However, it is also possible that the requirements 

established under a final ELG rule could affect the development 

of any final CCR rule more broadly. Since the close of the 

comment period on the CCR rule, EPA has received significant new

data obtained from a 2010 Information Collection Request (ICR) 

conducted by EPA’s Office of Water for the development of the 

ELG, which have the potential to affect the risk assessment for 

the CCR rule. This ICR gathered information from, among others, 

all 495 electric utility plants that operate coal-fired 

generating units. In the June 21, 2010 proposal, EPA did not 

have definitive data about the location, size, or age of the 

waste management units, nor on the type or composition of the 

wastes contained in surface impoundments. Consequently, the 

Agency relied on a 1995 industry report and a number of 

significant assumptions in the 2010 risk assessment supporting 

the proposed CCR rule. 

These facility-specific data could be used in EPA’s risk 

assessment for any CCR rule in several ways that could 

significantly affect the results of that assessment. For 

example, these data could be used to determine the extent to 

which plumes of contamination leaching from coal ash disposal 

units into groundwater are intercepted (and reduced) by surface 
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water bodies that exist between a disposal unit and a downgradient drinking water well. This information has the potential 

to significantly affect the nature and extent of the risks, and 

would allow EPA to better estimate the contaminant levels that 

people would be expected to receive in drinking water, and to 

better model the likely environmental risks (e.g., to fish and 

other aquatic life) from such contaminants in surface waters. 

Because so many of the disposal units (both surface impoundments 

and landfills) are located next to rivers, the results of the 

interception analysis could reasonably be expected to have a 

significant impact on the risk assessment results.

In addition, these data provide information on the 

location, size, and the type of waste present in hundreds of 

surface impoundments that were omitted from the data sources on 

which EPA relied to develop the proposed CCR rule. These 

impoundments are generally, smaller than the impoundments 

included in the data used to support the proposed CCR rule, and 

can differ significantly from the impoundments located at larger 

facilities. Exclusion of these smaller impoundments could 

potentially bias the results of the risk assessment, because 

smaller surface impoundments contain less waste that would be 

subject to leaching, and any plumes of contamination would 

likely be smaller. Similarly, these data would allow EPA to 

refine its analysis of the potential risks from fugitive dust at 
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landfills. Preliminary comparisons of the Office of Water data 

indicate that currently active portions of landfills are 

significantly smaller than the landfills identified in the 1995 

survey that EPA used in its assessment of the risks from 

fugitive dust prepared for the proposed rule. 

Although a final risk assessment for the CCR rule has not 

yet been completed, reliance on the data and analyses discussed 

above may have the potential to lower the CCR rule risk 

assessment results by as much as an order of magnitude. If this 

proves to be the case, EPA’s current thinking is that, the 

revised risks, coupled with the ELG requirements that the Agency 

may promulgate, and the increased Federal oversight such 

requirements could achieve, could provide strong support for a 

conclusion that regulation of CCR disposal under RCRA Subtitle D 

would be adequate.

Coordination of Timelines for Implementation. The second 

component of EPA’s approach to integrating any CCR rule with any 

ELG rule relates to the coordination of compliance and 

implementation deadlines. EPA’s goal is that, consistent with 

its statutory requirements, the implementation dates for each 

rule would not require facilities to make decisions without 

understanding the implications that such decisions would have 

for meeting any requirements of each rule. Thus, EPA’s current 

approach is to enable a facility to determine whether any 
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changes to its operations are needed to comply with the Steam 

Electric ELG – and if so, what those might be – before the 

facility would be required, for example, to decide whether to 

close or retrofit any surface impoundments pursuant to any CCR 

rule. For example, assuming that an electric utility relied on a 

series of surface impoundments or ponds to dispose of wastewater 

generated at the plant, EPA’s current approach would enable the 

facility – prior to the deadline by which the facility would 

need to decide whether to retrofit or close those surface 

impoundments to comply with any CCR rule – to effectively 

evaluate whether it makes business sense to continue to operate 

those ponds (with or without any modifications) in light of the 

requirements of both rules, or whether other changes to facility 

operations would be more cost-effective. 

As it has in this proposed ELG rule, EPA also intends to 

consider, to the extent permitted by statute, any practical 

constraints facilities may face in implementing any requirements 

under both rules (See, for example, Section XVI, addressing 

implementation issues for the Steam Electric ELGs). 

Comments on EPA’s current thinking described above on how 

any final CCR rule might be aligned and structured to account 

for any final requirements adopted under the ELGs for the Steam 

Electric Power Generating point source category should be 

directed to Docket ID Number: EPA-HQ-RCRA-2013-0209. Any 
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comments submitted on this limited set of issues will be 

considered as part of the CCR rulemaking. By contrast, comments 

submitted on any other issue related to the CCR rule will be 

considered “late comments” and EPA will not respond to such 

comments, nor will they be considered part of the CCR rulemaking 

record.

IV. Summary of Data Collection Activities

A. Questionnaire for the Steam Electric Power Generating 

Effluent Guidelines

A principal source of information used in developing 

today’s proposal is the industry responses to a survey, the 

Questionnaire for the Steam Electric Power Generating Effluent 

Guidelines, distributed by EPA under the authority of section 

308 of the CWA, 33 U.S.C. 1318. EPA designed the industry survey 

to obtain technical information related to wastewater generation 

and treatment, and economic information such as costs of 

wastewater treatment technologies and financial characteristics 

of potentially affected companies. The Agency consulted with the 

major industry trade associations to ensure that the industry 

survey would be useful and to ensure an accurate list of 

potential recipients. In June 2010, EPA mailed the survey to 733 
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plants. In general, plants were required to provide responses 

for the 2009 calendar year. The following describes the 

questionnaire, the recipient selection process, and the review 

of the questionnaire responses.

1. Description of the Industry Survey Components

To obtain information relevant to the rulemaking, EPA’s

survey consisted of the following nine parts:

Part A: Steam Electric Power Plant Operations; 

Part B: FGD Systems; 

Part C: Ash Handling; 

Part D: Pond/Impoundment Systems and Other Wastewater 

Treatment Operations; 

Part E: Wastes from Cleaning Metal Process Equipment; 

Part F: Management Practices for Ponds/Impoundments and 

Landfills; 

Part G: Leachate Sampling Data for Ponds/Impoundments and 

Landfills;

Part H: Nuclear Power Generation; and 

Part I: Economic and Financial Data. 

Part A gathered information on all steam electric 

generating units at the surveyed plant, the fuels used to 

generate electricity, air pollution controls, cooling water, an 

inventory of ponds/impoundments and landfills used for 

combustion residues (including coal, petroleum coke, and oil 

residues), coal storage and processing, and outfall information. 

Parts B through I collected economic data and detailed technical 

information on certain aspects of power plant operations, 

including requiring some plants to collect and analyze 
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wastewater samples. The process operation sections (Parts B, C, 

and E) included detailed questions about the types of processes 

employed, dates that certain types of equipment were installed 

or plans for future equipment installations, chemical usage, 

operating characteristics, wastewater generation, pollution 

prevention activities, and wastewater discharge information.

In Part D of the industry survey, EPA requested detailed 

information (including diagrams) on the wastewater treatment 

systems (including chemical usage), discharge flow rates, and 

operating and maintenance cost data (including chemical usage) 

(Part D). The ponds/impoundments and landfill questions (Parts F 

and G) requested information on the size, characteristics, and 

operation of the ponds/impoundments and landfills located at the 

facilities. These sections also obtained information on the 

leachate collection and treatment, and required facilities to 

collect and analyze samples of untreated and treated leachate 

from the ponds/impoundments and landfills that receive 

combustion residues. The survey respondents were required to 

provide the laboratory analytical results and additional 

descriptive information about the leachate samples.

For nuclear-fueled generating units, Part H of the industry 

survey requested general information on the operation of the 

nuclear units, the wastewaters generated, and the treatment of 

those wastewaters. 
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The financial and economic questions (Part I) requested 

information on the facilities’ ownership structure and financial 

conditions.

The Agency used these data to evaluate process operations

and wastewater generation, identify treatment technologies in 

place, and determine the feasibility of regulatory options for 

each plant. EPA identified and evaluated the treatment 

technologies available for treating FGD wastewater and leachate 

from surface impoundments and landfills, and approaches for ash 

handling that reduced or eliminated the use of water. EPA also 

used these data to estimate which plants may incur compliance 

costs and pollutant removals associated with the various 

technology control options.

EPA used survey data, along with additional data collected 

from public sources, to estimate economic impacts on facilities 

and owning entities under the fiveeight main regulatory options 

EPA considered for this proposal.

2. Identification of Potential Questionnaire Recipients

The Energy Information Administration (EIA), a statistical 

agency of the U.S. Department of Energy (DOE), collects 

information on existing electric generating plants and 

associated equipment to evaluate the current status and 

potential trends in the industry. EPA used the information 

available from the 2007 Electric Generator Report (Form EIA-
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860), and supplemented it with information found in Form EIA-923 

and a survey conducted by EPA’s Office of Solid Waste and 

Emergency Response (OSWER), to create a listing of plants that 

have steam electric power generating activities believed to be 

subject to the existing Steam Electric Power Generating Effluent 

Guidelines.

EPA used the EIA data, which contains information on the 

location of each of the plants (e.g., address, city, state), to 

create an initial draft of potential questionnaire recipients

that EPA shared with industry stakeholders (e.g., the Utility 

Water Act Group (UWAG)) and interested environmental 

organizations. UWAG distributed the list to its members and 

provided feedback to the Agency to correct inaccurate addresses 

as well as identify plants that were not included or plants that 

are no longer in operation. Based on the original EIA data and 

industry feedback, EPA identified 1,197 steam electric 

generating plants for the survey sample frame (i.e., a list of 

all steam electric power plants from which the surveyed plants 

would be selected). 

3. Questionnaire Recipient Selection

As a first step in selecting questionnaire recipients, EPA 

grouped all identified steam electric power plants based on the 

types of fuels burned at the facility. EPA first classified the 

generating units into fuel groups based on the primary and 
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secondary energy sources reported in the 2007 Form EIA-860. EPA 

used the following hierarchy to classify the generating units: 

coal, petroleum coke, gas, oil, and nuclear. Generating units 

that identified either coal or petroleum coke as the primary or

secondary energy source were classified as a coal or petroleum 

coke generating unit. For generating units that did not identify 

coal or petroleum coke as a primary or secondary energy source, 

EPA used the primary energy source to classify the generating 

unit as gas, oil or nuclear. Based on the generating unit 

classifications, EPA then grouped plants into the fuel 

categories based on the following hierarchy: coal, petroleum 

coke, combination, gas, oil, nuclear. For example, if a plant 

has one coal unit and five gas units, EPA identified the plant

as a coal plant. EPA used the “combination” designation for 

plants that have at least two generating units that have 

different unit-level designations (e.g., oil, gas, nuclear), but 

do not have any coal or petroleum coke units. Table IV-1 details 

the distribution of steam electric power plants by their fuel 

types.

Table IV-1. Steam Electric Power Plants by Fuel Type

Fuel Type Number of Facilities

Coal 495

Petroleum coke 9

Oil 43

Gas 555

Nuclear 63

Combination 32
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Because much of the focus of this proposed rule is on the 

FGD and ash wastewaters, which are primarily generated at coaland petroleum coke-fired plants, EPA sent questionnaires to all 

plants that operate coal- or petroleum coke-fired generating 

units. For plants without any coal- or petroleum coke-fired 

generating units (i.e., gas, oil, or nuclear-fueled), EPA sent 

questionnaires to a statistically selected subset of the 

identified plants. EPA created four different versions of the 

questionnaire to send out to plants based on the different parts 

of the questionnaire:

Version 1: Parts A through I; 

Version 2: Parts A, B, C, D, H, and I; 

Version 3: Parts A, B, C, D, E, H, and I; and

Version 4: Parts A, E, H, and I.

In June 2010, EPA mailed the surveys to 733 power plants.

EPA mailed Version 1 of the questionnaire to 97 coal- and 

petroleum coke-fired power plants, which is a subset of the 

total number of coal- and petroleum coke-fired power plants. EPA 

mailed Version 2 of the questionnaire to the remaining 407 coaland petroleum coke-fired power plants. EPA mailed Version 3 of 

the questionnaire to 20 oil-fired plants and 22 plants that burn 

at least two different types of fuel (e.g., combination plants).

EPA mailed Version 4 of the questionnaire to 187 gas-fired and 

nuclear power plants.
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4. Questionnaire Responses

EPA received completed surveys from all 733 questionnaire 

recipients. A total of 53 plants certified that they were not 

and did not have the capability to be engaged in steam electric 

power production, would be retired by December 31, 2011, or did 

not generate electricity in 2009 by burning any fossil or 

nuclear fuels. 

5. Questionnaire Review

EPA reviewed the surveys for completeness and consistency, 

using checklists for the review process to help identify 

potential issues with responses (e.g., data reported in 

incorrect units, missing responses). After completing the review 

for each plant, EPA contacted the plant to review the potential 

issues identified during the review process, if needed. EPA then 

created a database that contains all survey responses. The 

questionnaire database in the public record includes all 

information submitted for which facilities have not asserted 

that itthe information is confidential business information

(CBI). In some instances, EPA has redacted non-CBI data to 

prevent the disclosure of other data claimed as CBI.

B. Engineering Site Visits

EPA conducted 6368 site visits to power plants in 22 states 

and Italy between December 2006 and August 2012February 2013 to

collect information about plant operations, process wastewater 
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generation and management practices, and wastewater treatment 

systems. The primary purpose of these site visits was to 

evaluate candidate best available technologies and best 

available demonstrated control technologies, the changes 

necessary to implement new processes or technologies, and 

evaluate plants for potential inclusion in EPA’s field sampling 

program. EPA used information provided by UWAG, responses from 

the detailed study data request, industry survey data, and 

information learned from contacts with industry representatives 

to identify site visit candidates. EPA based site visit 

selection on the type of operations at the plant (e.g., wet FGD

systems, wet fly ash or bottom ash handling, gasification), and 

the plant’s approach for minimizing pollutant discharges 

associated with these operations (e.g., sites employing 

candidate best available technologies, best available 

demonstrated control technologies, or processes that reduce or 

eliminate pollutant discharges.)

EPA collected detailed information from the plants visited,

such as the operations associated with wastewater generation, 

in-process treatment and recycling systems, end-of-pipe 

treatment technologies, and, if the plant was a candidate for 

sampling, the logistics of collecting samples. EPA also obtained 

information regarding zero discharge options associated with the 

various operations and how the plants could potentially achieve 
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zero discharge for some or all of these operations. EPA prepared 

site visit reports summarizing the collected information. EPA 

has included in the public record site visit reports that 

contain all information collected during site visits for which 

the plants have not asserted a claim of CBI.

C. Field Sampling Program

Between July 2007 and April 2011, EPA conducted a sampling 

program at 17 different steam electric power plants in the 

United States and Italy to collect wastewater characterization 

data and/or treatment performance data associated with FGD 

wastewater, fly ash and bottom ash wastewater, and wastewater 

from gasification and carbon capture processes. EPA conducted 

on-site sampling activities (i.e., the Agency collected the 

samples), as well as requiring some plants to collect samples 

for analysis by EPA-contracted laboratories (i.e., CWA 308 

monitoring program). EPA conducted on-site sampling) at 13 of 

the 17 power plants (EPA sampled one of these plants twice)..

Using its authority under CWA section 308, EPA directed seven of 

these EPA-sampled plants and four additional plants not sampled 

by EPA to collect additional samples, which were sent to EPAcontracted laboratories for analysis. EPA also directed four 

additional plants (not sampled by EPA) to collect samples which 

were sent to EPA-contracted laboratories. (i.e., CWA 308 
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monitoring program). In general, EPA used the following criteria 

to identify the plants included in the sampling program:

The plant performs steam electric power generation 

activities representative of steam electric power plants 

(i.e., the plant’s operations are typical of operations 

observed at other power plants, and therefore, are 

representative of more than just itself); 

The plant uses coal and/or petroleum coke (the wastestreams 

of interest and pollutants of concern identified in this 

rulemaking are primarily associated with plants using these 

types of fuels); and

The plant has the wastestreams or treatment technologies of 

interest.

EPA also obtained sampling data for surface impoundment and 

landfill leachate collection and treatment systems at 39 plants, 

as requireddirected by Part G of the Questionnaire for the Steam 

Electric Power Generating Effluent Guidelines. This leachate 

sampling is not included in the following description of the 

field sampling program. See Section 10.2.3 of the TDD for more 

information on leachate data collected under the industry 

survey.

EPA’s field sampling program began during its detailed 

study and continued throughout this rulemaking effort. During 

the study, EPA conducted one- or two-day sampling episodes at 

six plants to characterize untreated wastewaters generated by 

coal-fired power plants, as well as to obtain a preliminary 

assessment of treatment technologies and best management 

practices for reducing pollutant discharges. The types of 
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wastewaters sampled during the detailed study were untreated and 

treated FGD wastewater, fly ash wastewater, and bottom ash 

wastewater.

Upon completing the detailed study, EPA subsequently 

selected 13 plants to collect additional wastewater 

characterization data and to evaluate wastewater treatment 

performance. Through this effort, EPA evaluated 10 FGD 

wastewater treatment systems; two gasification systems at 

integrated gasification combined cycle (IGCC) plants; and one 

pilot-scale carbon capture system. EPA selected these FGD 

systems because at the time it believed all were among the 

better performing FGD wastewater treatment systems in the 

industry, based on information obtained during the site visits 

and discussions with industry representatives about the 

design/operation of the treatment system and optimization 

efforts performed at the plant. In addition, these plants 

represent geographic variability, different coal types (i.e., 

bituminous, subbituminous, coal blends), and different operating 

practices (e.g., baseload vs cycling). The selected IGCC systems 

and the pilot-scale carbon capture system were the only known 

systems operating in the U.S. power industry at the time of 

EPA’s field sampling program.

For the 13 plants sampled following completion of the 

detailed study, samples were collected as follows:
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For seven of these 13 plants, EPA collected 

performance data for four consecutive days and the 

plants also subsequently collected four sets of 

samples over a four to five month period. ;

For four plants, the facility collected performance 

data for four consecutive days. ;

For one plant, EPA collected performance data for 

three consecutive days. Another; and

For one plant, the facility collected performance data 

for one day. 

EPA (or the plant) collected representative samples at the 

influent and effluent of the treatment system being evaluated 

using a combination of 24-hour composite and grab samples, 

depending on the sample location and the parameter to be 

analyzed. EPA analyzed the samples for up to 64 parameters,

including conventional pollutants (e.g., TSS, BOD5), 

nonconventional pollutants (e.g., TDS, nutrients), and metals.

For samples collected by EPA, EPA quantified both the total 

amount of metal and the dissolved portion only. For samples 

collected by the plants, EPA quantified the total amount of 

metal. Prior to initiating sampling activities, regardless of 

who collected the samples, EPA developed sampling plans that 

detailed the procedures for sample collection, including the 

Formatted: Indent: First line: 0"
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pollutants to be sampled, location of the sampling points, and 

sample collection, preservation, and shipment techniques.

Subsequent to the EPA and industry sampling efforts, EPA 

prepared a report summarizing the wastewater treatment 

processes, sampling procedures, and analytical results. EPA has 

included in the public record these reports containing all 

information collected for which a facility has not asserted a 

confidentiality claim or which would indirectly reveal 

information claimed to be CBI.

D. EPA and State Sources

EPA collected information from the Agency’s databases and 

publications, states, and permitting authorities, including the 

following: 

Information on current and proposed permitting practices 

for the steam electric industry from a review of selected 

NPDES permits and accompanying fact sheets;

Input from EPA and state permitting authorities regarding 

implementation of the existing Steam Electric Power 

Generating effluent guidelines; 

Background information on the steam electric industry from 

documents prepared during the development of the existing 

Steam Electric Power Generating effluent guidelines (i.e., 

the 1974 and 1982 rulemakings); 

Information from a survey of the industry conducted for the 

Cooling Water Intake Structures rulemaking; 

Information from EPA’s Office of Air and Radiation (OAR), 

including Integrated Planning Model (IPM) projections based

on recent air rules (i.e., CAIR/CSAPR rule and MATS); 

Information from EPA’s Office of Research and Development 

(ORD) characterizing CCR and the potential leaching of 

pollutants from CCRs stored or disposed of in landfills and 

surface impoundments; 
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Data provided by the North Carolina Department of 

Environment and Natural Resources for one plant that 

operates an anoxic/anaerobic biological treatment system 

for FGD wastewater; and 

Information collected by EPA’s OSWER, regarding surface 

impoundments or other similar management units that contain 

CCRs at power plants and other information gathered in 

support of the proposed rule for regulating CCR under RCRA.

E. Industry Data

EPA obtained information on steam electric wastewaters and 

pollutants directly from the industry through self-monitoring 

data, as well as NPDES Form 2C data. Specifically, EPA requested 

self-monitoring data from two power plants to support its

calculation of pollutant loading reductions from FGD wastewater 

treatment technologies and to supplement the data from the EPA 

sampling program in the development of ELGs for the FGD 

wastewater. EPA also coordinated with UWAG to create a database 

of selected NPDES Form 2C data from UWAG’s member companies. The 

NPDES Form 2C database contains information about the outfalls 

of coal-fired power plants that receive FGD, ash handling, or 

coal pile runoff wastestreams. EPA received Form 2C data from 

UWAG for 86 plants in late June 2008 and reviewed the data for 

use in developing the industry profile, in particular for ash 

wastewater treatment operations.

F. Technology Vendor Data

EPA gathered data from technology vendors through 

presentations, conferences, meetings, and email and phone 
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contacts to gain information on the technologies used in the 

industry. EPA also used these contacts with vendors to obtain 

costs to install and operate the technologies considered as part 

of the proposed rule. These data informed the development of the 

industry survey, the technology costs, and the pollutant 

loadings estimates.

G. Other Sources

EPA obtained additional information on steam electric 

processes, technologies, wastewaters, pollutants, and 

regulations from sources including trade associations (e.g., 

UWAG), the Electric Power Research Institute (EPRI), DOE, the 

U.S. Geological Survey (USGS), and literature and Internet 

searches. EPA used information provided by the Environmental 

Integrity Project (EIP), Earthjustice, and the Sierra Club to 

document known environmental impacts caused by steam electric 

power plant discharges. In addition, EPA considered information 

provided in public comments during the effluent guidelines 

planning process, as well as other contacts with interested 

stakeholders. 

H. Economic Data

To conduct cost and economic impact analysis of the 

proposed regulation, EPA used financial and operational data for 

steam electric power plants and their parent companies collected 
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through the Steam Electric Questionnaire described in Section 

IV.A of this preamble. 

EPA also used publicly available data describing current 

operating and business conditions at the steam electric power 

plants, operators, and parent companies, data describing 

economic/financial conditions in, and the regulatory environment 

of, the electric power industry, as well as data on electricity 

prices and electricity consumption. EPA obtained publicly 

available data from the following sources: the EIADepartment of 

the DOEEnergy’s EIA (in particular, the EIA 767, 860, 861, and 

906/920/923 databases),7 the U.S. Small Business Administration 

(SBA), the Bureau of Labor Statistics (BLS), and the Bureau of 

Economic Analysis (BEA), Securities and Exchange Commission 

(SEC) Forms 10-K, companies’ annual financial reports and press 

releases, newspapers articles, and Standard & Poor’s. Finally, 

EPA relied on analysis and outputs from the Integrated Planning 

Model (IPM), a comprehensive electricity market optimization 

model that can evaluate impacts within the context of regional 

and national electricity markets (See Section XI). 

 

7 EIA-767: Annual Steam-Electric Plant Operation and Design Data (annual);7

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).
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V. Scope/Applicability of the Proposed Rule

A. Facilities Subject to 40 CFR Part 423

Today’s proposal would establish new requirements for 

certain plants within the scope of the existing regulations for 

the steam electric power generating point source category. The 

proposed requirements would apply to discharges of wastewater 

associated with the following processes and byproducts: flue gas 

desulfurization, fly ash, bottom ash, combustion residual 

leachate, flue gas mercury control, nonchemical metal cleaning 

wastes, and gasification of fuels such as coal and petroleum 

coke. EPA is also considering establishing best management 

practices for surface impoundments receiving coal combustion 

residuals.

EPA is proposing to correct a typographical error in 40 CFR 

423.17(d)(1) by adding a footnote that is missing from the table 

specifying PSNS for cooling tower blowdown. As is clear from the 

development document for the 1982 rulemaking, the footnote was 

intended to appear, as it does in the corresponding table for 

NSPS, and its omission was an inadvertent mistake, which EPA is

now correcting. The footnote proposed to be added reads “No 

detectable amount” and refers to the effluent standard for 124 

of the 126 priority pollutants contained in chemicals added for 

cooling tower maintenance. (See “Development Document for Final 

Effluent Guidelines, New Source Performance Standards and 
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Pretreatment Standards for the Steam Electric Power Generating 

Point Source Category,” Document No. EPA 440/1-82/029. November 

1982.)

In addition, EPA is proposing three modifications to the 

applicability provision for the ELGs. These are not substantive 

modifications thatand would not alter which generating units are 

regulated by the ELGs and they would notnor impose compliance 

costs on the industry. Instead, the proposed modifications would

remove potential ambiguity present in the current regulatory 

text by revising the text to more clearly reflect EPA’s longstanding interpretation.

First, the applicability provision in the current ELGs 

states, in part, that the ELGs apply to ”an establishment 

primarily engaged in the generation of electricity for 

distribution and sale... .” 40 CFR 423.10. EPA is proposing to 

revise that phrase in the applicability provision to read ”an 

establishment whose generation of electricity is the predominant

source of revenue or principal reason for operation....” This 

proposed modification would clarify that certain facilities, 

such as generating units owned and operated by industrial 

facilities in other sectors (e.g., petroleum refineries, pulp 

and paper mills) are not included within the scope of the steam 

electric ELGs. In addition, the proposed modification would 

clarify that certain municipal-owned facilities, which generate 
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and distribute electricity within a service area (such as 

distributing electric power to municipal-owned buildings), but 

which use accounting practices that are not commonly thought of 

as a “sale” are nevertheless subject to the ELGs. Such 

facilities have traditionally been regulated by the steam 

electric ELGs, and EPA believes the proposed modification will 

improve regulatory clarity.

Second, EPA is proposing a modification to the 

applicability provision to clarify that fuels derived from 

fossil fuel are within the scope of the current ELGs. The ELGs 

currently state, in part, that the ELGs apply to discharges 

related to the generation of electricity “which results 

primarily from a process utilizing fossil-type fuels (coal, oil, 

or gas) or nuclear fuel... .” 40 CFR 423.10. Because there are a 

number of fuel types that are derived from fossil fuel, and 

which thus are fossil fuels themselves, EPA is proposing to 

revise that phrase in the applicability provision to read “which 

results primarily from a process utilizing fossil-type fuel 

(coal, oil, or gas), fuel derived from fossil fuel (e.g., 

petroleum coke, synthesis gas), or nuclear fuel... .”

Third, EPA is proposing to amend the applicability 

provision to clarify that combined cycle systems are subject to 

the requirements of the ELGs. The ELGs apply to electric 

generation processes that utilize “a thermal cycle employing the 
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steam water system as the thermodynamic medium.” 40 CFR 423.10.

EPA’s longstanding interpretation of this provision is that the 

ELGs apply to all electric generation processes with at least 

one prime mover that utilizes steam (if they also meet the other 

factors specified in Section 423.10, including the use of fossil 

or nuclear fuel). Combined cycle systems, which are generating 

units composed of one or more combustion turbines operating in 

conjunction with one or more steam turbines, are subject to the 

ELGs. The combustion turbines for a combined cycle system 

operate in tandem with the steam turbines; therefore, the ELGs 

apply to wastewater discharges associated with both the 

combustion turbine and steam turbine portions of the combined 

cycle system.

B. Subcategorization

The CWA requires EPA to consider a number of different 

factors when developing ELGs for a particular industry category 

(see BAT factors listed at Section 304(b)(2)(B), 33 U.S.C. § 

1314(b)(2)(B)). For BAT, in addition to the technological 

availability and economic achievability, these factors are the 

cost of achieving the effluent reduction, the age of the 

equipment and plantsfacilities involved, the processesprocess

employed, the engineering aspects of the application of various 

types of control technology, potentialtechniques, process 

changes, the cost of achieving such effluent reduction, non-
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water- quality environmental impactsimpact (including energy 

requirements), and such other factors the Administrator deems 

appropriate. One way EPA may take these factors into account is 

by dividing a point source category into groupings called 

“subcategories.” Regulating a category by subcategory, where 

determined to be warranted, ensures that each subcategory has a 

uniform set of ELGs that take into account technology 

availability and economic achievability and other relevant 

factors unique to that subcategory.

The current steam electric ELGs do not divide plants or 

process operations into subcategories, although it doesthey do

include different effluent requirements for cooling water 

discharges from generating units smaller than 25 MW generating 

capacity. For this proposed rule, EPA evaluated whether 

different effluent requirements should be established for 

certain facilities within the steam electric power generating 

point source category using information from responses to the 

industry questionnaires, site visits, sampling, and other data 

collection activities (see Section IV for more details). EPA 

performed analyses to assess the influence of age, size, fuel 

type, and geographic location on the wastewaters generated, 

discharge flow rates, pollutant concentrations, and treatment 

technology availability at steam electric power plants to 
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determine whether subcategorization was appropriate, as 

discussed further below. 

1. Age of Plant or Generating Unit

EPA analyzed the age of the power plants and the generating 

units included in the scope of the rule. It determined that the 

age of the plant by itself does not in general impactaffect the 

wastewater characteristics, the processes in place, or the 

ability to install the treatment technologies evaluated as part 

of this rulemaking. Therefore, EPA did not establish 

subcategories based on the age of the plant or generating unit 

for this proposal.

2. Geographic Location

EPA analyzed the geographic location of power plants 

included in the scope of the rule. It determined that the 

geographic location of the plant by itself does not affect the 

wastewater characteristics, the processes in place, or the 

ability to install the treatment technologies evaluated as part 

of this rulemaking. Therefore, EPA did not establish 

subcategories based solely on the age of the plant or generating 

unit for this proposal.

2. Geographic Location

Geographic location can influence the type of wastestreams 

generated at steam electric power plants. However, the type of 

wastestreams generated is more affected by the fuel type, 
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because plants in the eastern United States tend to burn highsulfur bituminous coal and, therefore, are more likely to 

operate wet FGD systems. For this reason, more plants in the 

eastern United States generate FGD wastewater; however, it is 

the fuel type, not the location the the plant that generally 

impacts the characteristics of the wastewater. During its 

evaluation, EPA found that wet FGD systems, both wet and dry fly 

ash handling systems, and both wet and dry bottom ash handling 

systems are located throughout the United States, as illustrated 

in Section 4 of the TDD. Additionally, the location of the 

plant does not affect the plant’s ability to install the 

treatment technologies evaluated as part of this rulemaking.

Therefore, EPA did not establish subcategories based on plant 

location for this proposal For example, a plant in the southern 

United States would be able to install and operate the chemical 

precipitation and biological treatment system proposed as the 

BAT technology basis for FGD wastewater. Because of the warm 

climate, plants in locations such as this may find it necessary 

to install heat exchangers to keep the FGD wastewater 

temperature at ideal operating conditions during the summer 

months. EPA’s approach for estimating compliance costs takes 

such factors into account. Based on the information in the 

record regarding the current geographic location of the various 

types of systems generating the wastewaters addressed by this 
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rulemaking and engineering knowledge of the operational 

processes and candidate BAT/NSPS treatment technologies, EPA 

determined that subcategories based on plant location are not 

warranted.

3. Size

EPA analyzed the size (i.e., nameplate generating capacity 

in MW) of the steam electric generating unit and determined that 

it can be an important factor influencing the volume of the 

discharge flow from the plant. Typically, as the size of the 

generating unit increases, the discharge flows of cooling water, 

ash handling water, boiler blowdown, and other wastestreamsash 

transport water generally increase. In general, this is to be 

expected because the larger the generating unit, the more fuel 

it consumes, which requires more cooling, generates more ash, 

and uses more water in the water/steam thermodynamic cycle. 

Although the volume of the wastewater increases with the size of 

the generating unit, the pollutant characteristics of the 

wastewater generally are unaffected by the size of the 

generating unit and any variability observed in wastewater 

pollutant characteristics does not appear to be correlated to 

generating capacity.

As a result of its evaluation, EPA believes that, in 

certain circumstances, it would be appropriate to apply 

different limits for a class of existing small generating units
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or plants based on size. Section VIII of this preamble discusses 

in greater detail EPA’s proposal for applying different 

standards to certain existing small units.

4. Fuel Type

The type of fuel (e.g., coal, petroleum coke, oil, gas, 

nuclear) used to create steam most directly influences the type 

and number of wastestreams generated. For example, gas and 

nuclear power plants typically generate cooling water, metal 

cleaning wastes (both chemical and nonchemical), and other low 

volume wastestreams, but do not generate wastewaters associated 

with air pollution control devices (e.g., fly ash and bottom ash 

transport water, FGD wastewater). Coal, oil, and petroleum-coke 

power plants may generate all of those wastewaters. The 

wastestream that is most influenced by fuel selection is the ash 

transport water because the quantity and quality of ash 

generated from oil-fired units is different from that generated 

from coal- and petroleum coke-fired units. Additionally, the 

quantity and quality of ash differs based on the type of oil 

used in the boiler. For example, heavy or residual oils such as 

No. 6 fuel oil generate fly ash and may generate bottom ash, but 

lighter oils such as No. 2 fuel oil may not generate any ash.

From an analysis of responses to the industry survey, EPA 

determined that 74 percent of the steam electric units in the 

industry burn more than one type of fuel (e.g., coal and oil, 
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coal and gas). Some of these plants may burn only one fuel at a 

specific time, but burn both types of fuels during the year. 

Other plants may burn multiple fuels at the same time. In cases 

where facilities burn multiple fuels at the same time, it would 

be impossible to separate the wastestreams by fuel type.

EPA did not identify any basis for subcategorizing gasfired and nuclear generating units. These generating units 

generally manage nonchemical metal cleaning wastes in the same 

manner as other steam electric generating units, and the 

proposed requirements for this wastestream would establish 

limitations and standards that are equal to current BPT 

limitations for existing direct dischargers.

8 Furthermore, the 

gas-fired and nuclear generating units do not generate the other 

six wastestreams addressed by this rulemaking. However, based on 

responses to the industry survey, there are some oil-fired units 

that generate and discharge fly ash and/or bottom ash transport 

water. For these reasons, EPA looked carefully at oil-fired 

units. As a result, EPA believes that, in certain circumstances, 

it is appropriate to apply different limits to existing oilfired generating units. Section VIII of this preamble discusses 

 

8 As described in Section VIII, EPA is proposing to exempt from new copper and 

iron BAT limitations any existing discharges of nonchemical metal cleaning 

wastes that are currently authorized without iron and copper limits. For 

these discharges, BAT limits would be set equal to BPT limits applicable to 

low volume wastes
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in greater detail EPA’s proposal for applying different 

standards to certain existing oil-fired units.

VI. Industry Description

A. General Description of Industry 

The steam electric power generating point source category 

(i.e., steam electric industry) consists of plants that generate 

electricity from a process utilizing fossil or nuclear fuel in 

conjunction with a thermal cycle employing the steam /water 

system as the thermodynamic medium. Based on responses to the 

industry survey, the Agency estimates that, excluding plants 

reporting that they would be retired by December 2011, and those 

plants reporting that they did not operate fossil- or nuclearfueled units in 2009, there were 1,079 steam electric power 

plants operating in 2009. These facilities operate an estimated 

2,195-2,230 generating units (including combined cycle systems), 

which have a total nameplate generating capacity of 741,000 MW.

(Note: EPA has withheld the precise number of generating units 

to prevent disclosing CBI.) Table VI-1 shows the estimated 

number of steam electric generating units broken out by the five 

primary types of fuels used: coal, petroleum coke, oil, gas, and 

nuclear.

Table VI-1. Estimated Number of Steam Electric Generating Units 

and Capacity by Primary Fuel Source

Primary Fuel Source

Number of Generating 

Units

Nameplate Capacity 

(MW)

Coal 1,080-1,090 328,000-330,000
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Table VI-1. Estimated Number of Steam Electric Generating Units 

and Capacity by Primary Fuel Source

Primary Fuel Source

Number of Generating 

Units

Nameplate Capacity 

(MW)

Petroleum Coke 12 1,000

Oil 75-100 23,900-25,400

Gas 929 282,000

Nuclear 99 104,000

Total Industry 2,195-2,230 741,000

Source: Steam Electric Technical Questionnaire Database (DCN SE01958)

As seen from these data, most of the steam electric 

generating capacity (82 percent) is associated with either coal 

or gas. Based on survey responses, EPA also found that most 

plants in the industry have a generating capacity greater than 

500 MW. and may operate only one generating unit or multiple 

generating units. Plants of that size account for over 60 

percent of all steam electric plants, 70 percent of all electric 

generating units, and 90 percent of the electric generating 

capacity.

For coal- and petroleum coke-fired plants, EPA determined 

that most plants (89 percent) are discharging at least some of 

their wastewater to surface waters or POTWs. Some plants operate 

without discharging certain wastewaters (e.g., fly ash transport 

water, FGD wastewater); however, most plants discharge at least 

their cooling water. Few of the discharging plants send 

wastestreams addressed by this rulemaking to POTWs. EPA 

identified approximately 10 coal- or petroleum coke-fired plants 
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that discharge their FGD wastewater and/or fly ash or bottom ash 

transport water to POTWs. EPA also found that approximately 11 

percent of coal- and petroleum coke-fired power plants do not 

discharge any wastewater. Most of these zero discharge plants 

are located in the southwestern United States (e.g., Arizona) 

and use evaporation ponds to control the wastewater.

B. Steam Electric Process Descriptions and Wastewater Generation

In the steam electric process, fuel is fed to a boiler 

where the fuel is combusted. The hot gases from combustion leave 

the boiler and pass through air pollution control systems prior 

to their emission through a stack. The resulting heat from 

combustion converts water to steam. The high-temperature, highpressure steam leaves the boiler and enters the turbine 

generator where it drives the turbine blades as it moves from 

the high-pressure to the low-pressure stages of the turbine. The 

lower-pressure steam leaving the turbine enters the condenser, 

where steam vapor is cooled and condensed back into liquid by 

cooling water. The water collected in the condenser is sent back 

to the boiler where it is again converted to steam.

Combined cycle systems consist of combustion turbine 

electric generating units operating in conjunction with steam 

turbine electric generating units. Combustion turbines, which 

typically are similar to jet engines, commonly use natural gas

as the fuel. Combined cycle systems feed the fuel into a chamber 
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where it is combusted to generate heat. The combustion exhaust 

gases are sent directly through a combustion turbine to generate 

electricity. These exhaust gases still contain useful waste heat

as they exit the combustion turbine, so they are directed to 

heat recovery steam generators to generate steam that is then 

used to drive a steam turbine, which operates as described above 

for the steam electric process. The operation of the steam 

turbine electric generating unit within a combined cycle system 

is virtually identical to a stand-alone steam electric 

generating unit, with the exception of the boiler.

IGCC is an electric power generation process that combines 

gasification technology with combined cycle systems. In an IGCC 

system, a gasifier converts carbon-based feedstocks (e.g., coal 

or petroleum coke) into a synthetic gas (syngas) using high 

temperature and pressure. The syngas is cleaned through multiple 

process operations and then combusted in a combustion turbine.

As with a combined cycle system, a heat recovery steam generator 

extracts the heat from the exhaust gases to generate steam and 

drive a steam turbine.

Certain wastewaters generated at steam electric power 

plants differ based on the fuel used; however, almost all steam 

electric power plants generate some wastewaters. For example, 

because all steam electric power plants use a steam water system 

as the thermodynamic medium, all power plants use cooling water 
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to condense the steam in the system. Additionally, most steam 

electric power plants have a boiler blowdown stream to purge 

salts from the water used in the steam water system. Other 

wastewaters are generated from the use of air pollution control 

systems and are more directly tied to the type of fuel burned. 

Coal- and petroleum coke-fired steam electric generating units, 

and to a lesser degree oil-fired 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 units are outfitted with 

air pollution control systems (e.g., particulate removal 

systems, flue gas desulfurization systems, and NOx removal 

systems). Gas-fired units generate fewer emissions of 

particulate matter, sulfur dioxide, and nitrogen oxides than 

coal- or oil-fired units, and therefore do not typically operate 

air pollution control systems to control emissions from their 

flue gas. EPA determined that the wastewaters associated with 

these air pollution control systems contain large quantities of 

metals (e.g., arsenic, mercury, and selenium). Due to increased

use of these air pollution control systems in the last decade, 

and an expected increase in the installation and use of air 

pollution controls over the next decade, EPA is focusing this 
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rulemaking, in part, on controlling the discharges of these 

wastewaters.

The information in the remainder of Section VI below 

describing industry practices generally presents data collected 

by the industry survey and represents operational conditions for 

the year 2009. The industry survey represents the most complete 

source of data available to EPA regarding the operational 

conditions and wastewater management practices at steam electric 

power plants. In some cases, where appropriate and as specified 

below, EPA presents additional information characterizing 

significant changes to operational practices that have taken 

place since 2009.

1. Fly Ash and Bottom Ash Systems

Plants use particulate removal systems, which typically 

consist of either electrostatic precipitators (ESPs) or fabric 

filters, to collect fly ash and other particulates from the flue 

gas. The fly ash and other particulates are captured by the ESP 

or fabric filters and collected in hoppers located underneath 

the equipment. From the collection hoppers, the fly ash is 

either pneumatically transferred as dry ash to silos for 

temporary storage or transported (sluiced) with water to a 

surface impoundment (i.e., ash pond). The water used to 

transport the fly ash to the surface impoundment is usually 

discharged to surface water as overflow from the impoundment
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after the fly ash has settled. Of the coal- and petroleum cokefired steam electric generating units that generate fly ash, 66

percent operate dry fly ash transport systems, while 15 percent

operate both wet and dry fly ash transport systems. The 

remaining 19 percent operate only wet fly ash transport systems, 

although not all of these plants discharge their fly ash 

transport water. In cases where a unit has both wet and dry 

handling operations, the wet handling system is typically used 

as a backup to the dry system.

Fly ash transport water is one of the largest volume flows 

for coal-fired power plants. Many wet transport plants (i.e., 45 

percent of plants with wet fly ash systems) sluice their fly ash 

continuously, and 68 percent of wet transport plants sluice 

their fly ash at least 12 hours per day. Based on responses to 

the industry survey, the average fly ash transport water flow 

rate is 2.4 million gallons per day (MGD.). EPA estimates that 

the total steam electric industry discharged a total of 81.1 

billion gallons of fly ash transport water to surface water in 

2009.

In addition to the particulate removal system for removing 

fly ash from the flue gas, there are also systems for handling 

the bottom ash that accumulates at the bottom of the furnace.

The bottom ash consists of the heavier ash particles that could 

not be entrained in the flue gas and fall to the bottom of the 
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furnace. In most furnaces, the hot bottom ash is quenched in a 

water-filled hopper. Ash from the hopper is then fed into a 

conveying line where it is diluted into slurry and pumped to an 

impoundment or dewatering storage 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 storage bins is 

usually discharged to surface water as overflow from the 

systems, after the bottom ash has settled. Alternatively, some 

furnaces are fitted with mechanical drag systems where the 

bottom ash drops into a water-filled trough, but the ash is 

removed using a submerged mechanical drag conveyor that drags 

the bottom ash out of the furnace. At the end of the trough, the 

drag chain reaches an incline, which dewaters the bottom ash by 

gravity, draining the water back to the trough as the ash moves 

up the conveyor. The bottom ash is often dumped into a nearby 

bunker for temporary storage. As the bottom ash continues 

dewatering in the nearby bunker, water that drains from the 

system may be discharged; however, EPA does not consider this 

water from the bunker to be bottom ash transport water because 

the mechanical conveyor, and not the water, is the transport 

mechanism that moves the ash away from the boiler. Instead, the 

wastewater draining from the bunker would be low volume wastes.

Over 65 percent of the units generating bottom ash operate wet 
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bottom ash transport systems, approximately 30 percent operate 

systems that eliminate the use of transport water, and 

approximately 5 percent operate both. Plants that have both wet 

and dry handling operations typically use the wet handling 

system as a backup to the dry system. Some plants that have wet 

bottom ash systems operate them in a manner that does not 

discharge to surface water.

Bottom ash transport water is an intermittent stream from 

steam electric units. The bottom ash transport water flow rates 

are typically not as large as the fly ash transport water flow 

rates; however, bottom ash transport water is still one of the 

larger volume flows for steam electric plants. Based on 

responses to the industry survey, the average bottom ash 

transport water flow rate is 1.8 MGD. EPA estimates that the 

total steam electric industry dischargedischarged a total of 157 

billion gallons of bottom ash transport water was 157 billion

gallons in 2009.

Power plants that generate fly ash and bottom ash can 

either dispose of it in landfills or surface impoundments, or 

can beneficially use it in other applications such as cement or 

concrete manufacturing. Power plants have used the ash in many 

applications to avoid disposingthat preclude the need to dispose

of the ash in landfills/impoundments.
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2. FGD Systems

FGD systems are used to remove sulfur dioxide from the flue 

gas, so that it is not emitted into the air. There are both wet 

and dry FGD systems. Dry FGD systems generally inject an aqueous 

sorbent (e.g., lime) into a spray dryer such that the water 

present evaporates as it contacts the hot flue gas. The sulfur 

dioxide in the flue gas reacts with the lime as it dries and 

results in a dry particulate product that is captured in a 

downstream fabric filter; no wastewater is generated from the 

dry FGD process. In wet FGD systems, the flue gas stream comes 

in contact with a liquid stream containing a sorbent, typically 

lime or limestone, which is used to effect the mass transfer of 

pollutants from the flue gas to the liquid stream. This process 

not only transfers the sulfur dioxide from the flue gas to the 

liquid stream, but other pollutants (e.g., metals) as well.

During this process, the lime/limestone and sulfur dioxide react 

to form calcium sulfite or calcium sulfate (i.e., gypsum), 

depending on the oxidation level of the FGD system. Gypsum is a 

marketable product, and as such, plants that generate gypsum 

generally sell (or give away) the material for use in building 

materials (e.g., wallboard). Plants that do not generate gypsum, 

or only partially oxidize the calcium sulfite, generally dispose 

of their FGD solids in landfills or surface impoundments. Those 

plants that produce a saleable product, such as gypsum, may 
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rinse the product cake to reduce the level of chlorides in the 

final product. This wash water may be reused or discharged to a 

receiving water or POTW. Additionally, both calcium sulfite and 

gypsum typically require dewatering prior to sale/disposal and 

this dewatering process also generates a wastewater stream that 

may be reused or discharged. Although the FGD system is a net 

water consumer because of the large evaporative water losses 

that require make-up water to the system, theThe FGD system 

generally requires a blowdown stream to purge chlorides to 

prevent scaling and corrosion of the FGD equipment.

FGD wastewater is typically an intermittent stream 

generated by coal-fired power plants operating wet FGD systems. 

Based on responses to the industry survey, the average FGD 

wastewater flow rate is 559,000 gallons per day (gpd). EPA 

estimates that the total steam electric industry 

dischargedischarged a total of FGD wastewater was 23.7 billion

gallons of FGD wastewater in 2009.

Based on the responses to the industry survey, there are 

approximately 401 FGD systems either currently operating or that 

will be installed by January 1, 2014.

9 Approximately 90 of the 

currently operating FGD systems are dry systems that do not 

 

9 Because EPA expects to take final action on this rule in 2014, EPA used 2014 

as the baseline year for its analysis. EPA is considering using alternative 

dates, such as 2022 which may better reflect the implementation timeframe for 

the ELG, for the baseline year for its analyses for the final rule.
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generate or affect any wastewater streams, while 311 systems are 

wet FGD systems.10

3. Flue Gas Mercury Control (FGMC) Systems

FGMC systems remove mercury from the flue gas, so that it 

is not emitted into the air. According to the responses to the 

industry survey, two main types of systems are currently in use 

in the industry: (1) addition of oxidizers to the coal prior to 

combustion, whereby the oxidized mercury is removed in the wet 

FGD system; and (2) injection of activated carbon into the flue 

gas which adsorbs the mercury and is captured in a downstream 

particulate removal system.

The use of the oxidizers does not generate a new wastewater 

stream; however, it may increase the concentration of mercury in 

the FGD wastewater because the oxidized mercury is more easily 

removed by the FGD system. The activated carbon injection system 

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 (i.e., FGMC waste) is

collected and handled the same way as the fly ash; therefore.

Therefore, if the fly ash is wet sluiced, then the FGMC wastes 

are also wet sluiced and likely sent to the same surface 

 

10 This is not the number of steam electric power plants with wet FGD systems. 

An individual steam electric power plant may operate one or more FGD systems. 
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impoundment. In this case, adding the FGMC wastes 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, then the plant will need a secondary 

particulate removal system (typically a fabric filter) to 

capture the FGMC wastes. Plants typically inject the carbon 

downstream of the primary particulate collection system if they 

plan to market the fly ash because the carbon in FGMC wastes can 

make the fly ash unmarketable. In this situation, the FGMC 

wastes, which would be collected with some carry-over fly ash, 

could be handled either wet or dry.

Based on the responses to the industry survey, in 2009 

there were approximately 120 currently operating FGMC systems, 

with an additional 40 planned for installation by 2020.

Approximately 90 percent of the currently operating FGMC systems 

are dry systems that do not generate or affect any wastewater 

streams. Approximately six percent of the currently operating 

systems are wet systems. For the remaining 4 percent of the 

systems, the type of handling system (e.g., wet or dry handling) 

is unknown.

4. Combustion Residual Leachate from Surface Impoundments and 

Landfills

Combustion residuals comprise a variety of wastes from the 

combustion process, including fly ash, bottom ash (which 
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includes boiler slag), and FGD solids (e.g., gypsum and calcium 

sulfite), which are generally collected by or generated from the 

air pollution control technologies. These combustion residuals 

may be stored at the plant in on-site landfills or surface 

impoundments (i.e., ponds). Based on industry survey results, 

there are approximately 228 plants that operate combustion 

residual landfills and 264 plants that operate combustion 

residual surface impoundments. Some plants operate both 

landfills and impoundments, while other plants may operate only 

one or the other, or neither type of disposal unit.

Leachate is the liquid that drains or leaches from a 

landfill or surface impoundment. Most landfills have a system to 

collect the leachate and some impoundments have leachate 

collection systems. The two sources of leachate are 

precipitation that percolates through the waste deposited in the 

landfill/impoundment and the liquids produced from the 

combustion residuals placed in the landfill/impoundment. In 

addition to leachate, stormwater that enters the impoundment or 

contacts and flows over the landfill would be contaminated with 

combustion residual pollutants. Leachate and contaminated 

stormwater contain heavy metals and other contaminants through 

the contact with the combustion residuals.

Some landfills and surface impoundments are lined. In a 

lined landfill/impoundment, the leachate collected in the liner
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typically flows through a collection system consisting of 

ditches and/or underground pipes. From the collection system, 

the leachate is transported to an impoundment (e.g., collection 

pond). The stormwater collection systems typically consist of 

one or more small impoundments or collection ponds. The leachate 

and stormwater may be treated in separate impoundments or 

combined together. Some plants discharge the effluent from these 

leachate impoundments, while other plants send the leachate 

impoundment effluent to another impoundment handling the ash 

transport water or other treatment system (e.g., constructed 

wetlands). Unlined impoundments and landfills usually do not 

collect leachate thereby leaving the leachate to potentially 

migrate to nearby ground waters, drinking water wells, or 

surface waters.

Based on responses to the industry survey, approximately 

100 plants collect landfill leachate from approximately 110 

existing (i.e., active or inactive) landfills containing CCR, 

while approximately 50 plants collect leachate from existing CCR 

surface impoundments. Another 40 plants collect leachate from 

both types of systems. 

Leachate is an intermittent stream whose flow rate, 

frequency, and duration are generally determined by weather 

conditions. For this reason, leachate flow rates can vary 

greatly for a plant, as well as varying from one plant to 
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another. Additionally, there are differences in flow rates 

depending on whether the landfill or surface impoundment is 

active/inactive or retired. Retired landfills or surface 

impoundments tend to have lower flow rates because they have 

been capped or closed and, therefore, are not open to the 

atmospheric rainfall. Based on the industry survey, the average 

active/inactive landfill leachate flow rate was approximately 

60,000 gpd. EPA estimates that the steam electric industry 

discharged approximately 6.2 billion gallons of leachate in 

2009.

5. Gasification Processes

As described above, IGCC plants uses 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.

In these IGCC plants, after the syngas is produced, it undergoes 

cleaning prior to combustion. The cleaning processes can involve 

any number of the following processes:

Water scrubbing;

Carbonyl-sulfide hydrolysis;

Acid gas removal (stripping); and

Sulfur recovery.

The wastewater generated by these processes, along with any 

condensate generated in flash tanks, slag handling water, or 

wastewater generated from the production of sulfuric acid, are 
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referred to as “grey water” or “sour water,” and require 

treatment prior to reuse or discharge. 

EPA identified two plants currently operating IGCC units, 

and a third IGCC unit is expectedscheduled to begin operation in 

the near future. According to the industry survey responses, no 

other plants reported plans to install anthis year. A fourth

IGCC unit by 2020power plant is under construction and is 

scheduled to begin commercial operation in 2014.

The gasification processes generally operate continuously 

and, therefore, generate most of the individual gasification 

wastestreams continuously. Based on the information collected 

during EPA’s sampling program, EPA determined the gasification 

wastewater transferred to the treatment system ranged from 6,000 

to 109,000 gpd, with an average flow of 66,000 gpd.

6. Metal Cleaning Wastes

The ELGs define metal cleaning waste as “any wastewater 

resulting from cleaning [with or without chemical cleaning 

compounds] any metal process equipment, including, but not 

limited to, boiler tube cleaning, boiler fireside cleaning, and 

air preheater cleaning.” 40 CFR 423.11. Plants use chemicals to

remove scale and corrosion products that accumulate on the 

boiler tubes and retard heat transfer. The major constituents of 

boiler cleaning wastes are the metals of which the boiler is 

constructed, typically iron, copper, nickel, and zinc. Boiler 
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firesides are commonly washed with a high-pressure water spray 

against the boiler tubes while they are still hot. Fossil fuels 

with significant sulfur content will produce sulfur oxides that 

adsorb on air preheaters. Water with alkaline reagents is often 

used in air preheater cleaning to neutralize the acidity due to 

the sulfur oxides, maintain an alkaline pH, and prevent 

corrosion. The types of alkaline reagents used include soda ash, 

caustic soda, phosphates, and detergent.

The frequency of metal cleaning activities can vary 

depending on the type of cleaning operation and individual plant 

practices. Some operations occur as often as several times a 

day, while others occur once every several years. Soot blowing, 

the process of blowing away the soot deposits on furnace tubes, 

generally occurs once a day, but some units do this as often as 

several hundred times a day. While 83 percent of units 

responding to the industry survey use steam or service air to 

blow soot, some plants may generate wastewater streams. Air 

heater cleaning is another frequent cleaning activity. Sixty-six 

percent of the units perform this operation at least once every 

two years, while other units perform this cleaning task very 

infrequently, only once every 40 years. Generally, plants use 

raw or potable water to clean the air heater [ERG, 2012b]..

The following types of metal cleaning wastes were reported 

in responses to the industry survey:
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Air compressor cleaning;

Air-cooled condenser cleaning;

Air heater cleaning;

Boiler fireside cleaning;

Boiler tube cleaning;

Combustion turbine cleaning (combustion portion and/or 

compressor portion);

Condenser cleaning;

Draft fan cleaning;

Economizer wash;

FGD equipment cleaning;

Heat recovery steam generator cleaning;

Mechanical dust collector cleaning;

Nuclear steam generator cleaning;

Precipitator wash;

SCR Catalystcatalyst soot blowing;

Sludge lancing;

Soot blowing;

Steam turbine cleaning; and

Superheater cleaning.

7. Carbon Capture and Storage Systems

The industry is investigating carbon capture and storage 

systems to remove carbon dioxide (CO2) from the flue gas. Many 

steam electric power plants are considering alternatives 

available for reducing CO2 emissions; however, according to the 

industry survey responses, there are no full-scale carbon 

capture systems currently operating. EPA obtained information 

about two pilot-scale systems that operated in recent years; 

however, neither of these systems is currently operating. 

Additionally, several plants reported in their survey responses 

that they are planning to install a pilot-scale carbon capture 
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system and some plants reported plans to install full-scale 

systems by 2020.

11

There are three main approaches for capturing the CO2

associated with generating electricity: post-combustion, precombustion, and oxyfuel combustion. 

In post-combustion capture, the CO2 is removed after 

combustion of the fossil fuel. 

In pre-combustion capture, the fossil fuel is partially 

oxidized, such as in a gasifier. The resulting syngas (CO 

and H2) is processed to create CO2 and more H2, and the 

resulting CO2 can be captured from a relatively pure exhaust 

stream before combustion takes place. 

In oxy-fuel combustion, also known as oxy-combustion, the 

fuel is burned in oxygen instead of air. The flue gas 

consists of mainly CO2 and water vapor; the latter condenses 

through cooling. The result is an almost pure CO2 stream 

that can be transported to the sequestration site and 

stored. 

Based on preliminary information regarding these 

technologies, EPA believes they may result in new wastewaters at 

steam electric power plants. However, as these technologies are 

currently in the early stages of research and development and/or 

pilot testing, the industry has little information on the 

potential wastewaters generated from carbon capture processes. 

As part of its sampling program, EPA obtained analytical data 

associated with two wastestreams generated from a postcombustion carbon capture system. Because of the small size of 

 

11 In order to protect CBI claims, EPA cannot provide specific numbers.
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the pilot-scale system, the plant transferred the wastewater off 

site for treatment.

C. Control and Treatment Technologies

EPA evaluated the technologies available to control and 

treat wastewater generated by the steam electric industry. 

Individual plants may use one or more processes that generate 

wastewater streams. They may treat these wastestreams separately 

or in various combinations. For this reason, EPA evaluated 

available technologies for each major wastestream separately.

1. FGD Wastewater

EPA identified 145 steam electric power plants that 

generate FGD wastewater. Of these, 117 plants (81 percent) 

discharge FGD wastewater after treatment using one or more of 

the following technologies:

Surface Impoundments: Surface impoundments (e.g., settling 

ponds), designed to remove particulates from wastewater by 

means of gravity, may be configured as one impoundment or a 

series of impoundments. Impoundments are typically sized to 

allow for a certain residence time to enable the suspended 

solids to settle to the bottom. The impoundments are also 

designed to have sufficient capacity to allow for temporary 

storage or permanent disposal of the settled solids. 

Surface impoundments are not designed to remove dissolved 

metals. Plants may add treatment chemicals to the 

impoundment, typically to adjust pH before final discharge.

There are 63 plants (54 percent of the discharging plants) 

that use surface impoundments as the only type of treatment 

for FGD wastewaters. Most (49) of these plants also combine 

their FGD wastewater with other plant wastewater while the 

remainder (14) use impoundments to treat FGD wastewater 
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alone. Additional plants (above and beyond the 63 plants 

described in the preceding sentences) also use surface 

impoundments to remove suspended solids prior to a more 

advanced treatment process, such as chemical precipitation 

or biological treatment. 

Chemical Precipitation: Some plants use chemical 

precipitation systems instead of or in addition to surface 

impoundments. Chemical precipitation treatment is a tankbased system in which chemicals are added to enhance the 

removal of suspended solids and dissolved solids, 

particularly certain dissolved metals. The dissolved metals 

amenable to chemical precipitation treatment are removed 

from aqueous solutions by converting soluble metal ions to 

insoluble metal hydroxides or sulfides. The precipitated 

solids are then removed from solution by 

coagulation/flocculation followed by clarification and/or 

filtration. Chemical reagents such as lime (calcium 

hydroxide), sodium hydroxide, and ferric chloride are used 

to adjust the pH of the water to reduce the solubility of 

the metal(s) targeted for removal.

Some plants also use sulfide chemicals (e.g., 

organosulfides or sodium sulfide) to precipitate and remove 

heavy metals, including mercury. Sulfide precipitation is 

more effective than hydroxide precipitation in removing 

mercury because mercury sulfides have lower solubilities 

than mercury hydroxides. Other metal sulfide compounds also 

typically have lower solubilities than metal hydroxide 

compounds. Because sulfide precipitation is more expensive 

than hydroxide precipitation, plants usually use hydroxide 

precipitation first to remove most of the metals, and then 

sulfide precipitation to remove the remaining low 

solubility metals. This configuration overall requires less 

sulfide, thereby reducing the expense for the sulfide 

treatment chemicals.

EPA identified 40 plants (34 percent of the discharging 

plants) that treat their FGD wastewater using chemical 

precipitation (in some cases, also employing additional 

treatment steps such as biological treatment). Lime is the 

most commonly used treatment chemical to perform the pH 

adjustment needed for these systems. Sulfide precipitation, 

alone or in combination with hydroxide precipitation, is 

used by 33 plants (28 percent of the discharging plants). 

Most plants operating chemical precipitation treatment 

systems for FGD wastewater employ ferric chloride addition 

(i.e., iron coprecipitation) as part of the treatment 

process.
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Biological Treatment: Some steam electric power plants also 

treat FGD wastewater using biological treatment systems. An 

anoxic/anaerobic biological system being used in the 

industry is effective at removing both metals (total and 

dissolved) and nutrients. This system is designed to 

significantly reduce nitrogen compounds and selenium. These 

fixed-film bioreactors are designed for plug flow operation 

and have zones of differing oxidation potential that allow 

for nitrification and denitrification of the wastewater and 

reduction of metals, such as selenium. The system alters 

the form of selenium, reducing selenate and selenite to 

elemental selenium, which is then captured by the biomass 

and retained in treatment system residuals.

EPA identified five plants that operate the fixed-film 

anoxic/anaerobic biological treatment systems to treat FGD 

wastewater. Another, and another plant recently installed a 

suspended growth biological treatment system that targets 

removal of selenium and other metals.12 Four of these six 

plants also operate chemical precipitation systems prior to 

the biological treatment system. There are also at least 

four other plants that operate aerobic/anaerobic sequencing 

batch reactors to treat FGD wastewater that has already 

undergone chemical precipitation. These systems are capable 

of removing organics and nutrients, but doare not operated 

in a manner to remove selenium or other metals.

Vapor-Compression Evaporation System: This type of system 

uses a falling-film evaporator (or brine concentrator) to 

produce a concentrated wastewater stream and a distillate 

stream. With pretreatment, such as chemical precipitation 

and softening, brine concentrators can reduce wastewater 

volumes by 80 to 90 percent. Plants can further process the 

concentrated wastewater stream in a crystallizer or spray 

dryer, which evaporates the remaining water to generate a 

solid waste product and potentially a condensate stream.

The distillate and condensate streams may be reused within 

the plant or discharged to surface waters. EPA identified 

two U.S. plants and four Italian plants that treat FGD 

wastewater using vapor-compression evaporation. A third 

U.S. plant is currently installing a vapor-compression

evaporation treatment system; it is scheduled to be 

operational by the end of 2013.

 

12 A seventh plant is scheduled to begin operating a biological treatment 

system for selenium removal in 2014. This plant is not included in this 

summary of biological treatment systems.
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Constructed Wetlands: Constructed wetlands are engineered 

systems that use natural biological processes involving 

wetland vegetation, soils, and microbial activity to reduce 

the concentrations of metals, nutrients, and TSS in 

wastewater. High temperature, chemical oxygen demand (COD), 

nitrates, sulfates, boron, and chlorides in wastewater can 

adversely affect constructed wetlands performance. To 

overcome this, plants typically dilute FGD wastewater with 

service water (i.e., supply water used widely throughout 

the plant for a variety of uses) before it enters a 

constructed wetland.

EPA identified three plants that treat their FGD wastewater 

using constructed wetlands. The constructed wetlands used 

to treat FGD wastewater typically are designed to treat 

only the FGD wastewater (and the service water used for 

dilution); however, because these systems are open to the 

environment, they also receive stormwater from the 

surrounding areas.

Other Technologies: EPA identified several other 

technologies that have been evaluated for treatment of FGD 

wastewater, including iron cementation, reverse osmosis, 

absorption or adsorption media, ion exchange, and electrocoagulation. Other technologies under laboratory-scale 

study include polymeric chelates, taconite tailings, and 

nano-scale iron reagents. Most of these technologies have 

been evaluated only as pilot-scale studies; however, two of 

these technologies are currently operating at full-scale to 

treat FGD wastewater. One plant operates a full-scale ion 

exchange system that selectively targets the removal of

boron, in conjunction with a chemical precipitation 

treatment stage to remove mercury and other metals, and an 

anaerobic biological treatment stage to remove selenium. 

Another plant treats the FGD wastewater with chemical 

precipitation, followed by a full-scale treatment unit that 

uses cartridge filters in combination with two sets of 

adsorbent media specifically designed to enhance removals 

of metals. After passing through three sets of cartridge 

filters (3-micron, 1-micron, and then 0.2-micron), the FGD 

wastewater passes through a carbon-based media that adsorbs 

mercury, and then through a ferric hydroxide-based media 

that adsorbs arsenic, chromium, and other metals. The 

adsorbent media reportedly achieves a maximum effluent 

concentration of 14 parts per trillion for mercury.

Design/Operating Practices Achieving Zero Discharge: EPA 

identified four design/operating practices available 

enabling plants to eliminate the discharge of wastewater 
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from wet FGD systems: 1) several variations of complete 

recycle, 2) evaporation ponds, 3) conditioning dry fly ash, 

and 4) underground injection. Of the 145 plants that 

generate wastewater from FGD processes, 28 plants (19

percent) operate in such a manner that they do not 

discharge wastewater to surface waters or POTWs. Many of 

the plants in the southwestern United States that generate 

FGD wastewater use evaporation ponds that do not discharge.

2. Fly Ash Transport Water

Fly ash separated from boiler exhaust by electrostatic 

precipitators (ESPs) or fabric filters is collected in hoppers 

located underneath the equipment. From the collection hoppers, 

the fly ash is either transferred as dry ash to silos for 

temporary storage or transported (sluiced) with water to a 

surface impoundment (i.e., ash settling pond). Plants that 

generate fly ash transport water use surface impoundments to 

manage the wastewater. EPA has not identified any facilities 

using more advanced treatment, such as chemical precipitation or 

biological treatment, to treat fly ash transport water. EPA 

identified 393 generating units (at 144 plants) that wet sluice 

at least a portion of fly ash. Wet sluicing systems use waterpowered hydraulic vacuums to withdraw fly ash from the hoppers. 

The ash is pulled to a separator/transfer tank, combined with 

sluicing water, and pumped to the surface impoundment to remove 

particulates from the wastewater by means of gravity, before 

discharge to a receiving stream. 
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Many coal and oil-fired power plants design their fly ash 

handling systems to minimize or eliminate the discharge of fly 

ash handling transport water. Such approaches include:

Wet Vacuum Pneumatic System: These systems use waterpowered hydraulic vacuums for the initial withdrawal of fly 

ash from the hoppers, similar to wet sluicing systems. 

Instead of sluicing the ash to a surface impoundment, these 

systems capture the ash in a filter – receiver (bag filter 

with a receiving tank) and then deposit the dry ash in a 

silo. 

Dry Vacuum Pneumatic System: These systems use a mechanical 

exhauster to move air, below atmospheric pressure, to pull 

the fly ash from the hoppers and convey it directly to a 

silo. The fly ash empties from the hoppers in to the 

conveying system via a material handling valve.

Pressure System: These systems use air produced by a 

positive displacement blower to convey ash directly from 

the hopper to a silo. Each ash collection hopper is 

equipped with airlock valves that transfer the fly ash from 

low pressure to high pressure in the conveying line. The 

airlock valves are installed at the bottom of the hoppers

and require a significant amount of space. Retrofit 

installations of pressure ash handling systems may require 

raising the bottom of the hopper. 

Combined Vacuum/Pressure System: These systems use a dry 

vacuum system to pull ash from the hoppers to a transfer 

station, where the ash is transferred from the vacuum (low 

pressure) to ambient pressure. From the transfer station, 

the fly ash is transferred via airlock valves to a high 

pressure conveying line. A positive displacement blower 

conveys the ash to a silo. Because the airlocks are not 

located under the hopper, combination vacuum/pressure 

systems have the space advantages of dry vacuum systems. 

Mechanical System: Oil-fired units or other units that 

generate a low volume of fly ash may use manual or 

systematic approaches to remove fly ash (e.g., scraping the 

sides of the boilers with sprayers or shovels, then 

collecting and removing the fly ash to an intermediate 

storage destination or disposal).
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The following identifies the number of units (and plants) 

in the steam electric industry operating each of the different 

technologies available to eliminate the discharge of fly ash 

transport water:

Wet vacuum pneumatic system – 51 units (22 plants);

Dry vacuum pneumatic system – 485 units (220 plants);

Pressure system – 188 units (91 plants);

Combined vacuum/pressure system – 223 units (102 plants);

Mechanical system – 16 units (13 plants); and

Other dry systems – 5 units (3 plants).

3. Bottom Ash Transport Water

Bottom ash (at times also referred to as boiler slag) is 

produced as fuel is burned in a boiler and collected in hoppers 

or other types of collection equipment directly below the 

boiler. Generally, boilers are sloped inward, with an opening at 

the bottom to allow the bottom ash to feed by gravity into 

collection hoppers. The hoppers contain water to quench the hot 

ash. Once the hoppers are full, gates at the bottom of the 

hoppers open, releasing the bottom ash and quench water to a 

conveying line, where the ash is diluted with water to 

approximately 20 percent solids (by weight) and pumped to a 

surface impoundment or a dewatering bin for solids removal. 

Conveying bottom ash in a water slurry is called wet sluicing. 

EPA identified 870 units (345 plants) that wet sluice at least a 

portion of their bottom ash. For further information, see 
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Section 4.3.2 of the Technical Development Document for Proposed 

Effluent Limitations Guidelines and Standards for the Steam 

Electric Power Generating Point Source Category (TDD) – EPA 821-

R-13-002.

Many coal and oil-fired power plants design their bottom 

ash handling systems to reduce or eliminate the discharge of 

bottom ash handling transport water. Available technologies

include:

Mechanical Drag System: In these systems, the ash 

collection hopper is replaced with a transition chute that 

routes the bottom ash to a water-filled trough. In the 

trough, a drag chain continuously moves the ash to an 

incline where it is dewatered and then conveyed to a nearby 

ash collection area. Excess quench water collected in the 

dewatering system is recycled to the quench water bath. 

Although mechanical drag systems require little space under 

the boiler they may not be suitable for all boiler 

configurations. 

In the steam electric industry, 99 coal-fired units use 

mechanical drag systems for bottom ash handling. Operators 

have announced plans to retrofit mechanical drag systems on 

additional units by 2020. EPA estimates that these 

announced retrofits include approximately 10-30 generating

units. (Note: the precise value has been withheld to 

prevent disclosing CBI.)

Remote Mechanical Drag System: These systems collect bottom 

ash in water-filled hoppers and wet sluice the ash to a 

mechanical drag system located away from the boilers. 

Sluice water collected from the dewatered bottom ash is 

collected and reused in the bottom ash handling system. 

Plants can use remote mechanical drag systems to convert 

existing bottom ash handling systems with limited space or 

other configuration limitations. TwoOne U.S. plants 

areplant has installed and is currently operating a remote 

mechanical drag system to handle bottom ash. At least one 

additional plant is currently installing a remote 

mechanical drag systems to handle bottom ash. Additionally, 
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a large U.S. power company has been evaluating installing

remote mechanical drag systems for several of its plants.

Dry Vacuum or Pressure System: These systems transport 

bottom ash from the boiler to a dry hopper without using 

any water. The system percolates air through the ash to 

cool it and combust unburned carbon. Cooled ash then drops 

to a crusher and is conveyed via vacuum or pressure to an 

intermediate storage destination.

Complete Recycle System: Complete recycle systems transport 

bottom ash using the same processes as wet sluicing 

systems. Plants can install complete recycle on existing 

wet sluicing units. Instead of transporting it to an 

impoundment, the ash is sluiced to dewatering bins, where 

it is dewatered and moved to storage. The transport 

(sluice) water is treated to remove solids in a settling 

tank and is recycled to the bottom ash collection system. 

Prior to reusing the treated transport water, plants may 

add treatment chemicals to the water to adjust pH and 

prevent equipment corrosion.

Vibratory Belt System: Bottom ash deposits on a vibratory 

conveyor trough, where the plant cools the ash by air and 

ultimately moves it through the conveyor deck to an 

intermediate storage destination.

Mechanical System: Oil-fired units or other units that 

generate a low volume of bottom ash, may use manual or 

systematic approaches to removing ash that accumulates in 

the boiler (e.g., scraping the sides of the boilers with 

sprayers or shovels, then collecting and removing the 

bottom ash to an intermediate storage destination or 

disposal).

The following identifies the number of units (and plants) 

in the steam electric industry operating each of the different 

technology options available to eliminate/ or minimize the 

amount of bottom ash transport water:

Mechanical drag system – 99 units (74 plants);

Remote mechanical drag system – at least 2 units (2 plants) 

installing systems since 2009;

Dry vacuum system – 111 units (68 plants);
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Dry pressure system – 13 units (11 plants);

Complete recycle systems – at least 20 plants; and

Mechanical systems – 38 units (19 plants).

4. Combustion Residuals Leachate from Landfills and Surface 

Impoundments

Plants often treat combustion residual landfill leachate 

with some of the same technologies used to treat FGD wastewater 

and described in Section VI.C.1. EPA identified 102 coal-fired 

power plants that generate and discharge leachate. Based on the 

responses to the industry survey, 29 of these plants treat the 

leachate prior to discharge using surface impoundments, 

constructed wetlands, or biological treatment. In some cases, 

plants co-treat the leachate with FGD wastewaters and, in some 

cases, treat the leachate independently.

Based on information from the industry survey and site 

visits, surface impoundments are the most common type of system 

used to treat combustion residual leachate from landfills and 

impoundments. Constructed wetlands are the next most commonly 

used treatment system. The anoxic/anaerobic biological treatment 

system used as the basis for FGD wastewater effluent limits in 

this proposed rule is also being used by one plant to treat 

leachate, with the leachate mixing with FGD wastewater 

immediately prior to the bioreactor stage.
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Some plants mix the leachate with fly ash prior to 

disposing the ash in a landfill to control fugitive dust 

emissions and to improve the handling characteristics of the dry 

fly ash. Leachate is also used at some plants for dust control 

around ash loading areas and landfills. Many plants will collect 

the leachate from a surface impoundment and pump it directly 

back to the impoundment from which it originated.

Physical/chemical treatment systems are capable of 

achieving low effluent concentrations of various metals and are 

effective at removing many of the pollutants of concern present 

in leachate discharges to surface waters. The pollutants of 

concern in leachate have also been identified as pollutants of 

concern for FGD wastewater, fly ash transport wastewater, bottom 

ash transport water, and other combustion residuals. This is to 

be expected since the leachate itself comes from landfills and 

surface impoundments containing the combustion residuals and 

those wastes are the source for the pollutants entrained in the 

leachate. Given the similarities present among the different 

types of wastewaters associated with combustion residuals, 

combustion residual leachate will be similarly amenable to 

chemical precipitation treatment. The treatability of pollutants 

such as arsenic and mercury using chemical precipitation 

technology is also demonstrated by technical information 

compiled for ELGs promulgated for other industry sectors. See, 
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e.g., the TDDs supporting the ELGs for the Landfills point 

source category (EPA-821-R-99-019) and the ELGs for the Metal 

Products and Machinery point source category (EPA-821-B-03-001). 

5. Gasification Wastewater 

The treatment technologies in use at steam electric power 

plants for gasification wastewater include:

Vapor-Compression Evaporation System: This type of system 

is identical to the vapor-compression evaporation system 

described for FGD wastewater. It uses a falling-film 

evaporator (or brine concentrator) to produce a 

concentrated wastewater stream and a distillate stream. The 

concentrated wastewater stream may be further processed in 

a crystallizer or spray dryer, which evaporates the 

remaining water to generate a solid waste product and 

potentially a condensate stream. Facilities may reuse the 

distillate and condensate streams within the plant or 

discharge them to surface waters.

Cyanide Destruction System: This system adds sodium 

hypochlorite (i.e., bleach) to the wastewater in mixing 

tanks to destroy the cyanide. The cyanide system treats the 

condensate and distillate streams from both the brine 

concentrator and crystallizer just prior to discharge.

EPA is aware of two plants that currently operate 

integrated gasification combined cycle (IGCC) units in the 

United States, as well as oneand a third plant that is currently 

constructingscheduled to begin operating an IGCC unit this year. 

All three of these plants currently treat or plan to treat the 

IGCC wastewaters with vapor-compression evaporation systems. The 

IGCC plant under constructionscheduled to begin operating this 

year is installing both a vapor-compression evaporation system 
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and a cyanide destruction system to treat the gasification 

wastewater.

6. Flue Gas Mercury Control (FGMC) Wastewater

FGMC wastewater originates from activated carbon injection

systems. The system can be configured either upstream or 

downstream of the primary particulate collection system. EPA 

identified 73 plants with current or planned activated carbon 

injection systems. Of these, 58 plants operate upstream 

injection systems while the remaining 15 plants inject the 

carbon downstream.

In cases where the injection occurs upstream of the primary 

particulate collection system, plants collect and handle the 

mercury-containing carbon with the fly ash. In cases where the 

injection occurs downstream of the primary particulate 

collection system, plants collect the mercury-containing carbon 

in a secondary particulate control system (e.g., a fabric 

filter). As with fly ash systems, plants collect the mercurycontaining carbon in hoppers located underneath the equipment. 

From the collection hoppers, plants either transfer the mercurycontaining carbon as dry ash to silos for temporary storage (67 

plants; 92 percent) or transport (sluice) it with water to an 

ash impoundment (6 plants; 8 percent). Water transport can 

result in a wastewater discharge, typically an overflow from the 

impoundment. However, five of the six plants that use water to 
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transport the FGMC waste to a surface impoundment do not 

discharge any FGMC wastewater and the remaining plant has the 

capability to handle the FGMC waste using a dry system but 

sometimes uses a wet system instead. 

Coal-fired power plants can minimize or eliminate the 

discharge of FGMC particulate handling transport water by using 

the same solids handling technologies asthat are available for 

fly ash. These technologies include:

Wet Vacuum Pneumatic System: These systems use waterpowered hydraulic vacuums to withdraw dry FGMC waste from 

the hoppers, similar to wet sluicing systems. Instead of 

sluicing the FGMC waste to a surface impoundment, these 

systems capture the FGMC waste in a filter – receiver (bag 

filter with a receiving tank) and then deposit it in a 

silo. 

Dry Vacuum Pneumatic System: These systems use a mechanical 

exhauster to move air, below atmospheric pressure, to pull 

the FGMC waste from the hoppers and convey it directly to a 

silo. The collected FGMC waste empties from the hoppers in 

to the conveying system via a material handling valve.

Pressure System: These systems use air produced by a 

positive displacement blower to convey FGMC waste directly 

from the hopper to a silo.

Combined Vacuum/Pressure System: These systems first 

utilize a dry vacuum system to pull FGMC waste from the 

hoppers to a transfer station, and then use a positive 

displacement blower to convey it to a silo.

7. Metal Cleaning Wastes

As described in Section VI.B.6, metal cleaning wastes are 

generated from cleaning any metal process equipment. Because 
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there are many different processes at plants that use metal 

equipment, there are a variety of metal cleaning wastes that are 

generated. The treatment methods used for each of the different 

types of metal cleaning wastes vary to some degree depending on 

the specific cleaning operations. 

Based on information from the industry survey, surface 

impoundments and chemical precipitation systems are two of the 

most common types of systems used to treat metal cleaning 

wastes. Other types of treatment systems include constructed 

wetlands, filtration, reverse osmosis, clarification, oil/water 

separation, and brine concentrators.

In addition to the treatment systems used to control the 

discharges of metal cleaning wastes, some plants also employ 

other handling approaches to control or eliminate the discharge 

of metal cleaning wastes. For example, some plants immediately 

recycle the metal cleaning wastes back to other plant 

operations, while other plants evaporate the metal cleaning 

wastes in the boiler to evaporate the wastewater and eliminate 

the discharge. Other handling operations reported in the 

industry survey include offsite treatment, hazardous waste 

disposal, third-party disposal, mixing with fly ash and 

landfilling, and deep well injection. 
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Physical/chemical treatment systems are capable of reducing 

the concentration of pollutants, including metals, in the 

wastewater.

VII. Selection of Regulated Pollutants

A. Identifying the Pollutants of Concern

The following paragraphs discuss the pollutants of concern

identified for each of the wastestreams considered for

regulation in this proposal. For the purpose of this rulemaking, 

pollutants of concern are those pollutants that have been 

quantified in a wastestream at sufficient frequency at treatable 

levels (i.e., concentrations). EPA used the following sources of 

wastewater characterization data to identify pollutants of 

concern in wastewater from steam electric power plants: EPA’s 

field sampling program, industry-supplied data including data 

provided in responses to the industry survey, and various 

literature sources. EPA relied primarily on its field sampling 

program data because the data were collected using consistent 

methods and analytical techniques for a broad range of 

pollutants. Therefore, where EPA had data from its field 

sampling program, it preferentially used that data. Where EPA 

did not collect field sampling data for a wastestream and 

industry-supplied data was available, EPA used that data. In the 

absence of either EPA field sampling data or industry-supplied 

data, EPA used literature data.
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After reviewing the available sources of data for each of 

the wastestreams addressed by this rulemaking, EPA first 

combined the pollutant data to create consolidated datasets 

representing the concentrations of pollutants present in each 

wastestream prior to treatment. EPA then eliminated all 

pollutants that were not detected in any wastewater samples –

any pollutants falling into this category are not considered 

pollutants of concern. Finally, for the remaining pollutants for 

each wastestream, EPA then identified each pollutant that was 

detected at a concentration greater than or equal to ten times 

the baseline value (see Section 6 of the TDD) in at least 10 

percent of all untreated process wastewater samples.

13

EPA identified the following 34 pollutants of concern for 

FGD wastewater using EPA field sampling data: one conventional 

pollutant (TSS);)

14; 13 toxic pollutants, including arsenic, 

cyanide, mercury, and selenium; 12 nonconventional metals; and 8 

other nonconventional pollutants (e.g., ammonia, 

nitrate/nitrite, and total phosphorus). 

EPA identified the following 24 pollutants of concern for 

fly ash transport water using EPA field sampling data: one 

 

13 This is consistent with the process EPA used to identify pollutants of 

concern for many categories. EPA takes this approach to ensure the pollutants 

are present in treatable levels.

14 EPA did not analyze its field sampling data for oil and grease. Rather, 

since the existing steam electric ELG currently contains BPT limitations 

applicable to FGD wastewater for oil and grease, EPA already has data from 

the existing rulemaking demonstrating oil and grease is also a pollutant of 

concern in FGD wastewater.
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conventional pollutant (TSS);)

15; 9 toxic pollutants (metals 

including arsenic, lead, mercury, and selenium)); 11 

nonconventional pollutant metals; and 3 other nonconventional 

pollutants (i.e., TDS, chloride, and nitrate/nitrite). 

EPA was unable to obtain readily available data for 

untreated bottom ash transport water for use in identifying the 

pollutants of concern using the methodology described above. 

However, because the pollutants found in bottom ash are 

constituents that are present in the coal (or petroleum coke or 

oil), as is the case for fly ash, EPA concluded that the 

pollutants of concern for bottom ash transport water are 

identical to the pollutants of concern identified for fly ash 

transport water. 

EPA was also unable to obtain readily available data for 

identifying the pollutants of concern in FGMC wastewater. 

Nevertheless, based on process knowledge and engineering 

judgment, EPA concluded that the pollutants of concern for FGMC 

wastewater are likely to be identical to the pollutants of 

concern identified for fly ash transport water. This is due to 

the fact that, when activated carbon is injected into the flue 

gases, the carbon intermixes with the fly ash particles, and 

 

15 EPA did not analyze its field sampling data for oil and grease. Rather, 

since the existing steam electric ELG currently contains BPT limitations 

applicable to fly ash transport wastewater for oil and grease, EPA already 

has data from the existing rulemaking demonstrating oil and grease is also a 

pollutant of concern in fly ash wastewater.
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then the commingled mixture of activated carbon (which adsorbs 

mercury and other pollutants from the flue gases) and fly ash 

particles is captured together and transferred to the FGMC 

wastewater.

EPA evaluated the pollutants of concern for combustion 

residual leachate using industry sampling data for untreated 

leachate submitted under Part G of the industry survey. EPA 

evaluated the landfill leachate separately from the surface 

impoundment leachate. The pollutants of concern for landfill 

leachate include the following: one conventional pollutant 

(TSS);)

16; 3 toxic pollutants (arsenic, mercury, and selenium); 9

nonconventional pollutant metals; and 3 other nonconventional 

pollutants (i.e., chloride, sulfate and TDS). The pollutants of 

concern for impoundment leachate include17: 2 toxic pollutants 

(i.e., arsenic and mercury), 7 nonconventional pollutant metals,

and 3 other nonconventional pollutants (i.e., chloride, sulfate, 

and TDS).

EPA identified 19 pollutants of concern for gasification 

wastewater using EPA field sampling data, including: 1 

 

16 The landfill leachate samples were not analyzed for oil and grease. 

Rather, since the existing steam electric ELG currently contains BPT 

limitations applicable to combustion residual leachate for oil and grease, 

EPA already has data from the existing rulemaking demonstrating oil and 

grease is also a pollutant of concern in combustion residual leachate.

17 The surface impoundment leachate samples were not analyzed for oil and 

grease. Rather, since the existing steam electric ELG currently contains BPT 

limitations applicable to combustion residual leachate for oil and grease, 

EPA already has data from the existing rulemaking demonstrating oil and 

grease is also a pollutant of concern in combustion residual leachate.
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conventional pollutant (BOD); 7 toxic pollutants (including 

arsenic, cyanide, mercury, and selenium); 5 nonconventional 

pollutant metals; and 6 other nonconventional pollutants.

As part of the 1974 rulemaking, EPA collected 

characterization data associated with chemical and nonchemical 

metal cleaning wastes. Based on the data collected during that 

rulemaking, EPA determined that TSS, oil and grease, copper, and 

iron were pollutants of concern for this wastestream warranting 

regulation and established BPT limitations for these four 

pollutants in discharges of metal cleaning wastes, including 

both nonchemical and chemical metal cleaning wastes. (EPA has 

also established BAT, NSPS, PSES, and PSESPSNS for chemical 

metal cleaning wastes.) For additional information regarding 

the pollutants that may be present in nonchemical metal cleaning 

wastes, see the 1974 Development Document for Effluent 

Limitations Guidelines and New Source Performance Standards for 

the Steam Electric Power Generating Point Source Category. Based 

on the information developed for the previous rulemakings for 

the steam electric power generating ELGs and the data from the 

industry survey, EPA identified 4 pollutants of concern for 

nonchemical metal cleaning wastes, including: 2 conventional 

pollutants (TSS and oil and grease); 1 toxic pollutant (copper); 

and 1 nonconventional pollutant (iron).
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See Section 6 of the TDDSee Section 6 of the Technical 

Development Document for Proposed Effluent Limitations 

Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category (TDD) – EPA 821-R-13-002 for more detailed 

information regarding pollutants of concern.

B. Selection of Pollutants for Regulation Under BAT/NSPS

The pollutants of concern identified for each wastestream

represents those pollutants that are present at treatable 

concentrations in a significant percentage of untreated 

wastewater samples from that wastestream. Effluent limits and 

monitoring for all pollutants of concern is not necessary to 

ensure that the pollutants are adequately controlled because 

many of the pollutants originate from similar sources, have 

similar treatabilities, and are removed by similar mechanisms. 

Because of this, it may be sufficient to establish effluent 

limits for one pollutant as a surrogate or indicator pollutant 

that ensures the removal of other pollutants of concern. In 

addition, establishing effluent limits may not be appropriate 

for certain pollutants of concern when the technology used as 

the basis for the effluent limits is not reliably effective at 

removing the pollutant(s). 

From the list of pollutants of concern identified for each 

wastestream, EPA selected a subset of pollutants for 

establishing numeric effluent limitations. EPA considered the 

Formatted: Body Text, Indent: First line: 0.5",

Line spacing: Double
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following factors in selecting regulated pollutants from the 

list of pollutants of concern:

The pollutant was detected in the untreated wastewater at 

treatable levels in a significant number of samples.

The pollutant is not used as a treatment chemical in the 

treatment technology that serves as a basis for the 

proposed regulatory option. EPA eliminated pollutants

associated with treatment system additives because 

regulating these pollutants could interfere with efforts to 

optimize treatment system operation.

The pollutant is effectively treated by the treatment 

technology that serves as the basis for the proposed 

regulatory option. EPA excluded all pollutants for which 

the treatment technology was ineffective (e.g., pollutant 

concentrations remained approximately unchanged or 

increased across the treatment system).

The pollutant is not adequately controlled through the 

regulation of another pollutant.

Because the criteria for identifying regulated pollutants 

from the list of pollutants of concern depends on the treatment 

technology that serves as the basis for a proposed regulatory 

option, EPA may regulate a different subset of pollutants for a 

single wastestream under different regulatory options. 

For the proposed options for this rulemaking (described 

below in Section VIII), EPA identified foursix pollutants for 

potential regulation under BAT/NSPS for FGD wastewater: oil and 

grease, TSS, arsenic, mercury, nitrate/nitrite, and selenium. 

For leachate, EPA is proposing twoidentified four potential

pollutants for regulation under NSPS and under one of the two 

preferred BAT options (Option 4):: oil and grease, TSS, arsenic 

and mercury. 
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EPA identified four pollutants for regulation under the 

proposed BAT/NSPS for gasification wastewater: arsenic, mercury, 

selenium and TDS.For fly ash discharges, bottom ash, and FGMC 

wastewater, under some proposed options, EPA is proposing to 

establish zero discharge limitations, which in effect directly 

control all pollutants of concern, for the following 

wastestreams: BAT for fly ash transport water; NSPS for bottom 

ash transport water and BAT for bottom ash transport water under 

one of the two preferred BAT options (Option 4); and BAT/NSPS 

for FGMC wastewater. For other proposed options that would not 

require zero pollutant discharge, EPA identified two potential 

pollutants for regulation: oil and grease and TSS for 

nonchemical metal cleaning wastes, EPA identified four 

pollutants for potential regulation (TSS, oil and grease, 

copper, and iron). EPA identified four pollutants for regulation 

for gasification wastewater: arsenic, mercury, selenium, and 

TDS.

For nonchemical metal cleaning wastes, EPA identified two 

pollutants for potential regulation under the proposed BAT 

copper and iron), four pollutants for the proposed NSPS (TSS, 

oil and grease, copper, and iron), and one pollutant for the 

proposed PSES and PSNS (copper). 

See Section 6.7 of the TDDSee Section 6.7 of the Technical 

Development Document for Proposed Effluent Limitations 
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Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category (TDD) – EPA 821-R-13-002 for more 

information about the pollutants of concern and EPA’s rationale 

for selecting the pollutants proposed for regulation.

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

Section 307(b) and (c) of the CWA requires EPA to 

promulgate pretreatment standards for pollutants that are not 

susceptible to treatment by POTWs or which would interfere with 

the operation of POTWs. EPA looks at a number of factors in 

selecting the technology basis for pretreatment standards for 

existing and new sources. These factors are generally the same 

as those considered in establishing BAT and NSPS, respectively.

However, unlike direct dischargers whose wastewater will receive 

no further treatment once it leaves the facility, indirect 

dischargers send their wastewater to POTWs for further 

treatment. As such, EPA must also determine that a pollutant is 

not susceptible to treatment at a POTW or would interfere with 

POTW operations. 

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 would pass 

thoughthrough POTWs, EPA generally compares the percentage of a 

pollutant removed by well-operated POTWs performing secondary 
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Page 126 of 517

treatment to the percentage removed by BAT/NSPS treatment 

systems. 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 direct dischargers 

complying with BAT/NSPS effluent limitations and standards.

Pretreatment standards are established for those pollutants 

regulated under BAT/NSPS that pass through POTWs to waters of 

the U.S. or interfere with POTW operations or sludge disposal 

practices. This approach to the definition of pass-through 

satisfies two competing objectives set by Congress: (1) that 

standards for indirect dischargers be equivalent to standards 

for direct dischargers, and (2) that the treatment capability 

and performance of POTWs be recognized and taken into account in 

regulating the discharge of pollutants from indirect 

dischargers.

For today’s proposed rule, EPA conducted a pass through 

analysis for the technology basis for each wastestream for each 

regulatory option presented below in Section VII.C. For those 

wastestreams and regulatory options for which EPA is proposing 

zero discharge of pollutants, EPA set the percentage removed by 

the technology basis at 100 percent. EPA did not conduct its 

traditional pass-through analysis for these wastestreams (e.g., 

fly ash transport water, bottom ash transport water, and flue 

gas mercury control wastewater) because limitations for these 
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wastestreams for direct dischargers would consist of no 

discharge of process wastewater pollutants to waters of the 

U.S., and therefore, all pollutants would “pass through” the 

POTW for these wastestreams. For nonchemical

During the 1976 development of pretreatment standards for 

chemical metal cleaning wastes, EPA selected pollutants for 

regulation based on two criteria:

The pollutant has the potential to harm the POTW 

(e.g., impair the activity of the biological treatment 

system); or

The pollutant has the potential to harm the receiving 

water (i.e., if the pollutant is not removed or is 

removed inadequately by the POTW).

Using these criteria, the Agency determined in previousit was 

appropriate to establish pretreatment standards for the 

discharge of copper in chemical metal cleaning wastes. For 

today’s rulemaking, EPA believes that, as is the case for copper 

present in chemical metal cleaning wastes would not be 

sufficiently removed by the POTW and that pretreatment standards 

(PSES and PSNS) were warranted. Based on this, EPA concluded 

that, the copper present in nonchemical metal cleaning wastes 

would pass through the POTW.

For FGD wastewater, leachate, and gasification wastewater,

EPA determined the percentage removed for the pollutants by the 
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Page 128 of 517

technology basis using the same data sources used to determine 

the long-term averages for each set of limitations (see Section 

13 of the TDD).)

18. As it has done for other rulemakings, EPA 

determined the percentage removed by well-operated POTWs 

performing secondary treatment from one of two data sources:

Fate of Priority Pollutants in Publicly Owned Treatment 

Works, September 1982, EPA 440/1-82/303 (50 POTW Study); 

and

National Risk Management Research Laboratory (NRMRL) 

Treatability Database, Version 5.0, February 2004 (formerly 

called the Risk Reduction Engineering Laboratory (RREL) 

database).

The 50 POTW study presents data on the performance of 50 

POTWs achieving secondary treatment in removing toxic 

pollutants. When data for a pollutant were available from the 50 

POTW Study, EPA used that data. When data for pollutants were 

not available from the 50 POTW Study, EPA used NRMRL data. The 

NRMRL treatability database provides information on removals 

obtained by various treatment technologies for a variety of 

wastewater sources. Therefore, where EPA used data from the 

NRMRL treatability database, it used only data from the 

treatment of domestic and industrial wastewater using 

technologies representative of secondary treatment. For a more 

detailed discussion of how EPA performed its removal analysis, 

see Section 11 of the TDD.

 

18 For FGD wastewater and leachate, this discussion applies to those 

regulatory options that would provide additional control for discharges of 

toxics like arsenic, mercury and selenium.
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With a few exceptions, EPA performs a POTW pass-through 

analysis for pollutants selected for regulation for BAT/NSPS for 

each wastestream of concern and for each regulatory option. The 

exception is for conventional pollutants such as BOD5, TSS, and 

oil and grease. POTWs are designed to treat these conventional 

pollutants; therefore, they are not considered to pass through. 

Section VIII below summarizes the results of the pass

through analysis. All of the pollutants proposed for regulation 

under BAT/NSPS (except for conventional pollutants and iron 

found in nonchemical metal cleaning wastes) were found to pass 

through and, therefore, were selected for regulation under 

PSES/PSNS.

VIII. Proposed Regulation

A. Regulatory Options

1. BPT/BCT

EPA is not proposing to revise the BPT effluent guidelines 

or establish BCT effluent guidelines in today’s notice because 

the same wastestreams would be controlled at the proposed 

BAT/BADCT (NSPS) level of control. EPA is proposing to remove 

FGD wastewater, FGMC wastewater, gasification wastewater, and 

leachate from the definition of low-volume wastes. As a result, 

EPA is making a structural adjustment to the text of the 

regulation at 40 CFR 423 to add paragraphs that list these four 

wastestreams by name, along with their applicable effluent 
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limitations. The reformatted regulatory text for these four 

wastestreams includes BPT effluent limits, which are the same as 

the current BPT effluent limits for low volume wastes.

2. Description of the BAT/NSPS/PSES/PSNS Options

EPA is proposing to revise or establish BAT, BADCT (NSPS), 

PSES, and PSNS that may apply to discharges of seven

wastestreams: FGD wastewater, fly ash transport water, bottom 

ash transport water, combustion residual leachate from landfills 

and surface impoundments containing CCR, nonchemical metal 

cleaning wastes, and wastewater from FGMC systems and 

gasification systems. In sectionSection VI of this preamble and 

in the TDD, EPA describes the treatment technologies and 

operational practices that it reviewed during the development of 

this proposed rule. From these, EPA identified a subset of 

technologies (treatment processes and operational practices) 

that were most promising as candidate BAT/BADCT options. In 

today’s proposal, EPA is presenting fiveeight main regulatory 

options (i.e., Option 1, Option 3a, Option 2, Option 3b, Option 

3, Option 4a, Option 4, and Option 5) that represent different 

levels of expected pollutant removal associated with different 

wastewater streams (i.e., each succeeding option from Option 1 

to Option 5 is based onwould achieve more reduction in 

discharges of pollutants to waters of the performance of more 

advanced treatment technologies and/or specify more wastestreams 
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for revised ELGs).U.S). Table VIII-1 summarizes the fiveeight

main regulatory options, which are described in the paragraphs

below. 

As discussed further below, EPA is also proposing to add 

provisions to the ELGs that would prevent facilities from 

circumventing applicable ELGs. The proposed provisions would 

clarify the acceptable conditions for discharge of reused 

process wastewater and establish effluent monitoring 

requirements. 

EPA is considering establishing BMPs that would apply to 

surface impoundments (i.e., ponds) that receive, store, dispose

of, or are otherwise used to manage coal combustion residuals 

including FGD wastes, fly ash, bottom ash (which includes boiler 

slag), leachate, and other residuals associated with the 

combustion of coal to prevent uncontrolled discharges from these 

impoundments as described below in the Sectionparagraph titled, 

“BMPs for CCR Surface Impoundments.”

As part of its consideration of technological availability 

and economic achievability for all regulatory options, EPA 

considered the magnitude and complexity of process changes and 

new equipment installations that would be required at facilities

to meet the requirements of the rule. As described further 

below, EPA proposes that certain limitations and standards being 

proposed today for existing sources dowould not apply until July 

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1, 2017 (approximately three years from the effective date of 

this rule). 

EPA is also considering establishing, as part of the BAT 

for existing sources, a voluntary incentive program that would 

provide more time for plants to implement the proposed BAT 

requirements if they adopt additional process changes and 

controls that would provide significant environmental 

protections beyond those achieved by the preferred options in 

this proposed rule. As described further below, power plants 

would be granted two additional years (beyond the time described 

above in the preceding paragraph) if they also dewater, close 

and cap all CCR surface impoundments at the facility (except 

combustion residual leachate impoundments), including those 

surface impoundments located on non-adjoining property that 

receive CCRs from the facility. A power plant participating in 

the voluntary incentive program could continue to operate

surface impoundments for which combustion residual leachate was 

the only type of CCR solids or wastewater contained in the 

impoundment... Power plants would be granted five additional 

years (beyond the time described above in the preceding 

paragraph) if they eliminate discharges of all process 

wastewater to surface waters, with the exception of cooling 

water discharges. 
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Table VIII-1. Steam Electric Main Regulatory Options

Wastestreams

Technology Basis for the Main BAT/NSPS/PSES/PSNS

Regulatory Options

1 3a 2 3b 3 34a 4 5

FGD

Wastewater

Chemical 

Precipitation

BPJ 

Determination

Chemical 

Precipitation 

+ Biological 

Treatment

Chemical 

Precipitation + 

Biological 

Treatment for 

units at a 

facility with a 

total wetscrubbed capacity 

of 2,000 MW and 

more; BPJ 

determination for 

<2,000 MW

Chemical 

Precipitation 

+ Biological 

Treatment

Chemical 

Precipitation + 

Biological 

Treatment

Chemical 

Precipitation + 

Biological 

Treatment

Chemical 

Precipitation +

Evaporation

Fly Ash 

Transport Water

Impoundment

(Equal to BPT)

Dry handling Impoundment 

(Equal to BPT)

Dry handling Dry handling Dry handling Dry handling Dry handling

Bottom Ash 

Transport Water

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT)

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

Combustion 

Residual 

Leachate

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT)

Impoundment

(Equal to BPT)

Chemical 

Precipitation

Chemical 

Precipitation

FGMC

Wastewater

Impoundment

(Equal to BPT)

Dry handling

Impoundment 

(Equal to BPT 

Dry handling Dry handling Dry handling Dry handling Dry handling

Gasification

Wastewater

Chemical 

Precipitati

on +

Evaporation

Evaporation Chemical 

Precipitati

on +

Evaporation

Evaporation Evaporation Chemical 

Precipitation +

Evaporation

Chemical 

Precipitation +

Evaporation

Chemical

Precipitatio

n +

Evaporation

Nonchemical 

Metal Cleaning 

Wastes19

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

Chemical 

Precipitation

FGD Wastewater. Addressing the variety of pollutants 

present in FGD wastewater typically requires several stages of 

treatment to remove the suspended solids, particulate and 

dissolved metals, and other pollutants present. Historically, 

power plants have relied on surface impoundments to treat FGD 

wastewater because NPDES permits generally focused on 

controlling suspended solids for this wastestream. Surface 

impoundments are the technology basis for the current BPT 

 

19 As described in Section VIII, EPA is proposing to exempt from new copper 

and iron BAT limitations any existing discharges of nonchemical metal 

cleaning wastes that are currently authorized without iron and copper limits.

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effluent limits (last revised in 1982) for steam electric power 

plants. In recent years, physical/chemical treatment systems and 

other more advanced systems have become more widely used as 

effluent limits for metals and other pollutants have been 

included in permits, in nearly all cases driven by the need to 

utilize such technologies to meet water quality-based effluent 

limits (WQBELs) established to meet applicable water quality 

standards in the receiving waters. At present, a number of steam 

electric plants either use chemical precipitation or chemical 

precipitation and biological treatment to control discharges of 

FGD wastes. However, surface impoundments continue to be the 

predominant technology used to treat FGD wastewater, with 54

percent of plants that discharge FGD wastewater relying on this 

technology alone (i.e., not including the plants that use 

surface impoundments as pretreatment for more advanced 

treatment). In addition, it is common for plants to commingle 

the surface impoundment FGD effluent with wastestreams of 

significantly higher flows (e.g., ash transport water and 

cooling water) because the higher-flow wastestreams dilute the 

FGD wastewater so that the resulting pollutant concentrations in 

the combined wastestream do not exceed the applicable water 

quality-based effluent limitations. 

Surface impoundments use gravity to remove solid particles 

(i.e., suspended solids) from the wastewater. Metals in FGD 
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wastewater are present in both soluble (i.e., dissolved) and 

particulate form. Some metals, such as arsenic, are often 

present mostly in particulate form; these usually can be removed

to a substantial degree by a well-operated settling process that 

has a sufficiently long residence time. However, other 

pollutants, such as selenium, boron, and magnesium, are present 

mostly in soluble form and are not effectively and reliably 

removed by wastewater surface impoundments. For metals present 

in both soluble and particulate forms (such as mercury), surface 

impoundments will not effectively remove the dissolved fraction. 

Furthermore, the conditions present in some surface impoundments 

can create chemical conditions (e.g., low pH) that convert 

particulate forms of metals to soluble forms, which would not be 

removed by the gravity settling process in the surface 

impoundment. Additionally, EPRI (a technical research 

organization funded by the electric power industry) has reported 

that adding FGD wastewater to surface impoundments used to treat 

ash transport water (i.e., ash ponds) may reduce the settling 

efficiency in the impoundments due to gypsum particle 

dissolution, thus increasing the effluent TSS concentrations. 

EPRI has also reported that the 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 resulting in higher 
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Page 136 of 517

concentrations of metals in the discharge from surface 

impoundments.

During the summer, some surface impoundments become 

thermally stratified. When this occurs, the top layer of the 

impoundment is warmer and contains higher levels of dissolved 

oxygen, whereas the bottom layer of the impoundment is colder 

and can have significantly lower levels of oxygen and may 

develop anoxic conditions. Typically, during fall, as the air 

temperature decreases, the upper layer of the impoundment 

becomes cooler and more dense, thereby sinking and causing the 

entire volume of the impoundment to circulate. Solids that have 

collected at the bottom of the impoundment may become 

resuspended due to such mixing, increasing the concentrations of 

pollutants discharged during the turnover period. Seasonal 

turnover effects largely depend upon the size and configuration 

of the surface impoundment. Smaller, and especially shallow, 

surface impoundments likely do not experience turnover because 

they do not have physical characteristics that promote thermal 

stratification. However, some surface impoundments are large 

(e.g., greater than 300 acres) and deep (e.g., greater than 10 

meters deep) and likely experience some degree of turnover.

Technologies more advanced than surface impoundments are 

availableexist and that are more effective at removing both 

soluble (i.e., dissolved) and particulate forms of metals, as 
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well as other pollutants such as nitrogen compounds and TDS. 

Because many of the pollutants of concern for the 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 by the FGD wastestream, EPA’s proposal is based on 

the view that surface impoundments do not represent the best 

available technology economically achievable for controlling

pollutants in FGD wastewater except for certain operations as 

specified below in sections VIII.A.3 and VIII.A.5, given that 

more effective controls of FGD wastewater have been demonstrated 

and are in operation. Nor doEPA explored other technologies that 

would be more effective at removing these pollutants of concern 

and is co-proposing three options that would include such 

technologies. However, for reasons discussed in Section VII.A.3, 

EPA is also co-proposing options under which some or all 

facilities would continue, for the purposes of the ELGs, to be 

subject to the BPT requirements based on surface impoundments 

for treatment of FGD wastewater. Under these options, BAT would 

be left to a site-specific determination. For the reasons 

discussed above and in Section VIII.A.3, EPA also does not 

believe that surface impoundments represent best available 

demonstrated control technology for controlling pollutants in 

FGD wastewater. Therefore, none of the regulatory options for 
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Page 138 of 517

NSPS presented in this proposal, except as specified below in 

sections VIII.A.3 and VIII.A.5, are based on the performance of 

surface impoundments for FGD wastewater.

The technology basis for the effluent limitations and 

standards for FGD wastewater in Option 1 is physical/chemical 

treatment consisting of the following: chemical 

precipitation/coprecipitation (employing the combination of 

hydroxide precipitation, iron coprecipitation, and sulfide 

precipitation). Option 1 also incorporates the use of flow 

minimization for plants with high FGD discharge flow rates 

(i.e., greater than 1,000 gpm) and FGD system metallurgy and 

operating practices that can accommodate an increase in 

chlorides (e.g., scrubber systems constructed of non-metallic 

materials or corrosion-resistant metal alloys, or systems 

operating with absorber chloride concentrations substantially 

below the design chloride limit). The flow minimization at these 

plants would be achieved by either reducing the FGD purge rate 

or recycling a portion of their FGD wastewater.

Physical/chemical treatment (i.e., chemical precipitation) 

is used to remove metals and other pollutants from wastewater. 

Chemicals are added to the wastewater in a series of reaction 

tanks to convert soluble metals to insoluble metal hydroxide or 

metal sulfide compounds, which precipitate from solution and are 

removed along with other suspended solids. An alkali, such as 
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Page 139 of 517

hydrated lime, is typically added to adjust the pH of the 

wastewater to the point where metals precipitate out as metal 

hydroxides (typically referred to as hydroxide precipitation). 

Chemicals such as ferric chloride are often added to the system 

to increase the removal of certain metals through iron 

coprecipitation. The ferric chloride also acts as a coagulant, 

forming a dense floc that enhances settling of the metal 

precipitate in the downstream clarification stage. Coagulants 

and flocculants are often added to facilitate the settling and 

removal of the newly formed solids. Plants trying to increase

removals of mercury and other metals will also include sulfide 

addition (e.g., organosulfide) as part of the process. Adding 

sulfide chemicals in addition to hydroxide precipitation

provides even greater reductions of heavy metals due to the very 

low solubility of metal sulfide compounds, relative to metal 

hydroxides. Sulfide precipitation is widely used in Europe and 

multiple locations in the United States have installed this 

technology. Forty U.S. power plants (34 percent of plants 

discharging FGD wastewater) include physical/chemical treatment 

as part of the FGD wastewater treatment system; more than half 

of these plants (28 percent of plants discharging FGD 

wastewater) use both hydroxide and sulfide precipitation in the 

process. 
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The technology basis for the effluent limitations and 

standards for FGD wastewater in Options 2, 33b (for units 

located at facilities with a total wet-scrubbed capacity of 

2,000 MW or more)20, 3, 4a, and 4 is chemical 

precipitation/coprecipitation (the same technology basis 

forunder Option 1) used in combination with anoxic/anaerobic 

biological treatment designed to optimize removal of selenium. 

As is the case for Option 1, these BAT options also incorporate 

the use of flow minimization for plants with high FGD discharge 

flow rates (i.e., greater than 1,000 gpm) and FGD system 

metallurgy and operating practices that can accommodate an 

increase in chlorides. The flow minimization at these plants 

would be achieved by either reducing the FGD purge rate or 

recycling a portion of their FGD wastewater.

Physical/chemical treatment systems are capable of 

achieving low effluent concentrations of various metals and the 

sulfide addition is particularly important for removing mercury; 

however, this technology is not effective at removing selenium, 

nitrogen compounds, and certain metals that contribute to high 

concentrations of TDS in FGD wastewater (e.g., bromides, boron). 

Six power plants in the U.S. are operating FGD treatment systems 

that include a biological treatment stage designed to 

 

20 This value is calculated by summing the nameplate capacity for all of the 

units that are serviced by wet FGD systems.
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substantially reduce nitrogen compounds and selenium.21 Other 

industries have also used this technology to remove selenium and 

other pollutants. These systems use anoxic/anaerobic bioreactors 

optimized to remove selenium from the wastewater. The bioreactor 

alters the form of selenium, reducing selenate and selenite to 

elemental selenium, which is then captured by the biomass and 

retained in treatment system residuals. The conditions in the 

bioreactor are also conducive to forming metal sulfide complexes 

to facilitate additional removals of mercury, arsenic, and other 

metals. The information in the record for this proposed rule 

demonstrates that the amount of mercury and other pollutants 

removed by the biological treatment stage of the treatment 

system, above and beyond the amount of pollutants removed in the 

chemical precipitation treatment stage preceding the bioreactor, 

can be substantial. In addition, the anoxic conditions in the 

bioreactor remove nitrates by denitrification and, if necessary,

the biological processes can be modified to include a step to 

nitrify and remove ammonia. Four of these six plants precede the 

biological treatment stage with physical/chemical treatment; 

thus, the entire system is designed to remove suspended solids, 

particulate and dissolved metals, soluble and insoluble forms of 

selenium, and nitrate and nitrite forms of nitrogen. The other 

 

21 A seventh plant is scheduled to begin operating a biological treatment 

system for selenium removal next year. Another plant is installing a similar 

treatment system to remove selenium in discharges of combustion residual 

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

Page 142 of 517

two plants operating anoxic/anaerobic bioreactors to remove 

selenium precede the biological treatment stage with surface 

impoundments instead of chemical precipitation. While the 

treatment systems at these two plants would be less effective at 

removing metals (including many dissolved metals) than the 

plants utilizing chemical pretreatment, they nevertheless 

demonstrateshow the availabilityefficacy of biological treatment 

for removing selenium and nitrate/nitrite from FGD wastewater.

Three percent of the plants discharging FGD wastewater use 

chemical precipitation followed by anaerobic biological 

treatment to treat this wastewater, which is the technology 

basis for Options 2, 3b (for units located at facilities with a 

total wet-scrubbed capacity of 2,000 MW or more), 3, 4a, and 4.

The technology basis for the effluent limitations and 

standards for FGD wastewater in Option 5 is chemical 

precipitation/coprecipitation used in combination with vapor 

compression evaporation. Physical/chemical treatment systems can 

achieve low effluent concentrations for a number of pollutants, 

and reduce concentrations even further when combined with 

biological treatment systems, as described above and in the TDD. 

However, these technologies have not been effective at removing 

substantial amounts of boron and pollutants such as sodium and 

bromides that contribute to high concentrations of TDS. Another 

FGD wastewater treatment technology that can address these more 
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Page 143 of 517

recalcitrant pollutants, as well as removing the pollutants 

treated by physical/chemical and biological technologies, is 

vapor-compression evaporation. This technology uses an 

evaporator to produce a concentrated wastewater stream and a 

reusable distillate stream. The concentrated wastewater stream 

is either disposed of or further processed to produce a solid 

by-product and additional distillate. The plant can reuse the

distillate stream as makeup water. ThreeTwo U.S. plants and four

Italian plants are operating this technology to treat FGD 

wastewater from their coal-fired generating units.22

For Option 3a and Option 3b (for units located at 

facilities with a total wet-scrubbed capacity of less than 2,000 

MW), EPA is proposing not to characterize a technology basis for

effluent limitations and standards applicable to discharges of 

pollutants in FGD wastewater at this time. As illustrated above, 

there is a wide range of technologies currently in use for 

reducing pollutant discharges associated with FGD wastewater, 

and research continues in the development of additional 

technologies to treat FGD wastewater (see Section 7.1.7 of the 

TDD for more information on emerging technologies). The more 

advanced technologies (those that reduce the most pollutants) 

reflect recent innovations in the area of treatment of FGD 

 

22 A third U.S. plant is currently installing a vapor-compression evaporation 

system to treat the FGD wastewater.
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wastewater. EPA expects this trend to continue and, therefore, 

under Option 3a and Option 3b (for units located at facilities 

with a total wet-scrubbed capacity of less than 2,000 MW), 

effluent limitations representing BAT for discharges of FGD 

wastewater would be determined on a site-specific BPJ basis. 

Under Options 3a and Option 3b (for units located at facilities 

with a total wet-scrubbed capacity of less than 2,000 MW), 

pretreatment program control authorities would need to develop 

local limits to address the introduction of pollutants in FGD 

wastewater by steam electric plants to the POTWs that cause pass 

through or interference, as specified in 40 C.F.R. 403.5(c)(2).

As described below in this section of the preamble, EPA is 

proposing that certain imitationslimitations and standards being 

proposed today for existing sources would apply to discharges of 

FGD wastewater generated on or after the date established by the 

permitting authority that is as soon as possible within the next 

permit cycle after July 1, 2017. FGD wastewater generated prior 

to that date (i.e., “legacy” wastewater) from existing direct 

dischargers would remain subject to the existing BPT effluent 

limits. For indirect dischargers, EPA is proposing that PSES for 

FGD wastewater would apply to FGD wastewater generated after a 

date determined by the control authority that is as soon as 

possible beginning July 1, 2017. EPA considered subjecting 

legacy FGD wastewater to the proposed BAT and PSES requirements.
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However, as explained above, FGD wastewater and its associated 

pollutants are typically sent to surface impoundments for 

treatment prior to discharge. These surface impoundments often 

contain other plant wastewaters, such as fly ash or bottom ash 

transport water, coal pile runoff, and/or low volume wastes. 

According to data provided by the industry survey, 78 percent of 

surface impoundments that receive FGD wastewater also receive 

fly ash and/or bottom ash transport water. EPA does not have the 

data to demonstrate that the technologies identified above 

represent BAT for legacy FGD wastewater. As such, EPA is not 

proposing BAT requirements associated with discharges of legacy 

FGD wastewater generated prior to the date established by the 

permitting authority (for direct dischargers) or control 

authority (for indirect dischargers). As proposed today, 

discharges of legacy FGD wastewater by existing direct 

dischargers would remain subject to the existing BPT effluent 

limits; however, under some of the proposed options, EPA is also 

considering whether to setsetting the BAT effluent limitations 

for legacy FGD wastewater that has not been mixed with nonlegacy wastes equal to the existing BPT effluent limits. See 

Section XVI for additional information.

Fly Ash Transport Water. Under Options 1 and 2, BAT 

effluent limitations for fly ash transport water would be set 

equal to the current BPT effluent limitations, based on the 

Formatted: Indent: First line: 0"
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technology of gravity settling in surface impoundments to remove 

suspended solids. The current effluent guidelines for existing 

sources include BPT effluent limits for the allowable levels of 

TSS and oil and grease in discharges of fly ash transport water. 

The BPT effluent limits are based on the performance of surface 

impoundments, which when well-designed and well-operated can 

effectively remove suspended solids, including pollutants such 

as particulate forms of certain metals when associated with the 

suspended solids.

ForUnder Options 3a, 3b, 3, 4a, 4, and 5, EPA would 

establish “zero discharge” effluent limitations and standards 

for discharges of pollutants in fly ash transport water, based 

on the use of dry fly ash handling technologies. The dry 

handling technologies for fly ash are described above in 

sectionSection VI of this preamble and in the TDD for the 

proposed rule. Although surface impoundments can be effective at 

removing particulate forms of certain metals and other 

pollutants, they are not designed for, nor are they effective 

at, removing other pollutants of concern such as dissolved 

metals and nutrients. The concentrations of pollutants that 

remain in the ash impoundment effluent following gravity 

settling, in combination with the large volumes of fly ash 

transport water discharged to surface waters (2.4 MGD on average 

per discharging plant), results in a large mass loading of 
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pollutants of concern being discharged from surface 

impoundments. Furthermore, as described in Section VI, surface 

impoundments can be susceptible to seasonal turnover that 

degrades pollutant removal efficacy, and co-managing FGD and ash 

wastes in the same impoundments can lead to increased pollutant 

discharges.

Dry handling technologies are the technology basis for the 

current fly ash NSPS/PSNS requirements, which were promulgated 

in 1982. All generating units built since then have been subject 

to a “zero discharge” standard. Some existing units have also 

converted to dry handling technologies. Due to the NSPS 

discharge standard or economic or operational factors (including 

plant decisions to convert to subbituminous coal, the ash from

which is not amenable to wet handling),, approximately 66

percent of coal- and petroleum coke-fired generating units that 

produce fly ash currently operate dry fly ash transport systems, 

while another 15 percent operate both wet and dry fly ash 

transport systems. The remaining 19 percent operate only wet fly 

ash transport systems. In cases where a unit has both wet and 

dry handling operations, the wet handling system is typically 

used as a backup to the dry system. Effluent limitations and 

standards based on dry ash handling would completely eliminate 

the discharge of pollutants in fly ash transport water. 
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EPA considered basing one or more regulatory options for 

fly ash transport water on chemical precipitation treatment 

technology, with numeric effluent limits for discharges of the 

wastestream to surface waters. EPA has not identified any 

facilities using this treatment technology to treat fly ash 

transport water, although EPA has reviewed two literature 

sources that describe laboratory- or pilot-scale tests using the 

technology. Upon reviewing the discharge flow rates for fly ash 

transport water, however, EPA determined that the capital and 

operating and maintenance (O&M) costs associated with treatment 

using chemical precipitation were comparable tohigher than the 

cost of the dry handling technology upon which Options 3a, 3b, 

3, 4a, 4, and 5 are based, despite being less effective at 

removing pollutants. Since the costs for chemical precipitation 

treatment are comparable tohigher than the cost for converting 

to dry handling technologies, and chemical precipitation removes 

fewer pollutants, EPA did not selectinclude chemical 

precipitation treatment as part of the regulatory options for 

fly ash in this proposed rule. See DCN SE03869.

As described below in this section of the preamble, EPA is 

proposing that the limitations and standards for existing 

sources based on Options 3a, 3b, 3, 4a, 4, or 5 would apply to 

discharges of fly ash transport water generated after the date 

established by the permitting authority orthat is as soon as 
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possible within the next permit cycle after July 1, 2017. For 

indirect dischargers, EPA is proposing that PSES for fly ash 

would apply to the fly ash transport water generated after a 

date determined by the control authority that is as soon as 

possible afterbeginning July 1, 2017. Fly ash transport water 

generated by existing direct dischargers prior to that date 

(i.e., “legacy” wastewater) would remain subject to the existing 

BPT effluent limits. EPA considered subjecting legacy fly ash 

transport water (i.e., the fly ash transport water generated 

prior to the date established by the permitting authority, as 

described above) to the proposed BAT zero discharge requirement.

As explained above, currently fly ash transport wastewater and 

the associated pollutants are sent to surface impoundments for 

treatment prior to discharge. The technology basis identified 

above for the proposed zero discharge requirement eliminates the 

generation of the fly ash wastewater but does not eliminate fly 

ash transport wastewater that has already been transferred to a 

surface impoundment. Furthermore, the technologies identified as 

the basis for fly ash transport water discharge requirements

have not been demonstrated for the legacy fly ash transport 

wastewater that has already been generated. As such, EPA is not 

proposing BAT or PSES requirements for discharges of legacy fly 

ash transport water generated prior to the date established by 

the permitting authority or control authority. As proposed 
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today, discharges of legacy fly ash transport water by existing 

direct dischargers would remain subject to the existing BPT 

effluent limits; however, EPA is also considering whether to set 

the BAT effluent limitations for legacy fly ash transport water 

equal to the existing BPT effluent limits. See Section XVI for 

additional information.

Bottom Ash Transport Water. Under Options 1, 3a, 2, 3b, 3,

and 3,4a (for units less than or equal to 400 MW), effluent 

limitations and standards for bottom ash transport water would 

be set equal to the current BPT effluent limitations, based on 

the technology of gravity settling in surface impoundments to 

remove suspended solids. The 1982 effluent guidelines for 

existing sources include BPT effluent limits for the allowable 

levels of TSS and oil and grease in discharges of bottom ash 

transport water. The BPT effluent limits are based on the 

performance of surface impoundments, which when well-designed 

and well-operated can effectively remove suspended solids, 

including pollutants such as particulate forms of certain metals 

when associated with the suspended solids.

Although surface impoundments can be effective at removing 

particulate forms of metals and other pollutants, they are not 

designed for nor are they effective at removing other pollutants 

of concern such as dissolved metals and nutrients. The 

concentrations of pollutants that remain in the wastestream at 
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the ash impoundment effluent, in combination with the large 

volumes of bottom ash transport water discharged to surface 

waters, results in a large mass loading of pollutants of concern 

being discharged from surface impoundments. Effluent limitations

and standards based on the technologies used as the basis for 

Options 44a (for units more than 400 MW), 4, and 5 would 

completely eliminate the discharge of pollutants in bottom ash 

transport water. 

ForUnder Options 4a (for units more than 400 MW), 4, and 5, 

EPA would establish “zero discharge” effluent limitations and 

standards for discharges of pollutants in bottom ash transport 

water, based on either using bottom ash handling technologies 

that do not require transport water or managing a wet-sluicing 

bottom ash handling system so that it does not discharge bottom 

ash transport water or pollutants associated with the bottom ash 

transport water. These technologies for handling bottom ash are 

described above in section VI of this preamble and in the TDD 

for the proposed rule. About 80 percent of coal- and petroleum 

coke-fired units generating bottom ash operate wet bottom ash 

transport systems, while approximately 20 percent operate 

systems that eliminate the use of transport water. Most, but not 

all, of the wet bottom ash transport systems discharge to 

surface waters. In cases where a plant has both wet and dry 

handling operations, the wet handling system is typically used 
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as a backup to the dry system. In the case of bottom ash 

handling systems, the term “dry” is typically used to refer to a 

process that does not use water as the transport medium to 

sluice the bottom ash to a CCR impoundment. In some cases, a 

“dry” bottom ash system may be entirely dry and avoid all use of 

water. Many dry bottom ash systems, however, include a water 

bath at the bottom of a boiler in which the bottom ash is 

dropped and cooled, and then the bottom ash is mechanically 

dragged out of the boiler along a conveyor belt and deposited in 

a pile adjacent to the building housing the boiler. The bottom 

ash conveyed out of the water bath will be damp because the ash 

particles retain some moisture from the water bath and small 

volumes of water will typically drain from the standing bottom 

ash pile. The water draining from the pile is usually collected 

in a sump and either returned to the water bath below the boiler 

or managed as low volume waste. Such mechanical drag systems are 

includedconsidered as one available technology basis for that 

may be used to achieve proposed limitations and standards under

Options 4a (for units >400 MW), 4, and 5. Other technologies 

serving as the basis for limitations and standards proposed 

under Options 4a (for units >400 MW), 4, and 5 are completely 

dry bottom ash systems, remote mechanical drag systems, and 

impoundment-based systems that are managed to eliminate the 
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discharge of all bottom ash transport water and the associated 

pollutants. 

In developing the technologies that serve as the basis for 

the regulatory options with respect to bottom ash transport 

water, EPA considered basing one or more options on chemical 

precipitation treatment technology, with numeric effluent 

limitations or standards for discharges of the wastestream to 

surface waters. Upon reviewing the discharge flow rates for 

bottom ash transport water, however, EPA determined that the 

capital and O&M costs associated with treatment were comparable 

to the cost of the technologies upon which Options 4a (for units 

more than 400 MW), 4, and 5 are based, despite being less 

effective at removing pollutants. Since the costs for chemical 

precipitation treatment were found to be comparable tohigher 

than the cost for converting to dry handling or closed loop 

technologies, and the treatment technology removes fewer 

pollutants, EPA did not selectinclude chemical precipitation 

treatment as part of the regulatory options for bottom ash in 

this proposed rule. See DCN SE03869.

As described below in this section of the preamble, EPA is 

proposing that certain BAT limitations and standards for 

existing sources developed under Options 4a (for units more than 

400 MW), 4, or 5 would apply to discharges of bottom ash 

transport water generated after the date established by the 
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permitting authority or control authority that is as soon as 

possible after July 1, 2017.within the next permit cycle after 

July 1, 2017. For indirect dischargers, EPA is proposing that 

PSES for bottom ash transport water would apply to bottom ash 

transport water generated after a date determined by the control 

authority that is as soon as possible beginning July 1, 2017.

Bottom ash transport water generated by existing direct 

dischargers prior to that date (i.e., “legacy” wastewater) would 

remain subject to the existing BPT effluent limits. EPA 

considered subjecting legacy bottom ash transport water (i.e., 

the bottom ash transport water generated prior to the date 

established by the permitting authority or control authority, as 

described above), to the BAT and PSES zero discharge requirement 

considered under Options 4a (for units more than 400 MW), 4, and 

5. As explained above, currently, bottom ash transport 

wastewater and the associated pollutants are sent to surface 

impoundments for treatment prior to discharge. The technology 

bases identified above for Options 4a (for units more than 400 

MW), 4, and 5 eliminateseliminate the generation of the bottom 

ash wastewater but doesdo not eliminate bottom ash transport 

wastewater that has already been transferred to a surface 

impoundment. The technologies identified as the basis for bottom 

ash transport water discharge requirements under Options 44a 

(for units more than 400 MW), 4, and 5 have not been 
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demonstrated for the legacy bottom ash transport wastewater that 

has already been generated and do not represent BAT/PSES with 

respect to legacy bottom ash wastewater. As such, under Options 

44a (for units more than 400 MW), 4, and 5 EPA would not 

establish BAT or PSES requirements for discharges of legacy 

bottom ash transport water generated prior to the date 

established by the permitting authority. As proposed today, 

discharges of legacy bottom ash transport water by existing 

direct dischargers would remain subject to the existing BPT 

effluent limits; however, EPA is also considering whether to set 

the BAT effluent limitations for legacy bottom ash transport 

water equal to the existing BPT effluent limits. See Section XVI

for additional information.

Leachate from Surface Impoundments and Landfills Containing 

Combustion Residuals.Residual Leachate. Under Options 1, 3a, 2

and, 3b, 3, and 4a, effluent limitations and standards for 

leachate from surface impoundments and landfills containing 

combustion residuals would be set equal to the current BPT 

effluent limitations, based on the technology of gravity 

settling in surface impoundments to remove suspended solids. 

Leachate is currently included under the definition of low 

volume wastes, which are regulated by effluent limits for TSS 

and oil and grease based on surface impoundments designed to 

remove suspended solids. EPA is proposing that under Options 1, 
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3a, 2, 3b, 3, and 34a, the rule would remove leachate from the 

definition of low volume wastes at 40 CFR 423.11(b) and would 

set BAT effluent limits for leachate equal to BPT limits for TSS 

and oil and grease (i.e., the current effluent limits for low 

volume wastes). 

The technology basis for effluent limitations and standards 

for leachate under Options 4 and 5 is chemical 

precipitation/coprecipitation. This is the same technology that 

is the basis for BAT Option 1 for FGD wastewater. Properly 

designed and operated surface impoundments can effectively

remove suspended solids, including pollutants such as 

particulate forms of certain metals when associated with the 

suspended solids. However, since surface impoundments are not 

designed for, nor are they effective at, removing other 

pollutants of concern such as dissolved metals, EPA used 

chemical precipitation/coprecipitation as the technology basis 

for Options 4 and 5. Physical/chemical treatment systems are 

capable of achieving low effluent concentrations of various 

metals and are effective at removing many of the pollutants of 

concern present in leachate discharges to surface waters. The 

pollutants of concern in leachate are the same pollutants that 

are present in, and in many cases are also pollutants of concern 

for, FGD wastewater, fly ash transport wastewater, bottom ash 

transport water, and other combustion residuals. This is to be 
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expected since the leachate itself comes from landfills and 

surface impoundments containing the combustion residuals and 

those wastes are the source for the pollutants entrained in the 

leachate. Given the similarities present among the different 

types of wastewaters associated with combustion residuals, 

combustion residual leachate will be similarly amenable to 

chemical precipitation treatment. The treatability of pollutants 

such as arsenic and mercury using chemical precipitation 

technology is also demonstrated by technical information 

compiled for ELGs promulgated for other industry sectors. See, 

e.g., the TDDs supporting the ELGELGs for the Landfills point 

source categoryPoint Source Category (EPA-821-R-99-019) and the 

ELGELGs for the Metal Products and Machinery point source 

categoryPoint Source Category (EPA-821-B-03-001). However, as is 

the case when treating FGD wastewater, this technology is not 

effective at removing selenium, boron and certain other 

parameters that contribute to total dissolved solids (e.g., 

magnesium, sodium).

EPA also considered developing a regulatory option that, 

for leachate, would be based on the technology of chemical 

precipitation/coprecipitation used in conjunction with 

anoxic/anaerobic biological treatment. This is the same 

technology used as the basis for effluent limitations and 

standards for FGD wastewater under Options 2, 33b (for units at 
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facilities with a total wet-scrubbed capacity of 2,000 MW or 

more), 3, 4a, and 4. EPA has reviewed this technology as a 

potential basis for effluent limitations and standards for 

leachate and the TDD presents information about the compliance 

costs and pollutant removals associated with this technology.

The microorganisms used in the bioreactors for the biological 

treatment technology for FGD wastewater are resilient and have 

shown that they operate effectively under varying conditions 

that occur in FGD system and the FGD wastewater treatment 

system. However, leachate flows can be more variable than FGD 

wastewater and, more importantly, may be too intermittent to 

facilitate reliable and consistent biological treatment. Such 

variations are easily accommodated in a chemical precipitation 

treatment system, but may be difficult to manage in a biological 

treatment system reliant on healthy and sustainable populations 

of microorganisms. EPA solicits comment on whether the BAT 

effluent limits for leachate should be based on the combination 

of chemical and biological treatment.

If EPA is proposing that anydid finalize BAT effluent 

limits developed under Options 4 or 5 would (although it is not 

proposing such limits as a preferred option today), EPA’s intent 

is that these limits would apply to discharges of leachate 

generated after the date established by the permitting authority 

orthat is as soon as possible within the next permit cycle after 
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July 1, 2017. For indirect dischargers, PSES for leachate would 

apply to leachate generated after a date determined by the

control authority that is as soon as possible afterbeginning

July 1, 2017. Leachate generated by existing direct dischargers 

prior to that date (i.e., “legacy” leachate wastewater) would 

remain subject to the existing BPT effluent limits. EPA 

considered subjecting legacy leachate wastewater to the proposed 

BAT and PSES limitations and standards. However, although some

plants use relatively small surface impoundments to treat 

leachate and these impoundments would contain relatively small 

volumes of legacy leachate wastewater, other plants send 

leachate to relatively large surface impoundments that also 

contain other plant wastewaters, such as fly ash or bottom ash 

transport water, cooling water, and/or other low volume wastes. 

EPA does not have the data to demonstrate that the technologies 

identified above represent BAT for legacy combustion residual 

leachate. As such, EPA iswould not proposingexpect to finalize

BAT requirements associated with discharges of legacy combustion 

residual leachate (i.e., the leachate generated prior to the 

date established by the permitting authority or control 

authority). As proposed today, discharges of legacy combustion 

residual leachate by existing direct dischargers would remain 

subject to the existing BPT effluent limits; however, EPA is 

also considering whether to set the BAT effluent limitations for 
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legacy combustion residual leachate that has not been mixed with 

non-legacy wastes equal to the existing BPT effluent limits. See 

Section XVI for additional information.

FGMC Wastewater. ForUnder Options 1 and 2, effluent 

limitations and standards for FGMC wastewater would be set equal 

to the current BPT effluent limitations, based on the technology 

of gravity settling in surface impoundments to remove suspended 

solids. Like leachate, FGMC wastewater is currently included 

under the definition of low volume wastes, with effluent limits 

for TSS and oil and grease based on surface impoundments 

designed to remove suspended solids. EPA is proposing that under

Options 1 and 2,all options, FGMC wastewater would be removed 

from the definition of low volume wastes at 40 CFR 423.11(b)). 

Under Options 1 and 2, BAT effluent limits for FGMC wastewater

would be set equal to BPT limits for TSS and oil and grease 

(i.e., the current effluent limits for low volume wastes).

As discussed above in sectionSection VI of this preamble, 

some plants inject dry sorbents (e.g., activated carbon) into 

the flue gas stream to reduce mercury emissions from the flue 

gas. Mercury adsorbs to the sorbent particles, and these 

mercury-enriched sorbents are then removed from the flue gas 

using a fabric filter or ESP. The sorbent can be injected 

upstream of the primary particulate collector, in which case the 

mercury-enriched sorbent is collected with the majority of the 
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fly ash. Alternatively, the sorbent can be injected downstream

of the primary particulate collector and collected with a much 

smaller amount of fly ash (i.e., the fly ash that passed through 

the primary collector) in a smaller, dedicated secondary 

particulate collector such as a fabric filter. In either case, 

the plant collects the mercury-enriched sorbents along with fly 

ash. Because of this, the BAT technology basis for FGMC 

wastewater in this proposal is identical to the BAT technology 

basis for fly ash. 

ForUnder Options 3a, 3b, 3, 4a, 4, and 5, EPA would 

establish “zero discharge” effluent limitations and standards

for discharges of pollutants in FGMC wastewater based on using

dry handling technologies to store and dispose of fly ash 

without utilizing transport water. The dry handling technologies 

that would be used for FGMC wastes are identical to the dry fly 

ash handling technologies described above in section VI of this 

preamble and in the TDD for the proposed rule. Although surface 

impoundments can effectively remove particulate forms of metals 

and other pollutants, they are not designed for nor are they 

effective at removing other pollutants of concern such as 

dissolved metals and nutrients. Effluent limits based on dry 

handling would completely eliminate the discharge of pollutants 

in FGMC wastewater. 
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EPA is also aware of some plants that add oxidizers to the 

coal prior to burning the coal in the boiler. This chemical 

addition oxidizes the mercury present in the flue gas, which 

allows the plant to remove mercury more readily from the flue 

gas in the wet FGD system. EPA did not evaluate separate 

treatment technologies for the use of oxidizers to control flue 

gas mercury emissions because using oxidizers does not generate 

a separate FGMC wastewater.

To the extent that a power plant generates FGMC wastewater 

before any BAT or PSES zero discharge limitation or standard 

were to apply, the proposed BAT and PSES limitations and 

standards under Options 3a, 3b, 3, 4a, 4, and 5 would apply to 

discharges of FGMC wastewater generated after the date 

established by the permitting authority orthat is as soon as 

possible within the next permit cycle after July 1, 2017. For 

indirect dischargers, EPA is proposing that PSES for FGMC 

wastewater would apply to FGMC wastewater generated after a date 

determined by the control authority that is as soon as possible 

afterbeginning July 1, 2017. As proposed today, legacy FGMC 

wastewater generated existing direct dischargers prior to that 

date would remain subject to the existing BPT effluent limits; 

however, EPA is also considering whether to set the BAT effluent 

limitations for legacy FGMC wastewater equal to the existing BPT 

effluent limits. EPA considered subjecting legacy FGMC 
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wastewater to the proposed BAT/PSES zero discharge requirements.

As explained above, although most FGMC wastes are managed using 

dry handling systems, EPA has identified six plants that manage 

their FGMC waste with systems that use water to transport the 

waste to surface impoundments. The technology basis identified 

above for the proposed zero discharge requirement eliminates the 

generation of the FGMC wastewater by implementing certain 

process changes that do not use water to transport the FGMC 

waste; however, it does not eliminate the already-generated FGMC 

wastewater that has already been transferred to and stored in a 

surface impoundment. The technologies that underlie regulatory 

Options 3a, 3b, 3, 4a, 4, and 5 do not represent BAT or PSES for 

the control of pollutants from legacy FGMC wastewater and would 

not allow FGMC wastewater that has already been generated to 

comply with a zero discharge requirement. As such, EPA is not 

proposing BAT or PSES requirements associated with discharges of 

legacy FGMC wastewater generated prior to the date established 

by the permitting authority. or control authority. However, EPA 

is considering whether to set the BAT effluent limitations for 

legacy FGMC wastewater equal to the existing BPT effluent 

limits. See Section XVI for additional information.

Gasification Wastewater. The technology basis for the 

effluent limitations for all eight regulatory options (Options 1 

though 5) for gasification wastewater is vapor-compression 
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evaporation. Two operating IGCC plants in the U.S. currently use 

this technology, and a third IGCC plant that is 

expectedscheduled to begin commercial operation soon will also 

use it to treat gasification wastewater. Like leachate and FGMC 

wastewater, gasification wastewater is currently included under 

the definition of low volume wastes, with effluent limits for 

TSS and oil and grease based on surface impoundments designed to 

remove suspended solids. EPA considered using surface 

impoundments as the technology basis for one or more of the 

regulatory options for gasification wastewater. However, surface 

impoundments are not effective at removing the pollutants of 

concern present in gasification wastewater. In addition, one of 

the currently operating IGCC plants formerly used a surface 

impoundment to treat its gasification wastewater and the 

impoundment effluent repeatedly exceeded NPDES permit limits 

established to protect water quality. Because of the 

demonstrated inability of surface impoundments to remove the 

pollutants of concern and the current industry practice of 

operating vapor-compression evaporation to treat the 

gasification wastewater at all U.S. IGCC plants, EPA determined 

that surface impoundments do not represent BAT level of control.

In addition to the vapor-compression evaporation technology 

that is the basis for all BAT and BADCT/NSPS options for 

gasification wastewater, EPA considered also including cyanide 
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treatment as part of the technology basis for one or more 

options. EPA notes that the Edwardsport IGCC plant that is 

scheduled to soon begin commercial operation includes cyanide 

destruction as one step in the treatment process for 

gasification wastewater. However, EPA currently does not have 

sufficient gasification wastewater data with which to calculate 

effluent limits based on the performance of cyanide treatment as 

part of a BAT/BADCT (NSPS) regulatory option. A possible 

approach to resolve this would be to transfer effluent limits 

for cyanide from an ELG for another industry sector. 

Alternatively, EPA may obtain effluent data from the 

gasification wastewater treatment system for the Edwardsport 

IGCC unit once it begins commercial operation and use these data 

to calculate effluent limitations for cyanide. EPA solicits data 

on the concentrations of cyanide present in gasification 

wastewater and solicits comment on whether EPA should establish 

BAT or BADCT (NSPS) control on the discharge of cyanide.

Nonchemical Metal Cleaning Wastes. The technology basis for 

the effluent limitations for all eight regulatory options

(Options 1 though 5) for nonchemical metal cleaning wastes is 

chemical precipitation. Separation processes in the 

physical/chemical treatment, along with chemical addition when 

needed to facilitate coagulation and settling of suspended 

solids, would effectively remove TSS and oil and grease to 
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effluent concentrations below the limitations included in the 

proposed rule. In addition, treatment chemicals added to adjust 

pH to precipitate dissolved metals or to facilitate 

flocculation/coagulation are effective at removing copper and 

iron to effluent concentrations below the proposed limitations, 

in addition to reducing the concentrations of other pollutants 

present in nonchemical metal cleaning wastes.

The current ELG relies on three key terms specific to metal 

cleaning waste: “metal cleaning waste,” “chemical metal cleaning 

waste,” and “nonchemical metal cleaning waste.” The regulation 

includes a definition of the broadest term, “metal cleaning 

waste,” as “any wastewater resulting from cleaning [with or 

without chemical cleaning compounds] any metal process 

equipment, including, but not limited to, boiler tube cleaning, 

boiler fireside cleaning, and air preheater cleaning.” 40 CFR 

423.11(d). Thus, this definition includes any wastewater 

generated from either the chemical or nonchemical cleaning of 

metal process equipment. In addition, the regulation also 

defines “chemical metal cleaning waste” as “any wastewater 

resulting from cleaning of any metal process equipment with 

chemical compounds, including, but not limited to, boiler tube 

cleaning.” See 40 CFR 423.11(c). The regulation also includes, 

but does not expressly define the term “nonchemical metal 

cleaning waste” when it states that it has “reserved” the 
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development of BAT ELGs for such wastes. See 40 CFR 423.13(f). 

Although the regulation provides no definition of “nonchemical 

metal cleaning waste,” it is clear from the definitions of metal 

cleaning waste and chemical metal cleaning waste that 

nonchemical metal cleaning waste is any wastewater resulting 

from the cleaning of metal process equipment without chemical 

cleaning compounds. 

The current ELGs include BPT effluent limits for the 

allowable levels of TSS, oil and grease, copper and iron in 

discharges of metal cleaning waste, which includes both chemical 

and nonchemical metal cleaning wastes. Although theAlthough the 

current BPT effluent limits apply to nonchemical metal cleaning 

wastes, EPA has found that some discharges of nonchemical metal 

cleaning waste are authorized pursuant to permits incorporating 

limitations based on BPT requirements for low volume wastes and, 

therefore, do not have iron and copper limits. The information 

EPA has collected to date indicates many facilities are not 

discharging nonchemical metal cleaning wastewater or have copper 

and iron limits (see Section VIII.A.3 and Section 7.7 of the TDD 

for more information). 

The current ELGs do not include BAT/NSPS requirements for 

the broadly defined category of metal cleaning wastes; however,

they do include BAT/NSPS for chemical metal cleaning waste. EPA 

has not promulgated BAT/NSPS for nonchemical metal cleaning 
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waste. Similarly, although the current ELGs do not include 

PSES/PSNS for metal cleaning waste, they do include PSES/PSNS 

for chemical metal cleaning waste. EPA has not promulgated 

PSES/PSNS for nonchemical metal cleaning waste. An overview of 

the existing ELGs for metal cleaning waste, including chemical 

and nonchemical metal cleaning waste, is provided below in Table 

VIII-2. 

Table VIII-2. Parameters Limited by Existing ELGs for Metal 

Cleaning Waste

As described above, EPA found that some discharges of 

nonchemical metal cleaning waste are authorized pursuant to 

permits incorporating limitations based on BPT requirements for 

low volume wastes and, therefore, do not have iron and copper 

limits. Because the potential costs for dischargers to comply 

with iron and copper limits is not known, EPA is proposing to 

provide an exemption from new copper and iron limitations or 

standards for existing discharges of nonchemical metal cleaning 

wastes from generating units that are currently authorized 

Wastestream BPT BAT NSPS PSES PSNS

Chemical 

Metal 

Cleaning 

Waste TSS

Oil & Grease

Copper 

Iron 

Copper 

Iron 

TSS 

Oil & Grease

Copper 

Iron 

Copper Copper

Nonchemical 

Metal 

Cleaning 

Waste

Reserved Reserved Reserved Reserved

Formatted Table

Formatted: Font: 10 pt
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without iron and copper limits. For these discharges, BAT 

limitations for nonchemical metal cleaning waste would be set 

equal to BPT limitations for low volume waste, and the 

regulations would not specify PSES. EPA solicits comment on the 

specific generating units that should be included in the 

exemption. See Section VIII.A.3 for additional details regarding 

the information that EPA is requesting as part of the comment 

solicitation. 

EPA is also considering setting BAT for nonchemical metal 

cleaning waste equal to the metal cleaning waste BPT for all 

nonchemical metal cleaning wastes (i.e., no exemption for 

discharges of nonchemical metal cleaning wastes currently 

authorized without iron and copper limits) and, for PSES, to 

establish copper standards for all discharges of nonchemical 

cleaning wastes. As part of this approach, EPA is evaluating 

whether some plants would incur costs to comply with the current 

BPT standards. Therefore, as described later in this preamble, 

EPA is also soliciting comments associated with each generating 

unit with discharges of nonchemical metal cleaning wastes that 

are not currently subject to the BPT copper and iron limits, in 

order to understand the nonchemical metal cleaning wastes that 

are generated, the characteristics of the wastewater, what 

actions would be needed to comply with the proposed copper and 

iron limits, and estimated costs associated with those actions. 
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See Section VIII.A.3 for details regarding the information that 

EPA is requesting as part of the comment solicitation.

Anti-Circumvention Provisions. EPA is also proposing to add 

provisions to the regulations that would prevent facilities from 

circumventing the effluent limitations guidelines and standards. 

The proposed provisions would do three things, as described 

below. 

First, the anti-circumvention provision would require that 

compliance with the new effluent limits applicable to a 

particular wastestream (e.g., FGD, gasification wastewater, 

leachate) be demonstrated prior to use of the wastewater in 

another plant process that results in surface water discharge or 

mixing the treated wastestream with other wastestreams. Under 40 

CFR 122.45(h), in situations where an NPDES permit effluent 

limitations or standards imposed at the point of discharge are 

impractical or infeasible, effluent limitations or standards may 

be imposed on internal wastestreams before mixing with other 

wastestreams or cooling water streams. Limitations on internal 

wastestreams may be necessary, such as in situations where the 

wastes at the point of discharge are so diluted as to make 

monitoring impracticable, or the interferences among pollutants 

would make detection or analysis impracticable. Many power 

plants combine FGD wastewater and other power plant wastewaters 

with ash transport water and/or cooling water prior to 
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discharge, which can dilute the wastewaters by several orders of 

magnitude prior to the final outfall. In addition, surface 

impoundments typically contain a variety of wastes (e.g., ash 

transport water, coal pile runoff, landfill/impoundment

leachate) that when mixed with the FGD wastewater or 

gasification wastewater may make the analysis to measure 

compliance with technology-based effluent limits impracticable. 

Because of the high degree of dilution and the number of 

wastestream sources containing similar pollutants, effluent 

limits and monitoring requirements for certain internal 

wastestreams (e.g., FGD wastewater, combustion residual 

leachate, gasification wastewater) are necessary to ensure 

appropriate control of the pollutants present in the wastewater.

EPA requests comment on the extent to which this provision may 

discourage water re-use. EPA requests comment on the extent, if 

any, to which this provision may discourage water re-use.

Second, the anti-circumvention provision would establish 

requirements intended to prevent steam electric power plants 

from circumventing the effluent limits and standards by moving 

effluent produced by a process operation for which there is a 

zero discharge effluent limit/standard to another process 

operation for discharge under less stringent requirements than 

intended by the steam electric ELGs. For example, Options 3 and 

4several options (including Option 3a) considered in this 

Formatted: Font color: Auto
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rulemaking would establish a zero discharge requirement for 

pollutants in fly ash transport water and FGMC wastewater. If 

this option were selected for the final rule, the anticircumvention provisions would allow power plants to 

recycle/reuse these wastestreams in ash transport processes or 

other plant processes, but only to the extent that the plants do 

not discharge any pollutants associated with flue gas mercury 

controls or transporting fly ash (or, under Option 4, 

transporting bottom ash). EPA does not believe it is possible to 

completely remove all pollutants present in these wastestreams 

via treatment or reuse; therefore, the. The presence of a zero 

discharge wastestream in a process that ultimately discharges to 

surface water (e.g., use of fly ash transport water as FGD 

absorber make-up water in a scrubber that discharges FGD 

wastewater) would not be in compliance with the effluent limit.

EPA requests comment on the extent to which this provision may 

discourage water re-use.

Last, the anti-circumvention provisions would expressly 

require permittees to use analytical EPA-approved methods that 

are sufficiently sensitive to provide reliable quantified 

results at levels necessary to demonstrate compliance with the 

effluent limits proposed by this rulemaking. when such methods 

are available. EPA’s detailed study and the field sampling for 

this rulemaking demonstrate that the use of sufficiently 
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sensitive analytical methods is critically important to 

detecting, identifying, and measuring the concentrations of 

pollutants present in power plant wastewaters. Where EPA has 

approved more than one analytical method for a pollutant, the 

Agency expects that permittees would select methods that are 

able to quantify the presence of pollutants in a given discharge 

at concentrations that are low enough to determine compliance 

with effluent limits., when such methods are available.

Facilities should not use a less sensitive or less appropriate 

method, thus masking the presence of a pollutant in the 

discharge, when an EPA-approved method is available that can 

quantify the pollutant concentration at the lower levels needed 

for demonstrating compliance. For purposes of the proposed anticircumvention provision, a method is “sufficiently sensitive” 

when the sample-specific quantitation level23 for the wastewater 

being analyzed is at or below the level of the effluent 

limitation. Allowing plants to use insufficiently sensitive 

analytical methods for compliance monitoring purposes when EPAapproved sufficiently sensitive methods are available could 

result in an undetected exceedance of the effluent limits.

BMPs for CCR Surface Impoundments. EPA is considering 

establishing BMPs for plant operators to conduct periodic 

 

23 For the purposes of this rulemaking, EPA is considering the following terms 

related to analytical method sensitivity to be synonymous: “quantitation 

limit,” “reporting limit,” “level of quantitation,” and “minimum level.”
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inspections of active and inactive surface impoundments and to 

take corrective actions where warranted. This requirement would 

apply to direct dischargers. For new sources, EPA would be 

relying on CWA section 306, which authorizes the promulgation of 

standards of performance for new sources. For existing sources, 

EPA would be relying on CWA section 304(e), which authorizes 

BMPs supplemental to ELGs for toxic or hazardous pollutants to 

control plant site runoff, spillage or leaks, sludge or waste 

disposal, and drainage from raw material storage which the 

Administrator determines are associated with or ancillary to the 

industrial process and may contribute significant amounts of 

pollutants to the nation’s waters. And CWA section 402(a) (2) 

authorizes the imposition of conditions, which would include 

BMPs and monitoring requirements, necessary to ensure compliance 

with all other applicable requirements. EPA’s regulation at 40 

CFR 122.44(k) implementimplements these authorities. 

Specifically, 40 CFR 122.44(k) allow for NPDES permits to 

require the use of BMPs to control and abate the discharge of 

toxic pollutants. Existing regulations at 40 CFR 122.41(e) 

further require that NPDES permittees properly operate and 

maintain all facilities and systems of treatment and control 

used to achieve compliance with their permits. Today’s action 

provides notification that EPA is considering establishing BMP 

requirements to address impoundment construction, operation, and 
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maintenance in the final ELG rule using CWA authority. Using CWA 

authority, EPA could establish the BMPs as part of the ELGs (BAT

and NSPS) codified at 40 CFR part 423, and thus these BMPs would

be implemented through NPDES permits. Structural integrity 

requirements that seek to reduce the potential for catastrophic 

releases from surface impoundments could, alternatively, be 

established using RCRA authority. The BMPs under consideration 

in this rulemaking are similar to the structural integrity 

inspection and corrective active requirements proposed in the 

CCR rulemaking, but do not include closure requirements that 

were proposed as part of the CCR rulemaking.

The Agency believes that the BMP requirements being 

considered by the Agency in this rulemaking and in the CCR 

rulemaking are critical to ensure that the owners and operators 

of surface impoundments become aware of any problems that may 

arise with the structural stability of the surface impoundment 

before they occur and, thus, prevent catastrophic releases, such 

as those that occurred at Martins Creek, Pennsylvania and TVA’s 

Kingston, Tennessee facility. 

The BMPs being considered by EPA in this rulemaking would 

require, first, that inspections be conducted every seven days 

by a person qualified to recognize specific signs of structural 

instability and other hazardous conditions by visual observation 

and, if applicable, to monitor instrumentation such as 
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piezometers. If a potentially hazardous condition develops, the 

owner or operator shall immediately take action to eliminate the 

potentially hazardous condition; notify the Regional 

Administrator or the authorized State Director; and notify and 

prepare to evacuate, if necessary, all personnel from the 

property that may be affected by the potentially hazardous 

condition(s). Additionally, the owner or operator must notify 

state and local emergency response personnel if conditions 

warrant so that people living in the area down gradient from the 

surface impoundment can evacuate. Reports of inspections are to 

be maintained in the facility operating record.

Second, to address the integrity of surface impoundments, 

EPA would establish BMPs for CCR surface impoundments similar to 

those promulgated for coal slurry impoundments regulated by the 

Mine Safety and Health Administration (MSHA) at 30 CFR 77.216.

Although the MSHA regulations are applicable to coal slurry 

impoundments at coal mines and not to the impoundments 

containing CCR at power plants, there are sufficient 

similarities between coal slurry and CCR impoundments for the 

MSHA regulations to be used as a model for the BMP requirements 

being considered for the ELG rule. Facilities using CCR 

impoundments would need to (1) submit to EPA or the authorized 

state plans for the design, construction, and maintenance of 

existing impoundments, (2) submit to EPA or the authorized state 
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plans for closure, (3) conduct periodic inspections by trained 

personnel who are knowledgeable in impoundment design and 

safety, and (4) provide an annual certification by an 

independent registered professional engineer that all 

construction, operation, and maintenance of impoundments is in 

accordance with the approved plan. When problematic stability 

and safety issues are identified, owners and operators would be 

required to address these issues in a timely manner.

In developing these possible structural integrity BMP 

requirements, EPA sought advice from the federal agencies 

charged with managing the safety of dams in the United States. 

Many agencies in the federal government are charged with dam 

safety, including the U.S. Department of Agriculture (USDA), the 

Department of Defense (DOD), the Department of Energy (DOE), the 

Nuclear Regulatory Commission (NRC), the Department of Interior 

(DOI), and the Department of Labor (DOL), MSHA. EPA looked 

particularly to MSHA, whose charge and jurisdiction appeared to 

EPA to be the most similar to the Agency’s in this context.

MSHA’s jurisdiction extends to all dams used as part of an 

active mining operation and their regulations cover “water, 

sediment or slurry impoundments” so they include dams for waste 

disposal, freshwater supply, water treatment, and sediment 

control. In fact, MSHA’s current impoundment regulations were 

created as a result of the dam failure at Buffalo Creek, West 
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Virginia on February 26, 1972. (This failure released 138 

million gallons of stormwater run-off and fine coal refuse, and 

resulted in 125 persons killed, another 1,000 injured, over 500 

homes completely destroyed, and nearly 1,000 others damaged.)

MSHA has nearly 40 years of experience writing regulations 

and inspecting dams associated with coal mining. MSHA’s

regulations are comprehensive and directly applicable to the 

dams used in surface impoundments at coal-fired utilities to 

manage CCRs. EPA believes that, based on the record compiled by 

MSHA for its rulemaking, and on MSHA’s 40 years of experience 

implementing these regulations, the requirements being 

considered in this rulemaking would substantially reduce the 

potential for catastrophic release of CCRs from surface 

impoundments, as occurred at TVA’s facility in Kingston, 

Tennessee, and would generally meet RCRA’s objective to ensure 

the protection of humans and the environment.24 Thus, EPA is 

considering establishing BMPs that would be modeled on MSHA 

regulations in 30 CFR Part 77. 

MSHA’s regulations for coal slurry impoundments apply to 

those impoundments at coal mines, which impound water, sediment 

 

24 On December 22, 2008, the retention wall of a coal ash impoundment at 

Tennessee Valley Authority’s Kingston Plant collapsed, which resulted in a 

massive release of CCRs directly into the Emory River and its tributaries. 

The Emory River joins to the Clinch River and then converges with the 

Tennessee River, a major drinking water source for populations downstream. 

This failure released over a billion gallons of fly ash and bottom ash, which 

impacted over 100 properties, destroyed three homes, and ruptured a gas line 

resulting in the evacuation of 22 residents.
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or slurry to an elevation of more than five feet and have a 

storage volume of 20 acre-feet or more and those coal slurry 

impoundments that impound water, sediment, or slurry to an 

elevation of 20 feet or more. The BMPs being considered today 

for the ELG rule would apply to all CCR impoundments at steam 

electric power generating facilities, regardless of height and 

storage volume. EPA is also considering variations on BMPs for 

the ELGs, including, but not limited to, different inspection 

frequencies or limitations on the applicability of BMPs that 

more closely mirror the applicability of the MSHA regulations. 

EPA requests comment on possible BMPs for inclusion in a final 

ELG rule including those described above and any other 

appropriate variations on them.

Voluntary Incentive Program for Power Plants That Close CCR 

Impoundments or Eliminate All Process Wastewater Discharges 

(Except Cooling Water). EPA is considering establishing, as 

part of the BAT for existing sources, a voluntary incentive 

program that provides more time for plants to implement the 

proposed BAT requirements if they adopt additional process 

changes and controls that provide significant environmental 

protections beyond those achieved by the preferred optionoptions

for this proposed rule. The development of advanced process 

changes and controls is a critical step toward the Clean Water 

Act’s ultimate goal of eliminating the discharge of pollutants 
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into the Nation’s waters. See CWA Section 101(a)(1). Section 

301(b)(1)(C) demands that BAT result in “reasonable further 

progress toward the national goal of eliminating the discharge 

of pollutants.” The preferredEPA intends that, for any BAT 

options discussed in this proposaloption that is ultimately 

selected as part of any final ELG rule, such option would

represent “reasonable further progress,” while the voluntary 

incentives program is designed to get one step closer tocontinue 

progress toward achieving the national goal of the Act. In 

addition, Section 104(a)(1) of the Act 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. The voluntary 

incentives program being considered today would effectively 

accelerate the research into and use of controls and processes 

intended to prevent, reduce, and eliminate pollution because it 

would increase the number of plants choosing to close and cap 

CCR surface impoundments and eliminate discharges of all process 

wastewater (except cooling water) to surface waters.

This voluntary program would establish two levels, or 

“tiers,” of advanced technology performance requirements. which 

would be incorporated into the NPDES permits for the facilities 
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that participate in the program. Under Tier 1, power plants 

would be granted two additional years (beyond the time described 

below in Section VIII.B) if they also commit to dewater, close 

and cap all CCR surface impoundments (except for those 

impoundments containing only combustion residual leachate) at 

the facility, including those surface impoundments located on 

non-adjoining property that receive CCRs from the facility. A 

power plant participating in the Tier 1 program could continue 

to operate surface impoundments for which combustion residual 

leachate is the only type of CCR solids or wastewater contained 

in the impoundment. In general, power plants accepted in the 

Tier 1 incentives program would first convert ash handling 

operations to dry handling or closed-loop tank-based systems and 

FGD wastewater treatment operations to tank-based systems, as 

described above in Section VI. This first step would eliminate 

new contributions of CCRs (solids and wastewater) to the surface 

impoundments. The plants would then dewater the impoundments by 

draining or pumping the wastewater from the impoundments, in 

compliance with the ELGs and other requirements established in 

their NPDES permits. Upon completing the dewatering operations, 

plants would then stabilize the contents and close and cap the 

impoundments consistent with state requirements and any other 

additional requirements that may be established by EPA as part
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of the Tier 1 incentives program or other applicable 

requirements. 

Under Tier 2, power plants would be granted five additional 

years (beyond the time described below in Section VIII.B) if 

they eliminate the discharge of all process wastewater to 

surface waters, with the exception of cooling water discharges. 

The Tier 2 incentives would not be available to power plants 

that eliminate direct discharge to surface water by sending the 

wastewater to a POTW. A plant accepted into the Tier 2 

incentives program would ultimately need to manage its processes 

and wastewater in a manner that implements a coordinated 

approach toward wastewater minimization, treatment and reuse. To 

achieve Tier 2 status, these plants would eliminate all process 

wastewater discharges (except cooling water) by reducing the 

amount of wastewater generated and preferentially using recycled 

wastewater to meet water supply demands. To accomplish this, 

Tier 2 plants would conduct engineering assessments of the 

processes that generate wastewater and identify opportunities to 

eliminate or reduce the amount of wastewater they generate. 

These plants would also assess the processes that use water and 

determine how they could use recycled wastewater in those 

processes, as well as the degree of treatment that may be needed 

to enable such reuse. Based on responses to the industry survey, 

EPA has identified a number of steam electric power plants that 
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currently discharge no process wastewater. In addition, two of 

the plants that EPA visited in Italy previously discharged 

process wastewater, but hadhave implemented wastewater treatment 

and process changes, including wastewater recycle, that now 

allow them to operate without discharging any process wastewater 

except for thsirtheir cooling water.

The primary objective of this program is to encourage 

individual power plants to install advanced pollution prevention 

technologies or make process changes that would further reduce 

releases of toxic pollutants to the environment beyond the 

limits that would be set by the proposed rule. The voluntary 

incentive program being considered is designed to promote 

improvements that, in concert with other environmental 

practices, make significant progress toward achieving EPA’s 

vision of the “power plant of the future” – one which will have 

a minimum impact on the environment. This program would give 

power plants a platform to advance the research and development 

of technologies and processes that promote water conservation 

and water recycling and provide greater environmental 

protection. EPA has conducted site visits at power plants that 

have implemented processes that eliminate the use of water or 

recycle process wastewater to a substantial degree. Furthermore, 

as noted above, EPA observed operations at power plants that 

implemented process modifications and treatment technologies 
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that eliminated all discharges of process wastewater with the 

exception of their cooling water. Implementing such practices at 

other power plants would dramatically reduce discharges of toxic 

and other pollutants. These practices would also substantially 

reduce the amount of water consumed or used by the plant, which 

could be an important consideration for addressing water 

availability and other concerns. In exchange for providing 

additional time for power plants to comply with the proposed BAT 

limitations, the program would lead to superior effluent quality 

and greater environmental protection. 

Participation in the program would be voluntary and it 

would be available only to existing power plants that discharge 

directly to surface waters. Power plants would have until July 

1, 2017 (approximately 3 years after promulgation of the final 

ELGs) to commit to the program and submit a plan for achieving 

the Tier 1 or Tier 2 requirements. Once a power plant enrolls in 

the program, the NPDES permitting authority would develop 

specific discharge limits and key milestones consistent with 

that tier.

Power plants enrolled in the program would ultimately be 

agreeing to adopt NPDES permit limits that are more stringent 

than those that would be required by the proposed and final BAT 

in exchange for additional time to comply with their new 

effluent limitations. These power plants and their corporate 
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owners would also receive public recognition for their 

commitment to increased environmental protection.

EPA considered including features of the Tier 1 and Tier 2 

incentives as part of the options for the proposed rule. 

However, although EPA has observed these practices in operation 

and they are available for at least a portion of the industry, 

the degree of complexity will vary from plant to plant and EPA 

does not have the site-specific information that could be used 

to sufficiently assess how that complexity may affect the 

engineering challenges and costs that plants would encounter. 

EPA requests comment on the voluntary incentives program 

described in this section and any appropriate variations.

3. Rationale for the Proposed Best Available Technology (BAT)

BAT represents the best available economically achievable

performance of facilities in an industrial subcategory or 

category taking into account factors specified in the CWA. The 

CWA factors considered in assessing BAT are the cost of 

achieving BAT effluent reductions, the age of equipment and 

facilities involved, the process employed, potential process 

changes, and non-water quality environmental impacts, including 

energy requirements and such other factors as the Administrator 

deems appropriate. See Section 304(b)(2)(B). In addition to 

technological availability, economic achievability is also a 

factor considered in setting BAT. See Section 301(b)(2)(A).
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After considering all of the technologies described in 

Section VII.B.2, in light of the factors specified in Section 

304(b)(2)(B) and Section 301(b)(2)(A) of the CWA, as 

appropriate, EPA is proposing two putting forth four preferred 

alternatives for BAT. These twofour preferred alternatives

primarily differ in that the second alternativesome would 

establish more environmentally protective BAT and PSES

requirements for discharges of bottom ash transport water and 

combustion residual leachate two of the of wastestreams from 

existing sources. Under onethe first preferred alternative, EPA 

is proposing to establish BAT effluent limits based on the 

technologies specified in Option 3a. With the exception of oilfired generating units and small generating units (i.e., 50 MW 

or smaller), the proposed rule under Option 3a would:

Establish a “zero discharge” effluent limit for all 

pollutants in fly ash transport water and FGMC wastewater;3

Establish numeric effluent limits for mercury, arsenic, 

selenium, and TDS in discharges of gasification wastewater;

Establish numeric effluent limits for copper and iron in 

discharges of nonchemical metal cleaning wastes25; 

Establish BAT effluent limits for bottom ash transport 

water and combustion residual leachate that are equal to 

the current BPT effluent limits for these discharges (i.e., 

numeric effluent limits for TSS and oil and grease; and

BAT for discharges of FGD wastewater would continue to be 

determined on a site-specific basis.

 

25 As described later in this section, EPA is proposing to exempt from new BAT 

copper and iron limitations existing discharges of nonchemical metal cleaning 

wastes that are currently authorized under their existing NPDES permit 

without iron and copper limits. For these discharges, BAT limits would be set 

equal to BPT limits for low volume waste.
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Under the second preferred alternative for BAT, EPA is 

proposing to establish BAT effluent limits based on the 

technologies specified in Option 3b. With the exception of oilfired generating units and small generating units (i.e., 50 MW 

or smaller), the proposed rule under Option 33b would:

Establish numeric effluent limits for mercury, arsenic,

selenium, and nitrate-nitrite in discharges of FGD 

wastewater for units located at plants with a total wetscrubbed capacity of 2,000 MW or more26,27;

Establish a “zero discharge” effluent limit for all 

pollutants in fly ash transport water and FGMC wastewater;

Establish a “zero discharge” effluent limit for all 

pollutants in fly ash transport water and FGMC wastewater;

Establish numeric effluent limits for mercury, arsenic, 

selenium, and TDS in discharges of gasification wastewater;

Establish numeric effluent limits for copper and iron in 

discharges of nonchemical metal cleaning wastes28; and

Establish BAT effluent limits for bottom ash transport 

water and leachate that are equal to the current BPT 

effluent limits for these discharges (i.e., numeric 

effluent limits for TSS and oil and grease).

Under the secondthird preferred alternative for BAT (Option 

4),, EPA is proposing to establish BAT effluent limits based on 

the technologies specified in Option 3. In addition to the 

requirements described for Option 3b, the proposed rule would 

 

26 Total plant-level wet-scrubbed capacity is calculated by summing the 

nameplate capacity for all of the units that are serviced by wet FGD systems.

27 For units below the 2,000 MW threshold, BAT would continue to be determined 

on a site-specific basis.

28 As described later in this section, EPA is proposing to exempt from new BAT 

copper and iron limitations existing discharges of nonchemical metal cleaning 

wastes that are currently authorized under their existing NPDES permit 

without iron and copper limits. For these discharges, BAT limits would be set 

equal to BPT limits for low volume wastes.
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establish the same numeric effluent limits as in Option 3b for 

mercury, arsenic, selenium, and nitrate-nitrite in discharges of 

FGD wastewater from units located at all steam electric 

facilities, with the exception of oil-fired generating units and 

small generating units (i.e., 50 MW or less).

Under the fourth preferred alternative for BAT (Option 4a), 

in addition to the requirements described for Option 3, the 

proposed rule would establish “zero discharge” effluent limits 

for all pollutants in bottom ash transport water and establish 

numeric effluent limits for mercury and arsenic in discharges of 

combustion residuals leachate. All other proposed Option 4 

requirements are identical to the proposed Option 3 

requirements.from units greater than 400 MW. 

For oil-fired generating units and small generating units

(i.e., 50 MW and smaller) that are existing sources, under both 

Options 3 and 4all four preferred options, EPA is proposing to 

set the BAT effluent limits equal to the current BPT effluent 

limits for copper and iron for nonchemical metal cleaning 

wastes29, and for TSS and oil and grease for five of the other

six wastestreams listed above.

 

29 As described later in this section, EPA is proposing to exempt from new BAT 

copper and iron limitations existing discharges of nonchemical metal cleaning 

wastes that are currently authorized under their existing NPDES permit 

without iron and copper limits. For these discharges, BAT limits would be set 

equal to BPT limits for low volume waste.
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EPA is proposing Options (i.e., FGD wastewater, fly ash 

transport water, FGMC wastewater, leachate from landfills and 

surface impoundments containing combustion residuals, and 

gasification wastewater). EPA is proposing Options 3a, 3b, 3 and 

44a as the preferred BAT regulatory options because its analysis 

to this date suggests that they are bothall technologically 

available, economically achievable, and have acceptable nonwater quality environmental impacts. However, EPA is coproposing these twoputting forth a range of options as 

candidates for BAT in order to confirmenhance the Agency’s 

understanding of the pros and cons of Options 3 and 4each of 

these options in light of the statutory factors through the 

public comment process and intends to evaluate this information 

and how it relates to the factors specified in the CWA. As 

discussed above in sectionSections VI and VIII.A.2, both Options

3 and 4the data in EPA’s record and its analysis to date 

suggests that all four options are technologically available. 

EPA’s record indicates that the technologies comprising Options 

3a, 3b, 3, and 44a are well-demonstrated and have been employed 

at power plants for years. The technology used as the basis for 

FGD wastewater treatment under both Options 3 and 4 has been 

tested at a subset of existing power plants for more than 10 

years and full-scale systems have been operating for 5 years.

The biological treatment processes used in the bioreactor 
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portion of the treatment technology have been widely used in 

many industrial applications for decades both in the U.S. and 

internationally. Five steam electric power plants operate fixedfilm anoxic/anaerobic biological treatment systems to treat FGD 

wastewater and another operates a suspended growth biological 

treatment system that targets removal of selenium.

30 Moreover, 

approximately one-third of plants that discharge FGD wastewater 

utilize chemical precipitation (in some cases, also using

additional treatment steps). The chemical precipitation 

treatment processes included in the FGD wastewater technology 

basis for Options 3 and 4 are used at 24 percent of steam 

electric power plants that discharge FGD wastewater (and another 

11 percent of plants also use chemical precipitation systems 

that could easily be upgraded to the Option 3 technology basis) 

and also at thousands of industrial facilities nationwide.. 

Under all of the preferred options, the technology basis 

for fly ash transport water is dry handling. All generating 

units built in the 30 years since the ELGs were last revised in 

1982 have been subject to a zero discharge standard for the 

pollutants in fly ash transport water, in nearly all cases 

installing dry fly ash handling technologies to comply with the 

standard. In addition, many other generating units that could 

 

30 Four of the six operate the biological treatment systems in combination 

with chemical precipitation.
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discharge their fly ash transport water upon meeting a TSS 

effluent limit have instead retrofitted the dry fly ash handling 

technology to meet operational needs or for economic reasons.

Approximately 40 percent of the plants that were operating wetsluicing systems in 2000 have converted generating units to dry 

fly ash (approximately 115 generating units at 45 power plants). 

Another 61 generating units are slated to convert to dry fly ash 

handling by 2020. Based on data collected by the industry 

survey, approximately 66 percent of coal- and petroleum cokefired generating units handle all fly ash with dry technologies. 

Another 15 percent of coal- and petroleum coke-fired generating 

units have both wet and dry fly ash handling systems (typically, 

the wet system is a legacy system that the plant has not 

decommissioned following retrofit with a dry system). Only 19 

percent of coal- and petroleum coke-fired generating units 

exclusively use a wet fly ash handling system. Furthermore, 

some of these plants with wet fly ash handling systems manage 

the ash handling process so that they do not discharge fly ash 

transport water. As a result, EPA determined that only 13 

percent of coal-fired power plants would incur costs to comply 

with a BAT zero discharge requirement for fly ash transport 

water. See Section 9.7.3 of the TDD.

Power plants recently began installing FGMC systems either 

to comply with state requirements or to prepare for emissions 
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limits established by the MATS rule. Plants using sorbent 

injection systems (e.g., activated carbon injection) typically 

handle the spent sorbent in the same manner as their fly ash. 

Nearly all plants with FGMC systems use dry handling 

technologies. 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 currently 

operate them as closed-loop systems and do not discharge FGMC 

wastewater to surface waters, or have the capability to do so. 

These plants could continue to operate these wet systems as 

closed-loop systems, or could convert to dry handling 

technologies by managing the fly ash and spent sorbent together 

in a retrofitted dry system (the wastes are currently managed 

together in the impoundments) or by installing dedicated dry 

handling equipment for the FGMC wastes similar to the equipment 

used for fly ash. 

The technology basis for control of discharges of FGD 

wastewater under Options 3, 3b (for units located at plants with 

a total wet-scrubbed capacity of 2,000 MW or more), and 4a is 

chemical precipitation followed by anaerobic biological 

treatment. Four power plants, or approximately three percent of 

wet-scrubbed power plants that discharge FGD wastewater already 

have the Options 3b (for units located at plants with a total 

wet-scrubbed capacity of 2,000 MW or more), 3 and 4a BAT 
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technology in place. Under Options 3b (for units located at 

plants with a total wet-scrubbed capacity of 2,000 MW or more), 

3, and 4a, in addition to other new requirements that would be 

established, numeric limits would be established for toxic 

discharges including arsenic, mercury, and selenium from FGD 

wastewater. 

The technology used as the basis for FGD wastewater 

treatment under Options 3b (for units at plants with a total 

wet-scrubbed capacity of 2,000 MW or more), 3 and 4a has been 

tested at power plants for more than 10 years and full-scale 

systems have been operating at a subset of plants for 5 years.

The biological treatment processes used in the bioreactor 

portion of the treatment technology have been widely used in 

many industrial applications for decades both in the U.S. and 

internationally. Five steam electric power plants operate fixedfilm anoxic/anaerobic biological treatment systems to treat FGD 

wastewater and another operates a suspended growth biological 

treatment system that targets removal of selenium.

31 Other power 

plants are considering installing the biological treatment 

technology to remove selenium and at least one plant is moving 

forward with construction. See DCN SE03874. In addition, four 

additional power plants currently operate anaerobic biological 

 

31 Four of the six operate the biological treatment systems in combination 

with chemical precipitation.
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treatment systems for their FGD wastewater, indicative that this 

is available technology. EPA is aware of industry concerns with 

the feasibility of biological treatment at some power plants. 

Specifically, industry has asserted that the efficacy of these 

systems is unpredictable, and is subject to temperature changes, 

high chloride concentrations, and high oxidation reduction 

potential in the absorber (which may kill the treatment 

bacteria). EPA’s record to date does not support these 

assertions, but is interested in additional information that 

addresses these concerns.

More than one-third of plants that discharge FGD wastewater 

utilize chemical precipitation (in some cases, also using

additional treatment steps). As noted above, four power plants 

currently operate chemical precipitation systems in combination 

with anaerobic biological treatment systems. The chemical 

precipitation treatment processes included in the FGD wastewater 

technology basis for these options are used at 24 percent of 

steam electric power plants that discharge FGD wastewater (and 

another 11 percent of plants also use chemical precipitation 

systems that could be upgraded to this technology basis) and 

also at thousands of industrial facilities nationwide (See 

Section 8.1.3 of the TDD).

32

 

32 Physical/chemical treatment systems can be effective at removing mercury 

and certain other metals; however, to achieve effective removal of selenium 
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Option 3b proposes limitations based on this technology for 

units at the largest plants (as determined by a 2,000 MW total 

wet-scrubbed capacity threshold), and BAT for the control of 

discharges of FGD wastewater from units at plants below this 

threshold would continue to be determined on a site-specific 

basis. For FGD wastewater only, EPA believes any threshold 

should be based on a plant level rather than a unit level 

because many plants currently use a single FGD treatment systems 

to service multiple units. Additionally, EPA determined that 

wet-scrubbed capacity is an appropriate metric because it only 

reflects units that are generating FGD wastewater. For example, 

a plant could have a total plant nameplate generating capacity 

of 3,500 MW, but only have a wet-scrubbed capacity of 200 MW if 

only one of its units is wet-scrubbed. EPA is putting forth this 

option as a preferred option based on an assumption that these 

facilities are more able to achieve these limits based on 

economies of scale. These largest facilities will likely also be 

able to absorb the costs of installing and operating the 

chemical precipitation and anaerobic biological treatment 

systems on which the FGD wastewater limitations are based. For 

these reasons, as well as those specified above related to 

current innovation and treatment trends, Option 3b proposes that 

 

this technology must be coupled with additional treatment technology such as 

anoxic/anaerobic biological treatment.
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BAT effluent limitations for discharges of FGD wastewater would 

continue to be determined on a site-specific basis for units at 

facilities below the 2,000 MW threshold. EPA solicits comment on 

the proposed 2,000 MW threshold applicable to discharges of FGD 

wastewater under Option 3b, including whether this or another 

threshold may be more appropriate. 

The fourth preferred alternative for this proposed rule,

Option 4a, in addition to the requirements that would be 

established under Option 3, would eliminate discharges of 

pollutants in bottom ash transport water from units greater than 

400 MW. The technology basis for bottom ash for the zero 

discharge requirement is dry handling or a closed-loop system. 

Bottom ash transport water is one of the three largest sources 

for discharges of the pollutants of concern from steam electric 

power plants and these discharges occur at many power plants 

across the nation. Based on data collected by the industry 

survey, approximately 30 percent of coal-fired and petroleum 

coke-fired power plants handle bottom ash using technologies 

that do not generate any transport water. In addition, another 

12 percent of coal- and petroleum coke-fired power plants manage 

the wet-sluicing bottom ash handling system as a closed-loop 

system that recirculates all bottom ash transport water so that 

it is not discharged. In addition, 83 percent of coal-fired 
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generating units built in the last 20 years installed dry bottom 

ash handling systems. 

EPA recognizes that the potential costs associated with 

compliance with a zero discharge standard for discharges of 

bottom ash transport water would be substantial if applied to 

all facilities (for example, approximately half of Option 4 

costs and approximately a third of Option 5 costs), and, 

therefore, looked carefully at this wastestream with a 

particular focus on generating unit size. Our review 

demonstrated that, in the case of bottom ash transport water, 

units less than or equal to 400 MW are more likely to incur 

compliance costs that are disproportionately higher per MW than 

those incurred by larger units. For example, the average 

annualized cost of achieving zero discharge limits for bottom 

ash discharges (i.e. dry handling or closed loop) per MW for a 

200 MW unit is more than three times higher than the average 

cost for a 400 MW unit. Based on the data from the industry 

survey, EPA estimates that 25 percent of coal-fired power plants 

would incur costs to comply with a BAT zero discharge 

requirement for bottom ash transport water from units greater 

than 400 MW.

Furthermore, while all plants, regardless of size, are 

capable of installing and operating dry handling or closed-loop 

systems for bottom ash transport water, and the costs would be 
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affordable for most plants, EPA believes that companies may 

choose to shut down 400 MW and smaller units instead of making 

new investments to comply with proposed zero discharge bottom 

ash requirements. EPA is basing this belief on its review of 

units that facilities have announced will be retired or 

converted to non-coal based fuel sources. Of those units that 

plants have announced for retirement, and that also generate 

bottom ash transport water, over 90 percent are 400 MW or less. 

See DCN SE03834.

Therefore, for the reasons specified above, for units less 

than or equal to 400 MW, Option 4a proposes to set the BAT 

effluent limits equal to the current BPT effluent limits based 

on surface impoundments. EPA solicits comment on the proposed 

400 MW threshold applicable to discharges of bottom ash 

transport water under Option 4a, including whether this or 

another threshold may be more appropriate.

The two IGCC plants currently operating in the United 

States use the technology that is the basis for Options 3 and 

4all four preferred options for gasification wastewater. A third 

IGCC plant that will soon begin commercial operation will also 

use the Option 3/4 technology and, in addition to that, will 

also operate a cyanide destruction step as part of the treatment 

system.
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TheFor all four preferred options, the proposed BAT limits 

for copper and iron in discharges of nonchemical metal cleaning 

waste are equal to the current BPT effluent limits for these 

pollutants in metal cleaning waste. This approach would be 

consistent with current industry practice for treating 

nonchemical metal cleaning waste and isThese effluent limits are

based on the same technology that was used as the basis for the 

current ELG BPT requirements for metal cleaning waste (i.e., 

chemical precipitation). 

Discharges of metal cleaning waste. wastes that are 

generated from cleaning metal process equipment without chemical 

cleaning compounds (i.e., nonchemical metal cleaning waste) are

already subject to BPT effluent limits for copper and iron equal 

to the BAT effluent limits being proposed today. Based on 

responses to the industry survey, facilities typically treat 

both chemical and nonchemical metal cleaning waste in similar 

fashion.

Since, as described above, nonchemical metal cleaning waste 

is included within the definition of metal cleaning waste, and 

copper and iron are already regulated under metal cleaning 

wastes, EPA would be establishing BAT limits equal to the BPT 

limits (for copper and iron) that already apply to these wastes.

As a result, facilities would incur no cost to comply with the 

proposed BAT for these wastes. Discharges of metal cleaning 
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wastes that are generated from cleaning metal process equipment 

without chemical cleaning compounds (i.e., nonchemical metal 

cleaning waste) are already subject to BPT effluent limits for 

copper and iron equal to the BAT effluent limits being proposed 

today. Based on responses to the industry survey, facilities 

typically treat both chemical and nonchemical metal cleaning 

waste in similar fashion As a result, facilities should incur no 

cost to comply with the proposed BAT for these wastes. However, 

EPA recognizes that previous guidance provided after the final 

1974 regulation stated that wastes from metal cleaning with 

water are considered “low volume” wastes. The extent to which 

this statement was relied upon is unclear, and EPA rejected the 

guidance in the 1982 rulemaking for the steam electric ELGs (47 

FR 52297). However, because permitting authorities and others 

may have relied on this guidance and the potential costs to 

those facilities are not known, EPA is proposing to exempt from 

any new copper and iron BAT requirements those discharges of 

nonchemical metal cleaning waste to which this guidance was 

applied in the past. In other words, EPA is proposing to exempt 

from proposed new copper and iron BAT limitations those 

discharges of nonchemical metal cleaning wastes from generating 

units that are currently authorized to discharge nonchemical 

metal cleaning wastes without copper and iron limits pursuant to 

existing BPT requirements for metal cleaning waste. For such 
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discharges, EPA is proposing to set BAT limitations equal to BPT 

limitations for low volume waste.

Under the second preferred alternative for this proposed 

rule, EPA is proposing Option 4 as the preferred BAT option 

which, in addition to the requirements that would be established 

under Option 3, would eliminate discharges of pollutants in 

bottom ash transport water and establish numeric limits on toxic 

metals for discharges of leachate. The pollutant discharges from 

these two wastestreams would be controlled at a much lesser 

degree under Option 3 (i.e., BAT would be set equal to BPT 

limits for TSS and oil and grease, based on the performance of 

gravity settling in surface impoundments). Option 4 is 

technologically available (see, for example, the extent of dry 

ash handling systems and closed-loop wet sluicing systems for 

bottom ash, and the availability of chemical precipitation 

treatment technology for leachate, discussed in section VI), 

economically achievable (based on IPM and other economic impact 

analyses), and has acceptable non-water quality environmental 

impacts (including reducing water use by 158 billion gallons per 

year).

Bottom ash transport water is one of the three largest 

sources for discharges of the pollutants of concern and these 

discharges occur at many power plants across the nation. Based 

on data collected by the industry survey, approximately 20 
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percent of coal-fired and petroleum coke-fired generating units 

handle bottom ash using technologies that do not generate any 

transport water. In addition, the wet-sluicing bottom ash 

handling system at some other power plants is managed as a 

closed-loop system that recirculates all bottom ash transport 

water so that it is not discharged. 

Combustion residual leachate is comprised of liquids that 

have either leaked from a surface impoundment or leached through 

a landfill containing combustion wastes, and thus it contains 

many of the pollutants present in FGD wastewater, fly ash 

wastewater, bottom ash wastewater, and other wastes. 

Furthermore, due to the continued use of coal (and with the 

resultant generation of coal ash that will be landfilled) and 

the increasing use of air pollution controls (e.g., FGD systems, 

FGMC systems), which generate residuals destined for a landfill, 

the amount of leachate that plants will discharge to surface 

waters (and the amount of pollutants entrained in the leachate 

discharges) is expected to increase over time. Many of the 

pollutants stripped from flue gases by air pollution controls, 

including dissolved metals, would be discharged to surface 

waters under Option 3. Under Option 4, however, effluent limits 

based on chemical precipitation treatment technology would 

ensure the removal of many of the pollutants from leachate prior 

to its discharge to surface waters.
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Both Options 3 and 4 are economically achievable.To get a 

better understanding of how discharges of nonchemical metal 

cleaning wastes are currently permitted, EPA’s regional offices 

recently reviewed 45 permits for plants that EPA had reason to 

believe generated nonchemical metal cleaning waste based on 

responses to the industry survey. For these permits, EPA 

determined the following based on the review:

64 percent of the plants are either zero discharge of 

metal cleaning wastes or have to comply with copper 

and iron limits;

27 percent of plants do not have to comply with copper 

and iron limits; and

9 percent of plant permits do not include enough 

information to determine whether the plant would be in 

compliance with the proposed BAT limitations.

While not exhaustive, this review provides some information to 

suggest that many, but not all, plants are either zero discharge 

or have iron and copper limits and thus are already meeting 

today’s proposed BAT limitations. Also see Section 7.7 of the 

TDD.

In order to implement the exemption proposed today for 

certain discharges of nonchemical metal cleaning waste that have 

historically been treated as low volume wastes and not subject 

to copper and iron limits under metal cleaning waste BPT 
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requirements, EPA’s current thinking is to develop a specific 

list of generating units eligible for the exemption. Therefore, 

EPA is seeking to identify those generating units that should be 

eligible for the exemption through the public comment process on 

this rulemaking. To qualify for the proposed exemption, the 

generating unit must meet all three of the following criteria:

The generating unit must currently generate 

nonchemical metal cleaning wastes;

The generating unit must discharge the nonchemical 

metal cleaning waste; and

The generating unit must be located at a plant that is 

authorized to discharge the nonchemical metal cleaning 

waste without limitations for copper and iron.

If the nonchemical metal cleaning wastes generated and 

discharged by a generating unit do not meet all of these three 

criteria, then EPA proposes that the generating unit will not be 

eligible for the exemption. For example, if the plant currently 

hauls the nonchemical metal cleaning wastes off site for 

disposal, the generating units associated with the nonchemical 

metal cleaning waste generation would not be exempt. Any public 

comments submitted with the intention of identifying generating 

units that might appropriately fall within the exemption must 

provide the necessary documentation (e.g., permits, fact sheets) 

to support a finding that the generating unit meets all three 
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criteria. EPA also requests comment on this general method of 

implementing the exemption. Another approach would be to define 

the conditions of the exemption, and then make it available to 

any facility that qualified, regardless of whether the facility 

was identified to EPA during the comment period. This would give 

EPA less information on the potential effects of including this 

exemption in the final rule, but would also allow qualified 

facilities to make use of the exemption even if they were 

unaware of the need to file comments during the comment period

in order to make use of it. EPA requests comment on this, or any 

other, way of implementing the proposed exemption.

EPA is also considering setting BAT limitations equal to 

BPT limitations applicable to metal cleaning waste for all 

discharges of nonchemical metal cleaning wastes (i.e., not 

creating an exemption from copper and iron limits for discharges 

of nonchemical metal cleaning wastes from generating units 

currently authorized to discharge those wastes without copper 

and iron limits). As part of this approach, EPA is evaluating 

whether plants would incur costs to comply with the current BPT 

requirements applicable to discharge of metal cleaning wastes. 

Therefore, EPA is also soliciting comments that provide 

information on those generating units that are not currently 

subject to the BPT metal cleaning waste limitations for copper 

and iron, in order to understand what actions would be required 
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to comply with the proposed BAT nonchemical metal cleaning waste 

limitations for iron and copper. EPA is particularly interested 

in the following information:

Type of nonchemical metal cleaning waste generated, 

frequency of generation, and volume generated;

Wastewater characterization data (i.e., monitoring data) 

for the nonchemical metal cleaning waste;33

Information regarding the actions that would need to be 

taken to comply with the iron and copper limits for the 

nonchemical metal cleaning wastes discharged; and

Estimated capital and operating and maintenance costs, 

broken out by specific cost components (e.g., equipment 

costs, installation costs, labor costs), to comply with the 

proposed copper and iron limits, along with the basis for 

the cost estimate.

EPA’s analysis to date suggests that all four preferred 

options, Option 3a, Option 3b, Option 3, and Option 4a, are

economically achievable. EPA performed cost and economic impact 

assessments using the Integrated Planning Model (IPM).34 The) for 

 

33 Commenters should provide available monitoring data (i.e., EPA is not 

requiring the commenters to collect additional samples). Additionally, 

commenters should specify what data are represented by the characterization 

data (which wastestreams were sampled, the percent contribution of each 

wastestream, whether the samples are untreated or treated, and if treated, 

the type of treatment system represented).

34 IPM is a comprehensive electricity market optimization model that can 

evaluate such impacts within the context of regional and national electricity 

markets. See Section XI for additional discussion.
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Option 3 and Option 4.35 Option 4 is more costly than any of the 

four preferred options including Option 4a; therefore by 

performing the assessments with these two options, EPA can 

evaluate the potential effects of each of the preferred options. 

Because the costs and the facilities affected by Option 3a and 

3b are a subset of Option 3, EPA can use the results of Option 3 

to inform the potential impacts of Option 3a and Option 3b. In a 

similar way, because the costs and the facilities affected by 

Option 4a are a subset of Option 4, EPA can use the results of 

Option 4 to inform the potential impacts of Option 4a. 

For the options analyzed overall, the model predictedshowed

very small effects on the electricity market, on both a national 

and regional sub-market basis. Based on the results of these 

analyses, EPA estimates that the proposed requirements 

associated with Option 3a, Option 3b, and Option 3 would not 

lead to the premature retirement of any steam electric 

generating units (i.e., no partial or full plant closures). 

EPA’s IPM analysis also shows that Option 4 is affordable 

for the industry. The results for Option 4 show fourteen unit 

(partial) closures and zero plant (full) closures 

predictedprojected as of the model year 2030, reflecting full 

 

35 IPM is a comprehensive electricity market optimization model that can 

evaluate such impacts within the context of regional and national electricity 

markets. See Section XI for additional discussion.
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compliance of all facilities.36,37 The 14 generating units are 

located at six plants. The IPM results also show that five steam 

electric units that are predictedprojected to close under the 

base case (i.e., in the absence of the proposed revisions to the 

ELG) would remain operating if Option 4 requirements were 

promulgated (i.e., avoiding closure). These IPM predictions for 

closures and avoided closures support EPA’s conclusion that 

Option 4under proposed Option 4 (i.e., avoiding closure). As a 

result, for Option 4, the IPM analysis projects total net 

closure of nine generating units, with total combined generating 

capacity of 317 MW. These results support EPA’s conclusion that 

Option 4 is economically achievable. As explained above, because 

the costs and facilities affected by Option 4a are only a subset 

of Option 4 (i.e., are less than those for Option 4), the model 

would project similar or smaller effects for Option 4a. These 

IPM estimates for closures and avoided closures also support 

EPA’s conclusion that Option 4a is economically achievable for 

the steam electric industry.

As part of its consideration of technological availability 

and economic achievability, EPA also considered the magnitude 

 

36 As used here for the purpose of this rulemaking, the term partial closure 

refers to a plant where the closure of a generating unit is projected, but 

one or more generating units at the plant will continue operating. A full 

closure refers to a situation where all generating units at a plant are 

projected to shut down. 

37 Given the design of IPM, unit-level and thereby plant-level projections are 

presented as an indicator of overall regulatory impact rather than a 

prediction of future unit–level or plant-specific compliance actions.
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and complexity of process changes and new equipment 

installations that would be required at facilities to meet the 

requirements of the rule. As described in greater detail in 

sectionSection XVI, EPA is proposing that, where the limitations 

and standards being proposed today for existing direct and 

indirect dischargers do notare more stringent than existing BPT 

requirements, those limitations and standards do not begin to

apply until July 1, 2017 (approximately three years following 

promulgation of the final rule). EPA is proposing this approach 

to provide the time that many facilities will need to raise 

capital, plan and design systems, procure equipment, and 

construct and then test systems. Moreover, this approach will 

enable facilities to take advantage of planned shutdown or 

maintenance periods to install new pollution control 

technologies. EPA’s proposal is designed to minimize any 

potential impacts on electricity availability caused by forced 

outages.

Options 3a, 3b, 3 and 44a have acceptable non-water quality 

environmental impacts, as discussed in sectionSection XV of the 

preamble and in the TDD. EPA estimates that OptionOptions 3a, 

3b, 3, and 4a would increase energy consumption by less than 

0.003 percent, less than 0.004 percent, less than 0.008 percent, 

and less than 0.012 percent, respectively, of the total 

electricity generated by power plants, and . EPA also estimates 
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that Options 3a, 3b, 3, and 4a would increase the amount of fuel 

consumed by increased operation of motor vehicles (e.g., for 

transporting coalfly ash) would increase by less than 0.009 

percent, less than 0.009 percent, less than 0.009 percent, and 

less than 0.014 percent, respectively, of total fuel consumption 

by all motor vehicles. Under Option 4, energy consumption would 

increase by 0.017 percent and fuel consumption would increase by 

less than 0.018 percent.

As discussed in Section XV.B., EPA also evaluated the 

effect of the proposed rule on air emissions generated by power 

plants (NOx, sulfur oxides (SOx), and CO2). TheFor Options 3a, 

3b, and 3, the NOx emissions are estimated to increase by onlyno 

more than 0.12 percent under, and for Option 3 and4a, by no more 

than 0.1513 percent under Option 4. EPA predictsprojects no 

significant increase in emissions of SOx andor CO2 will decrease

under both Option 3the four preferred options. 

EPA also evaluated the effect of the proposed rule on solid 

waste generation and 4.water usage. There would be no increase 

in solid waste generation under Option 3a, and EPA estimates 

that solid waste generation at power plants will increase by 

less than 0.001 percent under Option 3 and by 0.0011 percent 

under Option 4. Under Option 3, the other three preferred 

options. EPA estimates the power plants would reduce water use 

by 5450 billion gallons per year (147136 million gallons per 
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day). Water use would be reduced by 158) under Option 3a, 52

billion gallons per year (432143 million gallons per day) under 

Option 3b, 53 billion gallons per year (144 million gallons per 

day) under Option 3, and 103 billion gallons per year (282

million gallons per day) under Option 44a.

EPA also examined the effects of the preferred options on 

consumers as an “other factor” that might be appropriate when 

considering what level of control represents BAT. Even ifIf all 

compliance costs were passed on to residential consumers of 

electricity instead of being borne by the operators and owners 

of power plants, the monthly increase in electricity bill would 

be small – on the order ofno more than $0.04, $0.06, $0.13 per 

month for the average household, and $0.22, respectively under 

OptionOptions 3a, 3b, 3, and $0.32 per month for Option 4.

For the final rule, EPA will continue to evaluate whether 

BAT should be based on Option 3 or Option 4, or alternatively, 

with certain elements of Option 4 added to Option 3 (e.g., 

Option 3 plus zero discharge for bottom ash transport water, or 

Option 3 plus effluent limits for leachate based on chemical 

precipitation).4a.

EPA is not proposing either Option 1 or Option 2 as its 

preferred option for BAT because neither option would represent 

the best available technology level of control for steam 

electric power plant discharges. For example, Options 1 and 2 

Formatted: Highlight
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would allow plants to continue to discharge fly ash transport 

wastewater without treating the wastes to remove dissolved 

metals and many of the other pollutants present in the 

wastewater. However, 66 percent of all coal- and petroleum cokefired generating units that produce fly ash as a residue of the 

combustion process already use dry fly ash technologies to 

manage all of their fly ash without any associated creation or 

discharge of fly ash transport water. And another 15 percent of 

the coal- and petroleum coke-fired generating units that produce 

fly ash also already operate dry fly ash handling systems in 

addition to a wet ash handling system (either as a completely 

redundant system, or to manage a fraction of the fly ash that is 

produced during combustion). Similarly, every generating unit 

operating a FGMC system does so in a manner that avoids creating 

any FGMC wastewater (92 percent of units with FGMC), or manages 

the FGMC wastewater in a closed cycle process that does not 

result in a discharge to surface water (8 percent of units with 

FGMC). The technology serving as the basis for FGD effluent 

limits under Option 1 is not effective at removing many of the 

pollutants of concern in FGD wastewater, including selenium, 

nitrogen compounds, and certain metals that contribute to high 

concentrations of total dissolved solids in FGD wastewater 

(e.g., bromides, boron). Furthermore, the information in the 

record for this proposed rule demonstrates that the amount of 
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mercury, selenium, and other pollutants removed by the 

biological treatment stage of the treatment system, above and 

beyond the amount of pollutants removed in the chemical 

precipitation treatment stage preceding the bioreactor, can be 

substantial. Both Options 1 and 2 would remove fewer or similar 

levels of pollutants than Option 3 or Option 4, bothto the 

preferred options, all of which EPA has foundbelieves, based on 

its analysis to date, to be technologically available, 

economically achievable, and have acceptable non-water quality 

environmental impacts. Options 1 and 2 would establish new 

effluent limits for only three of the seven key wastestreams 

addressed in this rulemaking. For the remaining four 

wastestreams, BAT effluent limits would be set equal to the 

current BPT effluent limits.

EPA did not select Option 4 as its preferred regulatory 

option because of concerns expressed above associated with the 

projected compliance costs associated with zero discharge 

requirements for bottom ash for units equal to or below 400 MW. 

The bottom ash requirements for Option 4 and the preferred 

Option 4a are the same with the exception that Option 4a 

proposes to set the BAT effluent limits for bottom ash transport 

water equal to the current BPT effluent limits for units less 

than or equal to 400 MW, while Option 4 would set the BAT 

effluent limits for bottom ash transport water equal to the BPT 
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effluent limits for units less than or equal to or below 50 MW. 

All other units would be subject to “zero discharge” effluent 

limits for all pollutants in bottom ash transport water. 

Moreover, Option 4 proposes to establish BAT discharge 

limitations for toxic discharges for leachate. The record 

demonstrates that the amount of pollutants collectively 

discharged in leachate by steam electric plants is a very small 

portion of the pollutants discharged collectively for all steam 

electric power plants (i.e., less than 1⁄2 a percent). The 

technology basis for limitations on discharges of combustion 

residual leachate proposed under Option 4 is chemical 

precipitation. Because of the relatively low level of pollutants 

in this wastestream, and because EPA believes this is an area 

ripe for innovation and improved cost effectiveness, EPA is not 

putting forward this option as a preferred option. On balance, 

EPA would like to collect additional information on costs and 

effectiveness of chemical precipitation and other possible 

technologies for reducing pollutants discharged in leachate 

before making a finding with respect to what technologies 

represent the best available technology economically achievable 

for controlling discharges of pollutants found in combustion 

residual leachate. Consequently, EPA is interested in receiving 

information through the public-comment process related to cost, 

pollutant reduction, and effectiveness data on chemical 
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precipitation and alternative approaches to treatment of 

combustion residual leachate. 

EPA did not select Option 5 as its preferred option for BAT 

because of the high total industry cost for the option ($2.23

billion/year annualized social cost) and because of preliminary 

indications that Option 5 may not be economically achievable. 

While EPA has traditionally looked at affordability of the rule 

to the regulated industry, EPA has in some limited instances 

over the past three decades rejected an option primarily on the 

basis of total industry costs. See 48 FR 32462, 32468 (July 15, 

1983) (Final Rule establishing ELGs for the Electroplating and 

Metal Finishing Point Source Categories); 74 FR 62996, 63026 

(Dec. 1, 2009) (Final Rule establishing ELGs for the 

Construction and Development Point Source Category); BP 

Exploration & Oil, Inc. v. EPA, 66 F.3d 784, 796-97 (6th Cir. 

1996) (upholding EPA’s decision not to require zero discharge of 

produced waters based on reinjection for the Offshore 

subcategory of the Oil and Gas Extraction Point Source Category 

based in part on total industry cost). EPA similarly finds this 

appropriate here. In addition, certain screening-level economic 

impact analyses indicated that compliance costs may result in 

financial stress to some entities owning steam electric plants. 

Although EPA did not select Option 5 as the preferred BAT 

option, without question, Option 5 would remove the most 
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pollutants from steam electric power plant discharges. Also, the 

technologies are all potentially available and may be 

appropriate (individually or in totality) as the basis for water 

quality-based effluent limits in NPDES permits, depending on 

site-specific conditions. For example, any of the requirements 

that would be established under Option 5, including at a minimum 

the vapor compression evaporation technology serving as the 

Option 5 technology basis for FGD wastewater, may be appropriate 

for those power plants that discharge upstream of drinking water 

treatment plants and that have bromide releases in wastewaters 

that impact treatment of source waters at the drinking water 

treatment plants. Section XIII of the preamble includes 

additional discussion about discharges of bromides. Also, see 

the EA.

For the reasons described below in sectionSection VIII.B., 

EPA is proposing that, where the limitations and standards being 

proposed today do notare more stringent than existing BPT 

requirements, those limitations and standards do not begin to

apply until July 1, 2017 (approximately three years from the 

effective date of this rule).

For all fiveeight of the main BAT options under 

consideration, EPA is proposing to establish effluent limits for 

oil-fired generating units and small generating units (i.e., 50 

MW or smallerless) that differ from the effluent limits for all 
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other generating units38. For oil-fired generating units and 

small generating units, EPA is proposing to set the BAT effluent 

limits equal to the current BPT effluent limits for all seven of 

the key wastestreams addressed by this proposed rule. For six of 

these wastestreams, BAT would be set equal to current BPT

numeric limits for TSS and oil and grease, with these pollutants 

regulated as indicator pollutants for the control of toxic and 

nonconventional pollutants. For nonchemical metal cleaning 

wastes, EPA is proposing to set BAT equal to the current BPT 

effluent limits for copper and iron in metal cleaning wastes39, 

but would not establish BAT effluent limits for TSS and oil and 

grease (which are also currently regulated by BPT for metal 

cleaning wastes). EPA’s proposal and reasoning is detailed 

below.

In addition, EPA has identified some differences among the 

options in terms of cost effectiveness. Section XII of this 

preamble describes EPA’s cost-effectiveness analysis for the 

preferred regulatory options. EPA’s analysis to date shows that 

the average cost effectiveness ($1981/TWPE) under Option 3a, 3b, 

3, and 4a for existing direct dischargers is $27, $31, $44, and 

 

38 For Option 4a, for discharges of pollutants found in bottom ash transport 

water only, as explained previously, EPA is proposing to raise the value from 

less than or equal to 50 MW to less than or equal to 400 MW.

39 As described earlier in this section, EPA is proposing to exempt from new 

BAT copper and iron limitations existing discharges of nonchemical metal 

cleaning wastes that are currently authorized under their existing NPDES 

permit without iron and copper limits. For these discharges, BAT limits would 

be set equal to BPT limits for low volume waste.
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$57, respectively. This demonstrates that Option 3a is the most 

cost effective of the preferred options, Option 4a is the least 

cost effective of the preferred options, and Option 3 and Option 

3b are between the two. 

EPA also calculated the cost-effectiveness of particular 

controls for the wastestreams that would be controlled under the 

preferred options for existing direct dischargers40. The costeffectiveness for zero discharge of fly ash transport and FGMC 

wastewater, as in Option 3a, is $27 per TWPE removed. The cost 

effectiveness of chemical precipitation alone is $70 per TWPE 

removed, while the cost effectiveness of chemical precipitation 

plus anaerobic biological treatment, which is included in all 

options except Option 3a, is $60 per TWPE removed. The cost 

effectiveness of zero discharge of bottom ash transport water 

for all units more than 50 MW is $107 per TWPE. In comparison, 

when this requirement is applied only to units more than 400 MW, 

as in Option 4a, the cost effectiveness value is $99 per TWPE 

removed.

Thus, the cost effectiveness for control of the various 

wastestreams included within the preferred options ranges from 

$27-$107 per TWPE in $1981; with zero discharge controls on fly 

ash transport wastewater being the most cost-effective, zero 

 

40 While it is not included in the preferred options as a wastestream with 

additional controls, EPA also looked at the cost effectiveness of controlling 

leachate using chemical precipitation and this value would exceed $1,000 per 

TWPE removed.
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discharge controls on bottom ash transport wastewater being the 

least cost effective, and controls for FGD wastewater based on 

chemical precipitation in combination with anaerobic biological 

treatment between the two.

Effluent Limits for Oil-fired Generating Units. EPA is 

proposing to establish BAT limits equal to BPT for existing oilfired units. For the purpose of the proposed BAT effluent 

limits, oil-fired generating units would be those that use oil 

as either the primary or secondary fuel and do not burn coal or 

petroleum coke. Units that use oil only during startup or for 

flame stabilization would not be considered oil-fired generating 

units. EPA is proposing to set BAT limits equal to BPT for 

existing oil-fired units because, 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 

proposed ELGs.

The amount of ash generated at oil-fired units is a small 

fraction of the amount produced by coal-fired units. Coal-fired 

units generate hundreds or thousands of tons of ash each day, 

with some plants generating more than 1,500 tons per day of ash. 

In contrast, oil-fired units generate less than one ton of ash 

per day. This disparity is also apparent when comparing the ash 
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tonnage to the amount of power generated, with coal-fired units 

producing nearly 300 times more ash than oil-fired units (0.04 

tons per MW-hour on average for coal units; 0.000145 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 units discharge 

substantially less pollutants to surface waters than a coalfired unit even when generating the same amount of electricity. 

EPA estimates that if BAT effluent limits for oil-fired units 

were set equal to either the proposed Option 3 or Option 44a

limits for coal-fired units (>50 MW), the total industry 

pollutant reductions attributable to the proposed rule would 

increase by less than one percent.

Oil-fired 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. Only Based 

on responses to the industry survey, only 20 percent of oilfired units operate as baseload units; the rest are either 

cycling/intermediate units (45 percent) or peaking units (35 

percent). These units also have notably low capacity 

utilization. While a quarter of the baseload units report 

capacity utilization greater than 75 percent, most baseload 

units (60 percent) report a capacity utilization of less than 25 
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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 units operated for 

more than six months in 2009; nearly half of the units operated 

for less than 30 days. 

As shown above, oil-fired units are generally older and 

operate intermittently (i.e., they are peaking, cycling, or 

intermediate units). While these oil-fired units are capable of 

installing and operating the treatment technologies evaluated as 

part of this rulemaking, and the costs would be affordable for 

most of the plants, EPA believes that, due to the factors 

described here, companies may choose to shut down these oilfired units instead of making new investments to comply with the 

rule. If these units shut down, it could reduce the flexibility 

that grid operators have during peak demand because there would 

be 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 vital 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. Thus, the oil-fired generating units add 

substantially to electric grid reliability and the nation’s 

energy security.
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Based on responses to the industry survey, EPA estimates 

that less than 20 oil-fired units discharged fly ash or bottom 

ash transport water in 2009. At the same time, EPA notes that 

many oil-fired units operate infrequently, which could 

contribute to the relatively low numbers of units discharging 

ash-related wastewater. Should more widespread operation of oil 

units be required to meet demands of the electric grid, 

additional plants may find it necessary to discharge ash 

transport water. Because of the operating conditions unique to 

the existing fleet of oil-fired units and potential effects on 

the nation’s electric power grid, a non-water quality 

environmental impact that EPA considers under Section 304(b) of 

the CWA, EPA believes it is appropriate to set BAT effluent 

limits for oil-fired equal to the current BPT limits.

Effluent Limits for Small Generating Units. EPA is 

proposing to establish BAT effluent limits equal to BPT for 

existing small generating units, which would be defined as those 

units with a total nameplate generating capacity of 50 MW or 

less41. Small units are more likely to incur compliance costs 

that are disproportionately higher per amount of energy produced 

than those incurred by large units because they are not as able 

to take advantage of economies of scale. For example, the unit-

 

41 Preferred Option 4a would increase this threshold for purposes of 

discharges of pollutants in bottom ash transport water only, to 400 MW or 

less.
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level annualized cost for the proposed FGD wastewater treatment 

technology under OptionsOption 3 and 4 (chemical precipitation 

plus biological treatment) is approximately seven times more 

expensive on a dollar-per-megawatt basis for small generating 

units, relative to units larger than 50 MW. Similarly, the unitlevel annualized cost to convert the fly ash handling system to 

dry technology (conveyance equipment and intermediate storage 

silos) is more than four times more expensive on a dollar-permegawatt basis for small generating units, relative to units 

larger than 50 MW. Bottom For Option 4, bottom ash conversions 

are more than six times more expensive for small units, on a 

dollar-per-megawatt basis. 

Moreover, the record demonstrates that the amount of 

pollutants collectively discharged by small generating units is 

a very small portion of the pollutants discharged collectively 

for all steam electric power plants (i.e.g., less than 1 percent 

under both Option 3 and Option 4). As a result, setting BAT 

limits equal to BPT for existing steam electric generating units 

with a capacity of 50 MW or less will have little impact on the

pollutant removals for the overall rule. 

EPA considered establishing the size thresholds for small 

generating units at 25 MW because that threshold is already used 

for this industry sector in some regulatory contexts. For 

example, the Clean Air act defines an “electric utility 
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generating unit” as “any fossil fuel fired combustion unit of 

more than 25 megawatts that serves a generator that produces 

electricity for sale.” CAA Section 112(a)(8), 42 U.S.C. 

7412(a)(8). The existing ELGs for the steam electric power 

generating point source category also include different effluent 

limitations for plants with total rated generating capacity of 

less than 25 MW. See 40 CFR 423.13(c)(1) and 423.15(i)(1). 

EPA currently proposes a threshold of 50 MW42 rather than 25 

MW because the proposed 50 MW threshold would do more to 

alleviate potential impacts.43 EPA recognizes that any attempt to 

establish a size threshold for generating units will be 

imperfect due to individual differences across units and firms. 

However, EPA believes 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. EPA requests comment on the proposed 50 MW 

threshold applicable to discharges of the wastestreams described 

under each of the preferred options, and as well as other 

possible thresholds for small units.

 

42 For Option 4a, for bottom ash transport water only, as explained 

previously, EPA is proposing to raise the value from less than or equal to 50 

MW to less than or equal to 400 MW.

43 As discussed in Section XVII.C, the proposed 50 MW threshold also 

alleviates potential impacts which may be borne by small entities or 

municipalities.
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4. Rationale for the Proposed Best Available Demonstrated 

Control/NSPS Technology

Section 306 of the CWA directs EPA to promulgate New Source 

Performance Standards, or NSPS, “for the control of the 

discharge of pollutants which reflects the greatest degree of 

effluent reduction which the Administrator determines to be 

achievable through application of the best available 

demonstrated control technology, processes, operating methods, 

or other alternatives, including, where practicable, a standard 

permitting no discharge of pollutants.” Congress envisioned that 

new sources could meet tighter controls than existing sources 

because of the opportunity to incorporate the most efficient 

processes and treatment systems into the facility design. As a 

result, NSPS should represent the most stringent controls 

attainable through the application of the best available 

demonstrated control technology, or BADCT, for all pollutants 

(that is, conventional, nonconventional, and priority 

pollutants).

After considering all of the technology options described

above in Section VII.B.2, EPA is proposing to establish NSPS 

based on the suite of technologies identified for Option 4 in 

Table VIII-1. Thus, the proposed NSPS would do the following:

Establish numeric effluent limits for mercury, arsenic,

selenium, and nitrate-nitrite in discharges of FGD 

wastewater;
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Maintain the current “zero discharge” effluent limit for 

all pollutants in fly ash transport water, and establish 

new “zero discharge” effluent limits for all pollutants in

bottom ash transport water and FGMC wastewater;

Establish numeric effluent limits for mercury, arsenic, 

selenium, and TDS in discharges of gasification wastewater;

Establish numeric effluent limits for TSS, oil and grease, 

copper, and iron in discharges of nonchemical metal 

cleaning wastes; and

Establish numeric effluent limits for mercury and arsenic 

in discharges of leachate.

The record indicates that the proposed NSPS is 

technologically available and demonstrated. The technologies 

that serve as the basis for Option 4 are all available based on 

the performance of plants using components of the suite of 

technologies within the past decade. For example, approximately 

a third of plants that discharge FGD wastewater utilize chemical 

precipitation (in some cases, also using additional treatment 

steps). Five plants operate fixed-film anoxic/anaerobic 

biological treatment systems for the treatment of FGD wastewater

and another operates a suspended growth biological treatment 

system that targets removal of selenium.44 EPA is aware of 

industry concerns with the feasibility of biological treatment 

at some power plants. Specifically, industry has asserted that 

the efficacy of these systems is unpredictable, and is subject 

to temperature changes, high chloride concentrations, and high 

 

44 4Four of the 6six operate the biological treatment systems in combination 

with chemical precipitation. Other power plants are considering installing 

the biological treatment technology to remove selenium, and at least one 

plant is moving forward with construction.
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oxidation reduction potential in the absorber (that may kill the 

treatment bacteria). EPA’s record to date does not support these 

assertions, but is interested in additional information that 

addresses these concerns. Moreover, approximately 50 coal-fired 

generating units were built within the last 20 years and 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 Option 4 technologies being proposed today 

represent current industry practice for gasification wastewater.

Every IGCC power plant currently in operation uses vapor 

compression evaporation to treat the 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). Although not widely used by power plants 

to treat For leachate, as discussed above in Section VI, 

chemical precipitation is a well-demonstrated technology for 

removing metals and other pollutants from a variety of 

industrial wastewater, including leachate from other landfills 

not located at power plants. It therefore represents the 
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“greatest degree of effluent reduction...achievable” as that 

phrase is used in section 306 of the Clean Water Act.

The proposed NSPS for discharges of nonchemical metal 

cleaning waste are equal to the current BPT effluent limits that 

apply to discharges of these wastes from existing sources. As 

such, the proposed NSPS would be consistent with current 

industry practice for treating nonchemical metal cleaning waste 

and is based on the same technology that was used as the basis 

for the current NSPS for chemical metal cleaning waste. Based on 

responses to the industry survey, facilities typically treat 

both chemical and nonchemical metal cleaning waste in similar 

fashion.

The NSPS being proposed today also poses no barrier to 

entry. CostsThe cost to install technologies at new units are 

typically less than the cost to retrofit existing units. The For 

example, the cost differential between BAT Options 3 and 4 for 

existing sources is mostly associated with retrofitting controls 

for bottom ash handling systems. For existing generating units, 

the effluent requirements considered under Option 44a for BAT 

would cause those plants dischargingwith units greater than 400 

MW that discharge bottom ash wastewater to either modify their 

processes to become a closed-loop wet sluicing system, or 

retrofit modifications such as replacing the bottom of boilers 

to accommodate mechanical drag chain systems. For new sources, 
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however, Option 4 would not present plants with the same choice 

of retrofit versus modification of existing processes. This is 

because every new generating unit already has to install some 

type of bottom ash handling system as the unit is constructed. 

Establishing a zero discharge standard for 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. EPA 

estimates that over the past 20 years, more than 50 new coalfired generating units were built and that most of these units 

(83 percent) installed dry bottom ash handling systems.

Moreover, as described above in Section XI, EPA assessed 

the possible impacts of Option 4 to new units by comparing the 

costs of the Option 4 technologies to the costs of a new 

generating unit and as part of its Integrated Planning Model 

analyses. In both cases, the results show that the incremental 

costs that would be imposed by Option 4 do not present a barrier 

to entry. EPA estimated that the compliance costs for a new unit 

(capital and O&M) represent at most 1.5 percent of the 

annualized cost of building and operating a new 1,300 MW coalfired plant, with capital costs representing less than 1 percent 

of the overnight construction costs, and annual O&M costs 

representing less than 5 percent of the cost of operating a new 

plant. IPM results show no barrier to new generation capacity 
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during the model years in which all existing plants must be in 

compliance as a result of the BAT/NSPS compliance scenario. 

Finally, EPA has analyzed non-water quality environmental 

impacts associated with Option 4 for existing sources, and its 

analysis is relevant to the consideration of non-water quality 

environmental impacts associated with Option 4 for new sources. 

EPA’s analysis demonstrates that the non-water quality 

environmental impacts associated with Option 4 for existing 

sources are acceptable. Given that there is nothing inherent 

about a new unit that would alter the analysis for such sources, 

EPA believes that the non-water quality environmental impacts 

associated with the proposed NSPS regulatory option are, 

likewise, acceptable. 

In contrast to the best available technology economically 

achievable, or BAT, that EPA is proposing today for existing 

sources, the proposed NSPS would establish the same limits for 

oil-fired generating units and small generating units45 that are 

being proposed 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 trigger retrofit costs because the 

pollution controls (process operations or treatment technology) 

 

45 As a point of clarification, this similarly holds true for bottom ash 

limitations. 
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are installed at the time the new source is constructed. Thus, 

new sources are less likely than an existing source to 

experience financial stress by the cost of installing pollution 

controls, even if the pollution controls are identical. In 

addition, since the pollution controls would be installed at the 

time the new source is being constructed, a small new source 

generating unit is not expected to have disproportionately 

higher costs per generating capacity than a larger new source 

generating unit. EPA requests comment on its proposal to 

establish the same NSPS for small generating units as for larger 

units.

EPA didis not selectproposing regulatory Options 1 or 2, 

which would establish new effluent limits for only two of the 

seven key wastestreams addressed by this proposed rule, as its 

preferred option for NSPS. As explained above, neither of these 

two options represent the best available technology economically 

achievable (BAT) level of control, and therefore neither option 

represents the greatest degree of effluent reduction which the 

Administrator determines to be achievable through the best 

available demonstrated control technology to control the 

discharge of pollutants of concern from new sources.

EPA also did not select Option any of the preferred BAT 

regulatory Options (i.e., Options 3a, 3b, 3, or 4a) as its 

preferred option for NSPS because itthey would not control FGD 
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wastewater (Option 3a and Option 3b for units at plants with a 

total wet-scrubbed capacity of less than 2,000 MW), bottom ash 

transport water (Option 3a, Option 3b, Option 3, and Option 4a 

for units less than or equal to 400 MW) or leachate discharges

(Options 3a, 3b, 3, and 4a) and other, more effective, available 

technologies exist that do not present a barrier to entry and 

have acceptable non-water quality environmental impacts. 

UnderEPA did not select preferred Option 33a for the same 

reasons it rejected Options 1 and 2. EPA did not select Options 

3b, 3, or 4a because, under these regulatory options, NSPS 

effluent limits for bottom ash transport water for all or some 

portion of units and leachate would be set equal to the current 

NSPSBAT effluent limits on TSS and oil and grease, which are 

based on using surface impoundments. As described above for 

Option 4, the46. The record demonstrates that zero discharge 

technologies are effective and widely usedavailable for managing 

bottom ash at new sources. Since these zero discharge 

technologies have been installed at 83 percent of coal-fired 

units built in the last 20 years, effluent standards based on 

surface impoundments do not represent BADCTBest Available 

Demonstrated Control Technology to control the discharge of 

pollutants in the bottom ash wastestream from new sources.

regardless of the unit size. In addition, the record 

 

46 This rationale similarly applies to Option 3a.
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demonstrates that chemical precipitation is a more effective 

technology than surface impoundments for controlling the 

pollutants present in leachate. For these reasons, OptionOptions 

3b, 3 doesand 4a do not represent the best available 

demonstrated control technology to control the discharge of 

pollutants of concern from new sources.

EPA did not select Option 5 as its preferred option for 

NSPS because of its high costs, which are substantially higher 

than the costs for Option 4 and the other options evaluated for 

NSPS. See the TDD and RIA for more information about the 

estimated compliance costs for the NSPS options. Also, see 

Section XI below. The cost differential between Options 4 and 5 

is primarily due to the evaporation technology basis for 

controlling pollutants in FGD wastewater under Option 5.

Finally, EPA notes that Option 5 is comparable to Option 4 

with respect to much of the anticipated pollutant removals, 

particularly the expected removals of arsenic, mercury, selenium 

and nitrogen. At the same time, Option 5 would control other 

pollutants in FGD wastewater that Options 1 through 4 do not 

effectively control, namely boron, bromides, and TDS. EPA is 

aware that bromide in wastewater discharges from steam electric 

power plants located upstream from a drinking water intake has

been associated with the formation of trihalomethanes, also 

known as THMs, when it is exposed to disinfectant processes in 
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water treatment plants. EPA recommends that permitting 

authorities consider the potential for bromide discharges to 

adversely impact drinking water intakes when determining whether 

additional water quality-based effluent limits may be warranted.

Although EPA did not select Option 5 as the preferred NSPS 

option, the technologies forming the basis for Option 5 are all 

technologically available and may be appropriate (individually 

or in totality) as the basis for water quality-based effluent 

limits in individual or general permits depending on sitespecific conditions. EPA requests comment on its selection of 

Option 4 instead of Option 5 as the basis for NSPS.

5. Rationale for the Proposed PSES Technology

Section 307(b), 33 U.S.C. 1317(b), of the Clean Water Act 

requires EPA to promulgate pretreatment standards for pollutants 

that are not susceptible to treatment by POTWs or which would 

interfere with the operation of POTWs. EPA looks at a number of 

factors in selecting the technology basis for pretreatment 

standards. For existing sources, these factors are generally the 

same as those considered in establishing BAT. However, unlike 

direct dischargers whose wastewater will receive no further 

treatment once it leaves the facility, indirect dischargers send 

their wastewater to POTWs for further treatment. As such, EPA 

must also determine that a pollutant is not susceptible to 

treatment at a POTW or would interfere with POTW operations. 
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Table VIII-3 summarizes the pass through analysis results 

for the BAT/NSPS pollutants for the various wastestreams and 

regulatory options. As shown in the table, all of the pollutants 

proposed for regulation under BAT/NSPS pass through.

Table VIII-3. Summary of Pass Through Analysis Results

Treatment Option Pollutant Pass Through?

(Yes/No)

Chemical Precipitation for FGD 

Wastewater and/or Leachate

Arsenic Yes

Mercury Yes

Biological (chemical precipitation 

followed by anoxic/anaerobic 

biological) for FGD Wastewater 

and/or Leachate

Arsenic Yes

Mercury Yes

Nitrate Nitrite 

as N Yes

Selenium Yes

Mechanical Vapor-Compression 

Evaporation for FGD Wastewater 

Arsenic Yes

Mercury Yes

Selenium Yes

TDS Yes

Mechanical Vapor-Compression 

Evaporation for IGCC Wastewater 

Arsenic Yes

Mercury Yes

Selenium Yes

TDS Yes

Nonchemical Metal Cleaning Wastes Copper Yes

For today’s proposal, EPA evaluated the same model 

technologies and regulatory options for PSES that it evaluated 

for BAT (described in Section VIII.A.2). These standards would 

apply to existing generating units that discharge wastewater to 

POTWs.

As explained above in Section III.B.5, in selecting the 

PSES technology basis, the Agency generally considers the same 

factors as it considers when setting BAT, including economic 

achievability. Typically, the result is that the PSES technology 
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basis is the same as the BAT technology basis. Today’s proposal 

is no exception. After considering all of the technology options 

described in Section VIII.A.2, as is the case for BAT, EPA is 

proposing two preferred alternatives for PSES. Under one 

preferred alternative, EPA is proposing to establish PSES based 

on the technologies specified in Option 3. Under the second 

preferred alternative, EPA is proposing to establish PSES based 

on the technologies specified in Option 4four preferred 

alternatives for PSES (i.e., Options 3a, 3b, 3, and 4a). . With 

the exception of oil-fired generating units and small generating 

units (i.e., 50 MW or smaller), the proposed PSES under Option 3

would:

With the exception of oil-fired generating units and small 

generating units (i.e., 50 MW or smaller), the proposed rule 

under Option 3a would:

Establish a “zero discharge” effluent limit for all 

pollutants in fly ash transport water and FGMC wastewater;

Establish numeric effluent limits for mercury, arsenic, 

selenium, and TDS in discharges of gasification wastewater;

Establish numeric effluent limits for copper in discharges 

of nonchemical metal cleaning wastes47; and

Establish BAT effluent limits for bottom ash transport 

water and leachate that are equal to the current BPT 

 

47 As described in Section VIII.A.3, EPA is proposing to exempt from new BAT 

copper and iron effluent limits existing discharges of nonchemical metal 

cleaning wastes that are currently authorized by an NPDES permit without iron 

and copper limits. This exemption also applies to any indirect discharges of 

nonchemical metal cleaning waste that are authorized without copper 

pretreatment standards. For such indirect discharges, the regulation would 

not specify PSES.
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effluent limits for these discharges (i.e., numeric 

effluent limits for TSS and oil and grease)

With the exception of oil-fired generating units and small 

generating units (i.e., 50 MW or smaller), the proposed PSES 

under Option 3b would:

Establish standards for mercury, arsenic, selenium, and 

nitrate-nitrite in discharges of FGD wastewater for units 

located at plants with a total wet-scrubbed capacity of 

2,000 MW48;

Establish a “zero discharge” standard for all pollutants in 

fly ash transport water and FGMC wastewater; 

Establish standards for copper in discharges of nonchemical 

metal cleaning wastes; 49;and

Establish standards for mercury, arsenic, selenium and TDS 

in discharges of gasification wastewater.

Under the secondthird preferred alternative for PSES 

(Option 43), in addition to the requirements described for 

Option 3b, the proposed rule would establish the same standards

for mercury, arsenic, selenium, and nitrate-nitrite in 

discharges of FGD wastewater as for Option 3b from units at all 

steam electric facilities, with the exception of oil-fired 

generating units and small generating units (i.e., 50 MW or 

smaller).

 

48 Under Option 3b (for units located at plants with a total wet-scrubbed 

capacity of less than 2,000 MW), the regulations would not specify PSES for 

FGD wastewater, and POTWs would need to develop local limits to address the 

introduction of pollutants by steam electric power plants to the POTWs that 

cause pass through or interference, as specified in 40 C.F.R.403.5(c)(2).

49As described in Section VIII.A.3, EPA is proposing to exempt from new BAT 

copper and iron effluent limits existing discharges of nonchemical metal 

cleaning wastes that are currently authorized by an NPDES permit without iron 

and copper limits. This exemption also applies to any indirect discharges of 

nonchemical metal cleaning waste that are authorized without copper 

pretreatment standards. For such indirect discharges, the regulation would 

not specify PSES.

Formatted: Underline color: Auto

Formatted: Underline color: Auto
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Under the fourth preferred alternative for PSES (Option 

4a), the proposed rule would establish “zero discharge” effluent 

limits for all pollutants in bottom ash transport water and 

establish numeric effluent limits for mercury and arsenic in 

discharges of combustion residual leachatefor units greater than 

400 MW. All other proposed Option 44a requirements are identical 

to the proposed Option 3 requirements.

EPA is co-proposing these twoputting forth Options 3a, 3b, 

3, and 4a as the Agency’s preferred PSES regulatory options in 

order to confirm the Agency’sits understanding of the pros and 

cons of Options 3 and 4these options through the public comment 

process and intends to evaluate this information and how it 

relates to the factors specified in the CWA. For the same 

reasons identified in Section VIII.A.3 above for BAT, EPA has 

determinedEPA’s analysis to date suggests that for indirect 

dischargers as well as direct dischargers, the Option 3a, Option 

3b, Option 3, and Option 44a technologies are available and 

economically achievable, and that the other regulatory options 

(Options 1, 2, 4, and 5) do not reflect the criteria for PSES. 

In addition, EPA has determined that these standards will 

prevent pass-through of pollutants from POTWs into receiving 

streams and also help control contamination of POTW sludge. EPA 

also considered the non-water quality environmental impacts and 

found them to be acceptable, as described in sectionSection XV. 
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Furthermore, for the same reasons that apply to EPA’s preferred 

BAT options and described in Section VIII.A.3, with the 

exception of numeric standards for copper in discharges of 

nonchemical metal cleaning wastes50, EPA is proposing not to 

subject discharges from oil-fired generating units and small 

generating units (i.e., 50 MW or smaller51) to POTWs to 

requirements based on OptionOptions 3a, 3b, 3, or Option 44a. 

With the exception of numeric standards for copper in 

discharges of nonchemical metal cleaning wastes, EPA is 

proposing not to establish pretreatment standards for oil-fired 

generating units and small generating units. The reasoning for 

this is the same as EPA’s reasoning for proposing to set BAT 

limits equal to BPT limits for these wastestreams and particular 

units (i.e., numeric effluent limits for TSS and oil and 

grease). However, because POTWs are specifically designed to 

effectively treat conventional pollutants like TSS and oil and 

grease, there is no need to establish pretreatment standards for 

such pollutants. 

As is the case for BAT, EPA will continue to evaluate 

whether PSES should be based on Option 3 or Option 4, or 

alternatively, with certain elements of Option 4 added to Option 

 

50 EPA is proposing to exempt from new PSES copper standards for existing 

discharges of nonchemical metal cleaning wastes that are currently 

authorized. For these discharges, the regulation would not specify PSES.

51 Preferred Option 4a would increase this threshold for purposes of 

discharges of pollutants in bottom ash transport water only, to 400 MW or 

less.
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3 (e.g., Option 3 plus zero discharge for bottom ash transport 

water, or Option 3 plus numeric standards for leachate based on 

chemical precipitation). 

Finally, similar to EPA’s preferred BAT options and for the 

reasons supporting that optionthose options, for certain 

wastestreams, EPA is proposing that any new PSES discharge 

standards would apply to discharges of the regulated wastewater 

generated after July 1, 2017. See discussion in Section XVI.

6. Rationale for the Proposed PSNS Technology

Section 307(c) of the CWA, 33 U.S.C. 1317(c), authorizes

EPA to promulgate pretreatment standards for new sources (PSNS) 

at the same time it promulgates new source performance standards 

(NSPS). As is the case for PSES, PSNS are designed to prevent 

the discharge of any pollutant into a POTW that may interfere 

with, pass through, or may otherwise be incompatible with POTWs. 

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. As a result, 

EPA typically promulgates pretreatment standards for new sources 

based on best available demonstrated technology for new sources 

See National Ass'n of Metal Finishers v. EPA, 719 F.2d 624, 634

(3rd Cir. 1983). The legislative history explains that Congress 

required simultaneous establishment of new source standards and 

pretreatment standards for new sources for two reasons. First, 
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Congress wanted to ensure that any new source industrial user 

achieve the highest degree of internal effluent controls 

necessary to ensure that such user's contribution to the POTW 

would not cause a violation of the POTW's permit. Second, 

Congress wished to eliminate from the new user’s discharge any 

pollutant that would pass through, interfere, or was otherwise 

incompatible with POTW operations.

For today’s proposal, EPA evaluated the same model 

technologies and regulatory options for PSNS that it evaluated 

for NSPS (described above in Section VIII.A.4). These standards 

would apply to new generating units or new facilities that 

discharge wastewater to POTWs. After considering all of the 

technology options described in Section VIII.A.2, as is the case 

for NSPS, EPA is proposing to establish PSNS based on the 

technologies specified in Option 4. The proposed PSNS would:

Establish standards for mercury, arsenic, selenium, and 

nitrate-nitrite in discharges of FGD wastewater;

EstablishMaintain a “zero discharge” standard for all 

pollutants in fly ash transport water, and establish a zero 

discharge standard for bottom ash transport water, and FGMC 

wastewater;

Establish standards for mercury, arsenic, selenium and TDS 

in discharges of gasification wastewater;

Establish standards for copper in discharges of nonchemical 

metal cleaning wastes; and

Establish standards for mercury and arsenic in discharges 

of leachate. 
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For the same reasons identified for NSPS in Section 

VIII.A.4, EPA is proposing Option 4 as its preferred option 

because the technologies forming the basis for that option are

available and demonstrated and will not pose a barrier to 

entry.

52 In addition, EPA has determined that these standards 

will prevent pass-through of pollutants from POTWs into 

receiving streams and also help control contamination of POTW 

sludge. EPA also considered the non-water quality environmental 

impacts associated with the preferred option and found them to 

be acceptable, as described in Section XV.

7. Consideration of Future FGD Installations on the Analyses for 

the ELG Rulemaking

As explained earlier, implementation of air pollution 

controls may create new wastewater streams at power plants. The 

analyses and the findings on economic achievability presented in 

this preamble reflect consideration of wastestreams generated by 

air pollution controls that will likely be in operation at 

plants at the time EPA takes final action on this rulemaking. 

However, EPA recognizes that some recently promulgated Clean Air 

Act requirements, along with state requirements or enforcement 

actions, may lead to additional air pollution controls (and 

resulting wastestreams) at existing plants beyond this date. In 

 

52 For the same reasons discussed above in Section VIII for NSPS, EPA 

similarly determined the other regulatory options do not reflect PSNS.
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an effort to assess the economic achievability of the proposed 

rule in such cases, EPA also conducted a sensitivity analysis 

that forecasts future installations of air controls through 

202053 and the associated costs of complying with today’s 

proposed regulatory requirements for the wastewater that may 

result from the forecasted air control installations. The 

sensitivity analysis and results are described in more detail in 

DCN SE01989.

EPA has two primary data sources upon which to make its 

predictionsprojections of future air control installations: 1) 

Integrated Planning Model predictionsestimates for the final 

MATS rule54; and 2) responses to EPA’s steam electric industry 

survey. At the time EPA promulgated the MATS rule in 2011, it

projected air pollution control retrofits fromusing IPM modeling

(which also included projected retrofits for CSAPR). To support 

this rulemaking, EPA surveyed the industry about its plans for 

installing certain new air pollution controls at facilities 

through 2020. EPA has no reason to conclude that either the IPM 

FGD predictionsprojections or the survey predictionsprojections

are more accurate than the other. In fact, both of these sources 

may overstate actual installations. Prior to MATS becoming 

 

53 EPA considers that by forecasting future installations of controls out to 

the year 2020, the sensitivity analyses for this rulemaking reasonably 

reflect full implementation of air pollution controls to comply with existing 

federal and state requirements.

5454 EPA IPM v.4.10 predictionsprojections for units based on compliance with 

CSAPR, MATS, state rules, and enforcement actions including consent decrees.
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final, many plant owners and operators assumed that wet 

scrubbers would be the only technology available to meet 

emissions limits for acid gases. As EPA gathered and published 

additional data on facility emission rates (which informed how 

the Agency set the standards), and as stakeholders researched 

and published additional information on the performance of less 

capital-intensive control technologies such as dry sorbent 

injection, it has become clear that many facilities will find it 

more cost-effective to forgo wet scrubbers in favor of other 

emission-reduction strategies. Furthermore, major economic 

variables such as electricity demand and natural gas prices have 

changed substantially since the prevailing market conditions in 

2010, when respondents were answering the survey. For example, a 

facility originally indicating an expectation in the industry

survey to install a wet scrubber by 2020 may now find itself no 

longer competitive in the updated marketplace with substantially 

lower natural gas prices and lower electricity demand growth 

than previously expected. Consequently, the facility may elect 

to retire and thereby neutralize the previously reported intent 

to scrub. Nevertheless, these two sources remain the best 

available information EPA has with which to estimate future 

predictionsconditions. 

As a first step in conducting a sensitivity analysis, EPA 

compared the predictionsprojections from the two sources 
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described above. This comparison demonstrates that the IPM 

predictionsresults for the MATS Policy Case and the ELG industry 

survey responses are consistent at the aggregate level. 

Furthermore, in very large part, both the survey and IPM 

identify the same generating units as being wet -scrubbed, 

either currently or in the future (the two sources are in 

agreement for approximately 94 percent of the wet -scrubbed

units). The two sources also predictproject similar wet-scrubbed 

capacities. In the very few cases where there are differences 

between the two sources, the differences are primarily due to 

the expected variation at a unit-level (e.g., IPM model 

predictsprojects wet FGD at unit A and dry FGD at unit B, but 

instead the survey responses report wet FGD at unit B and dry 

FGD at unit A). Another difference between the MATS IPM 

estimates and the industry survey estimates is that, in a very 

few cases, the IPM results predictestimate that certain plants 

would retire (and therefore would not install wet scrubbers). In 

conducting the analyses for the ELG, EPA made the conservative

assumption (i.e., one that would tend to overestimate cost, if 

anything) that a plant would still be in operation in 2020 

unless the plant has formally announced its closure by 2014.

Because its goal in conducting this sensitivity analysis 

was to assess the economic achievability of the proposed ELG, 

even in light of possible future air controls, EPA developed a 
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conservative upper bound estimate of future installations by 

combining the results of the two sources to develop its “future 

steam profile.” In other words, EPA combined any source that 

reported or projected a wet FGD into one “future steam profile.” 

This “future steam profile” is conservative because it reflects 

more wet FGDs than are anticipated to actually be installed; 

that is, by aggregating the survey and IPM forecast estimates it 

results in a total number of wet FGD systems and wet-scrubbed 

capacity that is greater than either of those individual 

sources. EPA then added costs associated with projected 

wastewater discharges from this future steam profile to comply 

with today’s proposal to the total costs it previously 

calculated for the existing universe. Based on the results of 

this conservative analysis, EPA finds that discharges from these 

additional air controls (which, if actually installed, would be 

due to various requirements including state rules, consent 

decrees, CSAPR/CAIR, and MATS) may increase the costs of today’s 

proposed rule by no more than 10 to 15 percent. See discussion 

in Section VII.A.7. Even if all of these additional costs were 

to come to fruition, which is unlikely since the “future steam 

profile” overestimates the number of new wet FGD systems that 

are anticipated, EPA finds that these additional costs are 

economically achievable for Options 3 and 4..
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EPA notes that subsequent to its analysis, the D.C. Circuit 

Court of Appeals vacated the CSAPR. EPA will continue to assess 

the potential impacts that changes to air pollution regulations 

may have on future installations of wet FGD systems. For the 

purpose of FGD wastewater analyses for this rulemaking, EPA has 

made a conservative assumption that all of the previously 

projected wet scrubber additions in the CSAPR-inclusive baseline 

(which also included MATS, state rules, consent decrees, etc.) 

would continue to be built, and that discharges from those 

additional wet scrubbers would therefore be subject to the 

proposed revisions to the ELGs.

8. Consideration of the Proposed CCR Rule on the Analyses for 

the ELG Rulemaking

EPA conducted a series of sensitivity analyses to assess 

how the actions taken by the industry to comply with any CCR 

rule (assuming it is promulgated before the Agency takes final 

action on this ELG rulemaking) might affect the costs, pollutant 

reductions, economic and environmental/non-water quality

environmental impacts, and monetized benefits associated with 

the proposed ELG. As mentioned above in Section III.G, on June 

21, 2010, EPA co-proposed regulations under RCRA to regulate CCR 

generated from coal-fired power plants (75 FR 35128). This 

proposed rule, referred to in this preamble as the “CCR rule,” 

laid out two approaches for managing CCR wastes that are 
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disposed of: one would regulate CCR under RCRA Subtitle C as 

“special wastes,” while the other would regulate CCR under RCRA 

Subtitle D as non-hazardous wastes.

55 These two approaches differ 

significantly in how they would likely affect the operation of 

surface impoundments, and thus would likely affect the way steam 

electric power plants manage CCR in the future. In particular, 

the proposed CCR rule includes regulatory options that likely 

would result in the closure of some or all surface impoundments 

containing CCR. These changes in operations could alter the

expected incremental compliance costs and pollutant reductions 

(as well as other related analyses, such as economic and 

environmental impacts) attributable to any final action taken in

this ELG rulemaking.

EPA chose to conduct sensitivity analyses (consistent with 

the two approaches EPA proposed under RCRA) to better understand 

the effects of these operational changes because the CCR rule 

has not been promulgated in final form and, therefore, it cannot 

be factored with confidence into many of the analyses for the 

proposed ELGs. The sensitivity analyses are supplemental to the 

primary analyses discussed in today’s notice (including costs, 

loads, benefits, impacts, etc.), which reflect current, baseline 

conditions, and do not factor in the operational changes likely 

 

55 In both approaches, EPA proposed to retain the Bevill exemption for CCRs 

that are beneficially used.
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to occur under any final CCR rule. Depending on the option 

selected for any final CCR rule, EPA expects that some plants 

may take actions to transform their operations, such as 

converting to dry ash handling systems and closing surface 

impoundments in order to comply with such a CCR rule. Therefore, 

to better inform this rulemaking concerning the effects of any 

final CCR rule that might be promulgated prior to the selection 

of a final action in this ELG rulemaking, EPA has assessed the 

possible effects of a CCR rule as though it were finalized under 

various scenarios.

Changes that plants would be likely to make to comply with 

a final CCR rule can directly affect what the plants would be 

likely to do to comply with any revised ELG requirements. For 

example, plants that would elect to close impoundments 

containing fly ash in response to any final CCR rule would

likely convert an existing wet-sluicing ash handling system to 

one that is dry. Instead of pumping the fly ash to surface 

impoundments using large volumes of water, the plant would 

likely convert to a pneumatic system that uses air to transport 

the fly ash to temporary storage in a silo, and then either haul 

the ash off-site for beneficial use, or to on-site or off-site 

landfills for disposal. In cases such as this, when the plant 

converts to a dry fly ash handling system and stops using water 

to transport the ash, it would stop discharging fly ash 
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transport wastewater. If a plant were to elect to comply with a 

possible CCR rule in this way, it would also meet the “zero 

discharge” requirements for fly ash discussed in today’s 

proposal under Options 3, 4, and 5, as it will have no 

discharge. As a result, the plant would not incur any 

incremental costs associated with those particular proposed

regulatory options. EPA expects a similar situation to occur if 

a plant elects to close an impoundment containing bottom ash in 

response to any final CCR rule, although depending on the 

specific modifications a plant makes to comply with the CCR 

rule, the plant may continue to discharge bottom ash wastewater. 

Should it continue to discharge bottom ash transport wastewater

after complying with any final CCR rule, then the plant might

still incur additional costs to comply with a possible final ELG 

rule that includes bottom ash wastewater requirements (i.e.,

Options 4 and 5 discussed in today’s notice). However, if the 

bottom ash wastewater discharge ceased in response to the 

requirements of any CCR rule, then the plant would incur no 

additional cost to control the bottom ash wastestream, as could 

be required in any final ELG rule.

In addition to modifications that plants might make to 

their fly ash and bottom ash wastewater handling operations in 

response to any CCR rule, plants might also modify their FGD 

wastewater treatment systems to comply with the CCR rule. For 
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example, if a plant closes an impoundment that receives FGD 

wastes as a result of requirements under the CCR rule, EPA 

anticipates that the plant would continue to discharge FGD 

wastewater as it purges certain contaminants from the FGD 

absorber. In the absence of new effluent requirements under the 

ELG, EPA expects that the plant would install a tank-based 

treatment system that is designed, at a minimum, to remove 

suspended solids to comply with the existing ELG as incorporated 

in its NPDES permit effluent limits (which contain, at a 

minimum, TSS and oil and grease limits based on the current 

BPT). This replacement FGD treatment system that may be 

installed to meet possible CCR rule requirements would likely 

not be sufficient to meet today’s proposed ELG requirements. At 

the same time, however, it would include certain components 

(e.g., tanks, clarifiers, pumps) that could be used as part of 

the treatment systems included in the technology basis for the 

ELG options discussed in this proposed rule.

EPA’s sensitivity analyses focused on how the two proposed 

approaches for the CCR rule might affect the analyses conducted 

for this proposed ELG rulemaking under regulatory Options 3 and

4. Depending on the extent to which a final CCR rule ensures 

control of wastewater discharges for which EPA is proposing 

limitations and standards in this ELG rulemaking, the Agency may 

assess the appropriateness of promulgating other, possibly 
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narrower options such as Option 2, or a more stringent option 

such as Option 5, for the ELG.

For the sensitivity analyses, EPA first evaluated, under 

the two proposed approaches for the CCR rule, whether the 

surface impoundments operated by each ELG plant would likely 

continue operating, retrofit with a composite liner, or close. 

EPA then used these results to set a new baseline, if 

appropriate, to estimate incremental compliance costs associated 

with the technology options for fly ash, bottom ash, FGD 

wastewater, and leachate. Based on this assessment, EPA 

identified plants where costs attributable to the ELG would be 

eliminated or reduced due to actions taken to comply with a 

hypothetical final CCR rule. EPA used a similar methodology to 

assess how pollutant removals attributable to the proposed ELG 

rule might change in light of the two proposed approaches for 

the CCR rule. The Agency then used these revised incremental 

costs and pollutant removals as new data points in analyses for

this ELG rulemaking, including the economic impact analyses, 

pollutant reductions, environmental assessment analyses, and 

estimates of monetized benefits for BAT Options 3 and 4. A full 

description of the sensitivity analyses, including the 

methodology, data sources, and results, is presented in DCN 

SE02123. 
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The results of the sensitivity analyses show that, as 

expected, a CCR rule finalized under one of the two proposed 

regulatory approaches would have an associated effect on the 

pollutant reductions expected from the proposed ELG, as well as 

associated annualized costs to industry. First, the sensitivity 

analyses demonstrate that, if a CCR rule that would direct that 

all surface impoundments be closed were to be finalized before 

EPA takes final action on the ELG, the CCR rule would 

significantly reduce, or possibly eliminate nearly all, 

wastewater discharges associated with fly ash transport water. A 

CCR rule that requires all CCR surface impoundments to close may 

also produce substantial reductions in, but not eliminate a 

significant percentage of, discharges of bottom ash transport 

water. By contrast, a CCR rule that closes all surface 

impoundments would have little to no effect on discharges of the 

other wastestreams, including the FGD wastestreams. In 

particular, EPA estimates that the net effect of closing all CCR 

surface impoundments on the baseline pollutant toxic weighted 

pollutant loading from the industry would be a reduction of 

about 63 percent. In addition, if all surface impoundments were 

closed, the analyses also show that the total estimated annual 

costs of Option 3 would be reduced by about 51 percent and the 

pollutant loading reductions (in toxic weighted pounds) to 

surface waters would be reduced by about 49 percent. The total 
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estimated annual costs of regulatory Option 4 would be reduced 

by 73 percent and the pollutant loading reductions to surface 

waters would be reduced by about 66 percent.

The sensitivity analyses also demonstrate that, if the CCR 

rule were to be finalized before EPA takes final action on the 

ELG, an approach that directed that only certain surface 

impoundments must close or retrofit would provide some reduction 

in wastewater discharges, primarily fly ash and bottom ash, but 

would have little to no effect on discharges of the other 

wastestreams (e.g., FGD wastewater, FGMC wastewater, 

gasification water, and leachate). Because of the compliance 

choice given to facilities that have surface impoundments, and 

because the way that individual facilities will make their 

compliance choice is not known and cannot be estimated with 

confidence, EPA used an upper and lower bound estimate of 

impoundment closures in the sensitivity analyses. As a result, 

EPA estimates that the net effect on the baseline pollutant 

toxic weighted pollutant loading discharges would be a reduction 

in the range of 23 to 42 percent. Taking into account these 

reductions, the analyses demonstrate that, after implementation, 

the industry would continue to discharge significant quantities 

of pollutants from all wastestreams. Moreover, the analyses show 

that the total estimated annualized costs of Option 3 would be 

reduced by about 24 to 34 percent, and the pollutant loading
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reductions (in toxic weighted pounds) to surface waters would be 

reduced by about 31 to 40 percent. The total estimated annual 

costs of regulatory Option 4 would be reduced by about 39 to 55

percent and the pollutant loading reductions to surface waters 

would be reduced by about 24 to 34 percent.

If the CCR rule is promulgated before EPA takes final 

action on this ELG, EPA plans to revise its analyses of costs, 

pollutant reductions, economic impacts, environmental impacts, 

and non-water quality environmental impacts as appropriate to 

inform the option selected for this rule.

B. Timing of New Requirements

As part of its consideration of technological availability 

and economic achievability, EPA considered the magnitude and 

complexity of process changes and new equipment installations 

that would be required at many existing facilities to meet the 

requirements of the rule. As discussed in Section VIII.A.2, EPA 

proposes that certain BAT limitations and standards for existing 

sources being proposed today (those that would establish 

requirements more stringent than existing BPT requirements) 

would apply on a date determined by the permitting authority 

that is as soon as possible when the next permit is issued 

beginning July 1, 2017 (approximately three years from the 

effective date of this rule). This is true of the proposed 

limitations and standards based on any of the fiveeight main 
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regulatory options, including the preferred options, Option 3a, 

Option 3b, Option 3, or Option 4) would apply on July 1, 2017 

(approximately three years from the effective date of this 

rule). 4a.

EPA is proposing this approach for several practical 

reasons. While some facilities already have the necessary 

equipment and processes in place, or could do so relatively 

quickly, and may need little time before they are able to comply 

with the revised ELG requirements, not all will be able to do 

so. Some facilities will need time to raise the capital, plan 

and design the system, procure equipment, construct and then 

test the system. Moreover, providing a window of time will 

better enable facilities to install the pollution control 

technology during an otherwise planned shutdown or maintenance 

period. In some cases, a facility must apply for permission to 

enter into such a period where they are producing no or less 

power. 

During site visits, EPA found that most facilities need 

several years to plan, design, contract, and install major 

system modifications, especially if they are to be accomplished 

during planned maintenance periods to avoid causing forced 

outages. EPA recognizes that the proposed rule would require a 

significant amount of system design by engineering firms, 

equipment procurement from vendors, and installation by trained 
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labor forces. EPA anticipates that changes to FGD wastewater 

treatment systems, fly ash system, bottom ash systems, and/or

leachate treatment systems would constitute major system 

modifications requiring several years to accomplish for many 

plants. EPA identified certain technical and logistical issues 

at some facilities that may warrant additional time, such as 

coordinating ash system conversions for multiple generating 

units. In order to avoid any impacts on the consistency and 

reliability of power generation, outages at multiple facilities 

in one geographic area would need to be coordinated, which could 

also result in the need for more time.

EPA recognizes that permitting authorities have discretion 

with respect to when to reissue permits and can take into 

consideration the need to provide additional time to include BAT 

limits to prevent or minimize forced outages. Thus, in some 

cases, the new BAT requirements may as a practical matter be 

applied to a facility sometime after July 1, 2017. However, EPA 

judges that, under today's proposed approach, all steam electric 

facilities will have the proposed BAT limitations applied to 

their permits no later than July 1, 2022, approximately 8 years 

from the date of promulgation of any final ELGs. For indirect 

discharges, except with respect to discharges of nonchemical 

metal cleaning waste, the proposed PSES requirements would apply 

onby the date determined by the control authority that is as 
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soon as possible beginning July 1, 2017, or approximately three 

years after promulgation of any final ELGs.

EPA's record indicates it may not take that long for all 

facilities to meet the limitations and standards. Some plants 

may not require a major modification for one or more systems to 

be able to comply with new effluent limits and therefore would 

need less time. For example, some plants have installed dry fly 

ash handling systems that have capacity to handle all generated 

ash dry, yet they also maintain a wet ash handling system as a 

backup. The backup wet system is typically operated only a few 

days per year. According to the industry survey, plants such as 

these could easily and quickly cease operation of the wet 

system, complying with a zero discharge requirement with 

relative ease. 

EPA envisions that each facility subject to today’s 

proposal would study available technologies and operational 

measures, and subsequently install, incorporate and optimize the 

technology most appropriate for each site. EPA believes the 

proposed rule affords flexibility for a reasonable amount of 

time to conduct engineering studies, assess and select 

appropriate technologies, apply for necessary permits, complete 

construction, and optimize the technologies’ performance. The 
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permitting authority could establish any additional interim 

milestones, as appropriate, within these timelines.

IX. Technology Costs and Pollutant Reductions

This section provides an overview of EPA’s approach for 

estimating the compliance costs and pollutant reductions 

associated with the regulatory options discussed in today’s 

proposal. Sections 9 and 10 of the TDD provide a much more in 

depth discussion of these analyses.

EPA often estimates costs and pollutant loads on a per 

plant basis and then sums or otherwise escalates the plantspecific values to represent industry-wide compliance costs and 

pollutant reductions. Calculating costs and loads on a per plant 

basis allows EPA to account for differences in plant 

characteristics such as types of processes used, wastewaters 

generated and their flows/volumes and characteristics, and 

wastewater controls in place (e.g., BMPs and end-of-pipe 

treatment). EPA took this approach in estimating the compliance 

costs and pollutant reductions associated with today’s proposed 

rule.

EPA estimated the costs to steam electric power plants –

whose primary business is electric power generation or related 

electric power services – of complying with the proposed ELGs. 

EPA evaluated the costs of today’s proposal on all plants 

currently subject to the existing ELGs. Some aspects of today’s 
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proposal (e.g., applicability changes) would likely not lead to 

increased costs to complying facilities. Other aspects of 

today’s proposal would likely lead to increased costs to a 

subset of complying facilities. These facilities are generally 

those that generate and discharge the wastestreams for which EPA 

is proposing new limitations or standards. EPA reviewed the 

steam electric industry for all facilities that generate the 

specific types of wastewater streams for which EPA evaluated 

additional limitations or standards. The following describes the 

detailed costing and loadings evaluation EPA performed for these 

plants. 

As discussed earlier in this preamble, EPA proposes to 

establish a separate set of requirements for existing oil-fired 

generating units and units with a capacity of 50 MW or less. For 

these units, EPA is proposing to establish BAT limitations that 

would be set equal to BPT limitations. Since today’s proposed 

rule would not establish additional control on discharges 

associated with these operations, there would be no incremental 

costs for these units to comply with the requirements of this 

proposed rule.56

 

56 EPA did estimate costs for these existing oil-fired generating units and 

small generating units to comply with the options considered in this 

rulemaking and has included those estimates in the docket for the proposed 

rule (see DCN SE01957, Incremental Costs and Pollutant Removals for Proposed 

Effluent Limitations Guidelines and Standards for the Steam Electric 

Generating Point Source Category).
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For the aspects of today’s proposed regulatory options that 

include additional limitations and standards for additional 

pollutants, EPA estimated compliance costs and pollutant 

reductions from data collected through survey responses, site 

visits, sampling episodes, and from individual power plants and 

equipment vendors. EPA used this information to develop 

computerized cost and pollutant loadings models for each of the 

technologies that form the basis of the regulatory options. EPA 

used these models to calculate facility-specific compliance 

costs and pollutant reductions for all power plants that the 

information suggests may incur costs to comply with one or more 

proposed limitations or standards associated with the regulatory 

options.57,58 Therefore, EPA’s plant-specific cost and pollutant 

 

57 Because EPA anticipates taking final action on this rulemaking in 2014, EPA 

did not include plants that are expected to retire by 2014 and plants that do 

not discharge any of the applicable wastestreams. Since this timeframe is 

approximately one year following the date of the proposed rule, EPA considers 

there to be sufficient certainty regarding plant/unit retirements or relevant 

major system modifications for it to be reasonable for EPA to take into 

account in the regulatory analyses for this rulemaking, Retirements and 

modifications occurring farther into the future than 2014 become more 

speculativeuncertain and subject to change; thus, EPA has considered such 

future changes, as appropriate, in sensitivity analyses for this rulemaking. 

proposed rule. However, this approach can result in estimating compliance 

costs for generating units that companies have announced will retire, 

repower, or convert from wet to dry ash handling. Because of this, EPA is 

considering using alternative dates, such as 2022 which may better reflect 

the implementation timeframe for the ELG, for the baseline year for its 

analyses for the final rule.

58 EPA is considering establishing BMPs that would apply to surface 

impoundments that receive, store, dispose of, or are otherwise used to manage 

coal combustion residuals including FGD wastes, fly ash, bottom ash (which 

includes boiler slag), leachate, and other residuals associated with the 

combustion of coal to prevent uncontrolled discharges from these 

impoundments. Costs for the industry to implement the BMPs under 

consideration are included in EPA’s cost and economic analyses for the 

proposed rule.
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reduction estimates represent the incremental costs/pollutant 

reductions for a plant when its existing practices would not 

lead to compliance with the option being evaluated for the 

proposed rule. While plants would not be required to implement 

the specific technologies that form the basis for the proposed 

limitations and standards for each of the regulatory options, 

EPA calculated the cost and associated pollutant reductions for 

plants to implement these technologies to estimate the 

compliance costs and pollutant loading reductions associated 

with EPA’s proposed rule. 

EPA’s cost estimates include two key cost components: 

capital costs (one-time costs) and operating and maintenance 

(O&M) costs (which are incurred every year). Capital costs 

comprise the direct and indirect costs associated with the 

purchase, delivery, and installation of pollution control 

technologies. Capital cost elements are specific to the industry 

and commonly include purchased equipment and freight, equipment 

installation, buildings, land, site preparation, engineering 

costs, construction expenses, contractor’s fees, and 

contingency. Annual O&M costs comprise all costs related to 

operating and maintaining the pollution control technologies or 

performing BMPs for a period of one year. O&M costs are also 

specific to the industry and commonly include costs associated 

with operating labor, maintenance labor, maintenance materials 
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(routine replacement of equipment due to wear and tear), 

chemical purchase, energy requirements, residual disposal, and 

compliance monitoring. In some cases, the technology options may 

also result in recurring costs that are incurred less frequently 

than annually (e.g., 3-year recurring costs) or one-time costs 

other than capital investment (e.g., one-time engineering 

costs).

A. Methodology for Estimating Plant-Specific Costs

The limitations and standards associated with the 

regulatory options for today’s proposed rule address various 

wastestreams and, as such, consist of multiple technology bases 

(see Table IX-1). As a first step in estimating costs to control 

discharges associated with a particular generating unit at an 

existing steam electric power plant subject to this rulemaking 

(i.e., existing sources), EPA used the plant’s survey response 

to determine if the wastestreams it discharges may be affected 

by the limitations and standards for the regulatory options 

considered in this rulemaking. Then, for each of the 

wastestreams that may be affected by an option, EPA reviewed the

industry survey response, available sampling data, and industry 

long-term self-monitoring data to determine if the plant 

currently meets the performance level of the technology basis 

for the requirement of an option for that wastestream. A portion 

of the steam electric industry has already implemented processes 
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or treatment technologies that serve as the basis for the 

regulatory options considered for the proposed rule; as a 

result, these facilities would not incur costs to comply with 

the proposed rule, or would incur costs lower than they would be 

if the processes/technologies had not already been implemented.

In such cases, EPA assigned no compliance cost associated with 

the discharge of that particular wastestream other than 

compliance monitoring costs. For all other applicable 

wastestreams, EPA assessed the operations and treatment system 

components in place at the plant, identified necessary 

components that the plant would need to come into compliance, 

and estimated the cost to install and operate those components. 

Table IX-2 presents a list of the major cost components included 

in the evaluation. As appropriate, EPA also accounted for 

expected reductions in the plant’s costs associated with their 

current operations or treatment systems that would no longer be 

needed as a result of installing and operating the technology 

bases (e.g., avoided costs to manage surface impoundments). For 

plants that may already have certain components installed, EPA 

compared certain key operating characteristics, such as chemical 

addition rates, to determine if additional costs (e.g., chemical 

costs) were warranted. 
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Table IX-1. Technology Cost Modules Used to Estimate Compliance 

Costs

Wastestream

Technology Cost 

Modules

Regulatory Option

1 3a 2 13b 2

3

34a 4 5

FGD Wastewater

Chemical 

Precipitation X X X X X X X

Biological 

Treatment X X X X X

VaporCompression 

Evaporation X

Fly Ash 

Transport Water

Dry Fly Ash 

Handling X X X X X

Bottom Ash 

Transport Water

Dry Bottom Ash 

Handling X X X

Leachate Chemical 

Precipitation X X

Gasification 

Wastewater

VaporCompression 

Evaporation X X X X X X X

Flue Gas 

Mercury Control 

Wastes Dry Handling X X X X X

Other Plant-Level Costs

Solids 

Transportation X X X X X X X X

Solids Disposal X X X X X X X X

Impoundments X X X X X X X X

Compliance 

Monitoring X X X X X X X X

Table IX-2. Major Capital Cost Components Included in Compliance 

Costs

Technology Module Major Capital Cost Components

Chemical Precipitation Equalization tank;

Reaction tanks;

Chemical feed systems;

Solids contact clarifier;

Sand filters;

Treated wastewater tank;

Sludge filter press; and

Sludge holding tank.

Biological Treatment BioreatorBioreactor tanks;

Nutrient feed system and storage;

Formatted Table

Inserted Cells

Inserted Cells

Inserted Cells

Inserted Cells

Inserted Cells

Inserted Cells
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Table IX-2. Major Capital Cost Components Included in Compliance 

Costs

Technology Module Major Capital Cost Components

Backwash system and backwash wastewater 

tank; and

Heat exchangers (if needed).

Vapor-Compression 

Evaporation

Water softener;

Brine concentrator; and

Forced-circulation crystallizer.

Conversion of Wet Fly 

Ash Handling to Dry 

Vacuum Fly Ash Handling

Conveyance Vacuum Line Components (i.e., 

valves, piping, couplings);

Filter-Receiver;

Vacuum Pumps;

Lot miscellaneous instrumentation and 

control;

Steel or concrete silo;

Silo Instrumentation and Aeration System; 

and

Pugmill unloaders.

Conversion of Wet 

Bottom Ash Handling to 

Mechanical Drag System 

(MDS) or Remote MDS

Water bath trough;

Chain conveyor;

Inclined conveyor;

Storage silo;

Remote MDS only: collection sump, chemical 

feed system, and recirculation pumps.

Transportation Only operating and maintenance cost 

components

Disposal On-Site Disposal:

Landfill expansion construction

Leachate treatment system 

Groundwater wells 

Closure cap

Off-Site Disposal: no capital cost 

components

Compliance Monitoring Only operating and maintenance cost 

components

For example, to comply with BAT regulatory Option 4

presented in today’s proposal, EPA estimated compliance costs 

for a plant that currently sluices fly ash to an ash impoundment 

and subsequently discharges that fly ash transport water. In 

this case, EPA estimated the cost for the plant to convert its 
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fly ash handling system to a dry vacuum system and assumed that 

certain components of its existing system would continue to be 

used following the conversion.59 EPA also included costs for 

additional equipment, such as vacuum systems and silos, to 

handle and store the dry fly ash. EPA also included additional 

transportation and landfill disposal costs and cost savings for 

managing less waste through the ash impoundment(s). 

As another example, EPA estimated compliance costs to 

comply with BAT regulatory Option 4 for a plant that currently 

treats its FGD wastewater through a chemical precipitation 

system prior to discharge. In this case, EPA evaluated 1) 

whether the chemical precipitation system design basis included

equalization with 24-hour residence time, 2) if the plant had an 

equivalent number and/or type of reaction tanks, and 3) if the 

plant already had components such as chemical feed systems, 

solids contact clarification, sand filtration, effluent and 

sludge holding tanks, sludge filter press, and pumps in place. 

If the plant had any of these components in place, EPA did not 

include that cost in its compliance cost estimate. EPA also 

evaluated whether chemical addition costs would be required 

based on the plant’s reported chemical addition and dosages, and 

 

59 The conversion from wet to dry fly ash handling for a unit requires new 

equipment to pneumatically convey the ash; however, ash handling vendors 

stated that for dry vacuum retrofits, the existing hopper equipment and 

branch lines can be retained and reused.
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estimated the costs for installing and operating the biological 

treatment stage. 

Following the evaluation of treatment in place, EPA 

estimated plant and wastestream specific incremental costs using 

computerized design and cost models. For the applicable 

wastestreams, the models provide capital, annual O&M, one-time, 

and 3-, 5-, 6-, and 10-year recurring costs for implementing and 

using the applicable technology basis. EPA developed cost 

equations from responses to the industry survey, published 

information, vendor contacts, and engineering judgment. EPA 

developed the following cost modules:

One-Stage Chemical Precipitation – calculates capital and 

O&M costs associated with a one-stage chemical 

precipitation system;

Biological Treatment – calculates capital and O&M costs 

associated with an anoxic/anaerobic biological treatment 

system;

Vapor-Compression Evaporation – calculates capital and O&M 

costs associated with a vapor-compression evaporation 

system;

Dry Fly Ash Handling – calculates capital, O&M, and 

recurring costs associated with a dry fly ash handling 

system;

Dry Bottom Ash Handling – calculates capital, O&M, and 

recurring costs associated with a dry bottom ash handling 

system;

Transportation – calculates O&M costs associated with 

transporting FGD, ash, and/or landfill leachate solid waste 

to an on-site or off-site landfill; 

Disposal – calculates capital and O&M costs associated with 

disposing of FGD, ash, and/or landfill leachate solid waste 

in an on-site or off-site landfill; and
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Impoundment Costs – calculates capital, O&M, and recurring 

costs associated with the operation and maintenance of an 

on-site impoundment.

Ultimately, the cost model produces a plant-level summary 

of the incremental technology option costs associated with each 

regulatory option. Each plant incurring a cost for an evaluated 

wastestream is presented in the output. To determine the total 

compliance cost for a plant associated with a regulatory option, 

EPA calculated the various cost components described above for 

each applicable wastestream. EPA then summed the costs for each 

component of each wastestream to calculate the total capital, 

O&M, and other recurring costs for the plant. Section XI of this 

preamble and the RIA contains a more detailed discussion of 

EPA’s annualization of the compliance costs.

EPA also evaluated the expected costs of compliance for new 

sources. The construction of new generating units may occur at 

an existing power plant or at a new plant construction site. The 

incremental cost associated with complying with the proposed 

NSPS and PSNS options will vary depending on the types of 

processes, wastestreams, and waste management systems that the 

plant would have installed in the absence of the proposed new 

source requirements. EPA estimated capital and O&M costs for 

several scenarios that represent the different types of 

operations that are present at existing units at existing power 

plants or are typically included at new power plants. These 
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scenarios captured differences in the plant status (i.e., 

building a unit at a new location versus adding a new unit at an 

existing power plant), presence of on-site impoundments or 

landfills, type of ash handling, type of FGD systems in service, 

and type of leachate collection and handling.

Finally, EPA recognizes there are significant drivers 

including federal, state, and local requirements for future air 

control installations at existing units. As such, EPA also 

conducted a sensitivity analysis that forecasts future 

installations of air controls through 202060 and the associated 

costs of the regulatory options discussed in today’s proposal. 

EPA estimated these installations using data reported by 

individual plants in the survey regarding planned installations, 

as well as analyses conducted by OAR using the IPM, which is 

widely used by EPA for analysis of rules and policies affecting 

electric power generating facilities. Section VIII.A.7 contains 

a discussion of EPA’s approach for forecasting future 

installations. EPA then estimated plant-specific costs for these 

future installations, using the same approach as it used for 

current operations. 

 

60 EPA expects that plants will be in compliance with new federal and state 

air pollution control requirements by 2020.
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B. Methodology for Estimating Plant-Specific Pollutant 

Reductions

EPA took a similar approach to the one described above for 

costs in estimating pollutant reductions associated with the 

limitations and standards for the regulatory options in today’s 

proposal. That is, EPA estimated incremental pollutant 

reductions for discharges of a particular wastestream at a 

particular plant when its existing practices would not lead to 

compliance with the option being evaluated. In such cases, EPA 

estimated the annual pollutant (baseline) load associated with 

the current discharge of a wastestream and the post-compliance 

annual pollutant load expected after implementation of the 

applicable technology basis. EPA then calculated the pollutant 

loading reduction at a particular plant as the sum of the 

difference between the estimated baseline and post-compliance 

discharge load for each applicable wastestream. 

The following provides a brief discussion of the 

methodology EPA used to estimate baseline loads discharged for 

the various wastestreams. For those plants that discharge 

indirectly to POTWs, EPA adjusted the baseline loads to account 

for pollutant removals expected from POTWs. These adjusted 

pollutant reductions for indirect dischargers reflect reductions 

in discharges to receiving waters.
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1. FGD Wastewater

For FGD discharges, EPA estimated baseline loadings by 

assigning pollutant concentrations based on the type of 

treatment system currently in place at the plant. EPA assigned 

treatment in place for this wastestream to one of four classes 

of treatment: surface impoundment, chemical precipitation, 

anaerobic/anoxic biological treatment, and vapor-compression 

evaporation. EPA identified the plant’s current treatment system 

using data reported in the industry survey. Of the 117 plants 

that discharge FGD wastewater, 40 operate chemical precipitation 

systems, six operate biological treatment systems, and one 

operatestwo operate a vapor-compression evaporation system.61 All 

other plants are categorized in the surface impoundment class of 

treatment.

EPA then estimated the average baseline pollutant effluent 

concentration of each analyte for each class of treatment. EPA 

used data collected in its sampling program to characterize 

effluent concentrations from chemical precipitation, 

anoxic/anaerobic biological treatment, and vapor-compression 

evaporation systems. Because EPA lacked data on pollutant 

effluent concentrations associated with FGD wastewater 

impoundments, EPA estimated that surface impoundments remove 

 

61 A third power plant is currently installing a vapor-compression evaporation 

system to treat the FGD wastewater.
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particulate matter (including the particulate phase metals) to 

an equivalent treatment level of 30 mg/L TSS (based oni.e., thus 

assuming that the discharge would be in compliance with the 

current BPT effluent limits for low-volume waste sources). EPA 

estimated that all dissolved metals will pass through the 

surface impoundment and be discharged. Section 10 of the TDD 

contains more information on baseline pollutant effluent 

concentrations. 

EPA then used this average baseline pollutant effluent 

concentration with plant-specific discharge flow rates reported 

in the industry survey to estimate the mass pollutant discharged 

per plant.62 Section 9 of the TDD contains more details on how 

EPA developed flow rates.

For post-compliance FGD pollutant loading concentrations, 

for each pollutant, EPA used the long-term average for the 

technology basis for the option being evaluated. With a few 

exceptions, EPA then used these pollutant concentrations in 

combination with the same plant-specific discharge flow rates it 

used for baseline. The exceptions are five plants currently 

discharging FGD wastewater that EPA predicts will incorporate 

recycle within the FGD system based on the maximum operating 

 

62 In some cases, plant-specific discharge flow rates were not available in 

the survey response. See Section 9 of the TDD for more information on how EPA 

estimated flow rates.
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chlorides concentration compared to the design maximum chlorides 

concentration.

2. Fly Ash and Bottom Ash

For baseline ash loads, EPA used publicly available data to 

characterize discharges from ash impoundments, including data 

collected during EPA’s Detailed Study, EPRI PISCES reports, 

permit application data, and the 1982 Development Document for 

Final Effluent Limitations Guidelines, New Source Performance 

Standards, and Pretreatment Standards for the Steam Electric 

Point Source Category (EPA 440-1-82-029). EPA used the 

concentration data obtained from these sources to calculate the 

average pollutant concentration in fly ash, bottom ash, and 

combined ash impoundments. EPA then coupled these concentrations 

with plant-specific ash sluice rates reported in the industry 

survey to calculate baseline ash discharge loads. In cases where 

EPA had available information regarding recycle associated with 

the impoundment overflow, EPA adjusted the sluice rates to 

reflect the discharge flow rate from the impoundment. For postcompliance pollutant loadings, EPA assumed implementation of dry 

ash handling would result in a zero post-compliance load. 

3. Combustion Residual Leachate

For baseline leachate loads, EPA used data reported in Part 

G of the industry survey to calculate an average baseline 

pollutant concentration for leachate. These data included 
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responses from 22 active fuel combustion residual landfills and 

four inactive fuel combustion residual landfills. EPA then used 

the baseline pollutant concentrations in conjunction with 

leachate flow rates to calculate the baseline pollutant 

loadings. Section 9 of the TDD describes how EPA used industry 

survey data to estimate leachate flow rates. For post-compliance 

leachate loads, EPA lacked data on effluent concentrations from 

chemical precipitation or biological treatment of leachate from 

combustion residual landfills or surface impoundments. EPA is 

proposing the effluent limits for leachate discharges would be 

based on transferring the effluent limits calculated for FGD 

wastewater using the identical technology bases. Therefore, EPA 

estimates, based on engineering judgment, that post-compliance 

effluent concentrations for leachate would be equal to the 

average effluent FGD wastewater concentrations for a similar 

treatment technology.

4. FGMC and Gasification Wastewaters and Nonchemical Metal 

Cleaning Wastes

FGMC wastewater originates from activated carbon injection 

systems. EPA identified 73 plants with current or planned 

activated carbon injection systems. Most of these plants use, or 

plan to use, a dry handling system to transfer the mercurycontaining carbon to silos for temporary storage until the waste 

is hauled away by trucks for disposal in a landfill. EPA 
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identified only six plants that transport (sluice) FGMC waste

with water to a surface impoundment. However, five of these six 

plants do not discharge any FGMC wastewater and the remaining 

plant has the capability to handle the FGMC waste using a dry 

system but sometimes uses a wet system instead. Since the 

current baseline discharge of pollutants for FGMC wastewater is 

essentially zero, the proposed rule would establish effluent 

limitations that are consistent with the current industry 

practices for FGMC wastewater (i.e., zero discharge) and 

therefore EPA estimates there will be no (or little) incremental 

removal of pollutants relative to current practices. At the same 

time, however, establishing the proposed zero discharge standard 

for FGMC wastewater will ensure that future FGMC installations 

implement dry waste handling practices or manage wastewater in a

manner that achieves zero discharge of pollutants.

The two IGCC plants currently operating in the United 

States already use the technology that is the basis for all 

fiveeight regulatory options for gasification wastewater. A 

third IGCC plant that will soon begin commercial operation will 

also use this same treatment technology. Since these plants are 

already operating the technology that serves as the basis for 

the proposed BAT, the proposed rule would establish effluent 

limitations that are consistent with the current industry 

practices for gasification wastewater and, therefore, EPA 
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estimates there will be no incremental removal of pollutants 

relative to current practices.

The proposed ELGs for discharges of nonchemical metal 

cleaning waste are equal to the current BPT effluent limits for 

metal cleaning waste. TheseThe proposed requirements are

consistent with current industry practice for treating 

nonchemical metal cleaning waste and are based on the same 

technology that was used as the basis for the current ELGs

requirements for chemical metal cleaning waste. Since, as 

described above in Section VIII, nonchemical metal cleaning 

waste is included within the definition of metal cleaning waste, 

EPA would be establishing ELGs that are equal to the BPT limits 

that already apply to discharges of these wastes to surface 

waters.

63 As a result, facilities would incur no incremental 

costAdditionally, as described in Section VIII.A.3, EPA is 

proposing to exempt from new copper and iron limitations and 

standards any existing nonchemical metal cleaning wastes 

generated and currently authorized for discharge without copper 

and iron limits. As a result, all facilities are either already 

in compliance or will be exempt from the requirements; 

therefore, no facilities would incur incremental costs to comply 

 

63 The proposed BAT would establish limits for copper and iron equal to the 

existing BPT limits for these pollutants. The proposed NSPS would establish 

standards for copper, iron, TSS, and oil and grease that are equal to the BPT 

limits for these pollutants. The proposed PSES and PSNS would establish 

standards for copper equal to the BPT limits for copper. See Section VIII for 

details about the proposed limitations for nonchemical metal cleaning wastes.
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with the proposed ELGs for these wastes, nor would there be 

incremental pollutant removals associated with the proposed 

ELGs.

5. Request for Comment on Data

While EPA is soliciting comment on all aspects of today’s 

proposal, the Agency would like to highlight certain aspects 

related to the pollutant removal estimates. EPA solicits 

additional data or information on pollutant loadings in steam 

electric power plant wastewater discharges that would 

corroborate or correct the data used in EPA’s analysis, 

including data or information relating to the pollutants of 

concern that EPA has identified in this rulemaking. It is 

important that EPA have data and information of sufficient 

quality in order to incorporate the data into its analysis. If 

you have data or information or you intend to collect data that 

you believe would be relevant to EPA and you would like to 

submit the data as part of your public comments, EPA encourages 

you to contact the Agency first to ensure that the data 

submitted contains sufficient and relevant information, and that 

it is provided in an appropriate format, such that it can inform 

EPA’s analyses for the final action (see points of contact in 

the introduction to this preamble). 

EPA is also seeking comment related to the data used in 

developing this proposed rule and how it should be analyzed: age 
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of data, treatment of non-detects, treatment of pollutants in 

the source water and the calculation of toxic-weighted pollutant 

equivalents.

Age of data. How should EPA take into account changes that 

may have occurred in the industry over time and what information 

would be appropriate for demonstrating that certain data for 

certain pollutants or wastestreams should or should not be used? 

For example, should EPA use a date cutoff for the data used and 

what rationale should be used for any such cutoff? EPA 

encourages commenters to submit any more recent data (but you 

should contact EPA first to make sure the data you submit is 

usable for the analyses, see above). 

Treatment of non-detect values. How should EPA treat nondetects in effluent data when determining baseline pollutant 

loadings? What other information should inform how EPA handles 

the issue of non-detects, given that in some cases, analytical 

methods cannot determine the actual amount of pollutants in 

wastewater? Should EPA use a cutoff for the number or percentage 

of non-detects in a dataset in order for EPA to use the dataset 

for a specific pollutant? For example, there were more nondetects than detected values for effluent data for sulfides. 

Does this data set provide a sufficient basis, in the absence of 

any other information, for estimating pollutant loadings for 

sulfides? 
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Treatment of pollutants in the source water. When should 

EPA adjust pollutant loadings concentrations to account for 

contributions from a facility’s source water? Should EPA 

estimate pollutant loadings for pollutants for which a certain 

percentage of the influent concentration comes from source 

water? If EPA were to do this, what steps should the Agency 

take to ensure the adjustments for source water contribution 

definitively link the source water data to the influent and 

effluent data?

Calculation of toxic-weighted pollutant equivalents. Is 

EPA’s calculation of TWPEs appropriate? Do commenters have 

suggestions, either generally or relative to specific 

pollutants, for how this calculation can be improved?

C. Summary of National Engineering Costs and Pollutant 

Reductions for Existing Plants

As described in above in Section VIII, EPA evaluated 5eight

regulatory options comprised of various combinations of the 

technology options considered for each wastestream, summarized 

in Table VIII-1. The Agency estimated the costs and pollutant 

loading reductions associated with steam electric power plants 

to achieve compliance with each regulatory option under 

consideration. This section summarizes the total estimated 

compliance costs and pollutant reductions associated with each 

option for existing plants (see Tables IX-3 and IX-4). These 
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tables present the capital cost, annual operating and 

maintenance costs, one-time costs, and recurring costs for each 

regulatory option. Section XI contains a listing of total 

annualized costs by regulatory option. All cost estimates in 

this section are expressed in terms of pre-tax 2010 dollars. The 

costs shown in Section XI take into account the timeframe 

proposed to meet the limits in the rule.

Information, including plant-specific information, for 

EPA’s compliance cost and pollutant loading estimates and 

methodologies is located in the rulemaking record. Some of the 

information EPA used to estimate compliance costs and pollutant 

loadings was claimed by survey respondents as CBI. Therefore, 

this information is not included in the public docket. However, 

the public docket contains a number of documents that set forth 

EPA’s methodology, assumptions and rationale for developing its 

cost estimates and pollutant loadings estimates, and that also 

present as much data as possible by using aggregation, 

summaries, and other techniques to protect CBI. EPA encourages 

all interested parties to refer to the record and to provide 

comments where appropriate on any aspect of the methodology or 

the data used to estimate compliance costs and pollutant 

loadings associated with today’s proposal.
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TABLE IX-3.—Cost of Implementation (BAT and PSES)

[In millions of pre-tax 2010 dollars]

Regulatory 

Option

Number 

of 

Plants

Capital 

Cost

Annual 

O&M 

Cost

One 

Time 

Costs

Recurring Costs

3-

year

5-

year

6-

year

10-

year

1 116 $1,450 $194 $0 $0 $0 $10 ($33)

3a 66 $398 $177 $0 $0 $0 $0 ($21)

2 116 $2,499 $257 $0 $0 $0 $10 ($33)

3b 80 $998 $244 $0 $0 $0 $1 ($26)

3 155 $2,897 $434 $0 $0 $0 $10 ($54)

4aa 200 $5,478 $689 $0.3 $1 $38 $10 ($90)

4 277 $8,011 $988 $0.6 $28 $65 $16 ($137)

5 277 $11,755 $1,753 $0.6 $28 $65 $19 ($137)

a EPA estimated the costs for Option 4a based on approximated plant-level 

bottom ash costs for those plants that have at least one generating unit 

with a nameplate capacity of 400 MW or less and at least one other 

generating unit with a nameplate capacity of greater than 400 MW. For more 

details on how EPA estimated these plant-level bottom ash costs, see the 

memorandum entitled “Steam Electric ELG Regulatory Option 4a Estimation 

Methodologies” (DCN SE03834). 

TABLE IX-4.—Estimated Pollutant Loading Reduction (BAT and PSES) 

[In million pounds/year]

Regulatory 

Option

Pollutant Removals

Conventional 

Pollutantsa

Priority 

Pollutants

Nonconventional 

Pollutantsb

1 2.8 0.5 (418)c

3a 16 0.4 468

2 2.8 0.7 1,155

3b 17.1 0.6 914

3 19 1.1 1,623

4ad 28 1.4 2,612

4 35 1.7 3,328

5 36 1.7 5,287

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

Note that the BOD and TSS removals are not included in the total pollutant 

removals stated in Section II (1.63 billion pounds per year for Option 3; 

3.34 billion pounds per year for Option 4) to avoid double-counting 

removals for certain priority and nonconventional pollutants that would 

also be measured by these bulk parameters.

b The loadings reduction for nonconventional pollutants excludes TDS and COD

to avoid double-counting removals for certain pollutants that would also 

be measured by these bulk parameters (e.g., sodium, magnesium).

c Option 1 shows a negative removal for nonconventional pollutants because 

the mass of several pollutants (ammonia, chromium, TKN, and BOD) are not 

quantified at baseline, and because some pollutant discharge 

concentrations are higher under Option 1.

EPA estimated the pollutant removals for Option 4a based on 

approximated plant-level bottom ash loadings for those plants 
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that have at least one generating unit with a nameplate capacity 

of 400 MW or less and at least one other generating unit with a 

nameplate capacity of greater than 400 MW. For more details on 

how EPA estimated these plant-level bottom ash loadings, see the 

memorandum entitled “Steam Electric ELG Regulatory Option 4a 

Estimation Methodologies” (DCN SE03834).

X. Approach to Determine Long-Term Averages, Variability 

Factors, and Effluent Limitations and Standards

This section describes the statistical methodology used to 

calculate the long-term averages, variability factors, and 

limitations for BAT, new source performance standards and 

pretreatment standards for existing and new sources. The 

effluent limitations and standards are based on long-term 

average effluent values and variability factors that account for 

variation in treatment performance of the model technology. 

The proposed effluent limitations and/or standards, 

collectively referred to in the remainder of this section as 

“limitations,” for pollutants for each technology option, as 

presented in today's notice, are provided as “daily maximums” 

and “maximums for monthly averages.” Definitions provided in 40 

CFR 122.2 state that the daily maximum limitation is the 

“highest allowable ‘daily discharge,’” and the maximum for 

monthly average limitation is the “highest allowable average of 

‘daily discharges’ over a calendar month, calculated as the sum 

of all ‘daily discharges’ measured during a calendar month 

divided by the number of ‘daily discharges’ measured during that 
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month.” Daily discharges are defined to be the “‘discharge of a 

pollutant’ measured during a calendar day or any 24-hour period 

that reasonably represents the calendar day for purposes of 

sampling.” In this section, the term “option long-term average” 

and “option variability factor” are used to refer to the longterm averages and variability factors for technology options for 

an individual wastestream rather than the regulatory options 

described in Section VIII.

A. Criteria Used to Select Data as the Basis for the Limitations

and Standards

In developing effluent limitations guidelines and standards 

for any industry, EPA qualitatively reviews all the data before 

selecting data that represents proper operation of the 

technology that forms the basis for the limitations. EPA 

typically uses four criteria to assess the data. The first 

criterion requires that the plants have the model treatment 

technology and demonstrate consistently diligent and optimal 

operation. Application of this criterion typically eliminates 

any plant with treatment other than the model technology. EPA 

generally determines whether a plant meets this criterion based

upon site visits, discussions with plant management, and/or 

comparison to the characteristics, operation, and performance of 

treatment systems at other plants. EPA often contacts plants to 

determine whether data submitted were representative of normal 
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operating conditions for the plant and equipment. As a result of 

this review, EPA typically excludes the data in developing the 

limitations when the plant has not optimized the performance of 

its treatment system to the degree that represents the 

appropriate level of control (BAT or BADCT).

A second criterion generally requires that the influents 

and effluents from the treatment components represent typical 

wastewater from the industry, without incompatible wastewater 

from other sources. Application of this criterion results in EPA 

selecting those plants where the commingled wastewaters did not 

result in substantial dilution, unequalized slug loads resulting 

in frequent upsets and/or overloads, more concentrated 

wastewaters, or wastewaters with different types of pollutants 

than those generated by the wastestream for which EPA is 

proposing effluent limitations.

A third criterion typically ensures that the pollutants are 

present in the influent at sufficient concentrations to evaluate 

treatment effectiveness. To evaluate whether the data meet this 

criterion for inclusion as a basis of the limitations, EPA often 

uses the long-term average test (or LTA test) for plants where 

EPA possesses paired influent and effluent data (see Section 13

of the Technical Development Document for details of the LTA 

test). The test measures the influent concentrations to ensure a 

pollutant is present at a sufficient concentration to evaluate 
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treatment effectiveness. If a dataset for a pollutant fails the 

test (i.e., pollutant not present at a treatable concentration), 

EPA excludes the data for that pollutant at that plant when 

calculating the limitations.

A fourth criterion typically requires that the data are 

valid and appropriate for their intended use (e.g., the data 

must be analyzed with a sufficiently-sensitive method). Also, 

EPA does not use data associated with periods of treatment 

upsets because these data would not reflect the performance from 

well-designed and well-operated treatment systems. In applying 

the fourth criterion, EPA may evaluate the pollutant 

concentrations, analytical methods and the associated quality 

control/quality assurance data, flow values, mass loading, plant 

logs, and other available information. As part of this 

evaluation, EPA reviews the process or treatment conditions that 

may have resulted in extreme values (high and low). As a 

consequence of this review, EPA may exclude data associated with 

certain time periods or other data outliers that reflect poor 

performance or analytical anomalies by an otherwise welloperated site. 

The fourth criterion also is applied in EPA’s review of 

data corresponding to the initial commissioning period for 

treatment systems. Most industries incur commissioning periods 

during the adjustment period associated with installing new 
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treatment systems. During this acclimation and optimization 

process, the effluent concentration values tend to be highly 

variable with occasional extreme values (high and low). This 

occurs because the treatment system typically requires some 

“tuning” as the plant staff and equipment and chemical vendors 

work to determine the optimum chemical addition locations and 

dosages, vessel hydraulic residence times, internal treatment 

system recycle flows (e.g., filter backwash frequency, duration 

and flow rate, return flows between treatment system 

components), and other operational conditions including 

clarifier sludge wasting protocols. It may also take several

weeks or months for treatment system operators to gain expertise 

on operating the new treatment system, which also contributes to 

treatment system variability during the commissioning period. 

After this initial adjustment period, the systems should operate 

at steady state with relatively low variability around a longterm average over many years. Because commissioning periods 

typically reflect one-time operating conditions unique to the 

first time the treatment system begins operation, EPA generally 

excludes such data in developing the limitations.64

 

64 Examples of conditions that are typically unique to the initial 

commissioning period include operator unfamiliarity or inexperience with the 

system and how to optimize its performance; wastewater flow rates that differ 

significantly from engineering design, altering hydraulic residence times, 

chemical contact times, and/or clarifier overflow rates, and potentially 

causing large changes in planned chemical dosage rates or the need to 

substitute alternative chemical additives; equipment malfunctions; 
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B. Data Used As Basis of the Limitations and Standards

The sections below discuss the data used as the basis for 

today’s proposal, including data selection, the combination of 

data from multiple sources within each plant, and the data 

exclusions made prior to calculate the limitations. 

1. Data Selection for Each Technology Option

This section describes the data selected for use in 

developing the limitations for each technology option. This 

section includes an abbreviated description of the technology 

options. See Section VIII for a more complete discussion of the 

technology basis for each of the options considered. For fly ash 

transport water and FGMC wastewater, EPA is proposingall of the 

preferred regulatory options propose zero discharge of 

pollutants associated with these wastewaters based on dry 

handling technologies; therefore, no effluent concentration data 

were used to set the limitations for these wastestreams. This 

is also true for the options that include zero discharge of 

pollutants for any set of dischargers for bottom ash.

Except as described in Section VIII, EPA is proposing to 

establish limitations for discharges of pollutants in 

 

fluctuating wastewater flow rates or other dynamic conditions (i.e., not 

steady state operation); and initial purging of contaminants associated with 

installation of the treatment system, such as initial leaching from coatings, 

adhesives, and susceptible metal components. These conditions differ from 

those associated with the restart of an already-commissioned treatment 

system, such as may occur from a treatment system that has undergone either 

short or extended duration shutdown.
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nonchemical metal cleaning wastes that are equal to the current 

BPT limitations that apply to discharges of nonchemical metal 

cleaning wastes from existing sources that are direct 

dischargers. No new effluent concentration data were used to set 

the effluent limitations for nonchemical metal cleaning wastes 

in this rulemaking, therefore the limitations for this 

wastestream are not discussed in this section. See Section VIII 

for a more complete discussion of the basis for the proposed 

limitations.

Under some regulatory options being proposed today, EPA 

would establish limitations for certain wastewater discharges 

that are equal to the current BPT limitations for those 

discharges. No new effluent concentration data would be used to 

establish BAT/NSPS limitations that are set equal to BPT, 

therefore such limitations are not discussed in this section. 

See Section VIII for a more complete discussion of the basis for 

the proposed regulatory options. For the limitations for 

combustion residual leachate (hereafter referred to in this 

section as leachate) based on the chemical precipitation 

technology option, EPA is proposing to transfer the limitations 

calculated based on the chemical precipitation technology option 

for the FGD wastewater because EPA does not have the available 

effluent data for leachate from plants that employ the chemical 

precipitation technology. For the limitations based on the 
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biological treatment technology option for FGD wastewater, EPA 

is proposing to transfer the limitations for two pollutants 

(mercury and arsenic) calculated based on the chemical 

precipitation technology option for the FGD wastewater for the 

reasons described below. See Section 13 of the Technical 

Development Document for a detailed discussion on the transfer 

of limitations for leachate and FGD wastewater. 

EPA used specific data sources to derive limitations for 

pollutants in FGD and gasification wastewater discharges based 

on particular treatment technology. The data sources used to 

calculate limitations for each technology option, by 

wastestream, are described below.

a. FGD Wastewater

As part of the EPA sampling program and additional plant 

self-monitoring data EPA obtained during the rulemaking, EPA 

evaluated the performance of 10 FGD wastewater treatment 

systems. For seven of the 10 systems, EPA collected data 

representing the influent and effluent for chemical 

precipitation treatment systems. EPA evaluated these seven 

systems and determined that the systems operating the chemical 

precipitation system with both hydroxide and sulfide 

precipitation achieved better removals of mercury compared to 

the plants that used only hydroxide precipitation. Therefore, 

EPA did not use data from the three plants that use only 
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hydroxide precipitation. Four of the seven plants use hydroxide 

and sulfide precipitation; however, one of the plants operates a 

two-stage chemical precipitation system. Because EPA’s basis for 

the technology option is a one-stage system, EPA did not use the 

data from the two-stage system in developing the limitations.65

Therefore, EPA used data from the following three plants to 

develop the limitations based on treatment of FGD wastewater 

using the chemical precipitation technology option (i.e., onestage chemical precipitation system employing both hydroxide and 

sulfide precipitation and iron coprecipitation, as well as flow 

reduction at plants with large FGD wastewater flow rates, 

hereafter referred to in this section as “chemical 

precipitation” – see Section VIII above for a more detailed 

description):

Duke Energy’s Miami Fort Station (“Miami Fort”);

RRI Energy’s Keystone Generating Station (“Keystone”); and

Allegheny Energy’s Hatfield’s Ferry Power Station 

(“Hatfield’s Ferry”).

For the treatment of FGD wastewater using a system that 

includes biological treatment as part of the process, EPA 

evaluated the treatment systems at three power plants as part of 

 

65 Based on data EPA has evaluated for the steam electric industry and other 

industry sectors, two-stage chemical precipitation systems generally achieve 

better pollutant removals than one-stage systems. Since the technology basis 

for chemical precipitation treatment of FGD wastewater in the proposed rule 

is a one-stage system and that is the configuration used to estimate 

compliance costs, EPA concluded that effluent data for the two-stage system 

(Pleasant Prairie) should not be used when calculating effluent limits for 

the technology option.
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the EPA sampling program; however, one of the biological 

treatment systems was not designed for effective removal of 

selenium and does not represent the model technology. The 

biological treatment technology option is based on a one-stage 

chemical precipitation system employing both hydroxide and 

sulfide precipitation and iron coprecipitation, as well as flow 

reduction at plants with large FGD wastewater flow rates, 

followed by anoxic/anaerobic biological treatment designed to 

remove selenium, hereafter referred to in this section as

“biological treatment” – see Section VIII above for a more 

detailed description. EPA used data from the following two 

plants to develop the limitations for the treatment of FGD 

wastewater using a one-stage chemical precipitation system 

followed by biological treatment:

Duke Energy Carolina’s Belews Creek Steam Station (“Belews 

Creek”); and

Duke Energy Carolina’s Allen Steam Station (“Allen”).

While these two plants operate the biological treatment 

system included as the basis for the technology option, neither 

of these plants include sulfide precipitation in the upstream 

chemical precipitation system and rely only on hydroxide 

precipitation. Therefore, the effluent mercury and arsenic 

concentrations achieved by these plants do not fully represent

the effluent concentrations that would be achieved by the system 
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used as the design basis for the technology option. For this 

reason, EPA is proposing to establish the mercury and arsenic 

limitations for the biological treatment technology option 

(which includes one-stage chemical precipitation as an initial 

treatment stage) based on transferring the limitations that were 

calculated for the chemical precipitation treatment technology 

option. This is a reasonable approach for establishing mercury 

and arsenic limitations for the biological treatment technology 

option because, in doing so, EPA would be setting the 

limitations equal to the performance that reflects the level of 

treatment that would be achieved by the initial treatment stage 

of the wastewater treatment system. 

For the treatment of FGD wastewater using a chemical 

precipitation followed by vapor-compression evaporation system

hereafter referred to in this section as “vapor-compression 

evaporation” (which is the technology serving as the basis for 

regulatory Option 5, which is not thea preferred option in 

today’s proposal), EPA evaluated three systems as part of the 

EPA sampling program. One plant operates a system that is 

similar to the technology basis for the FGD wastewater 

limitations in the proposed rule: a one-stage chemical 

precipitation system followed by softening and a vaporcompression evaporation system. EPA used the data from this 

plant to develop the limitations based on the vapor-compression 
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evaporation technology for the treatment of the FGD wastewater. 

That plant is Enel’s Federico II Power Plant, located in 

Brindisi, Italy. EPA used data from a second plant for 

characterization purposes and not for limitations development 

because it only collected effluent data for one day from the 

plant. The third system does not represent the technology 

serving as the basis for the vapor compression evaporation 

option, and thus was not used for the limitations development. 

This plant operates a solids removal process prior to the vaporcompression evaporation system but does not include a full 

chemical precipitation system nor a softening step. Furthermore, 

this plant also operates a one-stage evaporation system and 

instead of employing a second stage of evaporation to 

crystallize and remove salts and other pollutants from the 

concentration brine, mixes the brine with fly ash and sends it 

to the landfill for disposal. 

b. Gasification Wastewater

For the treatment of gasification wastewater using a vaporcompression evaporation system, EPA evaluated systems from the 

following two plants as part of the EPA sampling program: 

Tampa Electric Company’s Polk Station (“Polk”); and

Wabash Valley Power Association’s Wabash River Station 

(“Wabash River”).
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Both systems are representative of the system used as the 

basis for the technology option and were used in calculating the 

limitations.

2. Combining Data from Multiple Sources Within a Plant

Typically, if sampling data from a plant were collected 

over two or more distinct time periods, EPA analyzes the data 

from each time period separately. In previous effluent 

guidelines rulemakings, where appropriate, EPA has analyzed the 

data for each time period as if each time period represents a 

different plant since these data can represent different 

operating conditions due to changes in management, personnel, 

and procedures. On the other hand, when EPA obtains the data 

(such as EPA’s sampling and plant self-monitoring data) from a 

plant during the same time period, EPA combines the data from 

these sources into a single dataset for the plant for the

statistical analysis.

For this rulemaking, data at most selected plants came from 

multiple sources (EPA’s sampling, plant sampling as directed by 

the EPA through 308 letters, or plant self-monitoring). For some 

plants, EPA has data collected from multiple sources during 

overlapping time periods. For these plants, EPA combined the 

multiple sources of data at each plant into a single dataset for 

the plant, which provided the basis for developing the 

limitations. Other plants had data collected from multiple 
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sources during non-overlapping time periods. However, in these 

instances the time period between the non-overlapping data 

collection periods was relatively small (two months). 

Furthermore, EPA has no information to indicate that the data 

represent different operating conditions. Thus, EPA also 

combined the multiple sources of data for each of these plants 

into a single data set for the plant, which provided the basis

for developing the limitations. Finally, a couple of plants had 

data from a single source, and for these plants it was not 

necessary to combine data. For a listing of all the data and 

their sampling sources for each of the plants, see DCN SE02002., 

“Sampling Data Used as the Basis for Effluent Limitations for 

the Steam Electric Rulemaking.”

3. Data Exclusions 

Following EPA’s selection of the model plant(s), EPA 

applied the criteria described above in Section A by thoroughly 

evaluating all available data for each model plant. EPA 

identified certain data that warranted exclusions from the 

calculations of the limitations because: (i) the samples were 

analyzed using an insufficiently-sensitive analytical method 

(i.e., use of EPA Method 245.1 instead of Method 1631E for 

mercury); (ii) the samples were collected during the initial 

commissioning period for the treatment system; (iii) or 

analytical results were identified as questionable due to 
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quality control issues, abnormal conditions or treatment upsets, 

or were analytical anomalies. See DCN SE01999 for a detailed 

discussion of the data excluded.

C. Overview of the Limitations and Standards

The sections below describe EPA’s objectives for proposing 

the daily maximum and monthly average limitations and the 

selection of percentiles for those limitations.

1. Objective

EPA’s objective in establishing daily maximum limitations 

is to restrict the discharges on a daily basis at a level that 

is achievable for a plant that targets its treatment at the 

long-term average. EPA acknowledges that variability around the 

long-term average occurs during normal operations. This 

variability means that plants occasionally may discharge at a 

level that is higher (or lower) than the long-term average. To 

allow for these possibly higher daily discharges, EPA has 

established the daily maximum limitation. A plant that 

consistently discharges at a level near the daily maximum 

limitation would not be operating its treatment to achieve the 

long-term average. Targeting treatment to achieve the daily 

limitation, rather than the long-term average, may result in 

values that frequently exceed the limitations due to routine 

variability in treated effluent.
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EPA’s objective in establishing monthly average limitations 

is to provide an additional restriction to help ensure that 

plants target their average discharges to achieve the long-term 

average. The monthly average limitation requires dischargers to 

provide on-going control, on a monthly basis, that supplements 

controls imposed by the daily maximum limitation. In order to 

meet the monthly average limitation, a plant must counterbalance 

a value near the daily maximum limitation with one or more 

values well below the daily maximum limitation. To achieve 

compliance, these values must result in a monthly average value 

at or below the monthly average limitation.

2. Selection of Percentiles

EPA calculates limitations based upon percentiles that 

should be both high enough to accommodate reasonably anticipated 

variability within control of the plant, and low enough to 

reflect a level of performance consistent with the Clean Water 

Act requirement that these effluent limitations be based on the 

“best” available technologies. The daily maximum limitation is 

an estimate of the 99th percentile of the distribution of the 

daily measurements. The monthly average limitation is an 

estimate of the 95th percentile of the distribution of the 

monthly averages of the daily measurements. The percentiles for 

both types of limitations are estimated using the products of 

long-term averages and variability factors. EPA has consistently 
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used the 99th percentile as the basis of the daily maximum 

limitation and 95th percentile as the basis of the monthly 

average limitation in establishing limitations for numerous 

industries and for many years and numerous courts have upheld 

EPA’s approach. 

EPA uses the 99th and 95th percentiles to draw a line at a 

definite point in the statistical distributions that would 

ensure that operators work to establish and maintain the 

appropriate level of control. These percentiles reflect a 

longstanding Agency policy judgment about where to draw the 

line. The development of the limitations takes into account the 

reasonable anticipated variability in discharges that may occur 

at a well-operated plant. By targeting its treatment at the 

long-term average, a well-operated plant should be capable of 

complying with the limitations at all times because EPA has 

incorporated an appropriate allowance for variability in the 

limitations. 

In conjunction with setting the limitations as described 

above, EPA performs an engineering review to verify that the 

limitations are reasonable based upon the design and expected 

operation of the control technologies and the plant process 

conditions. As part of the review, for each plant EPA compared 

the influent and effluent measurements with the proposed 

effluent limitations. See Section F below for details of these 
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comparisons for each pollutant at each plant, as well as a 

discussion of the findings of the engineering review.

D. Calculation of the Limitations and Standards

Effluent limitations and standards are based on a 

combination of the long-term average and the appropriate 

variability factors. In estimating the limitations for a 

pollutant, EPA first calculates an average performance level 

(the option long-term average discussed below) that a plant with 

well-designed and well-operated model technologies is capable of 

achieving. This long-term average is calculated using data from 

the plant or plants with the model technologies for the option. 

In the second step of developing a limitation for a 

pollutant, EPA determines an allowance for the variation (the 

option variability factors discussed below) in pollutant 

concentrations for wastewater that has been processed through 

well-designed and well-operated treatment systems. This 

allowance for variation incorporates all components of 

variability including shipping, sampling, storage, and 

analytical variability. This allowance is incorporated into the 

limitations through the use of the variability factors, which 

are calculated from the data from the plants using the model 

technologies. If a plant operates its treatment system to meet 

the relevant long-term average, EPA expects the plant will be 

able to meet the limitations. Variability factors ensure that 
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normal fluctuations in a plant’s treatment are accounted for in 

the limitations. By accounting for these reasonable excursions 

above the long-term average, EPA’s use of variability factors 

results in limitations that are generally well above the longterm averages.

The following sections describe the calculation of the 

option long-term averages, option variability factors and 

limitations, and adjustments for autocorrelation in calculating 

the limitations for each pollutant proposed for regulation. 

1. Calculation of Option Long-Term Average

EPA calculated the option long-term average for a pollutant 

using two steps. First, EPA calculated the plant-specific longterm average for each pollutant that had enough distinct 

detected66 values by fitting a statistical model to the daily 

effluent concentration values. In cases when a dataset for a 

specific pollutant did not have enough distinct detected values, 

then the statistical model was not used to obtain the plantspecific long-term average. In these cases, the plant-specific 

long-term average for each pollutant was the arithmetic mean of 

the available daily effluent concentration values. Appendix B of

 

66 For the purpose of discussing the calculation of the long-term averages, 

variability factors, and effluent limitations, the term “detected” refers to 

analytical results measured and reported above the sample-specific 

quantitation limit. Thus, values described in this section as “non-detected” 

refers to values that are below the method detection limit (MDL) and those 

measured by the laboratory as being between the MDL and the quantitation 

limit (QL).
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the Technical Development Document contains the required minimum 

number of distinct detected observations and an overview of the 

statistical model and a description of the procedures EPA used 

to estimate the plant-specific long-term average. 

Second, EPA calculated the option long-term average for a 

pollutant as the median of the plant-specific long-term averages 

for that pollutant. The median is the midpoint of the values 

when ordered (i.e., ranked) from smallest to largest. If there 

is an odd number of values, then the value of the mth ordered 

observation is the median (where m=(n+1)/2 and n=number of 

values). If there is an even number of values, then the median 

is the average of the two values in the n/2th and [(n/2)+1]th

positions among the ordered observations.

2. Calculation of Option Variability Factors and Limitations

The following describes the calculations performed to 

obtain the option variability factors and limitations. First, 

EPA calculated the plant-specific variability factors for each 

pollutant that had enough distinct detected values by fitting a 

statistical model to the daily effluent concentration values. 

Each plant-specific daily variability factor for each pollutant 

is the estimated 99th percentile of the distribution of the daily 

pollutant concentration values divided by the plant-specific 

long-term average. Each plant-specific monthly variability 

factor for each pollutant is the estimated 95th percentile of the 
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distribution of the 4-day average pollutant concentration values 

divided by the plant-specific long-term average. The calculation 

of the monthly variability factor assumes that the monthly 

averages are based on the pollutant being monitored weekly 

(approximately four times each month). In cases when there were 

not enough distinct detected values for a specific pollutant at 

a plant, then the statistical model was not used to obtain the

plant-specific variability factors. In these cases, the data for 

the pollutant at the plant was excluded from the calculation of 

the option variability factors. Appendix B of the Technical 

Development Document contains the required minimum number of 

distinct detected observations and a description of the 

procedures used to estimate the plant-specific daily and monthly 

variability factors.

Second, EPA calculated the option variability factors. The 

option daily variability factor for a pollutant was found as the 

mean of the plant-specific daily variability factors for that 

pollutant. Similarly, the option monthly variability factor was 

the mean of the plant-specific monthly variability factors for 

that pollutant. 

Finally, the daily limitation for each pollutant was the 

product of the option long-term average and option daily 

variability factor. The monthly average limitation for each 
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pollutant was the product of the option long-term average and 

option monthly variability factor. 

3. Adjustment for Autocorrelation Factors

Effluent concentrations that are collected over time may be 

autocorrelated. The data are positively autocorrelated when 

measurements taken at specific time intervals, such as one or 

two days apart, are similar. For example, positive 

autocorrelation would occur if the effluent concentration were 

relatively high one day and were likely to remain high on the 

next and possibly succeeding days. Because the autocorrelated 

data may affect the true variability of treatment performance 

EPA typically adjusts the variance estimates for the 

autocorrelated data, when appropriate. For this rulemaking, 

whenever there was sufficient data for a pollutant at a plant to 

evaluate the autocorrelation reliably, EPA estimated the 

autocorrelation and incorporated it into the calculation of the 

limitations. For a plant without enough data to reliably 

evaluate and obtain a reliable estimate of the autocorrelation, 

EPA set the autocorrelation to zero in calculation of the

limitations. EPA did so because there were not sufficient data 

to reliably evaluate the autocorrelation, nor did EPA have a 

valid correlation estimate available that could be transferred 

from a similar technology and wastestream. See DCN SE02001 for 

details of the statistical methods and procedures used to 
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determine the autocorrelation values, as well as a detailed 

discussion of the minimum number of observations needed to 

obtain a reliable estimate of the autocorrelation. Also, see 

Section 13 of the Technical Development Document.TDD. 

E. Long-Term Average, Variability Factors, and Limitations for 

Each Treatment Option

Due to routine variability in treated effluent, a power 

plant that discharges consistently at a level near the values of 

the daily maximum limitation or the monthly average limitation 

may experience frequent values exceeding the limitations. For 

this reason, EPA recommends that power plants design and operate 

the treatment system to achieve the option long-term average for 

the model technology. Thus, a system that is designed to 

represent the BAT level of control will be capable of complying 

with the limitations. The table below provides the proposed 

long-term average, variability factors, and limitations for each 

of the FGD, gasification, and leachate treatment technology 

options. See DCN SE01999 for details of the calculation of the 

results presented in the table below.
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Table X-1. Proposed Long-Term Averages, Variability Factors, and 

Effluent Limitations for each of the FGD, Gasification, and 

Leachate Treatment Technology Options.

Treatment 

Technology

Polluta

nt

Optio

n LTA

Daily

Variabil

ity 

Factor

Monthly

Variabil

ity 

Factor

Daily

Limitat

ion d

Monthly 

Limitat

ion d

Chemical 

Precipitation 

for FGD 

Arsenic 

(ug/L) 4.483 1.741 1.223 8 6

Mercury 

(ng/L)

75.40

4

3.209 1.570 242 119

Chemical 

Precipitation 

and Biological 

Treatment for

FGD 

Arsenic 

(ug/L)a 4.483 1.741 1.223 8 6

Mercury 

(ng/L)a

75.40

4

3.209 1.570 242 119

Nitrate

-

nitrite 

(mg/L)

0.110 1.499 1.157 0.17 0.13

Seleniu

m 

(ug/L) 7.455 2.145 1.321 16 10

VaporCompressionChem

ical 

Precipitation 

and Evaporation

for FGD

(Crystallizer 

Condensate)

Arsenic 

(ug/L) 4.0b ---

c ---c 4e ---f

Mercury 

(ng/L)

17.78

8

2.192 1.338 39 24

Seleniu

m 

(ug/L)

5.0b ---

c ---c 5e ---f

TDS 

(mg/L)

14.88

4

3.341 1.572 50 24

VaporCompression

Evaporation for 

Gasification 

(Vapor 

Compression 

Evaporator 

Condensate)

Arsenic 

(ug/L) 4.0b ---

c ---c 4e ---f

Mercury 

(ng/L) 1.075 1.632 1.194 1.76 1.29

Seleniu

m 

(ug/L)

146.7

80 3.083 1.545 453 227

TDS 

(mg/L)

15.20

9

2.483 1.389 38 22

Chemical 

Precipitation 

for Leachate 

Arsenic 

(ug/L)a 4.483 1.741 1.223 8 6

Mercury 

(ng/L)a 

75.40

4

3.209 1.570 242 119

a Option long-term average, option variability factors, and limitations 

were transferred from chemical precipitation treatment technology option.

b Long-term average is the arithmetic mean since all observations were nondetected.

c All observations were non-detected, so the variability factors could not 

be calculated. 
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d Limitations less than 1.0 are rounded up to the next highest hundredths 

decimal place. Limitations greater than 1.0 have been rounded upward to 

the next highest integer, except for limitations for mercury based on the 

vapor-compression evaporation treatment technology option for gasification 

wastewater which have been rounded up to the next highest hundredths 

decimal place. 

e Limitation is set equal to the detection limit.

f Monthly average limitation is not established when the daily maximum 

limitation is based on the detection limit.

F. Engineering Review of Limitations and Standards

In conjunction with the statistical methods, EPA performed 

an engineering review to verify that the proposed limitations 

are reasonable based upon the design and expected operation of 

the control technologies. EPA performed two types of 

comparisons. First, EPA compared the limitations to the effluent 

data used to develop the limitations. Second, EPA compared the 

limitations to the influent data. Sections below summarize the 

results of these comparisons. For a detailed discussion of the 

results, see Section 13 of the Technical Development Document

for Proposed Effluent Limitations Guidelines and Standards for 

the Steam Electric Power Generating Point Source Category (TDD) 

– EPA 821-R-13.

1. Comparison of Limitations to Effluent Data Used As the Basis 

for the Limitations

As part of its data evaluations, EPA compared the 

limitations to the effluent values used to calculate the 

limitations. This type of comparison helps to evaluate how 

reasonable the proposed limitations may be from an engineering 
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perspective. As part of this evaluation, for each pollutant 

proposed to be regulated under a technology option, EPA first 

compared the daily limitations to the daily effluent values. EPA 

then compared the monthly limitations to all the effluent daily 

values in a month, and identified those months where at least 

one value exceeded the monthly limitations.

After thoroughly evaluating the results of the comparison 

between the limitations and the effluent values used to 

calculate the limitations for each treatment technology option 

for FGD and gasification wastewaters, EPA determined that the 

statistical distributional assumptions used to develop the 

limitations are appropriate for the data, and thus the proposed 

limitations for each technology option are reasonable. (This 

conclusion is also true for the leachate limitations based on 

the chemical precipitation technology since the leachate 

limitations were transferred from the FGD wastewater technology 

option.) If a plant properly designs and operates its wastewater 

treatment system to achieve the option long-term average for the 

model technology (rather than targeting performance at the 

effluent limits themselves), it will be able to comply with the 

limitations.

However, EPA notes that some of the daily effluent values 

for the BAT plants used to calculate the limitations were found 

to exceed either the daily or monthly average effluent 
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limitations. See Section 13.9.1 for a detailed discussion of the 

comparison of the limitations and the effluent values, including 

a discussion of those effluent values that exceed the 

limitations. EPA solicits comment on this evaluation and EPA’s 

conclusion that plants with a properly designed and operating 

treatment system would be able to comply with the limitations.

2. Comparison of the Limitations to Influent Data 

In addition to comparing the proposed limitations to the 

data used to develop the limitations, EPA also compared the 

value of the proposed limitations to the influent concentration 

values. This comparison helps evaluate whether the proposed 

limitations are set at a level that ensures that treatment of 

the wastewater would be necessary to meet the limitations and 

that the influent concentrations were generally well-controlled 

by the treatment system. In doing so, EPA confirms that 

treatment to remove the regulated pollutants will take place. 

For all treatment technology options for both FGD and 

gasification wastewater, the minimum, average, and maximum 

influent concentration values were much higher than the longterm average and proposed limitations (see DCN SE01999). Thus, 

EPA determined that facilities would need to treat the 

wastewater to ensure compliance with the proposed limitations 

and that the proposed rule would result in removing the 

regulated pollutants and other pollutants of concern.
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Furthermore, in evaluating influent concentrations, EPA found 

that influent concentrations were generally well-controlled by

the treatment system for all plants with model technology. In 

general, the treatment systems adequately treated even the 

extreme influent values, and the high effluent values did not 

appear to be the result of high influent discharges.

EPA expects that facilities will comply with their effluent 

limitations at all times. If the exceedance is caused by an 

upset condition, the facility would have an affirmative defense 

to an enforcement action if the requirements of 40 CFR 122.41(n) 

are met. If an exceedance is caused by a design or operational 

deficiency, then EPA has determined that the facility’s 

performance does not represent the appropriate level of control.

For today’s proposed limitations, EPA has determined that such 

exceedances can be controlled by diligent process and wastewater 

treatment system operational practices such as frequent

inspection and repair of equipment, use of back-up systems, and 

operator training and performance evaluations. Additionally, 

some facilities may need to upgrade or replace existing 

treatment systems to ensure that the treatment system is 

designed to achieve performance to target the effluent 

concentrations at the option long-term average. This is 

consistent with EPA’s costing approach for the ELG technology 

options and its engineering judgment developed over years of 
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evaluating wastewater treatment processes for power plants and 

other industrial sectors. EPA recognizes that, as a result of 

the proposed rule, some dischargers, including those that are 

operating technologies representing the “best available” 

technology, may need to improve their treatment systems, process 

controls, and/or treatment system operations in order to 

consistently meet the effluent limitations. EPA believes that 

this is consistent with the Clean Water Act, which requires that 

discharge limitations reflect the best available technology

economically achievable or the best available demonstrated 

control technology.

XI. Economic Impact and Social Cost Analysis

A. Introduction

EPA assessed the social costs and the projected economic 

impacts of the fiveeight regulatory options described in today’s 

proposal (see Section VIII for a description of the options). 

This section provides an overview of the methodology EPA used to 

assess the social costs (or costs from the viewpoint of society 

rather than the regulated entity) and the economic impacts of 

the proposed ELGs and summarizes the results of these analyses. 

More details are available in the The Regulatory Impact Analysis

for Proposed Effluent Limitations Guidelines and Standards for 

the Steam Electric Power Generating Point Source Category (RIA) 

and Benefit-– EPA 821-R-13-005 and Benefits and Cost Analysis 
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for the Proposed Effluent Limitations Guidelines and Standards 

for the Steam Electric Power Generating Point Source Category 

(BCA) – EPA 821-R-13-004 reports available in the record for the 

rulemaking provide more details on these analyses, including 

discussion of uncertainties and limitations. 

EPA estimated the costs to electric power producers – which 

include steam electric plants owned by investor-owned utilities, 

municipalities, states, federal authorities, cooperatives, and 

nonutilities, whose primary business is electric power 

generation or related electric power services – of complying 

with the proposed ELGs. As described in Section VI of this 

preamble, EPA estimated th1that 1,079 power plants operated at 

least one steam electric generating unit subject to the ELGs in 

2009. EPA evaluated the costs and associated impacts of today’s 

proposal on these existing plants, and on new units that may be 

subject to the proposed revisions to the ELGs in the future. 

Plants that EPA estimates would incur compliance costs as a 

result of the proposed revisions to the ELGs are a subset of the 

1,079 steam electric power plants.67

 

67 As discussed in Section VIII, EPA is proposing different effluent limits

for existing oil-fired generating units and units with a capacity of 50 MW or 

less. Because today’s proposed rule would set BAT equal to BPT limits, EPA 

accordingly did not estimate incremental costs for these units as a result of 

this proposed rule. Many plants are comprised of multiple units, and as such, 

there may be costs associated with some but not all units at a plant. The 

plants may incur costs for other, larger units, however, if any such units 

are also present; EPA’s analysis includes costs for these larger units. 
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B. Annualized Compliance Costs

EPA’s analyses of costs and economic impacts use the plantlevel costs described in Section IX of this preamble. As 

described in that section, EPA developed plant-specific 

compliance costs for plants that generate a wastestream for 

which EPA evaluated new limitations and standards. Plantspecific compliance costs were developed for those plants for 

which EPA obtained detailed technical data through the industry 

survey. EPA applied survey weights to obtain costs for all 1,079 

steam electric plants. These costs consist of two principal 

components: initial planning and capital costs; and recurring 

operating and maintenance costs, which occur annually or 

according to a specified frequency (e.g., every 3 years, 5 

years, 6 years, or 10 years). EPA applied survey weights to 

obtain costs for all 1,079 steam electric plants. Since all 

plants incurring non-zero costs have a sample weight of 1, the 

sum of costs for the surveyed plants also represents the total 

costs for the entire universe of 1,079 plants.

EPA restated compliance costs, accounting for the specific 

years in which each plant is assumed to undertake compliancerelated activities and in 2010 dollars, using Construction Cost 

Index (CCI) from McGraw Hill Construction, the Employment Cost 

Index (ECI) published by the Bureau of Labor Statistics, and the 

Gross Domestic Product (GDP) deflator index published by the 
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U.S. Bureau of Economic Analysis (BEA). EPA used 2010 dollars 

based on data available at the time the analysis was developed. 

As a result, all dollar values reported in this analysis are in 

constant 2010 dollars.

EPA annualized the stream of future costs using 7 percent. 

The rate of 7 percent is used in the cost impact analysis as an 

estimate of the opportunity cost of capital.

EPA annualized one-time costs and costs recurring on other 

than an annual basis over a specific useful life, 

implementation, and/or event recurrence period, using a rate of 

7 percent. For capital costs and initial one-time costs, EPA 

used 20 years. For O&M costs incurred at intervals greater than 

one year, EPA used the interval as the annualization period 

(i.e., 3 years, 5 years, 6 years, 10 years). EPA added 

annualized capital, initial one-time costs, and the non-annual 

portion of O&M costs to annual O&M costs to derive total 

annualized compliance costs, where all costs are expressed on an 

equivalent constantly recurring annual cost basis. 

EPA uses pre- and/or after-tax compliance costs in 

different analyses, depending on the concept appropriate to each 

analysis (e.g., cost-to-revenue screening-level analyses 

discussed in Section XI.D are conducted using after-tax 

compliance costs, whereas social costs discussed in Section XI.C 

are calculated using pre-tax costs). For the assessment of 
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compliance costs, EPA considered costs on both a pre-tax and 

after-tax basis. Pre-tax costs provide insight on the total 

expenditure as incurred. After-tax costs are a more meaningful 

measure of compliance impact on privately owned for-profit 

plants, and incorporate approximate capital depreciation and 

other relevant tax treatments in the analysis. EPA calculated 

the after-tax value of compliance costs by applying combined 

federal and State tax rates to the pre-tax cost values for 

privately owned for-profit plants. For this adjustment, EPA used 

State corporate rates from the Federation of Tax Administrators 

(http://www.taxadmin.org/) combined with federal corporate tax 

rate schedules from the Department of the Treasury, Internal 

Revenue Service. 

Table XI-1 presents the total annualized compliance 

costcosts of the regulatory options on existing plants, 

estimated on a pre-tax and after-tax base. The table lists the 

eight options in order of increasing total annualized compliance 

costs. As shown in the table, after-tax annualized compliance 

costs range between $190.6108.4 million and $1.55 billion for 

options 1Options 3a and 5, respectively, with the preferred BAT 

and PSES options estimated to have annualized industry-wide 

after-tax costs of $108.4 million, $182.2 million, 

$389.0 million and $916.9, $635.7 million (after-tax), 

respectively for OptionsOptions3a, 3b, 3 and 4., and 4a. The 
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costs shown in Table XI-1 do not reflect the compliance costs 

for new sources. 

Table XI-1. Total Annualized Compliance Costs (in millions, 

2010$)

7% Discount Rate Pre-tax After-tax

7% 

Discount 

Rate

Option 13a Option 

2$168.1

Optio

n 3

Option 

$108.4

Optio

n 5

Option 3b $264.6 $182.2

Option 1 $265.9 $190.6

Option 2 $393.3 $280.6

Pre-tax $265.9Optio

n 3

$393561.3 $561.

3

$1,373.2389.

0

$2,27

7.3

Option 4a $947.8 $635.7

Aftertax

$190.6Optio

n 4

$280.61,373.

2

$389.

0

$916.9 $1,54

7.9

Option 5 $2,277.3 $1,547.9

The compliance costs above account for unit retirements, 

repowerings and conversions that have been announced by 

companies and are scheduled to occur by 2014, based on 

information obtained by EPA as of August 2012. But they do not 

reflect additional planned unit retirements, repowerings, and 

conversions that have been announced since August 2012, nor do 

they reflect announced retirements, repowerings, and conversions 

that are scheduled to occur by 2022. (See DCN SE02033, “Changes 

to Industry Profile for Steam Electric Generating Units 

Updates”). EPA estimates that accounting for these changes would 

reduce total annualized compliance costs. For example, EPA 

estimated that total pre-tax annualized compliance costs for 

Option 3 would go from $561.3 million to $532.8 million (5 

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percent reduction), whereas costs for Option 4 would go from 

$1,373.2 million to $1,252.9 million (9 percent reduction).

C. Social Costs

Social costs are the costs of the rule from the viewpoint 

of society as a whole, rather than regulated facilities. In 

calculating social costs, EPA tabulated the pre-tax costs in the 

year when they are incurred. EPA assumed that all plants subject 

to the proposed regulation that would need to upgrade their 

systems would install control technologies over a five-year 

period beginning in 2017. This accounts for the time plants 

would have to implement control technologies, as described in 

Section XVI. For the purpose of the economic analyses, EPA 

assumed that plants would implement control technologies 3 years 

after the renewal of their individual NPDES permit, following 

the promulgation year, with NPDES permits assumed to be renewed 

on time, following a 5-year cycle.68

EPA performed the social cost analysis over a 24-year 

analysis period, which combines the length of the period during 

which plants are expected to install the control technologies 

 

68 These assumed technology installation years do not necessarily correspond 

to the actual years in which individual facilities would be required to meet 

the effluent limits or standards as specified in their permit, but is a 

reasonable distribution of installation years for the aggregate set of steam 

electric plants incurring compliance costs. These assumptions reflect the 

approximate years in which technology installation would reasonably be 

expected to occur, assuming that expiring permits are renewed exactly on the 

5-year mark. Note that EPA also analyzed the effects of other technology 

installation periods. The results of these analyses are detailed in Appendix 

B of the RIA report.
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(five-year period beginning in 2017) and the useful life of the 

longest-lived compliance technology installed at any facility 

(20 years). Under this framework, the last year for which costs 

(and benefits) were tallied in the analysis is 2040. EPA 

calculated social cost of the fiveeight regulatory options for 

existing steam electric power plants using a 3 percent discount 

rate. EPA also calculated social costs using an alternative 

discount rate of 7 percent.69 For the analysis of social costs, 

EPA discounted all costs to the beginning of 2014, which is the 

expected promulgation year for the proposed rule.

As described in Section XVII.B, EPA does not believe the 

proposed rule would lead to additional costs to permitting 

authorities. Consequently, the only category of costs necessary 

to calculate social costs are compliance costs; social costs 

differ from pre-tax compliance costs due to timing of costs and 

discounting using a societal discount rate. 

Table XI-2 presents the total annualized social cost of the 

regulatory options on existing plants, calculated using 3 

percent and 7 percent discount rates. The table lists the eight 

options in order of increasing total social costs calculated 

using a 3 percent discount rate.

 

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

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

2003).
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Table XI-2. Total Annualized Social Costs (in millions, 2010$)

Discount 

Rate

Regulatory 

Option 1

Optio

n 2

Optio

n 3

Option 43% 

Discount Rate

Option 57% 

Discount Rate

Option 3a $185.2 $164.5

Option 1 $268.3 $259.2

Option 3b $281.4 $257.2

3% 

Discoun

t Rate

$268.3Opt

ion 2

$386.

8

$572.

1

$1,381.2386.8 $2,328380.8

Option 3 $572.0 $545.3

Option 4a $954.1 $914.7

7% 

Discoun

t Rate

$259.2Opt

ion 4

$380.

8

$545.

3

$1,323381.2 $1,323.2,209.

4

Option 5 $2,328.8 $2,209.4

At 3 percent discount rate, total annualized social costs 

for existing plants vary from $268185.2 million under Option 13a

to $2.3 billion under Option 5, with the preferred BAT and PSES 

options having total annualized social costs of $572 185.2 

million, $281.4 million, $572.0 million, and $954.1,381 million, 

respectively for Options 3a, 3b, 3 and 44a. The values presented 

in Table XI-2 for the 7 percent discount rate are slightly lower 

than the comparable values (pre-tax) presented in Table XI-1 due 

to the timing of compliance expenditures (e.g., $545.3 million 

versus $561.3 million, for Option 3).

These social costs do not reflect anticipated unit 

retirements and conversions anticipated through 2024. As noted 

in the previous Section, EPA anticipates that these changes 

would reduce total compliance costs incurred by the Steam 

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Electric power industry, and therefore reduce the social costs 

of this action.

D. Economic Impacts 

EPA assessed the economic impacts of the regulatory options 

in two ways: (1) a screening-level assessment of the impact of 

compliance costs on existing plants and the entities that own 

those plants, based on comparison of compliance costs to plant 

and entity revenue; and (2) an assessment of the impact of the 

proposed regulatory options for both existing and new plants 

within the context of the broader electricity market, which 

includes an assessment of incremental plant closures 

attributable to the proposed ELGs. EPA used the results of the 

screening-level assessment to inform the selection of regulatory 

options to be analyzed using the second approach. 

The following sections summarize the methods and findings 

for these analyses.

1. Screening-level Assessment of Impacts on Existing Plants and 

Parent Entities Incurring Compliance Costs Associated with this 

Proposed Rule

EPA conducted a screening-level analysis of the rule’s 

potential impact to existing steam electric plants and parent 

entities based on cost-to-revenue ratios. For each of the two 

levels of analysis (plant and parent entity), the Agency 

assumed, for analytic convenience and as a worst-case scenario, 
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that none of the compliance costs would be passed onto consumers 

through electricity rate increases and would instead be absorbed 

by complying plants and their parent entities. In performing 

these and other impact analyses, EPA used the survey weights to 

extrapolate impacts assessed initially for a sample of plants to 

all 1,079 steam electric plants and to their respective owning 

parent entities. 

a. Cost-to-Revenue Analysis for Plants Incurring Compliance 

Costs Associated with this Proposed Rule

EPA calculated the annualized after-tax compliance costs of 

the regulatory options as a percent of baseline annual 

revenues.70 Revenue estimates used in this analysis were 

developed using Energy Information Administration (EIA) data. 

(See Chapter 4 of the RIA report for a more detailed discussion 

of the methodology used for the plant-level cost-to-revenue 

analysis). 71

Table XI-3 summarizes the screening-level plant-level costto-revenue analysis results for the fiveeight main regulatory 

options. EPA estimates that the vast majority of plants subject 

to the proposed ELGs will incur annualized costs amounting to 

 

70 For private, tax-paying entities, after-tax costs are a more relevant 

measure of potential cost burden than pre-tax costs. For non tax-paying 

entities (e.g., State government and municipality owners of affected plants), 

the estimated costs used in this calculation include no adjustment for taxes.

71 To develop the average of year-by-year revenue values over the data years, 

EPA set aside from the averaging calculation, revenue values for years that 

are substantially lower than the otherwise “steady state average” – e.g., 

because of a generating unit being out of service for an extended period. 
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less than 1 percent of revenue for all fiveeight regulatory 

options (887 to 1,052051 plants, or 82 to 97 percent of the 

total 1,079 steam electric plants). A significant share of these 

plants incur no compliance costs. For the preferred BAT and PSES 

options (OptionOptions 3a, 3b, 3 and 4), 934a), 92 percent to 

9597 percent of steam electric plants have estimated costs that 

are less than 1 percent of revenue. The sharenumber of plants 

with ratios between 1 percent and 3 percent, and above 3 

percent, generally rises when moving from Option 33a to Option 

4, but drops slightly for Option 5 as costs for some plants 

exceed. For the preferred BAT and PSES options (Options 3a, 3b,

3 and 4a), two to six percent of plants have cost-to-revenue. 

The share of plants with ratios abovebetween 1 and 3 percent 

also rises when moving from Option 3 to Option 4, and continues 

to rise when movingand less than one percent to Option 5.two 

percent have ratios above 3 percent. 

Table XI-3. Plant-Level Cost-to-Revenue Analysis Results by 

Regulatory Optiona

Option

No Data on 

Revenueb

Number of Plants with Cost-To-Revenue 

Ratio of

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

Option 3a 5 1,008 43 22 1

Option 3b 5 994 54 24 2

Option 1 5 959 93 17 5

Option 2 5 959 86 18 11

Option 3 5 920 102 38 14

Option 4a 5 875 114 65 20

Option 4 5 798 111 117 48

Option 5 5 798 89 115 72
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Table XI-3. Plant-Level Cost-to-Revenue Analysis Results by 

Regulatory Optiona

Option

No Data on 

Revenueb

Number of Plants with Cost-To-Revenue 

Ratio of

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

a This analysis makes a counterfactual, conservative assumption of zero cost 

pass-through. Plant counts are weighted estimates.

b EIA does not report necessary data to estimate revenue for 5 plants.

b. Parent Entity-Level Cost-to-Revenue Analysis

EPA also assessed the economic impact of the fiveeight

regulatory options at the parent entity-level. The screeninglevel cost-to-revenue analysis at the parent entity level 

provides insight on the impact of compliance requirements on 

those entities that own more than one plant incurring compliance 

costs associated with this proposed rule. For this analysis, EPA 

identified the domestic parent entity of each plant and obtained 

the entity’s revenue from the industry survey or from publicly 

available data sources. In this analysis, the domestic parent 

entity associated with any given plant is defined as that entity 

that has the largest ownership share in the plant. 

For each parent entity, EPA compared the total annualized 

after-tax compliance costs, as of 2014, and the identified 

parent entity’s total revenue (see Chapter 4 of the RIA report 

for details). The total parent-level annualized after-tax 

compliance costs represent total costs for all steam electric 

plants in which the entity is the majority owner.
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Compliance costs for the regulatory options were developed

based on surveyed plants (see Section XI.D.1.a). For the parent 

entity-level analysis, EPA considered two approximate bounding 

cases to analyze the owners of all 1,079 steam electric plants, 

based on the survey weights developed from the industry survey. 

These cases, which are described in more detail in Chapter 4 of 

the RIA, provide a range of estimates for the number of entities 

incurring compliance costs and the costs incurred by any entity 

owning a steam electric plant. 

Table XI-4 summarizes the results of the entity-level 

analysis for the two analytic cases and the eight regulatory 

options.

Table XI-4: Parent Entity-Level After-Tax Annual Compliance Costs 

as a Percentage of Revenuea

Optio

n

Total 

Numbe

r of 

Entit

ies

Not 

Analyzed 

Due to 

Lack of 

Revenue 

Informatio

n

Number and Percentage with After Tax Annual 

Compliance Costs/Annual Revenue of:

0% 0-1% 1-3%

3% or 

Greater

# % # % # % # % # %

Case 1: Lower-bound estimate of number of entities owning steam electric 

plants; upper bound estimate of total compliance costs that an entity 

may incur

Optio

n 3a 243 14 6% 205 84% 22 9% 2 1% 0 0%

Optio

n 3b 243 14 6% 201 83% 26 11% 2 1% 0 0%

Optio

n 1 243 14 6% 173 71% 51 21% 1 <1% 4 2%

Optio

n 2

243 14 6% 173 71% 46 19% 6 2% 4 2%

Optio

n 3 243 14 6% 168 69% 49 20% 7 3% 5 2%

Optio

n 4a 243 14 6% 157 65% 55 23% 11 5% 6 2%
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Table XI-4: Parent Entity-Level After-Tax Annual Compliance Costs 

as a Percentage of Revenuea

Optio

n

Total 

Numbe

r of 

Entit

ies

Not 

Analyzed 

Due to 

Lack of 

Revenue 

Informatio

n

Number and Percentage with After Tax Annual 

Compliance Costs/Annual Revenue of:

0% 0-1% 1-3%

3% or 

Greater

# % # % # % # % # %

Optio

n 4 243 14 6% 137 56% 64 26% 21 9% 7 3%

Optio

n 5 243 14 6% 137 56% 57 23% 20 8% 15 6%

Case 2: Upper-bound estimate of number of entities owning steam electric 

plants; lower bound estimate of total compliance costs that an entity 

may incur

Optio

n 3a 507 30 6% 453 89% 22 4% 2 <1% 0 0%

Optio

n 3b 507 30 6% 449 89% 26 5% 2 <1% 0 0%

Optio

n 1 507 30 6% 421 83% 51 10% 1 <1% 4 1%

Optio

n 2 507 30 6% 421 83% 46 9% 6 1% 4 1%

Optio

n 3 507 30 6% 416 82% 49 10% 7 1% 5 1%

Optio

n 4a 507 30 6% 405 80% 55 11% 11 2% 6 1%

Optio

n 4 507 30 6% 385 76% 64 13% 21 4% 7 1%

Optio

n 5 507 30 6% 385 76% 57 11% 20 4% 15 3%

# equals the number of entities.

a. This analysis makes a counterfactual, conservative assumption of zero cost 

pass-through.

The cost-to-revenue ratios provide screening-level 

indicators of potential economic impacts. Entities incurring 

costs below 1 percent of revenue are unlikely to face economic 

impacts, while entities with costs between 1 percent and 3 

percent of revenue have a higher chance of facing economic 

impacts, and entities incurring costs above 3 percent of revenue 
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have a still higher probability of economic impacts. As 

presented in Table XI-4, EPA estimated that the number of 

entities owning steam electric plants ranges from 243 (lower 

bound estimate) to 507 (upper bound estimate), depending on the 

assumed ownership structure of plants not surveyed. Under the 

lower-bound case, EPA estimates that the vast majority of parent 

entities will incur annualized costs of less than 1 percent of 

revenues under all fiveeight analyzed regulatory Options (92, 

90the shares are 93, 93, 89, 82, and 7987 percent under Options 

1, 23a, 3, 4, and 54a, respectively). These observations also 

hold true under the upper bound case; an estimated 9394, 94, 92, 

92, 89, and 8791 percent of parent entities incur annualized 

costs of less than 1 percent of revenue, for Options 1, 23a, 3b, 

3, 4, and 54a, respectively. 

Overall, this screening-level analysis shows that the 

entity-level compliance costs are low in comparison to the 

entity-level revenues; very few entities are likely to face 

economic impacts at any level for eitherany of the twofour

preferred BAT and PSES options (Options 3a, 3b, 3 and 44a).

2. Assessment of the Impacts in the Context of Electricity 

Markets

In analyzing the impacts of regulatory actions affecting 

the electric power sector, EPA has sometimes used the Integrated 

Planning Model (IPM), a comprehensive electricity market 
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optimization model that can evaluate such impacts within the 

context of regional and national electricity markets. The model 

is designed to evaluate the effects of changes in production 

costs at the level of the individual generating unit, on the 

total cost of electricity supply, subject to specified demand 

and emissions constraints. To assess facility and market-level 

effects of today’s proposed ELGs, EPA used an updated version of 

this same analytic system: Integrated Planning Model Version 

4.10 MATS (IPM V4.10). 

Use of a comprehensive, market analysis system is important

in assessing the potential impact of the regulatory options 

because of the interdependence of electricity generating units 

in supplying power to the electric transmission grid. Increases 

in electricity production costs at some plants can have a range 

of broader market impacts affecting other plants, including the 

likelihood that various plants are dispatched, on average. 

IPM V4.10 provides outputs for the North American Electric 

Reliability Corporation (NERC) regions that lie within the 

continental United States. IPM V4.10 does not analyze electric 

power operations in Alaska and Hawaii because these states’ 

electric power operations are not connected to the continental 

U.S. power grid. However, none of the steam electric plants that

are estimated to incur compliance costs associated with today’s 

proposal are located in these two regions.
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IPM V4.10 is based on an inventory of U.S. utility- and 

non-utility-owned boilers and generators that provide power to 

the integrated electric transmission grid, as recorded in the 

Department of Energy’s Energy Information Administration 

databases EIA 860 (2006) and EIA 767 (2005).) databases.

72 The 

IPM baseline universe of plants includes nearly all of the steam 

electric plants that could be subject to the proposed ELGs and 

are estimated to incur compliance costs.73 IPM Version 4.10 

embeds a baseline energy demand forecast that is derived from 

the Department of Energy’sDOE’s Annual Energy Outlook 2010 

(AEO2010). IPM V4.10 also incorporates in its analytic baseline 

the expected compliance response to existing regulatory 

requirements for the following promulgated air regulations 

affecting the power sector: the final Mercury and Air Toxics 

Standards (MATS) rule; the final Cross-State Air Pollution Rule 

(CSAPR)74; regulatory SO2 emission rates arising from State 

 

72 In some instances, plant information has been updated to reflect known 

material changes in a plant’s generating capacity since 2006.

73 The IPM plant universe excludes two steam electric plants estimated to 

incur compliance costs under the proposed ELG scenarios EPA analyzed in IPM. 

See Chapter 5 of the RIA report for more details.

74 On August 21, 2012, the D.C. Circuit Court of Appeals issued an opinion 

that would vacate CSAPR. As CSAPR does not address mercury emissions, the 

rule was not expected to result in any additional activated carbon injection 

and therefore has no impact on the analysis in this rulemaking. For the 

purposes of the impact analysis of this effluent guidelines rulemaking, EPA 

made a conservative assumption that all of the previously projected wet 

scrubber additions in the CSAPR-inclusive baseline for this action would 

continue to be built, and that those additional wet scrubbers would therefore 

be subject to the effluent guidelines in this proposal. 74 EPA’s Cross-State 

Air Pollution Rule (CSAPR) was promulgated to replace EPA’s Clean Air 

Interstate Rule (CAIR), which had been remanded to EPA in 2008. However, on 

December 30, 2011, the U.S. Court of Appeals for the D.C. Circuit stayed 
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Implementation Plans (SIP); Title IV of the Clean Air Act 

Amendments; NOx SIP Call trading program; Clean Air Act 

Reasonable Available Control Technology requirements and Title 

IV unit specific rate limits for NOx; the Regional Greenhouse 

Gas Initiative; Renewable Portfolio Standards; New Source Review 

Settlements; and several state-level regulations affecting 

emissions of SO2, NOx, and mercury that are already in place or 

expected to come into force by 2017.

In contrast to the screening-level analyses, which are 

static analyses and do not account for interdependence of 

electric generating units in supplying power to the electric 

transmission grid, IPM accounts for potential changes in the 

generation profile of steam electric and other units and 

consequent changes in market-level generation costs, as the 

electric power market responds to higher generation costs for 

steam electric units due to the proposed ELGs. IPM is also 

dynamic in that it is capable of using forecasts of future 

conditions to make decisions for the present. Additionally, in 

 

CSAPR pending judicial review and left CAIR in place. On August 21, 2012 the 

Court issued an opinion vacating CSAPR and again leaving CAIR in place 

pending development of a valid replacement. On March 29, 2013, the United 

States filed a petition asking the Supreme Court to review the D.C. Circuit’s 

opinion. Nevertheless, as explained above, CAIR remains in effect at this 

time. In light of the continuing uncertainty on CAIR and CSAPR, EPA does not 

believe it would be appropriate or possible at this time to adjust emission 

projections on the basis of speculative alternative emission reduction 

requirements in 2020. EPA expects that the decision vacating CSAPR and 

leaving CAIR in place has a minimal effect on the results of the analysis 

conducted in support of the proposed ELGs.
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contrast to the screening-level analyses in which EPA assumed no 

pass through of compliance costs, IPM depicts production 

activity in wholesale electricity markets where some recovery of 

compliance costs through increased electricity prices is 

possible but not guaranteed.

In performing analyses based on IPM V4.10, EPA used as its 

baseline – i.e., reflecting the world without this proposed 

regulation – a projection of electricity markets and facility 

operations over the period from the expected promulgation year, 

2014, through 2030. As discussed above, this baseline accounts 

for compliance with the recently promulgated federal air rules. 

EPA then overlaid this analysis with the estimated compliance 

costs for steam electric plants incurring costs associated with 

this proposed rule under selected regulatory options (postcompliance cases).

As discussed in greater detail in Appendix C of the RIA, 

IPM generates least-cost resource dispatch decisions based on 

user-specified constraints such as environmental, demand, and 

other operational constraints. In analyzing the proposed ELGs, 

EPA specified additional fixed and variable costs that are 

expected to be incurred by specific steam electric plants and 

generating units to comply with the proposed ELGs. EPA then ran 

IPM including these additional costs to determine the dispatch 

of electricity generating units that would meet projected demand 
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at the lowest costs, subject to the same constraints as those 

present in the analysis baseline. The least-cost dispatch 

solution for meeting electricity supply may change as the result 

of the changes in fixed and variable costs at the level of the 

individual plant and generating unit, which EPA estimates would 

occur as a result of the proposed ELGs. These estimated changes 

in plant- and unit-specific production levels and costs – and, 

in turn, changes in total electric power sector costs and 

production profile – are key data elements in evaluating the 

expected national and regional effects of the proposed ELGs. 

EPA used the screening-level analyses described above to 

inform the selection of regulatory options to be analyzed using 

IPM. In allocating resources to analytical effort, EPA chose to 

run IPM in a phased approach, starting with Option 3 and then 

Option 4, with the notion to proceed if additional model runs 

were warranted. 

EPA first analyzed a scenario developed based on Option 3 

but where the total compliance costs and the set of existing 

plants that are assigned costs varied slightly from those in the 

Option 3 discussed in other parts of this preamble.75 Thus, the 

Option 3 scenario analyzed using IPM and discussed below did not 

 

75 The costs as analyzed in IPM differ slightly from those used in the non-IPM 

analyses. For more details on these differences, see Chapter 5 of the RIA 

report. Note that the scenario assigns compliance costs for existing plants 

based on Option 3, and compliance costs for new capacity projected in IPM 

based on Option 4.
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include small changes to the timing of some O&M costs and to the 

set of plants assigned compliance costs for this option. Because 

of these changes and the need to protect data claimed as CBI by 

plant owners, total compliance costs for Option 3 as analyzed in 

IPM are approximately 10 percent lower than for the proposed 

Option 3 discussed in the rest of this document. EPA also 

analyzed a scenario in IPM that corresponds to BAT and PSES

Option 4 discussed elsewhere in this notice.

76 Both scenarios 

analyzed in IPM included NSPS and PSNS compliance costs for new 

coal generation, based on the preferred Option 4 for new 

sources.

The two scenarios analyzed in IPM provide insight on the 

market impacts of the regulatory options EPA considered for this 

proposal. Options 3 and 4 as analyzed in IPM are similar enough 

to today’s proposed Options 3 and 4 to provide valuable insight 

on the likely impacts of the proposed ELGs. Options 3a, 1, 2,

and 23b are less stringent than either of the two other options 

analyzed in IPM; as discussed further below, the relatively 

small impacts observed when analyzing the Option 3 scenario 

suggest that the impacts of Options 3a, 1, 2 and 23b would be 

less than Option 3. EPA did not analyze Option 4a due to time 

and resource constraints, but expects that this option could 

 

76 Compliance costs differ only slightly (1 percent lower) from costs used in 

other analyses, primarily to avoid disclosing CBI. There are no differences 

in the set of plants estimated to incur compliance costs or in the timing of 

the costs. For more details, see Chapter 5 of the RIA report.
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have impacts between those of Options 3 and 4. EPA did not 

analyze Option 5 based on screening-level analysis results, 

which showed that compliance costs could result in financial 

stress to some entities owning steam electric plants. As shown 

in Section XI.D.1, under Option 5, about three times as many 

entities owning steam electric plants would incur costs that 

exceed 3 percent of revenue than under Options 3 (15 versus 5 

entities). Twice as many entities owning steam electric power 

plants are estimated to incur costs that exceed 3 percent of 

revenue under Option 5, when compared to Option 4 (15 versus 7 

entities). As discussed in Section XVII.C, the potential cost 

impacts to small entities are also greater under Option 5 than 

under Options 3 and 4.

The IPM V4.10 runs provide analysis results for selected 

run-years: 2020 and 2030. These analysis years, each of which 

represents multiple years, take into account the expected 

promulgation year for today’s proposed ELGs (2014) and the years 

in which all plants would be expected to install compliance 

technology (five-year period beginning in 2017). In the 

following sections, EPA reports results for the run-year 2030, 

which represents years 2025-2034, by which time all plants 

subject to this rulemaking will meet the revised guidelines and 

standards (i.e.,and all compliance costs will be reflected in 

production costs (i.e., steady state of post-compliance 
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operations). EPA considered impact metrics of interest at three 

levels of aggregation: (1) impact on national and regional 

electricity markets (i.e., all electric power generation, 

including steam and non-steam plants), (2) impact on steam 

electric power generating plants as a group (i.e., the 1,079 

plants subject to the proposed ELGs, not all of which are 

projected to incur compliance costs), and (3) impact on 

individual steam electric plants incurring compliance costs.

All results presented below are representative of modeled 

market conditions in the years 2025-2034. While costs are in 

2010 dollars, they are reflective of costs in the modeled years 

and are not discounted to the start of EPA’s analysis period of 

2014.77

a. Impact on National and Regional Electricity Markets

For the assessment of market level electricity impacts, EPA 

considered five output metrics from IPM V4.10: (1) incremental 

early retirements and capacity closures, calculated as the 

difference between capacity under the regulatory options and 

capacity under the baseline, which includes both full plant 

closures and partial plant closures (i.e., unit closures) in 

 

77 In contrast, the social cost estimated in Section XI.C reflects the 

discounted value of compliance costs over the entire 24-year period of 

analysis, as of 2014. Additionally, screening-level analyses presented in 

earlier sections are static analyses and do not account for interdependence 

of electric generating units in supplying power to the electric transmission 

grid. In contrast, IPM accounts for potential changes in generation profile 

of steam electric and other units and consequent changes in market-level 

generation costs, as the electric power market responds to higher generation 

costs for steam electric units due to the proposed ELG. 
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aggregate capacity terms; (2) incremental capacity closures as a 

percentage of baseline capacity; (3) post-compliance changes in 

variable production costs per MWh, calculated as the sum of 

total fuel and variable O&M costs divided by net generation; (4) 

changes in annual costs (fuel, variable O&M, fixed O&M, and 

capital); and (5) post-compliance changes in energy price, where 

electricity prices are defined as the wholesale prices received 

by plants for the sale of electricity they generate. 

Table XI-5 presents results for the two market model 

analysis scenarios. The table provides the baseline capacity and 

the values of each of the five metrics above, with national 

totals and detail at level of regional electricity markets 

defined on the basis of the eight NERC regions defined in IPM.

Additional results are presented in Chapter 5 of the RIA 

report. Chapter 5 also presents a more detailed interpretation 

of the results of the market-level analysis. 

Table XI-5. Impact of Market Model Analysis Options on National 

and Regional Markets at the Year 2030

NERC 

Region

Baseli

ne 

Capaci

ty 

(GW)

Incremental 

Early 

Retirements / 

Closuresa

Change in 

Variable 

Production 

Cost 

(2010$/MWh 

or % of 

Baseline)

Change in 

Annual 

Costs 

(Million 

2010$ or % 

of 

Baseline)

Change in 

Electricity 

Price 

(2010$/MWh 

or % of 

Baseline)

Capaci

ty 

(GW)

% of 

Baseli

ne 

Closur

es

Option 3

ERCOT 98 0 0.0% $0.11 0.3% $72 0.4% $0.21 0.3%

FRCC 68 0 0.0% $0.14 0.3% $49 0.3% $0.23 0.3%

MRO 76 0 0.0% $0.02 0.1% $53 0.4% $0.03 0.1%
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Table XI-5. Impact of Market Model Analysis Options on National 

and Regional Markets at the Year 2030

NERC 

Region

Baseli

ne 

Capaci

ty 

(GW)

Incremental 

Early 

Retirements / 

Closuresa

Change in 

Variable 

Production 

Cost 

(2010$/MWh 

or % of 

Baseline)

Change in 

Annual 

Costs 

(Million 

2010$ or % 

of 

Baseline)

Change in 

Electricity 

Price 

(2010$/MWh 

or % of 

Baseline)

Capaci

ty 

(GW)

% of 

Baseli

ne 

Closur

es

NPCC 73 0 0.0% $0.06 0.2% $15 0.1% $0.19 0.3%

RFC 237 0 0.0% $0.12 0.5% $276 0.5% $0.19 0.3%

SERC 274 0 0.0% $0.17 0.6% $322 0.6% $0.24 0.4%

SPP 59 0 -0.7% $0.08 0.3% $35 0.3% $0.17 0.3%

WECC 220 0 0.0% $0.05 0.2% $50 0.1% $0.15 0.2%

Total 1,106 0 0.0% $0.11 0.4% $872 0.4% N/A

Option 4

ERCOT 98 0 0.0% $0.14 0.4% $85 0.5% $0.07 0.1%

FRCC 68 0 0.0% $0.15 0.1% $33 0.2% $0.09 0.1%

MRO 74 0 0.0% $0.11 0.5% $134 1.0% -

$0.05 -0.1%

NPCC 73 0 0.06% $0.03 0.1% $32 0.2% $0.04 0.1%

RFC 237 1 0.3% $0.29 1.1% $804 1.5% $0.15 0.2%

SERC 274 0 0.0% $0.28 1.0% $662 1.2% $0.19 0.3%

SPP 60 0 -0.6% $0.15 0.5% $72 0.7% $0.09 0.2%

WECC 220 0 0.0% $0.03 0.1% $52 0.1% $0.04 0.1%

Total 1,106 0 0.0% $0.18 0.6% $1,87

4

0.9% N/A

a Values for incremental early retirements or closures represent change 

relative to the baseline run. IPM may show partial (i.e., unit) or full 

plant early retirements (closures) for a given option. It may also show 

avoided closures (negative closure values) in which a unit or plant that 

is projected to close in the baseline, is estimated to continue operating 

in the post-compliance case. Avoided closures may occur among plants that 

incur no compliance costs or for which compliance costs are low relative 

to other steam electric plants. 78

ERCOT (Electric Reliability Council of Texas), FRCC (Florida Reliability 

Coordinating Council), MRO (Midwest Reliability Organization), NPCC 

(Northeast Power Coordination Council), RFC (ReliabilityFirst 

Corporation), SERC (Southeastern Electricity Reliability Council), SPP 

(Southwest Power Pool), and WECC (Western Electricity Coordinating 

Council)

As shown in Table XI-5, the Market Model Analysis indicates 

that Option 3 would have very small effects in overall 

 

78 Given the design of IPM, unit-level and thereby plant-level projections are 

presented as an indicator of overall regulatory impact rather than a 

prediction of future unit- or plant-specific compliance actions. 
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electricity markets, on both a national and regional sub-market 

basis, in the year 2030. Overall at the national level, the net 

change in total capacity, including reductions in capacity 

(which includes early retirements) and capacity additions in new 

plants/units, results in approximately 1GW of additional 

capacity (less than 0.05 percent total market capacity), which 

is too small to appear in Table XI-5. This increase in capacity 

is expected to take place entirely in the SPP NERC region (0.088

percent of total SPP capacity) and is the result of reduction in 

retired capacity (avoided capacity closures) and increase in new 

capacity and capacity at existing generating units.79

Consequently, Option 3 is expected to have negligible effect on 

capacity availability and supply reliability at the national 

level. Overall impacts on electricity prices are similarly 

minimal. While electricity prices are expected to increase in 

all NERC regions, the magnitude of this increase varies across 

regions and ranges from $0.03 per MWh (0.1 percent) in MRO to 

$0.24 per MWh (0.4 percent) in SERC. Finally, at the national 

level, total costs increase by approximately 0.4 percent of the 

baseline value – again, a modest amount. Across regions, no NERC 

 

79 Avoided capacity closures occur when one or more generating units that are 

otherwise projected to cease operations in the baseline become more 

economically attractive sources of electricity in the post-compliance case, 

because of relative changes in the economics of electricity production across 

the full market, and thus avoid closure.
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region records an increase in power sector total costs exceeding 

1 percent. 

The findings for Option 4 overall lie very close to those 

of Option 3. Similar to Option 3, the net change in total 

capacity under Option 4 is essentially zero, indicating that 

this option would be expected to have a negligible effect on 

capacity availability and supply reliability, at the national 

level. This is also the case at the regional level, with small 

capacity changes in RFC (early retirement) and SPP (avoided 

retirement). Option 4 also has a slight impact on electricity 

prices across all NERC regions, with increases of no more than 

0.3 percent and a 0.1 percent reduction in the MRO region. At 

the national level, variable production costs – fuel and 

variable O&M – increase by $0.18 per MWh or 0.6 percent. While 

variable costs increase in all NERC regions, the change varies 

by region ranging from $0.03 per MWh in NPCC and WECC to $0.29 

in RFC. As expected for Option 4, which is more expensive than 

Option 3, the increase in total annual costs for the electric 

power sector is greater than under Option 3. At the national 

level, total annual costs increase by $1.9 billion (0.9 

percent). As discussed in greater detail in Chapter 5 of the RIA 

document, the largest shares of this increase occur in variable 

O&M; capital costs increase by a much smaller amount. As 

discussed above, EPA expects the impacts of Options 3a and 3b to 
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be smaller than those of Option 3, and the impacts of Option 4a 

to be between those of Options 3 and 4.

b. Impact on Existing Steam Electric Plants

EPA used IPM V4.10 results for 2030 to assess the potential 

impact of the regulatory options on steam electric plants. In 

contrast to the previously described electricity market-level 

analysis, which sought to assess the impact of the proposed ELGs

regulatory options on the entire electric power sector, the 

purpose of this second analysis is to assess impacts on steam 

electric plants specifically. 

Table XI-6 reports results for steam electric plants, as a 

group. In this case, EPA looked at the following metrics IPM 

produces: (1) incremental early retirements and capacity 

closures, calculated as the difference between capacity under 

the regulatory options and capacity under the baseline, which 

includes both full plant closures and partial plant closures 

(i.e., unit closures) in aggregate capacity terms; (2) 

incremental capacity closures as a percentage of baseline 

capacity; (3) post-compliance change in electricity generation; 

(4) post-compliance changes in variable production costs per 

MWh, calculated as the sum of total fuel and variable O&M costs 

divided by net generation; and (5) changes in annual costs 

(fuel, variable O&M, fixed O&M, and capital. Items (1) and (2) 
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are instrumental in determining the economic achievability of 

various regulatory options.

Table XI-6. Impact of Market Model Analysis Options on Steam 

Electric Plants as a Group at the Year 2030

NERC 

Region

Baseli

ne 

Capaci

ty 

(MW)

Incremental 

Early 

Retirements / 

Closuresa

Change in 

Total 

Generation 

(GWh or % 

of

Baseline)

Change in 

Variable 

Production 

Cost 

(2010$/MWh 

or % of 

Baseline)

Change in 

Annual 

Costs 

(Million 

2010$ or % 

of 

Baseline)

Capaci

ty 

(MW)

% of 

Baseli

ne 

Closur

esCapa

city

Option 3

ERCOT 32,275 0 0.0% -83 0.0% $0.09 0.3% $35 0.5%

FRCC 32,227 0 0.0% -25 0.0% $0.11 0.3% $27 0.4%

MRO 34,899 0 0.0% 83 0.0% -

$0.02 -0.1% $26 0.3%

NPCC 16,629 0 0.0% -3 0.0% $0.07 0.2% $9 0.2%

RFC 122,205 0 0.0% 234 0.0% $0.15 0.5% $225 0.7%

SERC 131,895 0 0.0% -

1,140

-0.2% $0.24 0.8% $283 0.8%

SPP 31,269 -102 -

5.90.3%

-123 -0.1% $0.04 0.1% $15 0.2%

WECC 54,494 0 0.0% 103 0.0% $0.05 0.2% $22 0.2%

Total 455,894 -102 -0.50% -954 0.0% $0.13 0.5% $642 0.6%

Option 4

ERCOT 32,275 0 0.0% -227 -0.1% $0.16 0.5% $66 1.0%

FRCC 32,227 0 0.0% 78 0.1% $0.05 0.1% $27 0.4%

MRO 34,899 0 0.0% 212 0.1% $0.12 0.5% $108 1.4%

NPCC

16,629 -431

-

21.82.6

%

-4 0.0%

$0.10 0.3%

$29 0.7%

RFC 122,205 681 15.10.6

%

-

2,351

-0.3% $0.38 1.3% $561 1.8%

SERC 131,895 0 0.01%

-

2,178

-0.3% $0.43 1.5% $607 1.8%

SPP 31,269 -30 -0.1.7% -510 -0.3% $0.16 0.6% $59 0.9%

WECC 54,494 0 0.0% 63 0.0% $0.07 0.3% $46 0.4%

Total 455,894 317 0.1.4%

-

4,916

-0.2% $0.28 1.0% $1,50

4

1.4%

a Values for incremental early retirements or closures represent change 

relative to the baseline run. IPM may show partial (i.e., unit) or full 

plant early retirements (closures) for a given option. It may also show 

avoided closures (negative closure values) in which a unit or plant that 

is projected to close in the baseline, is estimated to continue 

operating in the post-compliance case. Avoided closures may occur among 

plants that incur no compliance costs or for which compliance costs are 
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Table XI-6. Impact of Market Model Analysis Options on Steam 

Electric Plants as a Group at the Year 2030

NERC 

Region

Baseli

ne 

Capaci

ty 

(MW)

Incremental 

Early 

Retirements / 

Closuresa

Change in 

Total 

Generation 

(GWh or % 

of

Baseline)

Change in 

Variable 

Production 

Cost 

(2010$/MWh 

or % of 

Baseline)

Change in 

Annual 

Costs 

(Million 

2010$ or % 

of 

Baseline)

Capaci

ty 

(MW)

% of 

Baseli

ne 

Closur

esCapa

city

low relative to other steam electric plants. 80

Under Option 3, the net change in total capacity for steam 

electric plants is very small; this is similar to prior findings 

when considering the electricity market as a whole. For the 

group of steam electric plants, total capacity increases by 106 

MW (not shown in Table XI-6, see RIA for details) or 

approximately 0.02 percent of the 455,894 MW baseline capacity. 

This results in part from avoided capacity closures of 102 MW in 

the SPP region. Option 3 results in no closures, full (plant) or 

partial (unit), in the other seven regions.

The change in total generation is an indicator of how steam 

electric plants fare, relative to the rest of the electricity 

market. While at the market level there is essentially no 

projected change in total electricity generation,81 for steam 

electric plants, total available capacity and electricity 

 

80 Given the design of IPM, unit-level and thereby plant-level projections are 

presented as an indicator of overall regulatory impact rather than a 

prediction of future unit- or plant-specific compliance actions. 

81 At the national level, the demand for electricity does not change between 

the baseline and the analyzed regulatory options (generation within the 

regions is allowed to vary) because meeting demand is an exogenous constraint 

imposed by the model.
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generation at the national level is projected to fall by less 

than 0.1 percent. At the regional level, five NERC regions –

ERCOT, NPCC, RFC, SERC, and SPP – are projected to experience a 

reduction in electricity generation from steam electric plants, 

ranging from 3 GWh in NPCC (less than 0.01 percent) to 1,140 GWh 

in RFC (0.2 percent). The other three NERC regions are each 

projected to experience a very modest increase in electricity 

generation from steam electric plants of less than 0.1 percent. 

Finally, at the national level, variable production costs 

at steam electric plants increase by approximately 0.5 percent. 

These effects vary by region from about -0.1 percent in MRO to 

0.8 percent in SERC. These findings of very small national and 

regional effects in these impact metrics confirm EPA’s 

assessment that Option 3 can be expected to have little economic 

consequence in national and regional electricity markets.

Results of the analysis for Option 4 show almost no change 

in either total generating capacity or electricity generation 

for the electric power sector as whole, and steam electric 

generating capacity and electricity generation fall slightly by 

306 MW (0.07 percent) (not shown in Table XI-6, see RIA for 

details) and 4,916 GWh (0.2 percent), respectively. The steam 

electric capacity reduction includes early retirement and 

avoided retirement of generating units with the net effect of 

the two types of changes being capacity losses. Thus, under the 
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analysis for Option 4, 14 generating units close (1,125 MW) and 

5 generating units avoid closure (808 MW), leading to an 

estimated net closure of nine generating units (317 MW, see 

Table XI-6). All 14 units that are projected to close in this 

scenario are located within six plants that are projected to 

continue operating. In other words, Option 4 is not projected to 

result in any full plant closures.82

Findings for the change in total costs and variable 

production costs under Option 4 also exceed those under Option 

3. There is a 1.4 percent increase in total costs at the 

national level, with SERC recording the largest increase of 1.8 

percent. As detailed in Chapter 5 of the RIA document, at the 

national level, the increase in total costs occurs in fixed and 

variable O&M (3.2 percent and 9.3 percent, respectively) while 

fuel costs and capital costs decline (0.4 percent and 3.2 

percent, respectively). At the national level, variable 

production costs increase by 1.0 percent, with SERC recording 

the highest increase of 1.5 percent. As for impacts on national 

and regional markets, EPA expects the impacts on steam electric 

plants of Options 3a and 3b to be smaller than those of Option 

3, and the impacts of Option 4a to be between those of Options 3 

and 4.

 

82 Given the design of IPM, unit-level and thereby plant-level projections are 

presented as an indicator of overall regulatory impact rather than a 

prediction of future unit- or plant-specific compliance actions. 
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c. Impact on Individual Steam Electric Plants Incurring 

Compliance Costs under this Rulemaking

Results for the group of steam electric plants as a whole 

may mask shifts in economic performance among individual plants 

incurring compliance costs associated with today’s proposed 

ELGs. To assess potential plant-level effects, EPA analyzed 

plant-specific changes between the base case and the postcompliance cases for the following metrics: (1) capacity 

utilization (defined as annual generation (in MWh) divided by 

[capacity (MW) times 8,760 hours]) (2) electricity generation, 

and (3) variable production costs per MWh, defined as variable 

O&M cost plus fuel cost divided by net generation. 

Table XI-7 presents the estimated number of plants 

incurring compliance costs with specific degrees of change in 

operations and financial performance for the two regulatory 

options EPA analyzed using IPM. Metrics of interest include the 

number of plants with reductions in capacity utilization or 

generation (on left side of the table), and the number of plants 

with increases in variable production costs (on right side of 

the table).

Table XI-7. Impact of Market Model Analysis Options on 

Individual Steam Electric Plants Incurring Compliance Costs at 

the Year 2030 -- Number of Plants by Impact Magnitude

Economic Measures

Reduction

No 

Change

Increase

N/Ab 3%

1an

d 

<3% <1% <1%

1and 

<3% 3%
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Table XI-7. Impact of Market Model Analysis Options on 

Individual Steam Electric Plants Incurring Compliance Costs at 

the Year 2030 -- Number of Plants by Impact Magnitude

Economic Measures

Reduction

No 

Change

Increase

N/Ab 3%

1an

d 

<3% <1% <1%

1and 

<3% 3%

Option 3

Change in 

Capacity 

Utilizationa

6 7 62 438 41 4 6 101

Change in 

Generation

15 3 53 443 38 4 8 101

Change in 

Variable 

Production 

Costs/MWh

2 3 183 72 239 28 23 115

Option 4

Change in 

Capacity 

Utilizationa

6 4 131 291 113 7 9 104

Change in 

Generation

12 4 118 302 104 6 15 104

Change in 

Variable 

Production 

Costs/MWh

2 2 136 46 225 99 37 118

a. The change in capacity utilization is the difference between the capacity 

utilization percentages in the base case and post-compliance cases. For 

all other measures, the change is expressed as the percentage change 

between the base case and post-compliance values.

b. Plants with status changes in either baseline or post-compliance scenario 

have been excluded from these calculations. For example, for a plant that 

is projected to close in the post-compliance case, the reduction in 

variable costs per MWh of generated electricity would be 100 percent. 

Specifically, there are 23 full baseline plant closures, 77 partial 

baseline plant closures, and 1 avoided plant closure under Option 3. 

There are 23 full baseline plant closures, 72 partial baseline plant 

closures, 3 avoided plant closures, and 6 partial policy plant closures 

under Option 4.

For Option 3, the analysis of changes in individual plants 

indicates that most plants experience only slight effects – no 

change, or less than a 1 percent reduction or 1 percent 

increase. Only 13 plants (2 percent) are estimated to incur a 

reduction in capacity utilization exceeding 1 percent and 18
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plants (3 percent) incur a reduction in generation exceeding 1 

percent. The estimated change in variable production costs is 

higher; 51 plants (8 percent) incur an increase in variable 

production costs exceeding 1 percent; for 23 of these plants, 

this increase exceeds 3 percent. 

Results for Option 4 show greater effects as compared to 

Option 3. While the difference in the policy impact on capacity 

utilization and generation is small, the difference in policy 

impact on variable costs is greater. The reduction in capacity 

utilization and generation is estimated to exceed 1 percent for 

10 and 16 plants (approximately 2 percent), respectively. The 

increase in variable production costs is estimated to exceed 1 

percent for 136 plants, 99 of which have an increase between 1 

and 3 percent.

As for the market and industry-level results discussed 

above, EPA expects the impacts of Options 3a and 3b to be 

smaller than those of Option 3, and the impacts of Option 4a to 

be between those of Options 3 and 4. 

3. Summary of Economic Impacts for Existing Sources

EPA performed cost and economic impact assessment in two 

parts. The first set of cost and economic impact analyses –

including entity-level impacts at both the plant and parent 

company levels – reflects baseline operating characteristics of 

plants incurring compliance costs and assumes no changes in 
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those baseline operating characteristics (e.g., level of 

electricity generation and revenue) as a result of the 

requirements of the proposed regulatory options. They can serve 

as screening-level indicators of the relative cost of different 

regulatory options to plants, owning entities, or consumers, but 

are not determinative in terms of assessing the economic 

achievability of various regulatory options. 

The second set of analyses look at broader electricity 

market impacts taking into account the interconnection of 

regional and national electricity markets, for the full 

industry, for steam electric plants only, and at the 

distribution of impacts at the plant level. This second analysis 

provides insight on the impacts of the proposed ELGs on steam 

electric plants, as well as the electricity market as a whole, 

including generation capacity closure, and changes in generation 

and wholesale electricity prices. Results of the Market Model 

for Option 3 show no incremental plant closures (complete or 

partial) and relatively small changes in production costs. This 

analysis shows that Option 3 for existing steam electric plants 

is economically achievable. This same conclusion applies to 

Options 3a and 3b since the costs of these options are less than 

those of Option 3.

The Market Model analysis of Option 4 shows slightly 

higher, but still relatively small, impacts on steam electric 
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generation and individual plants as compared to Option 3. For 

example, the results show incremental partial capacity 

retirements of 317 MW at the national level (1.4 percent 

relative to the baseline without the proposed ELGs), no full 

plant retirements, and greater increases in production costs 

(1.0 percent), as compared to Option 3. On the basis of Given 

these small impacts, and since the impacts of Option 4a would 

fall between those of Options 3 and 4, EPA believes that Option 

44a is also economically achievable.

4. Summary of Economic Impacts for New Sources

Electric power generating units that meet the definition of 

a new source would be required to meet the proposed NSPS or 

PSNS. EPA developed estimated compliance costs for new units 

using a methodology similar to that used to develop compliance 

costs for existing plants, with the notable exception that EPA 

did not develop new unit compliance costs that are plant 

specific, which would require EPA to predict which plants will 

construct new units. 

EPA assessed the possible impact of incremental costs 

associated with today’s proposal for new units in two ways: (1) 

as part of its analysis using IPM discussed in Section XI.D.3; 

and (2) by comparing the incremental costs for new units to the 

overall cost of building and operating new scrubbed coal units.
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EPA estimated the incremental capital and fixed O&M costs 

for each new electricity generating coal unit projected to come 

online in IPM. The Agency estimated variable O&M costs assuming 

that any new unit would operate, on average, 330 days per year. 

IPM takes these additional regulatory costs into account when 

trying to determine the least costly means of meeting the total 

electricity demand. Results of the IPM analysis are summarized 

in Section XI.D.3 of this preamble and discussed in detail in 

Chapter 5 of the RIA document. IPM results show no barrier to 

new generation capacity for 2025-2034 as a result of compliance 

with the preferred NSPS/PSNS regulatory options (Option 4). The 

model predictsestimates no change in coal steam capacity 

relative to the baseline, and small increases in generation 

capacity from other steam83 (0.3 percent), combustion turbine 

(0.3 percent), other non-steam39 (less than 0.1 percent), and 

combined cycle (less than 0.1 percent)units.84

As a separate analysis, EPA also compared total compliance 

costs to the total cost of building and operating a new coal 

unit on an annualized basis. EPA obtained the overnight85 capital 

 

83 Other steam generation includes biomass, landfill gas, fossil waste, 

municipal solid waste, non-solid waste, tires, and geothermal. Other nonsteam generation includes wind, solar, pumped storage, and fuel cell.

84 Other steam generation includes biomass, landfill gas, fossil waste, 

municipal solid waste, non-solid waste, tires, and geothermal. Other nonsteam generation includes wind, solar, pumped storage, and fuel cell.

85 As defined by the Energy Information Administration, "overnight cost" is an 

estimate of the cost at which a plant could be constructed assuming that the 

entire process from planning through completion could be accomplished in a 
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and O&M costs of building and operating a new scrubbed coal unit 

used in the Energy Information Administration’s Annual Energy 

Outlook 2011; these costs were estimated for a new dual-unit 

plant with a total generation capacity of 1,300 MW. Table XI-8

shows capital and O&M costs of building and operating a new coal 

unit and contrasts these costs with the incremental costs 

associated with the preferred option (i.e., Option 4 for new 

sources). 

Table XI-8. Comparison of Incremental Compliance Costs with 

Costs for New Coal-fired Steam Electric Units

Cost Component

Costs of New 

Coal Generation 

($2010/MW)a

Incremental 

Compliance 

Costs 

($2010/MW)b

% of New 

Generation Cost

Capital $2,981,947 $19,911-$21,773 0.7%-0.7%

Annual O&M $66,427 $2,281-$3,093 3.4%-4.7%

Total Annualized 

Costs $329,487 $4,037-$5,013 1.2%-1.5%

a Source: New unit total cost value from Table 8.2 EIA NEMS Electricity 

Market Module. AEO 2011 Documentation. Available at 

http://www.eia.gov/forecasts/aeo/assumptions/pdf/electricity.pdf . 

Capital costs are based on the total overnight costs for new scrubbed 

coal dual-unit plant, 1,300 MW capacity coming online in 2014. EPA 

restated costs in 2010 dollars. Total annual O&M costs assume 90% 

capacity utilization. 

b Incremental costs for new 1300 MW unit for Option 4. Range represents 

the costs for a new unit at an existing plant (lower bound) and new unit 

at newly constructed plant (upper bound).

The comparison suggests that compliance with the proposed 

ELGs represents a relatively small fraction of overnight capital 

costs of a new unit (less than 1 percent) and a somewhat higher, 

but still small (less than 5 percent), fraction of non-fuel O&M 

 

single day. This concept is useful to avoid any impact of project delays and 

of financing issues and assumptions on estimated costs. 
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costs (not including fuels).. On an annualized basis, compliance 

costs for the proposed ELGs are 1.2 to 1.5 percent of annualized 

costs for a new plant.

Based on these two separate assessments, EPA finds no 

evidence that the incremental compliance costs associated with 

the proposed NSPS/PSNS present a barrier to entry.

5. Assessment of Potential Electricity Price Effects

EPA assessed the potential electricity price effects of 

today’s proposed rule in two ways: (1) an assessment of the 

potential annual increase in household electricity costs and (2) 

an assessment of the potential annual increase in electricity 

costs per MWh of total electricity sales. The analysis assumes, 

for analytic convenience as a worst-case scenario, that all

compliance costs will be passed through on a pre-tax basis as 

increased electricity prices as opposed to the treatment in the 

plant- and entity-level analyses discussed in Section XI.D.1 

above, which assume that none of the compliance costs will be 

passed to consumers through electricity rate increases. 

a. Cost to Residential Households

Using the assumptions outlined above, EPA estimated the 

potential annual increase in electricity costs per household, by 

North American Electric Reliability Corporation (NERC) region. 

The analysis uses the total annualized pre-tax compliance cost 

per megawatt hour (MWh) for the year 2014 (in 2010 dollars), in 
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conjunction with the reported total electricity sales quantity 

for each NERC region for 2009. This analysis also uses the 

quantity of residential electricity sales per household in 2009. 

To calculate the average cost per household, by region, EPA 

divided total compliance costs for each NERC region by the 

reported total MWh of sales within the region. The potential 

annual cost impact per household was then calculated by 

multiplying the estimated average cost per MWh by the average 

MWh per household, by NERC region.86 Details of this analysis are 

presented in Chapter 7 of the RIA.

Table XI-9 summarizes the annual household impact results 

for each regulatory option, by NERC region. The results for 

Option 33a show that the average annual cost per residential 

household increasing by $0 to $4.401.69 depending on the region, 

with a national average of $1.590.48. This represents a monthly 

increase of $0.1304 for the typical household. For Option 4, 

regional increases range between $0 to $10.083b, the results 

show the average annual cost per residential household 

increasing by $0 to $2.29, with a national average of $3.890.75, 

or $0.3206 per month. For Option 3, the average annual cost per 

residential household increases by $0 to $4.40, with a national 

average of $1.59, or $0.13 per month. Finally, for the typical 

 

86 Some NERC regions have been re-defined over the past few years. The NERC 

region definitions used in today’s proposed rule analyses vary by analysis 

depending on which region definition aligns better with the data elements 

underlying the analysis. 
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household.Option 4a, the average annual cost per residential 

household increases by $0 to $7.22, depending on the region, 

with a national average of $2.69, or $0.22 per month. 

Table XI-9. Average Annual Cost Burden per Residential 

Household in 2014 by Regulatory Option and NERC Region (2010$)a

NERC 

Region

Option 

3a

Option 

3b

Option 

1

Option 

2

Option 

3

Option 

4a

Option 

4

Option

5

ASCC $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 

ECAR $1.69 $2.29 $1.82 $2.71 $4.40 $7.22 $10.08 $16.86 

ERCOT $0.00 $0.42 $1.22 $1.73 $1.73 $2.60 $2.79 $5.76 

FRCC $0.00 $0.00 $0.18 $0.67 $0.67 $0.67 $0.99 $4.32 

HICC $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 

MAAC $0.00 $0.00 $0.06 $0.32 $0.32 $0.97 $2.04 $3.52 

MAIN $0.31 $0.31 $0.48 $0.69 $1.01 $2.55 $4.63 $6.16 

MAPP $0.01 $0.01 $0.97 $1.30 $1.32 $2.04 $3.23 $5.58 

NPCC $0.00 $0.00 $0.03 $0.08 $0.08 $0.08 $0.49 $0.67 

SERC $1.09 $2.00 $1.63 $2.19 $3.28 $4.98 $6.47 $10.81 

SPP $0.05 $0.14 $0.61 $0.96 $1.01 $2.85 $4.43 $6.30 

WECC $0.05 $0.05 $0.02 $0.03 $0.08 $0.23 $0.53 $0.59 

U.S. $0.48 $0.75 $0.75 $1.12 $1.59 $2.69 $3.89 $6.46 

a The rate impact analysis maintains the counterfactual, conservative 

assumption of 100 percent pass-through to electricity consumers.

As stated above, this analysis assumes that all of the 

compliance costs (100 percent) will be passed onto consumers 

through increased electricity rates. However, plants and owning 

entities are likely to absorb some of these costs, thereby 

reducing the impact of today’s proposed ELGs on electricity 

consumers. At the same time, EPA recognizes that electric 

generators that operate as regulated public utilities are 

generally permitted to pass on environmental compliance costs as 

rate increases to consumers. To evaluate the sensitivity of the 

results to the pass-through assumption, EPA analyzed alternative 

scenarios including cases where only half (50 percent) of the 

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incremental compliance costs are passed onto consumers. Appendix 

B of the RIA report presents the results of this sensitivity 

analysis. The results show smaller impacts on electricity rates, 

commensurate with the smaller fraction of the compliance costs 

that are passed onto consumers. 

b. Compliance Costs per Unit of Electricity Sales

As an additional measure of the potential electricity price 

effects associated with the proposed ELGs, EPA also assessed the 

potential increase in electricity prices to all consumer groups 

(residential, commercial, industrial, and transportation), again 

making a counterfactual, conservative assumption of a 100 

percent pass-through of compliance costs. This assessment uses 

as its basis the cost of the regulatory options per unit of 

electricity sold. 

EPA used two data inputs in this analysis (1) total pre-tax 

compliance cost by NERC region, and (2) estimated total 

electricity sales for 2014, by NERC region. The Agency summed 

sample-weighted pre-tax annualized compliance costs as of 2014 

over complying plants by NERC region to calculate the total 

estimated annual cost in each region. EPA then calculated the 

approximate average price impact per unit of electricity 

consumption by dividing total compliance costs by the reported 

total MWh of sales in each NERC region. Details of this analysis 

are presented in Chapter 7 of the RIA report.
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As reported in Table XI-10, on average, across the United 

States, Option 1 results in the lowest increased compliance cost 

of 0.007¢ per kWh, while Option 5 results in the highest 

increased compliance cost of 0.059¢ per kWh. Annualized 

compliance costs (in dollars per KWh sales) associated with 

Option 33a range from 0¢ to 0.042016¢, depending on the region, 

with a national average of 0.015004¢ per KWh. For Option 43b, 

annualized compliance costs range from 0¢ to 0.095¢ per kWh, 

depending on the region,022¢, with a national average of 

0.036007¢ per KWh, whereas Option 3 has a range of 0¢ to 0.042¢

per kWh and a national average of 0.015¢ per kWh and Option 4a 

has a range of 0¢ to 0.068¢ per kWh and a national average of 

0.025¢ per kWh. To determine the potential significance of these 

compliance costs on electricity prices, EPA compared the per kWh 

compliance cost to baseline electricity prices by consuming 

sector, and for the average of the sectors. Across the United 

States and consuming sectors, Option 13a is estimated to result 

in the smallest electricity price increase, 0.0805 percent, 

while Option 5 is expected to yield; the largest increase of 

0.66 percent; theother preferred BAT and PSES options (, Options 

3b, 3 and 4) are4a, have estimated to result in increases of 

0.08 percent, 0.16 percent and 0.3927 percent, respectively for 

Options 3 and 4. 
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Table XI-10. Compliance Cost per Unit of Electricity Sales in 

2014 by Regulatory Option and NERC Region (2010 ¢/ KWh Sales)a

NERC 

Region

Option 

3a

Option 

3b

Option 

1

Option 

2

Option 

3

Option 

4a

Option 

4

Option 

5

ASCC 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

ECAR 0.016 0.022 0.017 0.026 0.042 0.068 0.095 0.159

ERCOT 0.000 0.003 0.009 0.012 0.012 0.019 0.020 0.041

FRCC 0.000 0.000 0.001 0.005 0.005 0.005 0.007 0.032

HICC 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000

MAAC 0.000 0.000 0.001 0.003 0.003 0.010 0.021 0.036

MAIN 0.003 0.003 0.005 0.008 0.011 0.028 0.051 0.068

MAPP 0.000 0.000 0.009 0.012 0.013 0.019 0.031 0.053

NPCC 0.000 0.000 0.000 0.001 0.001 0.001 0.007 0.009

SERC 0.008 0.014 0.012 0.016 0.023 0.035 0.046 0.076

SPP 0.000 0.001 0.005 0.008 0.008 0.023 0.036 0.051

WECC 0.001 0.001 0.000 0.000 0.001 0.002 0.006 0.006

U.S. 0.004 0.007 0.007 0.010 0.015 0.025 0.036 0.059

a This analysis makes a counterfactual, conservative assumption of 100 

percent pass-through to electricity consumers.

As mentioned in the previous section, EPA ran alternative 

scenarios using an assumption that only half (50 percent) of the 

incremental compliance costs are passed onto consumers. The 

results of these alternative scenarios showed commensurately 

smaller impacts on compliance costs per unit of electricity sold 

(see Appendix B of the RIA report). 

E. Employment Effects

EPA assessed the potential for employment impacts at the 

national level for the fiveeight regulatory options considered 

in this action. 

1. Methodology

The employment effects analysis estimates employment 

changes only in the directly regulated electric power industry 

sector at the national level. This analysis focuses on the 

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longer-term, on-going employment effects of meeting compliance 

requirements, and accounts for all compliance costs, regardless 

of their time, duration, or frequency of occurrence. 

Morgenstern, Pizer and Shih (2000) explore both theoretically 

and empirically the relationship between employment and 

compliance costs of environmental regulation. Morgenstern et al. 

identify three separate components of the employment change 

within a regulated industry in response to a regulation. First, 

complying with environmental regulations causes higher 

production costs which raises market prices, higher prices 

reduce consumption (and production) reducing demand for labor 

within the regulated industry (“demand effect”). Second, as 

costs go up, to produce the same level of output, plants add 

more capital and labor. For example, pollution abatement 

activities require additional labor services to produce the same 

level of output (“cost effect”). Third, post-regulation 

production technologies may be more or less labor intensive 

(i.e., more/less labor is required per dollar of output) 

(“factor-shift effect”). The demand effect is unambiguously 

negative, the cost effect is unambiguously positive and the 

factor-shift effect could be positive or negative making the 

total effect theoretically indeterminate. In addition, 

Morgenstern et al. also estimate an empirical model for four 

highly polluting/regulated industries to examine the effect of 
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higher abatement costs from regulation on employment. They 

conclude that increased abatement expenditures generally do not 

cause a significant change in employment. More specifically, 

their results show that, on average across their industries, 

each additional $1 million spending on pollution abatement (in 

$1987 dollars) results in a (statistically insignificant) net 

increase of 1.5 jobs (95 percent confidence interval: -2.9 to + 

6.0).

2. Findings

Table XI-11 presents the estimated change, based on the 

Morgenstern et al. results, in employment in the electric power 

industry due to the proposed ELGs under each of the fiveeight

regulatory options. The table lists the options in increasing 

order of employment effects. Overall, in the aggregate and by a 

specific employment effect, Option 1 is projected to have the 

smallest effect and Option 5 is projected to have the largest 

effect on employment. The Demand Effect is projected to result 

in a decline in the number of jobs, while the Cost Effect and 

Factor Shift Effect are projected to result in an increase in 

the number of jobs. 

EPA estimated an average annual increase of 519168 jobs 

under proposed Option 33a for existing sources, with a range of 

-951 to 1,989 jobs, annually, at the 95 percent confidence 

level.. For proposed Option 4 for existing sources3b, the 
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average annual increase is estimated at 1,253 jobs, with a range 

of -2,296255 jobs, whereas Options 3 and 4a have estimated 

increases of 519 jobs and 865 jobs, respectively. Because the 

electric utility industry is more capital intensive and less 

labor intensive than the industries examined in Morganstern, 

Pizer and Shih, in addition to the employment estimates being 

statistically not distinguishable from the effect being zero, 

the estimates presented here are likely to 4,802be overestimated. Chapter 6 of the RIA report describes the 

methodologies and results in greater detail.

Table XI-11. Results of Ongoing Employment Effects on the 

Electric Power Industry Sector (Number of Jobs)a, b

Employment 

EffectRegulatory 

Option

Total Annual 

Average 

Employment Effect

95 percent confidence 

intervalTotal Annual Average 

Employment Effect

Option 13a Cost 262

Factor Shift 291

Demand -386

Total 168

Option 1

Cost 380 125 636

Factor Shift 421 5 836

Demand -559 -1,184 66

Total 243 -446 933

Option 23b Cost 399

Factor Shift 441

Demand -586

Total 255

Option 2

Cost 548 180 916

Factor Shift 607 8 1,206

Demand -806 -1,707 95

Total 548 180 916

Option 3 Cost 810

Cost 810 266 1,355

Factor Shift 897 11 1,783

Demand -1,192 -2,524 140

Total 519 -951 1,989

Option 44a Cost 1,351

Factor Shift 1,496

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Table XI-11. Results of Ongoing Employment Effects on the 

Electric Power Industry Sector (Number of Jobs)a, b

Employment 

EffectRegulatory 

Option

Total Annual 

Average 

Employment Effect

95 percent confidence 

intervalTotal Annual Average 

Employment Effect

Demand -1,988

Total 865

Option 4

Cost 1,956 641 3,271

Factor Shift 2,166 27 4,305

Demand -2,878 -6,094 339

Total 1,253 -2,296 4,802

Option 5

Option 5

Cost 3,298 1,081 5,515

Factor Shift 3,653 46 7,259

Demand -4,852 -10,274 571

Total 2,112 -3,871 8,096

a Source: Morgenstern, Pizer, and Shih (2002). 

b Coefficients from Table III, p. 427, for the Cost, Demand, Factor Shift 

and Total Effects were multiplied by the annualized cost of the proposed 

ELGs calculated as part of the social cost analysis (see Section XI.C) 

during the 24-year analysis period and re-stated in 1987 dollars, by the 

coefficient for the net increase in jobs.

Number of jobs is the average number of production workers plus other 

employees. The definition for employment used by the U.S. Census Bureau’s 

Annual Survey of Manufacturers can be found here: 

http://www.census.gov/manufacturing/asm/definitions/index.html.

XII. Cost-Effectiveness Analysis

EPA performed a cost-effectiveness analysis of the 

regulatory options for existing plants. EPA often uses costeffectiveness analysis in the development/revision of effluent 

limitations guidelines and standards to evaluate the relative 

efficiency of alternative regulatory options in removing toxic 

pollutants from the effluent discharges to the nation's waters. 

Although not required by the Clean Water Act, cost-effectiveness 

analysis is a useful tool for evaluating regulatory options that 

address toxic pollutants.

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A. Methodology

The cost-effectiveness of a regulatory option is defined as 

the incremental annual cost (in 1981 constant dollars) per 

incremental toxic-weighted pollutant removals for that option. 

This definition includes the following concepts:

Toxic-weighted removals. Pollutants differ in their 

toxicity. Therefore, the estimated reductions in pollution 

discharges, or pollutant removals, are adjusted for toxicity by 

multiplying the estimated removal quantity for each pollutant by 

a normalizing toxic weight (toxic weighting factorsfactor). The 

toxic weight for each pollutant measures its toxicity relative 

to copper, with more toxic pollutants having higher toxic 

weights. The use of toxic weights allows the removals of 

different pollutants to be expressed on a constant toxicity 

basis as toxic pound-equivalents (lb-eq). The removal quantities 

for the different pollutants can then be summed to yield an 

aggregate measure of the reduction in toxicity-normalized 

pollutant discharges that is achieved by a regulatory option. 

The cost-effectiveness analysis does not address the removal of 

conventional pollutants (e.g., total suspended solids) or 

nutrients (nitrogen, phosphorus), nor does it address the 

removal of bulk parameters, such as COD. In the case of indirect 

dischargers, the removal also accounts for the effectiveness of 
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treatment at publicly owned treatment works (POTW) and reflects

the toxic-weighted pounds remaining after POTW treatment.

Annual costs. The costs used in the cost-effectiveness 

analysis are the estimated annualized pre-tax costs to comply 

with the alternative regulatory options (refer to Section XI for 

a discussion of the annualized compliance costs). These costs to 

plants to remove the pollutants will be less because the costs 

are tax deductible. The annual costs include the annualized 

capital outlays for equipment and recurring expenses for 

operating and maintaining compliance equipment, meeting 

monitoring requirements, etc. 

Incremental calculations. The incremental values are the 

changes in total annual compliance costs and changes in 

pollutant removals as one moves to a regulatory option from the 

next less stringent regulatory option, or from the baseline for 

the least stringent option analyzed, where regulatory options 

are ranked by increasing levels of toxic-weighted removals. The 

resulting cost-effectiveness values for a given option are,

therefore, expressed relative to another option or, for the 

least stringent option considered, relative to the baseline.

The result of the cost-effectiveness calculation represents 

the unit cost of removing the next pound-equivalent of 

pollutants and is expressed in constant 1981 dollars per toxic 

pound-equivalent removed ($/lb-eq) to allow comparisons with the 
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reported cost effectiveness of other effluent guidelines, which 

use 1981 dollars.

EPA performed the cost-effectiveness analysis for the 

fiveeight regulatory options for the proposed Steam Electric 

ELGs separately for existing direct dischargers (subject to BAT) 

and indirect dischargers (subject to PSES). The following 

sections summarize the results. Note that the same plant may be 

categorized as a direct discharger for one of the wastewater 

streamswastestreams it generates and as an indirect discharger 

for another. 

B. Cost-Effectiveness Analysis for Direct Dischargers

Table XII-1 summarizes the cost-effectiveness analysis for 

the BAT regulatory options applicable to direct dischargers. The 

table lists the options in increasing order of total annual 

toxic-weighted pollutant removals.

Table XII-1. Cost-Effectiveness of Removing Toxic Pollutants for 

Direct DischargersDischargersa

Option

Annual pre-tax 

compliance costs 

(million, 1981$)

Total annual toxicweighted pollutant 

removals (000 lbeq)Cost effectiveness 

(1981$/lb-eq)

Option 

total

cost 

Increment

al cost 

Option 

total 

removals 

Increment

al 

removals 

Option 

cost 

effective

ness

Increment

al cost 

effective

ness

Option 1 $106.1105

.6

$106.1105

.6

1,530,719 1,530,719 $69 $69

Option 

3a

$67.5 -$38.1 2,488,470 957,751 $27 -$40

Option 2 $156.70 $50.688.5 2,603,628 1,072,909

115,158

$60 $47768

Option 

3b

$106.3 -$49.7 3,396,653 793,025 $31 -$63
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Table XII-1. Cost-Effectiveness of Removing Toxic Pollutants for 

Direct DischargersDischargersa

Option

Annual pre-tax 

compliance costs 

(million, 1981$)

Total annual toxicweighted pollutant 

removals (000 lbeq)Cost effectiveness 

(1981$/lb-eq)

Option 

total

cost 

Increment

al cost 

Option 

total 

removals 

Increment

al 

removals 

Option 

cost 

effective

ness

Increment

al cost 

effective

ness

Option 3 $224.1223

.5

$67.4117.

2

5,092,098 2,488,469

1,695,445

$44 $2769

Option 

4a

$378.7 $155.2 6,664,693 1,572,595 $57 $99

Option 4 $546.2547

.9

$322169.2 7,831,298 2,739,200

1,166,605

$70 $118145

Option 5 $906.75 $360.4358

.5

8,200,804 369,506 $111 $970

a Options are ranked by increasing levels of total annual toxicweighted removals.

As shown in Table XII-1, the proposed technology bases for 

BAT have a cost-effectiveness ratio of $4427/lb-eq, $31/lb-eq, 

$44/lb-eq, and $7057/lb-eq, respectively for Options 3a, 3b, 3 

and 44a ($1981). These cost-effectiveness ratios are well within 

the range of cost-effectiveness ratios for BAT of other 

industries. A review of approximately 25 of the most recently 

promulgated or revised BAT limitations shows BAT costeffectiveness ranging from less than $1/lb-eq (Inorganic 

Chemicals) to $404/lb-eq (Electrical and Electronic Components), 

in 1981 dollars.

C. Cost-Effectiveness Analysis for Indirect Dischargers

Table XII-2 summarizes the cost-effectiveness analysis for 

the PSES regulatory options applicable to indirect dischargers. 

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Toxic-weighted pollutant removals for indirect dischargers 

account for POTW removal efficiencies. The table lists the 

options in increasing order of total annual toxic-weighted 

pollutant removals.

Table XII-2. Cost-Effectiveness of Removing Toxic Pollutants for 

Indirect DischargersDischargersa

Option

Annual pre-tax 

compliance costs 

(million, 1981$)

Total annual toxicweighted pollutant 

removals (000 lb-eq)

Cost effectiveness 

(1981$/lb-eq)

Option 

total

cost 

Increme

ntal 

cost 

Option 

total 

removals 

Increment

al 

removals 

Option cost 

effectivene

ss

Incremental 

cost 

effectivene

ss

Option 

3a

$0.0 $0.0 0 0 -- --

Option 

3b

$0.0 $0.0 0 0 -- --

Option 

1

$0.71.2 $0.71.2 3,540 3,540 $198345 $198345

Option 

2

$1.32.0 $0.67 11,711 8,172171 $107168 $6792

Option 

3

$1.42.0 $0.10 11,711 0 $118168 --

a

Option 

4a

$2.0 $0.0 11,711 0 $168 --

Option 

4

$5.3.6 $3.91.6 15,532 3,821 $340233 $1,021430

Option 

5

$7.98.1 $2.64.5 18,297 2,765 $433445 $9551,636

a EPA conservatively (over) estimated compliance costs and 

(under) estimated pollutant removals. This methodology can 

result in incremental costs assigned to a regulatory option 

without incremental loading reductions assigned to the same 

option; it accounts for the additional costs to indirect 

dischargers when going from Option 2 to Option 3, without any 

change in toxic-weighted pollutant removals.a Options are ranked 

by increasing levels of total annual toxic-weighted removals.

As shown in Table XII-2, the proposed technology bases for 

PSESthere are no indirect dischargers that would incur 

compliance costs or result in incremental pollutant removals 

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under Options 3a and 3b, whereas Options 3 and 4a both have a 

cost effectiveness of $118168/lb-eq and $340/lb-eq, respectively 

for Options 3 and 4 ($1981). TheseThe cost -effectiveness ratios

areof Options 3 and 4a is within the range of cost-effectiveness 

for PSES of other industries. A review of approximately 25 of 

the most recently promulgated or revised categorical 

pretreatment standards shows PSES cost-effectiveness ranging 

from less than $1/lb-eq (Inorganic Chemicals) to $380/lb-eq 

(Transportation Equipment Cleaning), in 1981 dollars.

XIII. Environmental Assessment

This section describes the environmental assessment 

conducted in support of this rulemaking. The environmental 

assessment reviewed currently available literature on the 

documented environmental and human health impacts of combustion 

wastewaters and conducted modeling to determine the cumulative 

impacts caused by the universe of steam electric power plants 

proposed to be regulated under this effluent limitations

guidelines and standards. Modeling calculated both the impacts 

at baseline conditions (current conditions), and the 

improvements that will result after implementation of the 

different potential control options. The modeledenvironmental

improvements discussed in sectionSection XIII.A below are those 

for the preferred BAT and PSES regulatory options (Option 3a, 

Option 3b, Option 3, and Option 4.4a).
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A complete review of the scientific literature and a full 

description of EPA's modeling analysis (including the results 

for all other control options) are provided in the Environmental 

Assessment of the Proposed Effluent Limitations Guidelines and 

Standards for the Steam Electric Power Generating Point Source 

Category.

Current scientific literature indicates that combustion 

wastewaters such as fly ash and bottom ash transport water, FGD 

wastewater, and combustion residual leachate are toxic wastes 

and are causing significant detrimental environmental and human 

health impacts. Documented environmental impacts from exposure 

to these wastes reveals that the threat posed to human health, 

wildlife and the environment is a widespread problem that is not 

isolated to a few unique locations or circumstances. Documented 

instances of drinking water maximum contaminant level (MCL) 

exceedances near steam electric power plants and the issuance of 

fish advisories in waters that receive combustion wastewater 

indicates the likely threat of human health impacts from these 

wastestreams. (see Section 3.4.2 of the Environmental 

Assessment). In addition, one recent study provides confirming 

empirical evidence that toxic wastes are currently damaging 
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aquatic life and accumulating in the environment and will only 

get worse.

87

Ecological impacts include both acute (e.g., fish kills) 

and chronic effects (e.g., malformations, and metabolic, 

hormonal, and behavioral disorders) upon biota within the 

receiving water and the surrounding environment. Bioaccumulative 

toxic metals (e.g., selenium, mercury, and arsenic) are commonly 

cited as the primary cause for ecological damage following 

exposure to combustion wastewater. Selenium is the most 

frequently cited metal associated with environmental impacts 

following exposure to combustion wastewater discharges. 

Documented selenium-related impacts include lethal effects such 

as fish kills and sublethal effects such as histopathological 

changes (i.e., accumulation of trace elements in tissue) and 

damage to reproductive and developmental success. Other metals 

in combustion wastewater discharges such as arsenic, cadmium, 

chromium, copper, and lead have also been documented as causing 

sublethal effects such as changes to morphology (e.g., fin 

erosion, oral deformities), behavior (e.g., swimming ability, 

ability to catch prey, ability to escape from predators), and 

metabolism that can negatively affect long-term survival. 

Combined, these impacts can drastically alter aquatic 

 

87 Ruhl, L., A. Vengosh, G.S. Dwyer, H. Hsu-Kim, G. Schwartz, A. Romanski, and 

S.D. Smith. 2012. The Impact of Coal Combustion Residue Effluent on Water 

Resources: A North Carolina Example. Environmental Science and Technology. 

DCN SE01984.
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populations and communities and the surrounding ecosystems that 

rely on them. 

Recovery of the environment from exposure to combustion 

wastewater discharges can be extremely slow due to the 

accumulation and continued cycling of contaminants within the 

ecosystem and the potential to alter ecological processes, such 

as population diversity and community dynamics in the 

surrounding ecosystems. The ability of aquatic and adjacent 

terrestrial environments to recover from even short periods of 

exposure to these wastes depends on, among other factors, the 

distance from the discharge, the pollutant loadings, pollutant 

residence time, and the time elapsed since exposure. In 

particular, accumulation of metals in sediments can make 

recovery of aquatic systems following exposure to combustion 

wastewater discharges exceptionally slow due to the potential 

for resuspension in the water column and for benthic organisms 

to provide a pathway for exposure long after discharges have 

ended. In addition, metals such as selenium and arsenic 

bioaccumulate in organisms exposed to combustion wastewater 

discharges further complicating the potential magnitude of 

impacts these wastes pose. 

EPA identified several cases in the literature where metals 

from combustion wastewater discharges bioaccumulated to toxic 

levels in organisms inhabiting aquatic environments even with 
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low concentrations of these contaminants. The strong 

bioaccumulative properties of the pollutants, in conjunction 

with long residence times, emphasize the threat these wastes 

present to the local environment as many of the impacts may not 

be fully realized for years to come.

In addition to the bioaccumulative and toxic properties of 

the pollutants in combustion wastewaters, the total pollutant 

loadings associated with these discharges are large (see Section 

IX). EPA estimates that discharges from steam electric power 

plants alone contribute at least50 to 60 percent of the reported 

toxic-weighted pollutant loadings of the combined discharges of 

all industrial categories currently regulated in the U.S. 

Further, many steam electric power plants discharge to sensitive 

environments where pollutant loadings contribute to reduced 

water quality (e.g., Great Lakes, valuable estuaries, 303(d) 

listed waters, drinking water sources, and waters with fish 

consumption advisories). 

EPA has determined that 25 percent of surface waters that 

receive combustion wastewater discharges are impaired for a 

pollutant associated with combustion wastewater; 38 percent of 

surface waters are under a fish advisory for a pollutant 

associated with combustion wastewater. In addition to the 

concurrence of combustion wastewater discharges in close 

proximity to sensitive environments, EPA has identified over 120 
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steam electric power plants with documented environmental 

impacts to surface water and ground water environments following 

exposure to combustion wastewater, which is further evidence 

these wastes are of great concern. While in the past these cases 

may have been assumed to be anomalies, an increasing amount of 

evidence indicates that the characteristics contributing to the 

documented impact (e.g., size of the pollutant loadings, type of 

pollutant present in the waste, plant operations, and wastewater 

handling techniques) are common among power plant discharge 

locations. Further, as explained earlier, these documented 

impacts do not yet reflect the increased pollutant loadings 

associated with increasing use of air pollution controls. This, 

when coupled with the potential for long-term persistent impacts 

due to bioaccumulative pollutants, indicates that these impacts 

most likely are occurring in other locations around the country

even though they have not yet been documented. This suggests 

that the magnitude of the environmental impact of combustion 

wastewater discharges is potentially greater than the literature 

estimates.

In addition, EPA has identified other potential impacts 

from combustion wastewater discharges. Steam electric plants 

also discharge bromide in large quantities. Bromide in

wastewater discharges from steam electric plants located

upstream from a drinking water intake has been associated with
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the formation of trihalomethanes (THMs) and haloacetic acids

(HAAs) when it is exposed to chlorination disinfection processes

in drinking water treatment plants. Bromate, a disinfection 

byproduct (DBP) associated with drinking water treatment plants

that employ ozonation may also increase under the influence of

increased bromide in the source water. Human exposure to THMs 

and DBPs in chlorinated drinking water is associated with 

bladder cancer.

Based on the documented environmental impacts discussed in 

the literature, EPA identified several key environmental and 

human health concerns and pathways of exposure to evaluate in 

the environmental assessment. These included changes in surface 

water, sediment, and ground water quality; toxic effects on 

aquatic life; toxic metal bioaccumulation in fish and in 

piscivorous wildlife (e.g., minks and bald eagles); toxic metal 

bioaccumulation in fish consumed by humans; and contamination of 

ground water drinking water resources. 

EPA developed a three-part receiving water model to 

quantify changes in plant-specific impacts to surface waters, 

wildlife, and human health from pollutant reductions associated 

with the regulatory options discussed in Section VIII for a 

subset of evaluated wastestreams from steam electric power 

plants (i.e.., fly ash and bottom ash transport water, FGD 

wastewater, and leachate). EPA considered the type of receiving 
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waters commonly impacted by steam electric power plants and the 

pollutants typically found in the evaluated wastestreams in 

selecting the appropriate methodologies for the quantitative 

Environmental Assessment analysis. EPA designed the model to 

quantify the environmental impact within rivers/streams and 

lakes/ponds (including reservoirs) based on the finding that 94 

percent of the power plant outfalls discharge to these types of 

surface waters. EPA focused the modeling on toxic metals due to 

the total mass loadings discharged, potential for toxic effects 

to wildlife and human health, and potential for bioaccumulation 

within the ecosystem. EPA addressed environmental impacts from 

nutrients, in a separate analysis discussed in Section XIII.E.

EPA’s environmental assessment modeling includes three 

interrelated models: 1) a receiving water-scale water quality 

model; 2) a receiving water-scale wildlife model; and 3) a 

receiving water-scale human health model. Each of these models 

evaluates changes in environmental and human health effects 

under baseline conditions and the five of the regulatory 

options. discussed in Section VIII of this preamble (Options 1, 

2, 3, 4, and 5). The receiving water-scale water quality model 

estimates the concentration of metals (i.e., arsenic, cadmium, 

chromium VI, copper, lead, mercury, nickel, selenium, thallium, 

zinc) in the surface waters and sediments in the immediate 

discharge zone (i.e., approximately one to 10 kilometers [km] 
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from the outfall) for steam electric power plants with direct 

discharge loadings included in the costs and loadings analysis 

(see Section IX). EPA compared modeled receiving water 

concentrations based on pollutant loadings from the evaluated 

wastestreams against National Recommended Water Quality Criteria 

(NRWQC) and Maximum Contaminant Levels (MCLs) to assess changes 

in receiving water quality. The wildlife model evaluates the 

potential impact that water and sediment concentrations pose to 

aquatic life, calculates the metal concentrations in exposed 

fish populations, and evaluates the potential impact to wildlife 

(minks and eagles) from consumption of fish. The human health 

model calculates potential threat to cause non-cancer health 

effects and cancer risks to human populations from the 

consumption of fish exposed to discharges of the evaluated 

wastestreams. In addition to the immediate receiving water 

analysis, EPA modeled receiving water concentrations downstream 

from steam electric discharges using EPA’s Risk-Screening 

Environmental Indicators (RSEI) model and used the wildlife and 

human health models to calculate metal concentrations in exposed 

fish populations and human exposure doses from fish consumption 

in surface waters downstream from steam electric discharges. EPA 

compared downstream receiving water concentrations, fish tissue 

concentrations, and human exposure to water quality, wildlife, 

and non-cancer and cancer benchmarks to assess the number of 
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improved river miles associated with the different options for 

today’s proposed rule. 

EPA did not perform modeling to evaluate changes in 

environmental and human health effects under Option 3a, Option 

3b, or Option 4a. To estimate the environmental improvements 

under these three options, the Agency compared their pollutant 

load reductions to those of Option 3 (whose reductions would be 

greater than those of Option 3a and Option 3b, and less than 

those of Option 4a) and applied corresponding adjustments to the 

modeled environmental improvements under Option 3 to approximate 

those of the three un-modeled options.

EPA expects a number of environmental and ecological 

improvements and reduced impacts to wildlife and human receptors 

to result from reductions in effluent loadings examined for the 

different options discussed in today’s proposed rule. In 

particular, the Environmental Assessment evaluated the 

following: a) improvements in water quality, b) reduction in 

impacts to wildlife, c) reduction in number of receiving waters 

with potential human health cancer risks, d) reductions in 

number of receiving waters with potential to cause non-cancer 

human health effects, e) reduction in nutrient impacts, f) 

reduction in other environmental impacts, and g) unquantified 

environmental improvements. 
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A. Improvements in Surface Water and Ground Water Quality

The reduced pollutant loadings associated with the 

preferred options (Option 33a, Option 3b, Option 3, and Option 

44a) would reduce lead to reduced contamination levels in 

surface waters and sediments. EPA modeledestimated that reduced 

pollutant loadings to surface waters associated with Option 33a

would significantly improve water quality by reducing metal 

concentrations by up to 4833 percent on average within the 

immediate receiving waters. Option 43b, Option 3, and Option 4a

would achieve average reductions of up to a 9036 percent

reduction on average, 48 percent, and 60 percent, respectively. 

The pollutants with the greatest number of water quality 

standard (NRWQC or MCL) exceedances under baseline pollutant 

loadings include: total arsenic, total thallium, dissolved 

cadmium, and total selenium. EPA determined that 49 percent of 

the immediate receiving waters exceeded a water quality standard 

under baseline loadings. EPA estimates the number of immediate 

receiving waters with aquatic life exceedances, which are driven 

by dissolved cadmium and total selenium concentrations, would be 

reduced by up to 29 percent for both Option 3a and Option 3b, up 

to 35 percent for Option 3, and up to 8455 percent for Option 

44a under the post-compliance pollutant loadings. EPA also

estimates that the number of immediate receiving waters with 

human health water quality standards exceedances, primarily 
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driven by total arsenic and total thallium concentrations, would

be reduced by up to 14 percent for Option 3a, up to 15 percent 

for Option 3b, up to 18 percent for Option 3, and up to 7241

percent for Option 44a. 

Selenium was one of the primary pollutants identified in 

the literature as causing documented environmental impacts to 

fish and wildlife. EPA calculates that total selenium receiving 

water concentrations would be reduced by 33 percent on average 

under Option 3a, 36 percent on average under Option 3b, 48 

percent on average under Option 3, whichand 60 percent on 

average under Option 4a. This would result in a 55 percent 

reduction inreduce the number of immediate receiving waters 

exceeding the freshwater chronic criteria for selenium. Under 

Option 4, EPA calculates that total selenium receiving water 

concentrations would be reduced by 83 percent on average, which 

would result in a 74 percent reduction in the number of 

immediate receiving waters exceeding the freshwater chronic 

criteria for selenium. by 38 percent under Option 3a, 40 percent 

under Option 3b, 55 percent under Option 3, and 67 percent under 

Option 4a. EPA estimates that up to 3,643 river miles (Option 

3a), 3,862 river miles (Option 3b), 4,830 river miles (under 

Option 3)), and 10,3466,633 river miles (under Option 44a)

downstream from steam electric discharges would no longer exceed 
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aquatic life and human health NRWQC or MCL standards under the 

post-compliance pollutant loadings.

The preferred options would both reduce ground water 

contamination levels and improve the availability of ground 

water resources by reducing the future leaching of pollutants 

from steam electric impoundments to groundwater aquifers. 

Section XIV provides additional details on the benefits analysis 

of these ground water improvements.

B. Reduced Impacts to Wildlife

EPA calculates that the number of immediate receiving 

waterbodies with potential impacts to wildlife would be reduced 

by up to 23 percent under Option 3a, up to 24 percent under 

Option 3b, up to 30 percent under Option 3, and up to 8751

percent under Option 44a. EPA developed the receiving waters 

wildlife model to quantify the impacts to wildlife that consume 

fish exposed to steam electric discharges. EPA selected minks 

and eagles as representative indicator species to evaluate the 

impact discharges of the evaluated wastestreams posed to birds 

and mammals that consume fish. EPA selected minks and eagles 

based on their national population distribution and the fact 

that a majority of their diet is comprised of fish. EPA modeled 

fish tissue concentrations for the immediate and downstream 

receiving waters and compared those concentrations to no effect 

hazard concentrations (NEHC) benchmarks developed by the U.S. 
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Geological Survey (USGS) that indicate potential impacts to 

piscivorous (i.e., fish eating) wildlife. The NEHC benchmarks 

developed by the USGS are based on “no observed adverse effect 

levels” (NOAELs), which were derived from adult dietary exposure 

or tissue concentration studies and based primarily on 

reproductive endpoints. 

EPA determined that combustion wastewater discharges into 

lakes pose the greatest risk to piscivorous wildlife, with 

approximately 78 percent of lakes compared to 39 percent of 

rivers exceeding a NEHC benchmark for minks or eagles under 

baseline pollutant loadings. Mercury and selenium, and to a 

lesser extent cadmium and zinc, were the primary pollutants with 

greatest number of receiving waters with wildlife NEHC benchmark 

exceedances. EPA estimates that today’s preferred options would

reduce the number of immediate receiving waters exceeding the 

mercury NEHC for minks and eagles by up to 24 percent under 

Option 3a, up to 26 percent under Option 3b, up to 33 percent

under Option 3, and up to 9452 percent under Option 44a. For

selenium, EPA estimates that the number of immediate receiving 

waters exceeding the selenium NEHC would be reduced by up to 29 

percent under Option 3a, up to 31 percent under Option 3b, up to 

42 percent under Option 3, and up to 7456 percent under Option 

44a. This indicates that today’s preferred options would reduce 

the bioaccumulative impact of the evaluated wastestreams in the 
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broader ecosystem. EPA estimates that up to 4,135 river miles 

(Option 3a), up to 4,360 river miles (Option 3b), up to 5,300 

river miles (Option 3), and up to 8,206 river miles (Option 4a)

downstream from steam electric discharges would no longer exceed 

a NEHC benchmark for minks or eagles under the post-compliance 

pollutant loadings associated with Option 3. EPA estimates that 

9,235 and 14,100 river miles downstream from steam electric 

discharges would no longer exceed a NEHC benchmark for minks or 

eagles, respectively, under the post-compliance pollutant 

loadings associated with Option 4..

In addition, EPA estimates that the upgrades to water 

quality (i.e., reductions in aquatic life NRWQC exceedances) 

discussed above would improve aquatic and wildlife habitats in 

the immediate and downstream receiving waters from steam 

electric discharges. EPA determined that these water quality and 

habitat improvements would enhance efforts to protect threatened 

and endangered species. EPA identified eight species with a high 

vulnerability to changes in water quality whose recovery would 

be expected to be enhanced by the post-compliance pollutant 

loading reductions associated with today’s preferred options. 

C. Reduced Human Health Cancer Risk 

EPA estimates that reductions in arsenic loadings from 

today’s preferred options would result in a reduction in 

potential cancer risks to humans that consume fish exposed to 
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discharges of the evaluated wastestreams. The human health model 

calculates the potential cancer risk for select age groups and 

consumption categories (i.e., child and adult recreational 

fishers and child and adult subsistence fishers) based on 

assumptions of arsenic bioaccumulation in fish exposed to 

discharges of the evaluated wastestreams. Under baseline 

pollutant loadings, EPA determined that up to 9 percent of 

immediate receiving waters contain fish contaminated with 

inorganic arsenic that would present cancer risks above the 1-

in-a-million threshold for one or more of the cohorts evaluated. 

EPA determined that, depending on the cohort, immediate 

receiving waters with cancer risks above the 1-in-a-million 

threshold would be reduced by up to 40 percent (Option 3a), up 

to 60 percent, depending on the cohort, (Option 3b and Option 

3), and up to 80 percent (Option 4a) under post-compliance 

loadings associated with Option 3 and would be reduced by up to 

89 percent, depending on the cohort, under post-compliance 

loadings associated with Option 4. In addition, EPA estimates 

that up to 266 river miles, depending on the cohort, downstream 

from the steam electric discharges contain fish contaminated 

with inorganic arsenic that would present cancer risks above the 

1-in-a-million threshold. Under the post-compliance pollutant 

loadings associated with today’s preferred options, EPA 

estimates that up to 111 river miles (Option 3a), up to 116 
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river miles (Option 3b), up to 133 river miles (Option 3)), and 

up to 248169 river miles (Option 44a) downstream from steam 

electric discharges would no longer contain fish contaminated 

with inorganic arsenic that would present cancer risks above the 

1-in-a-million threshold for adult subsistence fishers.

D. Reduced Threat of Non-Cancer Human Health Effects

Exposure to metals poses risk of systemic and other effects 

to humans, including effects on the circulatory, respiratory, or 

digestive systems and neurological and developmental effects. 

Option 3 and Option 4The preferred options are estimated to 

reduce the number of receiving waters with potential to cause 

non-cancer health effects in humans who consume fish exposed to 

discharges of the evaluated wastestreams. The human health model 

calculates the number of immediate receiving waters with the 

potential to cause non-cancer health effects in select age

groups and consumption categories (i.e., child and adult 

recreational fishers and child and adult subsistence fishers) 

based on assumptions of metal bioaccumulation in fish exposed to 

discharges of the evaluated wastestreams. Depending on the 

cohort, EPA calculates that exceedances of non-cancer reference 

doses from the consumption of fish would decrease in up to 19 

percent of surface waters (Option 3a), up to 21 percent of 

surface waters (Option 3b), up to 26 percent of surface waters 

(under Option 3)), and up to 9153 percent of surface waters 
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(under Option 44a) immediately receiving discharges of the 

evaluated wastestreams. Non-cancer risks are driven by mercury 

(as methylmercury), total thallium, and total selenium, and to a 

lesser degree, total cadmium pollutant loadings. Under baseline 

pollutant loadings, the average daily dose from the consumption 

of fish in up to 65 percent of immediate receiving waters 

exceeds the non-cancer reference dose for mercury depending on 

the cohort. Under Option 3 post-compliance loadings, exceedances 

of the non-cancer mercury reference dose would decrease in up to 

21 percent (Option 3a), up to 22 percent (Option 3b), up to 29 

percent (Option 3), and up to 49 percent (Option 4a) of 

immediate receiving waters, depending on the cohort. Under 

Option 4 post-compliance loadings, exceedances of the non-cancer 

mercury reference dose would decrease in up to 92 percent of 

immediate receiving waters, depending on the cohort. In 

addition, Option 3 would decrease exceedances of total thallium 

and total selenium non-cancer reference doses would decrease in 

up to 1814 and 50 percent and up toof immediate receiving waters 

(Option 3a and Option 3b), up to 18 and 69 percent of immediate 

receiving waters, respectively, while (Option 4 would decrease 

these exceedances in up to 87 percent3), and up to 8843 and 77

percent of immediate receiving waters, (Option 4a),

respectively. EPA also estimates that up to 5,400 river miles 

downstream from steam electric discharges would have decreased, 
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under the post-compliance pollutant loadings, exceedances of 

non-cancer reference doses from the consumption of fish would 

decrease in up to 4,084 river miles downstream (Option 3a), up 

to 4,316 river miles downstream (Option 3b), up to 5,400 river 

miles downstream (Option 3), and up to 8,087 river miles 

downstream (Option 4a) for one or more of the cohorts under the 

post-compliance pollutant loadings associated with Option 3.

Under Option 4, up to 18,100 river miles downstream from steam 

electric discharges would have reduced exceedances of non-cancer 

reference doses from the consumption of fish for one or more of 

the cohorts under the post-compliance pollutant loadings.

In addition to the assessment of non-cancer reference dose 

exceedances described above, EPA also evaluated the adverse 

health effects to children who consume fish contaminated with 

lead from combustion wastewater. EPA estimated the reduction in 

lead exposure to pre-school children via consumption of 

contaminated fish tissue and determined that today’s preferred 

options would reduce the associated intelligence quotient (IQ) 

loss among children who live in recreational angler and 

subsistence fisher households. Today’s preferred options would 

also be expected to reduce the incidence of other health effects 

associated with lead exposure among children, including slowed 

or decayed growth, delinquent and anti-social behavior, 

metabolic effects, impaired hemesynthesis, anemia, impaired 
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hearing, and cancer. Today’s preferred options would also reduce 

the IQ loss among children exposed in-utero to mercury from 

maternal fish consumption in populations exposed to immediate 

and downstream receiving waters from steam electric discharges. 

Section XIV.B.1.a provides additional details on the benefits 

analysis of these reduced IQ losses.

EPA expects that today’s preferred options would result in 

additional non-cancer human health effects beyond those 

described above, including reduced health hazards due to 

exposure to contaminants in waters that are used for 

recreational purposes (e.g., swimming).

E. Reduced Nutrient Impacts

The primary concern with nutrients in steam electric 

discharges is the potential for adverse nutrient impacts to 

occur in water-bodies that receive discharges from multiple 

plants. Nine percent of surface waters receiving steam electric 

wastewater discharges are impaired for nutrients. While the 

current concentration of nitrogen present in steam electric 

discharges from any individual power plant is relatively low, 

the total nitrogen loadings from a single plant can be 

significant due to large wastewater discharge flow rates. Total 

nutrient loadings from multiple power plants is especially a 

concern on water bodies that are nutrient impaired or in 

watersheds that contribute to downstream nutrient problems. 
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Excessive nutrient loadings to receiving waters can 

significantly affect the ecological stability of freshwater and 

saltwater aquatic systems. Nutrient over-enrichment of surface 

waters can stimulate excessive plant growth that can obstruct 

sunlight penetration and increase turbidity, which can result in 

the death of bottom-dwelling aquatic plants. Higher nutrient 

loadings from steam electric discharges could result in the 

eutrophication of waters and the formation of hazardous algal 

blooms. An additional concern with nutrients in steam electric 

discharges is the potential for the total nitrogen loadings from 

plants to increase in the future as air pollution limits become 

stricter and the use of air pollution controls increases. 

EPA projects that the preferred options would reduce total 

nutrient loadings by 39 percent (Option 3a), by 41 percent 

(Option 3b), by 53 percent (under Option 3)), and by 9666

percent (under Option 44a) and improve overall water quality. 

EPA used the SPARROW (SPAtially Referenced Regressions On 

Watershed attributes) model to calculate baseline immediate 

receiving water concentrations, as well as immediate receiving 

water concentrations under eachbaseline conditions and under 

five of the regulatory optionoptions discussed in Section VIII 

of this preamble (Options 1, 2, 3, 4, and 5) to analyze benefits 

related to improvements in water quality. EPA used these 

concentrations to develop sub-indices for a water quality index 
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(WQI), a value that translates water quality measurements, 

gathered for multiple parameters that represent various aspects 

of water quality, into a single numerical indicator. Section XIV 

provides additional details on the water quality benefits 

analysis of nutrient reductions.

F. Unquantified Environmental and Human Health Improvements

The above environmental assessment focused on the 

quantification of environmental improvements within rivers and 

lakes from post-compliance pollutant loading reductions for 

toxic metals and excessive nutrients. While extensive, the 

environmental improvements quantified do not encompass the full 

range of improvements anticipated to result from today’s 

preferred options simply because some of the improvements have 

no method for measuring a quantifiable or monetizable 

improvement. EPA expects post-compliance pollutant loading 

reductions from today’s preferred options to result in much 

greater improvements to wildlife, human health and environmental 

health by reducing the:

Loadings of bioaccumulative metals to the broader ecosystem 

resulting in the reduction of long-term exposures and 

sublethal ecological effects; 

Sublethal chronic effects of toxic metals on aquatic life 

not captured by the NRWQC;

Impacts to aquatic and aquatic-dependant wildlife 

population diversity and community structures;

Exposure of wildlife to pollutants through direct contact 

with combustion residuals impoundments and constructed 
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wetlands built as treatment systems at steam electric power 

plants;

Adverse health effects in adults resulting from exposure to 

lead from consumption of contaminated fish tissue; and

Potential for the formation of hazardous algal blooms.

Data limitations prevented appropriately modeling the scale 

and complexity of the ecosystem processes potentially impacted 

by combustion wastewater, resulting in the inability to quantify 

the improvements listed. However, documented case studies in the 

literature reinforce that these impacts are common in the 

environments surrounding steam electric power plants and fully 

support the conclusion that reducing pollutant loadings will 

improve overall environmental, human health and wildlife health.

Although the Environmental Assessment quantifies impacts to 

wildlife that consume fish contaminated with metals from 

combustion wastewater, it does not capture the full range of 

exposure pathways through which bioaccumulative metals can enter 

the surrounding food web. Wildlife can encounter toxic 

bioaccumulative metals from discharges of the evaluated 

wastestreams from a variety of exposure pathways such as direct 

exposure, drinking water, consumption of contaminated 

vegetation, and consumption of contaminated prey other than 

fish. Therefore, the quantified improvements underestimate the 

complete loadings of bioaccumulative metals that can impact 

wildlife in the ecosystem. EPA anticipates that the post-
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compliance pollutant loading reductions associated with today’s 

preferred options would lower the total amount of toxic 

bioaccumulative metals entering the food web near steam electric 

power plants. 

EPA also expects the estimated reduction in pollutant 

loadings to lower the occurrence of sublethal effects associated 

with many of the pollutants in combustion wastewater that may 

not be captured by comparisons with NRWQC for aquatic life. 

Chronic effects such as changes in metabolic rates, decreased 

growth rates, changes in morphology (e.g., fin erosion, oral 

deformities), and behavior (e.g., swimming ability, ability to 

catch prey, ability to escape from predators) that can 

negatively affect long-term survival, are well documented in the 

literature in environments near steam electric power plants. 

Reductions in organism survival rates from the chronic effects 

such as abnormalities can alter interspecies relationships 

(e.g., declines in the abundance or quality of prey) and prolong 

ecosystem recovery. However, these effects were not quantified 

in the environmental assessment and improvements to wildlife 

health and survival from today’s preferred options are,

therefore, underestimated. EPA was unable to quantify changes to 

aquatic and wildlife population diversity and community 

dynamics; however, population effects (i.e., decline in number 

and type of organisms present) attributed to exposure to 
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combustion wastewater are well documented in the literature. 

Changes in aquatic populations can alter the structure of 

aquatic communities and cause cascading effects within the food 

web that result in long-term impacts to ecosystem dynamics. EPA 

expects that post-compliance pollutant loading reductions 

associated with today’s preferred options would lower the 

stressors that can cause alterations in population and community 

dynamics and improve the overall function of ecosystems 

surrounding steam electric power plants, as well as help resolve 

issues faced in other national ecosystem protection programs 

such as the Great Lakes program, the National Estuaries program 

and the 303(d) impaired waters program. 

EPA anticipates that the expected post-compliance pollutant 

loading reductions associated with today’s preferred options

would also decrease the environmental impacts to wildlife 

exposed to pollutants through direct contact with combustion 

residuals impoundments and constructed wetlands at steam 

electric power plants. Documented case studies demonstrate that 

wildlife living in close proximity to combustion residuals 

impoundments exhibit elevated levels of arsenic, cadmium, 

chromium, lead, mercury, selenium, strontium, and vanadium. 

Multiple studies have linked attractive nuisance areas 

(contaminated areas at a steam electric power plant, such as 

combustion wastewater surface impoundments, that are attractive 
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to wildlife (place for nesting)) to diminished reproductive 

success. EPA expects that the post-compliance pollutant loadings 

would decrease the exposure of wildlife populations to toxic 

pollutants and reduce the risks for impacts on reproductive 

success. 

G. Other Secondary Improvements

EPA anticipates that other secondary, or ancillary,

improvements would occur to other resources that are associated 

directly or indirectly as a result of the preferred options. 

These would include aesthetic and recreational improvements, 

reduced economic impacts such as clean up and treatment costs in 

response to contamination or impoundment failures, reduced 

injury associated with pond failures, reduced water usage and 

reduced air emissions. Section XIV provides additional details 

on the benefits of these other secondary improvements.

XIV. Benefit Analysis

This section summarizes EPA's estimates of the national 

environmental benefits expected to result from reduction in 

pollutant discharges described in Section IX and the resultant 

environmental effects summarized in Section XIII. The Benefit 

and Cost Analysis for the Proposed Effluent Limitations 

Guidelines and Standards for the Steam Electric Power Generating 

Point Source Category (BCA) report provides additional details 
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on benefits methodologies and analysis, including uncertainties 

and limitations.

A. Categories of Benefits Analyzed

Table XIV-1 summarizes benefit categories associated with 

today’s proposed rule and notes which categories EPA was able to 

quantify and monetize. Analyzed benefits fall within six broad 

categories: human health benefits, ecological conditions and 

recreational use benefits from surface water quality 

improvements, market and productivity benefits, air-related 

benefits, groundwater quality benefits, and water withdrawal 

benefits. Within these broad categories, EPA was able to assess 

benefits with varying degrees of completeness and rigor. Where 

possible, EPA quantified the expected effects and estimated 

monetary values. However, data limitations and gaps in the 

understanding of how society values certain water quality 

changes prevent EPA from quantifying and/or monetizing some 

benefit categories.

Table XIV-1. Benefit Categories Associated with Proposed ELGs

Benefit Category

Quantifie

d And 

Monetized

Quantified 

But Not 

Monetized

Neither 

Quantified 

Nor 

Monetized

1. Human Health Benefits from Surface Water Quality Improvements

Reduced incidence of cancer from

arsenic exposure via fish 

consumption

X
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Table XIV-1. Benefit Categories Associated with Proposed ELGs

Benefit Category

Quantifie

d And 

Monetized

Quantified 

But Not 

Monetized

Neither 

Quantified 

Nor 

Monetized

Reduced non-cancer adverse health 

effects (e.g., reproductive, 

immunological, neurological, 

circulatory, or respiratory 

toxicity) due to exposure to 

arsenic from fish consumption

X

Reduced IQ loss in children from 

lead exposure via fish consumption X

Reduced need for specialized 

education for children from lead 

exposure via fish consumption

X

Reduced adverse health effects in 

adults from exposure to lead from 

fish consumption

X

Reduced in-utero mercury exposure 

via maternal fish consumption X

Reduced health hazards from 

exposure to pollutants in waters 

used recreationally (e.g., 

swimming)

X

2.Ecological Conditions and Recreational Use Benefits from Surface 

Water Quality Improvements

Benefits from improvements in 

surface water quality, including: 

improved aquatic and wildlife 

habitat; enhanced water-based 

recreation, including fishing, 

swimming, boating, and near-water 

activities; increased aesthetic 

benefits, such as enhancement of 

adjoining site amenities (e.g., 

residing, working, traveling, and 

owning property near the watera; and 

non-use value (i.e., existence, 

option, and bequest value from 

improved ecosystem health)a

X

Benefits from improved protection 

of threatened and endangered 

species 

X

Reduced sediment contamination X

3.Groundwater Quality Benefits

Reduced groundwater contamination X

4.Market and Productivity Benefits 
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Table XIV-1. Benefit Categories Associated with Proposed ELGs

Benefit Category

Quantifie

d And 

Monetized

Quantified 

But Not 

Monetized

Neither 

Quantified 

Nor 

Monetized

Reduced impoundment failures 

(monetized benefits include avoided 

cleanup costs and environmental 

damages; non-quantified benefits 

include avoided injury)

X

Reduced water treatment costs for 

municipal drinking water, irrigation 

water, and industrial process

X

Improved commercial fisheries yields X

Increased tourism and participation 

in water-based recreation X

Increased property values from water 

quality improvements X

5.Air-Related Benefits

Reduced mortality from exposure to 

NOx, SO2 and particulate matter 

(PM2.5)

X

Avoided climate change impacts from 

CO2 emissions X

6.Benefits from Reduced Water Withdrawals

Increased availability of 

groundwater resources X

a. These values are implicit in the total willingness to pay (WTP) for water 

quality improvements.

The following section discusses EPA’s analysis of the 

benefits that the Agency was able to quantify and monetize 

(identified in the second column of Table XIV-1). The proposed 

rule would also result in additional benefits that the Agency 

was not able to monetize. See the Benefits and Cost Analysis 

Document for information about these non-monetized benefits.

EPA estimated benefits for five of the eight regulatory 

options discussed in this preamble (Options 1, 2, 3, 4, and 5). 

EPA did not estimate the benefits of Options 3a, 3b and 4a. 

Formatted: ___GHG PARAGRAPH
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However, EPA used its understanding of the wastestreams and 

treatment technologies for these options, along with projections 

of pollutant reductions for all eight options, to estimate total 

monetized benefits for Options 3a, 3b, and 4a. However, EPA is 

less confident that this approach would yield reasonable 

estimates if applied to the individual categories of benefits 

(water quality, air emissions, avoided impoundment failure 

cleanup costs, etc) and so has not done so. For these more 

granular benefits categories, estimates are provided only for 

Options 1, 2, 3, 4, and 5. Again, these can serve as upper and 

lower bounds for the individual categories of benefits of 

Options 3a, 3b, and 4a. Specifically, monetized benefits for 

Options 3a and 3b are likely to be between those for Options 2 

and 3. Similarly, monetized benefits for Option 4a are likely 

to be between those for Options 3 and 4. 

B. Quantification and Monetization of Benefits

1. Human Health Benefits from Surface Water Quality Improvements 

Reduced pollutant discharges from steam electric plants 

generate human health benefits in a number of ways. Pollutants 

commonly discharged in Steam Electric plant wastewater streams 

include conventional and toxic pollutants such as arsenic, 

cadmium, chromium, copper, lead, mercury, selenium, and zinc 

(steam electric pollutants). Exposure to these pollutants via 
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consumption of fish from affected waterways can cause a wide 

variety of adverse health effects, including cancer, kidney 

damage, nervous system damage, fatigue, irritability, liver 

damage, circulatory damage, vomiting, diarrhea, brain damage, IQ 

loss, and many others. Because today’s proposed ELGs would 

reduce discharges of steam electric pollutants into receiving 

waterways and downstream areas, they are likely to result in 

decreased incidences of associated illnesses.

Due to data limitations and uncertainties, EPA is able to 

monetize only a small subset of the health benefits associated 

with decreased pollutant discharges from steam electric plants. 

EPA analyzed the following measures of human health-related 

benefits: reduced cancer risk due to arsenic exposure from fish 

consumption, reduced lead-related IQ loss in children from fish 

consumption, and reduced mercury-related IQ loss in children 

exposed in-utero due to maternal fish consumption. EPA monetized 

these human health benefits by estimating the change in the 

expected number of individuals experiencing adverse human health 

effects in the populations exposed to steam electric discharges 

under various regulatory options and valuing these changes using 

a variety of nonmarket approaches (e.g., cost of illness).

a. Monetized Human Health Benefits

EPA quantified and monetized the following four categories 

of human health benefits:
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Benefits from Reduced Incidence of Cancer from Arsenic 

Exposure via Fish Consumption. EPA assessed changes in the 

incidence of cancer cases from consumption of arsenic in 

the tissue of fish caught in waters affected by steam 

electric plant discharges. For the baseline and each 

regulatory option, EPA estimated cancer risk from the 

consumption of arsenic-contaminated fish for recreational 

and subsistence anglers and their families. EPA used data 

on the populations living within 100 miles of affected 

waterbodies, state-specific average fishing rates, presence 

of fish consumption advisories, the availability of

substitute fishing locations, and average household size to 

estimate the exposed population for each steam electric 

facility. To identify the change in number of cancer cases 

caused by arsenic in this population, EPA used a cancer 

slope factor (CSF) from EPA’s Integrated Risk Information 

System (IRIS) of 1.5 per mg/kg-day and different fish 

consumption rates for recreational and subsistence anglers 

and age cohorts. The Agency valued changes in incidence of 

cancer cases using a value of a statistical life (VSL) of 

$8.0 million (2010$), with projections adjusted to account 

for income growth. This estimate does not include estimates 

of willingness to pay (WTP) to avoid illness prior to 

death. 

Benefits from Reduced IQ Loss in Children from Lead 

Exposure via Fish Consumption. Children's rapid rate of 

development makes them more susceptible to neurobehavioral 

effects from lead exposure. The neurobehavioral effects on 

children from lead exposure include hyperactivity, 

behavioral and attention difficulties, delayed mental 

development, and motor and perceptual skill deficits. EPA 

assessed benefits of reduced lead exposure from consumption 

of contaminated fish tissue and the associated IQ loss

among children aged 0 to 7. EPA predictedestimated bloodlead levels using EPA’s Integrated Exposure, Uptake, and 

Biokinetic (IEUBK) Model based on daily lead ingestion 

rates among children from birth to the seventh birthday. 

Based on blood lead concentrations for children in 

recreational and subsistence anglers’ families, EPA 

assessed neurobehavioral effects on children using an 

established dose response relationship between blood lead 

concentrations and IQ loss. Avoided neurological and 

cognitive damages are expressed as an increase in overall 

IQ points in the exposed population. EPA monetized the 

estimated changes in IQ scores based on the impact of 

additional IQ points on individuals’ future earnings. EPA 

assumed that each IQ point is worth between $1,156 
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(following Schwarz (1994) and discounting future earnings 

at 7 percent) and $13,651 (following Salkever (1995) and 

discounting future earnings at 3 percent). 

Benefits from Reduced Need for Specialized Education for 

Children from Lead Exposure via Fish Consumption. EPA also 

quantified the reduced incidences of especially high bloodlead levels (above 20 mg/dL) and low IQ scores (<70, or two 

standard deviations below the mean), and monetized the 

avoided costs associated with compensatory education that 

an individual would otherwise need. For this analysis, EPA 

used the IEUBK model to predictestimate how many children 

in the exposed population would have blood lead 

concentrations above 20 mg/dL, and assumed that 20 percent 

of those children would have IQ scores below 70. Based on 

education cost data from the United States Department of 

Education, EPA assumed that the incremental cost of special 

education for these individuals and ages 7 through 18 would 

be approximately $157,000 per child at a 3 percent discount 

rate, and $125,500 per child at a 7 percent discount rate.

Benefits of Reduced In-utero Mercury Exposure via Maternal 

Fish Consumption. Mercury is a highly toxic pollutant that 

presents serious health risks to adults and children, even 

in very small doses. Health effects can include damage to 

the brain, kidneys, heart, and especially nervous system. 

These impacts are particularly harmful for children, who 

can experience profound and permanent developmental and 

neurological delays as a result of exposure in-utero. EPA 

estimated the IQ-related benefits associated with reduced 

in-utero mercury exposure from maternal fish consumption in 

exposed populations. EPA used data on the populations 

living within 100 miles of affected waterbodies, statespecific average fishing rates, presence of fish 

consumption advisories, the availability of substitute 

fishing locations, average household size, the number of 

women of childbearing age, and state-specific birth rates 

to estimate the number of births in the exposed population. 

Based on a dose-response function developed by Axelrad et 

al. (2007), EPA assigned a 0.18 point IQ loss for each 1 

ppm increase in maternal hair mercury. To translate the 

daily mercury ingestion rate by women of childbearing age 

in the exposed populations to hair mercury concentrations, 

EPA used a conversion rate derived by Swartout and Rice 

(2000). Including decreased lifetime earnings and avoided 

education costs, EPA assumed that the value of an IQ point 

is between $1,156 and $13,651 over the life of each 

individual.

Formatted: Font: Not Bold, Underline
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Table XIV-2 summarizes monetized human health benefits 

associated with eachfive of the fiveeight regulatory options 

considered in today’s proposed rule using 3 percent and 7 

percent discount rates. As mentioned above, EPA did not 

monetize the human health benefits associated with Options 3a, 

3b and 4a. EPA expects the benefits of Option 4a to be between 

those of Options 3 and 4.

Table XIV-2. Annualized Human Health Benefits (Million 2010$)c

Human Health Benefit 

Category

Option 

1

Option 

2

Option 

3

Option 

4

Option 

5

3% Discount Rate

Benefits from Reduced 

Incidence of Cancer from 

Arsenic Exposure via Fish 

Consumption

<$0.1 <$0.1 $0.1 $0.2 $0.2 

Benefits from Reduced IQ 

Loss in Children from Lead 

Exposure via Fish 

Consumption a

$0.1 $0.1 $2.7 $6.7 $6.7

($0.1 

to 

$0.1)

($0.1 

to 

$0.1)

($2.2 

to 

$3.2)

($5.6 

to 

$7.9)

($5.6 

to 

$7.9)

Benefits from Reduced Need 

for Specialized Education 

for Children from Lead 

Exposure via Fish 

Consumption

<$0.1 <$0.1 <$0.1 $0.1 $0.1 

(<$0.1 

to 

<$0.1)

(<$0.1 

to 

<$0.1)

(<$0.1 

to 

<$0.1)

($0.1 

to 

$0.1)

($0.1 

to 

$0.1)

Benefits of Reduced Inutero Mercury Exposure via 

Maternal Fish Consumption 

a

$3.8 $3.9 $5.0 $10.2 $10.2

($3.2 

to 

$4.5)

($3.2 

to 

$4.6)

($4.1 

to 

$5.8)

($8.4 

to 

$12.1)

($8.4 

to 

$12.1)

Total Human Health 

Benefitsb

$3.9 $4.0 $7.7 $17.2 $17.2

$3.21 

to 

$4.59)

($3.28 

to 

$4.69)

($6.4 

to 

$9.11)

($14.2 

to 

$20.2)

($14.2 

to 

$20.2)

7% Discount Rate

Benefits from Reduced 

Incidence of Cancer from 

Arsenic Exposure via Fish 

Consumption

<$0.1 <$0.1 $0.1 $0.1 $0.1 

Benefits from Reduced IQ 

Loss in Children from Lead 

Exposure via Fish 

Consumption a

<$0.1 <$0.1 $0.2 $0.6 $0.6

(<$0.1 

to 

<$0.1)

(<$0.1 

to 

<$0.1)

($0.2 

to 

$0.3)

($0.4 

to 

$0.8)

($0.4 

to 

$0.8)

Benefits from Reduced Need <$0.1 <$0.1 <$0.1 <$0.1 <$0.1

Formatted Table

Formatted Table

Formatted Table
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Table XIV-2. Annualized Human Health Benefits (Million 2010$)c

Human Health Benefit 

Category

Option 

1

Option 

2

Option 

3

Option 

4

Option 

5

for Specialized Education 

for Children from Lead 

Exposure via Fish 

Consumption

(<$0.1 

to 

<$0.1)

(<$0.1 

to 

<$0.1)

(<$0.1 

to 

<$0.1)

(<$0.1 

to 

<$0.1)

(<$0.1 

to 

<$0.1)

Benefits of Reduced Inutero Mercury Exposure via 

Maternal Fish Consumption 

a

$0.3 $0.4 $0.4 $0.9 $0.9

($0.2 

to 

$0.5)

($0.2 

to 

$0.5)

($0.3 

to 

$0.6)

($0.6 

to 

$1.2)

($0.6 

to 

$1.2)

Total Human Health 

Benefitsb

$0.4 $0.4 $0.7 $1.6 $1.6

($0.2 

to 

$0.5)

($0.2 

to 

$0.5)

($0.5 

to 

$1.0)

($1.1 

to 

$2.1)

($1.1 

to 

$2.1)

a lowLow end assumes that the loss of one IQ point results in the loss of 

1.76% of lifetime earnings (following Schwartz, 1994); high end assumes 

that the loss of one IQ point results in the loss of 2.38% of lifetime 

earnings (following Salkever, 1995).

b totalsTotals may not add up due to independent rounding.

c EPA did not estimate the benefits of Options 3a, 3b and 4a. EPA expects 

the benefits of Option 4a to be between those of Options 3 and 4.

b. Reduced Exceedances of Health-Based AWQC

EPA expects that additional health benefits will arise from 

reduced discharges of steam electric pollutants; however, 

monetary valuation of these other health benefits is not 

currently possible due to lack of data on a dose-response 

relationship between pollutant ingestion rate and potential 

adverse health effects. To provide an additional measure of the 

potential health benefits of the proposed ELGs, EPA estimated 

the effect of steam electric plant discharges on the occurrence 

of pollutant concentrations in affected waterways that exceed 

human health-based ambient water quality criteria (AWQCs).88

 

88 Including AWQCs for the protection of human health through consumption of 

organisms and water.

Formatted Table
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Pollutant concentrations in excess of these values indicate 

potential risks to human health. This analysis and its findings 

are not additive to the preceding analyses of change in cancer 

or lead-related health risks but are another way of 

quantitatively characterizing possible benefit categories. 

EPA estimates that in-stream concentrations of steam 

electric pollutants (i.e., arsenic, cadmium, chromium, copper, 

lead, mercury, nickel, selenium, thallium, and zinc) exceed 

human health criteria for consumption of water and organisms for 

at least one pollutant in 146 receiving reaches nationwide in 

the baseline. Depending on the regulatory option, EPA expects 

that the proposed rule would eliminate the occurrence of 

concentrations in excess of human health criteria for 

consumption of water and organisms for 0 to 98 of the 

contaminated reaches, and reduce the number of exceedances in 9 

to 27 reaches. Option 3 is estimated to eliminate exceedances in 

27 receiving reaches, out of the 146 receiving reaches with 

exceedances in the baseline, while Option 4 is estimated to 

reduce exceedances in 98 reaches and eliminate exceedances 

altogether in 24 of those reaches. EPA did not quantitatively 

analyze the change in exceedances for Options 3a, 3b and 4a. 

However, EPA expects the effects of Option 4a to be between 

those of Options 3 and 4 (i.e., reduce or eliminate exceedances 

in between 27 and 98 receiving reaches).
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2. Improved Ecological Conditions and Recreational Use Benefits 

from Surface Water Quality Improvements

EPA expects the proposed ELGs to provide ecological 

benefits by improving ecosystems (aquatic and terrestrial) 

affected by the electric power industry’s effluent discharges. 

Benefits associated with changes in aquatic life include 

restoration of sensitive species, recovery of diseased species, 

changes in taste-and odor-producing algae, changes in dissolved 

oxygen (DO), increased assimilative capacity of affected 

waterways, and improved related recreational activities. 

Activities such as fishing, swimming, wildlife viewing, camping, 

waterfowl hunting, and boating may be enhanced when risks to 

aquatic life and perceivable water quality effects associated 

with pollutants are reduced. The magnitude of these benefits 

depends on the regulatory option.

EPA was able to monetize several categories of ecological 

benefits associated with today’s proposed rule, including 

recreational use and nonuse (i.e., existence, bequest, and 

altruistic) benefits from improvements in the health of aquatic 

environments, and nonuse benefits from increased populations of 

threatened and endangered species. As shown in Table XIV-1, the 

Agency quantified and monetized two main benefit subcategories, 

discussed below: (1) benefits from improvements in surface water 
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quality, and (2) benefits from improved protection of threatened 

and endangered (T&E) species.

a. Improvements in Surface Water Quality 

EPA expects today’s proposed ELGs to improve aquatic 

species habitats by reducing concentrations of toxic 

contaminants such as arsenic, cadmium, chromium, lead, mercury, 

nickel, selenium, and zinc in water. The rule is also expected 

to reduce nitrogen and phosphorus concentrations. These 

improvements would be expected to enhance the quality and value 

of water-based recreation. For example, some of the streams that 

were not usable for recreation under the baseline discharge 

conditions may become usable following implementation of the 

rule, thereby expanding options for recreational users. Streams 

that have been used for recreation under the baseline conditions 

can become more attractive for users by making recreational 

trips even more enjoyable. Individuals may also take trips more 

frequently if they enjoy their recreational activities more. 

Today’s proposed ELGs are also expected to generate nonuse 

benefits from bequest, altruism, and existence motivations. 

Individuals may value the knowledge that water quality is being 

maintained, ecosystems are being protected, and species 

populations are healthy, independently of their use.

To calculate baseline and post-compliance water quality, 

EPA utilized a water quality index (WQI) that translates water 
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quality measurements, gathered for multiple parameters that are 

indicative of various aspects of water quality, into a single

numerical indicator that reflects achievement of quality 

consistent with certain uses. The WQI provides the link between 

specific pollutant levels, as reflected in individual 

parameters, and the presence of aquatic species and suitability 

for particular recreational uses. Traditionally, WQIs are based 

on conventional pollutants (e.g., TSS, BOD, and fecal coliform) 

and nutrients (nitrogen and phosphorus). To account for water 

quality improvements resulting from reductions in toxic 

pollutants, EPA expanded the set of WQI parameters to include 

metals. The metals sub-index follows an approach developed by 

the Canadian Council of Ministers of the Environment (CCME) and 

uses the number of AWQC exceedances for a given waterbody in the 

baseline and/or under a given regulatory option.89 EPA assigned 

all parameters in the index an equal weight of 1/7th following 

other studies that use equal weights for all index parameters 

(Cude 2001, CCME 2001, and Carruthers and Wazniak 2003).

EPA calculated baseline and post compliance WQI values for 

reaches affected by steam electric plant discharges. Baseline 

and post compliance water quality data were taken from several 

sources including USGS’s SPARROW model, EPA’s Risk-Screening 

 

89 There may be between 0 and 8 exceedances per waterbody (freshwater chronic 

AWQC values are available for arsenic, cadmium, chromium, lead, mercury, 

nickel, selenium, and zinc).
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Environmental Indicators (RSEI) model, EPA’s STORET data 

warehouse, and estimated in-stream concentrations of steam 

electric pollutants. These sources provide water quality for 

stream networks defined according to the medium-resolution NHD 

or RF1. EPA conducted the benefits analysis at the level of RF1 

reaches and mapped NHD data to the appropriate RF1, as needed,

depending on the data source. EPA estimates that 3,945 reach 

miles would improve under Option 1 for existing sources, 12,683 

miles under Option 2, 15,682 miles under Option 3, 22,447 reach 

miles under Option 4, and 22,447 reach miles under Option 5.441

reach miles under Option 5. EPA did not estimate the number of 

reach miles that would improve under Option 4a but expects 

improvements to be between those of Options 3 and 4 (i.e., 

between 15,682 and 22,447 reach miles). 

EPA estimated monetized benefit values using a metaregression of surface water valuation studies originally 

developed for the Effluent Guidelines and Standards for the 

Construction and Development Point Source Category (U.S. EPA, 

2009). EPA used two benefit functions for each reach; one for 

households within a 100-mile radius of the reach that may have 

user values and one for nonuser households, located in the same 

state as the reach, but outside the 100-mile radius. Each 

benefit function was estimated for the years between 2014 and 

2040, although benefits start accruing in 2017 when certain 
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plants would be expected to start installing control 

technologies under today’s proposal (i.e., no benefits are 

assumed for 2014-2016). EPA estimated total benefits for each 

group –– users and nonusers – as follows:

The Agency first estimated annual household WTP values for 

a given reach and year using the meta-analysis regression. 

WTP values are a function of (1) reach-specific baseline 

and change in water quality values in a given year and (2) 

median household income values estimated for a given state 

or buffer zone in that year. For this analysis, two benefit 

functions were used for each reach in a given year; one for 

households that may have user values (households located 

within 100 miles of the reach) and one for nonuser 

households (households located with the same state as the 

reach, but outside the 100-mile buffer).

To estimate total WTP values, the Agency multiplied annual 

household WTP values by the percent of total reach miles 

within the state or buffer and the total number of 

households within the state or buffer for a given year.

EPA then discounted total WTP values to 2014, the expected 

promulgation year of the rule, and annualized them using a 

3 and 7 percent discount rate. 

A challenge for meta-analysis is developing a framework 

that both controls for differences in studies and can be used 

for meaningfully predicting benefits associated with regulatory 

options. In earlier benefits estimation for effluent 

guidelines, EPA often relied on the Carson and Mitchell (1993) 

water quality values. These values come from a survey that was 

one of the first major stated preference efforts, fielded in the 

early 1980s. The study reported values for all of the nation’s 

waters, using the same WQI that is used in the meta-analysis.

When EPA used the Carson and Mitchell values, the Agency was 
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able to tailor its benefits estimates to its regulations in two 

important dimensions: the level of water quality improvement, 

and the percent of the nation’s waters being improved. EPA is 

basing today’s benefits analysis on the meta-analysis because 

stated preference methodology and practices have advanced 

considerably since the Carson and Mitchell study (although 

methodological issues continue to be debated in the stated 

preference literature), more studies have been conducted, and 

changes in individuals’ preferences and income may well result 

in changing water quality values.

A trade-off, however, in using the meta-analysis is the 

difficulty in representing the percent of the nation’s waters 

that are being improved, in addition to combining the results of 

studies encompassing a variety of water quality improvements, 

geographic scales, and resource characteristics that has led to 

both expected results and results that are counterintuitive. To 

provide perspective on these different approaches to measure 

water quality improvement benefits, EPA is also reporting the 

water quality values obtained by applying the Carson and 

Mitchell values. In 2011 dollars, using a 3 percent discount 

rate, these values are: for Option 1, $0.5 million; for Option 

2, $2.9 million; for Option 3, $4.5 million; for Option 4, $12.9 

million; and for Option 5, $12.7 million. EPA requests comment 

on its reliance on the meta-analysis values rather than the 
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Carson and Mitchell values (or some other values) as the basis 

for estimating water quality benefits of the proposed rule.

Commenters should address methodological strengths and 

weaknesses of any suggested approach, and explain the basis for 

their recommendation.

b. Benefits to Threatened and Endangered (T&E) Species 

To assess the potential for impacts on threatened and 

endangered (T&E) species (both aquatic and terrestrial), EPA 

constructed a database of waterbodies currently exceeding 

wildlife-based AWQC but expected to have no wildlife AWQC 

exceedances as a result of the proposed ELGs. EPA then assessed 

the overlap between this geographic database and the known 

locations of approximately 530 T&E species. Once species 

overlapping waterbodies of interest were identified, EPA 

examined their life history traits to categorize species by the 

potential for population impacts likely to occur as a result of 

changes in water quality. T&E species with high probability of 

life-history effects were further screened to identify those 

species for which water quality was identified as a factor for 

listing under the Endangered Species Act (ESA) or as a limiting 

factor within species recovery plans. Because of this analysis, 

EPA identified seven fish species and one dragonfly species that 

may experience changes in population growth rates as a result of 
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the proposed ELGs. EPA did not identify data sufficient to 

explicitly model the effects of changes in water quality on 

population growth rates for these species. Therefore, to 

estimate total population increases resulting from the proposed 

ELGs, EPA assumed minimal increases in population size of 0.5, 

1, or 1.5 percent. To estimate monetary benefits to T&E species, 

EPA weighted these population growth estimates by the percent of 

reaches used by T&E species that are expected to meet wildlifebased AWQC because of the proposed ELGs.

The T&E species expected to benefit from the rule include 

two species of sturgeon and five species of small minnows. All 

of these species have nonuse values including existence, 

bequest, altruistic, and ecological service values apart from 

human uses or motives.

To estimate the potential economic values of increased T&E 

species populations affected by the proposed ELGs under each of 

the five regulatory options, EPA used a benefit function 

transfer approach based on a meta-analysis of 31 stated 

preference studies eliciting WTP for these changes (Richardson 

and Loomis 2009). This meta-analysis is based on studies 

conducted in the United States that valued threatened, rare, or 

endangered fish, bird, reptile, or mammal species. Because the 

underlying meta-data does not include insect valuation studies, 

EPA was unable to monetize any benefits for potential population 
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increases of Hine's Emerald Dragonfly due to the proposed rule. 

For each state containing T&E species estimated to show 

population growth because of the proposed ELGs, EPA calculated 

benefits using the weighted population growth assumptions under 

each analytic scenario (regulatory option and population 

increase assumption). For states with more than one T&E species 

estimated to see population growth, EPA only monetized the value 

for the species projected to see the greatest proportional 

population increase. Because population growth was calculated at 

the state level, EPA was unable to calculate benefits based on 

when each steam electric plant is assumed to install control 

technologies to comply with the proposed ELGs. EPA therefore

assumed that benefits begin accruing in 2019 for all states

because this is the midpoint of the compliance period used in 

other cost and benefit analyses and thus provides a reasonable 

assumption.

There may be some overlap between WTP estimates for T&E 

species and the WTP estimates for improvements in water quality; 

however, the magnitude of this overlap is likely to be minimal 

because none of the studies in EPA’s meta-analysis of WTP for 

water quality improvements specifically mentioned or otherwise 

prompted respondents to include benefits to T&E species 

populations. 
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Table XIV-3 summarizes the results of EPA’s analysis of 

benefits from improved ecological conditions and recreational 

uses. for five of the eight regulatory options. EPA did not 

estimate the benefits of Options 3a, 3b and 4a. As for the other 

benefit categories, however, the Agency expects the benefits of 

Option 4a to be between those of Options 3 and 4 (i.e., between 

$59.9 million and $116.1 million annually, at 3 percent discount 

rate).

Table XIV-3. Annualized Ecological Conditions and Recreational 

Uses Benefits (Million 2010$)e

Benefit 

Category Option 1 Option 2 Option 3 Option 4 Option 5

3% Discount Rate

Improved

Surface Water 

Qualitya

$8.3 $38.0 $49.9 $82.8 $81.9 

($2.0 to 

$22.4)

($7.1 to 

$107.1)

($10.2 to 

$137.6)

($19.6 to 

$215.8)

($19.3 to 

$214.1)

Benefits to E&T 

Speciesb

$7.0 $7.0 $10.0 $33.3 $33.3 

($3.9 to 

$10.0)

($3.9 to 

$10.0)

($5.5 to 

$14.2)

($18.2 to 

$47.3)

($18.2 to 

$47.3)

Total 

Ecological and 

Recreational 

Uses Benefitsd

$15.3 $45.0 $59.9 $116.1 $115.2

($5.8 to 

$32.4)

($11.0 to 

$117.7)

($15.7 to 

$151.8)

($37.8 to 

$263.1)

($37.5 to 

$261.4)

7% Discount Rate

Improved 

Surface Water 

Qualitya

$6.9 $31.7 $41.7 $69.2 $68.5

($1.6 to 

$18.7)

($6.0 to 

$48.3)

($8.5 to 

$115.0)

($16.4 to 

$180.3)

($16.1 to 

$178.9)

Benefits to E&T 

Speciesb

$5.9 $5.9 $8.4 $27.8 $27.8

($3.2 to 

$8.4)

($3.2 to 

$8.4)

($4.6 to 

$11.9)

($15.2 to 

$39.5)

($15.2 to 

$39.5)

Total 

Ecological and 

Recreational 

Uses Benefitsd

$12.8 $37.6 $50.1 $97.0 $96.2 

($4.8 to 

$27.0)

($9.1 to 

$56.6)

($13.1 to 

$126.9)

($31.6 to 

$219.8)

($31.3 to 

$218.4)

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Table XIV-3. Annualized Ecological Conditions and Recreational 

Uses Benefits (Million 2010$)e

Benefit 

Category Option 1 Option 2 Option 3 Option 4 Option 5

a Values represent partial benefits only for reaches that receive direct 

discharges from steam electric plants. Range in parenthesis represents the 

5th and 95th percentile of the WTP distribution.

b Range in parenthesis provides the low and high bound estimates.

c Range in parenthesis provides the 5th and 95th percentile of the WTP 

distribution incorporating minimum and maximum flow reduction assumptions.

d Totals may not add up due to independent rounding.

e EPA did not estimate the benefits of Options 3a, 3b and 4a. EPA expects the 

benefits of Option 4a to be between those of Options 3 and 4.

3. Groundwater Quality Benefits From Reduced Groundwater 

Contamination

EPA expects that some of the regulatory options will 

eliminate the future leaching of steam electric pollutants from 

steam electric impoundments to groundwater aquifers. The Agency 

monetized the associated benefits to households using private 

drinking wells in the vicinity of steam electric plants based on 

a benefits transfer from groundwater valuation studies. 

Specifically, EPA used existing groundwater valuation studies to 

derive household WTP estimates for two categorical improvements 

in groundwater quality: (1) “greatly improved” and (2) 

“improved.”

EPA identified the exposed population as the number of 

households using private drinking water wells in the vicinity of 

steam electric impoundments. EPA then modeled pollutant 

concentrations in the affected aquifers and determined which 

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aquifers exceed maximum contaminant levels (MCLs) for steam 

electric pollutants under the baseline. EPA assumed that if a 

plant ceases to use impoundments to handle combustion waste 

because of the proposed ELGs, these aquifers would improve, with 

an average household WTP of $450. For impoundments that continue 

to receive combustion wastes but in smaller amounts, EPA assumed 

that the plant-specific benefits would be proportional to the 

reduction in wastewater flows going to the impoundment, and 

scaled the benefits accordingly.

Table XIV-4 summarizes the results of EPA’s analysis of the 

groundwater benefits. As for other benefit categories, EPA did 

not analyze the benefits of Options 3a, 3b and 4a. EPA expects 

the benefits of Option 4a to be between those of Options 3 and 4 

(i.e., $1.6 million to $6.5 million annually, at 3 percent 

discount rate).

Table XIV-4. Annualized Groundwater Quality Benefits (Millions 

2010$)

Discount Rate Option 1 Option 2 Option 3 Option 4 Option 5

3% Discount 

Rate

$0.7 $0.7 $1.6 $6.5 $6.5 

7% Discount 

Rate

$0.6 $0.6 $1.4 $5.5 $5.5

4. Market and Productivity Benefits (Benefits from Reduced 

Impoundment Failures)

Operational changes prompted by compliance with the 

proposed ELGs may cause some plant owners to reduce their 

reliance on impoundments to handle their waste. EPA expects 

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these changes to reduce future impacts from impoundment 

failures. 

To assess the benefits associated with changes in 

impoundment use, EPA estimated the costs associated with 

expected failures for baseline conditions (assuming no change in 

operations) and for projected reductions in the amount of CCR 

waste managed by impoundments for eachfive of the fiveeight

regulatory options. (Options 1, 2, 3, 4, and 5). EPA performed 

the calculations for each of the 1,070 impoundments identified 

at steam electric plants, and for each year between 2014 and 

2040. EPA then calculated benefits as the difference between 

expected failure costs for a regulatory option and expected 

failure costs under baseline conditions.

To estimate the number of structural failure events that 

may be avoided as a result of the proposed ELGs, EPA used data 

on historical impoundment failures collected by EPA’s Office of 

Resource Conservation and Recovery (ORCR) for its Regulatory 

Impact Analysis for EPA’s Proposed Regulation of Coal Combustion 

Residues Generated by the Electric Utility Industry (Proposed 

CCR Rule; U.S. EPA 2010). Based on historical data, EPA 

estimated an average failure rate of 0.58 percent per 

impoundment per year and used this average failure rate to 

calculate the expected number of failure events in the baseline 
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and under each of the regulatory options.90 EPA also used data on 

historical failure events to develop average cleanup, natural 

resource damages91, and litigation costs92 per event. As detailed 

in Chapter 7 of the BCA, EPA used average total costs of $0.3106

per gallon of impoundment capacity to estimate the expected 

costs of an impoundment failure.93 EPA did not calculate benefits

for years 2014 through 2018 because EPA conducted surface 

impoundment integrity site assessments in 2009 through 2012 and 

expects the assessments and the recommended “action plan” 

improvements to impoundment structures will prevent all failures 

for the first five years after improvement are completed (i.e., 

2014 through 2018). 

Table XIV-5 presents the analysis results. Depending on the 

regulatory option, annual benefits range between $177from $62.1

 

90 EPA also estimated benefits using a best-fit regression equation developed 

based on the historical data that relates the probability of impoundment 

failure to impoundment capacity. For details, see Appendix G of the BCA. 

91 Natural resource damages do not include cleanup costs (or legal costs) but 

include only the resource restoration and compensation values. For example, 

in one case, Israel (2006) found that "In total, the State's claim was $764 

million, $342 million of which was restoration cost damages, $410 million of 

which was compensable value damages, and $12 million of which was assessment 

and legal costs." For this case, EPA used the sum of $342 million and $410 

million (excluded legal costs) as the value of natural resource damages.

92 For this analysis, litigation costs include the costs associated with 

negotiating NRD, determining responsibility among potentially responsible 

parties, and litigating details regarding settlements and remediation. These 

activities involve services, whether performed by the complying entity or 

other parties that EPA expects would be required in the absence of this 

regulation in the event of an impoundment failure. Note that the litigation

costs do not include fines, cleanup costs, damages, or other costs that 

constitute transfers or are already accounted for in the other categories 

analyzed separately.

93 This estimate assumes that each failure results in a spilled volume equal 

to 6.45 percent of the impoundment capacity, based on the average ratio of 

spill volume to impoundment capacity for 15 releases for which ORCR obtained 

both spill volume and capacity data.
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million to $695295.1 million (at 3 percent discount rate), with 

the preferred BAT and PSES options Option 3 having expected 

benefits of $267 million and $695114.8 million per year, 

respectively for. EPA did not estimate the benefits of Options 

3a, 3b and 4a; the Agency expects the benefits of Option 4a to 

be between those of Options 3 and 4. (i.e., $114.8 million to 

$295.1 million, at 3 percent discount rate). Note that these 

benefits do not include the effects of BMPs that may reduce the 

probability of failures and therefore would be expected to 

increase the benefits of the proposed ELGs. EPA will continue to 

seek ways to quantify and monetize BMP-related benefits in 

analyses for the final rule, should EPA ultimately include such 

BMPs as part of the final ELGs.

Table XIV-5. Annualized Benefits of Reduced Impoundment Failures 

(Million 2010$)

Discount 

Rate Option 1 Option 2 Option 3 Option 4 Option 5

3% Discount 

Rate

$177.462.1 $177.462.1 $267.6114.

8

$694.7295.

1

$694.7295.

1

7% Discount 

Rate

$148.652.2 $148.652.2 $224.095.9 $579.6245.

9

$579.6245.

9

5. Air-Related Benefits (Reduced Mortality and Avoided Climate 

Change Impacts)

The proposed ELGs are expected to affect air pollution 

through three main mechanisms: 1) additional auxiliary 

electricity use by steam electric plants to operate wastewater 

treatment, ash handling, and other systems needed to comply with 

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the new effluent limitations and standards; 2) additional 

transportation-related emissions due to the increased trucking 

of CCR waste to landfills; and 3) the change in the profile of 

electricity generation due to the relatively higher cost to 

generate electricity at plants incurring compliance costs for 

the proposed ELGs. Changes in the profile of generation can 

result in lower or higher air pollutant emissions because of 

variability in emission factors for different types of 

electricity generating units. See Section XIV.B of this preamble 

for details.For this analysis, the changes in air emissions are 

based on the change in dispatch of generation units projected by 

IPM as a result of overlaying the costs of the proposed ELGs 

onto steam electric units production costs. 

In this analysis, EPA estimated the human health and other 

benefits resulting from net changes in air emissions of three 

pollutants: nitrogen oxides (NOx), sulfur dioxide (SO2), and 

carbon dioxide (CO2). NOx and SOx are known precursors to fine 

particles (PM2.5), a criteria air pollutant that has been 

associated with a variety of adverse health effects – most 

notably, premature mortality. CO2 is an important greenhouse gas 

that is linked to a wide range of climate change effects. 

EPA used average benefit-per-ton (BPT) estimates to value 

benefits of changes in NOX and SO2 emissions, and social cost of 

carbon (SCC) estimates to value benefits of changes in CO2
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emissions. Because the analysis relies in part on estimates of 

air emissions obtained from IPM, EPA estimated air-related 

benefits for Options 3 and 4 only, as these are the two options 

analyzed in IPM. Table XIV-6 summarizes the annualized benefits 

associated with changes in air pollutant emissions. Chapter 8 in 

the BCA report provides the details of this analysis.

Table XIV-6. Annualized Benefits of Changes in NOx, SO2, and CO2 

Air Emissions (Million 2010$)c

Discount Rate

Option 1 Option 2

Option 3

O

p

t

i

o

n

4

O

p

t

i

o

n

5

3% Discount Rate (for 

NOx, SO2, and CO2-

related benefits)

Not 

estimate

d

Not 

estimate

d $127.6

$

1

7

0

.

5

N

o

t

e

s

t

i

m

a

t

e

d

7% Discount Rate (for 

NOx, SO2, and CO2-

related benefits)a,b

Not 

estimate

d

Not 

estimate

d $82.3

$

7

4

.

6

N

o

t

e

s

t

i

m

a

t

e

d

a. Because SCC values are not available for the 7 percent discount rate, EPA 

used the SCC based on a 5 percent discount rate to estimate values presented 

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for the 7 percent discount rate. EPA uses 5 percent to discount CO2-related 

benefits and 7 percent to discount benefits from changes in NOx and SO2 

emissions.

b. Air benefits for Option 4 at the 7 percent discount rate are lower than 

benefits estimated for Option 3 due to (1) smaller SO2 emissions reductions 

projected by IPM for Option 4 than Option 3 in early years and (2) 

differences in source- and discount-specific BPT and SCC values.

c. EPA did not estimate the benefits of Options 3a, 1, 2, 3b, 4a and 5. EPA 

expects the benefits of Option 4a to be between those of Options 3 and 4.

6. Benefits from Reduced Water Withdrawals (Increased 

Availability of Groundwater Resources)

Steam electric plants use water for handling solid waste 

(e.g., fly ash, bottom ash) and for operating wet FGD scrubbers. 

By eliminating or reducing water used in sluicing operations or 

prompting the recycling of water in FGD wastewater treatment 

systems, the proposed ELGs are expected to reduce water 

withdrawals from surface waterbodies and reduce demand on 

aquifers, in the case of plants that rely on groundwater 

sources.

EPA estimated the benefits of reduced groundwater 

withdrawals based on avoided costs of groundwater supply. For 

each affected facility and regulatory option, EPA multiplied the 

reduction in groundwater withdrawal (in gallons per year) by 

water costs ranging between $150 and $500 per acre-foot.

Table XIV-7 summarizes the annualized benefits associated 

with changes in water use by steam electric plants. for five of 

the eight options. Chapter 9 in the BCA report provides the 

details of this analysis. While EPA did not estimate benefits of 
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Options 3a, 3b and 4a, the Agency expects the benefits of Option 

4a to be between those of Options 3 and 4.

Table XIV-7. Annualized Monetized Benefits of Reduced Water 

Withdrawals by Steam Electric Plants (Million 2010$)a

Benefit 

Category Option 1 Option 2 Option 3 Option 4 Option 5

3% Discount Rate

Avoided 

groundwater 

withdrawals

$0.0 $0.0 <$0.1 $0.1 $0.1

7% Discount Rate

Avoided 

groundwater 

withdrawals

$0.0 $0.0 <$0.1 $0.1 $0.1

a. EPA did not estimate the benefits of Options 3a and 4a. EPA expects the 

benefits of Option 4a to be between those of Options 3 and 4.

C. Total Monetized Benefits

Using the analysis approach described above, EPA estimates 

annual total benefits for the six monetized categories at

approximately $197.382 million to $1,005.1605.5 million (at 3 

percent discount rate), depending on the option and based on 

EPA’s analysis of five of the eight regulatory optionoptions

(Table XIV-8). The preferred BAT and PSES options haveoption 3 

has annual total benefits estimated at $464.5311.7 million and 

1,005.1 million, respectively for Options 3 and 4 (at a 3 

percent discount rate). While EPA did not quantify the benefits 

of the other three preferred BAT and PSES Options (Option 3a, 

Option 3b and Option 4a), EPA expects the annual total benefits 

of Option 4a to be between those of Option 3 and 4 (i.e., $311.7 

million to $605.5 million at 3 percent discount rate).

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The monetized benefits of today’s proposed rule do not 

account for all benefits because, as described above, EPA is 

unable to monetize some categories. Examples of benefit 

categories not reflected in these estimates include non-cancer 

health benefits (other than IQ benefits from reduced childhood 

exposure to lead and in-utero exposure to mercury) and reduced 

cost of drinking water treatment for the pollutants with 

drinking water criteria. In addition, EPA’s analysis of human 

health benefits associated with water quality improvements 

includes only partial benefits for directly receiving reaches. 

EPA will continue to seek ways to monetize benefit 

categories not monetized in today’s proposal in order to provide 

a more accurate representation of benefits of the proposed rule. 

Table XIV-8. Summary of Total Annualized Monetized Benefits of 

Proposed ELGs (Million 2010$)f

Benefit Category Option 1 Option 2 Option 3 Option 4 Option 5

3 Percent Discount Rate

Human Health 

Benefitsa,c

$3.9 $4.0 $7.7 $17.2 $17.2

Improved 

Ecological 

Conditions and 

Recreational 

Usesa,b

$15.3 $45.0 $59.9 $116.1 $115.2

Groundwater 

Quality Benefits

$0.7 $0.7 $1.6 $6.5 $6.5

Market and 

Productivity 

Benefits

$177.462.

1

$177.462.

1

$267.6114

.8

$694.7295

.1

$694.7295

.1

Air-Related 

Benefitsd

NE NE $127.6 $170.5 NE

Reduced Water 

Withdrawals

$0.0 $0.0 $≤$0.1 $0.1 $0.1

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Table XIV-8. Summary of Total Annualized Monetized Benefits of 

Proposed ELGs (Million 2010$)f

Benefit Category Option 1 Option 2 Option 3 Option 4 Option 5

Total 

Benefitsabenefit

s, Excluding 

Air-Related 

Benefits

$197.3

$82.0

$227.0

$111.7

$464.5

$184.1

$1,005.1

$435.0

$833.7

$434.1

Total Benefits

(Including Airrelated 

Benefits)a

$311.7 $605.5

7 Percent Discount Rate

Human Health 

Benefitsa,c

$0.4 $0.4 $0.7 $1.6 $1.6

Improved 

Ecological 

Conditions and 

Recreational 

Usesa,b

$12.8 $37.6 $50.1 $97.0 $96.2 

Groundwater 

Quality Benefits

$0.6 $0.6 $1.4 $5.5 $5.5 

Market and 

Productivity 

Benefits

$148.652.

2

$148.652.

2

$224.095.

9

$579.6245

.9

$579.6245

.9

Air-Related 

Benefitsd,e

NE NE $82.3 $74.5 NE

Reduced Water 

Withdrawals

$0.0 $0.0 $0.0 $0.1 $0.1

Total 

Benefitsa,fTotal 

benefits, 

Excluding AirRelated Benefits 

$162.3

65.9

$187.1

90.7

$358.5

148.1

$758.5

350.2

$683.1

349.4

Total Benefits

(Including Airrelated 

Benefits)a

$230.4 $424.8

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Table XIV-8. Summary of Total Annualized Monetized Benefits of 

Proposed ELGs (Million 2010$)f

Benefit Category Option 1 Option 2 Option 3 Option 4 Option 5

a Values represent mean benefit estimates. Totals may not add up due to 

independent rounding. Option 5 results in slightly lower benefits because, 

under Option 4, EPA assumes that plants with both leachate and FGD waste 

streams implement chemical precipitation and biological treatment for the

combined streams. Under Option 5, EPA assumes that plants treat the two 

streams separately: FGD wastewater by evaporation and leachate using 

chemical precipitation (which removes less pollutant load than biological 

treatment).

b There may be some overlap between the willingness-to-pay (WTP) for surface 

water quality improvements and WTP for benefits to threatened and 

endangered species.

c Values represent partial human health benefits only for reaches that 

receive direct discharges from steam electric plants. 

d EPA estimated air-related benefits for Options 3 and 4 only because these 

benefits were estimated as part of the Agency’s analysis using IPM. Total 

benefits for Options 1, 2, and 5 are therefore understated. Air benefits 

for Option 4 at the 7 percent discount rate are lower than benefits 

estimated for Option 3 due to (1) smaller SO2 emissions reductions 

projected by IPM for Option 4 than Option 3 in early years and (2) 

differences in source- and discount-specific BPT and SCC values.

e Because SCC values are not available for the 7 percent discount rate, EPA 

used the SCC based on a 5 percent discount rate and discounted CO2-related 

benefits using a 5 percent discount rate, as compared to benefits in other 

categories, which are discounted using the 7 percent discount rate.

f Caution should be taken in comparing totals across options, as the airrelatedEPA did not estimate benefits were calculated for Options 3a, 3b 

and 4a, but expects the benefits of Option 4a to be between those of 

Options 3 and 4, but not for Options 1, 2 and 5, and this affects the 

relative totals.. 

Further, as noted earlier in this section, EPA calculated 

benefits for some of the options considered for this proposal. 

Benefits for these options, however, provide information 

relevant to understanding the potential magnitude of benefits 

under all proposed options, including Options 3a, 3b, and 4a. As 

explained earlier in this preamble, the facilities affected by 

Option 3a are a subset of Option 3 facilities; Option 3 benefit

estimates therefore provide an upper bound estimate of benefits 

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anticipated under Options 3a and 3b. In a similar way, EPA 

expects Option 4 to provide an upper bound estimate of benefits 

anticipated under Option 4a. As an illustrative analysis, EPA 

inferred the potential benefits associated with Options 3a and 

3b by subtracting the benefits for Option 2 (scaled up to 

include a rough estimate of air emissions benefits) from the 

benefits for Option 3, because Option 3 includes a combination 

of the wastestreams and control technologies in Options 3a and 

2. EPA inferred the potential benefits associated with Option 3b 

based on the pollutant loading reductions (pounds) projected for

Option 3b relative to pollutant loading reductions projected for

Option 2 (plus the fly ash dry handling benefits of Option 3a) 

because Option 3b includes both fly ash requirements and the 

Option 2 FGD wastewater treatment requirements for a subset of 

facilities. Specifically, EPA inferred the benefits of Options 

3a and 3b by multiplying the FGD benefits estimated for Option 2

by the ratio of pollutant loads removed by 3b over Option 2, and 

then adding in the fly ash benefits that are also included in 

Option 3b. Similarly, EPA inferred the potential benefits 

associated with Option 4a based on the bottom ash pollutant 

loading reductions projected for this option, relative to bottom 

ash pollutant loading reductions projected for Option 4, plus 

the benefits of Option 3, because Option 4a includes all of the 
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requirements of option 3 plus the bottom ash requirements of 

Option 4 for a subset of facilities. 

Table XIV-9 summarizes total annualized benefits estimated 

(or inferred using the calculations described above) for the 

eight options discussed in today’s proposal. Note that there is 

significant uncertainty in values inferred because the 

methodology used does not account for differences in the 

pollutants, receiving waterbodies, and exposed populations 

between the options. 

Table XIV-9: Total Monetized Benefits for the Proposed Rule 

(Millions; 2010)

Regulatory Option Method Total 

Monetized 

Benefits

3%

Total 

Monetized 

Benefits

7%

Option 1 Estimatea $82.0 $65.9

Option 3a Inferenceb $139.4 $104.8

Option 2 Estimatea $111.7 $90.7

Option 3b Inferenceb $205.5 $153.0

Option 3 Estimate $311.7 $230.4

Option 4a Inferenceb $482.5 $424.8

Option 4 Estimate $605.5 $424.8

Option 5 Estimatea $434.1 $349.4

a. Total benefits for Options 1, 2, and 5 do not include air-related 

benefits (see Table XIV-8) 

b. EPA did not estimate benefits for Options 3a, 3b and 4a. EPA inferred 

benefits for Options 3a, 3b, and 4a for illustrative purposes using 

elements of the more rigorous analysis done to estimate benefits for 

Options 3 and 4.

D. Children’s Environmental Health

As described in Section XIV.B.1, EPA assessed whether 

today’s proposed ELGs will benefit children by reducing health 

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risk from exposure to steam electric pollutants from consumption 

of contaminated fish tissue and improving recreational 

opportunities. The Agency was able to quantify two categories of 

benefits specific to children: (1) avoided neurological damage 

to pre-school age children from reduced exposure to lead and (2) 

avoided neurological damages from in-utero exposure to mercury. 

This analysis considered several measures of children’s 

health benefits associated with lead exposure for children up to 

age six. Avoided neurological and cognitive damages were 

expressed as changes in three metrics: (1) overall IQ levels; 

(2) the incidence of low IQ scores (<70); and (3) the incidence 

of blood-lead levels above 20 mg/dL. EPA’s methodology for 

assessing lead-related benefits to children is presented in 

Chapter 3 of the BCA report. EPA analysis shows that benefits to 

children from reduced lead discharges range from $0.1 million to 

$6.8 million (at 3 percent discount), depending on the 

regulatory option; annual benefits for the preferred BAT and 

PSES optionsOption 3 are estimated at $2.7 million and $6.8

million, respectively for Options 3 and 4 ((at a 3 percent 

discount rate). EPA did not quantify the benefits to children of 

Options 3a, 3b and 4a; however, the Agency expects the annual 

benefits of Option 4a to be between those of Options 3 and 4 

(i.e., between $2.7 million and $6.8 million).
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Children over the age of seven are also likely to benefit 

from reduced exposure to lead and the resultant neurological and 

cognitive damages, even though EPA did not quantify these 

benefits in its analysis of the proposed ELGs. Giedd et al. 

(1999) studied brain development among 10- to 18-year-old 

children and found substantial growth in brain development, 

mainly during early teenage years. This research suggests that 

older children may be hypersensitive to lead exposure, as are 

children aged 0 to 7. 

Additional benefits to children from reduced exposure to 

lead not quantified in this analysis may include prevention of 

the following adverse health effects: slowed or delayed growth, 

delinquent and anti-social behavior, metabolic effects, impaired 

heme synthesis, anemia, impaired hearing, and cancer.

EPA also estimated the IQ-related benefits associated with 

reduced in-utero mercury exposure from maternal fish consumption 

in exposed populations. Chapter 3 of the BCA report presents 

EPA’s methodology for assessing mercury-related benefits to 

children. Among approximately 1,932 babies born per year who are 

potentially exposed to discharges of mercury from steam electric 

plants, the proposed ELGs reduce total IQ point losses over the 

period of 2017 through 2040 by about 9,000 to 24,000 points, 

depending on the regulatory option. The monetary benefits 

associated with the avoided IQ point losses range from $3.8
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million and $10.2 million per year (mean estimate, at 3 percent 

discount rate), across the five options. The preferred BAT and 

PSES options are EPA analyzed. Option 3 is estimated to avoid 

the loss of about 12,000 and 24,000 IQ points in exposed 

infants, respectively for Options 3 and 4 over the 24-year 

period. The benefits associated with these avoided IQ point 

losses are estimated at $5.0 million andper year. EPA did not 

quantify the benefits to children of Options 3a, 3b and 4a; for 

Option 4a, however, EPA expects the annual benefits to be 

between those of Options 3 and 4 (i.e., $5.0 million to $10.2 

million per year, respectively for Options 3 and 4.).

XV. Non-Water Quality Environmental Impacts

The elimination or reduction of one form of pollution may 

create or aggravate other environmental problems. Therefore, 

Sections 304(b) and 306 of the Act require EPA to consider nonwater quality environmental impacts (including energy impacts) 

associated with ELGs. Accordingly, EPA has considered the 

potential impact of today’s regulatory options on air emissions, 

solid waste generation, and energy consumption. 

A. Energy Requirements

Steam electric power plants use energy when transporting 

ash and other solids on or off site, operating wastewater 

treatment systems (e.g., chemical precipitation, biological 

treatment), operating ash handling systems, or operating water 
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trucks for dust suppression. For those facilities that it

projected would incur costs to comply with today’s regulatory 

options, EPA considered whether or not there would be an 

associated incremental energy need. That need varies depending 

on the regulatory option evaluated and the current operations of 

the facility. Therefore, as applicable, EPA estimated the 

additional energy usage in megawatt hours (MWh) for equipment 

added to the plant systems or in consumed fuel (gallons) for 

transportation/operating equipment. Similarly, as applicable, 

EPA also estimated the decrease in energy requirements resulting 

from the reduction in wet sluicing operations and use of earth 

moving equipment. EPA scaled the facility-specific estimate to 

calculate the net increase in energy requirements for the 

regulatory options discussed in this rulemaking.

To determine potential increases in electrical energy use, 

EPA estimated the amount of energy needed to operate wastewater 

treatment systems and ash handling systems based on the 

horsepower rating of the pumps and other equipment. To determine 

potential decreases in electrical energy use, EPA estimated the 

amount of energy saved from reducing wet sluice pumping 

operations based on the horsepower rating of the pumps. See DCN 

SE01957 (Incremental Costs and Pollutant Removals for Proposed 

Effluent Limitations Guidelines and Standards for the Steam 

Electric Generating Point Source Category) for more information 
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on the specific calculations used to estimate changes in energy 

use. Table XV-1 shows the net change in annual electrical energy 

usage associated with the proposed regulation.

Energy usage also includes the fuel consumption associated 

with transportation. EPA estimated the need for increased 

transportation of solid waste and combustion residuals (e.g., 

ash) at steam electric power plants to on-site or off-site 

landfills using open dump trucks. The frequency and distance of 

transport depends on a plant’s operation and configuration. For 

example, the volume of waste generated per day determines the 

frequency with which trucks will be travelling to and from the 

storage sites. The availability of either an on-site or off-site 

non-hazardous landfill and its distance from the plant 

determines the length of travel time. EPA also estimated the 

energy usage associated with the dust suppression water trucks 

and earth moving equipment based on specific plant operations. 

For example, EPA calculated earth moving equipment energy usage 

only if the plant operates an impoundment. To determine the 

potential decrease in fuel consumption, EPA estimated the amount 

of fuel saved by reducing the number of backhoes needed to 

dredge solids from ash impoundments, due to the reduction of wet 

sluice operations. See DCN SE01957 (Incremental Costs and 

Pollutant Removals for Proposed Effluent Limitations Guidelines 

and Standards for the Steam Electric Generating Point Source 
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Category) for more information on the specific calculations used 

to estimate transportation fuel usage. Table XV-1 shows the net 

change in annual fuel consumption associated with the preferred 

BAT and PSES regulatory options (Options 3a, 3b, 3, and 44a).

To provide some perspective on the potential increase in 

annual electric energy consumption associated with the preferred

regulatory options, EPA compared the estimated increase in 

energy usage (MWh) to the net amount of electricity generated in 

a year by all electric power plants throughout the United 

States. According to EPA’s Emissions & Generation Resource 

Integrated Database (eGRID), the power plant industry generated 

approximately 3,951 million MWh of energy in 2009. EPA estimates 

that energy increases associated with the preferred BAT and PSES 

regulatory options range from less than 0.008003 percent (Option 

33a) to 0.017012 percent (Option 44a) of the total electricity 

generated by all electric power plants.

Similarly, EPA compared the additional fuel consumption 

(gallons) estimated for the preferred BAT and PSES regulatory 

options to national fuel consumption estimates for motor 

vehicles in the United States. According to the EIA, on-highway 

vehicles, which include automobiles, trucks, and buses, consumed 

approximately 34 billion gallons of distillate fuel oil in 2009. 

EPA estimates that the fuel consumption increase associated with 

the proposed Option 33a for BAT and PSES will be less than 
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0.009008 percent of total fuel consumption by all motor 

vehicles. Fuel consumption is estimated to increase by less than 

0.018009 percent under Options 3b and Option 43, and less than 

0.014 percent under Option 4a.

Table XV-1. Energy Use Associated With ELG Options 3 and 4

Table XV-1. Energy Use Associated With ELG Options 3a, 3b, 3, 

and 4a

Non-Water 

Quality Impact

ValueEnergy Use Associated with Proposed Rule

Option 3a Option 3b Option 3 Option 44a

Electrical 

Energy Usage

(MWh)

112,000 160,753 303,300 673,800472,369

Fuel

(Thousand 

Gallons)

2,867 2,903 3,040 6,0274,618

B. Air Pollution

The proposed ELGs are expected to affect air pollution 

through three main mechanisms: (1) additional auxiliary 

electricity use by steam electric plants to operate wastewater 

treatment, ash handling, and other systems needed to comply with 

the new effluent limitations and standards; (2) additional 

transportation-related emissions due to the increased trucking 

of CCR waste to landfills; and (3) the change in the profile of 

electricity generation due to relatively higher cost to generate 

electricity at plants incurring compliance costs for the 

proposed ELGs. This section provides greater detail on air 

emission changes associated with the first two mechanisms and 

presents the estimated net change in air emissions that take all 

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three mechanisms into account. See Section XIV for additional

discussion of the third mechanism.

Air pollution is generated when fossil fuels are combusted. 

In addition, steam electric power plants generate air emissions 

from operating transport vehicles, such as dump and vacuum 

trucks, dust suppression water trucks, and earth-moving 

equipment, which release criteria air pollutants and greenhouse 

gases when operated. Similarly, a decrease in energy use or 

vehicle operation will result in decreased air pollution. 

To estimate the net air emissions associated with increased 

electrical energy use, EPA combined the energy usage estimates 

with air emission factors associated with electricity production 

to calculate air emissions associated with the incremental 

energy requirements for each of the proposed regulatory options. 

EPA used emission factors projected by IPM (ton/MWh) for 

nitrogen oxides, sulfur dioxide, and carbon dioxide to generate 

estimates of increased air emissions associated with increased 

energy production.

To estimate net air emissions associated with increased 

operation of transport vehicles, EPA used the MOBILE6.2 model 

and the California Climate Action Registry, General Reporting 

Protocol, Version 2.2 to identify air emission factors (gram per 

mile) for the air pollutants of interest. EPA assumed the 

general input parameters such as the year of the vehicle and the 
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annual mileage accumulation by vehicle class to develop these 

factors. EPA estimated the annual number of miles that dump or 

vacuum trucks moving ash or wastewater treatment solids to onor offsite landfills would travel to comply with limits 

established by the proposed regulatory options. In addition to 

the trucks transporting the additional solid waste, EPA also 

estimated the annual number of miles that water trucks spraying 

water around landfills and ash unloading areas to control dust

would travel. EPA used these estimates to calculate the net 

change in air emissions for this rulemaking. 

EPA’s analyses using IPM also predict changes in air 

emissions. The modeled output from IPM predicts changes in 

electricity generation due to compliance costs attributable to 

the proposed regulatory options. These changes in electricity 

generation are, in turn, predicted to affect the air emissions 

from steam electric power plants,.

The net change in air emissions associated with the 

preferred BAT/PSES regulatory options (Options 3a, 3b, 3, and 

44a) are shown in TableTables XV-2. through XV-5. To provide 

some perspective on the potential increasechanges in annual air 

emissions associated with these increases, EPA compared the 

estimated change in air emissions to the net amount of air 

emissions generated in a year by all electric power plants 

throughout the United States. Tables XV-2 andthrough XV-3
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presents4 present the 2009estimated changes in air emissions 

based on the regulatory options, the total emissions generated 

by the electric power industry in 2009, based on eGRID, and the 

percent change in emissions associated with Options 3a, 3b, 3,

and 44a. See DCN SE02025 (Steam Electric Effluent Guidelines 

Non-Water Quality Impacts) in the record for today’s rulemaking 

for more information.

Table XV-2. Air Emissions Associated With BAT/PSES Option 33a

Non-Water 

Quality 

Impact

Value Associated 

with Option 33a

(Million Tons)

2009 Emissions by 

Electric Power 

Industry

(Million Tons)

Increase In 

Emissions

(%)

NOx 0.00121000088-

0.00109a 1

0.1210088-

0.109

SOx <0.000084b 6 <0.0014

CO2 <0.130b 2,403 <0.0054

a EPA quantified the air emissions associated with additional

electricity and additional transportation for Option 3a. Based 

on the values quantified for Option 3 for changes to air 

emissions projected by IPM, EPA calculated the range of 

emissions for NOx. The lower end of the range represents the 

emissions only associated with additional electricity and 

transportation. The upper end of the range also includes the 

changes to air emissions projected by IPM (based on Option 3), 

which are larger than would be expected for Option 3a.

b EPA quantified the air emissions associated with additional 

electricity and additional transportation for Option 3a. Based 

on the values quantified for Option 3 for changes to air 

emissions projected by IPM, which were negative, EPA decided 

not to include these IPM air emission changes in the 

calculated SOx and CO2 emissions for Option 3a. These SOx and 

CO2 emissions are considered maximum values because EPA 

expects that the air emission changes projected by IPM for 

Option 3a will also be negative (as they are for Options 3 and 

4).

Formatted: Superscript
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Table XV-3. Air Emissions Associated With BAT/PSES Option 3b

Non-Water 

Quality 

Impact

Value Associated 

with Option 3b

(Million Tons)

2009 Emissions by 

Electric Power 

Industry

(Million Tons)

Increase In 

Emissions

(%)

NOx 0.00011-0.00111a 1 0.011-0.111

SOx <0.00013b 6 <0.0021

CO2 <0.149b 2,403 <0.0062

a EPA quantified the air emissions associated with additional 

electricity and additional transportation for Option 3b. Based 

on the values quantified for Option 3 for changes to air 

emissions projected by IPM, EPA calculated the range of 

emissions for NOx. The lower end of the range represents the 

emissions only associated with additional electricity and 

transportation. The upper end of the range also includes the 

changes to air emissions projected by IPM (based on Option 3), 

which are larger than would be expected for Option 3b.

b EPA quantified the air emissions associated with additional 

electricity and additional transportation for Option 3b. Based 

on the values quantified for Option 3 for changes to air 

emissions projected IPM, which were negative, EPA decided not 

to include these IPM air emission changes in the calculated 

SOx and CO2 emissions for Option 3b. These SOx and CO2

emissions are considered maximum values because EPA expects 

that the air emission changes projected for IPM for Option 3b 

will also be negative (as they are for Options 3 and 4).

Table XV-4. Air Emissions Associated With BAT/PSES Option 3

Non-Water 

Quality 

Impact

Value Associated 

with Option 3

(Million Tons)

2009 Emissions by 

Electric Power 

Industry

(Million Tons)

Increase In 

Emissions

(%)

NOx 0.00121 1 0.121

SOx -0.00273 6 -0.045

CO2 -1.282 2,403 -0.053

Table XV-35. Air Emissions Associated With BAT/PSES Option 44a

Non-Water 

Quality 

Impact

Value Associated 

with Option 44a

(Million Tons)

2009 Emissions by 

Electric Power 

Industry

(Million Tons)

Increase In 

Emissions

(%)

NOx 0.0015400132a 1 0.154132

SOx -<-0.0032900258a 6 -<-0.055043

CO2 -4.133<-1.106a 2,403 -<-0.172046

a EPA quantified the air emissions associated with additional 

electricity and additional transportation for Option 4a. To 

estimate the total emissions for Option 4a, EPA added the

changes to air emissions projected by IPM for Options 3 

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because they are more conservative (i.e., they overestimate 

the emissions). The contribution of NOx is unchanged compared 

to Option 3 and 4; therefore, EPA assumed this would also be 

the contribution for Option 4a. For SOx and CO2, the 

contribution associated with Option 4 are lower (i.e., more 

negative); therefore, because EPA used the Option 3 values, 

the values presented in the table are maximum values.

C. Solid Waste Generation

Steam electric power plants generate solid waste associated 

with sludge from wastewater treatment systems (e.g., chemical 

precipitation, biological treatment). The regulatory options 

evaluated would increase the amount of solid waste generated 

from FGD wastewater treatment, including sludge from chemical 

precipitation, biological treatment, and vapor compression 

evaporation technologies. EPA estimated the amount of solid 

waste generated from each technology for each plant and 

estimates that the preferred BAT/PSES regulatory options 

(Options 3a, 3b, 3, and 44a) would increase solids generated 

annually from treatment. Fly and bottom ash are also solid 

wastes generated at steam electric power plants. The preferred

regulatory options for BAT and PSES are, however, not expected 

to alter the amount of ash or other combustion residuals 

generated. See DCN SE02025 (Steam Electric Effluent Guidelines 

Non-Water Quality Impacts) in the record for today’s rulemaking 

for more information.

To provide some perspective on the potential increase in 

annual solid waste generation associated with the preferred 
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BAT/PSES regulatory options, EPA compared the estimated increase 

in solid waste generation – approximately 1.2 million tons for 

Optionfor Options 3b, 3, and 1.5 million tons for Option 4 --4a94

to the amount of solids generated in a year by electric power 

plants throughout the United States – approximately 134 billion 

tons. This means thatThe increase in solid waste generation 

increases associated with the Option 3Options 3b, 3 and 4a for 

BAT and PSES will be less than 0.001 percent of the total solid 

waste generated by all electric power plants. Solid waste 

generation is estimated to increase by less than 0.0011 percent 

under Option 4.

D. Reductions in Water Use

Steam electric power plants generally use water for 

handling solid waste, including ash, and for operating wet FGD 

scrubbers. The regulatorytechnology options for fly and bottom 

ash will eliminate or reduce water use associated with current 

wet sluicing operating systems. EPA estimated the reductions in 

water use based on the amount of sluice water discharged by each 

plant, multiplied by the percentage of intake water identified 

as make-up in the survey. The memorandum entitled Steam Electric 

 

94 As described previously, the preferred regulatory options for BAT and PSES 

for fly ash and bottom ash transport water are not expected to alter the 

amount of ash or other combustion residuals generated. Therefore, there is no 

increase for Option 3a and the increase for Option 4a is equal to the 

increase for Option 3.
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Effluent Guidelines Non-Water Quality Impacts, located in the 

record for today’s rulemaking, provides more information.

The technology basis for the preferred regulatory option 

with respect to FGD wastewater discharges (e.g., chemical 

precipitation, biological treatment) would not be expected to 

reduce the amount of water used unless plants recycle FGD 

wastewater as part of their treatment system. EPA estimated that 

five plants would be able to incorporate recycling within their

FGD systems based on the maximum operating chlorides 

concentration compared to the design maximum chlorides 

concentration. Based on this comparison, EPA estimated the 

reduction in intake water at a plant level based on the amount 

of water that could be recycled by the FGD system and 

multiplying by the percentage of intake water identified as 

make-up water in the industry survey. EPA’s report entitled 

Incremental Costs and Pollutant Removals for Proposed Effluent 

Limitations Guidelines and Standards for the Steam Electric 

Generating Point Source Category, located in the record for 

today’s rulemaking, provides more information.

EPA estimates that power plants would reduce the use of 

water by 5450 billion gallons per year (147136 million gallons 

per day) under Option 3 and3a, by 15852 billion gallons per year 

(432143 million gallons per day) under Option 43b, by 53 billion 

gallons per year (144 million gallons per day) under Option 3, 
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and by 103 billion gallons per year (282 million gallons per 

day) under Option 4a.

XVI. Regulatory Implementation

A. Implementation of the Limitations and Standards

Effluent guidelines limitations and standards act as a 

primary mechanism to control the discharge of pollutants to 

waters of the United States. Today’s proposed rule would be 

applied to steam electric wastewater discharges through 

incorporation into NPDES permits issued by the EPA or states 

under Section 402 of the Act and through local pretreatment 

programs under Section 307 of the Act. 

The Agency has developed the limitations and standards for 

this proposed rule to control the discharge of pollutants from 

the steam electric power generating point source category. Once 

promulgated, those permits or control mechanisms issued after 

this rule’s effective date would be required to incorporate the 

effluent limitations guidelines and standards, as applicable. 

Also, under section 510 of the CWA, states may require effluent 

limitations under state law as long as they are no less 

stringent than the requirements of this rule. Finally, in 

addition to requiring application of the technology-based 

effluent limitations guidelines and standards in this rule, 

section 301(b)(1)(C) of CWA requires the permitting authority to 
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impose more stringent effluent limitations on discharges as 

necessary to meet applicable water quality standards. 

1. Timing

For the reasons explained in Section VIII, EPA proposes 

that certain limitations and standards based on any of the 

fiveeight main regulatory options being proposed today for 

existing direct and indirect dischargers do not apply until July 

1, 2017 (approximately three years from the effective date of 

this rule). EPA findfinds this is appropriate for any proposed 

BAT and PSES for FGD wastewater, gasification wastewater, fly 

ash transport water, flue gas mercury control wastewater, bottom 

ash transport water, or combustion residual leachate where EPA 

is not proposing to establish BAT limitations that are equal to 

BPT limitations. For those plants and wastestreams where EPA is 

proposing to establish BAT equal to the current BPT effluent 

limitations, the revised BAT requirements would be applicable on 

the effective date of the final rule. See Section VIII.B for 

additional discussion regarding the implementation timing for 

the proposed BAT and PSES requirements.

The proposed requirements for new direct and indirect 

dischargers (NSPS and PSNS) and the proposed requirements for 

existing sources where BAT is set equal to BPT would be 

applicable as of the effective date of the final rule.
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2. Applicability of NSPS/PSNS

In 1982, EPA promulgated NSPS/PSNS for certain discharges 

from new units. Regardless of the outcome of the current 

rulemaking, those units that are currently subject to the 1982 

NSPS/PSNS will continue to be subject to such standards. In 

addition, EPA is proposing to clarify in the text of the 

regulation that, assuming the Agency promulgates BAT/PSES 

requirements as part of the current rulemaking, units to which 

the 1982 NSPS/PSNS apply will also be subject to any newly 

promulgated BAT/PSES requirements because they will be existing 

sources with respect to such new requirements. 

3. Legacy Wastes

For the reasons explained in Section VIII, EPA is proposing 

that certain BAT and PSES requirements for existing sources 

based on any of the fiveeight main regulatory options would 

apply to discharges of FGD wastewater, fly ash transport water, 

bottom ash transport water, FGMC wastewater, combustion residual 

leachate, and gasification wastewater generated on or after the 

date established by the permitting authority that is as soon as 

possible after July 1, 2017. 95 As proposed today, for direct 

dischargers such wastewater generated prior to that date (i.e., 

“legacy” wastewater) and, in the case of direct dischargers,

would remain subject to the existing BPT effluent limits. EPA is 

 

95 Except where BAT is equivalent to BPT.
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also considering establishing BAT effluent limitations for 

legacy wastewater (except gasification wastewater) that would be 

equal to the existing BPT effluent limits.

34. Compliance Monitoring 

Working in conjunction with the effluent limitations 

guidelines and standards are the monitoring conditions set out 

in a NPDES discharge permit or POTW control mechanism. An 

integral part of the monitoring conditions is the monitoring 

point. The point at which a sample is collected can have a 

dramatic effect on the monitoring results for that facility. 

Therefore, it may be necessary to require internal monitoring 

points in order to assure compliance. Authority to address 

internal wastestreams is provided in 40 CFR 122.44(i)(1)(iii) 

and 122.45(h). 

EPA is proposing that dischargers demonstrate compliance 

with the proposed effluent limitations and standards applicable 

to a particular wastestream prior to mixing the treated 

wastestream with other wastestreams, as described below.

Therefore, with the exception of the cases where BAT limitations 

are equivalent to BPT limitations, any final limitations or 

standards (except pH) based on any of the fiveeight main 

regulatory options in today’s proposed rule could require 

internal monitoring points. Section 14 of the TDD provides 

detailed discussion for various types of configurations. The 
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following provides more detailed selected information for each 

wastestreamfrom the TDD:

FGD wastewater: Where an option proposes BAT/NSPS 

limitations for FGD wastewater that are not equal to 

existing BPT limitations96, EPA is also proposing to require 

monitoring for compliance with the proposed effluent 

limitations and standards prior to use of the FGD 

wastewater in any other non-FGD plant process or 

commingling of the FGD wastewater with any water or other 

process wastewater. This monitoring requirement would not, 

however, apply prior to commingling of FGD wastewater with

combustion residual leachate (including legacy leachate) or 

legacy FGD wastewater that is treated to achieve pollutant 

removals equivalent to or greater than achieved by the 

BAT/NSPS technology that serves as the basis for the 

effluent limitations and standards proposed today.

For example, many plants currently treat their FGD 

wastewater and leachate in onsite surface impoundments. EPA 

envisions that, under today’s proposed Option 3 

requirements, some of these plants may choose to install 

tank-based FGD wastewater treatment systems for their newly 

generated FGD wastewater. Such a plant may chose to 

discharge the effluent from its new treatment system 

directly or may wish to discharge it to the existing 

surface impoundment containing legacy wastewaters. In this 

case, the plant would be required to demonstrate compliance 

with the proposed effluent limitations and standards for 

the newly generated FGD wastewater at the effluent from the 

tank-based FGD wastewater treatment system, and compliance 

with the BPT requirements for the commingled new/legacy FGD 

wastewater at the point of discharge from the FGD 

wastewater impoundment. The same plant may also configure 

its system so that the impoundment (which also contains 

legacy FGD wastewater) is used for equalization, with the 

impoundment effluent sent to the tank-based treatment 

system. In this case, both the newly generated FGD 

wastewater and the legacy FGD wastewater would be treated 

by the tank-based treatment system and an appropriate 

compliance monitoring point would be the treatment system 

effluent. Under such a scenario, commingling of FGD 

wastewater generated at any date may occur as long as such 

 

96 Similarly applies to PSES and PSNS.

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combined wastewater meets the effluent limitations or 

standards prior to use of the treated commingled new/legacy 

FGD wastewater in any other plant process, or combining the 

FGD wastewater with any water or other process wastewater. 

Conversely, EPA envisions that under today’s proposed 

requirements, some plants may choose to install tank-based 

FGD wastewater treatment systems whose effluent is 

discharged to a legacy FGD wastewater impoundment. In this 

case, the plant would be required to demonstrate compliance 

with the proposed effluent limitations and standards for 

the newly generated FGD wastewater at the effluent from the 

tank-based FGD wastewater treatment system, and compliance 

with the BPT requirements for the commingled new/legacy FGD 

wastewater at the point of discharge from the FGD 

wastewater impoundment.

Ash transport water and FGMC wastewater: EPA is proposing 

to specify that whenever ash transport water or flue gas 

mercury control wastewater generated from a generating unit 

that must comply with the “zero discharge” standard is used 

in any other plant process or is sent to a treatment system 

at the plant, the resulting effluent must comply with the 

proposed discharge prohibition for the pollutants in such 

wastewater. . As an

For example, many plants currently treat their fly ash 

transport water in an onsite fly ash impoundment. In this 

case, under theany proposed “no discharge” requirements, 

EPA envisions that such plants may convert their fly ash 

handling to a dry system, and no longer generate fly ash 

transport water. In such cases, the plant could demonstrate 

compliance with the proposed BAT or PSES requirementszero 

discharge requirement by showing that no fly ash transport 

water is generated after the date of on which the new, 

proposed standards apply and by monitoring for compliance 

with the BPT requirements at the discharge from the legacy 

fly ash impoundment. Under EPA’s proposal, the plant could 

not demonstrate compliance with the applicable discharge 

prohibition by simply using the fly ash transport water in 

another plant process prior to discharge. Since the 

pollutants present in the ash transport water (or FGMC 

wastewater) would not be completely removed,that ultimately 

discharges because the prohibition on the discharge of 

pollutants in ash transport water and FGMC wastewater is 

also applicable to the discharge of wastewater from plant 

processes that use these wastewaters.

Formatted: Indent: Left: 0.5", No bullets or

numbering
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Gasification wastewater: EPA is proposing to require 

monitoring for compliance prior to use of the gasification 

wastewater in any other plant process or commingling of the 

gasification wastewater with water or any other process 

wastewater. As an example, EPA envisions gasification 

plants would show compliance with the proposed BAT or PSES 

requirements directly following gasification wastewater 

treatment (however, there would be no need to demonstrate 

compliance if the gasification wastewater is completely 

reused within the gasification process). Gasification 

wastewater currently being generated by the industry is 

already being treated with today’s proposed BAT/PSES

technology for this wastestream; therefore, there is no 

need for the proposed rule to include provisions for legacy 

gasification wastewater. 

Combustion Residual Leachate: Under Option 4 and 5, EPA is 

proposing to require monitoring for compliance prior to use 

of leachate in any other plant process or commingling of 

the leachate with water or any other process wastewater. 

This monitoring requirement would not, however, apply prior 

to commingling of combustion residual leachate with FGD 

wastewater (including legacy FGD wastewater) or legacy 

combustion residual leachate that is treated to achieve 

pollutant removals equivalent to or greater than that 

achieved by the BAT/NSPS technology that serves as the 

basis for the effluent limitations and standards proposed 

today. For example, many plants currently treat their 

leachate in onsite surface impoundments. EPA envisions 

that, under today’s proposed requirements, some plants may 

choose to install a tank-based leachate treatment system so 

that the impoundment (which also contains legacy combustion 

residual leachate) is used for equalization, with the 

impoundment effluent ultimately sent to the tank-based 

treatment system. In this case, both the newly generated 

leachate and the legacy leachate would be treated by the 

tank-based treatment system and an appropriate compliance 

monitoring point would be the treatment system effluent. 

Under such a scenario, commingling of combustion residual 

leachate generated at any date may occur as long as such 

combined wastewater meets the effluent limitations or 

standards prior to use of the treated commingled new/legacy 

leachate in any other plant process, or combining the 

leachate with any water or other process wastewater. (If 

the combustion residual leachate is commingled with FGD 

wastewater, the facility will also have to demonstrate 

compliance with the applicable FGD wastewater effluent 

limitations and standards.) Conversely, under today’s 

Formatted: Bulleted + Level: 1 + Aligned at:

0.25" + Indent at: 0.5"
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proposed requirements, EPA envisions some plants may choose 

to install tank-based leachate treatment systems whose 

effluent is discharged to the impoundment containing the 

legacy leachate. In this case, the plant would be required 

to demonstrate compliance with the proposed effluent 

limitations and standards for the newly generated 

combustion residual leachate at the effluent from the tankbased leachate treatment system and compliance with the BPT 

requirements for the commingled new/legacy leachate at the 

discharge from the impoundment.

B. Analytical Methods

Section 304(h) of the CWA directs the EPA to promulgate 

guidelines establishing test procedures (methods) for the 

analysis of pollutants. These methods are used to determine the 

presence and concentration of pollutants in wastewater and for 

compliance monitoring. They are also used for filing 

applications for the National Pollutant Discharge Elimination 

System (NPDES) permit program under 40 CFR 122.41(j)(4) and 

122.21(g)(7), and under 40 CFR 403.7(d) for the pretreatment 

program. The EPA has promulgated analytical methods for 

monitoring discharges to surface water at 40 CFR part 136 for 

the pollutants proposed for regulation in today’s notice. EPA is 

providing notice of a standard operating procedure 

(SOPprocedures (SOPs) for the analysis of FGD wastewater using 

collision cell technology in conjunction with EPA Method 200.8. 

EPA Method 200.8 has been promulgated under 40 CFR part 136 and 

is an approved method for use in NPDES compliance monitoring. 

Also, the use of collision cell technology is an approved 
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modification allowed under 40 CFR part 136.6. See DCN xxxSE03835 

and DCN SE03868 for the SOPSOPs and information on EPA’s 

development of the SOPSOPs. 

In addition, as explained in Section VIII, with the 

exception of the cases where BAT limitations are equivalent to 

BPT limitations, EPA is proposing that compliance with any final 

limitations or standards (except pH) based on any of the 

fiveeight main regulatory options in today’s proposed rule 

reflects results obtained from sufficiently sensitive analytical 

methods. Where EPA has approved more than one analytical method 

for a pollutant, the Agency expects that permittees would select 

methods that are able to quantify the presence of pollutants in 

a given discharge at concentrations that are low enough to 

determine compliance with effluent limits. For purposes of the 

proposed anti-circumvention provisions, a method is 

“sufficiently sensitive” when the sample-specific quantitation 

level97 for the wastewater matrix being analyzed is at or below 

the level of the effluent limit. 

C. Upset and Bypass Provisions

A “bypass” is an intentional diversion of wastestreams from 

any portion of a treatment facility. An “upset” is an 

exceptional incident in which there is unintentional and 

 

97 For the purposes of this rulemaking, EPA is considering the following terms 

related to analytical method sensitivity to be synonymous: “quantitation 

limit,” “reporting limit,” “level of quantitation,” and “minimum level.”
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temporary noncompliance with technology-based permit effluent 

limitations because of factors beyond the reasonable control of 

the permittee. EPA’s regulations concerning bypasses and upsets 

for direct dischargers are set forth at 40 CFR 122.41(m) and (n) 

and for indirect dischargers at 40 CFR 403.16 and 403.17.

D. Variances and Modifications

The CWA requires application of effluent limitations 

established pursuant to Section 301 or the pretreatment 

standards of Section 307 to all direct and indirect dischargers. 

However, the statute provides for the modification of these 

national requirements in a limited number of circumstances. The 

Agency has established administrative mechanisms to provide an 

opportunity for relief from the application of the national 

effluent limitations guidelines for categories of existing 

sources for toxic, conventional, and nonconventional pollutants.

1. Fundamentally Different Factors (FDF) Variance

As explained above, the CWA requires application of the 

effluent limitations established pursuant to Section 301 or the 

pretreatment standards of Section 307 to all direct and indirect 

dischargers. However, the statute provides for the modification 

of these national requirements in a limited number of 

circumstances. Moreover, the Agency has established 

administrative mechanisms to provide an opportunity for relief 

from the application of national effluent limitations guidelines 
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and pretreatment standards for categories of existing sources 

for priority, conventional, and nonconventional pollutants.

EPA may develop, with the concurrence of the state, 

effluent limitations or standards different from the otherwise 

applicable requirements for an individual existing discharger if 

it is fundamentally different with respect to factors considered 

in establishing the effluent limitations or standards applicable 

to the individual discharger. Such a modification is known as an 

FDF variance. 

EPA, in its initial implementation of the effluent 

guidelines program, provided for the FDF modifications in 

regulations, which were variances from the BPT effluent 

limitations, BAT limitations for toxic and nonconventional 

pollutants, and BCT limitations for conventional pollutants for 

direct dischargers. FDF variances for toxic pollutants were 

challenged judicially and ultimately sustained by the Supreme 

Court in Chemical Manufacturers Association v. Natural Resources 

Defense Council, 470 U.S. 116, 124 (1985).

Subsequently, in the Water Quality Act of 1987, Congress 

added a new section to the CWA -- Section 301(n). This provision 

explicitly authorizes modifications of the otherwise applicable 

BAT effluent limitations, if a discharger is fundamentally 

different with respect to the factors specified in CWA Section 

304 (other than costs) from those considered by EPA in 
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establishing the effluent limitations. CWA Section 301(n) also 

defined the conditions under which EPA may establish alternative 

requirements. Under Section 301(n), an application for approval 

of a FDF variance must be based solely on (1) information 

submitted during rulemaking raising the factors that are 

fundamentally different or (2) information the applicant did not 

have an opportunity to submit. The alternate limitation must be 

no less stringent than justified by the difference and must not 

result in markedly more adverse non-water quality environmental 

impacts than the national limitation.

EPA regulations at 40 CFR part 125, subpart D, authorizing 

the regional administrators to establish alternative 

limitations, further detail the substantive criteria used to 

evaluate FDF variance requests for direct dischargers. Thus, 40 

CFR 125.31(d) identifies six factors (e.g., volume of process 

wastewater, age and size of a discharger's facility) that may be 

considered in determining if a discharger is fundamentally 

different. The Agency must determine whether, based on one or 

more of these factors, the discharger in question is 

fundamentally different from the dischargers and factors 

considered by EPA in developing the nationally applicable 

effluent guidelines. The regulation also lists four other 

factors (e.g., inability to install equipment within the time 

allowed or a discharger's ability to pay) that may not provide a 
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basis for an FDF variance. In addition, under 40 CFR 125.31(b) 

(3), a request for limitations less stringent than the national 

limitation may be approved only if compliance with the national 

limitations would result in either (a) a removal cost wholly out 

of proportion to the removal cost considered during development 

of the national limitations, or (b) a non-water quality 

environmental impact (including energy requirements) 

fundamentally more adverse than the impact considered during 

development of the national limits. The legislative history of 

Section 301(n) underscores the necessity for the FDF variance 

applicant to establish eligibility for the variance. EPA's 

regulations at 40 CFR 125.32(b)(1) impose this burden upon the 

applicant. The applicant must show that the factors relating to 

the discharge controlled by the applicant's permit that are 

claimed to be fundamentally different are, in fact, 

fundamentally different from those factors considered by EPA in 

establishing the applicable guidelines. In practice, very few 

FDF variances have been granted for past ELGs. An FDF variance 

is not available to a new source subject to NSPS. DuPont v. 

Train, 430 U.S. 112 (1977).

2. Economic Variances

Section 301(c) of the CWA authorizes a variance from the 

otherwise applicable BAT effluent guidelines for nonconventional 

pollutants due to economic factors. The request for a variance 
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from effluent limitations developed from BAT guidelines must 

normally be filed by the discharger during the public notice 

period for the draft permit. Other filing periods may apply, as 

specified in 40 CFR 122.21(m)(2). Specific guidance for this 

type of variance is provided in ``”Draft Guidance for 

Application and Review of Section 301(c) Variance Requests,'',“

dated August 21, 1984, available on EPA's Web site at 

http://www.epa.gov/npdes/pubs/OWM0469.pdf. 

3. Water Quality Variances

Section 301(g) of the CWA authorizes a variance from BAT 

effluent guidelines for certain nonconventional pollutants due 

to localized environmental factors. These pollutants include 

ammonia, chlorine, color, iron, and total phenols. As this 

proposed rule would not establish limitations or standards for 

any of these pollutants, this variance would not be applicable 

to this particular rule.

4. Removal Credits

Section 307(b)(1) of the CWA establishes a discretionary 

program for POTWs to grant “removal credits” to their indirect 

dischargers. Removal credits are a regulatory mechanism by which 

industrial users may discharge a pollutant in quantities that 

exceed what would otherwise be allowed under an applicable 

categorical pretreatment standard because it has been determined 

that the POTW to which the industrial user discharges 
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consistently treats the pollutant. EPA has promulgated removal 

credit regulations as part of its pretreatment regulations. See 

40 CFR 403.7. These regulations provide that a POTW may give 

removal credits if prescribed requirements are met. The POTW 

must apply to and receive authorization from the Approval 

Authority. To obtain authorization, the POTW must demonstrate 

consistent removal of the pollutant for which approval authority 

is sought. Furthermore, the POTW must have an approved 

pretreatment program. Finally, the POTW must demonstrate that 

granting removal credits will not cause the POTW to violate 

applicable federal, state, or local sewage sludge requirements. 

40 CFR 403.7(a)(3).

The United States Court of Appeals for the Third Circuit 

interpreted the CWA as requiring EPA to promulgate the 

comprehensive sewage sludge regulations pursuant to CWA Section 

405(d)(2)(A)(ii) before any removal credits could be authorized. 

See NRDC v. EPA, 790 F.2d 289, 292 (3d Cir., 1986); cert. 

denied., 479 U.S. 1084 (1987). Congress made this explicit in 

the Water Quality Act of 1987, which provided that EPA could not 

authorize any removal credits until it issued the sewage sludge 

use and disposal regulations. On February 19, 1993, EPA 

promulgated Standards for the Use or Disposal of Sewage Sludge, 

which are codified at 40 CFR part 503 (58 FR 9248). EPA 

interprets the Court’s decision in NRDC v. EPA as only allowing 
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removal credits for a pollutant if EPA has either regulated the 

pollutant in part 503 or established a concentration of the 

pollutant in sewage sludge below which public health and the 

environment are protected when sewage sludge is used or 

disposed.

The part 503 sewage sludge regulations allow four options 

for sewage sludge disposal: (1) land application for beneficial 

use, (2) placement on a surface disposal unit, (3) firing in a 

sewage sludge incinerator, and (4) disposal in a landfill which 

complies with the municipal solid waste landfill criteria in 40 

CFR part 258. Because pollutants in sewage sludge are regulated 

differently depending upon the use or disposal method selected, 

under EPA’s pretreatment regulations the availability of a 

removal credit for a particular pollutant is linked to the 

POTW’s method of using or disposing of its sewage sludge. The 

regulations provide that removal credits may be potentially 

available for the following pollutants:

(1) If POTW applies its sewage sludge to the land for 

beneficial uses, disposes of it in a surface disposal unit, or 

incinerates it in a sewage sludge incinerator, removal credits 

may be available for the pollutants for which EPA has 

established limits in 40 CFR part 503. EPA has set ceiling 

limitations for nine metals in sludge that is land applied, 

three metals in sludge that is placed on a surface disposal 
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unit, and seven metals and 57 organic pollutants in sludge that 

is incinerated in a sewage sludge incinerator. 40 CFR 

403.7(a)(3)(iv)(A).

(2) Additional removal credits may be available for sewage 

sludge that is land applied, placed in a surface disposal unit, 

or incinerated in a sewage sludge incinerator, so long as the 

concentration of these pollutants in sludge do not exceed 

concentration levels established in part 403, Appendix G, Table 

II. For sewage sludge that is land applied, removal credits may 

be available for an additional two metals and 14 organic 

pollutants. For sewage sludge that is placed on a surface 

disposal unit, removal credits may be available for an 

additional seven metals and 13 organic pollutants. For sewage 

sludge that is incinerated in a sewage sludge incinerator, 

removal credits may be available for three other metals 40 CFR 

403.7(a)(3)(iv)(B). 

(3) When a POTW disposes of its sewage sludge in a 

municipal solid waste landfill that meets the criteria of 40 CFR 

part 258, removal credits may be available for any pollutant in 

the POTW’s sewage sludge. 40 CFR 403.7(a)(3)(iv)(C).
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XVII. Related Acts of Congress, Executive Orders, and Agency 

Initiatives

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

Under Section 3(f)(1) of Executive Order (EO) 12866 (58 FR 

51735, October 4, 1993), this action is an “economically 

significant regulatory action” because it is likely to have an 

annual effect on the economy of $100 million or more. 

Accordingly, EPA submitted this action to the Office of 

Management and Budget (OMB) for review under Executive Orders 

12866 and 13563 (76 FR 3821, January 21, 2011) and any changes 

made in response to OMB recommendations have been documented in 

the docket for this action.

In addition, EPA prepared an analysis of the potential

costs and benefits associated with this action. This analysis is 

contained in Chapter 12 of the BCA report. A copy of the 

analysis is available in the docket for this action and the 

analysis is briefly summarized here.

Table XVII-1 (drawn from Table 12-1 of the BCA report) 

provides the results of the benefit-cost analysis with both 

costs and benefits annualized over 24 years and discounted using 

a 3 percent discount rate. The table lists the eight options in 

order of increasing total social costs.
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Table XVII-1. Total Monetized Annualized Benefits and Costs of 

the BAT and PSES Regulatory Options (Millions 2010 $, 3 percent 

discount rate)a

Regulatory Option Total Social Costsb

Total Monetized 

Benefitsc,d,e

Option 3a $185.2 e

Option 1 $268.3 $197.382.0

Option 3b $281.4 e

Option 2 $386.8 $227.0111.7

Option 3 $572.10 $464.5311.7

Option 4a $954.1 e

Option 4 $1,381.2 $1,005.1605.5

Option 5 $2,328.8 $833.7434.1

a All costs and benefits were annualized over 24 years and using a 3 percent 

discount rate.

b Total social costs include compliance costs to facilities.

c Mean benefit estimates. Values include partial human health benefits only 

for reaches that receive direct discharges from steam electric plants. 

Values for Options 1, 2, and 5 do not include air-related benefits.

d EPA estimated certain benefits for Options 3 and 4 only. Total benefits 

for Options 1, 2, and 5 are therefore understated. See Section XIV and 

Table XIV-8.

e EPA did not estimate benefits for Options 3a, 3b and 4a. The benefits of 

Option 4a are expected to be between those of Options 3 and 4.

EPA also analyzed the employment effects of the proposed 

ELGs. The results of that analysis are summarized in Section 

XI.E.

B. Paperwork Reduction Act

This action does not impose any new information collection 

burden. However, the Office of Management and Budget (OMB) has 

previously approved the information collection requirements 

contained in the existing regulations 40 CFR part 423 under the 

provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et 

seq. and has assigned OMB control number 2040-0281. The OMB 

Formatted: Superscript
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control numbers for EPA's regulations in 40 CFR are listed in 40 

CFR part 9.

EPA estimated small changes in monitoring costs due to 

additional metals for which EPA is proposing limits and 

standards; the Agency accounted for these costs as part of its 

analysis of the economic impacts of the proposed ELGs. However, 

plants will also realize certain savings by no longer monitoring 

effluent that would cease to exist under the proposed ELGs. The 

net changes in monitoring and reporting are expected to be 

minimal, and EPA consequently did not revise its information 

collection burden estimate.

EPA does not believe that the proposed rule would lead to 

additional costs to permitting authorities. The proposed rule 

would not change permit application requirements or the 

associated review, it would not increase the number of permits 

issued to steam electric plants, and nor it increase the efforts 

involved in developing or reviewing such permits. In the absence 

of nationally applicable BAT requirements, as appropriate, 

permitting authorities are directed to establish technologybased effluent limitations using their use best professional 

judgment (BPJ) to establish site-specific requirements. EPA has 

data that demonstrates that permitting authorities that 

establish technology-based effluent limitations on a BPJ basis 

based on site-specific conditions can spend significant time 
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effort and resources doing so. Establishing nationally 

applicable BAT requirements that eliminate the need to develop 

BPJ-based limitations would make permitting easier and less 

costly in this respect. As explained in Section XVI, under 

today’s rule, permitting authorities would be required to 

determine, for one permit cycle, on a facility-specific basis, 

what date is “as soon as possible.” This one-time burden, 

however, would be no more excessive than the existing burden to 

develop technology-based effluent limitations on a BPJ basis; in 

fact, it would likely be less burdensome. Nevertheless, EPA 

conservatively estimated no net change (i.e., increase or 

decrease) in the cost burden to federal or state governments 

associated with today’s proposal. 

C. Regulatory Flexibility Act

The Regulatory Flexibility Act (RFA) generally requires an 

agency to prepare a regulatory flexibility analysis of any rule 

subject to notice-and-comment rulemaking requirements under the 

Administrative Procedure Act or any other statute unless the 

agency certifies that the rule will not have a significant 

economic impact on a substantial number of small entities. Small 

entities include small businesses, small organizations, and 

small governmental jurisdictions. 
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1. Definition of Small Entities and Estimation of the Number of

Small Entities Subject to Today’s Proposed ELGs

For purposes of assessing the impacts of today's proposed 

rule on small entities, small entity is defined as either a: (1) 

a small business as defined by the Small Business 

Administration’s (SBA) regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a government of a city, 

county, town, school district or special district with a 

population of less than 50,000; or (3) a small organization that 

is any not-for-profit enterprise which is independently owned 

and operated and is not dominant in its field. In reaching 

entity size determinations, EPA assumed that all federal or 

state entities owning steam electric plants affected by this 

rulemaking are not small entities.

The SBA criteria for identifying small, non-government 

entities in the electric power industry are as follows:

For non-government entities with electric power generation 

as a primary business, small entities are those with total 

annual electric output less than 4 million MWh;

For non-federal or state jurisdictions, small entities are 

those with a population of less than 50,000.

For entities with a primary business other than electric 

power generation, the relevant size criteria are based on 

revenue or number of employees by NAICS sector (see Table 

XVII-2).
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Table XVII-2. NAICS Codes and SBA Entity Size Standards for 

Steam Electric Generators with a Primary Business Other Than 

Electric Power Generationa

NAICS Code NAICS Description SBA Size Standardb

211111 Crude Petroleum and Natural Gas 

Extraction

500 Employees

212111 Bituminous Coal and Lignite Surface 

Mining

500 Employees

213112 Support Activities for Oil and Gas 

Operations $7 million in revenue

221210 Natural Gas Distribution 500 Employees

221310 Water Supply and Irrigation Systems $7 million in revenue

221330 Steam and Air-Conditioning Supply $12.5 million in 

revenue

237130 Power and Communication Line and 

Related Structures Construction

$33.5 million in 

revenue

324110 Petroleum Refineries 1,500 Employees

332410 Power Boiler and Heat Exchanger 

Manufacturing 500 Employees

333611 Turbine and Turbine Generator Set 

Unit Manufacturing

1,000 Employees

423510 Metal Service Centers and Other 

Metal Merchant Wholesalers

100 Employees

486110 Pipeline Transportation of Crude 

Oil

1,500 Employees

522110 Commercial Banking $175 million in 

assets

523110 Investment Banking and Securities 

Dealing

$7 million in revenue

523910 Miscellaneous Intermediation $7 million in revenue

523920 Portfolio Management $7 million in revenue

524113 Direct Life Insurance Carriers $7 million in revenue

524126 Direct Property and Casualty 

Insurance Carriers 1,500 employees

525910 Open-End Investment Funds $7 million in revenue

541614 Process, Physical Distribution and 

Logistics Consulting Services

$14 million in 

revenue

541690 Other Scientific and Technical 

Consulting Services

$14 million in 

revenue

551111 Offices of Bank Holding Companies $7 million in revenue

551112 Offices of Other Holding Companies $7 million in revenue

562219 Other Nonhazardous Waste Treatment 

and Disposal 

$12.5 million in 

revenuerevenuec
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Table XVII-2. NAICS Codes and SBA Entity Size Standards for 

Steam Electric Generators with a Primary Business Other Than 

Electric Power Generationa

NAICS Code NAICS Description SBA Size Standardb

a. Certain plants affected by this rulemaking are owned by non-government 

entities whose primary business is not electric power generation.

b. Based on size standards effective at the time EPA conducted this 

analysis (SBA size standards, effective October 1, 2012).

c. EPA is aware that SBA revised the size standard applicable to this 

sector, effective January 7, 2013 (from $12.5 million in revenue to 

$35.5 million in revenue); EPA used the size standards effective at the 

time the analyses were completed and will update the size standards as 

part of revisions to support final rulemaking.

EPA identified the domestic parent entity of each steam 

electric plant and obtained the entity’s revenue from the Steam 

Electric industry survey or from publicly available data 

sources. In this analysis, the domestic parent entity associated 

with any given plant is defined as that entity that has the 

largest ownership share in the plant. To determine whether these 

entities are small entities based on the size criteria outlined 

above, EPA compared the relevant measure for the identified 

parent entities to the appropriate SBA size criterion. 

EPA used alternative sample-weighting approaches, which 

provide a range of estimates of the numbers of small entities 

and affected plants owned by these small entities (see Chapter 8

in the RIA for details of methodology used to develop weighted 

estimates). The results of this analysis using both weighting 

approaches are summarized below. 
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EPA estimates that 243 to 507 entities own steam electric 

plants subject to today’s proposal. Applying the small entity 

identification criteria, EPA estimates that 97 to 170 of these 

entities are small (see Table XVII-3). Municipalities make up 

the largest number of small entities owning steam electric 

plants under the lower bound estimate (37 out of 97) and are 

also a significant fraction of small entities under the upper 

bound estimate (46 out of 170). Small entities owning steam 

electric plants as a percentage of total entities range, by 

ownership category, from 14 to 17 percent for other political 

subdivision, to 47 to 51 percent for nonutility and 45 to 57 

percent for municipality.

EPA determined that 14 small entities own steam electric 

plants expected to incur compliance costs under at least one of 

the fiveeight regulatory options, for either of the two bounding 

cases. 

Table XVII-3. Number of Entities Owning Steam Electric Plants by 

Sector and Size (assuming two different ownership cases)a

Ownership Type

Lower bound estimate of 

number of entities owning 

steam electric plantsb

Upper bound estimate of 

number of entities owning 

steam electric plantsb

Total Smallc % Small Total Smallc % Small

Investor-Owned 

Utilities

97 27 27.8% 244 64 26.3%

Nonutilities 35 18 51.4% 73 34 46.8%

Rural Electric 

Cooperatives

30 13 43.3% 52 21 40.7%

Municipality 65 37 56.9% 101 46 45.3%

Other Political 

Subdivision

12 2 16.7% 30 4 14.2%

Formatted: Superscript
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Table XVII-3. Number of Entities Owning Steam Electric Plants by 

Sector and Size (assuming two different ownership cases)a

Ownership Type

Lower bound estimate of 

number of entities owning 

steam electric plantsb

Upper bound estimate of 

number of entities owning 

steam electric plantsb

Federala 2 0 0.0% 4 0 0.0%

Statea 2 0 0.0% 2 0 0.0%

Tribal 0 0 N/A 0 0 N/A

All Entity Types 243 97 39.9% 507 170 33.5%

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

one instance, the plant is owned by a joint venture of three entities.

b Of these, 92 entities, 14 of which are small, own steam electric plants 

that are expected to incur compliance costs under at least one regulatory 

option under both Case 1 and Case 2. 

c EPA was unable to determine size for 10 parent entities; for this 

analysis, these entities are assumed to be small.

In total, small entities own a total of 189 steam electric 

plants, or 18 percent of the total universe of 1,079 steam 

electric plants. Of these, EPA determined that 14 plants may 

incur compliance costs under at least one of the fiveeight

regulatory options.

EPA notes that its proposal (discussed in Section VIII) to 

set the BAT equal to BPT for existing generating units with a 

total nameplate generating capacity of 50 MW or less for all of 

the eight proposed regulatory options will reduce the potential 

impacts of the proposed rule on small entities and 

municipalities. The rulemaking record indicates that 

establishing a size threshold for the BAT would preferentially 

minimize some of the economic impacts expected on municipalities 

and small entities. This is the result, in particular, of the 

fact that 37 percent of small entities own a steam electric 

Formatted: Superscript
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Page 466 of 517

generating unit with a capacity of 50 MW or smaller. This stands 

in contrast to the 22 percent of all firms (both large and small 

entities) that own such a unit and the 18 percent of large 

entities that own one. Moreover, more than half (54 percent) of 

generating units owned by small entities are 50 MW or smaller. 

In contrast, only seven percent of generating units owned by 

large entities are 50 MW or smaller. Municipalities also tend to 

own smaller generating units, with 30 percent of municipalities 

and 42 percent of municipal-owned units being affected by the 50 

MW size threshold.

EPA requests comment on the proposed 50 MW threshold 

applicable to discharges of the wastestreams described under 

each of the preferred options, and as well as other possible 

thresholds for small units.

2. Statement of Basis

As described above, EPA began its assessment of the impact 

of regulatory options on small entities by first estimating the 

number of small entities owning Steam Electric plants that would 

be subject to today’s proposed ELGs. EPA then assessed whether 

these small entities would be expected to incur costs that 

constitute a significant impact; and whether the number of those 

small entities estimated to incur a significant impact represent 

a substantial number of small entities. 
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To assess whether small entities’ compliance costs might 

constitute a significant impact, EPA summed annualized 

compliance costs for the steam electric plants determined to be 

owned by a given small entity and calculated these costs as a 

percentage of entity revenue (cost-to-revenue test). EPA 

compared the resulting percentages to impact criteria of 1 

percent and 3 percent of revenue. Small entities estimated to 

incur compliance costs exceeding one or more of the 1 percent 

and 3 percent impact thresholds were identified as potentially 

incurring a significant impact. 

EPA used alternative sample-weighting approaches, which 

provide a range of estimates of the numbers of small entities 

and steam electric plants owned by these small entities. The 

results of this analysis using both weighting approaches are 

summarized below. Table XVII-4 presents the estimated numbers of 

small entities incurring costs exceeding 1 percent and 3 percent 

of revenue. For more information on this analysis in general and 

the weighting approaches in particular, see Chapter 7 in the RIA 

report.
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Table XVII-4. Estimated Cost-to-Revenue Impact on Small Entities 

Owning Steam Electric Plants Subject to this Proposed Rule 

(Excluding those below the Size Threshold)

Regu

lato

ry 

Opti

on

Lower bound estimate of 

number of entities 

owning steam electric 

plants

Upper bound estimate of number of 

entities owning steam electric plants

Regulat

ory 

Option Cost 1% of Revenue

Cost 3% of 

Revenue

Cost 

1% of 

Revenue

Cost 3% of 

Revenue

Number of Small 

Entities

% of 

Small 

Affect

ed 

Entiti

esb

Number of 

Small 

Entitiesa

% of 

Small 

Affect

ed 

Entiti

esb

Num

ber 

of 

Sma

ll 

Ent

iti

es

% 

of 

Sma

ll 

Aff

ect

ed 

Ent

iti

esb

Num

ber 

of 

Sma

ll 

Ent

iti

esa

% 

of 

Sma

ll 

Aff

ect

ed 

Ent

iti

esb

Lower bound estimate of number of entities owning steam electric 

plants

Option 

3a 0 0.0% 0 0.0%

Option 

3b 0 0.0% 0 0.0%

Option 

1

3 3.1% 3 3.1% 31.8% 31.8%

Option 

2

5 5.2% 3 3.1% 52.9% 31.8%

Option 

3

5 5.2% 3 3.1% 52.9% 31.8%

Option 

4a 6 6.2% 4 4.1%

Option 

4

12 12.4% 4 4.1% 127.1% 42.4%

Option 

5

12 12.4% 7 7.2%

Upper bound estimate of number of entities owning steam electric 

plants

Option 

3a 0 0.0% 0 0.0%

Option 

3b 0 0.0% 0 0.0%

Option 

1

3 1.8% 3 1.8%

Option 

2

5 2.9% 3 1.8%

Formatted Table

Merged Cells

Formatted Table

Deleted Cells

Deleted Cells

Deleted Cells

Deleted Cells

Deleted Cells

Deleted Cells

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Tab stops: 1", Right

Deleted Cells

Deleted Cells

Deleted Cells

Deleted Cells

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Tab stops: 1", Right

Formatted: Indent: Left: -0.13", Right: 0.12",

Tab stops: 1", Right

Formatted Table

Formatted: Indent: Left: -0.13", Right: 0.12",

Tab stops: 1", Right

Deleted Cells

Deleted Cells

Deleted Cells

Deleted Cells
*** E. O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Table XVII-4. Estimated Cost-to-Revenue Impact on Small Entities 

Owning Steam Electric Plants Subject to this Proposed Rule 

(Excluding those below the Size Threshold)

Regu

lato

ry 

Opti

on

Lower bound estimate of 

number of entities 

owning steam electric 

plants

Upper bound estimate of number of 

entities owning steam electric plants

Regulat

ory 

Option Cost 1% of Revenue

Cost 3% of 

Revenue

Cost 

1% of 

Revenue

Cost 3% of 

Revenue

Number of Small 

Entities

% of 

Small 

Affect

ed 

Entiti

esb

Number of 

Small 

Entitiesa

% of 

Small 

Affect

ed 

Entiti

esb

Num

ber 

of 

Sma

ll 

Ent

iti

es

% 

of 

Sma

ll 

Aff

ect

ed 

Ent

iti

esb

Num

ber 

of 

Sma

ll 

Ent

iti

esa

% 

of 

Sma

ll 

Aff

ect

ed 

Ent

iti

esb

Lower bound estimate of number of entities owning steam electric 

plants

Option 

3a 0 0.0% 0 0.0%

Option 

3b 0 0.0% 0 0.0%

Option 

1

3 3.1% 3 3.1% 31.8% 31.8%

Option 

2

5 5.2% 3 3.1% 52.9% 31.8%

Option 

3

5 2.9% 3 1.8%

Option 

4a 6 3.5% 4 2.4%

Option 

4

12 7.1% 4 2.4%

Option 

5

12 12.4

%

77.2% 12 7.1% 7 4.1%

a The number of entities with cost-to-revenue ratios exceeding 3 percent is

a subset of the number of entities with such ratios exceeding 1 percent.

b Percentage values were calculated relative to the total of 97 (Case 1) and 

170 (Case 2) small entities owning steam electric plants 

As reported in Table XVII-4, EPA estimates that between 30

and 12 small entities owning steam electric plants will incur 

costs exceeding 1 percent of revenue, and that between 30 and 7 

Formatted Table

Merged Cells

Formatted Table

Deleted Cells

Deleted Cells

Deleted Cells

Deleted Cells

Deleted Cells

Deleted Cells

Formatted Table

Formatted: Indent: Left: -0.13", Right: 0.12",

Tab stops: 1", Right

Deleted Cells

Deleted Cells

Deleted Cells

Deleted Cells

Formatted: Indent: Left: -0.13", Right: 0.12",

Tab stops: 1", Right

Formatted Table

Formatted: Right: 0.12"

Deleted Cells

Deleted Cells

Deleted Cells

Deleted Cells

Formatted: Right: 0.12"
*** E. O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 470 of 517

small entities owning steam electric plants will incur costs 

exceeding 3 percent of revenue, depending on the regulatory 

option. This is out of an estimated total of 97 to 170 small 

entities owning steam electric plants. The impact findings in 

terms of numbers of entities affected at different levels, and 

the percentage of small entities by ownership category vary by 

regulatory option. Overall across entity types, no small entity 

is estimated to have costs exceeding 1 percent of revenue under 

Options 3a and 3b. Under Option 3, 5 small entities are 

estimated to have costs exceeding 1 percent of revenue under 

Option 3 for BAT and PSES, and 3 small entities have costs 

exceeding 3 percent of revenue. Under Option 4, 124a, 6 small 

entities are estimated to have costs 1 percent of revenue or 

higher under Option 3, and 4 small entities have costs 3 percent 

of revenue or higher. Table XVII-5 presents the distribution of 

these entities by ownership type for Options 3 and 4.4a (Options 

3a and 3b are not included in the table since no small entity 

has costs 1 percent of revenue or higher under these two 

options). As shown in the table, small entities with costs 1 

percent of revenue or greater under Option 3 include 2 small 

cooperatives and 3 small municipalities. Under Option 4, 8 small 

municipalities4a, 2 small cooperatives, one small investor-owned 

entity, and one small nonutility and 4 municipalities have costs 

1 percent of revenue or greater. The cost-to-revenue test is one 
*** E. O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

Page 471 of 517

of several metrics EPA used to determine the impacts of the 

proposed ELGs. As discussed in Section XI.D, EPA also looked at 

impacts in the context of the electricity market-level effects 

to assess economic achievability. 

Table XVII-5. Estimated Cost-to-Revenue Impact on Small Entities 

Owning Steam Electric Plants Under the Preferred BAT and PSES 

Options (Options 3 and 44a), By Ownership Type (Excluding those 

below the Size Threshold)a

Regulator

y Option

Lower bound estimate of number 

of entities owning steam 

electric plants

Upper bound estimate of number 

of entities owning steam 

electric plants

Cost 1% of 

Revenue

Cost 3% of 

Revenue

Cost 1% of 

Revenue

Cost 3% of 

Revenue

Number 

of 

Small 

Entitie

s

% of 

Small 

Affecte

d 

Entitie

s

bEntit

iesc

Number 

of 

Small 

Entitie

s

aEntit

iesb

% of 

Small 

Affecte

d 

Entitie

s

bEntit

iesc

Number 

of 

Small 

Entitie

s

% of 

Small 

Affecte

d 

Entitie

s

bEntit

iesc

Number 

of 

Small 

Entitie

s

aEntit

iesb

% of 

Small 

Affecte

d 

Entitie

s

bEntit

iesc

Option 3

Cooperati

ve

2 15.4% 2 15.4% 2 9.4% 2 9.4%

InvestorOwned 0 0.0% 0 0.00% 0 0.0% 0 0.0%

Municipal

ity 3 8.1% 1 2.7% 3 6.5% 1 2.2%

Nonutilit

y

0 0.0% 0 0.0% 0 0.0% 0 0.0%

Other 

Political 

Subdivisi

on

0 0.0% 0 0.0% 0 0.0% 0 0.0%

Total 5 5.2% 3 3.1% 5 2.9% 3 1.8%

Option 

44a

Cooperati

ve

2 15.4% 2 15.4% 2 9.4% 2 9.4%

InvestorOwned10 3.70.0% 0 0.0% 10 1.60.0% 0 0.0%

Municipal

ity

84 21.610.

8%

2 5.4% 84 17.48.7

%

2 4.4%

Nonutilit

y

10 5.60.0% 0 0.0% 10 2.90.0% 0 0.0%
*** E. O. 12866 Review – Draft – Do Not Cite, Quote, or Release During Review***

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Table XVII-5. Estimated Cost-to-Revenue Impact on Small Entities 

Owning Steam Electric Plants Under the Preferred BAT and PSES 

Options (Options 3 and 44a), By Ownership Type (Excluding those 

below the Size Threshold)a

Regulator

y Option

Lower bound estimate of number 

of entities owning steam 

electric plants

Upper bound estimate of number 

of entities owning steam 

electric plants

Cost 1% of 

Revenue

Cost 3% of 

Revenue

Cost 1% of 

Revenue

Cost 3% of 

Revenue

Number 

of 

Small 

Entitie

s

% of 

Small 

Affecte

d 

Entitie

s

bEntit

iesc

Number 

of 

Small 

Entitie

s

aEntit

iesb

% of 

Small 

Affecte

d 

Entitie

s

bEntit

iesc

Number 

of 

Small 

Entitie

s

% of 

Small 

Affecte

d 

Entitie

s

bEntit

iesc

Number 

of 

Small 

Entitie

s

aEntit

iesb

% of 

Small 

Affecte

d 

Entitie

s

bEntit

iesc

Other 

Political 

Subdivisi

on

0 0.0% 0 0.0% 0 0.0% 0 0.0%

Total 126 12.46.2

%

4 4.1% 126 7.13.5% 4 2.4%

aa Options 3a and 3b are not included in the table since no small entity has 

costs 1 percent of revenue or higher under these two preferred options.

b The number of entities with cost-to-revenue ratios exceeding 3 percent is 

a subset of the number of entities with such ratios exceeding 1 percent.

bc Percentage values were calculated relative to the total of 97 (Case 1) and 

170 (Case 2) small entities owning steam electric plants. EPA expects that 

Case 2 is a more likely ownership scenario for small entities (e.g., small 

municipalities) as small entities may be less likely to own multiple nonsurveyed steam electric plants. See RIA Chapter 8 for details.

Based on this analysis, EPA determines that the small 

entity impact levels for the preferred BAT and PSES options 

(Options 3a, 3b, 3 and 44a) support a finding of no significant 

impact on a substantial number of small entities (No SISNOSE).

The Where not zero altogether, the numbers of small entities 

incurring costs exceeding either the 1 or 3 percent of revenue 

impact threshold are small in the absolute and represent small 

percentages of the total estimated number of small entities (see 
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Table XVII-5). For more details on this analysis, see Chapter 8

of the RIA report.

3. Certification Statement

After considering the economic impacts of these proposed 

ELGs on small entities, I certify that this action will not have 

a significant economic impact on a substantial number of small 

entities. EPA bases its finding on the low number of small 

entities estimated to incur costs exceeding one and/or three 

percent of revenue, and the small percentage that these entities 

represent within the total of small entities owning steam 

electric plants. EPA continues to be interested in the potential 

impacts of the proposed rule on small entities and welcomes 

comments on issues related to potential impacts.

D. Unfunded Mandates Reform Act (UMRA)

Title II of the Unfunded Mandates Reform Act of 1995 

(UMRA), 2 U.S.C. 1531-1538, requires federal agencies, unless 

otherwise prohibited by law, to assess the effects of their 

regulatory actions on State, local, and tribal governments and 

the private sector. This rule contains a federal mandate that 

may result in expenditures of $100 million or more for State, 

local, and tribal governments, in the aggregate, or the private 

sector in any one year. Accordingly, EPA has prepared under 

Section 202 of the UMRA a written statement, which is summarized 

below (see Chapter 9 in the RIA report for more details). 
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Consistent with the intergovernmental consultation 

provisions of Section 204 of the UMRA EPA has initiated 

consultations with governmental entities affected by this rule. 

As described in Sections XVII.E, EPA held consultation meetings 

with elected officials or their designated employees in October 

2011 to ensure their meaningful and timely input into the 

proposed ELGs development. EPA also conducted outreach with 

several intergovernmental associations representing elected 

officials. As described in Section XVII.F, EPA also initiated 

consultation and coordination with federally-recognized tribal 

governments in August 2011 and continued this government-togovernment dialogue in March 2012.

Consistent with Section 205, EPA has identified and 

considered a reasonable number of regulatory alternatives. EPA 

considered and analyzed several alternative regulatory options 

to determine BAT/BADCT. These regulatory options are discussed 

in Section VIII of this preamble. These options included a range 

of technology-based approaches. As discussed in detail in 

Section VIII, EPA is proposing Options 3a, 3b, 3 and 44a as the 

preferred BAT and PSES options andbecause they are 

technologically available, economically achievable, and have 

acceptable non-water quality environmental impacts. EPA is 

proposing Option 4 as the preferred NSPS and PSNS option because 

they represent the statutorily required levels of controls which 
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effectively target the pollutants of concern in power plant 

discharges that pose risks to human healthit is technologically 

available and the environmentdemonstrated, poses no barrier to 

entry, and have caused documentedhas acceptable non-water 

quality environmental impacts.

This rule is not subject to the requirements of Section 203 

of UMRA because it contains no regulatory requirements that 

might significantly or uniquely affect small governments. For 

its assessment of the impact of compliance requirements on small 

governments (i.e., governments with a population of less than 

50,000), EPA compared total costs and costs per plant estimated 

to be incurred by small governments with the costs estimated to 

be incurred by large governments. EPA also compared costs for 

small government-owned plants with those of non-government-owned 

facilities. The Agency evaluated both the average and maximum 

annualized cost per plant. Chapter 9 of the RIA report provides 

details of these analyses. In all of these comparisons, both for 

the cost totals and, in particular, for the average and maximum 

cost per plant, the costs for small government-owned facilities

were less than those for large government-owned facilities or 

for small non-government-owned facilities. On this basis, EPA 

concludes that the compliance cost requirements of the proposed 

Steam Electric ELGs would not significantly or uniquely affect 

small governments. 
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E. Executive Order 13132: Federalism

Under Executive Order 13132, EPA may not issue an action 

that has federalism implications, that imposes substantial 

direct compliance costs, and that is not required by statute, 

unless the Federal government provides the funds necessary to 

pay the direct compliance costs incurred by State and local 

governments, or EPA consults with state and local officials 

early in the process of developing the proposed action.

EPA has concluded that this action may have federalism 

implications, because it may impose substantial direct 

compliance costs on state or local governments, and the federal 

government will not provide the funds necessary to pay those 

costs. 

As discussed in Section XI, EPA anticipates that this 

proposed action will not impose incremental administrative 

burden on states from issuing, reviewing, and overseeing 

compliance with discharge requirements. However, EPA has 

identified 168 steam electric plants owned by state or local 

government entities, out of which 14less than 10 percent may 

incur costs under one of the preferred regulatory Options. 

Specifically, EPA projects that five government-owned plants 

incur compliance costs under BAT/PSES regulatory Option 3 and 

313a, six plants incur compliance costs under Option 43b, 14 

plants incur compliance costs under Option 3, and 15 plants 
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incur compliance costs under Option 4a. EPA estimates that the 

maximum compliance cost in any one year to governments 

(excluding federal government) is $58.2for the eight regulatory 

options ranges from $13.8 million under Option 1, $95.6 million 

under Option 2, $109.5 million under Option 3, $244.2 million 

under Option 4, and 3a to $406.2 million under Option 5. Options 

3b, 3 and 4a have maximum compliance costs in any one year to 

governments of $31.9 million, $109.5 million and $141.8 million, 

respectively (see Chapter 9 of the RIA report for details). From 

these cost values, EPA determined that the proposed ELGs contain 

a federal mandate that may result in expenditures of $100 

million or more for state, local, and tribal governments, in the 

aggregate, in any one year. Based on this information, EPA finds 

that the action may impose substantial direct compliance costs 

on state or local governments. Accordingly, EPA provides the 

following federalism summary impact statement as required by 

Section 6(b) of Executive Order 13132.

EPA consulted with elected officials or their 

representative national organizations early in the process of 

developing the proposed action to permit them to have meaningful 

and timely input into its development. 

EPA invited government officials to a consultation meeting 

held on October 11, 2011. EPA conducted outreach with several 

intergovernmental associations representing elected officials 
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and encouraged their members to participate in the meeting, 

including the National Governors Association, the National 

Conference of State Legislatures, the Council of State 

Governments, the National Association of Counties, the National 

League of Cities, the U.S. Conference of Mayors, the County 

Executives of America and the National Associations of Towns and 

Townships. 

Over 50 participants attended the consultation by phone and 

another 20 attended the meeting in person. EPA representatives 

were also present. Participants raised concerns during the 

meeting and in written comments regarding the technology 

options, pollutant removal effectiveness, costs of specific 

technologies and overall costs, impacts on small generating 

units and on small governments, and generally requested more 

detailed information. They also expressed their concern with 

regulating the industry at this time given the difficult 

economic conditions. 

As explained in Section VIII, under all eight proposed 

regulatory options, EPA is proposing differentiated requirements 

for oil-fired generating units and units 50 MW or less. EPA 

believes these differentiated requirements will alleviate some 

of the concerns raised above. Further, as explained in Section 

XI, EPA’s analysis demonstrates that the proposed requirements 

are economically achievable for the steam electric industry as a 
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Page 479 of 517

whole and for plants owned by state or local government 

entities. EPA is including in the docket for this action a 

memorandum that provides a response to the comments it received 

through this consultation. In the spirit of Executive Order 

13132, and consistent with EPA policy to promote communications 

between EPA and State and local governments, EPA specifically 

solicits comment on the proposed ELGs from State and local 

officials.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

This action does not have tribal implications, as specified 

in Executive Order 13175 (65 FR 67249, November 9, 2000). It 

would not have substantial direct effects on tribal governments, 

on the relationship between the federal government and the 

Indian tribes, or the distribution of power and responsibilities 

between the Federal government and Indian tribes as specified in 

Executive Order 13175. EPA’s analyses show that no facility 

subject to today’s proposed ELGs is owned by tribal governments. 

Thus, Executive Order 13175 does not apply to this action. 

Although Executive Order 13175 does not apply to this 

action, EPA consulted with tribal officials in developing this 

action. EPA initiated consultation and coordination with 

federally recognized tribal governments in August 2011, sharing 

information about the steam electric effluent guidelines 
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rulemaking with the National Tribal Caucus and the National 

Tribal Water Council. EPA continued this government-togovernment dialogue and, in March 2012, invited tribal 

representatives to participate in further discussions about the 

rulemaking process and objectives, with a focus on identifying 

specific ways that the rulemaking may affect tribes. EPA mailed 

an invitation letter directly to those tribes that were 

preliminarily identified as potentially affected by the 

rulemaking, as well extended the invitation via email to all 

federally-recognized tribal governments encouraging their 

participation in the consultation process. The consultation 

process ended on April 17, 2012 and no comments were received 

from any tribal representative. For further information 

regarding the consultation process and supplemental materials 

provided to tribal representatives please go to the steam 

electric power generating effluent guidelines website at this 

link: 

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

nt8. EPA specifically solicits additional comment on this 

proposed action from tribal officials.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

This action is not subject to Executive Order 13045 (62 FR 

19885, April 23, 1997) because the Agency does not believe the 
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Page 481 of 517

environmental health risks or safety risks addressed by this 

action present a disproportionate risk to children. This 

proposed action’s health and risk assessments are summarized in 

Section XIV.D.

H. Executive Order 13211: Actions that Significantly Affect 

Energy Supply, Distribution, or Use

This action is not a “significant energy action” as defined 

in Executive Order 13211 (66 FR 28355 (May 22, 2001)) because it 

is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. 

The Agency analyzed the potential energy effects of today’s 

proposed ELGs. The potentially significant effects of today’s 

rule on energy supply, distribution or use concern the electric 

power sector. EPA’s analysis found that the proposed ELGs would 

not cause effects in the electric power sector that would 

constitute a significant adverse effect under Executive Order 

13211. Namely, the Agency’s analysis found that today’s rule 

would not reduce electricity production in excess of 1 billion 

kilowatt hours per year or in excess of 500 megawatts of 

installed capacity, and therefore would not constitute a 

significant regulatory action under Executive Order 13211. 

For more detail on the potential energy effects of this 

proposal, see Chapter 10 in the RIA report.
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I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and 

Advancement Act of 1995 (“NTTAA”), Public Law No. 104-113, 12(d) 

(15 U.S.C. 272 note), directs EPA to use voluntary consensus 

standards in its regulatory activities unless to do so would be 

inconsistent with applicable law or otherwise impractical. 

Voluntary consensus standards are technical standards (e.g., 

materials specifications, test methods, sampling procedures, and 

business practices) that are developed or adopted by voluntary 

consensus standards bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations when the Agency decides not 

to use available and applicable voluntary consensus standards.

This rulemaking does not involve technical standards, for 

example, in the measurement of pollutant loads. Nothing in this 

proposed rule would prevent the use of voluntary consensus 

standards for such measurement where available, and EPA 

encourages permitting authorities and regulated entities to do 

so. Therefore, EPA is not considering the use of any voluntary 

consensus standards.

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) 

establishes federal executive policy on environmental justice. 
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Its main provision directs federal agencies, to the greatest 

extent practicable and permitted by law, to make environmental 

justice part of their mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and 

activities on minority populations and low-income populations in 

the United States. 

EPA has determined that this proposed rule will not have 

disproportionately high and adverse human health or 

environmental effects on minority or low-income populations 

because it increases the level of environmental protection for 

all affected populations without having any disproportionately 

high and adverse human health or environmental effects on any 

population, including any minority or low-income population. 

To meet the objectives of Executive Order 12898, EPA 

examined whether today’s proposed ELGs will have potential 

environmental justice concerns in the areas affected by steam 

electric plant discharges. The Agency analyzed the demographic 

characteristics of the populations currently exposed to steam 

electric plant discharges through receiving reaches (i.e., 

populations located within 100 miles of the affected reaches, 

also referred to as the “benefit regions” in the rest of this 

discussion) to determine whether minority and or low-income 

populations are subject to disproportionally high environmental 
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Page 484 of 517

impacts. Chapter 10 of the RIA provides a detailed discussion of 

the environmental justice analysis.

EPA compared demographic data from the 2010 Census for 

benefit regions with corresponding characteristics at the state 

and national levels. This analysis focuses on the spatial 

distribution of minority and low-income groups to determine 

whether these groups are more or less represented in the 

populations expected to benefit from the proposed ELGs. The 

demographic characteristics that EPA analyzed include: percent 

African Americans, percent Native American, Eskimo, or Aleut, 

percent Asian or Pacific Islander, percent of the population 

below the poverty level, and median income. This analysis shows 

that approximately 14 percent of households in affected 

populations are below the poverty threshold, and 25 percent of 

them are minority, compared with national averages of 14 percent 

and 36 percent, respectively. Additionally, the median household 

income in affected populations is $48,579, while it is $51,914 

nationally.

Of the 344 benefit regions defined in the analysis (within 

100 miles of an affected plant), 28 regions (8 percent) may have 

Environmental Justice concerns under all three metrics, 79 

regions (23 percent) under two metrics, and 194 regions (56 

percent) under one metric. Forty-three regions (13 percent) 
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would not be considered has having Environmental Justice 

concerns under any of the metrics.

This analysis indicates that minority and low-income 

communities are expected to benefit as much as anyone from the 

proposed ELGs.

Appendix A: Definitions, Acronyms, and Abbreviations Used in 

This Notice

The following acronyms and abbreviations are used in this 

document.

Administrator — The Administrator of the U.S. Environmental 

Protection Agency.

Agency — U.S. Environmental Protection Agency.

BAT — Best available technology economically achievable, , as 

defined by Sections 301(b)(2)(A) and 304(b)(2)(B) of the CWA.

BCT — The best control technology for conventional pollutants, 

applicable to discharges of conventional pollutants from 

existing industrial point sources, as defined by Sections 

301(b)(2)(E) and 304(b)(4) of the CWA.

BMP — Best management practice.

Bottom ash – The ash, including boiler slag, that drops out of 

the furnace gas stream in the furnace and which settles in the 

furnace or are dislodged from furnace walls. Economizer ash is 

included when it is collected with bottom ash. 

BPT — The best practicable control technology currently 

available, applicable to effluent limitations, for industrial 

discharges to surface waters, as defined by Sections 301(b)(1) 

and 304(b)(1) of the CWA.

CBI — Confidential Business Information.

CCR — Coal Combustion Residuals.

Clean Water Act (CWA) — The Federal Water Pollution Control Act 

Amendments of 1972 (33 U.S.C. Section 1251 et seq.), as amended 
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e.g., by the Clean Water Act of 1977 (Pub. L. 95–217), and the 

Water Quality Act of 1987 (Pub. L. 100–4).

Combustion Residual Leachate – Leachate from landfills or 

surface impoundments containing combustion residuals. Leachate 

includes liquid, including any suspended or dissolved 

constituents in the liquid that has percolated through or 

drained from waste or other materials emplaced in a landfill, or 

that pass through the containment structure (e.g., bottom, 

dikes, berms) of a surface impoundment. Leachate also includes 

the terms seepage, leak, and leakage, which are generally used 

in reference to leachate from an impoundment. Includes landfills 

and surface impoundments located on non-adjoining property when 

under the operational control of the permitted facility.

Direct Discharger — A facility that discharges or may discharge 

treated or untreated wastewaters into waters of the United 

States.

DOE — Department of Energy.

Dry bottom ash handling system – A system that does not use 

water to convey bottom ash away from the boiler. It includes 

systems that collect and convey the ash without any use of 

water, as well as systems in which bottom ash is mechanically or 

pneumatically conveyed away from the boiler.

Dry fly ash handling system – A system that does not use water 

as the transport medium to convey fly ash away from particulate 

collection equipment. 

EIA — Energy Information Administration.

EO — Executive Order.

EPA — U.S. Environmental Protection Agency.

Facility — All property owned, operated, leased, or under the 

control of the same person or entity.

Flue Gas Desulfurization (FGD) Wastewater – Any process 

wastewater generated specifically from the wet flue gas 

desulfurization scrubber system, including any solids separation 

or solids dewatering processes.

Flue Gas Mercury Control (FGMC) System – An air pollution 

control system installed or operated for the purpose of removing 

mercury from flue gas. 

Flue Gas Mercury Control Wastewater – Any process wastewater 

generated from an air pollution control system installed or 

operated for the purpose of removing mercury from flue gas. This 
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includes fly ash collection systems when the particulate control 

system follows the injection of sorbents or implementation of 

other controls to remove mercury from flue gas. Flue gas 

desulfurization systems are not included in this definition.

Fly Ash – The ash that is carried out of the furnace by the gas 

stream and collected by mechanical precipitators, electrostatic 

precipitators, and/or fabric filters. Economizer ash is included 

when it is collected with fly ash. Ash collected in wet scrubber 

air pollution control systems whose primary purpose is 

particulate removal is not included.

Gasification Wastewater – Wastewater from all sources at an 

integrated gasification combined cycle operation except those 

for which specific limitations are otherwise established.

Gasification wastewater includes, but is not limited to the 

following: slag handling wastewater; fly ash and water stream; 

sour/grey water (which consists of condensate generated for gas 

cooling, as well as other wastestreams); CO2/steam stripper 

wastewater; air separation unit blowdown; and sulfur recover 

unit blowdown.

IPM – Integrated Planning Model.

Landfill – A disposal facility or part of a facility where solid 

waste, sludges, or other process residuals are placed in or on 

any natural or manmade formation in the earth for disposal and 

which is not a storage pile, a land treatment facility, a 

surface impoundment, an underground injection well, a salt dome 

or salt bed formation, an underground mine, a cave, or a 

corrective action management unit.

Low Volume Waste Sources – Wastewater from all sources 

including, but not limited to: ion exchange water treatment 

systems, water treatment evaporator blowdown, laboratory and 

sampling streams, boiler blowdown, floor drains, cooling tower 

basin cleaning wastes, and recirculating house service water 

systems. Sanitary and air conditioning wastes and carbon capture 

wastewater are not included.

NAICS — North American Industry Classification System. 

NSPS, or New Source Performance Standards, applicable to 

industrial facilities whose construction is begun after the 

effective date of the final regulations. See 40 CFR 122.2.

ORCR — Office of Resource Conservation and Recovery.

PSES --— Pretreatment Standards for Existing Sources.

PSNS --— Pretreatment Standards for New Sources.
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Publicly Owned Treatment Works (POTW) — Any device or system, 

owned by a state or municipality, used in the treatment 

(including recycling and reclamation) of municipal sewage or 

industrial wastes of a liquid nature that is owned by a state or 

municipality. This includes sewers, pipes, or other conveyances 

only if they convey wastewater to a POTW providing treatment.

See 40 CFR 122.2.

RCRA — The Resource Conservation and Recovery Act of 1976, 42 

U.S.C. 6901 et seq.

RFA — Regulatory Flexibility Act.

SBA — Small Business Administration.

Surface Impoundments – A facility or part of a facility which is 

a natural topographic depression, man-made excavation, or diked

or dammed area formed primarily of earthen materials (although 

it may be lined with man-made materials), which is designed to 

hold an accumulation of liquid process wastes or process wastes 

containing free liquids, and which is not an injection well.

Examples of surface impoundments are holding, storage, settling, 

and aeration pits, ponds, and lagoons.

UMRA — Unfunded Mandates Reform Act.

Wet bottom ash handling system – A system in which bottom ash is 

conveyed away from the boiler using water as a transport medium.

Wet bottom ash systems typically send the ash slurry to 

dewatering bins or a surface impoundment.

Wet FGD system – Wet FGD systems capture sulfur dioxide from the 

flue gas using a sorbent that has mixed with water to form a wet 

slurry, and that generates a water stream that exits the FGD 

scrubber absorber.

Wet fly ash handling system – A system that conveys fly ash away 

from particulate removal equipment using water as a transport 

medium. Wet fly ash systems typically dispose of the ash slurry 

in a surface impoundment.
Effluent Limitations Guidelines and New Source Performance Standards for the 

Steam Electric Power Generating Point Source Category

Page 489 of 517

List of Subjects 40 CFR Part 423

Environmental protection, Electric power generation, Power 

plants, Waste treatment and disposal, Water pollution control

Dated:

Lisa P. Jackson, 

Bob Perciasepe, 

Acting Administrator.
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Part 423 is amended to read as follows:

PART 423_STEAM ELECTRIC POWER GENERATING POINT SOURCE CATEGORY--

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

Authority: Secs. 101; 301; 304(b), (c), (e), and (g); 306; 

307; 308 and 501, Clean Water Act (Federal Water Pollution 

Control Act Amendments of 1972, as amended; 33 U.S.C. 1251; 1311; 

1314(b), (c), (e), and (g); 1316; 1317; 1318 and 1361).

2. Section 423.10 is revised as follows:

Sec. 423.10 Applicability.

The provisions of this part apply to discharges resulting 

from the operation of a generating unit by an establishment whose 

generation of electricity is the predominant source of revenue or 

principal reason for operation, and which results primarily from a 

process utilizing fossil-type fuel (coal, oil, or gas), fuel 

derived from fossil fuel (e.g., petroleum coke, synthesis gas), or 

nuclear fuel in conjunction with a thermal cycle employing the 

steam water system as the thermodynamic medium. This part applies 

to discharges associated with both the combustion turbine and steam 

turbine portions of a combined cycle generating unit. Facilities 

defined as new sources under the 1982 new source performance 

standards specified in section 423.15(a) and section 423.17(a) of 

this part continue to be subject to those standards. Facilities 

definedUnits that qualify as 1982 new sources are also subject to 

revised BAT effluent limitations specified in section 423.13 of 

this part (for direct dischargers) or the revised pretreatment 

standards specified in section 423.16 of this part (for indirect 

dischargers). These new requirementsrevised limitations and 

standards constitute amendments to the new source performance 

standards applicable to 1982 new sources.

3. Section 423.11 is amended by:

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

b. Adding paragraphs (n) – (tu).

Sec. 423.11 Specialized definitions.

* * * * *
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(b) The term low volume waste sources means, taken 

collectively as if from one source, wastewater from all sources 

except those for which specific limitations are otherwise 

established in this part. Low volume waste sources include, but are 

not limited to, the following: wastewaters from ion exchange water 

treatment systems, water treatment evaporator blowdown, laboratory 

and sampling streams, boiler blowdown, floor drains, cooling tower 

basin cleaning wastes, recirculating house service water systems, 

and wet scrubber air pollution control systems whose primary 

purpose is particulate removal. Sanitary wastes, air conditioning 

wastes, and wastewater from carbon capture or sequestration systems 

are not included in this definition.

* * * * *

(e) The term fly ash means the ash that is carried out of the 

furnace by a gas stream and collected by a capture device such as a 

mechanical precipitator, electrostatic precipitator, or fabric 

filter. Economizer ash is included in this definition when it is 

collected with fly ash. Ash is not included in this definition when 

it is collected in wet scrubber air pollution control systems whose 

primary purpose is particulate removal.

* * * * *

(n) The term flue gas desulfurization (FGD) wastewater means 

any process wastewater generated from a wet flue gas 

desulfurization scrubber system, including any solids separation or 

solids dewatering processes.

(o) The term flue gas mercury control wastewater means any 

process wastewater generated from an air pollution control system 

installed or operated for the purpose of removing mercury from flue 

gas. This includes fly ash collection systems when the particulate 

control system follows the injection of sorbents or implementation 

of other controls to remove mercury from flue gas. Flue gas 

desulfurization systems are not included in this definition.

(p) The term transport water means any process wastewater 

that is used to convey fly ash or bottom ash from the ash 

collection equipment and has direct contact with the ash.

(q) The term gasification wastewater means any process 

wastewater generated from a system used to create synthesis gas 

from fuels such as coal or petroleum coke. Gasification wastewater 

includes, but is not limited to, the following: slag handling 

wastewater, sour/grey water (which includes condensate generated 
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for gas cooling, as well as other wastestreams), CO2/steam stripper 

wastewater, air separation unit blowdown, and sulfur recovery unit 

blowdown.

(r) The term combustion residual leachate means leachate from 

landfills or surface impoundments containing residuals from the 

combustion of fossil or fossil-derived fuel. 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 pass through the 

containment structure (e.g., bottom, dikes, berms) of a surface 

impoundment. Leachate also includes the terms seepage, leak, and 

leakage, which are generally used in reference to leachate from an 

impoundment.

(s) The term oil-fired unit means a generating unit that uses 

oil as the primary or secondary fuel source and does not use a 

gasification process or any coal or petroleum coke as a fuel 

source. This definition does not include units that use oil only 

for start up or flame-stabilization purposes. 

(t) The term sufficiently sensitive analytical method means a 

method that ensures the sample-specific quantitation level for the 

wastewater being analyzed is at or below the level of the effluent 

limitation.

(u) The term nonchemical metal cleaning waste means any 

wastewater resulting from the cleaning of any metal process 

equipment without chemical cleaning compounds, including, but not 

limited to, boiler tube cleaning, boiler fireside cleaning, and air 

preheater cleaning.

4. Section 423.12 is amended by:

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

b. Adding paragraph (b)(13).

* * * * *

(b)***

(11) The quantity of pollutants discharged in FGD wastewater, flue 

gas mercury control wastewater, combustion residual leachate, or 

gasification wastewater shall not exceed the quantity determined by 

multiplying the flow of the applicable wastewater times the 

concentration listed in the following table:

Pollutant or BPT effluent limitations Formatted: Font: 12 pt
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pollutant property

Maximum for any 

1 day (mg/l)

Average of daily values for 30 

consecutive days shall not exceed 

(mg/l)

TSS 100.0 30.0

Oil and grease 20.0 15.0

(12) At the permitting authority's discretion, the quantity 

of pollutant allowed to be discharged may be expressed as a 

concentration limitation instead of the any mass based limitations 

specified in paragraphs (b)(3) through (7) and (b)(11) of this 

section. Concentration limitations shall be those concentrations 

specified in this section.

(13) In the event that wastestreams from various sources are 

combined for treatment or discharge, the quantity of each pollutant 

or pollutant property controlled in paragraphs (b)(1) through 

(b)(12) of this section attributable to each controlled waste 

source shall not exceed the specified limitations for that waste 

source.

5. Section 423.13 is amended by:

a. Revising paragraphs (f)-(h).

b. Adding paragraphs (i)-(on).

* * * * *

(f) The (f) (1) Except for those discharges to which 

paragraph (f)(2) of this section applies, the quantity of 

pollutants discharged in nonchemical metal cleaning wastes shall 

not exceed the quantity determined by multiplying the flow of 

nonchemical metal cleaning wastes times the concentration listed in 

the following table:

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

 BAT effluent limitations

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

 Average of

 daily

 values for

 Pollutant or pollutant property Maximum for 30

 any 1 day consecutive

 (mg/l) days shall

 not exceed

 (mg/l)

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

 Copper, total............... 1.0 1.0

Iron, total................. 1.0 1.0

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

 

(2) For those discharges of nonchemical metal cleaning waste 

that are currently authorized pursuant to limitations based on 

requirements in section 423.12(b)(3) for low-volume waste, the 

quantity of pollutants discharged in nonchemical metal cleaning 

wastes shall not exceed the quantity determined by multiplying the 

flow of nonchemical metal cleaning wastes times the concentration 

listed in section 423.12(b)(3).

(g)(1) Except for those discharges to which 

subsectionparagraph (g)(2) of this section applies, dischargers 

must meet the effluent limitations in this paragraph by a date 

determined by the permitting authority that is as soon as possible 

within the next permit cycle beginning July 1, 2017. These effluent 

limitations apply to pollutants in FGD wastewater generated on or 

after the date the permitting authority has determined is as soon 

as possible. Such effluent limitations shall not allow the quantity 

of pollutants in FGD wastewater to exceed the quantity determined 

by multiplying the flow of FGD wastewater times the concentration 

listed in the following table98:

Pollutant or pollutant 

property

BAT effluent limitations

Maximum 

for any 1 

day 

Average of daily values for 30 

consecutive days shall not exceed 

Arsenic, total (ug/L) 8 6

Mercury, total (ng/L) 242 119

Selenium, total (ug/L) 16 10

Nitrate/nitrate as N (mg/L) 0.17 0.13

(2) For any electric generating unit with a total nameplate 

capacity of less than or equal to 50 megawatts or that is an oilfired unit, the quantity of pollutants discharged in FGD wastewater 

shall not exceed the quantity determined by multiplying the flow of 

FGD wastewater times the concentration listed in section 

423.12(b)(11). 

 

98 All proposed revisions to section 423.13(g) reflect proposed Option 4a, Option 

3, and Option 3b (for units located at facilities with a total wet-scrubbed 

capacity of 2,000 MW or more), only. Under proposed Option 3a and Option 3b 

(for units located at facilities with a total wet-scrubbed capacity of less than 

2,000 MW), BAT would continue to need to be determined on a site-specific basis 

using best professional judgment.

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(3) A discharger must demonstrate compliance with the effluent 

limitations in paragraph (g)(1) of this section, as applicable, by 

monitoring for all pollutants (except pH) at a point prior to use 

of the FGD wastewater in any other plant process or commingling of 

the FGD wastewater with any water or other process wastewater, 

except for any combustion residual leachate or any other FGD 

wastewater. Compliance with the effluent limitations must reflect 

results obtained from sufficiently sensitive analytical methods. 

(h)(1) Except for those discharges to which 

subparagraphparagraph (h)(2) of this section applies, dischargers 

must meet the discharge prohibition in this paragraph by a date 

determined by the permitting authority that is as soon as possible 

within the next permit cycle beginning July 1, 2017. There shall be 

no discharge of wastewater pollutants from fly ash transport water 

generated on or after the date the permitting authority determines 

is as soon as possible. Whenever fly ash transport water is used in 

any other plant process or is sent to a treatment system at the 

plant, the resulting effluent must comply with the discharge 

prohibition in this paragraph.

(2) For any electric generating unit with a total nameplate 

generating capacity of less than or equal to 50 megawatts or that 

is an oil-fired unit, the quantity of pollutants discharged in fly 

ash transport water shall not exceed the quantity determined by 

multiplying the flow of fly ash transport water times the 

concentration listed in section 423.12(b)(4). 

(i)(1) Except for those discharges to which 

subparagraphparagraph (i)(2) of this section applies, dischargers 

must meet the discharge prohibition in this paragraph by a date 

determined by the permitting authority that is as soon as possible 

within the next permit cycle beginning July 1, 2017. There shall be 

no discharge of wastewater pollutants from flue gas mercury control 

wastewater generated on or after the date the permitting authority 

determines is as soon as possible. Whenever flue gas mercury 

control wastewater is used in any other plant process or is sent to 

a treatment system at the plant, the resulting effluent must comply 

with the discharge prohibition in this paragraph.

(2) For any electric generating unit with a total nameplate 

generating capacity of less than or equal to 50 megawatts or that 

is an oil-fired unit, the quantity of pollutants discharged in flue 

gas mercury control wastewater shall not exceed the quantity 

determined by multiplying the flow of flue gas mercury control 

wastewater times the concentration listed in 

section 423.12(b)(11).
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(j)(1) Except for those discharges to which subsectionparagraph

(j)(2) of this section applies, dischargers must meet the effluent 

limitations in this paragraph by a date determined by the 

permitting authority that is as soon as possible within the next 

permit cycle beginning July 1, 2017. Such effluent limitations 

shall not allow the quantity of pollutants in gasification 

wastewater to exceed the quantity determined by multiplying the 

flow of gasification wastewater times the concentration listed in 

the following table:

Pollutant or pollutant 

property

BAT effluent limitations

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not exceed 

Arsenic, total (ug/L) 4 (

1)

Selenium, total (ug/L) 453 227

Mercury, total (ng/L) 1.76 1.29

Selenium, total (ug/L) 453 227

Total dissolved 

solids

(mg/L) 38 22

1

This regulation does not specify this type of limitation for this 

pollutant; however, permitting authorities may do so as appropriate.

(2) For any electric generating unit with a total nameplate 

generating capacity of less than or equal to 50 megawatts or that 

is an oil-fired unit, the quantity of pollutants discharged in 

gasification wastewater shall not exceed the quantity determined by 

multiplying the flow of gasification wastewater times the 

concentration listed in section 423.12(b)(11).

(3) A discharger must demonstrate compliance with the effluent 

limitations in paragraph (j)(1) of this section, as applicable, by 

monitoring for all pollutants (except pH) at a point prior to use 

of the gasification wastewater in any other plant process or

commingling of the gasification wastewater with water or any other 

process wastewater. Compliance with the effluent limitations must 

reflect results obtained from sufficiently sensitive analytical 

methods.

(k)(1) Except for those discharges to which subparagraph 

(lparagraph (k)(2) of this section applies, dischargers must meet 

the discharge prohibition in this paragraph by a date determined by 

the permitting authority that is as soon as possible within the 

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next permit cycle beginning July 1, 2017. There shall be no 

discharge of wastewater pollutants from bottom ash transport water 

generated on or after the date the permitting authority determines 

is as soon as possible. Whenever bottom ash transport water is used 

in any other plant process or is sent to a treatment system at the 

plant, the resulting effluent must comply with the discharge 

prohibition in this paragraph99.

(2) For any electric generating unit with a total nameplate 

generating capacity of less than or equal to 50400 megawatts or 

that is an oil-fired unit, the quantity of pollutants discharged in 

bottom ash transport water shall not exceed the quantity determined 

by multiplying the flow of the applicable wastewater times the 

concentration in section 423.12(b)(4).100

(l)(1) Except for those discharges to which subsection (m)(2) 

applies, dischargers must meet the effluent limitations in this 

paragraph by a date determined by the permitting authority that is 

as soon as possible beginning July 1, 2017. These effluent 

limitations apply to pollutants in combustion residual leachate

generated on or after the date the permitting authority has 

determined is as soon as possible. Such effluent limitations shall 

not allow the quantity of pollutants in combustion residual 

leachate to exceed the quantity determined by multiplying the flow 

of combustion residual leachate times the concentration listed in 

the following table:

Pollutant or pollutant 

property

BAT effluent limitations

Maximum 

for any 1 

day 

Average of daily values for 30 

consecutive days shall not exceed 

Arsenic, total (ug/L) 8 6

Mercury, total (ng/L) 242 119

 

99 All proposed revisions to section 423.13(k) reflect proposed Option 4a, only. 

Under proposed Option 3, Option 3a, and Option 3b, section 423.13(k) would be 

revised to specify that the quantity of pollutants discharged in bottom ash 

transport water shall not exceed the quantity determined by multiplying the flow 

of the applicable wastewater times the concentration in section 423.12(b)(4).

100 These revisions to section 423.13(l) reflect proposed Option 4, only. Under 

proposed Option 3, section 423.13(l) would be revised to specify that the 

quantity of pollutants discharged in bottom ash transport water shall not exceed 

the quantity determined by multiplying the flow of the applicable wastewater 

times the concentration in section 423.12(b)(4).
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(2) For any electric generating unit with a total nameplate 

capacity of less than or equal to 50 megawatts or that is an oilfired unit, the (l) The quantity of pollutants discharged in 

combustion residual leachate shall not exceed the quantity 

determined by multiplying the flow of leachate times the 

concentration listed in section 423.12(b)(11).

(3) A discharger must demonstrate compliance with the effluent 

limitations in paragraph (m)(1) of this section, as applicable, by 

monitoring for all pollutants (except pH) at a point prior to use 

of the combustion residual leachate in any other plant process or 

commingling of the combustion residual leachate with any water or 

other process wastewater, except for any FGD wastewater or any 

other combustion residual leachate. Compliance with the effluent 

limitations must reflect results obtained from sufficiently 

sensitive analytical methods.101

(m) At the permitting authority's discretion, the quantity of 

pollutant allowed to be discharged may be expressed as a 

concentration limitation instead of theany mass based limitations 

specified in paragraphs (b) through (l) of this section. 

Concentration limitations shall be those concentrations specified 

in this section.

(n) In the event that wastestreams from various sources are 

combined for treatment or discharge, the quantity of each pollutant 

or pollutant property controlled in paragraphs (a) through (m) of 

this section attributable to each controlled waste source shall not 

exceed the specified limitation for that waste source.

6. Section 423.15 is amended by revising paragraphs (a) and 

(b) to read as follows:

Sec. 423.15 New source performance standards (NSPS)

(a) 1982 New source performance standards. Any new source as 

of November 19, 1982, subject to this subpart, must achieve the 

following new source performance standards and the revised 

requirements of section 423.13 of this part:, published on [insert 

date of publication of final rule]:

 

101 These revisions to section 423.13(m) reflect proposed Option 4, only. Under 

proposed Option 3, section 423.13(m) would be revised to specify that the 

quantity of pollutants discharged in combustion residual leachate shall not 

exceed the quantity determined by multiplying the flow of leachate times the 

concentration listed in section 423.12(b)(11).

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(1) The pH of all discharges, except once through cooling 

water, shall be within the range of 6.0-9.0.

(2) There shall be no discharge of polychlorinated biphenyl 

compounds such as those commonly used for transformer fluid.

(3) The quantity of pollutants discharged from low volume 

waste sources shall not exceed the quantity determined by 

multiplying the flow of low volume waste sources times the 

concentration listed in the following table:

Pollutant or 

pollutant property

NSPS

Maximum for any 

1 day (mg/l)

Average of daily values for 30 

consecutive days shall not exceed 

(mg/l)

TSS 100.0 30.0

Oil and grease 20.0 15.0

(4) The quantity of pollutants discharged in chemical metal 

cleaning wastes shall not exceed the quantity determined by 

multiplying the flow of chemical metal cleaning wastes times the 

concentration listed in the following table:

Pollutant or 

pollutant property

NSPS

Maximum for any 

1 day (mg/l)

Average of daily values for 30 

consecutive days shall not exceed 

(mg/l)

TSS 100.0 30.0

Oil and grease 20.0 15.0

Copper, total 1.0 1.0

Iron, total 1.0 1.0

(5) [Reserved--Nonchemical Metal Cleaning Wastes].

(6) The quantity of pollutants discharged in bottom ash 

transport water shall not exceed the quantity determined by 

multiplying the flow of the bottom ash transport water times the 

concentration listed in the following table:

Pollutant or NSPS

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Page 500 of 517

pollutant property

Maximum for any 

1 day (mg/l)

Average of daily values for 30 

consecutive days shall not exceed 

(mg/l)

TSS 100.0 30.0

Oil and grease 20.0 15.0

(7) There shall be no discharge of wastewater pollutants from 

fly ash transport water. Whenever fly ash transport water is used 

in any other plant process or is sent to a treatment system at the 

plant, the resulting effluent must comply with the discharge 

prohibition in this paragraph.

(8)(A) For any plant with a total rated electric generating 

capacity of 25 or more megawatts, the quantity of pollutants 

discharged in once through cooling water from each discharge point 

shall not exceed the quantity determined by multiplying the flow of 

once through cooling water from each discharge point times the 

concentration listed in the following table:

Pollutant or pollutant 

property

NSPS

Maximum concentrations

(mg/l)

Total residual chlorine 0.20

(B) Total residual chlorine may not be discharged from any 

single generating unit for more than two hours per day unless the 

discharger demonstrates to the permitting authority that discharge 

for more than two hours is required for macroinvertebrate control. 

Simultaneous multi-unit chlorination is permitted.

(9)(A) For any plant with a total rated generating capacity of 

less than 25 megawatts, the quantity of pollutants discharged in 

once through cooling water shall not exceed the quantity determined 

by multiplying the flow of once through cooling water sources times 

the concentration listed in the following table:

Pollutant or pollutant 

property

Maximum concentration

(mg/l)

Average concentration

(mg/l)

Free available chlorine 0.5 0.2

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Page 501 of 517

(B) Neither free available chlorine nor total residual 

chlorine may be discharged from any unit for more than two hours in 

any one day and not more than one unit in any plant may discharge 

free available or total residual chlorine at any one time unless 

the utility can demonstrate to the Regional Administrator or State, 

if the State has NPDES permit issuing authority, that the units in 

a particular location cannot operate at or below this level of 

chlorination.

(10)(A) The quantity of pollutants discharged in cooling tower 

blowdown shall not exceed the quantity determined by multiplying 

the flow of cooling tower blowdown times the concentration listed 

below:

Pollutant or pollutant property

NSPS

Maximum concentration

(mg/l)

Average concentration

(mg/l)

Free available chlorine 0.5 0.2

Pollutant or pollutant property

NSPS

Maximum for 

any 1 day

(mg/l)

Average of daily values for 

30 consecutive days shall 

not exceed (mg/l)

The 126 priority pollutants 

(Appendix A)contained in chemicals 

added for cooling tower 

maintenance, except:

(

1) (1)

Chromium, total 0.2 0.2

zinc, total 1.0 1.0

1 No detectable amount.

(B) Neither free available chlorine nor total residual 

chlorine may be discharged from any unit for more than two hours in 

any one day and not more than one unit in any plant may discharge 

free available or total residual chlorine at any one time unless 

the utility can demonstrate to the Regional Administrator or State, 

if the State has NPDES permit issuing authority, that the units in 

a particular location cannot operate at or below this level of 

chlorination.

(C) At the permitting authority's discretion, instead of the 

monitoring in 40 CFR 122.11(b), compliance with the limitations for 

the 126 priority pollutants in paragraph (a)(10)(A) of this section 

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Page 502 of 517

may be determined by engineering calculations which demonstrate 

that the regulated pollutants are not detectable in the final 

discharge by the analytical methods in 40 CFR part 136.

(11) Subject to the provisions of section 423.15(a)(12), the 

quantity or quality of pollutants or pollutant parameters 

discharged in coal pile runoff shall not exceed the limitations 

specified below:

Pollutant or pollutant 

property

NSPS

for any time

TSS not to exceed 50 mg/l.

(12) Any untreated overflow from facilities designed, 

constructed, and operated to treat the coal pile runoff which 

results from a 10 year, 24 hour rainfall event shall not be subject 

to the limitations in section 423.15(a)(11).

(13) At the permitting authority's discretion, the quantity of 

pollutant allowed to be discharged may be expressed as a 

concentration limitation instead of theany mass based 

limitationlimitations specified in paragraphs (a)(3) through 

(a)(10) of this section. Concentration limits shall be based on the 

concentrations specified in this section.

(14) In the event that wastestreams from various sources are 

combined for treatment or discharge, the quantity of each pollutant 

or pollutant property controlled in paragraphs (a)(1) through 

(a)(13) of this section attributable to each controlled waste 

source shall not exceed the specified limitation for that waste 

source.

(The information collection requirements contained in 

paragraphs (a)(8)(B), (a)(9)(B), and (a)(10)(B) were approved by 

the Office of Management and Budget under control number 2040-0040. 

The information collection requirements contained in paragraph 

(a)(10)(C) were approved under control number 2040-0033.)

(b) 2014 New source performance standards. Any new source as 

of [insert date of publication of final rule], subject to this 

subpart, must achieve the following new source performance 

standards:

(1) The pH of all discharges, except once through cooling 

water, shall be within the range of 6.0-9.0.

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

Page 503 of 517

(2) There shall be no discharge of polychlorinated biphenyl 

compounds such as those commonly used for transformer fluid.

(3) The quantity of pollutants discharged from low volume 

waste sources shall not exceed the quantity determined by 

multiplying the flow of low volume waste sources times the 

concentration listed in the following table:

Pollutant or pollutant property

NSPS

Maximum for 

any 1 day

(mg/l)

Average of daily values for 

30 consecutive days shall 

not exceed (mg/l)

TSS 100.0 30.0

Oil and grease 20.0 15.0

(4) The quantity of pollutants discharged in chemical metal 

cleaning wastes shall not exceed the quantity determined by 

multiplying the flow of chemical metal cleaning wastes times the 

concentration listed in the following table:

Pollutant or pollutant property

NSPS

Maximum for 

any 1 day

(mg/l)

Average of daily values for 

30 consecutive days shall 

not exceed (mg/l)

TSS 100.0 30.0

Oil and grease 20.0 15.0

Copper, total 1.0 1.0

Iron, total 1.0 1.0

(5) The quantity of pollutants discharged in nonchemical 

metal cleaning wastes shall not exceed the quantity determined by 

multiplying the flow of nonchemical metal cleaning wastes times the 

concentration listed in the following table:

Pollutant or 

pollutant property

NSPS

Maximum for any 

1 day (mg/l)

Average of daily values for 30 

consecutive days shall not exceed 

(mg/l)

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Page 504 of 517

Pollutant or 

pollutant property

NSPS

Maximum for any 

1 day (mg/l)

Average of daily values for 30 

consecutive days shall not exceed 

(mg/l)

TSS 100.0 30.0

Oil and grease 20.0 15.0

Copper, total 1.0 1.0

Iron, total 1.0 1.0

(6) There shall be no discharge of wastewater pollutants from 

bottom ash transport water. Whenever bottom ash transport water is 

used in any other plant process or is sent to a treatment system at 

the plant, the resulting effluent must comply with the discharge 

prohibition in this paragraph.

(7) There shall be no discharge of wastewater pollutants from 

fly ash transport water. Whenever fly ash transport water is used 

in any other plant process or is sent to a treatment system at the 

plant, the resulting effluent must comply with the discharge 

prohibition in this paragraph.

(8)(A) For any plant with a total rated electric generating 

capacity of 25 or more megawatts, the quantity of pollutants 

discharged in once through cooling water from each discharge point 

shall not exceed the quantity determined by multiplying the flow of 

once through cooling water from each discharge point times the 

concentration listed in the following table:

Pollutant or pollutant 

property

NSPS

Maximum concentration 

(mg/l)

Total residual chlorine 0.20

(B) Total residual chlorine may not be discharged from any 

single generating unit for more than two hours per day unless the 

discharger demonstrates to the permitting authority that discharge 

for more than two hours is required for macroinvertebrate control. 

Simultaneous multi-unit chlorination is permitted.

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Page 505 of 517

(9)(A) For any plant with a total rated generating capacity of 

less than 25 megawatts, the quantity of pollutants discharged in 

once through cooling water shall not exceed the quantity determined 

by multiplying the flow of once through cooling water sources times 

the concentration listed in the following table:

Pollutant or pollutant property

NSPS

Maximum concentration

(mg/l)

Average concentration

(mg/l)

Free available chlorine 0.5 0.2

(B) Neither free available chlorine nor total residual 

chlorine may be discharged from any unit for more than two hours in 

any one day and not more than one unit in any plant may discharge 

free available or total residual chlorine at any one time unless 

the utility can demonstrate to the Regional Administrator or State, 

if the State has NPDES permit issuing authority, that the units in 

a particular location cannot operate at or below this level of 

chlorination.

(10)(A) The quantity of pollutants discharged in cooling tower 

blowdown shall not exceed the quantity determined by multiplying 

the flow of cooling tower blowdown times the concentration listed 

below:

Pollutant or pollutant property

NSPS

Maximum concentration

(mg/l)

Average concentration

(mg/l)

Free available chlorine 0.5 0.2

Pollutant or pollutant property

Maximum for 

any 1 day

(mg/l)

Average of daily values for 

30 consecutive days shall 

not exceed (mg/l)

The 126 priority pollutants 

(Appendix A)contained in chemicals 

added for cooling tower 

maintenance, except:

(

1) (1)

Chromium, total 0.2 0.2

zinc, total 1.0 1.0

1 No detectable amount.

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

Page 506 of 517

(B) Neither free available chlorine nor total residual 

chlorine may be discharged from any unit for more than two hours in 

any one day and not more than one unit in any plant may discharge 

free available or total residual chlorine at any one time unless 

the utility can demonstrate to the Regional Administrator or State, 

if the State has NPDES permit issuing authority, that the units in 

a particular location cannot operate at or below this level of 

chlorination.

(C) At the permitting authority's discretion, instead of the 

monitoring in 40 CFR 122.11(b), compliance with the limitations for 

the 126 priority pollutants in paragraph (b)(10)(A) of this section 

may be determined by engineering calculations which demonstrate 

that the regulated pollutants are not detectable in the final 

discharge by the analytical methods in 40 CFR part 136.

(11) Subject to the provisions of section 423.15(b)(12), the 

quantity or quality of pollutants or pollutant parameters 

discharged in coal pile runoff shall not exceed the limitations 

specified below:

Pollutant or pollutant 

property

NSPS

for any time

TSS not to exceed 50 mg/l.

(12) Any untreated overflow from facilities designed, 

constructed, and operated to treat the coal pile runoff which 

results from a 10 year, 24 hour rainfall event shall not be subject 

to the limitations in section 423.15(b)(11).

(13)(A) The quantity of pollutants discharged in FGD 

wastewater shall not exceed the quantity determined by multiplying 

the flow of FGD wastewater times the concentration listed in the 

following table:

Pollutant or pollutant 

property

NSPS

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not exceed 

Arsenic, total (ug/L) 8 6

Mercury, total (ng/L) 242 119

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

Page 507 of 517

Pollutant or pollutant 

property

NSPS

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not exceed 

Selenium, total (ug/L) 16 10

Nitrate/nitrite as N (mg/L) 0.17 0.13

(B) A discharger must demonstrate compliance with the 

standards in paragraph (b)(13)(A) of this section, as applicable, 

by monitoring for all pollutants (except pH) at a point prior to 

use of the FGD wastewater in any other plant process or commingling 

of the FGD wastewater with any water or other process wastewater, 

except for any combustion residual leachate or any other FGD 

wastewater. Compliance with the standards must reflect results 

obtained from sufficiently sensitive analytical methods. 

(14) There shall be no discharge of wastewater pollutants from 

flue gas mercury control wastewater. Whenever flue gas mercury 

control wastewater is used in any other plant process or is sent to 

a treatment system at the plant, the resulting effluent must comply 

with the discharge prohibition in this paragraph.

(15)(A) The quantity of pollutants discharged in gasification 

wastewater shall not exceed the quantity determined by multiplying 

the flow of gasification wastewater times the concentration listed 

in the following table:

Pollutant or pollutant 

property

NSPS

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not exceed 

Arsenic, total (ug/L) 4 (

1)

Selenium, total (ug/L) 453 227

Mercury, total (ng/L) 1.76 1.29

Selenium, total (ug/L) 453 227

Total dissolved solids (mg/L) 38 22

1 This regulation does not specify this type of limitation for this 

pollutant; however, permitting authorities may do so as appropriate.

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Page 508 of 517

(B) A discharger must demonstrate compliance with the 

standards in paragraph (b)(15)(A) of this section, as applicable, 

by monitoring for all pollutants (except pH) prior to use of the 

gasification wastewater in any other plant process or commingling 

of the gasification wastewater with any water or other process 

wastewater. Compliance with the standards must reflect results 

obtained from sufficiently sensitive analytical methods. 

(16)(A) The quantity of pollutants discharged in combustion 

residual leachate shall not exceed the quantity determined by 

multiplying the flow of combustion residual leachate times the 

concentration listed in the following table:

Pollutant or pollutant 

property

NSPS

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not exceed 

Arsenic, total (ug/L) 8 6

Mercury, total (ng/L) 242 119

(B) A discharger must demonstrate compliance with the 

standards in paragraph (b)(16)(A) of this section, as applicable, 

by monitoring for all pollutants (except pH) at a point prior to 

use of the combustion residual leachate in any other plant process 

or commingling of the combustion residual leachate with any water 

or other process wastewater, except for any FGD wastewater or any 

other combustion residual leachate. Compliance with the effluent 

limitations must reflect results obtained from sufficiently 

sensitive analytical methods.

(17) At the permitting authority's discretion, the quantity of 

pollutant allowed to be discharged may be expressed as a 

concentration limitation instead of theany mass based 

limitationlimitations specified in paragraphs (b)(3) through 

(b)(10), (b)(13), (b)(15), and (b)(16) of this section. 

Concentration limits shall be based on the concentrations specified 

in this section.

(18) In the event that wastestreams from various sources are 

combined for treatment or discharge, the quantity of each pollutant 

or pollutant property controlled in paragraphs (b)(1) through 

(b)(16) of this section attributable to each controlled waste 

source shall not exceed the specified limitation for that waste 

source.

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

Page 509 of 517

7. Section 423.16 is amended by revising paragraph (c) and 

adding paragraphs (e)-(hi):

* * * * *

(c) TheExcept for those discharges of nonchemical metal 

cleaning waste that are currently authorized without meeting 

standards for copper, the pollutants discharged in nonchemical metal 

cleaning wastes 

shall not exceed the concentration listed in the following table:

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

 PSES pretreatment

 standards

 Pollutant or pollutant property ------------------------

 Maximum for 1 day (mg/l)

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

Copper, total.................................. 1.0

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

* * * * *

(e)(1) For any electric generating unit with a total nameplate 

generating capacity of more than 50 megawatts and that is not an 

oil-fired unit, dischargers must meet the standards in this 

paragraph by a date determined by the control authority that is as 

soon as possible beginning July 1, 2017. These standards apply to 

pollutants in FGD wastewater generated on or after a date 

determined by the control authority that is as soon as possible 

beginning July 1, 2017. Such effluent limitations shall not allow 

the quantity of pollutants in FGD wastewater to exceed the quantity 

determined by multiplying the flow of FGD wastewater times the 

concentration listed in the following table102:

Pollutant or pollutant 

property

PSES

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not exceed 

Arsenic, total (ug/L) 8 6

Mercury, total (ng/L) 242 119

 

102 All proposed revisions to section 423.16(e) reflect proposed Option 4a, Option 

3, and Option 3b (for units located a facilities with a total wet-scrubbed 

capacity of 2,000 MW or more), only. Under proposed Option 3a and Option 3b 

(for units located at facilities with a total wet-scrubbed capacity of less than 

2,000 MW), POTWS would need to develop local limits to address the introduction 

of pollutants found in FGD wastewater by steam electric plants to the POTWs that 

cause pass through or interference, as specified in 40 C.F.R. 403.5(c)(2). 

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Page 510 of 517

Pollutant or pollutant 

property

PSES

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not exceed 

Selenium, total (ug/L) 16 10

Nitrate/nitrite as N (mg/L) 0.17 0.13

(2) A discharger must demonstrate compliance with the 

standards in paragraph (e)(1) of this section, as applicable, by 

monitoring for all pollutants (except pH) at a point prior to use 

of the FGD wastewater in any other plant process or commingling of 

the FGD wastewater with any water or other process wastewater, 

except for any combustion residual leachate or FGD wastewater. 

Compliance with the effluent limitations must reflect results 

obtained from sufficiently sensitive analytical methods. 

(f) For any electric generating unit with a total nameplate 

generating capacity of more than 50 megawatts and that is not an 

oil-fired unit, there shall be no discharge of wastewater 

pollutants from fly ash transport water generated on or after a 

date determined by the control authority that is as soon as 

possible beginning July 1, 2017. Whenever fly ash transport water 

is used in any other plant process or is sent to a treatment system 

at the plant, the resulting effluent must comply with the discharge 

prohibition in this paragraph.

(g) For any electric generating unit with a total nameplate 

generating capacity of more than 50400 megawatts and that is not an 

oil-fired unit, there shall be no discharge of wastewater 

pollutants from bottom ash transport water generated on or after a 

date determined by the control authority that is as soon as 

possible beginning July 1, 2017. Whenever bottom ash transport 

water is used in any other plant process or is sent to a treatment 

system at the plant, the resulting effluent must comply with the 

discharge prohibition in this paragraph.

103

(h) For any electric generating unit with a total nameplate 

generating capacity of more than 50 megawatts and that is not an 

oil-fired unit, there shall be no discharge of wastewater 

pollutants from flue gas mercury control wastewater generated on or 

after a date determined by the control authority that is as soon as 

 

103 TheseAll proposed revisions to section 423.16(g) reflect proposed Option 44a, 

only. For proposed Option 3, Option 3a, and Option 3b, the regulations would 

not specify a PSES for bottom ash transport water.

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

Page 511 of 517

possible beginning July 1, 2017. Whenever flue gas mercury control 

wastewater is used in any other plant process or is sent to a 

treatment system at the plant, the resulting effluent must comply 

with the discharge prohibition in this paragraph.

(i)(1) For any electric generating unit with a total nameplate 

generating capacity of more than 50 megawatts and that is not an 

oil-fired unit, dischargers must meet the standards in this 

paragraph by a date determined by the control authority that is as 

soon as possible beginning July 1, 2017. These standards apply to 

pollutants in gasification wastewater generated on or after a date 

determined by the control authority that is as soon as possible 

beginning July 1, 2017. Such effluent limitations shall not allow 

the quantity of pollutants in gasification wastewater to exceed the 

quantity determined by multiplying the flow of gasification 

wastewater times the concentration listed in the following table:

Pollutant or pollutant property

PSES

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not 

exceed 

Arsenic, total (ug/L) 4 (

1)

Selenium, total (ug/L) 453 227

Mercury, total (ng/L) 1.76 1.29

Selenium, total (ug/L) 453 227

Total dissolved solids (mg/L) 38 22

1 This regulation does not specify this type of limitation for this 

pollutant; however, permitting authorities may do so as appropriate.

(2) A discharger must demonstrate compliance with the 

standards in paragraph (i)(1) of this section, as applicable, by 

monitoring for all pollutants (except pH) at a point prior to use 

of the gasification wastewater in any other plant process or 

commingling of the gasification wastewater with any water or other 

process wastewater. Compliance with the standards must reflect 

results obtained from sufficiently sensitive analytical methods.

(j)(1) For any electric generating unit with a total nameplate 

generating capacity of more than 50 megawatts and that is not an 

oil-fired unit, dischargers must meet the standards in this 

paragraph by a date determined by the control authority that is as 

soon as possible beginning July 1, 2017. These standards apply to 

pollutants in combustion residual leachate generated on or after a 

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

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date determined by the control authority that is as soon as 

possible beginning July 1, 2017. Such effluent limitations shall 

not allow the quantity of pollutants in combustion residual 

leachate to exceed the quantity determined by multiplying the flow 

of combustion residual leachate times the concentration listed in 

the following table:

Pollutant or pollutant 

property

PSES

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not exceed 

Arsenic, total (ug/L) 8 6

Mercury, total (ng/L) 242 119

(2) A discharger must demonstrate compliance with the 

standards in paragraph (j)(1) of this section, as applicable, by 

monitoring for all pollutants (except pH) at a point prior to use 

of the combustion residual leachate in any other plant process or 

commingling of the combustion residual leachate with any water or 

other process wastewater, except for any FGD wastewater or any 

other combustion residual leachate. Compliance with the effluent 

limitations must reflect results obtained from sufficiently 

sensitive analytical methods.104

8. Section 423.17 is amended by revising paragraphs (a) and 

(b) to read as follows:

Section 423.17 Pretreatment standards for new sources (PSNS).

(a) 1982 Pretreatment standards for new sources. Except as 

provided in 40 CFR 403.7, any new source as of November 19, 1982, 

subject to this subpart, which introduces pollutants into a 

publicly owned treatment works must comply with 40 CFR part 403 and 

the following pretreatment standards for new sources (PSNS), and 

the revised requirements of section 423.16 of this part:, published 

on [insert date of publication of final rule]:

(1) There shall be no discharge of polychlorinated biphenyl 

compounds such as those used for transformer fluid.

 

104 These revisions to section 423.16(j) reflect the proposed Option 4, only. 
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Page 513 of 517

(2) The pollutants discharged in chemical metal cleaning 

wastes shall not exceed the concentration listed in the following 

table:

Pollutant or pollutant 

property

PSNS

Maximum for any 1 

day 

Copper, total 1.0

(3) [Reserved--Nonchemical Metal Cleaning Wastes].

(4)(A) The pollutants discharged in cooling tower blowdown 

shall not exceed the concentration listed in the following table:

Pollutant or pollutant property

PSNS

Maximum for any time (mg/l)

The 126 priority pollutants (Appendix A)

contained in chemicals added for cooling 

tower maintenance, except:

(1)

Chromium, total 0.2

zinc, total 1.0

1 No detectable amount.

(B) At the permitting authority's discretion, instead of the 

monitoring in 40 CFR 122.11(b), compliance with the limitations for 

the 126 priority pollutants in paragraph (a)(4)(A) of this section 

may be determined by engineering calculations which demonstrate 

that the regulated pollutants are not detectable in the final 

discharge by the analytical methods in 40 CFR part 136.

(5) There shall be no discharge of wastewater pollutants from 

fly ash transport water. Whenever fly ash transport water is used 

in any other plant process or is sent to a treatment system at the 

plant, the resulting effluent must comply with the discharge 

prohibition in this paragraph.

(b) 2014 Pretreatment standards for new sources. Except as 

provided in 40 CFR 403.7, any new source as of [insert date of 

publication of final rule], subject to this subpart, which 

introduces pollutants into a publicly owned treatment works must 

comply with 40 CFR part 403 and the following pretreatment 

standards for new sources (PSNS):

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

Page 514 of 517

(1) There shall be no discharge of polychlorinated biphenyl 

compounds such as those used for transformer fluid.

(2) The pollutants discharged in chemical metal cleaning 

wastes shall not exceed the concentration listed in the following 

table:

Pollutant or pollutant 

property

PSNS

Maximum for 1 day 

(mg/l)

Copper, total 1.0

(3) The pollutants discharged in nonchemical metal cleaning 

wastes shall not exceed the concentration listed in the following 

table:

Pollutant or pollutant 

property

PSNS

Maximum for 1 day 

(mg/l)

Copper, total 1.0

(4)(A) The pollutants discharged in cooling tower blowdown 

shall not exceed the concentration listed in the following table:

Pollutant or pollutant property

PSNS

Maximum for any time (mg/l)

The 126 priority pollutants (Appendix A)

contained in chemicals added for cooling 

tower maintenance, except:

(

1)

Chromium, total 0.2

zinc, total 1.0

1 No detectable amount.

(B) At the permitting authority's discretion, instead of the 

monitoring in 40 CFR 122.11(b), compliance with the limitations for 

the 126 priority pollutants in paragraph (b)(4)(A) of this section 

may be determined by engineering calculations which demonstrate 

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

Page 515 of 517

that the regulated pollutants are not detectable in the final 

discharge by the analytical methods in 40 CFR part 136.

(5) There shall be no discharge of wastewater pollutants from 

fly ash transport water. Whenever fly ash transport water is used 

in any other plant process or is sent to a treatment system at the 

plant, the resulting effluent must comply with the discharge 

prohibition in this paragraph.

(6)(A) The quantity of pollutants discharged in FGD wastewater 

shall not exceed the quantity determined by multiplying the flow of 

FGD wastewater times the concentration listed in the following 

table:

Pollutant or pollutant 

property

PSNS

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not exceed 

Arsenic, total (ug/L) 8 6

Mercury, total (ng/L) 242 119

Selenium, total (ug/L) 16 10

Nitrate/nitrite as N (mg/L) 0.17 0.13

(B) A discharger must demonstrate compliance with the 

standards in paragraph (b)(6)(A) of this section, as applicable, by 

monitoring for all pollutants (except pH) at a point prior to use 

of the FGD wastewater in any other plant process or commingling of 

the FGD wastewater with any water or other process wastewater, 

except for any combustion residual leachate or any other FGD 

wastewater. Compliance with the standards must reflect results 

obtained from sufficiently sensitive analytical methods. 

(7) There shall be no discharge of wastewater pollutants from 

flue gas mercury control wastewater. Whenever flue gas mercury 

control wastewater is used in any other plant process or is sent to 

a treatment system at the plant, the resulting effluent must comply 

with the discharge prohibition in this paragraph.

(8) There shall be no discharge of wastewater pollutants from 

bottom ash transport water. Whenever bottom ash transport water is 

used in any other plant process or is sent to a treatment system at 

the plant, the resulting effluent must comply with the discharge 

prohibition in this paragraph.

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

Page 516 of 517

(9)(A) The quantity of pollutants discharged in gasification 

wastewater shall not exceed the quantity determined by multiplying 

the flow of gasification wastewater times the concentration listed 

in the following table:

Pollutant or pollutant property

PSNS

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not 

exceed 

Arsenic, total (ug/L) 4 (

1)

Selenium, total (ug/L) 453 227

Mercury, total (ng/L) 1.76 1.29

Selenium, total (ug/L) 453 227

Total dissolved solids (mg/L) 38 22

(

1) This regulation does not specify this type of limitation for this 

pollutant; however, permitting authorities may do so as appropriate.

(B) A discharger must demonstrate compliance with the 

standards in paragraph (b)(9)(A) of this section, as applicable, by 

monitoring for all pollutants (except pH) at a point prior to use 

of the gasification wastewater in any other plant process or 

commingling of the gasification wastewater with any water or other 

process wastewater. Compliance with the standards must reflect 

results obtained from sufficiently sensitive analytical methods.

(10)(A) The quantity of pollutants discharged in combustion 

residual leachate shall not exceed the quantity determined by 

multiplying the flow of combustion residual leachate times the 

concentration listed in the following table:

Pollutant or pollutant 

property

PSNS

Maximum 

for any 

1 day 

Average of daily values for 30 

consecutive days shall not exceed 

Arsenic, total (ug/L) 8 6

Mercury, total (ng/L) 242 119

(B) A discharger must demonstrate compliance with the 

standards in paragraph (b)(10)(A) of this section, as applicable, 

by monitoring for all pollutants (except pH) at a point prior to 

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

Page 517 of 517

use of the combustion residual leachate in any other plant process 

or commingling of the combustion residual leachate with any water 

or other process wastewater, except for any FGD wastewater or any 

other combustion residual leachate. Compliance with the effluent 

limitations must reflect results obtained from sufficiently 

sensitive analytical methods.

* * * * *

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