Vol. 78 Friday, 

No. 110 June 7, 2013 

Part II 

Environmental Protection Agency 

40 CFR Part 423 

Effluent Limitations Guidelines and Standards for the Steam Electric Power 

Generating Point Source Category; Proposed Rule 


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34432 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 423 

[EPA–HQ–OW–2009–0819. FRL–9801–6; 

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 technologybased effluent limitations guidelines 

and standards for the steam electric 

power generating point source category. 

Steam electric power plants alone 

contribute 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. This proposal, if 

implemented, would reduce the amount 

of toxic metals and other pollutants 

discharged to surface waters from power 

plants. EPA is considering several 

regulatory options in this rulemaking 

and has identified four preferred 

alternatives for regulation of discharges 

from existing sources. These four 

preferred alternatives differ with respect 

to the scope of requirements that would 

be applicable to existing discharges of 

pollutants found in two wastestreams 

generated at power plants. EPA 

estimates that the preferred options for 

this proposed rule would annually 

reduce pollutant discharges by 0.47 

billion to 2.62 billion pounds, reduce 

water use by 50 billion to 103 billion 

gallons, cost $185 million to $954 

million, and would be economically 

achievable. 

DATES: Comments on this proposed rule 

must be received on or before August 6, 

2013. EPA will conduct a public hearing 

on the proposed pretreatment standards 

on July 9, 2013 at 1:00 p.m. in the EPA 

East Building, Room 1153, 1201 

Constitution Avenue NW., Washington, 

DC. 

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–HQ–OW– 

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–HQ– 

RCRA–2013–0209. In contrast to EPA’s 

electronic public docket, EPA’s email 

system is not an ‘‘anonymous access’’ 

system. If you send an email comment 

directly to the Docket without going 

through EPA’s electronic public docket, 

EPA’s email system automatically 

captures your email address. Email 

addresses that are automatically 

captured by EPA’s email 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 

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–OW–2009–0819. 

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 Web 

site 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 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 Web site 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 


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legal holidays. The telephone number 

for the Public Reading Room is 202– 

566–1744, and the telephone number for 

the Water Docket is 202–566–2426. 

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: 

EPA will conduct a public hearing on 

the proposed pretreatment standards on 

July 9, 2013 at 1:00 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 

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 

technical information, contact Jezebele 

Alicea-Virella, Engineering and 

Analysis Division, Telephone: 202–566– 

1755; Email: alicea.jezebele@epa.gov. 

For economic information, contact 

James Covington, Engineering and 

Analysis Division, Telephone: 202–566– 

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

SUPPLEMENTARY INFORMATION: 

Regulated Entities 

Category Example of regulated entity 

North American 

industry classification system 

(NAICS) code 

Industry .......................................... Electric Power Generation Facilities—Electric Power Generation .................................. 22111 

Electric Power Generation Facilities—Fossil Fuel Electric Power Generation ............... 221112 

Electric Power Generation Facilities—Nuclear Electric Power Generation .................... 221113 

This section is not intended to be 

exhaustive, but rather provides a guide 

for readers regarding entities likely 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 hardcopy form. EPA also will accept 

comments and data on disks in the 

aforementioned file formats. Electronic 

comments received on this notice may 

be 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–13–002. 

• 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–13–003. 

• Benefits and Cost Analysis for the 

Proposed Effluent Limitations 

Guidelines and Standards for the Steam 

Electric Power Generating Point Source 

Category, Document No. EPA–821–R– 

13–004. 

• 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–13–005. 

These documents are available in the 

public record for this rule and on EPA’s 

Web site 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 

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 


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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 

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 

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 PlantSpecific Costs 

B. Methodology for Estimating PlantSpecific 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 

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 

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 This 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 


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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 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 reduce the amount 

of metals and other pollutants 

discharged to surface waters from power 

plants. 

EPA is considering several options in 

this rulemaking and has identified four 

preferred alternatives for regulation of 

discharges from existing sources. These 

four 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 discharges 

associated with two wastestreams from 

existing sources. EPA also projects 

different levels of pollutant reduction 

and cost associated with these 

alternatives. 

EPA estimates that the preferred 

regulatory options would reduce 

pollutant discharges by 0.47 billion to 

2.62 billion pounds annually, and 

reduce water use by 50 billion to 103 

billion gallons per year. EPA predicts 

substantial environmental and 

ecological improvements would result 

under the preferred 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 in volume and total mass, 

and currently account for approximately 

50–60 percent of 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). As 

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 source of 

widespread aquatic-life impacts, and a 

source of increased cancer and noncancer risks in humans, and 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. 

This proposed rule would reduce 

current toxic and other pollutant 

discharges and their associated impacts. 

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 (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, nonchemical 

metal cleaning wastes, and wastewater 

from flue gas mercury control (FGMC) 

systems and gasification systems. 

EPA has 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 

four preferred alternatives are 

summarized below. 

Discharges directly to surface water 

from existing facilities—For existing 

sources that discharge directly to 

surface water, with the exception of oilfired generating units and small 

generating units (i.e., 50 MW or 

smaller), under one preferred alternative 

for BAT (referred to as Option 3a in this 

proposal) the proposed rule would 

establish BAT for wastestreams from 

these sources that include: 


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34436 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

1As 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. 

2Total plant-level wet scrubbed capacity is 

calculated by summing the nameplate capacity for 

all of the units that are serviced by wet FGD 

systems. 

3As 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. 

4As 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. 

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. 

• ‘‘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 wastes; 1 and 

• Effluent limits for bottom ash 

transport water and combustion residual 

leachate from landfills and surface 

impoundments 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 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 nitratenitrite in discharges of FGD wastewater 

from certain steam electric facilities 

(those with a total plant-level wet 

scrubbed capacity of 2,000 MW or 

greater 2). 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 numeric effluent limits for 

mercury, arsenic, selenium, and nitratenitrite 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, with the exception of 

all generating units with a nameplate 

capacity of 400 MW or less (for those 

generating units that are less than or 

equal to 400 MW, the proposed rule 

would set BAT equal to BPT for 

discharges of pollutants found in the 

bottom ash transport water). All other 

proposed Option 4a 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 smaller 3) that are existing 

sources and discharge directly to surface 

waters, under the four preferred 

alternatives for regulation of existing 

sources, the proposed rule would 

establish effluent limits (BAT) equal to 

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: 

• Numeric standards for discharges of 

nonchemical metal cleaning wastes 

would be established only for copper; 4

• Under Options 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 

for generating units with a nameplate 

capacity of 400 MW or less; 5 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 oilfired generating and small 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; 

• 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, 

oil and grease, or iron in discharges of 

nonchemical metal cleaning wastes. 

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 benefits 6

and social costs for the four 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 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 associated 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. 

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 


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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 ............................ a 139.4 a 104.8 $185.2 $164.5 

Option 3b for Existing Sources; Option 4 for New Sources ............................ a 205.5 a 153.0 281.4 257.2 

Option 3 for Existing Sources; Option 4 for New Sources .............................. $311.7 $230.4 572.0 545.3 

Option 4a for Existing Sources; Option 4 for New Sources ............................ a 482.5 a 424.8 954.1 914.7 

aEPA 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. 

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, 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 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., ammoniaN, 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 plants and 

processes, and other improvements in 

technology, taking into account the cost 

of controls. Congress has also stated that 

EPA need not consider water quality 

impacts on individual water bodies as 

the guidelines are developed; see 

Statement of Senator Muskie (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 

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 


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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). 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 

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). 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 with the 

operation of POTWs. Categorical 

pretreatment standards are technologybased 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 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 non-thermal 

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 


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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. 

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 oncethrough 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 

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 the 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, 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 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., closed-loop) 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, 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 are a 

number of pollutants present in 

wastewaters generated at coal-fired 

power plants that can impact the 

environment, including metals (e.g., 


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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 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. 

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 hazardous air 

pollutants including metals (e.g., 

mercury, arsenic, chromium, nickel) 

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

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) 

EPA promulgated the CSAPR in 2011 

to require 28 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. The emissions 

of sulfur dioxide, NOX and ozoneseason NOX addressed by the CSAPR 

react in the atmosphere to form PM2.5

and ground-level 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 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 

On 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 outputbased 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-fuelfired 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 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 that 

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 

the water it withdraws for cooling 

purposes. See 40 CFR 125.81. EPA’s 

requirements 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. 


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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 sitespecific 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 

that could be attained by using a closedcycle 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. 

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 this notice for purposes of 

better understanding the analyses 

underlying this proposed revisions to 

the steam electric generating ELGs. This 

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. 

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 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, 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 


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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 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 water bodies that 

exist between a disposal unit and a 

down-gradient 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 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 

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 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 this 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 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. 


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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 

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. 

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 eight 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–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 

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. 

Because much of the focus of this 

proposed rule is on the FGD and ash 

wastewaters, which are primarily 

generated at coal- and petroleum cokefired 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 


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number of coal- and petroleum cokefired power plants. EPA mailed Version 

2 of the questionnaire to the remaining 

407 coal- and 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. 

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 the 

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 68 site visits to power 

plants in 22 states and Italy between 

December 2006 and February 2013 to 

collect information about plant 

operations, process wastewater 

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 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 (i.e., the Agency collected the 

samples) at 13 of the 17 power plants. 

Using its authority under CWA section 

308, EPA directed seven of these EPAsampled plants and four additional 

plants not sampled by EPA to collect 

additional samples, which were sent to 

EPA-contracted laboratories for analysis 

(i.e., CWA 308 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 directed 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 oneor 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 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 pilotscale 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: 

• For seven 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; and 


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7EIA–860: Annual Electric Generator Report; 

EIA–861: Annual Electric Power Industry Database; 

EIA–923: Utility, Non-Utility, and Combined Heat 

& Power Plant Database (monthly). 

• 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 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; 

• 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 selfmonitoring 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 coalfired 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 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 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 Department of Energy’s EIA 

(in particular, the EIA 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). 

V. Scope/Applicability of the Proposed 

Rule 

A. Facilities Subject to 40 CFR Part 423 

This 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 


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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 

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 and would 

not alter which generating units are 

regulated by the ELGs nor 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 long-standing 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 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 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 age of equipment and facilities 

involved, the process employed, the 

engineering aspects of the application of 

various types of control techniques, 

process changes, the cost of achieving 

such effluent reduction, non-water 

quality environmental impact 

(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 they 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 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 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 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. 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 


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8As 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. 

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. 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 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 ash transport water 

generally increase. In general, this is to 

be expected because the larger the 

generating unit, the more fuel it 

consumes, which 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 

generating units or plants based on size. 

Section VIII of this preamble discusses 

in greater detail EPA’s proposal for 

applying different standards to certain 

existing 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 petroleumcoke 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, 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 gas-fired 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 oilfired units. As a result, EPA believes 

that, in certain circumstances, it is 

appropriate to apply different limits to 

existing oil-fired generating units. 

Section VIII of this preamble discusses 

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 nuclear-fueled 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 

Petroleum Coke ........................................................................................................................................... 12 1,000 

Oil ................................................................................................................................................................. 75–100 23,900–25,400 

Gas .............................................................................................................................................................. 929 282,000 

Nuclear ......................................................................................................................................................... 99 104,000 


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TABLE VI–1—ESTIMATED NUMBER OF STEAM ELECTRIC GENERATING UNITS AND CAPACITY BY PRIMARY FUEL SOURCE— 

Continued 

Primary fuel source Number of 

Generating units 

Nameplate 

capacity 

(MW) 

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 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 cokefired 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 hightemperature, high-pressure steam leaves 

the boiler and enters the turbine 

generator where it drives the turbine 

blades as it moves from the highpressure 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 

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 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 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 


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Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 34449 

9Because 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. 10This 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. 

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 after the fly ash 

has settled. Of the coal- and petroleum 

coke-fired 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 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 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 bins. The ash sent to a 

dewatering bin is separated from the 

transport water and then disposed. For 

both of these systems, the water used to 

transport the bottom ash to the 

impoundment or dewatering bins is 

usually discharged to surface water as 

overflow from the systems, after the 

bottom ash has settled. 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 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 

steam electric industry discharged a 

total of 157 billion gallons of bottom ash 

transport water in 2009. 

Power plants that generate fly ash and 

bottom ash can either dispose of it in 

landfills or surface impoundments, or 

can use it in applications such as 

cement or concrete manufacturing. 

Power plants have used the ash in many 

applications that preclude the need to 

dispose of the ash in landfills/ 

impoundments. 

2. FGD Systems 

FGD systems 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 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. The 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 coalfired 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 

steam electric industry discharged a 

total of 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 generate 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 


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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 mercurycontaining carbon (i.e., FGMC waste) is 

collected and handled the same way as 

the fly ash. Therefore, if the fly ash is 

wet sluiced, then the FGMC wastes are 

also wet sluiced and likely sent to the 

same surface impoundment. In this 

case, adding the FGMC 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 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 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 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 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 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 scheduled to begin operation this 

year. A fourth IGCC power 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 


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11 In order to protect CBI claims, EPA cannot 

provide specific numbers. 

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 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. 

The following types of metal cleaning 

wastes were reported in responses to the 

industry survey: 

• 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 catalyst 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 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, 

pre-combustion, 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 the pilotscale 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 

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 tank-based 

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 


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12A 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. 

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. 

• 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, 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 

are 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 vaporcompression evaporation. A third U.S. 

plant is currently installing a vaporcompression evaporation treatment 

system; it is scheduled to be operational 

by the end of 2013. 

• 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 

electro-coagulation. 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 fullscale 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 

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 


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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 

water-powered 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. 

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 water-powered 

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). 

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 

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 coalfired 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. One U.S. 

plant 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, 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 


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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); 

• 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 as 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. 

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, 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, and a third plant is 

scheduled 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 

scheduled to begin operating this year is 

installing both a vapor-compression 

evaporation system 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 

mercury-containing carbon in hoppers 

located underneath the equipment. 

From the collection hoppers, plants 

either transfer the mercury-containing 

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 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 that are available for fly 

ash. These technologies include: 

• Wet Vacuum Pneumatic System: 

These systems use water-powered 

hydraulic vacuums to withdraw dry 

FGMC waste from the hoppers, similar 

to wet sluicing systems. Instead of 


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13This 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. 

14EPA 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. 

15EPA 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. 

16The 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 

Continued 

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 into 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 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. 

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, industrysupplied 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. 

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 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 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 


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grease is also a pollutant of concern in combustion 

residual leachate. 

17The 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. 

(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 include: 17 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 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 

PSNS 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). 

See 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 

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 six pollutants for 

potential regulation for FGD wastewater: 

oil and grease, TSS, arsenic, mercury, 

nitrate/nitrite, and selenium. For 

leachate, EPA identified four potential 

pollutants for regulation: oil and grease, 

TSS, arsenic and mercury. 

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 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. 

See Section 6.7 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 

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 through POTWs, 

EPA generally compares the percentage 

of a pollutant removed by well-operated 

POTWs performing secondary treatment 


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18For 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. 

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 passthrough 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 this 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 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. 

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 it was appropriate to 

establish pretreatment standards for the 

discharge of copper in chemical metal 

cleaning wastes. For this rulemaking, 

EPA believes that, as is the case for 

copper in chemical metal cleaning 

wastes, 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 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. 

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 this 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 part 423 to add paragraphs 

that list these four wastestreams by 

name, along with their applicable 

effluent 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, 

nonchemical metal cleaning wastes, and 

wastewater from FGMC systems and 

gasification systems. In Section 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 this 

proposal, EPA is presenting eight 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 

pollutant removal associated with 

different wastewater streams (i.e., each 

succeeding option from Option 1 to 

Option 5 would achieve more reduction 

in discharges of pollutants to waters of 

the U.S). Table VIII–1 summarizes the 

eight 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. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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19As 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. 

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 paragraph 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 

would not apply until July 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 nonadjoining 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. 

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 4a 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.Evaporation ..... Evaporation ..... Evaporation ..... Evaporation ..... Evaporation ..... Evaporation ..... Evaporation ..... Evaporation 

Nonchemical Metal 

Cleaning 

Wastes 19.

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 

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 


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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 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 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 denser, 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 exist and that 

are more effective at removing both 

soluble (i.e., dissolved) and particulate 

forms of metals, as well as other 

pollutants such as nitrogen compounds 

and TDS. Because many of the 

pollutants of concern for 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 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 NSPS presented 

in this proposal 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 corrosionresistant 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 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34460 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

20This value is calculated by summing the 

nameplate capacity for all of the units that are 

serviced by wet FGD systems. 

21A 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. 

22A third U.S. plant is currently installing a 

vapor-compression evaporation system to treat the 

FGD wastewater. 

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. 

The technology basis for the effluent 

limitations and standards for FGD 

wastewater in Options 2, 3b (for units 

located at facilities with a total wetscrubbed capacity of 2,000 MW or 

more) 20, 3, 4a, and 4 is chemical 

precipitation/coprecipitation (the same 

technology basis under 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 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 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 show the efficacy 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 recalcitrant 

pollutants, as well as removing the 

pollutants treated by physical/chemical 

and biological technologies, is vaporcompression 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. 

Two 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 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 CFR 403.5(c)(2). 

As described below in this section of 

the preamble, EPA is proposing that 

certain limitations 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, 


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Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 34461 

2017. EPA considered subjecting legacy 

FGD wastewater to the proposed BAT 

and PSES requirements. 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 setting the BAT 

effluent limitations for legacy FGD 

wastewater that has not been mixed 

with non-legacy 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 

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 welloperated can effectively remove 

suspended solids, including pollutants 

such as particulate forms of certain 

metals when associated with the 

suspended solids. 

Under 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 Section 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 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 comanaging 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, approximately 66 

percent of coal- and petroleum cokefired 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. 

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 costs associated 

with treatment using chemical 

precipitation were higher 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 

higher than the cost for converting to 

dry handling technologies, and 

chemical precipitation removes fewer 

pollutants, EPA did not include 

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 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 

that is as soon as 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 beginning 

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 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 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, 


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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 welldesigned 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 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 4a (for 

units more than 400 MW), 4, and 5 

would completely eliminate the 

discharge of pollutants in bottom ash 

transport water. 

Under 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 cokefired 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 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 

considered as one available technology 

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 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 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 higher than the cost for 

converting to dry handling or closed 

loop technologies, and the treatment 

technology removes fewer pollutants, 

EPA did not include 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 for existing 

sources 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 permitting authority 

or control authority that is as soon as 

possible 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 

eliminate the generation of the bottom 

ash wastewater but do 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 4a (for units more than 

400 MW), 4, and 5 have not been 

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 4a (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. 

Combustion Residual Leachate. Under 

Options 1, 3a, 2, 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 


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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, 

3a, 2, 3b, 3, and 4a, 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 same 

technology 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 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 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). 

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, 3b 

(for units at facilities with a total wetscrubbed 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. 

If EPA did 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 that is as soon as possible 

within the next permit cycle after 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 beginning 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 would not expect 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 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. Under 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 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 Section 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 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 mercuryVerDate Mar<15>2010 17:43 Jun 06, 2013 Jkt 229001 PO 00000 Frm 00033 Fmt 4701 Sfmt 4702 E:\FR\FM\07JNP2.SGM 07JNP2

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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. 

Under 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. 

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 zero discharge limitation were to 

apply, the proposed BAT limitations 

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 

that 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 

beginning July 1, 2017. As proposed 

today, legacy FGMC wastewater 

generated by 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 

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 for gasification wastewater is 

vapor-compression evaporation. Two 

operating IGCC plants in the U.S. 

currently use this technology, and a 

third IGCC plant that is scheduled 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 

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 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 

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 


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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 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 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 

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

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. 

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 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. 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 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 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34466 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

23For 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.’’ 

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, 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, several options (including 

Option 3a) considered in this 

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 anti-circumvention 

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. 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 EPAapproved 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 

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 level 23 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 EPA-approved 

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 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) 

implements 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. This 

action provides notification that EPA is 

considering establishing BMP 

requirements to address impoundment 

construction, operation, and 

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 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 


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24On 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. 

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 

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 

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 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 options 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 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.’’ EPA 

intends that, for any BAT option 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 continue 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 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 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 nonadjoining 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34468 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

25As 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. 

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 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 currently 

discharge no process wastewater. In 

addition, two of the plants that EPA 

visited in Italy previously discharged 

process wastewater, but have 

implemented wastewater treatment and 

process changes, including wastewater 

recycle, that now allow them to operate 

without discharging any process 

wastewater except for their 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 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 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 nonwater 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). 

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 putting forth four preferred 

alternatives for BAT. These four 

preferred alternatives primarily differ in 

that some would establish more 

environmentally protective BAT 

requirements for discharges from two of 

the wastestreams from existing sources. 

Under the first preferred alternative, 

EPA is proposing to establish BAT 

effluent limits based on the technologies 

specified in Option 3a. 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 and iron in discharges of 

nonchemical metal cleaning wastes 25; 

• Establish BAT effluent limits for 

bottom ash transport water and 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 34469 

26Total plant-level wet-scrubbed capacity is 

calculated by summing the nameplate capacity for 

all of the units that are serviced by wet FGD 

systems. 

27For units below the 2,000 MW threshold, BAT 

would continue to be determined on a site-specific 

basis. 

28As 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. 

29As 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. 

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. 

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 oil-fired 

generating units and small generating 

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

proposed rule under Option 3b would: 

• Establish numeric effluent limits for 

mercury, arsenic, selenium, and nitratenitrite in discharges of FGD wastewater 

for units located at plants with a total 

wet-scrubbed capacity of 2,000 MW or 

more 26 27; 

• 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 wastes 28; 

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 third preferred alternative 

for BAT, 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 

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 

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 

all 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 wastes,29 and for TSS 

and oil and grease for five of the six 

wastestreams listed above (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 4a as 

the preferred BAT regulatory options 

because its analysis to this date suggests 

that they are all technologically 

available, economically achievable, and 

have acceptable non-water quality 

environmental impacts. However, EPA 

is putting forth a range of options as 

candidates for BAT in order to enhance 

the Agency’s understanding of the pros 

and cons of each 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 Sections VI 

and VIII.A.2, the 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 4a are well-demonstrated and 

have been employed at a subset of 

existing power plants. 

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 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 wet-sluicing 

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 coke-fired 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 coaland 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 coalfired 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 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 wetscrubbed power plants that discharge 

FGD wastewater already have the 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34470 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

30Four of the six operate the biological treatment 

systems in combination with chemical 

precipitation. 

31Physical/chemical treatment systems can be 

effective at removing mercury and certain other 

metals; however, to achieve effective removal of 

selenium this technology must be coupled with 

additional treatment technology such as anoxic/ 

anaerobic biological treatment. 

Options 3b (for units located at plants 

with a total wet-scrubbed capacity of 

2,000 MW or more), 3 and 4a BAT 

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 fixed-film anoxic/ 

anaerobic biological treatment systems 

to treat FGD wastewater and another 

operates a suspended growth biological 

treatment system that targets removal of 

selenium.30 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 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).31

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 wetscrubbed 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 wetscrubbed 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 BAT effluent limitations for 

discharges of FGD wastewater would 

continue to be determined on a sitespecific 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 coaland 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 

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 

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 


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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 all four 

preferred options for gasification 

wastewater. A third IGCC plant that will 

soon begin commercial operation will 

also use the technology and, in addition 

to that, will also operate a cyanide 

destruction step as part of the treatment 

system. 

For 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. These 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 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 

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 

discharges, EPA is proposing to set BAT 

limitations equal to BPT limitations for 

low volume waste. 

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 

these 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 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 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 to 

comply with the proposed BAT 

nonchemical metal cleaning waste 

limitations for iron and copper. EPA is 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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32Commenters 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). 

33 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. 

34As 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. 

35 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. 

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; 32

• 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) for Option 3 and 

Option 4.33 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 showed 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). 

The results for Option 4 show 

fourteen unit (partial) closures and zero 

plant (full) closures projected as of the 

model year 2030, reflecting full 

compliance of all facilities.34 35 The 14 

generating units are located at six 

plants. The IPM results also show that 

five steam electric units that are 

projected to close under the base case 

(i.e., in the absence of the proposed 

revisions to the ELG) would remain 

operating under 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 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 

Section XVI, EPA is proposing that, 

where the limitations and standards 

being proposed today for existing direct 

and indirect dischargers are 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 4a have 

acceptable non-water quality 

environmental impacts, as discussed in 

Section XV of the preamble and in the 

TDD. EPA estimates that Options 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. EPA also 

estimates that Options 3a, 3b, 3, and 4a 

would increase the amount of fuel 

consumed by increased operation of 

motor vehicles (e.g., for transporting fly 

ash) 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. 

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). For Options 3a, 3b, and 3, the 

NOX emissions are estimated to increase 

by no more than 0.12 percent, and for 

Option 4a, by no more than 0.13 

percent. EPA projects no significant 

increase in emissions of SOX or CO2

under the four preferred options. 

EPA also evaluated the effect of the 

proposed rule on solid waste generation 

and 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 the other three preferred options. 

EPA estimates the power plants would 

reduce water use by 50 billion gallons 

per year (136 million gallons per day) 

under Option 3a, 52 billion gallons per 

year (143 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 4a. 

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. If 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 no more than 

$0.04, $0.06, $0.13, and $0.22, 

respectively under Options 3a, 3b, 3, 

and 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 would allow plants to continue 


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36For 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. 

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 coke-fired 

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 cokefired 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 

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. Options 1 and 2 

would remove fewer or similar levels of 

pollutants to the preferred options, all of 

which EPA believes, 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 

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 

effluent limits for units less than or 

equal to 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 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 

($2.3 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 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 sitespecific 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 

Section VIII.B., EPA is proposing that, 

where the limitations and standards 

being proposed today are 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 eight 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 less) that differ 

from the effluent limits for all other 

generating units.36 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34474 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

37As 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. 

38While 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. 

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 wastes 37, 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 costeffectiveness 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 

$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 costeffectiveness of particular controls for 

the wastestreams that would be 

controlled under the preferred options 

for existing direct dischargers.38 The 

cost-effectiveness 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 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 oil-fired units. For the purpose 

of the proposed BAT effluent limits, oilfired 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 oilfired 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 oilfired 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 tonnage to the 

amount of power generated, with coalfired 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 4a 

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. Based 

on responses to the industry survey, 

only 20 percent of oil-fired 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 

percent. Eighty percent of the cycling/ 

intermediate units and all peaking units 

also report capacity utilization less than 

25 percent. Thirty-five percent of oilfired 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 oil-fired 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 oilfired generating units add substantially 

to electric grid reliability and the 

nation’s energy security. 

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 oilfired units operate infrequently, which 

could contribute to the relatively low 

numbers of units discharging ashrelated 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 nonwater 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 


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39Preferred Option 4a would increase this 

threshold for purposes of discharges of pollutants 

in bottom ash transport water only, to 400 MW or 

less. 

40For 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. 

41As discussed in Section XVII.C, the proposed 

50 MW threshold also alleviates potential impacts 

which may be borne by small entities or 

municipalities. 

42Four of the six 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. 

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 less.39 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-level annualized 

cost for the proposed FGD wastewater 

treatment technology under Option 3 

(chemical precipitation plus biological 

treatment) is approximately seven times 

more expensive on a dollar-permegawatt basis for small generating 

units, relative to units larger than 50 

MW. Similarly, the unit-level 

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 dollarper-megawatt basis for small generating 

units, relative to units larger than 50 

MW. 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 (e.g., 

less than 1 percent under Option 3). 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 

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 MW40 rather than 25 MW because 

the proposed 50 MW threshold would 

do more to alleviate potential impacts.41

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. 

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 nitratenitrite in discharges of FGD wastewater; 

• 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.42 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 (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 


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43As a point of clarification, this similarly holds 

true for bottom ash limitations. 44This rationale similarly applies to Option 3a. 

manages the FGMC wastewater so that 

it is not discharged to surface waters (or 

has the capability to do so). For 

leachate, as discussed above in Section 

VI, chemical precipitation is a welldemonstrated 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 ‘‘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. The cost to 

install technologies at new units are 

typically less than the cost to retrofit 

existing units. 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 

4a for BAT would cause those plants 

with 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, 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 wetsluicing system. EPA estimates that over 

the past 20 years, more than 50 new 

coal-fired 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 coal-fired 

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 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 nonwater 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 nonwater 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 oilfired generating units and small 

generating units 43 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) 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. EPA 

requests comment on its proposal to 

establish the same NSPS for small 

generating units as for larger units. 

EPA is not proposing 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 represents 

the greatest degree of effluent reduction 

which the Administrator determines to 

be achievable through the best available 

demonstrated control technology. 

EPA also did not select any of the 

preferred BAT regulatory Options (i.e., 

Options 3a, 3b, 3, or 4a) as its preferred 

option for NSPS because they would not 

control FGD 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. EPA did 

not select preferred Option 3a 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 BAT effluent 

limits on TSS and oil and grease, which 

are based on using surface 

impoundments.44 The record 

demonstrates that zero discharge 

technologies are effective and available 

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 Best 

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 demonstrates that chemical 

precipitation is a more effective 

technology than surface impoundments 

for controlling the pollutants present in 

leachate. For these reasons, Options 3b, 

3 and 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 


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45As 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. 

46Under 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 CFR 403.5(c)(2). 

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 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 site-specific 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. 

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 .............................................................

Mercury ............................................................

Yes. 

Yes. 

Biological (chemical precipitation followed by anoxic/anaerobic biological) for 

FGD Wastewater and/or Leachate.

Arsenic .............................................................

Mercury ............................................................

Nitrate Nitrite as N ...........................................

Yes. 

Yes. 

Yes. 

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

Mechanical Vapor-Compression Evaporation for FGD Wastewater ................. Arsenic .............................................................

Mercury ............................................................

Yes. 

Yes. 

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

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

Mechanical Vapor-Compression Evaporation for IGCC Wastewater ................ Arsenic .............................................................

Mercury ............................................................

Yes. 

Yes. 

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

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

Nonchemical Metal Cleaning Wastes ................................................................ Copper ............................................................. Yes. 

For this 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 basis is the same as the BAT 

technology basis. This 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 four 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 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 wastes; 45 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). 

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 wetscrubbed capacity of 2,000 MW; 46

• Establish a ‘‘zero discharge’’ 

standard for all pollutants in fly ash 

transport water and FGMC wastewater; 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34478 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

47As 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. 

48EPA 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. 

49Preferred Option 4a would increase this 

threshold for purposes of discharges of pollutants 

in bottom ash transport water only, to 400 MW or 

less. 

50For the same reasons discussed above in 

Section VIII for NSPS, EPA similarly determined 

the other regulatory options do not reflect PSNS. 

51EPA 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 

• Establish standards for copper in 

discharges of nonchemical metal 

cleaning wastes; 47 and 

• Establish standards for mercury, 

arsenic, selenium and TDS in discharges 

of gasification wastewater. 

Under the third preferred alternative 

for PSES (Option 3), 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). 

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 for units 

greater than 400 MW. All other 

proposed Option 4a requirements are 

identical to the proposed Option 3 

requirements. 

EPA is putting forth Options 3a, 3b, 

3, and 4a as the Agency’s preferred 

PSES regulatory options in order to 

confirm its understanding of the pros 

and cons of these 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’s 

analysis to date suggests that for indirect 

dischargers as well as direct dischargers, 

the Option 3a, Option 3b, Option 3, and 

Option 4a 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 passthrough 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 Section 

XV. 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 wastes,48

EPA is proposing not to subject 

discharges from oil-fired generating 

units and small generating units (i.e., 50 

MW or smaller 49) to POTWs to 

requirements based on Options 3a, 3b, 

3, or Option 4a. 

Finally, similar to EPA’s preferred 

BAT options and for the reasons 

supporting those 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, 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 this 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; 

• Maintain 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. 

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.50 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 nonwater 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 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 

2020 51 and the associated costs of 


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to comply with existing federal and state 

requirements. 

52EPA IPM v.4.10 projections for units based on 

compliance with CSAPR, MATS, state rules, and 

enforcement actions including consent decrees. 

complying with these 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 projections of 

future air control installations: 1) 

Integrated Planning Model estimates for 

the final MATS rule; 52 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 using IPM (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 projections or the survey 

projections are more accurate than the 

other. In fact, both of these sources may 

overstate actual installations. Prior to 

MATS becoming 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 conditions. 

As a first step in conducting a 

sensitivity analysis, EPA compared the 

projections from the two sources 

described above. This comparison 

demonstrates that the IPM results 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 project similar wetscrubbed 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 

projects 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 

estimate 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 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 wetscrubbed 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 

this 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 this 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. 

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. 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 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 eight 

main regulatory options, including the 

preferred options, Option 3a, Option 3b, 

Option 3, or Option 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 


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53EPA did estimate costs for these existing oilfired 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). 

54Because 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 uncertain and subject to 

change; thus, EPA has considered such future 

changes, as appropriate, in sensitivity analyses for 

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. 

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 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 this 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 by the date 

determined by the control authority that 

is as 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 quickly cease operation of the wet 

system, complying with a zero discharge 

requirement with relative ease. 

EPA envisions that each facility 

subject to this 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 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 this 

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 

plant-specific 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 

this 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 this proposal 

on all plants currently subject to the 

existing ELGs. Some aspects of this 

proposal (e.g., applicability changes) 

would likely not lead to increased costs 

to complying facilities. Other aspects of 

this 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 this 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.53

For the aspects of these proposed 

regulatory options that include 

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.54 55 Therefore, 


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55EPA 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. 

EPA’s plant-specific cost and pollutant 

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 (onetime 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 (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 PlantSpecific Costs 

The limitations and standards 

associated with the regulatory options 

for this 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 selfmonitoring 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 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. 

TABLE IX–1—TECHNOLOGY COST MODULES USED TO ESTIMATE COMPLIANCE COSTS

Wastestream Technology cost modules 

Regulatory option 

1 3a 2 3b 3 4a 4 5 

FGD Wastewater .............................. Chemical Precipitation ...................... X .......... X X X X X X 

Biological Treatment ......................... .......... .......... X X X X X 

Vapor-Compression Evaporation ..... .......... .......... .......... .......... .......... .......... .......... X 

Fly Ash Transport Water .................. Dry Fly Ash Handling ....................... .......... X .......... X X X X X 

Bottom Ash Transport Water ............ Dry Bottom Ash Handling ................. .......... .......... .......... .......... .......... X X X 

Leachate ........................................... Chemical Precipitation ...................... .......... .......... .......... .......... .......... .......... X X 

Gasification Wastewater ................... Vapor-Compression Evaporation ..... X X X X X X X X 

Flue Gas Mercury Control Wastes ... Dry Handling ..................................... .......... X .......... 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 


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56The 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. 

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 ................................................................................. • Bioreactor tanks; 

• Nutrient feed system and storage; 

• 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 this 

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 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.56 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 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; 


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57EPA expects that plants will be in compliance 

with new federal and state air pollution control 

requirements by 2020. 

58A third power plant is currently installing a 

vapor-compression evaporation system to treat the 

FGD wastewater. 

59 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. 

• 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 

• 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 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 

2020 57 and the associated costs of the 

regulatory options discussed in this 

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 plantspecific costs for these future 

installations, using the same approach 

as it used for current operations. 

B. Methodology for Estimating PlantSpecific 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 

this 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. 

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 two operate a vapor-compression 

evaporation system.58 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 particulate matter (including the 

particulate phase metals) to an 

equivalent treatment level of 30 mg/L 

TSS (i.e., thus assuming that the 

discharge would be in compliance with 

the current BPT effluent limits for lowvolume 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.59 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 chlorides concentration 

compared to the design maximum 

chlorides concentration. 


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60The 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. 

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 post-compliance 

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 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 postcompliance 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 mercury-containing carbon 

to silos for temporary storage until the 

waste is hauled away by trucks for 

disposal in a landfill. EPA 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 eight 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 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. The proposed 

requirements 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.60 Additionally, 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 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 this 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 of data, treatment of nondetects, 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 


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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 non-detects 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 non-detects than detected 

values for effluent data for sulfides. 

Does this dataset provide a sufficient 

basis, in the absence of any other 

information, for estimating pollutant 

loadings for sulfides? 

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 above in Section VIII, 

EPA evaluated eight 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 tables 

present the capital cost, annual 

operating and maintenance costs, onetime 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 this proposal. 

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) 

4a a ................................................................................. 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) 

aEPA 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 ‘‘Methodologies for Estimating Costs and 

Pollutant Removals for Steam Electric ELG Regulatory Option 4a’’ (DCN SE03834). 

TABLE IX–4—ESTIMATED POLLUTANT LOADING REDUCTION (BAT AND PSES) 

[In million pounds/year] 

Regulatory option 

Pollutant removals 

Conventional 

pollutants a Priority pollutants Nonconventional 

pollutants b

1 ........................................................................................................................... 2.8 0.5 c (418) 

3a ......................................................................................................................... 16 0.4 468 

2 ........................................................................................................................... 2.8 0.7 1,155 

3b ......................................................................................................................... 17.1 0.6 914 

3 ........................................................................................................................... 19 1.1 1,623 

4a d ....................................................................................................................... 28 1.4 2,612 

4 ........................................................................................................................... 35 1.7 3,328 


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TABLE IX–4—ESTIMATED POLLUTANT LOADING REDUCTION (BAT AND PSES)—Continued 

[In million pounds/year] 

Regulatory option 

Pollutant removals 

Conventional 

pollutants a Priority pollutants Nonconventional 

pollutants b

5 ........................................................................................................................... 36 1.7 5,287 

aThe 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. bThe 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). cOption 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 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 

‘‘Methodologies for Estimating Costs 

and Pollutant Removals for Steam 

Electric ELG Regulatory Option 4a’’ 

(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 longterm 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 this 

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 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 long-term 

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 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 longterm 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 

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 sufficientlysensitive 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 


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61Examples 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; 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 alreadycommissioned treatment system, such as may occur 

from a treatment system that has undergone either 

short or extended duration shutdown. 

62Based on data EPA has evaluated for the steam 

electric industry and other industry sectors, twostage 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. 

analytical anomalies by an otherwise 

well-operated 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 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 long-term 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.61

B. Data Used as Basis of the Limitations 

and Standards 

The sections below discuss the data 

used as the basis for this 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, all of the preferred 

regulatory options propose zero 

discharge of pollutants 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 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 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 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.62 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., 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, hereafter referred 

to in this section as ‘‘chemical 

precipitation’’—see Section VIII above 

for a more detailed description): 


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• 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 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 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 a preferred 

option in this 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 vapor-compression 

evaporation system. EPA used the data 

from this plant to develop the 

limitations based on the vaporcompression 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 vapor-compression 

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 vapor-compression 

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’’). 

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 selfmonitoring 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 selfmonitoring). 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 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 quality 

control issues, abnormal conditions or 

treatment upsets, or were analytical 

anomalies. See DCN SE01999 for a 

detailed discussion of the data 

excluded. 


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63For 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). 

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. 

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 

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 

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 welloperated 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 normal fluctuations in a 

plant’s treatment are accounted for in 

the limitations. By accounting for these 

reasonable excursions above the longterm average, EPA’s use of variability 

factors results in limitations that are 

generally well above the long-term 

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 

long-term average for each pollutant that 

had enough distinct detected 63 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 plant-specific 

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 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 


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(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 plantspecific 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 

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 plantspecific 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 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 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 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 longterm 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. 

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 Pollutant Option LTA Daily variability 

factor 

Monthly 

variability 

factor 

Daily 

limitation d

Monthly 

limitation d

Chemical Precipitation for 

FGD.

Arsenic (ug/L) .................

Mercury (ng/L) ................

4.483 

75.404 

1.741 

3.209 

1.223 

1.570 

8 

242 

6 

119 

Chemical Precipitation and Biological Treatment for FGD.Arsenic (ug/L)a ...............

Mercury (ng/L)a ..............

Nitrate-nitrite (mg/L) .......

4.483 

75.404 

0.110 

1.741 

3.209 

1.499 

1.223 

1.570 

1.157 

8 

242 

0.17 

6 

119 

0.13 

Selenium (ug/L) .............. 7.455 2.145 1.321 16 10 

Chemical Precipitation and 

Evaporation for FGD.

Arsenic (ug/L) .................

Mercury (ng/L) ................

Selenium (ug/L) ..............

b 4.0 

17.788 b 5.0 

(c) 

2.192 

(c) 

(c) 

1.338 

(c) 

e 4 

39 

5 e

(f) 

24 

(f) 

TDS (mg/L) ..................... 14.884 3.341 1.572 50 24 

Vapor-Compression Evaporation for Gasification.Arsenic (ug/L) .................

Mercury (ng/L) ................

Selenium (ug/L) ..............

b 4.0 

1.075 

146.780 

(c) 

1.632 

3.083 

(c) 

1.194 

1.545 

e 4 

1.76 

453 

(f) 

1.29 

227 

TDS (mg/L) ..................... 15.209 2.483 1.389 38 22 

Chemical Precipitation for 

Leachate.

Arsenic (ug/L)a ...............

Mercury (ng/L)a ..............

4.483 

75.404 

1.741 

3.209 

1.223 

1.570 

8 

242 

6 

119 

aOption 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 non-detected. 


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cAll observations were non-detected, so the variability factors could not be calculated. 

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 

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 limitations. 

See Section 13.9.1 of the TDD 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 long-term 

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. 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 these 

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 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 eight 

regulatory options described in this 

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. The Regulatory 


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64As 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 this 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. 

Impact Analysis for Proposed Effluent 

Limitations Guidelines and Standards 

for the Steam Electric Power Generating 

Point Source Category (RIA)—EPA 821– 

R–13–005 and Benefits and Cost 

Analysis 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 investorowned 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 that 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 this 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.64

B. Annualized Compliance Costs 

EPA’s analyses of costs and economic 

impacts use the plant-level 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. Plant-specific compliance 

costs were developed for those plants 

for which EPA obtained detailed 

technical data through the industry 

survey. 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 compliance-related 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 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 aftertax compliance costs, whereas social 

costs discussed in Section XI.C are 

calculated using pre-tax costs). For the 

assessment of 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 forprofit 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 costs 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 $108.4 million and 

$1.55 billion for Options 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, $635.7 million (aftertax), respectively for Options3a, 3b, 3, 

and 4a. The 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 

Option 3a .................. $168.1 $108.4 

Option 3b .................. 264.6 182.2 

Option 1 .................... 265.9 190.6 

Option 2 .................... 393.3 280.6 

Option 3 .................... 561.3 389.0 

Option 4a .................. 947.8 635.7 

Option 4 .................... 1,373.2 916.9 

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 

percent reduction), whereas costs for 

Option 4 would go from $1,373.2 

million to $1,252.9 million (9 percent 

reduction). 


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65These 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. 

66These discount rate values follow guidance 

from the Office of Management and Budget (OMB) 

regulatory analysis guidance document, Circular A– 

4 (OMB, 2003). 

67For 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. 

68To 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. 

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.65

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 (fiveyear 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 eight 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.66

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. 

TABLE XI–2—TOTAL ANNUALIZED

SOCIAL COSTS

[In millions, 2010$] 

Regulatory 

option 

3% Discount 

rate 

7% Discount 

rate 

Option 3a ...... $185.2 $164.5 

Option 1 ........ 268.3 259.2 

Option 3b ...... 281.4 257.2 

Option 2 ........ 386.8 380.8 

Option 3 ........ 572.0 545.3 

Option 4a ...... 954.1 914.7 

Option 4 ........ 1,381.2 1,323.2 

Option 5 ........ 2,328.8 2,209.4 

At 3 percent discount rate, total 

annualized social costs for existing 

plants vary from $185.2 million under 

Option 3a to $2.3 billion under Option 

5, with the preferred BAT and PSES 

options having total annualized social 

costs of $185.2 million, $281.4 million, 

$572.0 million, and $954.1 million, 

respectively for Options 3a, 3b, 3 and 

4a. 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 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, 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 aftertax compliance costs of the regulatory 

options as a percent of baseline annual 

revenues.67 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).68

Table XI–3 summarizes the screeninglevel plant-level cost-to-revenue 

analysis results for the eight main 

regulatory options. EPA estimates that 

the vast majority of plants subject to the 

proposed ELGs will incur annualized 

costs amounting to less than 1 percent 

of revenue for all eight regulatory 

options (887 to 1,051 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 

(Options 3a, 3b, 3 and 4a), 92 percent 

to 97 percent of steam electric plants 

have estimated costs that are less than 

1 percent of revenue. The number of 

plants with ratios between 1 percent 

and 3 percent, and above 3 percent, 


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generally rises when moving from 

Option 3a to Option 5. For the preferred 

BAT and PSES options (Options 3a, 3b, 

3 and 4a), two to six percent of plants 

have cost-to-revenue ratios between 1 

and 3 percent and less than one percent 

to two percent have ratios above 3 

percent. 

TABLE XI–3—PLANT-LEVEL COST-TO-REVENUE ANALYSIS RESULTS BY REGULATORY OPTION a

Option No data on 

revenue b

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 

aThis analysis makes a counterfactual, conservative assumption of zero cost pass-through. Plant counts are weighted estimates. 

bEIA 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 eight 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. 

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 REVENUE a

Option 

Total 

number 

of entities 

Not analyzed 

due to lack of 

revenue 

information 

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 

Option 3a .......................................................... 243 14 6 205 84 22 9 2 1 0 0 

Option 3b .......................................................... 243 14 6 201 83 26 11 2 1 0 0 

Option 1 ............................................................ 243 14 6 173 71 51 21 1 <1 4 2 

Option 2 ............................................................ 243 14 6 173 71 46 19 6 2 4 2 

Option 3 ............................................................ 243 14 6 168 69 49 20 7 3 5 2 

Option 4a .......................................................... 243 14 6 157 65 55 23 11 5 6 2 

Option 4 ............................................................ 243 14 6 137 56 64 26 21 9 7 3 

Option 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 

Option 3a .......................................................... 507 30 6 453 89 22 4 2 <1 0 0 

Option 3b .......................................................... 507 30 6 449 89 26 5 2 <1 0 0 

Option 1 ............................................................ 507 30 6 421 83 51 10 1 <1 4 1 

Option 2 ............................................................ 507 30 6 421 83 46 9 6 1 4 1 

Option 3 ............................................................ 507 30 6 416 82 49 10 7 1 5 1 

Option 4a .......................................................... 507 30 6 405 80 55 11 11 2 6 1 

Option 4 ............................................................ 507 30 6 385 76 64 13 21 4 7 1 

Option 5 ............................................................ 507 30 6 385 76 57 11 20 4 15 3 

# equals the number of entities. 


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69 In some instances, plant information has been 

updated to reflect known material changes in a 

plant’s generating capacity since 2006. 

70The 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. 

71EPA’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 

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. 

aThis 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 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 lowerbound case, EPA estimates that the vast 

majority of parent entities will incur 

annualized costs of less than 1 percent 

of revenues under all eight analyzed 

regulatory Options (the shares are 93, 

93, 89, and 87 percent under Options 

3a, 3 and 4a, respectively). These 

observations also hold true under the 

upper bound case; an estimated 94, 94, 

92, and 91 percent of parent entities 

incur annualized costs of less than 1 

percent of revenue, for Options 3a, 3b, 

3 and 4a, 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 any of the four preferred 

BAT and PSES options (Options 3a, 3b, 

3 and 4a). 

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 used the Integrated 

Planning Model (IPM), a comprehensive 

electricity market optimization model 

that can evaluate such impacts within 

the context of regional and national 

electricity markets. The model is 

designed to evaluate the effects of 

changes in 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 these 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 this proposal are located 

in these two regions. 

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 EIA 

860 (2006) and EIA 767 (2005) 

databases.69 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.70 IPM Version 

4.10 embeds a baseline energy demand 

forecast that is derived from DOE’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) 71; regulatory 

SO2 emission rates arising from State 

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 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. 

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 at 


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72The 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. 

73Compliance 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. 

74 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. 

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 plantand 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.72 Thus, the Option 3 scenario 

analyzed using IPM and discussed 

below did not 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.73

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 

these proposed Options 3 and 4 to 

provide valuable insight on the likely 

impacts of the proposed ELGs. Options 

3a, 1, 2, and 3b 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 

3b would be less than Option 3. EPA 

did not analyze Option 4a due to time 

and resource constraints, but expects 

that this option could 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 these 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 and all 

compliance costs will be reflected in 

production costs (i.e., steady state of 

post-compliance 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 2014.74

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 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. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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75 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. 

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). 

76Avoided 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. 

TABLE XI–5—IMPACT OF MARKET MODEL ANALYSIS OPTIONS ON NATIONAL AND REGIONAL MARKETS AT THE YEAR 2030 

NERC region Baseline capacity 

(GW) 

Incremental early 

retirements/closures a

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) Capacity 

(GW) 

% of Baseline 

closures 

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 

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 0.6 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 1,874 0.9 N/A 

aValues 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.75

As shown in Table XI–5, the Market 

Model Analysis indicates that Option 3 

would have very small effects in overall 

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 (0.8 

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.76 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 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 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34498 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

77 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. 

78At 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. 

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) postcompliance change in electricity 

generation; (4) post-compliance changes 

in variable production costs per MWh, 

calculated as the sum of total fuel and 

variable O&M costs divided by net 

generation; and (5) changes in annual 

costs (fuel, variable O&M, fixed O&M, 

and capital. Items (1) and (2) 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 

Baseline 

capacity 

(MW) 

Incremental early 

retirements/ 

closures a

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) Capacity 

(MW) 

% of Baseline 

capacity 

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 ¥0.3 ¥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 0.0 ¥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 ¥2.6 ¥4 0.0 0.10 0.3 29 0.7 

RFC ........................... 122,205 681 0.6 ¥2,351 ¥0.3 0.38 1.3 561 1.8 

SERC ........................ 131,895 0 0.1 ¥2,178 ¥0.3 0.43 1.5 607 1.8 

SPP ........................... 31,269 ¥30 ¥0.1 ¥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 ¥4,916 ¥0.2 0.28 1.0 1,504 1.4 

aValues 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. 77

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,78 for steam 

electric plants, total available capacity 

and electricity 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 


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79 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. 

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 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.79

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. 

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 the proposed 

ELGs. To assess potential plant-level 

effects, EPA analyzed plant-specific 

changes between the base case and the 

post-compliance cases for the following 

metrics: (1) Capacity utilization (defined 

as annual generation (in MWh) divided 

by [capacity (MW) times 8,760 hours]) 

(2) electricity generation, and (3) 

variable production costs per MWh, 

defined as variable O&M cost plus fuel 

cost divided by net generation. 

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% ≥1 and <3% <1% <1% ≥1 and <3% ≥ 3% 

Option 3 

Change in Capacity Utilization a ........................ 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 Utilization a ........................ 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 

aThe 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. bPlants 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 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 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34500 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

80Other 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. 

81As 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 

single day. This concept is useful to avoid any 

impact of project delays and of financing issues and 

assumptions on estimated costs. 

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 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. 

Given these impacts, and since the 

impacts of Option 4a would fall 

between those of Options 3 and 4, EPA 

believes that Option 4a 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 this 

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. 

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 estimates no change in 

coal steam capacity relative to the 

baseline, and small increases in 

generation capacity from other steam 

(0.3 percent), combustion turbine (0.3 

percent), other non-steam (less than 0.1 

percent), and combined cycle (less than 

0.1 percent) units.80

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 overnight 81 capital 

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

Percent 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 

aSource: 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 

costs. 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 this 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. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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82Some NERC regions have been re-defined over 

the past few years. The NERC region definitions 

used in this proposed rule analyses vary by analysis depending on which region definition aligns better 

with the data elements underlying the analysis. 

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 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.82 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 3a show the average 

annual cost per residential household 

increasing by $0 to $1.69 depending on 

the region, with a national average of 

$0.48. This represents a monthly 

increase of $0.04 for the typical 

household. For Option 3b, the results 

show the average annual cost per 

residential household increasing by $0 

to $2.29, with a national average of 

$0.75, or $0.06 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 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 

aThe 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 the 

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 passthrough assumption, EPA analyzed 

alternative scenarios including cases 

where only half (50 percent) of the 

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 sampleweighted 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. 

As reported in Table XI–10, on 

average, across the United States, 

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 

3a range from 0¢ to 0.016¢, depending 

on the region, with a national average of 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34502 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

0.004¢ per KWh. For Option 3b, 

annualized compliance costs range from 

0¢ to 0.022¢, with a national average of 

0.007¢ 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 3a is 

estimated to result in the smallest 

electricity price increase, 0.05 percent; 

the other preferred BAT and PSES 

options, Options 3b, 3 and 4a, have 

estimated increases of 0.08 percent, 0.16 

percent and 0.27 percent, respectively. 

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 

aThis 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 eight 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 longerterm, 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) (‘‘factorshift 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 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 eight 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 168 jobs under proposed 

Option 3a for existing sources. For 

proposed Option 3b, the average annual 

increase is estimated at 255 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 be over-estimated. Chapter 6 of 

the RIA report describes the 

methodologies and results in greater 

detail. 


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Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 34503 

TABLE XI–11—RESULTS OF ONGOING

EMPLOYMENT EFFECTS ON THE

ELECTRIC POWER INDUSTRY SECTOR (NUMBER OF JOBS) a b

Regulatory 

option 

Employment 

effect 

Total annual 

average 

employment 

effect 

Option 3a ...... Cost .............. 262 

Factor Shift .. 291 

Demand ....... ¥386 

Total ...... 168 

Option 1 ........ Cost .............. 380 

Factor Shift .. 421 

Demand ....... ¥559 

Total ...... 243 

Option 3b ...... Cost .............. 399 

Factor Shift .. 441 

Demand ....... ¥586 

Total ...... 255 

Option 2 ........ Cost .............. 548 

Factor Shift .. 607 

Demand ....... ¥806 

Total ...... 548 

Option 3 Cost .............. 810 

Factor Shift .. 897 

Demand ....... ¥1,192 

Total ...... 519 

Option 4a ...... Cost .............. 1,351 

Factor Shift .. 1,496 

Demand ....... ¥1,988 

Total ...... 865 

Option 4 ........ Cost .............. 1,956 

Factor Shift .. 2,166 

Demand ....... ¥2,878 

Total ...... 1,253 

Option 5 ........ Cost .............. 3,298 

Factor Shift .. 3,653 

Demand ....... ¥4,852 

Total ...... 2,112 

aSource: Morgenstern, Pizer, and Shih 

(2002). c 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. 

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 factor). The toxic 

weight for each pollutant measures its 

toxicity relative to copper, with more 

toxic pollutants having higher toxic 

weights. The use of toxic weights allows 

the removals of different pollutants to 

be expressed on a constant toxicity basis 

as toxic pound-equivalents (lb-eq). 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 

treatment at publicly owned treatment 

works (POTW) and reflects the toxicweighted 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 reported cost effectiveness of 

other effluent guidelines, which use 

1981 dollars. 

EPA performed the cost-effectiveness 

analysis for the eight 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 wastestreams it generates and 

as an indirect discharger for another. 

B. Cost-Effectiveness Analysis for Direct 

Dischargers 

Table XII–1 summarizes the costeffectiveness analysis for the BAT 

regulatory options applicable to direct 

dischargers. The table lists the options 

in increasing order of total annual toxicweighted pollutant removals. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34504 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

TABLE XII–1—COST-EFFECTIVENESS OF REMOVING TOXIC POLLUTANTS FOR DIRECT DISCHARGERS a

Option 

Annual pre-tax compliance costs 

(million, 1981$) 

Total annual toxic-weighted 

pollutant removals (000 lb-eq) 

Cost effectiveness 

(1981$/lb-eq) 

Option total 

cost 

Incremental 

cost 

Option total 

removals 

Incremental 

removals 

Option cost 

effectiveness 

Incremental 

cost 

effectiveness 

Option 1 ....................................... $105.6 $105.6 1,530,719 1,530,719 $69 $69 

Option 3a ..................................... 67.5 ¥38.1 2,488,470 957,751 27 ¥40 

Option 2 ....................................... 156.0 88.5 2,603,628 115,158 60 768 

Option 3b ..................................... 106.3 ¥49.7 3,396,653 793,025 31 ¥63 

Option 3 ....................................... 223.5 117.2 5,092,098 1,695,445 44 69 

Option 4a ..................................... 378.7 155.2 6,664,693 1,572,595 57 99 

Option 4 ....................................... 547.9 169.2 7,831,298 1,166,605 70 145 

Option 5 ....................................... 906.5 358.5 8,200,804 369,506 111 970 

aOptions are ranked by increasing levels of total annual toxic-weighted removals. 

As shown in Table XII–1, the 

proposed technology bases for BAT 

have a cost-effectiveness ratio of $27/lbeq, $31/lb-eq, $44/lb-eq, and $57/lb-eq, 

respectively for Options 3a, 3b, 3 and 4a 

($1981). These cost-effectiveness ratios 

are well within the range of costeffectiveness ratios for BAT of other 

industries. A review of approximately 

25 of the most recently promulgated or 

revised BAT limitations shows BAT 

cost-effectiveness ranging from less than 

$1/lb-eq (Inorganic Chemicals) to $404/ 

lb-eq (Electrical and Electronic 

Components), in 1981 dollars. 

C. Cost-Effectiveness Analysis for 

Indirect Dischargers 

Table XII–2 summarizes the costeffectiveness analysis for the PSES 

regulatory options applicable to indirect 

dischargers. 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 DISCHARGERSa

Option 

Annual pre-tax compliance costs 

(million, 1981$) 

Total annual toxic-weighted pollutant removals (000 lb–eq) Cost effectiveness (1981$/lb-eq) 

Option total 

cost 

Incremental 

cost 

Option total 

removals 

Incremental 

removals 

Option cost 

effectiveness 

Incremental 

cost 

effectiveness 

Option 3a ..................................... $0.0 $0.0 0 0 

Option 3b ..................................... 0.0 0.0 0 0 

Option 1 ....................................... 1.2 1.2 3,540 3,540 $345 $345 

Option 2 ....................................... 2.0 0.7 11,711 8,171 168 92 

Option 3 ....................................... 2.0 0.0 11,711 0 168 

Option 4a ..................................... 2.0 0.0 11,711 0 168 

Option 4 ....................................... 3.6 1.6 15,532 3,821 233 430 

Option 5 ....................................... 8.1 4.5 18,297 2,765 445 1,636 

aOptions are ranked by increasing levels of total annual toxic-weighted removals. 

As shown in Table XII–2, there are no 

indirect dischargers that would incur 

compliance costs or result in 

incremental pollutant removals under 

Options 3a and 3b, whereas Options 3 

and 4a both have a cost effectiveness of 

$168/lb-eq ($1981). The costeffectiveness of 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 

environmental improvements discussed 

in Section XIII.A below are those for the 

preferred BAT and PSES regulatory 

options (Option 3a, Option 3b, Option 3, 

and Option 4a). 

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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 34505 

83Ruhl, 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. 

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 

aquatic life and accumulating in the 

environment and will only get worse.83

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 

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 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 50 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 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 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 


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receiving 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 waterscale human health model. Each of 

these models evaluates changes in 

environmental and human health effects 

under baseline conditions and 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] 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 RiskScreening 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 improved river 

miles associated with the different 

options for this 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 this 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. 

A. Improvements in Surface Water and 

Ground Water Quality 

The reduced pollutant loadings 

associated with the preferred options 

(Option 3a, Option 3b, Option 3, and 

Option 4a) would lead to reduced 

contamination levels in surface waters 

and sediments. EPA estimated that 

reduced pollutant loadings to surface 

waters associated with Option 3a would 

significantly improve water quality by 

reducing metal concentrations by up to 

33 percent on average within the 

immediate receiving waters. Option 3b, 

Option 3, and Option 4a would achieve 

average reductions of up to 36 percent, 

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 55 percent for Option 4a 

under the post-compliance pollutant 

loadings. EPA also estimates that the 

number of immediate receiving waters 

with human health water quality 

standards exceedances, primarily 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 41 percent for 

Option 4a. 

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, and 60 percent on average under 

Option 4a. This would reduce 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 (Option 3), and 

6,633 river miles (Option 4a) 

downstream from steam electric 

discharges would no longer exceed 

aquatic life and human health NRWQC 

or MCL standards under the postcompliance 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 


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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 51 percent under 

Option 4a. 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. 

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 the 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 52 

percent under Option 4a. 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 56 

percent under Option 4a. This indicates 

that the preferred options would reduce 

the bioaccumulative impact of the 

evaluated wastestreams in the 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. 

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 the preferred options. 

C. Reduced Human Health Cancer Risk 

EPA estimates that reductions in 

arsenic loadings from the preferred 

options would result in a reduction in 

potential cancer risks to humans that 

consume fish exposed to 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 (Option 3b and Option 

3), and up to 80 percent (Option 4a) 

under post-compliance loadings. 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-amillion threshold. Under the postcompliance pollutant loadings 

associated with the preferred options, 

EPA estimates that up to 111 river miles 

(Option 3a), up to 116 river miles 

(Option 3b), up to 133 river miles 

(Option 3), and up to 169 river miles 

(Option 4a) 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. 

The 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 

(Option 3), and up to 53 percent of 

surface waters (Option 4a) 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 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. In addition, 

exceedances of total thallium and total 

selenium non-cancer reference doses 

would decrease in up to 14 and 50 

percent of immediate receiving waters 

(Option 3a and Option 3b), up to 18 and 

69 percent of immediate receiving 

waters (Option 3), and up to 43 and 77 

percent of immediate receiving waters 

(Option 4a), respectively. EPA also 

estimates that, under the postcompliance 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 


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(Option 3), and up to 8,087 river miles 

downstream (Option 4a) for one or more 

of the cohorts. 

In addition to the assessment of noncancer 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 the preferred 

options would reduce the associated 

intelligence quotient (IQ) loss among 

children who live in recreational angler 

and subsistence fisher households. The 

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 hearing, and cancer. 

The 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 the preferred 

options would result in additional noncancer 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. 

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 

(Option 3), and by 66 percent (Option 

4a) and improve overall water quality. 

EPA used the SPARROW (SPAtially 

Referenced Regressions On Watershed 

attributes) model to calculate immediate 

receiving water concentrations under 

baseline conditions and under five of 

the regulatory options 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 

(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 

the 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 the 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 aquaticdependant wildlife population diversity 

and community structures; 

• Exposure of wildlife to pollutants 

through direct contact with combustion 

residuals impoundments and 

constructed 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-compliance 

pollutant loading reductions associated 

with the 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 


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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 the 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 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 the 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 the 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 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 on 

benefits methodologies and analysis, 

including uncertainties and limitations. 

A. Categories of Benefits Analyzed 

Table XIV–1 summarizes benefit 

categories associated with this 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 Quantified and 

monetized 

Quantified but 

not monetized 

Neither 

quantified nor 

monetized 

1. Human Health Benefits from Surface Water Quality Improvements 

Reduced incidence of cancer from arsenic exposure via fish consumption ................... X ............................ ............................

Reduced 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 ............................ ............................


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TABLE XIV–1—BENEFIT CATEGORIES ASSOCIATED WITH PROPOSED ELGS—Continued 

Benefit category Quantified and 

monetized 

Quantified but 

not monetized 

Neither 

quantified nor 

monetized 

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 

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. 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 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 the 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: 

• 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, statespecific average fishing rates, presence 

of fish consumption advisories, the 

availability of substitute fishing 


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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 estimated 

blood-lead 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 (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 blood-lead 

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 estimate 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 3 percent discount rate, and 

$125,500 per child at 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, state-specific 

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. 

Table XIV–2 summarizes monetized 

human health benefits associated with 

five of the eight regulatory options 

considered in this 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 to $0.1) .... $0.1 ($0.1 to $0.1) ..... $2.7 ($2.2 to $3.2) .... $6.7 ($5.6 to $7.9) .... $6.7 ($6.5 to $7.9) 


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84 Including AWQCs for the protection of human 

health through consumption of organisms and 

water. 

TABLE XIV–2—ANNUALIZED HUMAN HEALTH BENEFITS—Continued 

[million 2010$] c

Human health benefit 

category Option 1 Option 2 Option 3 Option 4 Option 5 

Benefits from Reduced Need for 

Specialized Education for Children 

from Lead Exposure via Fish Consumption.

<$0.1 (<$0.1 to 

<$0.1).

<$0.1 (<$0.1 to 

<$0.1).

<$0.1 (<$0.1 to 

<$0.1).

$0.1 ($0.1 to $0.1) ..... $0.1 ($0.1 to $0.1) 

Benefits of Reduced 

In-utero Mercury 

Exposure via Maternal Fish Consumption a.

$3.8 ($3.2 to $4.5) .... $3.9 ($3.2 to $4.6) ..... $5.0 ($4.1 to $5.8) .... $10.2 ($8.4 to $12.1) $10.2 ($8.4 to $12/1) 

Total Human 

Health Benefits b.

$3.9 ($3.21 to $4.59) $4.0 ($3.28 to $4.69) $7.7 ($6.4 to $9.11) .. $17. ($14.2 to $20.2) $17. ($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 to 

<$0.1).

<$0.1 (<$0.1 to 

<$0.1).

$0.2 ($0.2 to $0.3) ..... $0.6 ($0.4 to $0.8) .... $0.6 ($0.4 to $0.8) 

Benefits from Reduced Need for 

Specialized Education for Children 

from Lead Exposure via Fish Consumption.

<$0.1 (<$0.1 to 

<$0.1).

<$0.1 (<$0.1 to 

<$0.1).

<$0.1 (<$0.1 to 

<$0.1).

<$0.1 (<$0.1 to 

<$0.1).

<$0.1 (<$0.1 to 

<$0.1) 

Benefits of Reduced 

In-utero Mercury 

Exposure via Maternal Fish Consumption a.

$0.3 ($0.2 to $0.5) .... $0.4 ($0.2 to $0.5) ..... $0.4 ($0.3 to $0.6) .... $0.9 ($0.6 to $1.2) .... $0.9 ($0.6 to $1.2) 

Total Human 

Health Benefits b.

$0.4 ($0.2 to $0.5) .... $0.4 ($0.2 to $0.5) ..... $0.7 ($0.5 to $1.0) .... $1.6 ($1.1 to $2.1) .... $1.6 ($1.1 to $2.1) 

a Low 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). bTotals may not add up due to independent rounding. 

cEPA 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 HealthBased 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 doseresponse 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 healthbased ambient water quality criteria 

(AWQCs).84 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 


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85There 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). 

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). 

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 this 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 quality, and (2) benefits from 

improved protection of threatened and 

endangered (T&E) species. 

a. Improvements in Surface Water 

Quality 

EPA expects these 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 waterbased 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. These 

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 postcompliance water quality, EPA utilized 

a water quality index (WQI) that 

translates water quality measurements, 

gathered for multiple parameters that 

are indicative of various aspects of 

water quality, into a single numerical 

indicator that reflects achievement of 

quality consistent with 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.85 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 RiskScreening 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 22,441 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 meta-regression 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 plants 

would be expected to start installing 

control technologies under this 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 


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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 metaanalysis. When EPA used the Carson 

and Mitchell values, the Agency was 

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 this 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 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 lifehistory 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 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 

wildlife-based 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, EPA used a benefit function 

transfer approach based on a metaanalysis 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 

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. 

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). 


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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 

3% Discount Rate 

Improved Surface Water Quality a ...................................... $8.3 ................

($2.0 to $22.4) 

$38.0 ..............

($7.1 to 

$107.1).

$49.9 ..............

($10.2 to 

$137.6).

$82.8 ..............

($19.6 to 

$215.8).

$81.9 

($19.3 to 

$214.1) 

Benefits to E&T Species b .................................................. $7.0 ................

($3.9 to $10.0) 

$7.0 ................

($3.9 to $10.0) 

$10.0 ..............

($5.5 to $14.2) 

$33.3 ..............

($18.2 to 

$47.3).

$33.3 

($18.2 to 

$47.3) 

Total Ecological and Recreational Uses Benefits d ..... $15.3 ..............

($5.8 to $32.4) 

$45.0 ..............

($11.0 to 

$117.7).

$59.9 ..............

($15.7 to 

$151.8).

$116.1 ............

($37.8 to 

$263.1).

$115.2 

($37.5 to 

$261.4) 

7% Discount Rate 

Improved Surface Water Quality a ...................................... $6.9 ................

($1.6 to $18.7) 

$31.7 ..............

($6.0 to $48.3) 

$41.7 ..............

($8.5 to 

$115.0).

$69.2 ..............

($16.4 to 

$180.3).

$68.5 

($16.1 to 

$178.9) 

Benefits to E&T Species b .................................................. $5.9 ................

($3.2 to $8.4)

$5.9 ................

($3.2 to $8.4)

$8.4 ................

($4.6 to $11.9) 

$27.8 ..............

($15.2 to 

$39.5).

$27.8 

($15.2 to 

$39.5) 

Total Ecological and Recreational Uses Benefits d ..... $12.8 ..............

($4.8 to $27.0) 

$37.6 ..............

($9.1 to $56.6) 

$50.1 ..............

($13.1 to 

$126.9).

$97.0 ..............

($31.6 to 

$219.8).

$96.2 

($31.3 to 

$218.4) 

aValues 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. dTotals may not add up due to independent rounding. 

eEPA 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 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

[Million 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 


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86EPA 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. 87Natural 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. 88For 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. 

89This 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. 

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 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 five of the eight 

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 and under each of the 

regulatory options.86 EPA also used data 

on historical failure events to develop 

average cleanup, natural resource 

damages,87 and litigation costs 88 per 

event. As detailed in Chapter 7 of the 

BCA, EPA used average total costs of 

$0.06 per gallon of impoundment 

capacity to estimate the expected costs 

of an impoundment failure.89 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 from $62.1 

million to $295.1 million (at 3 percent 

discount rate), with Option 3 having 

expected benefits of $114.8 million per 

year. 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 ............................................ $62.1 $62.1 $114.8 $295.1 $295.1 

7% Discount Rate ............................................ 52.2 52.2 95.9 245.9 245.9 

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 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. 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

emissions. Because the analysis relies in 

part on estimates of air emissions 

obtained from IPM, EPA estimated airrelated benefits for Options 3 and 4 

only, as these are the two options 

analyzed in IPM. Table XIV–6 


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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 3 Option 4 

3% Discount Rate (for NOX, SO2, and CO2-related benefits) ........................................................................ $127.6 $170.5 

7% Discount Rate (for NOX, SO2, and CO2-related benefits) a b ..................................................................... 82.3 74.6 

aBecause 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 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. bAir 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. cEPA 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 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 

aEPA 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 $82 million to $605.5 

million (at 3 percent discount rate), 

depending on the option and based on 

EPA’s analysis of five of the eight 

regulatory options (Table XIV–8). BAT 

and PSES option 3 has annual total 

benefits estimated at $311.7 million (at 

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). 

The monetized benefits of this 

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 this 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 Benefits a c ................................ $3.9 $4.0 $7.7 $17.2 $17.2 


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TABLE XIV–8—SUMMARY OF TOTAL ANNUALIZED MONETIZED BENEFITS OF PROPOSED ELGS—Continued 

[Million 2010$] f

Benefit category Option 1 Option 2 Option 3 Option 4 Option 5 

Improved Ecological Conditions and Recreational Uses a 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 ..................... 62.1 62.1 114.8 295.1 295.1 

Air-Related Benefits d ....................................... NE NE 127.6 170.5 NE 

Reduced Water Withdrawals ........................... 0.0 0.0 ≤0.1 0.1 0.1 

Total benefits, Excluding Air-Related Benefits 82.0 111.7 184.1 435.0 434.1 

Total Benefits (Including Air-related Benefits) a ...................................................... ............................ ............................ 311.7 605.5 ............................

7 Percent Discount Rate 

Human Health Benefits a c ................................ 0.4 0.4 0.7 1.6 1.6 

Improved Ecological Conditions and Recreational Uses a 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 ..................... 52.2 52.2 95.9 245.9 245.9 

Air-Related Benefits d e ..................................... NE NE 82.3 74.5 NE 

Reduced Water Withdrawals ........................... 0.0 0.0 0.0 0.1 0.1 

Total benefits, Excluding Air-Related Benefits ........................................................ 65.9 90.7 148.1 350.2 349.4 

Total Benefits (Including Air-related Benefits) a ...................................................... ............................ ............................ 230.4 424.8 ............................

aValues 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). bThere may be some overlap between the willingness-to-pay (WTP) for surface water quality improvements and WTP for benefits to threatened and endangered species. cValues represent partial human health benefits only for reaches that receive direct discharges from steam electric plants. 

dEPA 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. eBecause 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. fEPA did not estimate benefits for Options 3a, 3b and 4a, but expects the benefits of Option 4a to be between those of Options 3 and 4. 

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 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 

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 this 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. 


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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 .................................................................... Estimate a .................................................................. $82.0 $65.9 

Option 3a .................................................................. Inference b ................................................................. 139.4 104.8 

Option 2 .................................................................... Estimate a .................................................................. 111.7 90.7 

Option 3b .................................................................. Inference b ................................................................. 205.5 153.0 

Option 3 .................................................................... Estimate .................................................................... 311.7 230.4 

Option 4a .................................................................. Inference b ................................................................. 482.5 343.4 

Option 4 .................................................................... Estimate .................................................................... 605.5 424.8 

Option 5 .................................................................... Estimate a .................................................................. 434.1 349.4 

aTotal benefits for Options 1, 2, and 5 do not include air-related benefits (see Table XIV–8). 

bEPA 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 these proposed ELGs 

will benefit children by reducing health 

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 preschool age children from reduced 

exposure to lead and (2) avoided 

neurological damages from in-utero 

exposure to mercury. 

This analysis considered several 

measures of children’s health benefits 

associated with lead exposure for 

children up to age six. Avoided 

neurological and cognitive damages 

were expressed as changes in three 

metrics: (1) Overall IQ levels; (2) the 

incidence of low IQ scores (<70); and (3) 

the incidence of 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 Option 3 are 

estimated at $2.7 million (at 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). 

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 inutero 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 million and 

$10.2 million per year (mean estimate, 

at 3 percent discount rate), across the 

five options EPA analyzed. Option 3 is 

estimated to avoid the loss of about 

12,000 IQ points in exposed infants over 

the 24-year period. The benefits 

associated with these avoided IQ point 

losses are estimated at $5.0 million per 

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). 

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 non-water quality 

environmental impacts (including 

energy impacts) associated with ELGs. 

Accordingly, EPA has considered the 

potential impact of the 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 trucks for 

dust suppression. For those facilities 

that it projected would incur costs to 

comply with these 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 


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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 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 nonhazardous 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 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 4a). 

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 0.003 percent (Option 3a) to 0.012 

percent (Option 4a) 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 3a for BAT and PSES will be 

0.008 percent of total fuel consumption 

by all motor vehicles. Fuel consumption 

is estimated to increase by less than 

0.009 percent under Options 3b and 

Option 3, and less than 0.014 percent 

under Option 4a. 

TABLE XV–1—ENERGY USE ASSOCIATED WITH ELG OPTIONS 3a, 3b, 3, AND 4a 

Non-water quality impact 

Energy use associated with proposed rule 

Option 3a Option 3b Option 3 Option 4a 

Electrical Energy Usage (MWh) ...................................................................... 112,000 160,753 303,300 472,369 

Fuel (Thousand Gallons) ................................................................................. 2,867 2,903 3,040 4,618

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 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 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 on- or 

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 


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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 4a) are shown in Tables XV–2 

through XV–5. To provide some 

perspective on the potential changes in 

annual air emissions, 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 through XV–4 present the 

estimated 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 4a. See DCN SE02025 (Steam 

Electric Effluent Guidelines Non-Water 

Quality Impacts) in the record for this 

rulemaking for more information. 

TABLE XV–2—AIR EMISSIONS ASSOCIATED WITH BAT/PSES OPTION 3a 

Non-water quality 

impact 

Value associated 

with option 3a 

(million tons) 

2009 Emissions by 

electric power 

industry 

(million tons) 

Increase in 

emissions 

(%) 

NOX .......................................................................................................... a 0.000088–0.00109 1 0.0088–0.109 

SOX .......................................................................................................... b <0.000084 6 <0.0014 

CO2 .......................................................................................................... b <0.130 2,403 <0.0054 

aEPA 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. bEPA 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). 

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 .......................................................................................................... a 0.00011–0.00111 1 0.011–0.111 

SOX .......................................................................................................... b <0.00013 6 <0.0021 

CO2 .......................................................................................................... b <0.149 2,403 <0.0062 

aEPA 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. bEPA 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–5—AIR EMISSIONS ASSOCIATED WITH BAT/PSES OPTION 4a 

Non-water quality impact 

Value associated 

with option 4a 

(million tons) 

2009 Emissions by 

electric power industry 

(million tons) 

Increase in emissions 

(%) 

NOX .......................................................................................................... a 0.00132 1 0.132 

SOX .......................................................................................................... a <¥0.00258 6 <¥0.043 

CO2 .......................................................................................................... a <¥1.106 2,403 <¥0.046 

aEPA 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 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. 


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90As 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. 

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 4a) 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 this 

rulemaking for more information. 

To provide some perspective on the 

potential increase in annual solid waste 

generation associated with the preferred 

BAT/PSES regulatory options, EPA 

compared the estimated increase in 

solid waste generation for Options 3b, 3, 

and 4a 90 to the amount of solids 

generated in a year by electric power 

plants throughout the United States— 

approximately 134 billion tons. The 

increase in solid waste generation 

associated with Options 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. 

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 technology 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 

Effluent Guidelines Non-Water Quality 

Impacts, located in the record for this 

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 this rulemaking, provides more 

information. 

EPA estimates that power plants 

would reduce the use of water by 50 

billion gallons per year (136 million 

gallons per day) under Option 3a, by 52 

billion gallons per year (143 million 

gallons per day) under Option 3b, by 53 

billion gallons per year (144 million 

gallons per day) under Option 3, 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. This 

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 technologybased effluent limitations guidelines 

and standards in this rule, section 

301(b)(1)(C) of CWA requires the 

permitting authority to 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 eight 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 finds 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. 

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 eight main 

regulatory options would apply to 

discharges of FGD wastewater, fly ash 


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91Except where BAT is equivalent to BPT. 

92Similarly applies to PSES and PSNS. 

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, 2017.91 As proposed today, for 

direct dischargers such wastewater 

generated prior to that date (i.e., 

‘‘legacy’’ wastewater) would remain 

subject to the existing BPT effluent 

limits. EPA is also considering 

establishing BAT effluent limitations for 

legacy wastewater (except gasification 

wastewater) that would be equal to the 

existing BPT effluent limits. 

4. 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 eight main regulatory options in this 

proposed rule could require internal 

monitoring points. Section 14 of the 

TDD provides detailed discussion for 

various types of configurations. The 

following provides selected information 

from the TDD: 

• FGD wastewater: Where an option 

proposes BAT/NSPS limitations for FGD 

wastewater that are not equal to existing 

BPT limitations,92 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 this 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 tankbased 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 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. 

• 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. 

For example, many plants currently 

treat their fly ash transport water in an 

onsite fly ash impoundment. In this 

case, under any 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 zero discharge requirement by 

showing that no fly ash transport water 

is generated after the date 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 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. 

• 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). 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 the proposed requirements, some 

plants may choose to install a tankbased 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34524 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

93For 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.’’ 

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 the 

proposed requirements, EPA envisions 

some plants may choose to install tankbased 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 tank-based 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 this notice. 

EPA is providing notice of standard 

operating procedures (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 

modification allowed under 40 CFR part 

136.6. See DCN SE03835 and DCN 

SE03868 for the SOPs and information 

on EPA’s development of the SOPs. 

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 eight main regulatory options in this 

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 level 93

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 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 

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 

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 


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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 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 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 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 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 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. 

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 

costs b

Total 

monetized 

benefits cde

Option 3a .......... $185.2 (e) 

Option 1 ............ 268.3 $82.0 

Option 3b .......... 281.4 (e) 

Option 2 ............ 386.8 111.7 

Option 3 ............ 572.0 311.7 

Option 4a .......... 954.1 (e) 

Option 4 ............ 1,381.2 605.5 

Option 5 ............ 2,328.8 434.1 

aAll costs and benefits were annualized 

over 24 years and using a 3 percent discount 

rate. bTotal 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. 

dEPA 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. eEPA 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 

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 

technology-based 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 sitespecific conditions can spend 

significant time 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 this 

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 onetime 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 

this 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. 

1. Definition of Small Entities and 

Estimation of the Number of Small 

Entities Subject to These Proposed ELGs 

For purposes of assessing the impacts 

of this 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-forprofit 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 GENERATION a

NAICS Code NAICS description SBA size standard b

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 revenue.c

a Certain plants affected by this rulemaking are owned by non-government entities whose primary business is not electric power generation. bBased on size standards effective at the time EPA conducted this analysis (SBA size standards, effective October 1, 2012). 

cEPA 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 sampleweighting 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. 

EPA estimates that 243 to 507 entities 

own steam electric plants subject to this 

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 eight 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 plants b

Upper bound estimate of number of entities 

owning steam electric plants b

Total Small c % Small Total Small c % 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 

Federal a ................................................... 2 0 0.0 4 0 0.0 

State a ....................................................... 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. 


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bOf 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. cEPA 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 eight 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 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 these 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. 

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 sampleweighting 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. 

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] 

Regulatory option 

Cost ≥1% of revenue Cost ≥3% of revenue 

Number of small 

entities 

% of small affected entities b

Number of small 

entities a

% of small affected entities b

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 

Option 2 ........................................................................................... 5 5.2 3 3.1 

Option 3 ........................................................................................... 5 5.2 3 3.1 

Option 4a ......................................................................................... 6 6.2 4 4.1 

Option 4 ........................................................................................... 12 12.4 4 4.1 

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 

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 7.1 7 4.1 

aThe 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. bPercentage values were calculated relative to the total of 97 (Case 1) and 170 (Case 2) small entities owning steam electric plants. 


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As reported in Table XVII–4, EPA 

estimates that between 0 and 12 small 

entities owning steam electric plants 

will incur costs exceeding 1 percent of 

revenue, and that between 0 and 7 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, and 3 small entities 

have costs exceeding 3 percent of 

revenue. Under Option 4a, 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 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 cooperatives 

and 3 municipalities. Under Option 4a, 

2 cooperatives and 4 municipalities 

have costs 1 percent of revenue or 

greater. The cost-to-revenue test is one 

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 4a), BY OWNERSHIP TYPE (EXCLUDING THOSE BELOW

THE SIZE THRESHOLD) a

Regulatory 

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 

entities 

% of small 

affected 

entities c

Number 

of small 

entities b

% of small 

affected 

entities c

Number 

of small 

entities 

% of small 

affected 

entities c

Number of 

small 

entities b

% of small 

affected 

entities c

Option 3: 

Cooperative ....... 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 

Municipality .... 3 8.1 1 2 .7 3 6.5 1 2.2 

Nonutility 0 0.0 0 0 .0 0 0.0 0 0.0 

Other Political 

Subdivision ...... 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 4a: 

Cooperative ....... 2 15.4 2 15 .4 2 9.4 2 9.4 

InvestorOwned 0 0.0 0 0 .0 0 0.0 0 0.0 

Municipality .... 4 10.8 2 5 .4 4 8.7 2 4.4 

Nonutility 0 0.0 0 0 .0 0 0.0 0 0.0 

Other Political 

Subdivision ...... 0 0.0 0 0 .0 0 0.0 0 0.0 

Total 6 6.2 4 4 .1 6 3.5 4 2.4 

aOptions 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. bThe 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. cPercentage 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 non-surveyed 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 4a) 

support a finding of no significant 

impact on a substantial number of small 

entities (No SISNOSE). 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 Table 

XVII–5). For more details on this 


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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). 

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 technologybased approaches. As discussed in 

detail in Section VIII, EPA is proposing 

Options 3a, 3b, 3 and 4a as the preferred 

BAT and PSES options because they are 

technologically available, economically 

achievable, and have acceptable nonwater quality environmental impacts. 

EPA is proposing Option 4 as the 

preferred NSPS and PSNS option 

because it is technologically available 

and demonstrated, poses no barrier to 

entry, and has 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 governmentowned facilities or for small nongovernment-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. 

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 less 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 3a, six plants incur 

compliance costs under Option 3b, 14 

plants incur compliance costs under 

Option 3, and 15 plants incur 

compliance costs under Option 4a. EPA 

estimates that the maximum compliance 

cost in any one year to governments 

(excluding federal government) for the 

eight regulatory options ranges from 

$13.8 million under Option 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 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 


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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 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 these 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 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 Web site at this link: http:// 

water.epa.gov/scitech/wastetech/guide/ 

steam_index.cfm#point8. 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 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 these proposed ELGs. 

The potentially significant effects of this 

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 this 

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. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

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. 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 

these proposed ELGs will have potential 

environmental justice concerns in the 

areas affected by steam electric plant 


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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 

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) 

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 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 nonadjoining 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 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. 

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. 


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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. 

List of Subjects 40 CFR Part 423 

Environmental protection, Electric 

power generation, Power plants, Waste 

treatment and disposal, Water pollution 

control. 

Dated: April 19, 2013. 

Bob Perciasepe, 

Acting Administrator. 

Therefore, 40 CFR chapter I is 

proposed to be amended as follows: 

PART 423—STEAM ELECTRIC POWER 

GENERATING POINT SOURCE 

CATEGORY 

■ 1. The authority citation for part 423 

is revised to read as follows: 

Authority: Secs. 101; 301; 304(b), (c), (e), 

and (g); 306; 307; 308 and 501, Clean Water 

Act (Federal Water Pollution Control Act 

Amendments of 1972, as amended; 33 U.S.C. 

1251; 1311; 1314(b), (c), (e), and (g); 1316; 

1317; 1318 and 1361). 

■ 2. Section 423.10 is revised as follows: 

§ 423.10 Applicability. 

The provisions of this part apply to 

discharges resulting from the operation 

of a generating unit by an establishment 

whose generation of electricity is the 

predominant source of revenue or 

principal reason for operation, and 

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 §§ 423.15(a) and 

423.17(a) of this part continue to be 

subject to those standards. Units that 

qualify as 1982 new sources are also 

subject to revised BAT effluent 

limitations specified in § 423.13 of this 

part (for direct dischargers) or the 

revised pretreatment standards specified 

in § 423.16 of this part (for indirect 

dischargers). These revised 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); and 

■ b. Adding paragraphs (n) through (u). 

The revised and added paragraphs 

read as follows: 

§ 423.11 Specialized definitions. 

* * * * * 

(b) The term low volume waste 

sources means, taken collectively as if 

from one source, wastewater from all 

sources except those for which specific 

limitations 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 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. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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■ 4. Section 423.12 is amended by: 

■ a. Revising paragraphs (b)(11) and 

(12); and 

■ b. Adding paragraph (b)(13). 

The revised and added paragraphs 

read as follows: 

§ 423.12 Effluent limitations guidelines 

representing the degree of effluent 

reduction attainable by the application of 

the best practicable control technology 

currently available (BPT). 

* * * * * 

(b) * * * 

(11) The quantity of pollutants 

discharged in FGD wastewater, flue gas 

mercury control wastewater, 

combustion residual leachate, or 

gasification wastewater shall not exceed 

the quantity determined by multiplying 

the flow of the applicable wastewater 

times the concentration listed in the 

following table: 

Pollutant or pollutant property 

BPT effluent limitations 

Maximum for 

any 1 day 

(mg/l) 

Average of daily 

values for 30 

consecutive days 

shall not exceed 

(mg/l) 

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

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

(12) At the permitting authority’s 

discretion, the quantity of pollutant 

allowed to be discharged may be 

expressed as a concentration limitation 

instead of the any mass based 

limitations specified in paragraphs 

(b)(3) through (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. Adding paragraph (f); 

■ b. Revising paragraphs (g) and (h); and 

■ c. Adding paragraphs (i) through (n). 

§ 423.13 Effluent limitations guidelines 

representing the degree of effluent 

reduction attainable by the application of 

the best available technology economically 

achievable (BAT). 

* * * * * 

(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: 

Pollutant or pollutant property 

BAT effluent limitations 

Maximum for any 

1 day 

(mg/l) 

Average of daily 

values for 30 

consecutive days 

shall not exceed 

(mg/l) 

Copper, total ................................................................................................................................................ 1.0 1.0 

Iron, total ...................................................................................................................................................... 1.0 1.0 

(2) For those discharges of 

nonchemical metal cleaning waste that 

are currently authorized pursuant to 

limitations based on requirements in 

§ 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 

§ 423.12(b)(3). 

(g)(1) Except for those discharges to 

which paragraph (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 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 

Selenium, total (ug/L) .............................................................................................................................. 16 10 

Nitrate/nitrate as N (mg/L) ....................................................................................................................... 0 .17 0 .13 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
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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 oil-fired unit, the quantity of 

pollutants discharged in FGD 

wastewater shall not exceed the 

quantity determined by multiplying the 

flow of FGD wastewater times the 

concentration listed in § 423.12(b)(11). 

(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. 

Note to (g): All proposed revisions to 

§ 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 sitespecific basis using best professional 

judgment. 

(h)(1) Except for those discharges to 

which paragraph (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 

§ 423.12(b)(4). 

(i)(1) Except for those discharges to 

which paragraph (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 

§ 423.12(b)(11). 

(j)(1) Except for those discharges to 

which paragraph (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) 

Mercury, total (ng/L) ................................................................................................................................ 1 .76 1 .29 

Selenium, total (ug/L) .............................................................................................................................. 453 227 

Total dissolved solids (mg/L) ................................................................................................................... 38 22 

1This 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 

§ 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 

paragraph (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 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 paragraph. 

(2) For any electric generating unit 

with a total nameplate generating 

capacity of less than or equal to 400 

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 

§ 423.12(b)(4). 

Note to (k): All proposed revisions to 

§ 423.13(k) reflect proposed Option 4a, only. 

Under proposed Option 3, Option 3a, and 

Option 3b, § 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 

§ 423.12(b)(4). 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34536 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

(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 § 423.12(b)(11). 

(m) At the permitting authority’s 

discretion, the quantity of pollutant 

allowed to be discharged may be 

expressed as a concentration limitation 

instead of any mass based limitations 

specified in paragraphs (b) through (l) of 

this section. Concentration limitations 

shall be those concentrations specified 

in this section. 

(n) In the event that wastestreams 

from various sources are combined for 

treatment or discharge, the quantity of 

each pollutant or pollutant property 

controlled in paragraphs (a) through (m) 

of this section attributable to each 

controlled waste source shall not exceed 

the specified limitation for that waste 

source. 

■ 6. Section 423.15 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 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 § 423.13 of this 

part, published on [insert date of 

publication of final rule]: 

(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: 

NSPS 

Pollutant or 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 

(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]. 

(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 pollutant property 

NSPS 

Maximum for 

any1 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)(i) 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: 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 34537 

Pollutant or pollutant property 

NSPS 

Maximum 

concentrations 

(mg/l) 

Total residual chlorine ........ 0.20 

(ii) 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)(i) For any plant with a total rated 

generating capacity of less than 25 

megawatts, the quantity of pollutants 

discharged in once through cooling 

water shall not exceed the quantity 

determined by multiplying the flow of 

once through cooling water sources 

times the concentration listed in the 

following table: 

Pollutant or pollutant property 

Maximum 

concentration 

(mg/l) 

Average 

concentration 

(mg/l) 

Free available chlorine ................................................................................................................................ 0.5 0.2 

(ii) Neither free available chlorine nor 

total residual chlorine may be 

discharged from any unit for more than 

two hours in any one day and not more 

than one unit in any plant may 

discharge free available or total residual 

chlorine at any one time unless the 

utility can demonstrate to the Regional 

Administrator or State, if the State has 

NPDES permit issuing authority, that 

the units in a particular location cannot 

operate at or below this level of 

chlorination. 

(10)(i) 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 

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 

concentration 

(mg/l) 

Average of daily 

values for 30 

consecutive days 

shall not exceed 

(mg/l) 

The 126 priority pollutants (Appendix A) contained in chemicals added for cooling tower maintenance, 

except: ...................................................................................................................................................... (1) (1) 

Chromium, total ........................................................................................................................................... 0.2 0.2 

Zinc, total ..................................................................................................................................................... 1.0 1.0 

1 No detectable amount. 

(ii) Neither free available chlorine nor 

total residual chlorine may be 

discharged from any unit for more than 

two hours in any one day and not more 

than one unit in any plant may 

discharge free available or total residual 

chlorine at any one time unless the 

utility can demonstrate to the Regional 

Administrator or State, if the State has 

NPDES permit issuing authority, that 

the units in a particular location cannot 

operate at or below this level of 

chlorination. 

(iii) At the permitting authority’s 

discretion, instead of the monitoring in 

40 CFR 122.11(b), compliance with the 

limitations for the 126 priority 

pollutants in paragraph (a)(10)(i) of this 

section may be determined by 

engineering calculations which 

demonstrate that the regulated 

pollutants are not detectable in the final 

discharge by the analytical methods in 

40 CFR part 136. 

(11) Subject to the provisions of 

§ 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 § 423.15(a)(11). 

(13) At the permitting authority’s 

discretion, the quantity of pollutant 

allowed to be discharged may be 

expressed as a concentration limitation 

instead of any mass based limitations 

specified in paragraphs (a)(3) through 

(a)(10) of this section. Concentration 

limits shall be based on the 

concentrations specified in this section. 

(14) In the event that wastestreams 

from various sources are combined for 

treatment or discharge, the quantity of 

each pollutant or pollutant property 

controlled in paragraphs (a)(1) through 

(a)(13) of this section attributable to 

each controlled waste source shall not 

exceed the specified limitation for that 

waste source. 

(The information collection requirements 

contained in paragraphs (a)(8)(ii), (a)(9)(ii), 

and (a)(10)(ii) were approved by the Office of 

Management and Budget under control 

number 2040–0040. The information 

collection requirements contained in 

paragraph (a)(10)(iii) 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34538 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

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. 

(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) 

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)(i) 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 

(ii) Total residual chlorine may not be 

discharged from any single generating 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 34539 

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)(i) For any plant with a total rated 

generating capacity of less than 25 

megawatts, the quantity of pollutants 

discharged in once through cooling 

water shall not exceed the quantity 

determined by multiplying the flow of 

once through cooling water sources 

times the concentration listed in the 

following table: 

Pollutant or pollutant property 

NSPS 

Maximum 

concentration 

(mg/l) 

Average 

concentration 

(mg/l) 

Free available chlorine ................................................................................................................................ 0.5 0.2 

(ii) Neither free available chlorine nor 

total residual chlorine may be 

discharged from any unit for more than 

two hours in any one day and not more 

than one unit in any plant may 

discharge free available or total residual 

chlorine at any one time unless the 

utility can demonstrate to the Regional 

Administrator or State, if the State has 

NPDES permit issuing authority, that 

the units in a particular location cannot 

operate at or below this level of 

chlorination. 

(10)(i) The quantity of pollutants 

discharged in cooling tower blowdown 

shall not exceed the quantity 

determined by multiplying the flow of 

cooling tower blowdown times the 

concentration listed below: 

Pollutant or pollutant property 

NSPS 

Maximum 

concentration 

(mg/l) 

Average 

concentration 

(mg/l) 

Free available chlorine ................................................................................................................................ 0.5 0.2 

Pollutant or pollutant property 

Maximum for 

any 1 day 

(mg/l) 

Average of daily 

values for 30 

consecutive days 

shall not exceed 

(mg/l) 

The 126 priority pollutants (Appendix A) contained in chemicals added for cooling tower maintenance, 

except: ...................................................................................................................................................... (1) (1) 

Chromium, total ........................................................................................................................................... 0.2 0.2 

Zinc, total ..................................................................................................................................................... 1.0 1.0 

1 No detectable amount. 

(ii) Neither free available chlorine nor 

total residual chlorine may be 

discharged from any unit for more than 

two hours in any one day and not more 

than one unit in any plant may 

discharge free available or total residual 

chlorine at any one time unless the 

utility can demonstrate to the Regional 

Administrator or State, if the State has 

NPDES permit issuing authority, that 

the units in a particular location cannot 

operate at or below this level of 

chlorination. 

(iii) 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)(i) of this 

section may be determined by 

engineering calculations which 

demonstrate that the regulated 

pollutants are not detectable in the final 

discharge by the analytical methods in 

40 CFR part 136. 

(11) Subject to the provisions of 

§ 423.15(b)(12), the quantity or quality 

of pollutants or pollutant parameters 

discharged in coal pile runoff shall not 

exceed the 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 § 423.15(b)(11). 

(13)(i) The quantity of pollutants 

discharged in FGD wastewater shall not 

exceed the quantity determined by 

multiplying the flow of FGD wastewater 

times the concentration listed in the 

following table: 

Pollutant or pollutant property 

NSPS 

Maximum for 

any1 day 

(mg/l) 

Average of daily 

values for 30 

consecutive days 

shall not exceed 

Arsenic, total (ug/L) ................................................................................................................................. 8 6 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34540 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

Pollutant or pollutant property 

NSPS 

Maximum for 

any1 day 

(mg/l) 

Average of daily 

values for 30 

consecutive days 

shall not exceed 

Mercury, total (ng/L) ................................................................................................................................ 242 119 

Selenium, tota (ug/L) ............................................................................................................................... 16 10 

Nitrate/nitrite as N (mg/L) ........................................................................................................................ 0 .17 0 .13 

(ii) A discharger must demonstrate 

compliance with the standards in 

paragraph (b)(13)(i) 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)(i) The quantity of pollutants 

discharged in gasification wastewater 

shall not exceed the quantity 

determined by multiplying the flow of 

gasification wastewater times the 

concentration listed in the following 

table: 

Pollutant or pollutant property 

NSPS 

Maximum for 

any 1 day 

Average ff daily 

values for 30 

consecutive days 

shall not exceed 

Arsenic, total (ug/L) ................................................................................................................................. 4 (1) 

Mercury, total (ng/L) ................................................................................................................................ 1 .76 1 .29 

Selenium, total (ug/L) .............................................................................................................................. 453 227 

Total dissolved solids (mg/L) ................................................................................................................... 38 22 

1This regulation does not specify this type of limitation for this pollutant; however, permitting authorities may do so as appropriate. 

(ii) A discharger must demonstrate 

compliance with the standards in 

paragraph (b)(15)(i) 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)(i) 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 

(ii) A discharger must demonstrate 

compliance with the standards in 

paragraph (b)(16)(i) 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 any mass based limitations 

specified in paragraphs (b)(3) through 

(b)(16) of this section. Concentration 

limits shall be based on the 

concentrations specified in this section. 

(18) In the event that wastestreams 

from various sources are combined for 

treatment or discharge, the quantity of 

each pollutant or pollutant property 

controlled in paragraphs (b)(1) through 

(b)(16) of this section attributable to 

each controlled waste source shall not 

exceed the specified limitation for that 

waste source. 

■ 7. Section 423.16 is amended by 

adding paragraphs (c) and (e) through (i) 

to read as follows: 

§ 423.16 Pretreatment standards for 

existing sources (PSES). 

* * * * * 

(c) Except 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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 34541 

the concentration listed in the following 

table: 

Pollutant or pollutant 

property 

PSES 

pretreatment 

standards 

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 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 

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. 

Note to (e): 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 CFR 

403.5(c)(2). 

(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 400 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. 

Note to (g): All proposed revisions to 

section 423.16(g) reflect proposed Option 4a, 

only. For proposed Option 3, Option 3a, and 

Option 3b, the regulations would not specify 

a PSES for bottom ash transport water. 

(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 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) 

Mercury, total (ng/L) ................................................................................................................................ 1 .76 1 .29 

Selenium, total (ug/L) .............................................................................................................................. 453 227 

Total dissolved solids (mg/L) ................................................................................................................... 38 22 

1This regulation does not specify this type of limitation for this pollutant; however, permitting authorities may do so as appropriate. 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
34542 Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 

(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. 

■ 8. Section 423.17 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 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 § 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. 

(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]. 

(4)(i) The pollutants discharged in 

cooling tower blowdown shall not 

exceed the concentration listed in the 

following table: 

Pollutant or pollutant 

property 

PSNS 

Maximum for 

any time 

(mg/l) 

The 126 priority pollutants 

(Appendix A) contained in 

chemicals added for cooling tower maintenance, 

except: ............................. (1) 

Chromium, total .................. 0.2 

Zinc, total ............................ 1.0 

1 No detectable amount. 

(ii) At the permitting authority’s 

discretion, instead of the monitoring in 

40 CFR 122.11(b), compliance with the 

limitations for the 126 priority 

pollutants in paragraph (a)(4)(i) of this 

section may be determined by 

engineering calculations which 

demonstrate that the regulated 

pollutants are not detectable in the final 

discharge by the analytical methods in 

40 CFR part 136. 

(5) 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): 

(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)(i) The pollutants discharged in 

cooling tower blowdown shall not 

exceed the concentration listed in the 

following table: 

Pollutant or pollutant 

property 

PSNS 

Maximum for 

any time 

(mg/l) 

The 126 priority pollutants 

(Appendix A) contained in 

chemicals added for cooling tower maintenance, 

except: ............................. (1) 

Chromium, total .................. 0.2 

Zinc, total ............................ 1.0 

1 No detectable amount. 

(ii) At the permitting authority’s 

discretion, instead of the monitoring in 

40 CFR 122.11(b), compliance with the 

limitations for the 126 priority 

pollutants in paragraph (b)(4)(i) of this 

section may be determined by 

engineering calculations which 

demonstrate that the regulated 

pollutants are not detectable in the final 

discharge by the analytical methods in 

40 CFR part 136. 

(5) 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)(i) The quantity of pollutants 

discharged in FGD wastewater shall not 

exceed the quantity determined by 

multiplying the flow of FGD wastewater 

times the concentration listed in the 

following table: 

Pollutant or 

pollutant property 

PSNS 

Maximum for 

any 1 day 

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 


tkelley on DSK3SPTVN1PROD with PROPOSALS2
Federal Register / Vol. 78, No. 110 / Friday, June 7, 2013 / Proposed Rules 34543 

(ii) A discharger must demonstrate 

compliance with the standards in 

paragraph (b)(6)(i) 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. 

(9)(i) The quantity of pollutants 

discharged in gasification wastewater 

shall not exceed the quantity 

determined by multiplying the flow of 

gasification wastewater times the 

concentration listed in the following 

table: 

Pollutant or 

pollutant property 

PSNS 

Maximum for 

any 1 day 

Arsenic, total (ug/L) ................................................................................................................................. 4 (1) 

Mercury, total (ng/L) ................................................................................................................................ 1 .76 1 .29 

Selenium, total (ug/L) .............................................................................................................................. 453 227 

Total dissolved solids (mg/L) ................................................................................................................... 38 22 

1This regulation does not specify this type of limitation for this pollutant; however, permitting authorities may do so as appropriate. 

(ii) A discharger must demonstrate 

compliance with the standards in 

paragraph (b)(9)(i) 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)(i) 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 

Arsenic, total (ug/L) ..................................................................................................................................... 8 6 

Mercury, total (ng/L) .................................................................................................................................... 242 119 

(ii) A discharger must demonstrate 

compliance with the standards in 

paragraph (b)(10)(i) 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. 

* * * * * 

[FR Doc. 2013–10191 Filed 6–6–13; 8:45 am] 

BILLING CODE 6560–50–P 


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