[Federal Register Volume 78, Number 110 (Friday, June 7, 2013)]
[Proposed Rules]
[Pages 34431-34543]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-10191]



[[Page 34431]]

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

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

[[Page 34432]]


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

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 technology-based 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

[[Page 34433]]

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

------------------------------------------------------------------------
                                                        North American
                                                           industry
           Category             Example of regulated    classification
                                       entity           system (NAICS)
                                                             code
------------------------------------------------------------------------
Industry.....................  Electric Power                      22111
                                Generation
                                Facilities--Electric
                                Power Generation.
                               Electric Power                     221112
                                Generation
                                Facilities--Fossil
                                Fuel Electric Power
                                Generation.
                               Electric Power                     221113
                                Generation
                                Facilities--Nuclear
                                Electric Power
                                Generation.
------------------------------------------------------------------------

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

How to Submit Comments

    The public may submit comments in written or electronic form. (See 
the ADDRESSES section above.) Electronic comments must be identified by 
the Docket No. [EPA-HQ-OW-2009-0819] and must be submitted as a MS 
Word, WordPerfect, or ASCII text file, avoiding the use of special 
characters and any form of encryption. EPA requests that any graphics 
included in electronic comments also be provided in hard-copy form. EPA 
also will accept comments and data on disks in the aforementioned file 
formats. Electronic comments received on this notice may be 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

[[Page 34434]]

    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 Plant-Specific Costs
    B. Methodology for Estimating Plant-Specific Pollutant 
Reductions
    1. FGD Wastewater
    2. Fly Ash and Bottom Ash
    3. Combustion Residual Leachate
    4. FGMC and Gasification Wastewaters and Nonchemical Metal 
Cleaning Wastes
    C. Summary of National Engineering Costs and Pollutant 
Reductions for Existing Plants
    X. Approach to Determine Long-Term Averages, Variability 
Factors, and Effluent Limitations and Standards
    A. Criteria Used to Select Data as the Basis for the Limitations 
and Standards
    B. Data Used As Basis of the Limitations and Standards
    1. Data Selection for Each Technology Option
    2. Combining Data from Multiple Sources Within a Plant
    3. Data Exclusions
    C. Overview of the Limitations and Standards
    1. Objective
    2. Selection of Percentiles
    D. Calculation of the Limitations and Standards
    1. Calculation of Option Long-Term Average
    2. Calculation of Option Variability Factors and Limitations
    3. Adjustment for Autocorrelation Factors
    E. Long-Term Average, Variability Factors, and Limitations for 
Each Treatment Option
    F. Engineering Review of Limitations and Standards
    1. Comparison of Limitations to Effluent Data Used As the Basis 
for the Limitations
    2. Comparison of the Limitations to Influent Data
XI. Economic Impact and Social Cost Analysis
    A. Introduction
    B. Annualized Compliance Costs
    C. Social Costs
    D. Economic Impacts
    1. Screening-level Assessment of Impacts on Existing Plants and 
Parent Entities Incurring Compliance Costs Associated with this 
Proposed Rule
    2. Assessment of the Impacts in the Context of Electricity 
Markets
    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

[[Page 34435]]

    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 non-cancer 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 oil-fired 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:

[[Page 34436]]

     ``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
---------------------------------------------------------------------------

    \1\ As described in Section VIII, EPA is proposing to exempt 
from new copper and iron BAT limitations any existing discharges of 
nonchemical metal cleaning wastes that are currently authorized 
without iron and copper limits. For these discharges, BAT limits 
would be set equal to BPT limits applicable to low volume wastes.
---------------------------------------------------------------------------

     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 nitrate-nitrite in 
discharges of FGD wastewater from certain steam electric facilities 
(those with a total plant-level wet scrubbed capacity of 2,000 MW or 
greater \2\). All other proposed Option 3b requirements are identical 
to the proposed 3a requirements described above.
---------------------------------------------------------------------------

    \2\ Total plant-level wet scrubbed capacity is calculated by 
summing the nameplate capacity for all of the units that are 
serviced by wet FGD systems.
---------------------------------------------------------------------------

    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 nitrate-nitrite in 
discharges of FGD wastewater, with the exception of small generating 
units (i.e., 50 MW or smaller). All other proposed Option 3 
requirements are identical to the proposed Option 3a requirements 
described above.
    Under a fourth preferred alternative for BAT (referred to as Option 
4a in this proposal), the proposed rule would establish ``zero 
discharge'' effluent limits for all pollutants in bottom ash transport 
water, 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.
---------------------------------------------------------------------------

    \3\ As described in Section VIII, one of the preferred options 
would increase this threshold for purposes of discharges of 
pollutants in bottom ash transport water only, to 400 MW or less.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \4\ As described in Section VIII, EPA is proposing to exempt 
from new copper PSES standards any existing discharges of 
nonchemical metal cleaning wastes that are currently authorized 
without copper limits. For these discharges, the regulations would 
not specify PSES.
---------------------------------------------------------------------------

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

    \5\ This 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.
---------------------------------------------------------------------------

     Other than the pretreatment standards for nonchemical 
metal cleaning wastes, EPA is not proposing to establish pretreatment 
standards for existing sources for discharges from existing oil-fired 
units and small generating units (i.e., 50 MW or smaller).
    Discharges directly to surface water from new sources--For all 
generating units that are new sources and discharge directly to surface 
waters, including oil-fired generating and small 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.
---------------------------------------------------------------------------

    \6\ EPA 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.
---------------------------------------------------------------------------

    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

[[Page 34437]]

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$]
----------------------------------------------------------------------------------------------------------------
                                                      Total monetized social            Total social costs
                                                             benefits            -------------------------------
        Preferred regulatory alternatives        --------------------------------
                                                        3%              7%              3%              7%
----------------------------------------------------------------------------------------------------------------
Option 3a for Existing Sources; Option 4 for New       \a\ 139.4       \a\ 104.8          $185.2          $164.5
 Sources........................................
Option 3b for Existing Sources; Option 4 for New       \a\ 205.5       \a\ 153.0           281.4           257.2
 Sources........................................
Option 3 for Existing Sources; Option 4 for New           $311.7          $230.4           572.0           545.3
 Sources........................................
Option 4a for Existing Sources; Option 4 for New       \a\ 482.5       \a\ 424.8           954.1           914.7
 Sources........................................
----------------------------------------------------------------------------------------------------------------
\a\ EPA did not estimate benefits for Options 3a, 3b and 4a. EPA inferred benefits for Options 3a, 3b, and 4a
  for illustrative purposes using elements of the more rigorous analysis done to estimate benefits for Options 3
  and 4. See Section XIV for details.

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., 
ammonia-N, phosphorus, and total dissolved solids).

B. Effluent Guidelines Program

    EPA develops effluent guidelines that are technology-based 
regulations for a category of dischargers. EPA bases these regulations 
on the performance of control and treatment technologies. The 
legislative history of CWA section 304(b), which is the heart of the 
effluent guidelines program, describes the need to press toward higher 
levels of control through research and development of new processes, 
modifications, replacement of obsolete 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

[[Page 34438]]

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 technology-
based and are analogous to BPT and BAT effluent limitations guidelines, 
and thus the Agency typically considers the same factors in 
promulgating PSES as it considers in promulgating BAT. The General 
Pretreatment Regulations, which set forth the framework for the 
implementation of categorical pretreatment standards, are found at 40 
CFR part 403. These regulations establish pretreatment standards that 
apply to all non-domestic dischargers. See 52 FR 1586 (January 14, 
1987).
6. Pretreatment Standards for New Sources (PSNS)
    Section 307(c), 33 U.S.C. 1317(c), of the Act calls for EPA to 
promulgate PSNS. Such pretreatment standards must prevent the discharge 
of any pollutant into a POTW that may interfere with, pass through, or 
may otherwise be incompatible with the POTW. EPA promulgates PSNS based 
on best available demonstrated control technology (BADCT) for new 
sources. New indirect dischargers have the opportunity to incorporate 
into their facilities the best available demonstrated technologies. The 
Agency typically considers the same factors in promulgating PSNS as it 
considers in promulgating NSPS.

C. Steam Electric Effluent Guidelines Rulemaking History

    EPA promulgated BPT, BAT, NSPS, and PSNS for the steam electric 
point source category on October 8, 1974 (39 FR 36186, as amended at 40 
FR 7095, February 19, 1975; 40 FR 23987, June 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

[[Page 34439]]

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 once-through cooling water; BAT, NSPS, 
PSES, and PSNS for cooling tower blowdown; NSPS and PSNS for fly ash 
transport water; NSPS for bottom ash transport water; and PSES and PSNS 
for chemical metal cleaning wastes. Finally, the rule revised the 
definition of low volume wastes to include boiler blowdown and withdrew 
the separate regulation for boiler blowdown.

D. Steam Electric Detailed Study

    Section 304 of the CWA requires EPA to periodically review all 
effluent limitations guidelines and standards to determine whether 
revisions are warranted. In addition, Section 304(m) of the CWA 
requires EPA to develop and publish, biennially, a plan that 
establishes a schedule for reviewing and revising promulgated national 
effluent guidelines required by Section 304(b) of the CWA. During the 
2005 annual review of the existing effluent guidelines for all 
categories, EPA identified the regulations governing the steam electric 
power generating point 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.,

[[Page 34440]]

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 ozone-season 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 ozone-season 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 output-based 
standard of 1,000 pounds of carbon dioxide per MW-hour of electricity 
generated. EPA based this proposed standard on the performance of 
natural gas combined cycle technology because EPA and others project 
that even without this rule, for the foreseeable future, new fossil-
fuel-fired power plants will be built with that technology. New coal- 
or petroleum coke-fired generating units could meet the standard by 
using carbon capture and storage of approximately 50 percent of the 
carbon dioxide in the exhaust gas when the unit begins operating or by 
later installing more effective carbon capture and storage to meet the 
standard on average over a 30-year period. EPA is evaluating the public 
comments received on the proposal and has not determined a 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.

[[Page 34441]]

    In March 2011, EPA proposed standards to reduce injury and death of 
fish and other aquatic life caused by cooling water intake structures 
at existing power plants and manufacturing facilities. The proposed 
rule would subject existing power plants and manufacturing facilities 
withdrawing in excess of 2 MGD of cooling water to an upper limit on 
the number of fish destroyed through impingement, as well as site-
specific entrainment mortality standards. Certain plants that withdraw 
very large volumes of water would also be required to conduct studies 
for use by the permit writer in determining site-specific entrainment 
controls for such facilities. Finally, under the proposed rule, new 
generating units at existing power plants would be required to reduce 
the intake of cooling water associated with the new unit, to a level 
that could be attained by using a closed-cycle cooling system. EPA is 
continuing analysis and is in the process of addressing comments and 
finalizing the rule.

G. Coal Combustion Residuals (CCR) Proposed Rule

    CCRs are residues from the combustion of coal in steam electric 
power plants and include materials such as coal ash (fly ash and bottom 
ash) and FGD wastes. CCRs are currently exempt from the requirements of 
Subtitle C of the Resource Conservation and Recovery Act (RCRA), which 
governs the disposition and management of hazardous wastes. Potential 
environmental concerns regarding the management and disposal of CCR 
include pollution leaching from surface impoundments and landfills 
contaminating ground water and natural resource damages and risks to 
human health caused by structural failures of surface impoundments, 
like that which occurred at the Tennessee Valley Authority's plant in 
Kingston, Tennessee, in December 2008. The spill, which flooded more 
than 300 acres of land with CCRs and contaminated the Emory and Clinch 
rivers, emphasized the need for national standards to address risks 
associated with the disposal of CCRs.
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

[[Page 34442]]

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.

[[Page 34443]]

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 
coke-fired plants, EPA sent questionnaires to all plants that operate 
coal- or petroleum coke-fired generating units. For plants without any 
coal- or petroleum coke-fired generating units (i.e., gas, oil, or 
nuclear-fueled), EPA sent questionnaires to a statistically selected 
subset of the identified plants. EPA created four different versions of 
the questionnaire to send out to plants based on the different parts of 
the questionnaire:
     Version 1: Parts A through I;
     Version 2: Parts A, B, C, D, H, and I;
     Version 3: Parts A, B, C, D, E, H, and I; and
     Version 4: Parts A, E, H, and I.
    In June 2010, EPA mailed the surveys to 733 power plants. EPA 
mailed Version 1 of the questionnaire to 97 coal- and petroleum coke-
fired power plants, which is a subset of the total

[[Page 34444]]

number of coal- and petroleum coke-fired 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 EPA-sampled 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 one- or two-day sampling episodes at six plants to 
characterize untreated wastewaters generated by coal-fired power 
plants, as well as to obtain a preliminary assessment of treatment 
technologies and best management practices for reducing pollutant 
discharges. The types of wastewaters sampled during the detailed study 
were untreated and treated FGD wastewater, fly ash wastewater, and 
bottom ash wastewater.
    Upon completing the detailed study, EPA subsequently selected 13 
plants to collect additional wastewater characterization data and to 
evaluate wastewater treatment performance. Through this effort, EPA 
evaluated 10 FGD wastewater treatment systems; two gasification systems 
at integrated gasification combined cycle (IGCC) plants; and one pilot-
scale carbon capture system. EPA selected these FGD systems because at 
the time it believed all were among the better performing FGD 
wastewater treatment systems in the industry, based on information 
obtained during the site visits and discussions with industry 
representatives about the design/operation of the treatment system and 
optimization efforts performed at the plant. In addition, these plants 
represent geographic variability, different coal types (i.e., 
bituminous, subbituminous, coal blends), and different operating 
practices (e.g., baseload vs cycling). The selected IGCC systems and 
the pilot-scale carbon capture system were the only known systems 
operating in the U.S. power industry at the time of EPA's field 
sampling program.
    For the 13 plants sampled following completion of the detailed 
study, samples were collected as follows:
     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

[[Page 34445]]

     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 self-monitoring data, as 
well as NPDES Form 2C data. Specifically, EPA requested self-monitoring 
data from two power plants to support its calculation of pollutant 
loading reductions from FGD wastewater treatment technologies and to 
supplement the data from the EPA sampling program in the development of 
ELGs for the FGD wastewater. EPA also coordinated with UWAG to create a 
database of selected NPDES Form 2C data from UWAG's member companies. 
The NPDES Form 2C database contains information about the outfalls of 
coal-fired power plants that receive FGD, ash handling, or coal pile 
runoff wastestreams. EPA received Form 2C data from UWAG for 86 plants 
in late June 2008 and reviewed the data for use in developing the 
industry profile, in particular for ash wastewater treatment 
operations.

F. Technology Vendor Data

    EPA gathered data from technology vendors through presentations, 
conferences, meetings, and email and phone 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).
---------------------------------------------------------------------------

    \7\ EIA-860: Annual Electric Generator Report; EIA-861: Annual 
Electric Power Industry Database; EIA-923: Utility, Non-Utility, and 
Combined Heat & Power Plant Database (monthly).
---------------------------------------------------------------------------

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

[[Page 34446]]

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. Sec.  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

[[Page 34447]]

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 petroleum-coke power plants may generate all of those 
wastewaters. The wastestream that is most influenced by fuel selection 
is the ash transport water because the quantity and quality of ash 
generated from oil-fired units is different from that generated from 
coal- and petroleum coke-fired units. Additionally, the quantity and 
quality of ash differs based on the type of oil used in the boiler. For 
example, heavy or residual oils such as No. 6 fuel oil generate fly ash 
and may generate bottom ash, but lighter oils such as No. 2 fuel oil 
may not generate any ash.
    From an analysis of responses to the industry survey, EPA 
determined that 74 percent of the steam electric units in the industry 
burn more than one type of fuel (e.g., coal and oil, 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 oil-fired 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.
---------------------------------------------------------------------------

    \8\ As described in Section VIII, EPA is proposing to exempt 
from new copper and iron BAT limitations any existing discharges of 
nonchemical metal cleaning wastes that are currently authorized 
without iron and copper limits. For these discharges, BAT limits 
would be set equal to BPT limits applicable to low volume wastes.
---------------------------------------------------------------------------

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
------------------------------------------------------------------------
                                        Number of          Nameplate
        Primary fuel source          Generating units    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

[[Page 34448]]

 
    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 coke-fired power plants do not discharge any 
wastewater. Most of these zero discharge plants are located in the 
southwestern United States (e.g., Arizona) and use evaporation ponds to 
control the wastewater.

B. Steam Electric Process Descriptions and Wastewater Generation

    In the steam electric process, fuel is fed to a boiler where the 
fuel is combusted. The hot gases from combustion leave the boiler and 
pass through air pollution control systems prior to their emission 
through a stack. The resulting heat from combustion converts water to 
steam. The high-temperature, high-pressure steam leaves the boiler and 
enters the turbine generator where it drives the turbine blades as it 
moves from the high-pressure to the low-pressure stages of the turbine. 
The lower-pressure steam leaving the turbine enters the condenser, 
where steam vapor is cooled and condensed back into liquid by cooling 
water. The water collected in the condenser is sent back to the boiler 
where it is again converted to steam.
    Combined cycle systems consist of combustion turbine electric 
generating units operating in conjunction with steam turbine electric 
generating units. Combustion turbines, which typically are similar to 
jet engines, commonly use natural gas as the fuel. Combined cycle 
systems feed the fuel into a chamber 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

[[Page 34449]]

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 
coal-fired power plants operating wet FGD systems. Based on responses 
to the industry survey, the average FGD wastewater flow rate is 559,000 
gallons per day (gpd). EPA estimates that the 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\
---------------------------------------------------------------------------

    \9\ Because EPA expects to take final action on this rule in 
2014, EPA used 2014 as the baseline year for its analysis. EPA is 
considering using alternative dates, such as 2022 which may better 
reflect the implementation timeframe for the ELG, for the baseline 
year for its analyses for the final rule.
    \10\ This is not the number of steam electric power plants with 
wet FGD systems. An individual steam electric power plant may 
operate one or more FGD systems.
---------------------------------------------------------------------------

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

[[Page 34450]]

systems are currently in use in the industry: (1) Addition of oxidizers 
to the coal prior to combustion, whereby the oxidized mercury is 
removed in the wet FGD system; and (2) injection of activated carbon 
into the flue gas which adsorbs the mercury and is captured in a 
downstream particulate removal system.
    The use of the oxidizers does not generate a new wastewater stream; 
however, it may increase the concentration of mercury in the FGD 
wastewater because the oxidized mercury is more easily removed by the 
FGD system. The activated carbon injection system does have the 
potential to generate a new wastestream at a plant, depending on the 
location of the injection. If the injection occurs upstream of the 
primary particulate removal system, then the mercury-containing carbon 
(i.e., FGMC waste) is collected and handled the same way as the fly 
ash. Therefore, 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

[[Page 34451]]

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\
---------------------------------------------------------------------------

    \11\ In order to protect CBI claims, EPA cannot provide specific 
numbers.
---------------------------------------------------------------------------

    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 post-
combustion carbon capture system. Because of the small size of the 
pilot-scale system, the plant transferred the wastewater off site for 
treatment.

C. Control and Treatment Technologies

    EPA evaluated the technologies available to control and treat 
wastewater generated by the steam electric industry. Individual plants 
may use one or more processes that generate wastewater streams. They 
may treat these wastestreams separately or in various combinations. For 
this reason, EPA evaluated available technologies for each major 
wastestream separately.
1. FGD Wastewater
    EPA identified 145 steam electric power plants that generate FGD 
wastewater. Of these, 117 plants (81 percent) discharge FGD wastewater 
after treatment using one or more of the following technologies:
     Surface Impoundments: Surface impoundments (e.g., settling 
ponds), designed to remove particulates from wastewater by means of 
gravity, may be configured as one impoundment or a series of 
impoundments. Impoundments are typically sized to allow for a certain 
residence time to enable the suspended solids to settle to the bottom. 
The impoundments are also designed to have sufficient capacity to allow 
for temporary storage or permanent disposal of the settled solids. 
Surface impoundments are not designed to remove dissolved metals. 
Plants may add treatment chemicals to the impoundment, typically to 
adjust pH before final discharge.
    There are 63 plants (54 percent of the discharging plants) that use 
surface impoundments as the only type of treatment for FGD wastewaters. 
Most (49) of these plants also combine their FGD wastewater with other 
plant wastewater while the remainder (14) use impoundments to treat FGD 
wastewater 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

[[Page 34452]]

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.
---------------------------------------------------------------------------

    \12\ A seventh plant is scheduled to begin operating a 
biological treatment system for selenium removal in 2014. This plant 
is not included in this summary of biological treatment systems.
---------------------------------------------------------------------------

     Vapor-Compression Evaporation System: This type of system 
uses a falling-film evaporator (or brine concentrator) to produce a 
concentrated wastewater stream and a distillate stream. With 
pretreatment, such as chemical precipitation and softening, brine 
concentrators can reduce wastewater volumes by 80 to 90 percent. Plants 
can further process the concentrated wastewater stream in a 
crystallizer or spray dryer, which evaporates the remaining water to 
generate a solid waste product and potentially a condensate stream. The 
distillate and condensate streams may be reused within the plant or 
discharged to surface waters. EPA identified two U.S. plants and four 
Italian plants that treat FGD wastewater using vapor-compression 
evaporation. A third U.S. plant is currently installing a vapor-
compression evaporation treatment system; it is scheduled to be 
operational by the end of 2013.
     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 full-scale ion exchange system that 
selectively targets the removal of boron, in conjunction with a 
chemical precipitation treatment stage to remove mercury and other 
metals, and an anaerobic biological treatment stage to remove selenium. 
Another plant treats the FGD wastewater with chemical precipitation, 
followed by a full-scale treatment unit that uses cartridge filters in 
combination with two sets of adsorbent media specifically designed to 
enhance removals of metals. After passing through three sets of 
cartridge filters (3-micron, 1-micron, and then 0.2-micron), the FGD 
wastewater passes through a carbon-based media that adsorbs mercury, 
and then through a ferric hydroxide-based media that adsorbs arsenic, 
chromium, and other metals. The adsorbent media reportedly achieves a 
maximum effluent concentration of 14 parts per trillion for mercury.
     Design/Operating Practices Achieving Zero Discharge: EPA 
identified four design/operating practices available enabling plants to 
eliminate the discharge of wastewater 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

[[Page 34453]]

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 coal-fired units use mechanical 
drag systems for bottom ash handling. Operators have announced plans to 
retrofit mechanical drag systems on additional units by 2020. EPA 
estimates that these announced retrofits include approximately 10-30 
generating units. (Note: the precise value has been withheld to prevent 
disclosing CBI.)
     Remote Mechanical Drag System: These systems collect 
bottom ash in water-filled hoppers and wet sluice the ash to a 
mechanical drag system located away from the boilers. Sluice water 
collected from the dewatered bottom ash is collected and reused in the 
bottom ash handling system. Plants can use remote mechanical drag 
systems to convert existing bottom ash handling systems with limited 
space or other configuration limitations. 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

[[Page 34454]]

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

[[Page 34455]]

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, industry-supplied data including 
data provided in responses to the industry survey, and various 
literature sources. EPA relied primarily on its field sampling program 
data because the data were collected using consistent methods and 
analytical techniques for a broad range of pollutants. Therefore, where 
EPA had data from its field sampling program, it preferentially used 
that data. Where EPA did not collect field sampling data for a 
wastestream and industry-supplied data was available, EPA used that 
data. In the absence of either EPA field sampling data or industry-
supplied data, EPA used literature data.
    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\
---------------------------------------------------------------------------

    \13\ This is consistent with the process EPA used to identify 
pollutants of concern for many categories. EPA takes this approach 
to ensure the pollutants are present in treatable levels.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    \14\ EPA did not analyze its field sampling data for oil and 
grease. Rather, since the existing steam electric ELG currently 
contains BPT limitations applicable to FGD wastewater for oil and 
grease, EPA already has data from the existing rulemaking 
demonstrating oil and grease is also a pollutant of concern in FGD 
wastewater.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    \15\ EPA did not analyze its field sampling data for oil and 
grease. Rather, since the existing steam electric ELG currently 
contains BPT limitations applicable to fly ash transport wastewater 
for oil and grease, EPA already has data from the existing 
rulemaking demonstrating oil and grease is also a pollutant of 
concern in fly ash wastewater.
---------------------------------------------------------------------------

    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

[[Page 34456]]

(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).
---------------------------------------------------------------------------

    \16\ The landfill leachate samples were not analyzed for oil and 
grease. Rather, since the existing steam electric ELG currently 
contains BPT limitations applicable to combustion residual leachate 
for oil and grease, EPA already has data from the existing 
rulemaking demonstrating oil and grease is also a pollutant of 
concern in combustion residual leachate.
    \17\ The surface impoundment leachate samples were not analyzed 
for oil and grease. Rather, since the existing steam electric ELG 
currently contains BPT limitations applicable to combustion residual 
leachate for oil and grease, EPA already has data from the existing 
rulemaking demonstrating oil and grease is also a pollutant of 
concern in combustion residual leachate.
---------------------------------------------------------------------------

    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

[[Page 34457]]

to the percentage removed by BAT/NSPS treatment systems. A pollutant is 
determined to pass through POTWs when the median percentage removed 
nationwide by well-operated POTWs is less than the median percentage 
removed by direct dischargers complying with BAT/NSPS effluent 
limitations and standards. Pretreatment standards are established for 
those pollutants regulated under BAT/NSPS that pass through POTWs to 
waters of the U.S. or interfere with POTW operations or sludge disposal 
practices. This approach to the definition of pass-through satisfies 
two competing objectives set by Congress: (1) That standards for 
indirect dischargers be equivalent to standards for direct dischargers, 
and (2) that the treatment capability and performance of POTWs be 
recognized and taken into account in regulating the discharge of 
pollutants from indirect dischargers.
    For 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:
---------------------------------------------------------------------------

    \18\ For FGD wastewater and leachate, this discussion applies to 
those regulatory options that would provide additional control for 
discharges of toxics like arsenic, mercury and selenium.
---------------------------------------------------------------------------

     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.

[[Page 34458]]

    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 non-adjoining property that receive CCRs from the facility. 
A power plant participating in the voluntary incentive program could 
continue to operate surface impoundments for which combustion residual 
leachate was the only type of CCR solids or wastewater contained in the 
impoundment. Power plants would be granted five additional years 
(beyond the time described above in the preceding paragraph) if they 
eliminate discharges of all process wastewater to surface waters, with 
the exception of cooling water discharges.

                                                                      Table VIII-1--Steam Electric Main Regulatory Options
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Technology basis for the main BAT/NSPS/PSES/PSNS regulatory options
          Wastestreams           ---------------------------------------------------------------------------------------------------------------------------------------------------------------
                                           1                  3a                   2                  3b                   3                  4a                   4                   5
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
FGD Wastewater..................  Chemical            BPJ Determination.  Chemical            Chemical            Chemical            Chemical            Chemical            Chemical
                                   Precipitation.                          Precipitation +     Precipitation +     Precipitation +     Precipitation +     Precipitation +     Precipitation +
                                                                           Biological          Biological          Biological          Biological          Biological          Evaporation
                                                                           Treatment.          Treatment for       Treatment.          Treatment.          Treatment.
                                                                                               units at a
                                                                                               facility with a
                                                                                               total wet-
                                                                                               scrubbed capacity
                                                                                               of 2,000 MW and
                                                                                               more; BPJ
                                                                                               determination for
                                                                                               <2,000 MW.
Fly Ash Transport Water.........  Impoundment (Equal  Dry handling......  Impoundment (Equal  Dry handling......  Dry handling......  Dry handling......  Dry handling......  Dry handling
                                   to BPT).                                to BPT).
Bottom Ash Transport Water......  Impoundment (Equal  Impoundment (Equal  Impoundment (Equal  Impoundment (Equal  Impoundment (Equal  Dry handling/       Dry handling/       Dry handling/
                                   to BPT).            to BPT).            to BPT).            to BPT).            to BPT).            Closed loop (for    Closed loop.        Closed loop
                                                                                                                                       units >400 MW);
                                                                                                                                       Impoundment
                                                                                                                                       (Equal to
                                                                                                                                       BPT)(for units
                                                                                                                                       <=400 MW).
Combustion Residual Leachate....  Impoundment (Equal  Impoundment (Equal  Impoundment (Equal  Impoundment (Equal  Impoundment (Equal  Impoundment (Equal  Chemical            Chemical
                                   to BPT).            to BPT).            to BPT).            to BPT).            to BPT).            to BPT).            Precipitation.      Precipitation
FGMC Wastewater.................  Impoundment (Equal  Dry handling......  Impoundment (Equal  Dry handling......  Dry handling......  Dry handling......  Dry handling......  Dry handling
                                   to BPT).                                to BPT).
Gasification Wastewater.........  Evaporation.......  Evaporation.......  Evaporation.......  Evaporation.......  Evaporation.......  Evaporation.......  Evaporation.......  Evaporation
Nonchemical Metal Cleaning        Chemical            Chemical            Chemical            Chemical            Chemical            Chemical            Chemical            Chemical
 Wastes \19\.                      Precipitation.      Precipitation.      Precipitation.      Precipitation.      Precipitation.      Precipitation.      Precipitation.      Precipitation
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

    \19\ As described in Section VIII, EPA is proposing to exempt 
from new copper and iron BAT limitations any existing discharges of 
nonchemical metal cleaning wastes that are currently authorized 
without iron and copper limits.
---------------------------------------------------------------------------

    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

[[Page 34459]]

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 corrosion-resistant 
metal alloys, or systems operating with absorber chloride 
concentrations substantially below the design chloride limit). The flow 
minimization at these plants would be achieved by either reducing the 
FGD purge rate or recycling a portion of their FGD wastewater.
    Physical/chemical treatment (i.e., chemical precipitation) is used 
to remove metals and other pollutants from wastewater. Chemicals are 
added to the wastewater in a series of reaction tanks to convert 
soluble metals to insoluble metal hydroxide or metal sulfide compounds, 
which precipitate from solution and are removed along with other 
suspended solids. An alkali, such as 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

[[Page 34460]]

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 wet-scrubbed 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.
---------------------------------------------------------------------------

    \20\ This value is calculated by summing the nameplate capacity 
for all of the units that are serviced by wet FGD systems.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \21\ A seventh plant is scheduled to begin operating a 
biological treatment system for selenium removal next year. Another 
plant is installing a similar treatment system to remove selenium in 
discharges of combustion residual leachate.
---------------------------------------------------------------------------

    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 vapor-compression 
evaporation. This technology uses an evaporator to produce a 
concentrated wastewater stream and a reusable distillate stream. The 
concentrated wastewater stream is either disposed of or further 
processed to produce a solid by-product and additional distillate. The 
plant can reuse the distillate stream as makeup water. Two U.S. plants 
and four Italian plants are operating this technology to treat FGD 
wastewater from their coal-fired generating units.\22\
---------------------------------------------------------------------------

    \22\ A third U.S. plant is currently installing a vapor-
compression evaporation system to treat the FGD wastewater.
---------------------------------------------------------------------------

    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,

[[Page 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 well-
operated 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 co-managing FGD and ash wastes in the same impoundments 
can lead to increased pollutant discharges.
    Dry handling technologies are the technology basis for the current 
fly ash NSPS/PSNS requirements, which were promulgated in 1982. All 
generating units built since then have been subject to a ``zero 
discharge'' standard. Some existing units have also converted to dry 
handling technologies. Due to the NSPS discharge standard or economic 
or operational factors, approximately 66 percent of coal- and petroleum 
coke-fired generating units that produce fly ash currently operate dry 
fly ash transport systems, while another 15 percent operate both wet 
and dry fly ash transport systems. The remaining 19 percent operate 
only wet fly ash transport systems. In cases where a unit has both wet 
and dry handling operations, the wet handling system is typically used 
as a backup to the dry system. Effluent limitations and standards based 
on dry ash handling would completely eliminate the discharge of 
pollutants in fly ash transport water.
    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,

[[Page 34462]]

based on the technology of gravity settling in surface impoundments to 
remove suspended solids. The 1982 effluent guidelines for existing 
sources include BPT effluent limits for the allowable levels of TSS and 
oil and grease in discharges of bottom ash transport water. The BPT 
effluent limits are based on the performance of surface impoundments, 
which when well-designed and well-operated can effectively remove 
suspended solids, including pollutants such as particulate forms of 
certain metals when associated with the suspended solids.
    Although surface impoundments can be effective at removing 
particulate forms of metals and other pollutants, they are not designed 
for nor are they effective at removing other pollutants of concern such 
as dissolved metals and nutrients. The concentrations of pollutants 
that remain in the wastestream at 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 
coke-fired units generating bottom ash operate wet bottom ash transport 
systems, while approximately 20 percent operate systems that eliminate 
the use of transport water. Most, but not all, of the wet bottom ash 
transport systems discharge to surface waters. In cases where a plant 
has both wet and dry handling operations, the wet handling system is 
typically used 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

[[Page 34463]]

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 wet-scrubbed capacity of 2,000 MW or 
more), 3, 4a, and 4. EPA has reviewed this technology as a potential 
basis for effluent limitations and standards for leachate and the TDD 
presents information about the compliance costs and pollutant removals 
associated with this technology. The microorganisms used in the 
bioreactors for the biological treatment technology for FGD wastewater 
are resilient and have shown that they operate effectively under 
varying conditions that occur in FGD system and the FGD wastewater 
treatment system. However, leachate flows can be more variable than FGD 
wastewater and, more importantly, may be too intermittent to facilitate 
reliable and consistent biological treatment. Such variations are 
easily accommodated in a chemical precipitation treatment system, but 
may be difficult to manage in a biological treatment system reliant on 
healthy and sustainable populations of microorganisms.
    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 mercury-

[[Page 34464]]

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

[[Page 34465]]

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..........  TSS, Oil & Grease,     Copper...............  Copper.
                                      Copper, Iron.                                   Copper, Iron.
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

[[Page 34466]]

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 EPA-approved methods that are sufficiently 
sensitive to provide reliable quantified results at levels necessary to 
demonstrate compliance with the effluent limits proposed by this 
rulemaking when such methods are available. EPA's detailed study and 
the field sampling for this rulemaking demonstrate that the use of 
sufficiently 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 anti-
circumvention 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.
---------------------------------------------------------------------------

    \23\ For the purposes of this rulemaking, EPA is considering the 
following terms related to analytical method sensitivity to be 
synonymous: ``quantitation limit,'' ``reporting limit,'' ``level of 
quantitation,'' and ``minimum level.''
---------------------------------------------------------------------------

    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

[[Page 34467]]

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.
---------------------------------------------------------------------------

    \24\ On December 22, 2008, the retention wall of a coal ash 
impoundment at Tennessee Valley Authority's Kingston Plant 
collapsed, which resulted in a massive release of CCRs directly into 
the Emory River and its tributaries. The Emory River joins to the 
Clinch River and then converges with the Tennessee River, a major 
drinking water source for populations downstream. This failure 
released over a billion gallons of fly ash and bottom ash, which 
impacted over 100 properties, destroyed three homes, and ruptured a 
gas line resulting in the evacuation of 22 residents.
---------------------------------------------------------------------------

    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 non-
adjoining property that receive CCRs from the facility. A power plant 
participating in the Tier 1 program could continue to operate surface 
impoundments for which combustion residual leachate is the only type of 
CCR solids or wastewater contained in the impoundment. In general, 
power plants accepted in the Tier 1 incentives program would first 
convert ash handling operations to dry handling or closed-loop tank-
based systems and FGD wastewater treatment operations to tank-based 
systems, as described above in Section VI. This first step would 
eliminate new contributions of CCRs (solids and wastewater) to the 
surface impoundments. The plants would then dewater the impoundments by 
draining

[[Page 34468]]

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 non-water quality 
environmental impacts, including energy requirements and such other 
factors as the Administrator deems appropriate. See Section 
304(b)(2)(B). In addition to technological availability, economic 
achievability is also a factor considered in setting BAT. See Section 
301(b)(2)(A).
    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\;
---------------------------------------------------------------------------

    \25\ As described later in this section, EPA is proposing to 
exempt from new BAT copper and iron limitations existing discharges 
of nonchemical metal cleaning wastes that are currently authorized 
under their existing NPDES permit without iron and copper limits. 
For these discharges, BAT limits would be set equal to BPT limits 
for low volume waste.
---------------------------------------------------------------------------

     Establish BAT effluent limits for bottom ash transport 
water and

[[Page 34469]]

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 nitrate-nitrite in discharges of FGD wastewater for units 
located at plants with a total wet-scrubbed capacity of 2,000 MW or 
more 26 27;
---------------------------------------------------------------------------

    \26\ Total plant-level wet-scrubbed capacity is calculated by 
summing the nameplate capacity for all of the units that are 
serviced by wet FGD systems.
    \27\ For units below the 2,000 MW threshold, BAT would continue 
to be determined on a site-specific basis.
---------------------------------------------------------------------------

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

    \28\ As described later in this section, EPA is proposing to 
exempt from new BAT copper and iron limitations existing discharges 
of nonchemical metal cleaning wastes that are currently authorized 
under their existing NPDES permit without iron and copper limits. 
For these discharges, BAT limits would be set equal to BPT limits 
for low volume wastes.
---------------------------------------------------------------------------

     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.
---------------------------------------------------------------------------

    \29\ As described later in this section, EPA is proposing to 
exempt from new BAT copper and iron limitations existing discharges 
of nonchemical metal cleaning wastes that are currently authorized 
under their existing NPDES permit without iron and copper limits. 
For these discharges, BAT limits would be set equal to BPT limits 
for low volume waste.
---------------------------------------------------------------------------

    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 coal- and petroleum coke-fired generating units 
exclusively use a wet fly ash handling system. Furthermore, some of 
these plants with wet fly ash handling systems manage the ash handling 
process so that they do not discharge fly ash transport water. As a 
result, EPA determined that only 13 percent of coal-fired power plants 
would incur costs to comply with a BAT zero discharge requirement for 
fly ash transport water. See Section 9.7.3 of the TDD.
    Power plants recently began installing FGMC systems either to 
comply with state requirements or to prepare for emissions limits 
established by the MATS rule. Plants using sorbent injection systems 
(e.g., activated carbon injection) typically handle the spent sorbent 
in the same manner as their fly ash. Nearly all plants with FGMC 
systems use dry handling technologies. Only a few plants use wet 
systems to transport the spent sorbent to disposal in surface 
impoundments. Based on the industry survey, the plants using wet 
handling systems currently operate them as closed-loop systems and do 
not discharge FGMC wastewater to surface waters, or have the capability 
to do so. These plants could continue to operate these wet systems as 
closed-loop systems, or could convert to dry handling technologies by 
managing the fly ash and spent sorbent together in a retrofitted dry 
system (the wastes are currently managed together in the impoundments) 
or by installing dedicated dry handling equipment for the FGMC wastes 
similar to the equipment used for fly ash.
    The technology basis for control of discharges of FGD wastewater 
under Options 3, 3b (for units located at plants with a total wet-
scrubbed capacity of 2,000 MW or more), and 4a is chemical 
precipitation followed by anaerobic biological treatment. Four power 
plants, or approximately three percent of wet-scrubbed power plants 
that discharge FGD wastewater already have the

[[Page 34470]]

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.
---------------------------------------------------------------------------

    \30\ Four of the six operate the biological treatment systems in 
combination with chemical precipitation.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \31\ Physical/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.
---------------------------------------------------------------------------

    Option 3b proposes limitations based on this technology for units 
at the largest plants (as determined by a 2,000 MW total wet-scrubbed 
capacity threshold), and BAT for the control of discharges of FGD 
wastewater from units at plants below this threshold would continue to 
be determined on a site-specific basis. For FGD wastewater only, EPA 
believes any threshold should be based on a plant level rather than a 
unit level because many plants currently use a single FGD treatment 
systems to service multiple units. Additionally, EPA determined that 
wet-scrubbed capacity is an appropriate metric because it only reflects 
units that are generating FGD wastewater. For example, a plant could 
have a total plant nameplate generating capacity of 3,500 MW, but only 
have a wet-scrubbed capacity of 200 MW if only one of its units is wet-
scrubbed. EPA is putting forth this option as a preferred option based 
on an assumption that these facilities are more able to achieve these 
limits based on economies of scale. These largest facilities will 
likely also be able to absorb the costs of installing and operating the 
chemical precipitation and anaerobic biological treatment systems on 
which the FGD wastewater limitations are based. For these reasons, as 
well as those specified above related to current innovation and 
treatment trends, Option 3b proposes that BAT effluent limitations for 
discharges of FGD wastewater would continue to be determined on a site-
specific basis for units at facilities below the 2,000 MW threshold. 
EPA solicits comment on the proposed 2,000 MW threshold applicable to 
discharges of FGD wastewater under Option 3b, including whether this or 
another threshold may be more appropriate.
    The fourth preferred alternative for this proposed rule, Option 4a, 
in addition to the requirements that would be established under Option 
3, would eliminate discharges of pollutants in bottom ash transport 
water from units greater than 400 MW. The technology basis for bottom 
ash for the zero discharge requirement is dry handling or a closed-loop 
system. Bottom ash transport water is one of the three largest sources 
for discharges of the pollutants of concern from steam electric power 
plants and these discharges occur at many power plants across the 
nation. Based on data collected by the industry survey, approximately 
30 percent of coal-fired and petroleum coke-fired power plants handle 
bottom ash using technologies that do not generate any transport water. 
In addition, another 12 percent of coal- and petroleum coke-fired power 
plants manage the wet-sluicing bottom ash handling system as a closed-
loop system that recirculates all bottom ash transport water so that it 
is not discharged. In addition, 83 percent of coal-fired 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

[[Page 34471]]

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

[[Page 34472]]

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\
---------------------------------------------------------------------------

    \32\ Commenters should provide available monitoring data (i.e., 
EPA is not requiring the commenters to collect additional samples). 
Additionally, commenters should specify what data are represented by 
the characterization data (which wastestreams were sampled, the 
percent contribution of each wastestream, whether the samples are 
untreated or treated, and if treated, the type of treatment system 
represented).
---------------------------------------------------------------------------

     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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \34\ As used here for the purpose of this rulemaking, the term 
partial closure refers to a plant where the closure of a generating 
unit is projected, but one or more generating units at the plant 
will continue operating. A full closure refers to a situation where 
all generating units at a plant are projected to shut down.
    \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.
---------------------------------------------------------------------------

    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

[[Page 34473]]

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 
coke-fired generating units that produce fly ash also already operate 
dry fly ash handling systems in addition to a wet ash handling system 
(either as a completely redundant system, or to manage a fraction of 
the fly ash that is produced during combustion). Similarly, every 
generating unit operating a FGMC system does so in a manner that avoids 
creating any FGMC wastewater (92 percent of units with FGMC), or 
manages the FGMC wastewater in a closed cycle process that does not 
result in a discharge to surface water (8 percent of units with FGMC). 
The technology serving as the basis for FGD effluent limits under 
Option 1 is not effective at removing many of the pollutants of concern 
in FGD wastewater, including selenium, nitrogen compounds, and certain 
metals that contribute to high concentrations of total dissolved solids 
in FGD wastewater (e.g., bromides, boron). Furthermore, the information 
in the record for this proposed rule demonstrates that the amount of 
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 site-specific conditions. For example, any of the 
requirements that would be established under Option 5, including at a 
minimum the vapor compression evaporation technology serving as the 
Option 5 technology basis for FGD wastewater, may be appropriate for 
those power plants that discharge upstream of drinking water treatment 
plants and that have bromide releases in wastewaters that impact 
treatment of source waters at the drinking water treatment plants. 
Section XIII of the preamble includes additional discussion about 
discharges of bromides. Also, see the EA.
    For the reasons described below in 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

[[Page 34474]]

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.
---------------------------------------------------------------------------

    \36\ For Option 4a, for discharges of pollutants found in bottom 
ash transport water only, as explained previously, EPA is proposing 
to raise the value from less than or equal to 50 MW to less than or 
equal to 400 MW.
    \37\ As described earlier in this section, EPA is proposing to 
exempt from new BAT copper and iron limitations existing discharges 
of nonchemical metal cleaning wastes that are currently authorized 
under their existing NPDES permit without iron and copper limits. 
For these discharges, BAT limits would be set equal to BPT limits 
for low volume waste.
---------------------------------------------------------------------------

    In addition, EPA has identified some differences among the options 
in terms of cost effectiveness. Section XII of this preamble describes 
EPA's cost-effectiveness analysis for the preferred regulatory options. 
EPA's analysis to date shows that the average cost effectiveness 
($1981/TWPE) under Option 3a, 3b, 3, and 4a for existing direct 
dischargers is $27, $31, $44, and $57, respectively. This demonstrates 
that Option 3a is the most cost effective of the preferred options, 
Option 4a is the least cost effective of the preferred options, and 
Option 3 and Option 3b are between the two.
    EPA also calculated the cost-effectiveness of particular controls 
for the wastestreams that would be controlled under the preferred 
options for existing direct 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.
---------------------------------------------------------------------------

    \38\ While it is not included in the preferred options as a 
wastestream with additional controls, EPA also looked at the cost 
effectiveness of controlling leachate using chemical precipitation 
and this value would exceed $1,000 per TWPE removed.
---------------------------------------------------------------------------

    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, oil-fired generating units 
would be those that use oil as either the primary or secondary fuel and 
do not burn coal or petroleum coke. Units that use oil only during 
startup or for flame stabilization would not be considered oil-fired 
generating units. EPA is proposing to set BAT limits equal to BPT for 
existing oil-fired units because, in comparison to coal- and petroleum 
coke-fired units, oil-fired units generate substantially fewer 
pollutants, are generally older and operate less frequently, and in 
many cases are more susceptible to early retirement when faced with 
compliance costs attributable to the proposed ELGs.
    The amount of ash generated at oil-fired units is a small fraction 
of the amount produced by coal-fired units. Coal-fired units generate 
hundreds or thousands of tons of ash each day, with some plants 
generating more than 1,500 tons per day of ash. In contrast, oil-fired 
units generate less than one ton of ash per day. This disparity is also 
apparent when comparing the ash tonnage to the amount of power 
generated, with coal-fired units producing nearly 300 times more ash 
than oil-fired units (0.04 tons per MW-hour on average for coal units; 
0.000145 tons per MW-hour on average for oil units). The amount of 
pollutants discharged to surface waters is roughly correlated to the 
amount of ash wastewater discharged, thus oil-fired units discharge 
substantially less pollutants to surface waters than a coal-fired 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 oil-fired 
units operated for more than six months in 2009; nearly half of the 
units operated for less than 30 days.
    As shown above, oil-fired units are generally older and operate 
intermittently (i.e., they are peaking, cycling, or intermediate 
units). While these oil-fired units are capable of installing and 
operating the treatment technologies evaluated as part of this 
rulemaking, and the costs would be affordable for most of the plants, 
EPA believes that, due to the factors described here, companies may 
choose to shut down these 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 oil-
fired 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 oil-fired units 
operate infrequently, which could contribute to the relatively low 
numbers of units discharging ash-related wastewater. Should more 
widespread operation of oil units be required to meet demands of the 
electric grid, additional plants may find it necessary to discharge ash 
transport water. Because of the operating conditions unique to the 
existing fleet of oil-fired units and potential effects on the nation's 
electric power grid, a non-water quality environmental impact that EPA 
considers under Section 304(b) of the CWA, EPA believes it is 
appropriate to set BAT effluent limits for oil-fired equal to the 
current BPT limits.
    Effluent Limits for Small Generating Units. EPA is proposing to 
establish

[[Page 34475]]

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-per-
megawatt 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 
dollar-per-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.
---------------------------------------------------------------------------

    \39\ Preferred Option 4a would increase this threshold for 
purposes of discharges of pollutants in bottom ash transport water 
only, to 400 MW or less.
---------------------------------------------------------------------------

    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 MW \40\ 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.
---------------------------------------------------------------------------

    \40\ For Option 4a, for bottom ash transport water only, as 
explained previously, EPA is proposing to raise the value from less 
than or equal to 50 MW to less than or equal to 400 MW.
    \41\ As discussed in Section XVII.C, the proposed 50 MW 
threshold also alleviates potential impacts which may be borne by 
small entities or municipalities.
---------------------------------------------------------------------------

4. Rationale for the Proposed Best Available Demonstrated Control/NSPS 
Technology
    Section 306 of the CWA directs EPA to promulgate New Source 
Performance Standards, or NSPS, ``for the control of the discharge of 
pollutants which reflects the greatest degree of effluent reduction 
which the Administrator determines to be achievable through application 
of the best available demonstrated control technology, processes, 
operating methods, or other alternatives, including, where practicable, 
a standard permitting no discharge of pollutants.'' Congress envisioned 
that new sources could meet tighter controls than existing sources 
because of the opportunity to incorporate the most efficient processes 
and treatment systems into the facility design. As a result, NSPS 
should represent the most stringent controls attainable through the 
application of the best available demonstrated control technology, or 
BADCT, for all pollutants (that is, conventional, nonconventional, and 
priority pollutants).
    After considering all of the technology options described above in 
Section VII.B.2, EPA is proposing to establish NSPS based on the suite 
of technologies identified for Option 4 in Table VIII-1. Thus, the 
proposed NSPS would do the following:
     Establish numeric effluent limits for mercury, arsenic, 
selenium, and nitrate-nitrite in discharges of FGD wastewater;
     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

[[Page 34476]]

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 well-demonstrated 
technology for removing metals and other pollutants from a variety of 
industrial wastewater, including leachate from other landfills not 
located at power plants. It therefore represents the ``greatest degree 
of effluent reduction . . . achievable'' as that phrase is used in 
section 306 of the Clean Water Act.
---------------------------------------------------------------------------

    \42\ Four 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.
---------------------------------------------------------------------------

    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 wet-sluicing 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 non-water quality environmental impacts 
associated with Option 4 for existing sources are acceptable. Given 
that there is nothing inherent about a new unit that would alter the 
analysis for such sources, EPA believes that the non-water quality 
environmental impacts associated with the proposed NSPS regulatory 
option are, likewise, acceptable.
    In contrast to the best available technology economically 
achievable, or BAT, that EPA is proposing today for existing sources, 
the proposed NSPS would establish the same limits for oil-fired 
generating units and small generating 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.
---------------------------------------------------------------------------

    \43\ As a point of clarification, this similarly holds true for 
bottom ash limitations.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \44\ This rationale similarly applies to Option 3a.
---------------------------------------------------------------------------

    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

[[Page 34477]]

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
------------------------------------------------------------------------
                                                    Pass through? (Yes/
       Treatment option             Pollutant               No)
------------------------------------------------------------------------
Chemical Precipitation for FGD  Arsenic..........  Yes.
 Wastewater and/or Leachate.    Mercury..........  Yes.
Biological (chemical            Arsenic..........  Yes.
 precipitation followed by      Mercury..........  Yes.
 anoxic/anaerobic biological)   Nitrate Nitrite    Yes.
 for FGD Wastewater and/or       as N.
 Leachate.
                                Selenium.........  Yes.
Mechanical Vapor-Compression    Arsenic..........  Yes.
 Evaporation for FGD            Mercury..........  Yes.
 Wastewater.
                                Selenium.........  Yes.
                                TDS..............  Yes.
Mechanical Vapor-Compression    Arsenic..........  Yes.
 Evaporation for IGCC           Mercury..........  Yes.
 Wastewater.
                                Selenium.........  Yes.
                                TDS..............  Yes.
Nonchemical Metal Cleaning      Copper...........  Yes.
 Wastes.
------------------------------------------------------------------------

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

    \45\ As described in Section VIII.A.3, EPA is proposing to 
exempt from new BAT copper and iron effluent limits existing 
discharges of nonchemical metal cleaning wastes that are currently 
authorized by an NPDES permit without iron and copper limits. This 
exemption also applies to any indirect discharges of nonchemical 
metal cleaning waste that are authorized without copper pretreatment 
standards. For such indirect discharges, the regulation would not 
specify PSES.
---------------------------------------------------------------------------

     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 wet-scrubbed capacity of 2,000 MW; \46\
---------------------------------------------------------------------------

    \46\ Under Option 3b (for units located at plants with a total 
wet-scrubbed capacity of less than 2,000 MW), the regulations would 
not specify PSES for FGD wastewater, and POTWs would need to develop 
local limits to address the introduction of pollutants by steam 
electric power plants to the POTWs that cause pass through or 
interference, as specified in 40 CFR 403.5(c)(2).
---------------------------------------------------------------------------

     Establish a ``zero discharge'' standard for all pollutants 
in fly ash transport water and FGMC wastewater;

[[Page 34478]]

     Establish standards for copper in discharges of 
nonchemical metal cleaning wastes; \47\ and
---------------------------------------------------------------------------

    \47\ As described in Section VIII.A.3, EPA is proposing to 
exempt from new BAT copper and iron effluent limits existing 
discharges of nonchemical metal cleaning wastes that are currently 
authorized by an NPDES permit without iron and copper limits. This 
exemption also applies to any indirect discharges of nonchemical 
metal cleaning waste that are authorized without copper pretreatment 
standards. For such indirect discharges, the regulation would not 
specify PSES.
---------------------------------------------------------------------------

     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 pass-through of 
pollutants from POTWs into receiving streams and also help control 
contamination of POTW sludge. EPA also considered the non-water quality 
environmental impacts and found them to be acceptable, as described in 
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.
---------------------------------------------------------------------------

    \48\ EPA is proposing to exempt from new PSES copper standards 
for existing discharges of nonchemical metal cleaning wastes that 
are currently authorized. For these discharges, the regulation would 
not specify PSES.
    \49\ Preferred Option 4a would increase this threshold for 
purposes of discharges of pollutants in bottom ash transport water 
only, to 400 MW or less.
---------------------------------------------------------------------------

    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 non-water quality environmental impacts 
associated with the preferred option and found them to be acceptable, 
as described in Section XV.
---------------------------------------------------------------------------

    \50\ For the same reasons discussed above in Section VIII for 
NSPS, EPA similarly determined the other regulatory options do not 
reflect PSNS.
---------------------------------------------------------------------------

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

[[Page 34479]]

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.
---------------------------------------------------------------------------

    \51\ EPA considers that by forecasting future installations of 
controls out to the year 2020, the sensitivity analyses for this 
rulemaking reasonably reflect full implementation of air pollution 
controls to comply with existing federal and state requirements.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \52\ EPA IPM v.4.10 projections for units based on compliance 
with CSAPR, MATS, state rules, and enforcement actions including 
consent decrees.
---------------------------------------------------------------------------

    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 wet-
scrubbed capacities. In the very few cases where there are differences 
between the two sources, the differences are primarily due to the 
expected variation at a unit-level (e.g., IPM 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 wet-
scrubbed capacity that is greater than either of those individual 
sources. EPA then added costs associated with projected wastewater 
discharges from this future steam profile to comply with 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

[[Page 34480]]

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\
---------------------------------------------------------------------------

    \53\ EPA did estimate costs for these existing oil-fired 
generating units and small generating units to comply with the 
options considered in this rulemaking and has included those 
estimates in the docket for the proposed rule (see DCN SE01957, 
Incremental Costs and Pollutant Removals for Proposed Effluent 
Limitations Guidelines and Standards for the Steam Electric 
Generating Point Source Category).
---------------------------------------------------------------------------

    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,

[[Page 34481]]

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.
---------------------------------------------------------------------------

    \54\ Because EPA anticipates taking final action on this 
rulemaking in 2014, EPA did not include plants that are expected to 
retire by 2014 and plants that do not discharge any of the 
applicable wastestreams. Since this timeframe is approximately one 
year following the date of the proposed rule, EPA considers there to 
be sufficient certainty regarding plant/unit retirements or relevant 
major system modifications for it to be reasonable for EPA to take 
into account in the regulatory analyses for this rulemaking, 
Retirements and modifications occurring farther into the future than 
2014 become more 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.
    \55\ EPA is considering establishing BMPs that would apply to 
surface impoundments that receive, store, dispose of, or are 
otherwise used to manage coal combustion residuals including FGD 
wastes, fly ash, bottom ash (which includes boiler slag), leachate, 
and other residuals associated with the combustion of coal to 
prevent uncontrolled discharges from these impoundments. Costs for 
the industry to implement the BMPs under consideration are included 
in EPA's cost and economic analyses for the proposed rule.
---------------------------------------------------------------------------

    EPA's cost estimates include two key cost components: Capital costs 
(one-time costs) and operating and maintenance (O&M) costs (which are 
incurred every year). Capital costs comprise the direct and indirect 
costs associated with the purchase, delivery, and installation of 
pollution control technologies. Capital cost elements are specific to 
the industry and commonly include purchased equipment and freight, 
equipment installation, buildings, land, site preparation, engineering 
costs, construction expenses, contractor's fees, and contingency. 
Annual O&M costs comprise all costs related to operating and 
maintaining the pollution control technologies or performing BMPs for a 
period of one year. O&M costs are also specific to the industry and 
commonly include costs associated with operating labor, maintenance 
labor, maintenance materials (routine replacement of equipment due to 
wear and tear), chemical purchase, energy requirements, residual 
disposal, and compliance monitoring. In some cases, the technology 
options may also result in recurring costs that are incurred less 
frequently than annually (e.g., 3-year recurring costs) or one-time 
costs other than capital investment (e.g., one-time engineering costs).

A. Methodology for Estimating Plant-Specific Costs

    The limitations and standards associated with the regulatory 
options for 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 self-monitoring data to determine if the plant currently meets the 
performance level of the technology basis for the requirement of an 
option for that wastestream. A portion of the steam electric industry 
has already implemented processes 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                             Regulatory option
                  Wastestream                        Technology cost modules     -----------------------------------------------------------------------
                                                                                     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
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 34482]]


 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     Conveyance Vacuum Line
 Dry Vacuum Fly Ash Handling.             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     Water bath trough;
 to Mechanical Drag System (MDS) or
 Remote MDS.
                                          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).
---------------------------------------------------------------------------

    \56\ The conversion from wet to dry fly ash handling for a unit 
requires new equipment to pneumatically convey the ash; however, ash 
handling vendors stated that for dry vacuum retrofits, the existing 
hopper equipment and branch lines can be retained and reused.
---------------------------------------------------------------------------

    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;

[[Page 34483]]

     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 plant-specific costs for these future 
installations, using the same approach as it used for current 
operations.
---------------------------------------------------------------------------

    \57\ EPA expects that plants will be in compliance with new 
federal and state air pollution control requirements by 2020.
---------------------------------------------------------------------------

B. Methodology for Estimating Plant-Specific Pollutant Reductions

    EPA took a similar approach to the one described above for costs in 
estimating pollutant reductions associated with the limitations and 
standards for the regulatory options in 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.
---------------------------------------------------------------------------

    \58\ A third power plant is currently installing a vapor-
compression evaporation system to treat the FGD wastewater.
---------------------------------------------------------------------------

    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 low-volume waste sources). EPA estimated that all dissolved metals 
will pass through the surface impoundment and be discharged. Section 10 
of the TDD contains more information on baseline pollutant effluent 
concentrations.
    EPA then used this average baseline pollutant effluent 
concentration with plant-specific discharge flow rates reported in the 
industry survey to estimate the mass pollutant discharged per 
plant.\59\ Section 9 of the TDD contains more details on how EPA 
developed flow rates.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.

[[Page 34484]]

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 post-
compliance leachate loads, EPA lacked data on effluent concentrations 
from chemical precipitation or biological treatment of leachate from 
combustion residual landfills or surface impoundments. EPA is proposing 
the effluent limits for leachate discharges would be based on 
transferring the effluent limits calculated for FGD wastewater using 
the identical technology bases. Therefore, EPA estimates, based on 
engineering judgment, that post-compliance effluent concentrations for 
leachate would be equal to the average effluent FGD wastewater 
concentrations for a similar treatment technology.
4. FGMC and Gasification Wastewaters and Nonchemical Metal Cleaning 
Wastes
    FGMC wastewater originates from activated carbon injection systems. 
EPA identified 73 plants with current or planned activated carbon 
injection systems. Most of these plants use, or plan to use, a dry 
handling system to transfer the 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.
---------------------------------------------------------------------------

    \60\ The proposed BAT would establish limits for copper and iron 
equal to the existing BPT limits for these pollutants. The proposed 
NSPS would establish standards for copper, iron, TSS, and oil and 
grease that are equal to the BPT limits for these pollutants. The 
proposed PSES and PSNS would establish standards for copper equal to 
the BPT limits for copper. See Section VIII for details about the 
proposed limitations for nonchemical metal cleaning wastes.
---------------------------------------------------------------------------

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 non-detects, treatment of pollutants in the source water 
and the calculation of toxic-weighted pollutant equivalents.
    Age of data. How should EPA take into account changes that may have 
occurred in the industry over time and what information would be 
appropriate for demonstrating that certain data for certain pollutants 
or wastestreams should or should not be used? For

[[Page 34485]]

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, one-time 
costs, and recurring costs for each regulatory option. Section XI 
contains a listing of total annualized costs by regulatory option. All 
cost estimates in this section are expressed in terms of pre-tax 2010 
dollars. The costs shown in Section XI take into account the timeframe 
proposed to meet the limits in the rule.
    Information, including plant-specific information, for EPA's 
compliance cost and pollutant loading estimates and methodologies is 
located in the rulemaking record. Some of the information EPA used to 
estimate compliance costs and pollutant loadings was claimed by survey 
respondents as CBI. Therefore, this information is not included in the 
public docket. However, the public docket contains a number of 
documents that set forth EPA's methodology, assumptions and rationale 
for developing its cost estimates and pollutant loadings estimates, and 
that also present as much data as possible by using aggregation, 
summaries, and other techniques to protect CBI. EPA encourages all 
interested parties to refer to the record and to provide comments where 
appropriate on any aspect of the methodology or the data used to 
estimate compliance costs and pollutant loadings associated with this 
proposal.

                                Table IX-3--Cost of Implementation (BAT and PSES)
                                      [In millions of pre-tax 2010 dollars]
----------------------------------------------------------------------------------------------------------------
                                  Number                                              Recurring costs
       Regulatory option            of      Capital   Annual    One time ---------------------------------------
                                  plants     cost    O&M cost    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)
----------------------------------------------------------------------------------------------------------------
\a\ EPA estimated the costs for Option 4a based on approximated plant-level bottom ash costs for those plants
  that have at least one generating unit with a nameplate capacity of 400 MW or less and at least one other
  generating unit with a nameplate capacity of greater than 400 MW. For more details on how EPA estimated these
  plant-level bottom ash costs, see the memorandum entitled ``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]
----------------------------------------------------------------------------------------------------------------
                                                                          Pollutant removals
                                                     -----------------------------------------------------------
                  Regulatory option                      Conventional          Priority         Nonconventional
                                                        pollutants \a\        pollutants        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

[[Page 34486]]

 
5...................................................                  36                 1.7               5,287
----------------------------------------------------------------------------------------------------------------
\a\ The loadings reduction for conventional pollutants includes BOD and TSS. Note that the BOD and TSS removals
  are not included in the total pollutant removals stated in Section II (1.63 billion pounds per year for Option
  3; 3.34 billion pounds per year for Option 4) to avoid double-counting removals for certain priority and
  nonconventional pollutants that would also be measured by these bulk parameters.
\b\ The loadings reduction for nonconventional pollutants excludes TDS and COD to avoid double-counting removals
  for certain pollutants that would also be measured by these bulk parameters (e.g., sodium, magnesium).
\c\ Option 1 shows a negative removal for nonconventional pollutants because the mass of several pollutants
  (ammonia, chromium, TKN, and BOD) are not quantified at baseline, and because some pollutant discharge
  concentrations are higher under Option 1.

    EPA estimated the pollutant removals for Option 4a based on 
approximated plant-level bottom ash loadings for those plants 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 long-term averages, variability factors, and limitations 
for BAT, new source performance standards and pretreatment standards 
for existing and new sources. The effluent limitations and standards 
are based on long-term average effluent values and variability factors 
that account for variation in treatment performance of the model 
technology.
    The proposed effluent limitations and/or standards, collectively 
referred to in the remainder of this section as ``limitations,'' for 
pollutants for each technology option, as presented in 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 long-term 
average test (or LTA test) for plants where EPA possesses paired 
influent and effluent data (see Section 13 of the Technical Development 
Document for details of the LTA test). The test measures the influent 
concentrations to ensure a pollutant is present at a sufficient 
concentration to evaluate treatment effectiveness. If a dataset for a 
pollutant fails the test (i.e., pollutant not present at a treatable 
concentration), EPA excludes the data for that pollutant at that plant 
when calculating the limitations.
    A fourth criterion typically requires that the data are valid and 
appropriate for their intended use (e.g., the data must be analyzed 
with a sufficiently-sensitive method). Also, EPA does not use data 
associated with periods of treatment upsets because these data would 
not reflect the performance from well-designed and well-operated 
treatment systems. In applying the fourth criterion, EPA may evaluate 
the pollutant concentrations, analytical methods and the associated 
quality control/quality assurance data, flow values, mass loading, 
plant logs, and other available information. As part of this 
evaluation, EPA reviews the process or treatment conditions that may 
have resulted in extreme values (high and low). As a consequence of 
this review, EPA may exclude data associated with certain time periods 
or other data outliers that reflect poor performance or

[[Page 34487]]

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\
---------------------------------------------------------------------------

    \61\ Examples of conditions that are typically unique to the 
initial commissioning period include operator unfamiliarity or 
inexperience with the system and how to optimize its performance; 
wastewater flow rates that differ significantly from engineering 
design, altering hydraulic residence times, chemical contact times, 
and/or clarifier overflow rates, and potentially causing large 
changes in planned chemical dosage rates or the need to substitute 
alternative chemical additives; equipment malfunctions; fluctuating 
wastewater flow rates or other dynamic conditions (i.e., not steady 
state operation); and initial purging of contaminants associated 
with installation of the treatment system, such as initial leaching 
from coatings, adhesives, and susceptible metal components. These 
conditions differ from those associated with the restart of an 
already-commissioned treatment system, such as may occur from a 
treatment system that has undergone either short or extended 
duration shutdown.
---------------------------------------------------------------------------

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):
---------------------------------------------------------------------------

    \62\ Based on data EPA has evaluated for the steam electric 
industry and other industry sectors, two-stage chemical 
precipitation systems generally achieve better pollutant removals 
than one-stage systems. Since the technology basis for chemical 
precipitation treatment of FGD wastewater in the proposed rule is a 
one-stage system and that is the configuration used to estimate 
compliance costs, EPA concluded that effluent data for the two-stage 
system (Pleasant Prairie) should not be used when calculating 
effluent limits for the technology option.

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

[[Page 34488]]

     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 vapor-
compression 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 self-monitoring data) from a plant during the 
same time period, EPA combines the data from these sources into a 
single dataset for the plant for the statistical analysis.
    For this rulemaking, data at most selected plants came from 
multiple sources (EPA's sampling, plant sampling as directed by the EPA 
through 308 letters, or plant self-monitoring). For some plants, EPA 
has data collected from multiple sources during overlapping time 
periods. For these plants, EPA combined the multiple sources of data at 
each plant into a single dataset for the plant, which provided the 
basis for developing the limitations. Other plants had data collected 
from multiple 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.

[[Page 34489]]

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 well-operated model 
technologies is capable of achieving. This long-term average is 
calculated using data from the plant or plants with the model 
technologies for the option.
    In the second step of developing a limitation for a pollutant, EPA 
determines an allowance for the variation (the option variability 
factors discussed below) in pollutant concentrations for wastewater 
that has been processed through well-designed and well-operated 
treatment systems. This allowance for variation incorporates all 
components of variability including shipping, sampling, storage, and 
analytical variability. This allowance is incorporated into the 
limitations through the use of the variability factors, which are 
calculated from the data from the plants using the model technologies. 
If a plant operates its treatment system to meet the relevant long-term 
average, EPA expects the plant will be able to meet the limitations. 
Variability factors ensure that normal fluctuations in a plant's 
treatment are accounted for in the limitations. By accounting for these 
reasonable excursions above the long-term average, EPA's use of 
variability factors results in limitations that are generally well 
above the 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.
---------------------------------------------------------------------------

    \63\ For the purpose of discussing the calculation of the long-
term averages, variability factors, and effluent limitations, the 
term ``detected'' refers to analytical results measured and reported 
above the sample-specific quantitation limit. Thus, values described 
in this section as ``non-detected'' refers to values that are below 
the method detection limit (MDL) and those measured by the 
laboratory as being between the MDL and the quantitation limit (QL).
---------------------------------------------------------------------------

    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

[[Page 34490]]

(where m=(n+1)/2 and n=number of values). If there is an even number of 
values, then the median is the average of the two values in the n/2th 
and [(n/2)+1]th positions among the ordered observations.
2. Calculation of Option Variability Factors and Limitations
    The following describes the calculations performed to obtain the 
option variability factors and limitations. First, EPA calculated the 
plant-specific variability factors for each pollutant that had enough 
distinct detected values by fitting a statistical model to the daily 
effluent concentration values. Each plant-specific daily variability 
factor for each pollutant is the estimated 99th percentile of the 
distribution of the daily pollutant concentration values divided by the 
plant-specific long-term average. Each plant-specific monthly 
variability factor for each pollutant is the estimated 95th percentile 
of the distribution of the 4-day average pollutant concentration values 
divided by the plant-specific long-term average. The calculation of the 
monthly variability factor assumes that the monthly averages are based 
on the pollutant being monitored weekly (approximately four times each 
month). In cases when there were not enough distinct detected values 
for a specific pollutant at a plant, then the statistical model was not 
used to obtain the plant-specific variability factors. In these cases, 
the data for the pollutant at the plant was excluded from the 
calculation of the option variability factors. Appendix B of the 
Technical Development Document contains the required minimum number of 
distinct detected observations and a description of the procedures used 
to estimate the plant-specific daily and monthly variability factors.
    Second, EPA calculated the option variability factors. The option 
daily variability factor for a pollutant was found as the mean of the 
plant-specific daily variability factors for that pollutant. Similarly, 
the option monthly variability factor was the mean of the plant-
specific monthly variability factors for that pollutant.
    Finally, the daily limitation for each pollutant was the product of 
the option long-term average and option daily variability factor. The 
monthly average limitation for each 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 
long-term average, variability factors, and limitations for each of the 
FGD, gasification, and leachate treatment technology options. See DCN 
SE01999 for details of the calculation of the results presented in the 
table below.

     Table X-1--Proposed Long-Term Averages, Variability Factors, and Effluent Limitations for Each of the FGD, Gasification, and Leachate Treatment
                                                                   Technology Options
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                               Daily          Monthly
           Treatment technology                       Pollutant             Option LTA      variability     variability        Daily          Monthly
                                                                                              factor          factor      limitation \d\  limitation \d\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Chemical Precipitation for FGD............  Arsenic (ug/L)..............           4.483           1.741           1.223               8               6
                                            Mercury (ng/L)..............          75.404           3.209           1.570             242             119
Chemical Precipitation and Biological       Arsenic (ug/L)\a\...........           4.483           1.741           1.223               8               6
 Treatment for FGD.                         Mercury (ng/L)\a\...........          75.404           3.209           1.570             242             119
                                            Nitrate-nitrite (mg/L)......           0.110           1.499           1.157            0.17            0.13
                                            Selenium (ug/L).............           7.455           2.145           1.321              16              10
Chemical Precipitation and Evaporation for  Arsenic (ug/L)..............         \b\ 4.0           (\c\)           (\c\)           \e\ 4           (\f\)
 FGD.                                       Mercury (ng/L)..............          17.788           2.192           1.338              39              24
                                            Selenium (ug/L).............         \b\ 5.0           (\c\)           (\c\)           5 \e\           (\f\)
                                            TDS (mg/L)..................          14.884           3.341           1.572              50              24
Vapor-Compression Evaporation for           Arsenic (ug/L)..............         \b\ 4.0           (\c\)           (\c\)           \e\ 4           (\f\)
 Gasification.                              Mercury (ng/L)..............           1.075           1.632           1.194            1.76            1.29
                                            Selenium (ug/L).............         146.780           3.083           1.545             453             227
                                            TDS (mg/L)..................          15.209           2.483           1.389              38              22
Chemical Precipitation for Leachate.......  Arsenic (ug/L)\a\...........           4.483           1.741           1.223               8               6
                                            Mercury (ng/L)\a\...........          75.404           3.209           1.570             242             119
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Option long-term average, option variability factors, and limitations were transferred from chemical precipitation treatment technology option.
\b\ Long-term average is the arithmetic mean since all observations were non-detected.

[[Page 34491]]

 
\c\ All 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

[[Page 34492]]

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 investor-owned utilities, 
municipalities, states, federal authorities, cooperatives, and 
nonutilities, whose primary business is electric power generation or 
related electric power services--of complying with the proposed ELGs. 
As described in Section VI of this preamble, EPA estimated 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\
---------------------------------------------------------------------------

    \64\ As discussed in Section VIII, EPA is proposing different 
effluent limits for existing oil-fired generating units and units 
with a capacity of 50 MW or less. Because 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.
---------------------------------------------------------------------------

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 after-tax 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 for-profit plants. For this 
adjustment, EPA used State corporate rates from the Federation of Tax 
Administrators (http://www.taxadmin.org/) combined with federal 
corporate tax rate schedules from the Department of the Treasury, 
Internal Revenue Service.
    Table XI-1 presents the total annualized compliance 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 (after-tax), 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).

[[Page 34493]]

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\
---------------------------------------------------------------------------

    \65\ These assumed technology installation years do not 
necessarily correspond to the actual years in which individual 
facilities would be required to meet the effluent limits or 
standards as specified in their permit, but is a reasonable 
distribution of installation years for the aggregate set of steam 
electric plants incurring compliance costs. These assumptions 
reflect the approximate years in which technology installation would 
reasonably be expected to occur, assuming that expiring permits are 
renewed exactly on the 5-year mark. Note that EPA also analyzed the 
effects of other technology installation periods. The results of 
these analyses are detailed in Appendix B of the RIA report.
---------------------------------------------------------------------------

    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 (five-year period 
beginning in 2017) and the useful life of the longest-lived compliance 
technology installed at any facility (20 years). Under this framework, 
the last year for which costs (and benefits) were tallied in the 
analysis is 2040. EPA calculated social cost of the 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.
---------------------------------------------------------------------------

    \66\ These discount rate values follow guidance from the Office 
of Management and Budget (OMB) regulatory analysis guidance 
document, Circular A-4 (OMB, 2003).
---------------------------------------------------------------------------

    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$]
------------------------------------------------------------------------
                                               3% Discount   7% Discount
              Regulatory option                   rate          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 after-tax 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\
---------------------------------------------------------------------------

    \67\ For private, tax-paying entities, after-tax costs are a 
more relevant measure of potential cost burden than pre-tax costs. 
For non tax-paying entities (e.g., State government and municipality 
owners of affected plants), the estimated costs used in this 
calculation include no adjustment for taxes.
    \68\ To develop the average of year-by-year revenue values over 
the data years, EPA set aside from the averaging calculation, 
revenue values for years that are substantially lower than the 
otherwise ``steady state average''--e.g., because of a generating 
unit being out of service for an extended period.
---------------------------------------------------------------------------

    Table XI-3 summarizes the screening-level 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,

[[Page 34494]]

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
----------------------------------------------------------------------------------------------------------------
                                                                Number of plants with cost-to-revenue ratio of
                     Option                       No data on ---------------------------------------------------
                                                 revenue \b\       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
----------------------------------------------------------------------------------------------------------------
\a\ This analysis makes a counterfactual, conservative assumption of zero cost pass-through. Plant counts are
  weighted estimates.
\b\ EIA does not report necessary data to estimate revenue for 5 plants.

b. Parent Entity-Level Cost-to-Revenue Analysis
    EPA also assessed the economic impact of the eight regulatory 
options at the parent entity-level. The screening-level 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Not analyzed due      Number and percentage with after tax annual compliance costs/annual
                                                               to lack of                                     revenue of:
                                                  Total         revenue      ---------------------------------------------------------------------------
                    Option                      number of     information             0%                0-1%               1-3%          3% or Greater
                                                 entities ----------------------------------------------------------------------------------------------
                                                                %         %         %         %         %
--------------------------------------------------------------------------------------------------------------------------------------------------------
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.

[[Page 34495]]

 
\a\ This analysis makes a counterfactual, conservative assumption of zero cost pass-through.

    The cost-to-revenue ratios provide screening-level indicators of 
potential economic impacts. Entities incurring costs below 1 percent of 
revenue are unlikely to face economic impacts, while entities with 
costs between 1 percent and 3 percent of revenue have a higher chance 
of facing economic impacts, and entities incurring costs above 3 
percent of revenue have a still higher probability of economic impacts. 
As presented in Table XI-4, EPA estimated that the number of entities 
owning steam electric plants ranges from 243 (lower bound estimate) to 
507 (upper bound estimate), depending on the assumed ownership 
structure of plants not surveyed. Under the lower-bound case, EPA 
estimates that the vast majority of parent entities will incur 
annualized costs of less than 1 percent of revenues under all 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.
---------------------------------------------------------------------------

    \69\ In some instances, plant information has been updated to 
reflect known material changes in a plant's generating capacity 
since 2006.
    \70\ The IPM plant universe excludes two steam electric plants 
estimated to incur compliance costs under the proposed ELG scenarios 
EPA analyzed in IPM. See Chapter 5 of the RIA report for more 
details.
    \71\ EPA's Cross-State Air Pollution Rule (CSAPR) was 
promulgated to replace EPA's Clean Air Interstate Rule (CAIR), which 
had been remanded to EPA in 2008. However, on December 30, 2011, the 
U.S. Court of Appeals for the D.C. Circuit stayed 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.
---------------------------------------------------------------------------

    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

[[Page 34496]]

the lowest costs, subject to the same constraints as those present in 
the analysis baseline. The least-cost dispatch solution for meeting 
electricity supply may change as the result of the changes in fixed and 
variable costs at the level of the individual plant and generating 
unit, which EPA estimates would occur as a result of the proposed ELGs. 
These estimated changes in plant- and unit-specific production levels 
and costs--and, in turn, changes in total electric power sector costs 
and production profile--are key data elements in evaluating the 
expected national and regional effects of the proposed ELGs.
    EPA used the screening-level analyses described above to inform the 
selection of regulatory options to be analyzed using IPM. In allocating 
resources to analytical effort, EPA chose to run IPM in a phased 
approach, starting with Option 3 and then Option 4, with the notion to 
proceed if additional model runs were warranted.
    EPA first analyzed a scenario developed based on Option 3 but where 
the total compliance costs and the set of existing plants that are 
assigned costs varied slightly from those in the Option 3 discussed in 
other parts of this preamble.\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.
---------------------------------------------------------------------------

    \72\ The costs as analyzed in IPM differ slightly from those 
used in the non-IPM analyses. For more details on these differences, 
see Chapter 5 of the RIA report. Note that the scenario assigns 
compliance costs for existing plants based on Option 3, and 
compliance costs for new capacity projected in IPM based on Option 
4.
    \73\ Compliance costs differ only slightly (1 percent lower) 
from costs used in other analyses, primarily to avoid disclosing 
CBI. There are no differences in the set of plants estimated to 
incur compliance costs or in the timing of the costs. For more 
details, see Chapter 5 of the RIA report.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.

[[Page 34497]]



                          Table XI-5--Impact of Market Model Analysis Options on National and Regional Markets at the Year 2030
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Incremental early  retirements/       Change in         Change in         Change in
                                                                           closures \a\                 variable        annual costs       electricity
                 NERC region                      Baseline     ------------------------------------  production cost   (million 2010$   price (2010$/MWh
                                                capacity (GW)                       % of Baseline    (2010$/MWh or %       or % of           or % of
                                                                  Capacity (GW)       closures        of baseline)        baseline)         baseline)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values for incremental early retirements or closures represent change relative to the baseline run. IPM may show partial (i.e., unit) or full plant
  early retirements (closures) for a given option. It may also show avoided closures (negative closure values) in which a unit or plant that is
  projected to close in the baseline, is estimated to continue operating in the post-compliance case. Avoided closures may occur among plants that incur
  no compliance costs or for which compliance costs are low relative to other steam electric plants.\75\

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

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \76\ Avoided capacity closures occur when one or more generating 
units that are otherwise projected to cease operations in the 
baseline become more economically attractive sources of electricity 
in the post-compliance case, because of relative changes in the 
economics of electricity production across the full market, and thus 
avoid closure.
---------------------------------------------------------------------------

    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

[[Page 34498]]

analysis, which sought to assess the impact of the proposed ELGs 
regulatory options on the entire electric power sector, the purpose of 
this second analysis is to assess impacts on steam electric plants 
specifically.
    Table XI-6 reports results for steam electric plants, as a group. 
In this case, EPA looked at the following metrics IPM produces: (1) 
Incremental early retirements and capacity closures, calculated as the 
difference between capacity under the regulatory options and capacity 
under the baseline, which includes both full plant closures and partial 
plant closures (i.e., unit closures) in aggregate capacity terms; (2) 
incremental capacity closures as a percentage of baseline capacity; (3) 
post-compliance change in electricity generation; (4) post-compliance 
changes in variable production costs per MWh, calculated as the sum of 
total fuel and variable O&M costs divided by net generation; and (5) 
changes in annual costs (fuel, variable O&M, fixed O&M, and capital. 
Items (1) and (2) 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Incremental early retirements/                          Change in
                                                                           closures \a\              Change in total      variable      Change in annual
                 NERC region                      Baseline     ------------------------------------  generation (GWh   production cost   costs (million
                                                capacity (MW)                       % of Baseline        or % of       (2010$/MWh or %    2010$ or % of
                                                                  Capacity (MW)       capacity          baseline)       of baseline)        baseline)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values for incremental early retirements or closures represent change relative to the baseline run. IPM may show partial (i.e., unit) or full plant
  early retirements (closures) for a given option. It may also show avoided closures (negative closure values) in which a unit or plant that is
  projected to close in the baseline, is estimated to continue operating in the post-compliance case. Avoided closures may occur among plants that incur
  no compliance costs or for which compliance costs are low relative to other steam electric plants. \77\

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

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \78\ At the national level, the demand for electricity does not 
change between the baseline and the analyzed regulatory options 
(generation within the regions is allowed to vary) because meeting 
demand is an exogenous constraint imposed by the model.
---------------------------------------------------------------------------

    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

[[Page 34499]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                Reduction                                            Increase
                Economic measures                ---------------------------------------  No Change  ---------------------------------------   N/A \b\
                                                     >= 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ The change in capacity utilization is the difference between the capacity utilization percentages in the base case and post-compliance cases. For
  all other measures, the change is expressed as the percentage change between the base case and post-compliance values.
\b\ Plants with status changes in either baseline or post-compliance scenario have been excluded from these calculations. For example, for a plant that
  is projected to close in the post-compliance case, the reduction in variable costs per MWh of generated electricity would be 100 percent.
  Specifically, there are 23 full baseline plant closures, 77 partial baseline plant closures, and 1 avoided plant closure under Option 3. There are 23
  full baseline plant closures, 72 partial baseline plant closures, 3 avoided plant closures, and 6 partial policy plant closures under Option 4.

    For Option 3, the analysis of changes in individual plants 
indicates that most plants experience only slight effects--no change, 
or less than a 1 percent reduction or 1 percent increase. Only 13 
plants (2 percent) are estimated to incur a reduction in capacity 
utilization exceeding 1 percent and 18 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

[[Page 34500]]

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\
---------------------------------------------------------------------------

    \80\ Other steam generation includes biomass, landfill gas, 
fossil waste, municipal solid waste, non-solid waste, tires, and 
geothermal. Other non-steam generation includes wind, solar, pumped 
storage, and fuel cell.
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    \81\ As defined by the Energy Information Administration, 
``overnight cost'' is an estimate of the cost at which a plant could 
be constructed assuming that the entire process from planning 
through completion could be accomplished in a single day. This 
concept is useful to avoid any impact of project delays and of 
financing issues and assumptions on estimated costs.

    Table XI-8--Comparison of Incremental Compliance Costs with Costs for New Coal-Fired Steam Electric Units
----------------------------------------------------------------------------------------------------------------
                                                         Costs of new coal     Incremental
                     Cost component                          generation      compliance costs    Percent of new
                                                           ($2010/MW) \a\     ($2010/MW) \b\    generation cost
----------------------------------------------------------------------------------------------------------------
Capital................................................         $2,981,947    $19,911-$21,773            0.7-0.7
Annual O&M.............................................             66,427       2,281-$3,093            3.4-4.7
                                                        --------------------------------------------------------
Total Annualized Costs.................................            329,487       4,037-$5,013            1.2-1.5
----------------------------------------------------------------------------------------------------------------
\a\ Source: New unit total cost value from Table 8.2 EIA NEMS Electricity Market Module. AEO 2011 Documentation.
  Available at http://www.eia.gov/forecasts/aeo/assumptions/pdf/electricity.pdf. Capital costs are based on the
  total overnight costs for new scrubbed coal dual-unit plant, 1,300 MW capacity coming online in 2014. EPA
  restated costs in 2010 dollars. Total annual O&M costs assume 90% capacity utilization.
\b\ Incremental costs for new 1300 MW unit for Option 4. Range represents the costs for a new unit at an
  existing plant (lower bound) and new unit at newly constructed plant (upper bound).

    The comparison suggests that compliance with the proposed ELGs 
represents a relatively small fraction of overnight capital costs of a 
new unit (less than 1 percent) and a somewhat higher, but still small 
(less than 5 percent), fraction of non-fuel O&M 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.

[[Page 34501]]

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.
---------------------------------------------------------------------------

    \82\ Some 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.
---------------------------------------------------------------------------

    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\
----------------------------------------------------------------------------------------------------------------
                                   Option    Option                                  Option
           NERC Region               3a        3b     Option 1  Option 2  Option 3     4a     Option 4  Option 5
----------------------------------------------------------------------------------------------------------------
ASCC............................     $0.00     $0.00     $0.00     $0.00     $0.00     $0.00     $0.00     $0.00
ECAR............................      1.69      2.29      1.82      2.71      4.40      7.22     10.08     16.86
ERCOT...........................      0.00      0.42      1.22      1.73      1.73      2.60      2.79      5.76
FRCC............................      0.00      0.00      0.18      0.67      0.67      0.67      0.99      4.32
HICC............................      0.00      0.00      0.00      0.00      0.00      0.00      0.00      0.00
MAAC............................      0.00      0.00      0.06      0.32      0.32      0.97      2.04      3.52
MAIN............................      0.31      0.31      0.48      0.69      1.01      2.55      4.63      6.16
MAPP............................      0.01      0.01      0.97      1.30      1.32      2.04      3.23      5.58
NPCC............................      0.00      0.00      0.03      0.08      0.08      0.08      0.49      0.67
SERC............................      1.09      2.00      1.63      2.19      3.28      4.98      6.47     10.81
SPP.............................      0.05      0.14      0.61      0.96      1.01      2.85      4.43      6.30
WECC............................      0.05      0.05      0.02      0.03      0.08      0.23      0.53      0.59
U.S.............................      0.48      0.75      0.75      1.12      1.59      2.69      3.89      6.46
----------------------------------------------------------------------------------------------------------------
\a\ The rate impact analysis maintains the counterfactual, conservative assumption of 100 percent pass-through
  to electricity consumers.

    As stated above, this analysis assumes that all of the compliance 
costs (100 percent) will be passed onto consumers through increased 
electricity rates. However, plants and owning entities are likely to 
absorb some of these costs, thereby reducing the impact of 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 pass-through 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 sample-weighted pre-
tax annualized compliance costs as of 2014 over complying plants by 
NERC region to calculate the total estimated annual cost in each 
region. EPA then calculated the approximate average price impact per 
unit of electricity consumption by dividing total compliance costs by 
the reported total MWh of sales in each NERC region. Details of this 
analysis are presented in Chapter 7 of the RIA report.
    As reported in Table XI-10, on average, across the United States, 
Option 5 results in the highest increased compliance cost of 
0.059[cent] per kWh. Annualized compliance costs (in dollars per KWh 
sales) associated with Option 3a range from 0[cent] to 0.016[cent], 
depending on the region, with a national average of

[[Page 34502]]

0.004[cent] per KWh. For Option 3b, annualized compliance costs range 
from 0[cent] to 0.022[cent], with a national average of 0.007[cent] per 
KWh, whereas Option 3 has a range of 0[cent] to 0.042[cent] per kWh and 
a national average of 0.015[cent] per kWh and Option 4a has a range of 
0[cent] to 0.068[cent] per kWh and a national average of 0.025[cent] 
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 [cent]/KWh Sales] \a\
----------------------------------------------------------------------------------------------------------------
                                   Option    Option                                  Option
           NERC Region               3a        3b     Option 1  Option 2  Option 3     4a     Option 4  Option 5
----------------------------------------------------------------------------------------------------------------
ASCC............................     0.000     0.000     0.000     0.000     0.000     0.000     0.000     0.000
ECAR............................     0.016     0.022     0.017     0.026     0.042     0.068     0.095     0.159
ERCOT...........................     0.000     0.003     0.009     0.012     0.012     0.019     0.020     0.041
FRCC............................     0.000     0.000     0.001     0.005     0.005     0.005     0.007     0.032
HICC............................     0.000     0.000     0.000     0.000     0.000     0.000     0.000     0.000
MAAC............................     0.000     0.000     0.001     0.003     0.003     0.010     0.021     0.036
MAIN............................     0.003     0.003     0.005     0.008     0.011     0.028     0.051     0.068
MAPP............................     0.000     0.000     0.009     0.012     0.013     0.019     0.031     0.053
NPCC............................     0.000     0.000     0.000     0.001     0.001     0.001     0.007     0.009
SERC............................     0.008     0.014     0.012     0.016     0.023     0.035     0.046     0.076
SPP.............................     0.000     0.001     0.005     0.008     0.008     0.023     0.036     0.051
WECC............................     0.001     0.001     0.000     0.000     0.001     0.002     0.006     0.006
U.S.............................     0.004     0.007     0.007     0.010     0.015     0.025     0.036     0.059
----------------------------------------------------------------------------------------------------------------
\a\ This analysis makes a counterfactual, conservative assumption of 100 percent pass-through to electricity
  consumers.

    As mentioned in the previous section, EPA ran alternative scenarios 
using an assumption that only half (50 percent) of the incremental 
compliance costs are passed onto consumers. The results of these 
alternative scenarios showed commensurately smaller impacts on 
compliance costs per unit of electricity sold (see Appendix B of the 
RIA report).

E. Employment Effects

    EPA assessed the potential for employment impacts at the national 
level for the 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 longer-term, on-going 
employment effects of meeting compliance requirements, and accounts for 
all compliance costs, regardless of their time, duration, or frequency 
of occurrence. Morgenstern, Pizer and Shih (2000) explore both 
theoretically and empirically the relationship between employment and 
compliance costs of environmental regulation. Morgenstern et al. 
identify three separate components of the employment change within a 
regulated industry in response to a regulation. First, complying with 
environmental regulations causes higher production costs which raises 
market prices, higher prices reduce consumption (and production) 
reducing demand for labor within the regulated industry (``demand 
effect''). Second, as costs go up, to produce the same level of output, 
plants add more capital and labor. For example, pollution abatement 
activities require additional labor services to produce the same level 
of output (``cost effect''). Third, post-regulation production 
technologies may be more or less labor intensive (i.e., more/less labor 
is required per dollar of output) (``factor-shift effect''). The demand 
effect is unambiguously negative, the cost effect is unambiguously 
positive and the factor-shift effect could be positive or negative 
making the total effect theoretically indeterminate. In addition, 
Morgenstern et al. also estimate an empirical model for four highly 
polluting/regulated industries to examine the effect of 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.

[[Page 34503]]



Table XI-11--Results of Ongoing Employment Effects on the Electric Power
                  Industry Sector (Number of Jobs) a b
------------------------------------------------------------------------
                                                            Total annual
                                                               average
         Regulatory option             Employment effect     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
------------------------------------------------------------------------
\a\ Source: 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 cost-effectiveness 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 
toxic-weighted pounds remaining after POTW treatment.
    Annual costs. The costs used in the cost-effectiveness analysis are 
the estimated annualized pre-tax costs to comply with the alternative 
regulatory options (refer to Section XI for a discussion of the 
annualized compliance costs). These costs to plants to remove the 
pollutants will be less because the costs are tax deductible. The 
annual costs include the annualized capital outlays for equipment and 
recurring expenses for operating and maintaining compliance equipment, 
meeting monitoring requirements, etc.
    Incremental calculations. The incremental values are the changes in 
total annual compliance costs and changes in pollutant removals as one 
moves to a regulatory option from the next less stringent regulatory 
option, or from the baseline for the least stringent option analyzed, 
where regulatory options are ranked by increasing levels of toxic-
weighted removals. The resulting cost-effectiveness values for a given 
option are, therefore, expressed relative to another option or, for the 
least stringent option considered, relative to the baseline.
    The result of the cost-effectiveness calculation represents the 
unit cost of removing the next pound-equivalent of pollutants and is 
expressed in constant 1981 dollars per toxic pound-equivalent removed 
($/lb-eq) to allow comparisons with the 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 cost-effectiveness analysis for the BAT 
regulatory options applicable to direct dischargers. The table lists 
the options in increasing order of total annual toxic-weighted 
pollutant removals.

[[Page 34504]]



                                  Table XII-1--Cost-Effectiveness of Removing Toxic Pollutants for Direct Dischargers a
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                     Annual pre-tax compliance costs     Total annual toxic-weighted     Cost effectiveness  (1981$/lb-
                                                            (million, 1981$)           pollutant removals (000 lb-eq)                  eq)
                                                   -----------------------------------------------------------------------------------------------------
                      Option                                                                                                               Incremental
                                                      Option total     Incremental      Option total     Incremental      Option cost          cost
                                                          cost             cost           removals         removals      effectiveness    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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Options 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/lb-eq, $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 cost-effectiveness 
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 cost-effectiveness 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                     Annual pre-tax compliance costs     Total annual toxic-weighted    Cost effectiveness (1981$/lb-eq)
                                                            (million, 1981$)           pollutant removals (000 lb-eq)  ---------------------------------
                      Option                       --------------------------------------------------------------------                    Incremental
                                                      Option total     Incremental      Option total     Incremental      Option cost          cost
                                                          cost             cost           removals         removals      effectiveness    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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Options 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 cost-effectiveness 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

[[Page 34505]]

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\
---------------------------------------------------------------------------

    \83\ Ruhl, L., A. Vengosh, G.S. Dwyer, H. Hsu-Kim, G. Schwartz, 
A. Romanski, and S.D. Smith. 2012. The Impact of Coal Combustion 
Residue Effluent on Water Resources: A North Carolina Example. 
Environmental Science and Technology. DCN SE01984.
---------------------------------------------------------------------------

    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

[[Page 34506]]

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 water-scale 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 Risk-Screening Environmental 
Indicators (RSEI) model and used the wildlife and human health models 
to calculate metal concentrations in exposed fish populations and human 
exposure doses from fish consumption in surface waters downstream from 
steam electric discharges. EPA compared downstream receiving water 
concentrations, fish tissue concentrations, and human exposure to water 
quality, wildlife, and non-cancer and cancer benchmarks to assess the 
number of 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 
post-compliance pollutant loadings.
    The preferred options would both reduce ground water contamination 
levels and improve the availability of ground water resources by 
reducing the future leaching of pollutants from steam electric 
impoundments to groundwater aquifers. Section XIV provides additional 
details on the benefits analysis of these ground water improvements.

B. Reduced Impacts to Wildlife

    EPA calculates that the number of immediate receiving waterbodies 
with potential impacts to wildlife would be

[[Page 34507]]

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-a-million threshold. 
Under the post-compliance 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 post-compliance 
pollutant loadings, exceedances of non-cancer reference doses from the 
consumption of fish would decrease in up to 4,084 river miles 
downstream (Option 3a), up to 4,316 river miles downstream (Option 3b), 
up to 5,400 river miles downstream

[[Page 34508]]

(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 non-cancer reference dose 
exceedances described above, EPA also evaluated the adverse health 
effects to children who consume fish contaminated with lead from 
combustion wastewater. EPA estimated the reduction in lead exposure to 
pre-school children via consumption of contaminated fish tissue and 
determined that 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 
non-cancer human health effects beyond those described above, including 
reduced health hazards due to exposure to contaminants in waters that 
are used for recreational purposes (e.g., swimming).

E. Reduced Nutrient Impacts

    The primary concern with nutrients in steam electric discharges is 
the potential for adverse nutrient impacts to occur in water-bodies 
that receive discharges from multiple plants. Nine percent of surface 
waters receiving steam electric wastewater discharges are impaired for 
nutrients. While the current concentration of nitrogen present in steam 
electric discharges from any individual power plant is relatively low, 
the total nitrogen loadings from a single plant can be significant due 
to large wastewater discharge flow rates. Total nutrient loadings from 
multiple power plants is especially a concern on water bodies that are 
nutrient impaired or in watersheds that contribute to downstream 
nutrient problems.
    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 aquatic-dependant 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

[[Page 34509]]

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
----------------------------------------------------------------------------------------------------------------
                                                                                                    Neither
                    Benefit category                       Quantified and     Quantified but     quantified nor
                                                             monetized        not monetized        monetized
----------------------------------------------------------------------------------------------------------------
                        1. Human Health Benefits from Surface Water Quality Improvements
----------------------------------------------------------------------------------------------------------------
Reduced incidence of cancer from arsenic exposure via                   X   .................  .................
 fish consumption......................................
Reduced non-cancer adverse health effects (e.g.,         .................                 X   .................
 reproductive, immunological, neurological,
 circulatory, or respiratory toxicity) due to exposure
 to arsenic from fish consumption......................
Reduced IQ loss in children from lead exposure via fish                 X   .................  .................
 consumption...........................................
Reduced need for specialized education for children                     X   .................  .................
 from lead exposure via fish consumption...............
Reduced adverse health effects in adults from exposure   .................  .................                 X
 to lead from fish consumption.........................
Reduced in-utero mercury exposure via maternal fish                     X   .................  .................
 consumption...........................................
Reduced health hazards from exposure to pollutants in    .................  .................                 X
 waters used recreationally (e.g., swimming)...........
----------------------------------------------------------------------------------------------------------------
         2. Ecological Conditions and Recreational Use Benefits from Surface Water Quality Improvements
----------------------------------------------------------------------------------------------------------------
Benefits from improvements in surface water quality,                    X   .................  .................
 including: improved aquatic and wildlife habitat;
 enhanced water-based recreation, including fishing,
 swimming, boating, and near-water activities;
 increased aesthetic benefits, such as enhancement of
 adjoining site amenities (e.g., residing, working,
 traveling, and owning property near the water\a\; and
 non-use value (i.e., existence, option, and bequest
 value from improved ecosystem health)\a\..............

[[Page 34510]]

 
Benefits from improved protection of threatened and                     X   .................  .................
 endangered species....................................
Reduced sediment contamination.........................  .................  .................                 X
----------------------------------------------------------------------------------------------------------------
                                         3. Groundwater Quality Benefits
----------------------------------------------------------------------------------------------------------------
Reduced groundwater contamination......................                 X   .................  .................
----------------------------------------------------------------------------------------------------------------
                                       4. Market and Productivity Benefits
----------------------------------------------------------------------------------------------------------------
Reduced impoundment failures (monetized benefits                        X   .................  .................
 include avoided cleanup costs and environmental
 damages; non-quantified benefits include avoided
 injury)...............................................
Reduced water treatment costs for municipal drinking     .................  .................                 X
 water, irrigation water, and industrial process.......
Improved commercial fisheries yields...................  .................  .................                 X
Increased tourism and participation in water-based       .................  .................                 X
 recreation............................................
Increased property values from water quality             .................  .................                 X
 improvements..........................................
----------------------------------------------------------------------------------------------------------------
                                             5. Air-Related Benefits
----------------------------------------------------------------------------------------------------------------
Reduced mortality from exposure to NOX, SO2 and                         X   .................  .................
 particulate matter (PM2.5)............................
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, state-
specific average fishing rates, presence of fish consumption 
advisories, the availability of substitute fishing

[[Page 34511]]

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   <$0.1.........................  <$0.1.........................  $0.1..........................  $0.2..........................  $0.2
 of Cancer from Arsenic Exposure
 via Fish Consumption.
Benefits from Reduced IQ Loss in  $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)
 Children from Lead Exposure via
 Fish Consumption a.

[[Page 34512]]

 
Benefits from Reduced Need for    <$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)
 Specialized Education for
 Children from Lead Exposure via
 Fish Consumption.
Benefits of Reduced In-utero      $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)
 Mercury Exposure via Maternal
 Fish Consumption a.
                                 ---------------------------------------------------------------------------------------------------------------------------------------------------------------
    Total Human Health Benefits   $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)
     b.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                        7% Discount Rate
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Benefits from Reduced Incidence   <$0.1.........................  <$0.1.........................  $0.1..........................  $0.1..........................  $0.1
 of Cancer from Arsenic Exposure
 via Fish Consumption.
Benefits from Reduced IQ Loss in  <$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)
 Children from Lead Exposure via
 Fish Consumption a.
Benefits from Reduced Need for    <$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)
 Specialized Education for
 Children from Lead Exposure via
 Fish Consumption.
Benefits of Reduced In-utero      $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)
 Mercury Exposure via Maternal
 Fish Consumption a.
                                 ---------------------------------------------------------------------------------------------------------------------------------------------------------------
    Total Human Health Benefits   $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)
     b.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
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).
b Totals may not add up due to independent rounding.
c EPA did not estimate the benefits of Options 3a, 3b and 4a. EPA expects the benefits of Option 4a to be between those of Options 3 and 4.

b. Reduced Exceedances of Health-Based AWQC
    EPA expects that additional health benefits will arise from reduced 
discharges of steam electric pollutants; however, monetary valuation of 
these other health benefits is not currently possible due to lack of 
data on a dose-response relationship between pollutant ingestion rate 
and potential adverse health effects. To provide an additional measure 
of the potential health benefits of the proposed ELGs, EPA estimated 
the effect of steam electric plant discharges on the occurrence of 
pollutant concentrations in affected waterways that exceed human 
health-based ambient water quality criteria (AWQCs).\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.
---------------------------------------------------------------------------

    \84\ Including AWQCs for the protection of human health through 
consumption of organisms and water.
---------------------------------------------------------------------------

    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

[[Page 34513]]

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 water-based recreation. For example, some of the 
streams that were not usable for recreation under the baseline 
discharge conditions may become usable following implementation of the 
rule, thereby expanding options for recreational users. Streams that 
have been used for recreation under the baseline conditions can become 
more attractive for users by making recreational trips even more 
enjoyable. Individuals may also take trips more frequently if they 
enjoy their recreational activities more. 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 post-compliance 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).
---------------------------------------------------------------------------

    \85\ There may be between 0 and 8 exceedances per waterbody 
(freshwater chronic AWQC values are available for arsenic, cadmium, 
chromium, lead, mercury, nickel, selenium, and zinc).
---------------------------------------------------------------------------

    EPA calculated baseline and post compliance WQI values for reaches 
affected by steam electric plant discharges. Baseline and post 
compliance water quality data were taken from several sources including 
USGS's SPARROW model, EPA's Risk-Screening 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

[[Page 34514]]

promulgation year of the rule, and annualized them using a 3 and 7 
percent discount rate.
    A challenge for meta-analysis is developing a framework that both 
controls for differences in studies and can be used for meaningfully 
predicting benefits associated with regulatory options. In earlier 
benefits estimation for effluent guidelines, EPA often relied on the 
Carson and Mitchell (1993) water quality values. These values come from 
a survey that was one of the first major stated preference efforts, 
fielded in the early 1980s. The study reported values for all of the 
nation's waters, using the same WQI that is used in the meta-analysis. 
When EPA used the Carson and Mitchell values, the Agency was 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 life-history 
effects were further screened to identify those species for which water 
quality was identified as a factor for listing under the Endangered 
Species Act (ESA) or as a limiting factor within species recovery 
plans. Because of this analysis, EPA identified seven fish species and 
one dragonfly species that may experience changes in population growth 
rates as a result of 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 meta-analysis of 31 stated preference 
studies eliciting WTP for these changes (Richardson and Loomis 2009). 
This meta-analysis is based on studies conducted in the United States 
that valued threatened, rare, or endangered fish, bird, reptile, or 
mammal species. Because the underlying meta-data does not include 
insect valuation studies, EPA was unable to monetize any benefits for 
potential population 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).

[[Page 34515]]



                                      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    $8.3..................  $38.0.................  $49.9.................  $82.8.................  $81.9
 \a\.                             ($2.0 to $22.4).......  ($7.1 to $107.1)......  ($10.2 to $137.6).....  ($19.6 to $215.8).....  ($19.3 to $214.1)
                                 -----------------------------------------------------------------------------------------------------------------------
Benefits to E&T Species \b\.....  $7.0..................  $7.0..................  $10.0.................  $33.3.................  $33.3
                                  ($3.9 to $10.0).......  ($3.9 to $10.0).......  ($5.5 to $14.2).......  ($18.2 to $47.3)......  ($18.2 to $47.3)
                                 -----------------------------------------------------------------------------------------------------------------------
    Total Ecological and          $15.3.................  $45.0.................  $59.9.................  $116.1................  $115.2
     Recreational Uses Benefits   ($5.8 to $32.4).......  ($11.0 to $117.7).....  ($15.7 to $151.8).....  ($37.8 to $263.1).....  ($37.5 to $261.4)
     \d\.
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    7% Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Improved Surface Water Quality    $6.9..................  $31.7.................  $41.7.................  $69.2.................  $68.5
 \a\.                             ($1.6 to $18.7).......  ($6.0 to $48.3).......  ($8.5 to $115.0)......  ($16.4 to $180.3).....  ($16.1 to $178.9)
                                 -----------------------------------------------------------------------------------------------------------------------
Benefits to E&T Species \b\.....  $5.9..................  $5.9..................  $8.4..................  $27.8.................  $27.8
                                  ($3.2 to $8.4)........  ($3.2 to $8.4)........  ($4.6 to $11.9).......  ($15.2 to $39.5)......  ($15.2 to $39.5)
                                 -----------------------------------------------------------------------------------------------------------------------
    Total Ecological and          $12.8.................  $37.6.................  $50.1.................  $97.0.................  $96.2
     Recreational Uses Benefits   ($4.8 to $27.0).......  ($9.1 to $56.6).......  ($13.1 to $126.9).....  ($31.6 to $219.8).....  ($31.3 to $218.4)
     \d\.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values represent partial benefits only for reaches that receive direct discharges from steam electric plants. Range in parenthesis represents the
  5th and 95th percentile of the WTP distribution.
\b\ Range in parenthesis provides the low and high bound estimates.
\c\ Range in parenthesis provides the 5th and 95th percentile of the WTP distribution incorporating minimum and maximum flow reduction assumptions.
\d\ Totals may not add up due to independent rounding.
\e\ EPA did not estimate the benefits of Options 3a, 3b and 4a. EPA expects the benefits of Option 4a to be between those of Options 3 and 4.

3. Groundwater Quality Benefits From Reduced Groundwater Contamination
    EPA expects that some of the regulatory options will eliminate the 
future leaching of steam electric pollutants from steam electric 
impoundments to groundwater aquifers. The Agency monetized the 
associated benefits to households using private drinking wells in the 
vicinity of steam electric plants based on a benefits transfer from 
groundwater valuation studies. Specifically, EPA used existing 
groundwater valuation studies to derive household WTP estimates for two 
categorical improvements in groundwater quality: (1) ``greatly 
improved'' and (2) ``improved.''
    EPA identified the exposed population as the number of households 
using private drinking water wells in the vicinity of steam electric 
impoundments. EPA then modeled pollutant concentrations in the affected 
aquifers and determined which 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
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 34516]]

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).
---------------------------------------------------------------------------

    \86\ EPA also estimated benefits using a best-fit regression 
equation developed based on the historical data that relates the 
probability of impoundment failure to impoundment capacity. For 
details, see Appendix G of the BCA.
    \87\ Natural resource damages do not include cleanup costs (or 
legal costs) but include only the resource restoration and 
compensation values. For example, in one case, Israel (2006) found 
that ``In total, the State's claim was $764 million, $342 million of 
which was restoration cost damages, $410 million of which was 
compensable value damages, and $12 million of which was assessment 
and legal costs.'' For this case, EPA used the sum of $342 million 
and $410 million (excluded legal costs) as the value of natural 
resource damages.
    \88\ For this analysis, litigation costs include the costs 
associated with negotiating NRD, determining responsibility among 
potentially responsible parties, and litigating details regarding 
settlements and remediation. These activities involve services, 
whether performed by the complying entity or other parties that EPA 
expects would be required in the absence of this regulation in the 
event of an impoundment failure. Note that the litigation costs do 
not include fines, cleanup costs, damages, or other costs that 
constitute transfers or are already accounted for in the other 
categories analyzed separately.
    \89\ This estimate assumes that each failure results in a 
spilled volume equal to 6.45 percent of the impoundment capacity, 
based on the average ratio of spill volume to impoundment capacity 
for 15 releases for which ORCR obtained both spill volume and 
capacity data.
---------------------------------------------------------------------------

    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 air-related 
benefits for Options 3 and 4 only, as these are the two options 
analyzed in IPM. Table XIV-6

[[Page 34517]]

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             $127.6            $170.5
 CO2-related benefits)..............
7% Discount Rate (for NOX, SO2, and               82.3              74.6
 CO2-related benefits) a b..........
------------------------------------------------------------------------
\a\ Because SCC values are not available for the 7 percent discount
  rate, EPA used the SCC based on a 5 percent discount rate to estimate
  values presented for the 7 percent discount rate. EPA uses 5 percent
  to discount CO2-related benefits and 7 percent to discount benefits
  from changes in NOX and SO2 emissions.
\b\ Air benefits for Option 4 at the 7 percent discount rate are lower
  than benefits estimated for Option 3 due to (1) smaller SO2 emissions
  reductions projected by IPM for Option 4 than Option 3 in early years
  and (2) differences in source- and discount-specific BPT and SCC
  values.
\c\ EPA did not estimate the benefits of Options 3a, 1, 2, 3b, 4a and 5.
  EPA expects the benefits of Option 4a to be between those of Options 3
  and 4.

6. Benefits From Reduced Water Withdrawals (Increased Availability of 
Groundwater Resources)
    Steam electric plants use water for handling solid waste (e.g., fly 
ash, bottom ash) and for operating wet FGD scrubbers. By eliminating or 
reducing water used in sluicing operations or prompting the recycling 
of water in FGD wastewater treatment systems, the proposed ELGs are 
expected to reduce water withdrawals from surface waterbodies and 
reduce demand on aquifers, in the case of plants that rely on 
groundwater sources.
    EPA estimated the benefits of reduced groundwater withdrawals based 
on avoided costs of groundwater supply. For each affected facility and 
regulatory option, EPA multiplied the reduction in groundwater 
withdrawal (in gallons per year) by water costs ranging between $150 
and $500 per acre-foot.
    Table XIV-7 summarizes the annualized benefits associated with 
changes in water use by steam electric plants for five of the eight 
options. Chapter 9 in the BCA report provides the details of this 
analysis. While EPA did not estimate benefits of Options 3a, 3b and 4a, 
the Agency expects the benefits of Option 4a to be between those of 
Options 3 and 4.

                            Table XIV-7--Annualized Monetized Benefits of Reduced Water Withdrawals by Steam Electric Plants
                                                                   [Million 2010$] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                       Benefit category                             Option 1          Option 2          Option 3          Option 4          Option 5
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    3% Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Avoided groundwater withdrawals...............................              $0.0              $0.0             <$0.1              $0.1              $0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    7% Discount Rate
--------------------------------------------------------------------------------------------------------------------------------------------------------
Avoided groundwater withdrawals...............................               0.0               0.0              <0.1               0.1              0.1
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ EPA did not estimate the benefits of Options 3a and 4a. EPA expects the benefits of Option 4a to be between those of Options 3 and 4.

C. Total Monetized Benefits

    Using the analysis approach described above, EPA estimates annual 
total benefits for the six monetized categories at approximately $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

[[Page 34518]]

 
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  ................
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values represent mean benefit estimates. Totals may not add up due to independent rounding. Option 5 results in slightly lower benefits because,
  under Option 4, EPA assumes that plants with both leachate and FGD waste streams implement chemical precipitation and biological treatment for the
  combined streams. Under Option 5, EPA assumes that plants treat the two streams separately: FGD wastewater by evaporation and leachate using chemical
  precipitation (which removes less pollutant load than biological treatment).
\b\ There may be some overlap between the willingness-to-pay (WTP) for surface water quality improvements and WTP for benefits to threatened and
  endangered species.
\c\ Values represent partial human health benefits only for reaches that receive direct discharges from steam electric plants.
\d\ EPA estimated air-related benefits for Options 3 and 4 only because these benefits were estimated as part of the Agency's analysis using IPM. Total
  benefits for Options 1, 2, and 5 are therefore understated. Air benefits for Option 4 at the 7 percent discount rate are lower than benefits estimated
  for Option 3 due to (1) smaller SO2 emissions reductions projected by IPM for Option 4 than Option 3 in early years and (2) differences in source- and
  discount-specific BPT and SCC values.
\e\ Because SCC values are not available for the 7 percent discount rate, EPA used the SCC based on a 5 percent discount rate and discounted CO2-related
  benefits using a 5 percent discount rate, as compared to benefits in other categories, which are discounted using the 7 percent discount rate.
\f\ EPA 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.

[[Page 34519]]



                           Table XIV-9--Total Monetized Benefits for the Proposed Rule
                                                [Millions; 2010]
----------------------------------------------------------------------------------------------------------------
                                                                               Total monetized   Total monetized
              Regulatory option                           Method                benefits  3%      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
----------------------------------------------------------------------------------------------------------------
\a\ Total benefits for Options 1, 2, and 5 do not include air-related benefits (see Table XIV-8).
\b\ EPA did not estimate benefits for Options 3a, 3b and 4a. EPA inferred benefits for Options 3a, 3b, and 4a
  for illustrative purposes using elements of the more rigorous analysis done to estimate benefits for Options 3
  and 4.

D. Children's Environmental Health

    As described in Section XIV.B.1, EPA assessed whether 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 pre-school age children from reduced 
exposure to lead and (2) avoided neurological damages from in-utero 
exposure to mercury.
    This analysis considered several measures of children's health 
benefits associated with lead exposure for children up to age six. 
Avoided neurological and cognitive damages were expressed as changes in 
three metrics: (1) Overall IQ levels; (2) the incidence of low IQ 
scores (<70); and (3) the incidence of blood-lead levels above 20 mg/
dL. EPA's methodology for assessing lead-related benefits to children 
is presented in Chapter 3 of the BCA report. EPA analysis shows that 
benefits to children from reduced lead discharges range from $0.1 
million to $6.8 million (at 3 percent discount), depending on the 
regulatory option; annual benefits for 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 
in-utero mercury exposure from maternal fish consumption in exposed 
populations. Chapter 3 of the BCA report presents EPA's methodology for 
assessing mercury-related benefits to children. Among approximately 
1,932 babies born per year who are potentially exposed to discharges of 
mercury from steam electric plants, the proposed ELGs reduce total IQ 
point losses over the period of 2017 through 2040 by about 9,000 to 
24,000 points, depending on the regulatory option. The monetary 
benefits associated with the avoided IQ point losses range from $3.8 
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

[[Page 34520]]

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 non-hazardous landfill and its distance from the plant determines 
the length of travel time. EPA also estimated the energy usage 
associated with the dust suppression water trucks and earth moving 
equipment based on specific plant operations. For example, EPA 
calculated earth moving equipment energy usage only if the plant 
operates an impoundment. To determine the potential decrease in fuel 
consumption, EPA estimated the amount of fuel saved by reducing the 
number of backhoes needed to dredge solids from ash impoundments, due 
to the reduction of wet sluice operations. See DCN SE01957 (Incremental 
Costs and Pollutant Removals for Proposed Effluent Limitations 
Guidelines and Standards for the Steam Electric Generating Point Source 
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
----------------------------------------------------------------------------------------------------------------
                                                             Energy use associated with proposed rule
            Non-water quality impact             ---------------------------------------------------------------
                                                     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

[[Page 34521]]

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
----------------------------------------------------------------------------------------------------------------
                                                                        2009 Emissions by
                                                  Value associated       electric power          Increase in
           Non-water quality impact                with option 3a      industry  (million      emissions  (%)
                                                   (million tons)             tons)
----------------------------------------------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------------------------
\a\ EPA quantified the air emissions associated with additional electricity and additional transportation for
  Option 3a. Based on the values quantified for Option 3 for changes to air emissions projected by IPM, EPA
  calculated the range of emissions for NOX. The lower end of the range represents the emissions only associated
  with additional electricity and transportation. The upper end of the range also includes the changes to air
  emissions projected by IPM (based on Option 3), which are larger than would be expected for Option 3a.
\b\ EPA quantified the air emissions associated with additional electricity and additional transportation for
  Option 3a. Based on the values quantified for Option 3 for changes to air emissions projected by IPM, which
  were negative, EPA decided not to include these IPM air emission changes in the calculated SOx and CO2
  emissions for Option 3a. These SOX and CO2 emissions are considered maximum values because EPA expects that
  the air emission changes projected by IPM for Option 3a will also be negative (as they are for Options 3 and
  4).


                          Table XV-3--Air Emissions Associated With BAT/PSES Option 3b
----------------------------------------------------------------------------------------------------------------
                                                                        2009 Emissions by
                                                  Value associated       electric power          Increase in
           Non-water quality impact                with option 3b      industry  (million      emissions  (%)
                                                   (million tons)             tons)
----------------------------------------------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------------------------
\a\ EPA quantified the air emissions associated with additional electricity and additional transportation for
  Option 3b. Based on the values quantified for Option 3 for changes to air emissions projected by IPM, EPA
  calculated the range of emissions for NOX. The lower end of the range represents the emissions only associated
  with additional electricity and transportation. The upper end of the range also includes the changes to air
  emissions projected by IPM (based on Option 3), which are larger than would be expected for Option 3b.
\b\ EPA quantified the air emissions associated with additional electricity and additional transportation for
  Option 3b. Based on the values quantified for Option 3 for changes to air emissions projected IPM, which were
  negative, EPA decided not to include these IPM air emission changes in the calculated SOX and CO2 emissions
  for Option 3b. These SOX and CO2 emissions are considered maximum values because EPA expects that the air
  emission changes projected for IPM for Option 3b will also be negative (as they are for Options 3 and 4).


                           Table XV-4--Air Emissions Associated With BAT/PSES Option 3
----------------------------------------------------------------------------------------------------------------
                                                                        2009 Emissions by
                                                  Value associated       electric power          Increase in
           Non-water quality impact                 with option 3      industry  (million      emissions  (%)
                                                   (million tons)             tons)
----------------------------------------------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------------------------
                                                                        2009 Emissions by
                                                  Value associated       electric power          Increase in
           Non-water quality impact                with option 4a      industry  (million      emissions  (%)
                                                   (million tons)             tons)
----------------------------------------------------------------------------------------------------------------
NOX...........................................           \a\ 0.00132                     1                 0.132
SOX...........................................         \a\ <-0.00258                     6               <-0.043
CO2...........................................           \a\ <-1.106                 2,403               <-0.046
----------------------------------------------------------------------------------------------------------------
\a\ EPA quantified the air emissions associated with additional electricity and additional transportation for
  Option 4a. To estimate the total emissions for Option 4a, EPA added the changes to air emissions projected by
  IPM for Options 3 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.


[[Page 34522]]

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.
---------------------------------------------------------------------------

    \90\ As described previously, the preferred regulatory options 
for BAT and PSES for fly ash and bottom ash transport water are not 
expected to alter the amount of ash or other combustion residuals 
generated. Therefore, there is no increase for Option 3a and the 
increase for Option 4a is equal to the increase for Option 3.
---------------------------------------------------------------------------

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 technology-based 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

[[Page 34523]]

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.
---------------------------------------------------------------------------

    \91\ Except where BAT is equivalent to BPT.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \92\ Similarly applies to PSES and PSNS.
---------------------------------------------------------------------------

    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 tank-based FGD 
wastewater treatment system, and compliance with the BPT requirements 
for the commingled new/legacy FGD wastewater at the point of discharge 
from the FGD wastewater impoundment. The same plant may also configure 
its system so that the impoundment (which also contains legacy FGD 
wastewater)is used for equalization, with the impoundment effluent sent 
to the tank-based treatment system. In this case, both the newly 
generated FGD wastewater and the legacy FGD wastewater would be treated 
by the tank-based treatment system and an appropriate compliance 
monitoring point would be the treatment system effluent. Under such a 
scenario, commingling of FGD wastewater generated at any date may occur 
as long as such 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 tank-based leachate treatment system so that the 
impoundment (which also contains legacy combustion residual leachate) 
is used for equalization, with the impoundment effluent ultimately sent 
to the tank-based treatment system. In this case, both the newly 
generated leachate and the legacy leachate would

[[Page 34524]]

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 tank-based leachate treatment systems whose effluent is 
discharged to the impoundment containing the legacy leachate. In this 
case, the plant would be required to demonstrate compliance with the 
proposed effluent limitations and standards for the newly generated 
combustion residual leachate at the effluent from the 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.
---------------------------------------------------------------------------

    \93\ For the purposes of this rulemaking, EPA is considering the 
following terms related to analytical method sensitivity to be 
synonymous: ``quantitation limit,'' ``reporting limit,'' ``level of 
quantitation,'' and ``minimum level.''
---------------------------------------------------------------------------

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

[[Page 34525]]

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).

[[Page 34526]]

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\
------------------------------------------------------------------------
                                                                Total
                                                   Total      monetized
              Regulatory  option                   social      benefits
                                                 costs \b\   \c\ \d\ \e\
------------------------------------------------------------------------
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
------------------------------------------------------------------------
\a\ All costs and benefits were annualized over 24 years and using a 3
  percent discount rate.
\b\ Total social costs include compliance costs to facilities.
\c\ Mean benefit estimates. Values include partial human health benefits
  only for reaches that receive direct discharges from steam electric
  plants. Values for Options 1, 2, and 5 do not include air-related
  benefits.
\d\ EPA estimated certain benefits for Options 3 and 4 only. Total
  benefits for Options 1, 2, and 5 are therefore understated. See
  Section XIV and Table XIV-8.
\e\ EPA did not estimate benefits for Options 3a, 3b and 4a. The
  benefits of Option 4a are expected to be between those of Options 3
  and 4.

    EPA also analyzed the employment effects of the proposed ELGs. The 
results of that analysis are summarized in Section XI.E.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden. 
However, the Office of Management and Budget (OMB) has previously 
approved the information collection requirements contained in the 
existing regulations 40 CFR part 423 under the provisions of the 
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB 
control number 2040-0281. The OMB 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 
site-specific 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 one-time burden, however, would 
be no more excessive than the existing burden to develop technology-
based effluent limitations on a BPJ basis; in fact, it would likely be 
less burdensome. Nevertheless, EPA conservatively estimated no net 
change (i.e., increase or decrease) in the cost burden to federal or 
state governments associated with 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-for-profit enterprise which is 
independently owned and operated and is not dominant in its field. In 
reaching entity size determinations, EPA assumed that all federal or 
state entities owning steam electric plants affected by this rulemaking 
are not small entities.
    The SBA criteria for identifying small, non-government entities in 
the electric power industry are as follows:
     For non-government entities with electric power generation 
as a primary business, small entities are those with total annual 
electric output less than 4 million MWh;
     For non-federal or state jurisdictions, small entities are 
those with a population of less than 50,000.
     For entities with a primary business other than electric 
power generation, the relevant size criteria are based on revenue or 
number of employees by NAICS sector (see Table XVII-2).

[[Page 34527]]



    Table XVII-2--NAICS Codes and SBA Entity Size Standards for Steam
  Electric Generators with a Primary Business Other Than Electric Power
                              Generation a
------------------------------------------------------------------------
                                                      SBA size standard
    NAICS Code             NAICS description                 \b\
------------------------------------------------------------------------
211111............  Crude Petroleum and Natural     500 Employees.
                     Gas Extraction.
212111............  Bituminous Coal and Lignite     500 Employees.
                     Surface Mining.
213112............  Support Activities for Oil and  $7 million in
                     Gas Operations.                 revenue.
221210............  Natural Gas Distribution......  500 Employees.
221310............  Water Supply and Irrigation     $7 million in
                     Systems.                        revenue.
221330............  Steam and                       $12.5 million in
                     Air[dash]Conditioning Supply.   revenue.
237130............  Power and Communication Line    $33.5 million in
                     and Related Structures          revenue.
                     Construction.
324110............  Petroleum Refineries..........  1,500 Employees.
332410............  Power Boiler and Heat           500 Employees.
                     Exchanger Manufacturing.
333611............  Turbine and Turbine Generator   1,000 Employees.
                     Set Unit Manufacturing.
423510............  Metal Service Centers and       100 Employees.
                     Other Metal Merchant
                     Wholesalers.
486110............  Pipeline Transportation of      1,500 Employees.
                     Crude Oil.
522110............  Commercial Banking............  $175 million in
                                                     assets.
523110............  Investment Banking and          $7 million in
                     Securities Dealing.             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    1,500 employees.
                     Insurance Carriers.
525910............  Open[dash]End Investment Funds  $7 million in
                                                     revenue.
541614............  Process, Physical Distribution  $14 million in
                     and Logistics Consulting        revenue.
                     Services.
541690............  Other Scientific and Technical  $14 million in
                     Consulting Services.            revenue.
551111............  Offices of Bank Holding         $7 million in
                     Companies.                      revenue.
551112............  Offices of Other Holding        $7 million in
                     Companies.                      revenue.
562219............  Other Nonhazardous Waste        $12.5 million in
                     Treatment and Disposal.         revenue.\c\
------------------------------------------------------------------------
\a\ Certain plants affected by this rulemaking are owned by non-
  government entities whose primary business is not electric power
  generation.
\b\ Based on size standards effective at the time EPA conducted this
  analysis (SBA size standards, effective October 1, 2012).
\c\ EPA is aware that SBA revised the size standard applicable to this
  sector, effective January 7, 2013 (from $12.5 million in revenue to
  $35.5 million in revenue); EPA used the size standards effective at
  the time the analyses were completed and will update the size
  standards as part of revisions to support final rulemaking.

    EPA identified the domestic parent entity of each steam electric 
plant and obtained the entity's revenue from the Steam Electric 
industry survey or from publicly available data sources. In this 
analysis, the domestic parent entity associated with any given plant is 
defined as that entity that has the largest ownership share in the 
plant. To determine whether these entities are small entities based on 
the size criteria outlined above, EPA compared the relevant measure for 
the identified parent entities to the appropriate SBA size criterion.
    EPA used alternative sample-weighting approaches, which provide a 
range of estimates of the numbers of small entities and affected plants 
owned by these small entities (see Chapter 8 in the RIA for details of 
methodology used to develop weighted estimates). The results of this 
analysis using both weighting approaches are summarized below.
    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\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Lower bound estimate of number of entities      Upper bound estimate of number of entities
                                                                 owning steam electric plants \b\                owning steam electric plants \b\
                     Ownership type                      -----------------------------------------------------------------------------------------------
                                                               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.

[[Page 34528]]

 
\b\ Of these, 92 entities, 14 of which are small, own steam electric plants that are expected to incur compliance costs under at least one regulatory
  option under both Case 1 and Case 2.
\c\ EPA was unable to determine size for 10 parent entities; for this analysis, these entities are assumed to be small.

    In total, small entities own a total of 189 steam electric plants, 
or 18 percent of the total universe of 1,079 steam electric plants. Of 
these, EPA determined that 14 plants may incur compliance costs under 
at least one of the 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 sample-weighting approaches, which provide a 
range of estimates of the numbers of small entities and steam electric 
plants owned by these small entities. The results of this analysis 
using both weighting approaches are summarized below. Table XVII-4 
presents the estimated numbers of small entities incurring costs 
exceeding 1 percent and 3 percent of revenue. For more information on 
this analysis in general and the weighting approaches in particular, 
see Chapter 7 in the RIA report.

  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]
----------------------------------------------------------------------------------------------------------------
                                                 Cost >=1% of revenue                Cost >=3% of revenue
                                         -----------------------------------------------------------------------
            Regulatory option                                  % of small                          % of small
                                           Number of small      affected       Number of small      affected
                                              entities        entities \b\      entities \a\      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
----------------------------------------------------------------------------------------------------------------
\a\ The number of entities with cost-to-revenue ratios exceeding 3 percent is a subset of the number of entities
  with such ratios exceeding 1 percent.
\b\ Percentage values were calculated relative to the total of 97 (Case 1) and 170 (Case 2) small entities
  owning steam electric plants.


[[Page 34529]]

    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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                            Lower bound estimate of number  of entities owning      Upper bound estimate  of number of entities owning
                                                          steam  electric plants                                  steam  electric plants
                                        ----------------------------------------------------------------------------------------------------------------
                                            Cost >=1% of revenue         Cost >=3% of revenue        Cost >=1% of revenue        Cost >=3% of revenue
           Regulatory option            ----------------------------------------------------------------------------------------------------------------
                                           Number of    % of small     Number of     % of small     Number of    % of small     Number of    % of small
                                             small       affected        small        affected        small       affected        small       affected
                                           entities    entities \c\  entities \b\   entities \c\    entities    entities \c\  entities \b\  entities \c\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 3:
    Cooperative........................             2          15.4             2          15.4              2           9.4             2           9.4
    Investor-Owned.....................             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
    Investor-Owned.....................             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
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Options 3a and 3b are not included in the table since no small entity has costs 1 percent of revenue or higher under these two preferred options.
\b\ The number of entities with cost-to-revenue ratios exceeding 3 percent is a subset of the number of entities with such ratios exceeding 1 percent.
\c\ Percentage values were calculated relative to the total of 97 (Case 1) and 170 (Case 2) small entities owning steam electric plants. EPA expects
  that Case 2 is a more likely ownership scenario for small entities (e.g., small municipalities) as small entities may be less likely to own multiple
  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

[[Page 34530]]

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-to-government 
dialogue in March 2012.
    Consistent with Section 205, EPA has identified and considered a 
reasonable number of regulatory alternatives. EPA considered and 
analyzed several alternative regulatory options to determine BAT/BADCT. 
These regulatory options are discussed in Section VIII of this 
preamble. These options included a range of technology-based 
approaches. As discussed in detail in Section VIII, EPA is proposing 
Options 3a, 3b, 3 and 4a as the preferred BAT and PSES options because 
they are technologically available, economically achievable, and have 
acceptable non-water quality environmental impacts. EPA is proposing 
Option 4 as the preferred NSPS and PSNS option because 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 government-owned facilities or for small non-government-owned 
facilities. On this basis, EPA concludes that the compliance cost 
requirements of the proposed Steam Electric ELGs would not 
significantly or uniquely affect small governments.

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

[[Page 34531]]

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-
to-government 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

[[Page 34532]]

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 
non-adjoining property when under the operational control of the 
permitted facility.
    Direct Discharger--A facility that discharges or may discharge 
treated or untreated wastewaters into waters of the United States.
    DOE--Department of Energy.
    Dry bottom ash handling system--A system that does not use water 
to convey bottom ash away from the boiler. It includes systems that 
collect and convey the ash without any use of water, as well as 
systems in which bottom ash is mechanically or pneumatically 
conveyed away from the boiler.
    Dry fly ash handling system--A system that does not use water as 
the transport medium to convey fly ash away from particulate 
collection equipment.
    EIA--Energy Information Administration.
    EO--Executive Order.
    EPA--U.S. Environmental Protection Agency.
    Facility -- All property owned, operated, leased, or under the 
control of the same person or entity.
    Flue Gas Desulfurization (FGD) Wastewater--Any process 
wastewater generated specifically from the wet flue gas 
desulfurization scrubber system, including any solids separation or 
solids dewatering processes.
    Flue Gas Mercury Control (FGMC) System--An air pollution control 
system installed or operated for the purpose of removing mercury 
from flue gas.
    Flue Gas Mercury Control Wastewater--Any process wastewater 
generated from an air pollution control system installed or operated 
for the purpose of removing mercury from flue gas. This 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.

[[Page 34533]]

    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

0
1. The authority citation for part 423 is revised to read as follows:

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

0
2. Section 423.10 is revised as follows:


Sec.  423.10  Applicability.

    The provisions of this part apply to discharges resulting from the 
operation of a generating unit by an establishment whose generation of 
electricity is the predominant source of revenue or principal reason 
for operation, and 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 Sec. Sec.  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 Sec.  423.13 of this part (for direct 
dischargers) or the revised pretreatment standards specified in Sec.  
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.
0
3. Section 423.11 is amended by:
0
a. Revising paragraphs (b) and (e); and
0
b. Adding paragraphs (n) through (u).
    The revised and added paragraphs read as follows:


Sec.  423.11  Specialized definitions.

* * * * *
    (b) The term low volume waste sources means, taken collectively as 
if from one source, wastewater from all sources except those for which 
specific limitations 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.

[[Page 34534]]

0
4. Section 423.12 is amended by:
0
a. Revising paragraphs (b)(11) and (12); and
0
b. Adding paragraph (b)(13).
    The revised and added paragraphs read as follows:


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

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

------------------------------------------------------------------------
                                          BPT effluent limitations
                                   -------------------------------------
                                                        Average of daily
  Pollutant or pollutant property                        values for 30
                                    Maximum for any 1   consecutive days
                                        day (mg/l)      shall not exceed
                                                             (mg/l)
------------------------------------------------------------------------
TSS...............................              100.0               30.0
Oil and grease....................               20.0               15.0
------------------------------------------------------------------------

    (12) At the permitting authority's discretion, the quantity of 
pollutant allowed to be discharged may be expressed as a concentration 
limitation instead of the 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.
0
5. Section 423.13 is amended by:
0
a. Adding paragraph (f);
0
b. Revising paragraphs (g) and (h); and
0
c. Adding paragraphs (i) through (n).


Sec.  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:

------------------------------------------------------------------------
                                          BAT effluent limitations
                                   -------------------------------------
                                                        Average of daily
  Pollutant or pollutant property                        values for 30
                                    Maximum for any 1   consecutive days
                                        day (mg/l)      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 Sec.  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 Sec.  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:

------------------------------------------------------------------------
                                         BAT effluent limitations
                                 ---------------------------------------
                                                       Average of daily
 Pollutant or pollutant property   Maximum for any 1     values for 30
                                          day          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
------------------------------------------------------------------------


[[Page 34535]]

    (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 Sec.  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 Sec.  423.13(g) reflect 
proposed Option 4a, Option 3, and Option 3b (for units located at 
facilities with a total wet-scrubbed capacity of 2,000 MW or more), 
only. Under proposed Option 3a and Option 3b (for units located at 
facilities with a total wet-scrubbed capacity of less than 2,000 
MW), BAT would continue to need to be determined on a site-specific 
basis using best professional judgment.

    (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 
Sec.  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 Sec.  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:

------------------------------------------------------------------------
                                         BAT effluent limitations
                                 ---------------------------------------
                                                       Average of daily
 Pollutant or pollutant property   Maximum for any 1     values for 30
                                          day          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
------------------------------------------------------------------------
\1\ This regulation does not specify this type of limitation for this
  pollutant; however, permitting authorities may do so as appropriate.

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

    Note to (k):  All proposed revisions to Sec.  423.13(k) reflect 
proposed Option 4a, only. Under proposed Option 3, Option 3a, and 
Option 3b, Sec.  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 Sec.  
423.12(b)(4).


[[Page 34536]]


    (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 Sec.  423.12(b)(11).
    (m) At the permitting authority's discretion, the quantity of 
pollutant allowed to be discharged may be expressed as a concentration 
limitation instead of any mass based limitations specified in 
paragraphs (b) through (l) of this section. Concentration limitations 
shall be those concentrations specified in this section.
    (n) In the event that wastestreams from various sources are 
combined for treatment or discharge, the quantity of each pollutant or 
pollutant property controlled in paragraphs (a) through (m) of this 
section attributable to each controlled waste source shall not exceed 
the specified limitation for that waste source.
0
6. Section 423.15 is amended by revising paragraphs (a) and (b) to read 
as follows:


Sec.  423.15  New source performance standards (NSPS).

    (a) 1982 New source performance standards. Any new source as of 
November 19, 1982, subject to this subpart, must achieve the following 
new source performance standards and the revised requirements of Sec.  
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:

------------------------------------------------------------------------
                                       Pollutant or pollutant property
                                   -------------------------------------
                                                        Average of daily
               NSPS                                      values for 30
                                     Maximum for  any   consecutive days
                                       1 day (mg/l)     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:

------------------------------------------------------------------------
                                                    NSPS
                                   -------------------------------------
                                                        Average of daily
  Pollutant or pollutant property                        values for 30
                                    Maximum for any 1   consecutive days
                                        day (mg/l)      shall not exceed
                                                             (mg/l)
------------------------------------------------------------------------
TSS...............................              100.0               30.0
Oil and grease....................               20.0               15.0
Copper, total.....................                1.0                1.0
Iron, total.......................                1.0                1.0
------------------------------------------------------------------------

    (5) [Reserved].
    (6) The quantity of pollutants discharged in bottom ash transport 
water shall not exceed the quantity determined by multiplying the flow 
of the bottom ash transport water times the concentration listed in the 
following table:

------------------------------------------------------------------------
                                                    NSPS
                                   -------------------------------------
                                                        Average of daily
  Pollutant or pollutant property                        values for 30
                                    Maximum for  any1   consecutive days
                                       day  (mg/l)      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:

[[Page 34537]]



------------------------------------------------------------------------
                                                               NSPS
                                                        ----------------
            Pollutant or pollutant property                  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:

------------------------------------------------------------------------
                                         Maximum            Average
  Pollutant or pollutant property     concentration      concentration
                                          (mg/l)             (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:

------------------------------------------------------------------------
                                         Maximum            Average
  Pollutant or pollutant property     concentration      concentration
                                          (mg/l)             (mg/l)
------------------------------------------------------------------------
Free available chlorine...........                0.5                0.2
------------------------------------------------------------------------


------------------------------------------------------------------------
                                                    NSPS
                                   -------------------------------------
                                                        Average of daily
  Pollutant or pollutant property    Maximum for  any    values for 30
                                          1 day         consecutive days
                                      concentration     shall not exceed
                                          (mg/l)             (mg/l)
------------------------------------------------------------------------
The 126 priority pollutants                     (\1\)              (\1\)
 (Appendix A) contained in
 chemicals added for cooling tower
 maintenance, except:.............
Chromium, total...................                0.2                0.2
Zinc, total.......................                1.0                1.0
------------------------------------------------------------------------
\1\ No detectable amount.

    (ii) Neither free available chlorine nor total residual chlorine 
may be discharged from any unit for more than two hours in any one day 
and not more than one unit in any plant may discharge free available or 
total residual chlorine at any one time unless the utility can 
demonstrate to the Regional Administrator or State, if the State has 
NPDES permit issuing authority, that the units in a particular location 
cannot operate at or below this level of chlorination.
    (iii) At the permitting authority's discretion, instead of the 
monitoring in 40 CFR 122.11(b), compliance with the 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 Sec.  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:

 
------------------------------------------------------------------------
                                                    NSPS
  Pollutant or pollutant property  -------------------------------------
                                                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 
Sec.  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

[[Page 34538]]

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:

 
------------------------------------------------------------------------
                                                    NSPS
                                   -------------------------------------
                                                        Average of daily
  Pollutant or pollutant property                        values for 30
                                     Maximum for  any   consecutive days
                                       1 day (mg/l)     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:

 
------------------------------------------------------------------------
                                                    NSPS
                                   -------------------------------------
                                                        Average of daily
  Pollutant or pollutant property                        values for 30
                                     Maximum for  any   consecutive days
                                       1 day (mg/l)     shall not exceed
                                                             (mg/l)
------------------------------------------------------------------------
TSS...............................              100.0               30.0
Oil and grease....................               20.0               15.0
Copper, total.....................                1.0                1.0
Iron, total.......................                1.0                1.0
------------------------------------------------------------------------

    (5) 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:

 
------------------------------------------------------------------------
                                                    NSPS
                                   -------------------------------------
                                                        Average of daily
  Pollutant or pollutant property                        values for 30
                                     Maximum for  any   consecutive days
                                       1 day (mg/l)     shall not exceed
                                                             (mg/l)
------------------------------------------------------------------------
TSS...............................              100.0               30.0
Oil and grease....................               20.0               15.0
Copper, total.....................                1.0                1.0
Iron, total.......................                1.0                1.0
------------------------------------------------------------------------

    (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:

------------------------------------------------------------------------
                                                               NSPS
                                                        ----------------
            Pollutant or pollutant property                  Maximum
                                                          concentration
                                                              (mg/l)
------------------------------------------------------------------------
Total residual chlorine................................             0.20
------------------------------------------------------------------------

    (ii) Total residual chlorine may not be discharged from any single 
generating

[[Page 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:

------------------------------------------------------------------------
                                                    NSPS
                                   -------------------------------------
  Pollutant or pollutant property        Maximum            Average
                                      concentration      concentration
                                          (mg/l)             (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:

------------------------------------------------------------------------
                                                    NSPS
                                   -------------------------------------
  Pollutant or pollutant property        Maximum            Average
                                      concentration      concentration
                                          (mg/l)             (mg/l)
------------------------------------------------------------------------
Free available chlorine...........                0.5                0.2
------------------------------------------------------------------------


------------------------------------------------------------------------
                                                        Average of daily
                                                         values for 30
  Pollutant or pollutant property    Maximum for  any   consecutive days
                                       1 day (mg/l)     shall not exceed
                                                             (mg/l)
------------------------------------------------------------------------
The 126 priority pollutants                     (\1\)              (\1\)
 (Appendix A) contained in
 chemicals added for cooling tower
 maintenance, except:.............
Chromium, total...................                0.2                0.2
Zinc, total.......................                1.0                1.0
------------------------------------------------------------------------
\1\ No detectable amount.

    (ii) Neither free available chlorine nor total residual chlorine 
may be discharged from any unit for more than two hours in any one day 
and not more than one unit in any plant may discharge free available or 
total residual chlorine at any one time unless the utility can 
demonstrate to the Regional Administrator or State, if the State has 
NPDES permit issuing authority, that the units in a particular location 
cannot operate at or below this level of chlorination.
    (iii) At the permitting authority's discretion, instead of the 
monitoring in 40 CFR 122.11(b), compliance with the 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 Sec.  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:

------------------------------------------------------------------------
                                                    NSPS
  Pollutant or pollutant property  -------------------------------------
                                                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 
Sec.  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:

------------------------------------------------------------------------
                                                   NSPS
                                 ---------------------------------------
                                                       Average of daily
 Pollutant or pollutant property   Maximum for any1      values for 30
                                      day (mg/l)       consecutive days
                                                       shall not exceed
------------------------------------------------------------------------
Arsenic, total (ug/L)...........                8                   6

[[Page 34540]]

 
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:

------------------------------------------------------------------------
                                                   NSPS
                                 ---------------------------------------
                                                       Average ff daily
 Pollutant or pollutant property   Maximum for any 1     values for 30
                                          day          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
------------------------------------------------------------------------
\1\ This 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:

------------------------------------------------------------------------
                                                    NSPS
                                   -------------------------------------
                                                        Average of daily
  Pollutant or pollutant property   Maximum for any 1    values for 30
                                           day          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.
0
7. Section 423.16 is amended by adding paragraphs (c) and (e) through 
(i) to read as follows:


Sec.  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

[[Page 34541]]

the concentration listed in the following table:

------------------------------------------------------------------------
                                                               PSES
                                                           pretreatment
                                                            standards
            Pollutant or pollutant property             ----------------
                                                          Maximum  for 1
                                                           day  (mg/l)
------------------------------------------------------------------------
Copper, total..........................................              1.0
------------------------------------------------------------------------

* * * * *
    (e)(1) For any electric generating unit with a total nameplate 
generating capacity of more than 50 megawatts and that is not an oil-
fired unit, dischargers must meet the standards in this paragraph by a 
date determined by the control authority that is as soon as possible 
beginning July 1, 2017. These standards apply to pollutants in FGD 
wastewater generated on or after a date determined by the control 
authority that is as soon as possible beginning July 1, 2017. Such 
effluent limitations shall not allow the quantity of pollutants in FGD 
wastewater to exceed the quantity determined by multiplying the flow of 
FGD wastewater times the concentration listed in the following table:

------------------------------------------------------------------------
                                                   PSES
                                 ---------------------------------------
                                                       Average of daily
 Pollutant or pollutant property   Maximum for any 1     values for 30
                                          day          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:

------------------------------------------------------------------------
                                                   PSES
                                 ---------------------------------------
                                                       Average of daily
 Pollutant or pollutant property   Maximum for any 1     values for 30
                                          day          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
------------------------------------------------------------------------
\1\ This regulation does not specify this type of limitation for this
  pollutant; however, permitting authorities may do so as appropriate.


[[Page 34542]]

    (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.
0
8. Section 423.17 is amended by revising paragraphs (a) and (b) to read 
as follows:


Sec.  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 Sec.  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:

------------------------------------------------------------------------
                                                               PSNS
                                                        ----------------
            Pollutant or pollutant property              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:

------------------------------------------------------------------------
                                                               PSNS
                                                        ----------------
            Pollutant or pollutant property              Maximum for any
                                                           time (mg/l)
------------------------------------------------------------------------
The 126 priority pollutants (Appendix A) contained in              (\1\)
 chemicals added for cooling tower maintenance, except:
Chromium, total........................................              0.2
Zinc, total............................................              1.0
------------------------------------------------------------------------
\1\ No detectable amount.

    (ii) At the permitting authority's discretion, instead of the 
monitoring in 40 CFR 122.11(b), compliance with the 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:

------------------------------------------------------------------------
                                                               PSNS
                                                        ----------------
            Pollutant or pollutant property               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:

------------------------------------------------------------------------
                                                               PSNS
                                                        ----------------
            Pollutant or pollutant property               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:

------------------------------------------------------------------------
                                                               PSNS
                                                        ----------------
            Pollutant or pollutant property              Maximum for any
                                                           time (mg/l)
------------------------------------------------------------------------
The 126 priority pollutants (Appendix A) contained in              (\1\)
 chemicals added for cooling tower maintenance, except:
Chromium, total........................................              0.2
Zinc, total............................................              1.0
------------------------------------------------------------------------
\1\ No detectable amount.

    (ii) At the permitting authority's discretion, instead of the 
monitoring in 40 CFR 122.11(b), compliance with the 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:

----------------------------------------------------------------------------------------------------------------
                                                                                                 PSNS
                                                                                  ---------------------------------
                                                                                                        Average
                                                                                                          daily
                                                                  Pollutant or                          values for
                                                               pollutant property  Maximum for  any 1       30
                                                                                           day         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
----------------------------------------------------------------------------------------------------------------


[[Page 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:

----------------------------------------------------------------------------------------------------------------
                                                                                                 PSNS
                                                                                  ---------------------------------
                                                                                                        Average
                                                                                                          daily
                                                                  Pollutant or                          values for
                                                               pollutant property  Maximum for  any 1       30
                                                                                           day         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
----------------------------------------------------------------------------------------------------------------
\1\ This 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:

----------------------------------------------------------------------------------------------------------------
                                                                                                 PSNS
                                                                                   --------------------------------
                                                                                                        Average
                                                                    Pollutant or                          daily
                                                                     pollutant                          values for
                                                                      property       Maximum for  any       30
                                                                                          1 day        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)(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