Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category
Federal RegisterJun 7, 2013
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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
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
Entities potentially regulated by this action include:
Category
Example of regulated entity
North American
industry classification system (NAICS) code
Industry
Electric Power Generation Facilities—Electric Power Generation
22111
Electric Power Generation Facilities—Fossil Fuel Electric Power Generation
221112
Electric Power Generation Facilities—Nuclear Electric Power Generation
221113
This section is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely 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
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
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:
• “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
Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category—EPA 821-R-13-004 (BCA). EPA requests comment on the reasonableness of these assumptions, additional data that may be available to reduce uncertainties in these estimates, and approaches to characterize the remaining uncertainty.
Table II-1—Total Monetized Annualized Benefits and Costs for the Proposed Rule
[Millions; 2010$]
Preferred regulatory alternatives
Total monetized social benefits
3%
7%
Total social costs
3%
7%
Option 3a for Existing Sources; Option 4 for New Sources
a
139.4
a
104.8
$185.2
$164.5
Option 3b for Existing Sources; Option 4 for New Sources
a
205.5
a
153.0
281.4
257.2
Option 3 for Existing Sources; Option 4 for New Sources
$311.7
$230.4
572.0
545.3
Option 4a for Existing Sources; Option 4 for New Sources
a
482.5
a
424.8
954.1
914.7
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 (BOD
5
), 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
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: BOD
5
, 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
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 (SO
2
) 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.,
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 (NO
X
) and/or ozone-season NO
X
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, NO
X
and ozone-season NO
X
addressed by the CSAPR react in the atmosphere to form PM
2.5
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.
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
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.
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
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
• 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, BOD
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), 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),
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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).
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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
cleaning wastes, and gasification of fuels such as coal and petroleum coke. EPA is also considering establishing best management practices for surface impoundments receiving coal combustion residuals.
EPA is proposing to correct a typographical error in 40 CFR 423.17(d)(1) by adding a footnote that is missing from the table specifying PSNS for cooling tower blowdown. As is clear from the development document for the 1982 rulemaking, the footnote was intended to appear, as it does in the corresponding table for NSPS, and its omission was an inadvertent mistake, which EPA is now correcting. The footnote proposed to be added reads “No detectable amount” and refers to the effluent standard for 124 of the 126 priority pollutants contained in chemicals added for cooling tower maintenance. (See “Development Document for Final Effluent Guidelines, New Source Performance Standards and Pretreatment Standards for the Steam Electric Power Generating Point Source Category,” Document No. EPA 440/1-82/029. November 1982.)
In addition, EPA is proposing three modifications to the applicability provision for the ELGs. These are not substantive modifications and would not alter which generating units are regulated by the ELGs nor impose compliance costs on the industry. Instead, the proposed modifications would remove potential ambiguity present in the current regulatory text by revising the text to more clearly reflect EPA's long-standing interpretation.
First, the applicability provision in the current ELGs states, in part, that the ELGs apply to “an establishment primarily engaged in the generation of electricity for distribution and sale. . . .” 40 CFR 423.10. EPA is proposing to revise that phrase in the applicability provision to read “an establishment whose generation of electricity is the predominant source of revenue or principal reason for operation . . .” This proposed modification would clarify that certain facilities, such as generating units owned and operated by industrial facilities in other sectors (e.g., petroleum refineries, pulp and paper mills) are not included within the scope of the steam electric ELGs. In addition, the proposed modification would clarify that certain municipal-owned facilities, which generate and distribute electricity within a service area (such as distributing electric power to municipal-owned buildings), but which use accounting practices that are not commonly thought of as a “sale” are nevertheless subject to the ELGs. Such facilities have traditionally been regulated by the steam electric ELGs, and EPA believes the proposed modification will improve regulatory clarity.
Second, EPA is proposing a modification to the applicability provision to clarify that fuels derived from fossil fuel are within the scope of the current ELGs. The ELGs currently state, in part, that the ELGs apply to discharges related to the generation of electricity “which results primarily from a process utilizing fossil-type fuels (coal, oil, or gas) or nuclear fuel . . .” 40 CFR 423.10. Because there are a number of fuel types that are derived from fossil fuel, and which thus are fossil fuels themselves, EPA is proposing to revise that phrase in the applicability provision to read “which results primarily from a process utilizing fossil-type fuel (coal, oil, or gas), fuel derived from fossil fuel (e.g., petroleum coke, synthesis gas), or nuclear fuel . . .”
Third, EPA is proposing to amend the applicability provision to clarify that combined cycle systems are subject to the requirements of the ELGs. The ELGs apply to electric generation processes that utilize “a thermal cycle employing the steam water system as the thermodynamic medium.” 40 CFR 423.10. EPA's longstanding interpretation of this provision is that the ELGs apply to all electric generation processes with at least one prime mover that utilizes steam (if they also meet the other factors specified in Section 423.10, including the use of fossil or nuclear fuel). Combined cycle systems, which are generating units composed of one or more combustion turbines operating in conjunction with one or more steam turbines, are subject to the ELGs. The combustion turbines for a combined cycle system operate in tandem with the steam turbines; therefore, the ELGs apply to wastewater discharges associated with both the combustion turbine and steam turbine portions of the combined cycle system.
B. Subcategorization
The CWA requires EPA to consider a number of different factors when developing ELGs for a particular industry category (see BAT factors listed at Section 304(b)(2)(B), 33 U.S.C. § 1314(b)(2)(B)). For BAT, in addition to the technological availability and economic achievability, these factors are the age of equipment and facilities involved, the process employed, the engineering aspects of the application of various types of control techniques, process changes, the cost of achieving such effluent reduction, non-water quality environmental impact (including energy requirements), and such other factors the Administrator deems appropriate. One way EPA may take these factors into account is by dividing a point source category into groupings called “subcategories.” Regulating a category by subcategory, where determined to be warranted, ensures that each subcategory has a uniform set of ELGs that take into account technology availability and economic achievability and other relevant factors unique to that subcategory.
The current steam electric ELGs do not divide plants or process operations into subcategories, although they do include different effluent requirements for cooling water discharges from generating units smaller than 25 MW generating capacity. For this proposed rule, EPA evaluated whether different effluent requirements should be established for certain facilities within the steam electric power generating point source category using information from responses to the industry questionnaires, site visits, sampling, and other data collection activities (see Section IV for more details). EPA performed analyses to assess the influence of age, size, fuel type, and geographic location on the wastewaters generated, discharge flow rates, pollutant concentrations, and treatment technology availability at steam electric power plants to determine whether subcategorization was appropriate, as discussed further below.
1. Age of Plant or Generating Unit
EPA analyzed the age of the power plants and the generating units included in the scope of the rule. It determined that the age of the plant by itself does not in general affect the wastewater characteristics, the processes in place, or the ability to install the treatment technologies evaluated as part of this rulemaking. Therefore, EPA did not establish subcategories based on the age of the plant or generating unit for this proposal.
2. Geographic Location
EPA analyzed the geographic location of power plants included in the scope of the rule. It determined that the geographic location of the plant by itself does not affect the wastewater characteristics, the processes in place, or the ability to install the treatment technologies evaluated as part of this rulemaking. During its evaluation, EPA found that wet FGD systems, both wet and dry fly ash handling systems, and both wet and dry bottom ash handling systems are located throughout the United States, as illustrated in Section
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.
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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.
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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
Primary fuel source
Number of
Generating units
Nameplate
capacity
(MW)
Coal
1,080-1,090
328,000-330,000
Petroleum Coke
12
1,000
Oil
75-100
23,900-25,400
Gas
929
282,000
Nuclear
99
104,000
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 NO
X
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
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
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
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 (CO
2
) from the flue gas. Many steam electric power plants are considering alternatives available for reducing CO
2
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 CO
2
associated with generating electricity: Post-combustion, pre-combustion, and oxyfuel combustion.
• In post-combustion capture, the CO
2
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 H
2
) is processed to create CO
2
and more H
2
, and the resulting CO
2
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 CO
2
and water vapor; the latter condenses through cooling. The result is an almost pure CO
2
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
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.
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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
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.)
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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.
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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.
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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.
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Vibratory Belt System:
Bottom ash deposits on a vibratory conveyor trough, where the plant cools the ash by air and ultimately moves it through the
conveyor deck to an intermediate storage destination.
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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
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