Steam Electric Reconsideration Rule

Federal RegisterOct 13, 2020

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 423

[EPA-HQ-OW-2009-0819; FRL-10014-41-OW]

RIN 2040-AF77

Steam Electric Reconsideration Rule

AGENCY:

Environmental Protection Agency.

ACTION:

Final rule.

SUMMARY:

The Environmental Protection Agency (EPA or the Agency) is finalizing a regulation to revise the technology-based effluent limitations guidelines and standards (ELGs) for the steam electric power generating point source category applicable to flue gas desulfurization (FGD) wastewater and bottom ash (BA) transport water. This final regulation is estimated to save approximately $140 million annually in after tax compliance costs as a result of less costly FGD wastewater technologies that could be used with the modification of the Steam Electric Power Generating Effluent Guidelines 2015 rule (the 2015 rule) limitations; less costly BA transport water technologies made possible by the revision of the 2015 rule's zero discharge limitations; a two-year extension of compliance time frames for meeting FGD wastewater and BA transport water limitations, and additional subcategories for both FGD wastewater and BA transport water. Participation in the voluntary incentive program would contribute to the reduction in pollutant discharges by these steam electric power plants in FGD wastewater by approximately 26.7 million pounds per year.

DATES:

This final rule is effective on December 14, 2020. In accordance with 40 CFR part 23, this regulation shall be considered issued for purposes of judicial review at 1:00 p.m. Eastern time on October 27, 2020. Under section 509(b)(1) of the CWA, judicial review of this regulation can be had only by filing a petition for review in the U.S. Court of Appeals within 120 days after the regulation is considered issued for purposes of judicial review. Under section 509(b)(2), the requirements in this regulation may not be challenged later in civil or criminal proceedings brought by EPA to enforce these requirements.

ADDRESSES:

EPA has established a docket for this action under Docket ID No. EPA-HQ-OW-2009-0819. All documents in the docket are listed on the

http://www.regulations.gov

website. Although listed in the index, some information is not publicly available,

e.g.,

Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the internet and will be publicly available only in hard copy form. Publicly available docket materials are available electronically through

http://www.regulations.gov

FOR FURTHER INFORMATION CONTACT:

For technical information, contact Richard Benware, Engineering and Analysis Division, Telephone: 202-566-1369; Email:

benware.richard@epa.gov

. For economic information, contact James Covington, Engineering and Analysis Division, Telephone: 202-566-1034; Email:

covington.james@epa.gov

SUPPLEMENTARY INFORMATION:

Preamble Acronyms and Abbreviations.

We use multiple acronyms and terms in this preamble. While this list may not be exhaustive, to ease the reading of this preamble and for reference purposes, EPA defines terms and acronyms in Appendix A.

Supporting Documentation.

Today's final rule is supported by numerous documents including:

•

Supplemental Technical Development Document for Revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category

(Supplemental TDD), Document No. EPA-821-R-20-001. The Supplemental TDD summarizes the technical and engineering analyses supporting the final rule. It presents EPA's updated analyses supporting the revisions to FGD wastewater and BA transport water. These updates include additional data collected since the signature of the 2015 rule, updates to the industry (

e.g.,

retirements, updates to FGD treatment and BA handling), cost methodologies, pollutant removal estimates, corresponding non-water quality environmental impacts associated with updated FGD and BA methodologies, and explanations of the calculations of the effluent limitations and standards. Except for the updates described in the Supplemental TDD, the

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

(2015 TDD, Document No. EPA-821-R-15-007) is still applicable and provides a more complete summary of EPA's data collection, description of the industry, and underlying analyses supporting the ELGs established for other wastestreams in the 2015 rule.

•

Supplemental Environmental Assessment for Revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category

(Supplemental EA), Document No. EPA-821-R-20-002. The Supplemental EA summarizes the potential environmental and human health impacts that are estimated to result from implementation of this final rule.

•

Benefit and Cost Analysis for Revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category

(BCA Report), Document No. EPA-821-R-20-003. The BCA Report summarizes estimates of the societal benefits and costs resulting from implementation of this final rule.

•

Regulatory Impact Analysis for Revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category

(RIA), Document No. EPA-821-R-20-004. The RIA presents a profile of the steam electric power generating industry, a summary of estimated costs and impacts associated with this final rule, and an assessment of the potential impacts on employment and small businesses.

•

Response to Public Comments for Revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category.

This document provides EPA's responses to substantive public comments received on the 2019 proposed rule.

•

Docket Index for the Revisions to the Steam Electric ELGs.

This document provides a list of the additional memoranda, references, and other information relied upon by EPA for this final rule.

Organization of this Document.

The information in this preamble is organized as follows:

I. Executive Summary

II. Public Comments and Online Public Hearing

III. General Information

A. Does this action apply to me?

B. What action is EPA taking?

C. What is EPA's authority for taking this action?

D. What are the monetized incremental costs and benefits of this action?

IV. Background

A. Clean Water Act (CWA)

B. Relevant Effluent Guidelines

1. Best Practicable Control Technology Currently Available (BPT)

2. Best Available Technology Economically Achievable (BAT)

3. Pretreatment Standards for Existing Sources (PSES)

C. 2015 Steam Electric Power Generation Point Source Category Rule

D. Legal Challenges, Administrative Petitions, Section 705 Action, Postponement Rule, and Reconsideration of Certain Limitations and Standards

E. Other Ongoing Rules Affecting the Steam Electric Sector

1. Affordable Clean Energy (ACE) Rule

2. Coal Combustion Residuals (CCR)

F. Scope of the Final Rule

V. Steam Electric Power Generating Industry Description

A. General Description of Industry

B. Current Market Conditions in the Electricity Generation Sector

C. Control and Treatment Technologies

1. FGD Wastewater

2. BA Transport Water

VI. Data Collection Since the 2015 Rule

A. Information From the Electric Utility Industry

1. Engineering Site Visits

2. Data Requests, Responses, and Meetings

3. Voluntary BA Transport Water Sampling

4. Electric Power Research Institute (EPRI) Voluntary Submission

5. Meetings With Trade Associations

B. Information From the Drinking Water Utility Industry and States

C. Information From Technology Vendors and Engineering, Procurement, and Construction (EPC) Firms

D. Other Data Sources

VII. Final Regulation

A. Description of the Main BAT/PSES Options

1. FGD Wastewater

2. BA Transport Water

B. Rationale for the Final BAT

1. FGD Wastewater

2. BA Transport Water

3. Voluntary Incentives Program (VIP)

C. Additional Subcategories

1. Plants With High FGD Flows

2. Low Utilization EGUs

3. EGUs Permanently Ceasing Coal Combustion by 2028

D. Availability Timing of New Requirements

E. Additional Rationale for the Final PSES

F. Economic Achievability

G. Non-Water Quality Environmental Impacts

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

VIII. Costs, Economic Achievability, and Other Economic Impacts

A. Plant-Specific and Industry Total Costs

B. Social Costs

C. Economic Impacts

1. Screening-Level Assessment

a. Plant-Level Cost-to-Revenue Analysis

b. Parent Entity-Level Cost-to-Revenue Analysis

2. Electricity Market Impacts

a. Impacts on Existing Steam Electric Power Plants

b. Impacts on Individual Plants Incurring Costs

IX. Pollutant Loadings

A. FGD Wastewater

B. BA Transport Water

C. Summary of Incremental Changes of Pollutant Loadings From Final Rule

X. Non-Water Quality Environmental Impacts

A. Energy Requirements

B. Air Pollution

C. Solid Waste Generation and Beneficial Use

D. Changes in Water Use

A. Introduction

B. Updates to the Environmental Assessment Methodology

C. Outputs From the Environmental Assessment

XII. Benefits Analysis

A. Categories of Benefits Analyzed

B. Quantification and Monetization of Benefits

1. Changes in Human Health Effects From Surface Water Quality Changes

2. Ecological Condition and Recreational Use Effects From Changes in Surface Water Quality

3. Effects on Threatened and Endangered Species

4. Changes in Ability To Market Coal Combustion Byproducts

5. Changes in Dredging Costs

6. Changes in Air Quality-Related Effects

7. Changes in Water Withdrawals

C. Total Monetized Benefits

D. Unmonetized Benefits

XIII. Development of Effluent Limitations and Standards

A. FGD Wastewater

1. Overview of the Limitations and Standards

2. Criteria Used to Select Data

3. Data Used to Calculate Limitations and Standards

4. Long-Term Averages and Effluent Limitations and Standards for FGD Wastewater

B. BA Transport Water Limitations

1. Maximum 10 Percent 30-Day Rolling Average Purge Rate

2. Best Management Practices Plan

XIV. Regulatory Implementation

A. Implementation of the Limitations and Standards

1. Timing

3. Implementation for the Low Utilization Subcategory

4. Transitioning Between Limitations

5. Addressing Unexpected Changes in Generation

a. Involuntary Retirement Delays

b. Emergencies and Major Disasters Under the Stafford Act

c. Voluntary Retirement Withdrawals and Delays

B. Reporting and Recordkeeping Requirements

C. Site-Specific Water Quality-Based Effluent Limitations

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

A. Executive Orders 12866 (Regulatory Planning and Review) and 13563 (Improving Regulation and Regulatory Review)

B. Executive Order 13771 (Reducing Regulation and Controlling Regulatory Costs)

C. Paperwork Reduction Act

D. Regulatory Flexibility Act

E. Unfunded Mandates Reform Act

F. Executive Order 13132: Federalism

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

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

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

J. National Technology Transfer and Advancement Act

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

L. Congressional Review Act (CRA)

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

I. Executive Summary

A. Purpose of Rule

Coal-fired plants are affected by several environmental regulations. One of these regulations, the Steam Electric Power Generating ELGs, was promulgated in 2015 (80 FR 67838; November 3, 2015) and applies to the subset of the electric power industry in which “generation of electricity is the predominant source of revenue or principal reason for operation, and whose generation of electricity results primarily from a process utilizing fossil-type fuel (coal, oil, gas), fuel derived from fossil fuel (

e.g.,

petroleum coke, synthesis gas), or nuclear fuel in conjunction with a thermal cycle employing the steam-water system as the thermodynamic medium” (40 CFR 423.10). The 2015 rule addressed discharges from FGD wastewater, fly ash (FA) transport water, BA transport water, flue gas mercury control wastewater, gasification wastewater, combustion residual leachate, and non-chemical metal cleaning wastes.

Since the Steam Electric Power Generating ELGs were revised in 2015, steam electric power plants have installed more affordable technologies that can remove similar amounts of pollution as those operating in 2015. This final rule revises limitations and standards for two of the wastestreams addressed in the 2015 rule: BA transport water and FGD wastewater. Today's rule does not revise the other wastestreams covered by the 2015 rule.

B. Summary of Final Rule

For existing sources that discharge directly to surface water, with the subcategories discussed below excepted, the final rule establishes the following effluent limitations based on Best Available Technology Economically Achievable (BAT):

• For FGD wastewater, the final rule establishes numeric BAT effluent limitations on mercury, arsenic,

selenium, and nitrate/nitrite as nitrogen.

While the proposed rule described “two sets” of BAT limitations for both FGD wastewater and BA transport water, this rulemaking has been focused on revisions to the 2015 rule limitations and standards that were new and more stringent than previously established BPT limitations and standards (the “second set” of limitations). It was not intended to address the TSS BAT limitations for these wastestreams promulgated in the 2015 rule (the “first set” of limitations), which have since been vacated by the U.S. Court of Appeals for the Fifth Circuit, see Section IV.D, below.

• For BA transport water, the final rules establishes as BAT a high recycle rate system with a site-specific volumetric purge (defined in the final rule as BA purge water) which cannot exceed 10 percent of the BA transport water system's volume where the purge volume and associated effluent limitations are established by the permitting authority.

The final rule includes separate requirements for the following subcategories: High FGD flow plants, electric generating units (EGUs) that will permanently cease the combustion of coal by 2028, and low utilization EGUs (LUEGUs). The 2015 rule's subcategories for oil-fired EGUs and small generating units (50 MW or less) were not reopened in this rulemaking and remain in effect. For high FGD flow plants (FGD wastewater flows over four million gallons per day, after accounting for the plant's ability to recycle the wastewater to the maximum limits of the FGD system's materials of construction) and LUEGUs (those with a capacity utilization rating (CUR) of less than 10 percent), the final rule establishes BAT limitations in the discharged FGD wastewater as numeric effluent limitations on mercury and arsenic. For LUEGUs, the final rule establishes BAT limitations for BA transport water for total suspended solids (TSS) and also includes standards for implementing a best management practices (BMP) plan. For EGUs permanently ceasing the combustion of coal by 2028, the final rule establishes BAT limitations for total suspended solids (TSS) in FGD wastewater and bottom ash transport water.

The final rule establishes a voluntary incentives program that provides the certainty of more time (until December 31, 2028) for plants to meet new standards and limitations, if they adopt additional process changes and controls that achieve more stringent limitations on mercury, arsenic, selenium, nitrate/nitrite, bromide, and TSS in FGD wastewater. The optional program offers environmental protections beyond those achieved by the final BAT limitations, while providing plants that opt into the program more flexibility when permeate or distillate is used as boiler makeup water, and additional time to meet the limitations established for BAT in this final rule.

For indirect discharges (

i.e.,

discharges to publicly owned treatment works (POTWs)), the final rule establishes pretreatment standards for existing sources that are the same as the BAT limitations, except for TSS, there is no pass through of pollutants at POTWs.

Where BAT limitations in this rule are more stringent than previously established BPT limitations applicable to the relevant wastestreams, those limitations do not apply until the permitting authority determines a date that is as soon as possible on or after October 13, 2021, but no later than December 31, 2025.

C. Summary of Costs and Benefits

EPA estimates that the final rule will save $127 million per year in social costs and result in between $−1.7 million and $43 million in benefits, using a three percent discount rate, and will save $153 million per year in social costs and between $6.5 million and $46 million in benefits, using a seven percent discount. Table XV-1 summarizes the benefits and social costs for the four regulatory options that EPA analyzed at a three percent discount rate. EPA's analysis reflects the Agency's understanding of the actions steam electric power plants are expected to take to meet the limitations and standards in the final rule. EPA based its analysis on a modeled baseline that reflects the expected effects of announced retirements and fuel conversions, impacts of relevant final rules such as the Coal Combustion Residuals (CCR) Part A final rule that the Agency promulgated in August 2020 and the Affordable Clean Energy (ACE) rule that the Agency promulgated in 2019, and full implementation of the 2015 rule. EPA has also provided an assessment of the economic impacts of the final revised Steam Electric ELGs relative to an alternative baseline including the CCR Part B Rule, which EPA is working on but which has not been issued at this time (see DCN SE09360). EPA understands that these modeled results have uncertainty and that the actual costs for individual plants could be higher or lower than estimated. The current estimate reflects the best data and analysis available at this time. For additional information, see Sections V and VIII.

II. Public Comments and Online Public Hearing

During the 60-day public comment period for the 2019 proposed rule (November 22, 2019 to January 21, 2020), EPA received more than 7,400 public comment submissions from private citizens, industry members, technology vendors, government entities, environmental groups, and trade associations. EPA also hosted an online public hearing on December 19, 2019 (during the public comment period). The hearing had 110 attendees, 32 of whom spoke about the proposed rule. Available documents from the public hearing include the presentation given by EPA and a transcript (DCN SE08497 and DCN SE08498).

III. General Information

A. Does this action apply to me?

Entities potentially regulated by the final rule include:

see also Clean Water Action.

EPA,

No. 18-60079 (5th Cir.). On October 29, 2018, the District of Arizona case was dismissed upon EPA's motion to dismiss for lack of jurisdiction, and on August 28, 2019, the Fifth Circuit denied the petition for review of the postponement rule.

E. Other Ongoing Rules Affecting the Steam Electric Sector

1. Affordable Clean Energy (ACE) Rule

On June 19, 2019, EPA issued the ACE rule pursuant to Clean Air Act (CAA) sections 111(a)(1) and 111(d), providing states with guidelines for establishing standards of performance regulating CO

emissions at existing coal-fired electric utility generating units (EGUs).

This action was finalized in conjunction with two related, but separate and distinct rulemakings: (1) The repeal of the Clean Power Plan (CPP), and (2) revised implementing regulations for ACE, ongoing emission guidelines, and all future emission guidelines for existing sources issued under the authority of CAA section 111(d).

84 FR 32520.

Under CAA section 111(a)(1) and 111(d), respectively, EPA determines the best system of emission reduction (BSER) and states submit plans establishing standards of performance based on the BSER. The BSER must be applicable to, at, and on the premises of a source that is subject to CAA section 111(d). EPA repealed the CPP on the basis that it in part improperly premised its BSER on power generation that was shifting between EGUs and other, lower-emitting sources. In ACE, EPA determined the BSER for coal-fired EGUs as six heat rate improvements (HRI) “candidate technologies,” as well as additional operations and maintenance (O&M) practices, all of which are applicable to and at the source.

For each candidate technology, EPA has provided the extent of achievable emissions limitations through application of the BSER as ranges of expected improvements and costs. States are required to submit plans by July 8, 2022 that establish standards of performance for their EGUs that are subject to the ACE rule. The standards of performance must reflect the degree of emissions limitation through application of the BSER, and states may take into account remaining useful life and other factors in applying a standard to a particular EGU. Multiple legal challenges to this rule were consolidated in

American Lung Association

EPA,

No. 19-1140, and are currently pending in the D.C. Circuit Court of Appeals.

These six technologies are: (1) Neural network/intelligent soot blowers, (2) EGU feed pumps, (3) air heater and duct leakage control, (4) variable frequency drives, (5) blade path upgrade (steam turbine), and (6) redesign/replace economizer.

2. Coal Combustion Residuals (CCR)

On April 17, 2015, the Agency published the Disposal of Coal Combustion Residuals from Electric Utilities final rule (2015 CCR rule). This rule finalized national regulations to provide a comprehensive set of requirements for the safe disposal of CCR, commonly known as coal ash, from steam electric power plants. The final 2015 CCR rule was the culmination of extensive study on the effects of coal ash on the environment and public health. The rule established technical requirements for CCR landfills and surface impoundments under subtitle D of the Resource Conservation and Recovery Act (RCRA), the nation's primary law for regulating solid waste.

These regulations addressed coal ash disposal, including regulations designed to prevent leaking of contaminants into groundwater, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments. Additionally, the 2015 CCR rule set recordkeeping and reporting requirements as well as the requirement for each plant to establish and post specific information to a publicly accessible website. This final 2015 CCR rule also supported the responsible recycling of CCR by distinguishing beneficial use from disposal.

As a result of the D.C. Circuit Court rulings in

USWAG

EPA,

No. 15-1219 (D.C. Cir. 2018) and

Waterkeeper Alliance Inc. et al.

EPA,

No. 18-1289 (D.C. Cir. 2019), the Administrator signed

A Holistic Approach to Closure Part A: Deadline to Initiate Closure and Enhancing Public Access to Information

on July 29 (CCR Part A). In particular, four amendments to the CCR rule were finalized which could impact plants' decisions under this final ELG rule. First, the CCR Part A rule establishes a new deadline of April 11, 2021, for all unlined surface impoundments, as well as those surface impoundments that failed the location restriction for placement above the uppermost aquifer, to stop receiving waste and begin closure or retrofit. EPA determined this date after evaluating the steps that owners and operators need to take for surface impoundments to stop receiving waste and begin closure, and the time frames needed for implementation. Second, the rule establishes procedures for plants to obtain additional time to develop alternate capacity to manage their wastestreams (both coal ash and non-coal ash) before they have to stop receiving waste and begin closing their coal ash surface impoundments. Third, the rule changes the classification of compacted-soil-lined and clay-lined surface impoundments from lined to unlined. Finally, the rule revises the coal ash regulations to specify that all unlined surface impoundments are required to retrofit or close. This would not affect the ability of plants to install new, composite-lined surface impoundments.

As explained in the 2015 ELG rule and 2019 ELG proposal, the ELGs and 2015 CCR rule may affect the same EGU or activity at a plant. Therefore, when EPA finalized the ELG and CCR rule in 2015 and proposed revisions to both rules in 2019, the Agency coordinated the ELG and CCR rules to facilitate and minimize the complexity of implementing engineering, financial, and permitting activities. EPA continued to coordinate these two rules during the development of the final rule for ELG and CCR Part A. EPA's analysis now estimates how the CCR Part A rule may affect surface impoundments and the ash handling systems and FGD treatment systems that send wastes to those impoundments. This is further described in Supplemental TDD, Section 3. For more information on the CCR Part A rule and accompanying background documents, visit

www.regulations.gov

Docket EPA-HQ-OLEM-2019-0172 and

www.epa.gov/coalash/coal-ash-rule

In addition to the final CCR Part A rule, EPA has proposed further revisions to the CCR regulations (CCR Part B). Specifically, EPA proposed four changes in the CCR Part B rule. First, EPA proposed procedures to allow plants to request approval to continue operating CCR surface impoundments equipped

with an alternate liner. Second, EPA proposed two options to allow the continued placement of CCR in surface impoundments undergoing forced closure. Third, EPA proposed an additional closure option for CCR units being closed by removal of CCR. Finally, EPA proposed requirements for annual closure progress reports. While the Part B proposal was issued after the comment period for the ELG rule had closed and EPA had already taken significant steps to respond to public comments on the ELG rule and develop the final ELG rule, EPA recognizes that, just as with the Part A rule, the first provision of the Part B rule may affect the same EGU or activity at a plant that these final ELGs affect. EPA is continuing to work on the Part B rule and may finalize this provision in the future. Thus, to provide the public with meaningful analysis of the potential overlap and impacts of this final rule with the CCR Part B rule, EPA has conducted a sensitivity analysis that is described further in a memo titled “Assessment of the economic impacts of the final revised Steam Electric ELGs relative to an alternative baseline including the CCR Part B Rule”, (DCN SE09360). For more information on the CCR Part B rule and accompanying background documents, visit

www.regulations.gov

Docket EPA-HQ-OLEM-2019-0173.

F. Scope of the Final Rule

The final rule revises the new, more stringent BAT ELGs and pretreatment standards for existing sources in the 2015 rule that apply to FGD wastewater and BA transport water.

V. Steam Electric Power Generating Industry Description

A. General Description of Industry

EPA provided a general description of the steam electric power generating industry in the 2013 proposed rule, the 2015 rule, the 2019 proposed rule, and has continued to collect information and update that industry profile. The previous descriptions reflected the known information about the universe of steam electric power plants and incorporated final environmental regulations applicable at that time. For the final rule, as described in the Supplemental TDD, Section 3, EPA has revised its description of the steam electric power generating industry (and its supporting analyses) to incorporate major changes such as additional retirements, fuel conversions, ash handling conversions, wastewater treatment updates, and updated information on capacity utilization.

The analyses supporting the final rule use an updated baseline that incorporates these changes in the industry. The analyses then compare the effect of the final rule's requirements for FGD wastewater and BA transport water to the effect on the industry (as it exists today) of the 2015 rule's limitations for FGD wastewater and BA transport water.

The data presented in the general description continue to reflect some conditions existing in 2009, as the industry survey remains EPA's best available source of information for characterizing operations across the industry.

As described in the Regulatory Impact Analysis, of the 914 steam electric power plants in the country identified by EPA, only those coal-fired power plants that discharge bottom ash transport water or FGD wastewater may incur compliance costs under this final rule. EPA estimates that 108 such plants could have incurred non-zero compliance costs under the 2015 rule but that only 75 plants may incur non-zero compliance costs under this final rule. As described above, this difference is due to plant retirements, fuel conversions, ash handling conversions, wastewater treatment updates, and updated information on capacity utilization discussed in

Changes to Industry Profile for Coal-Fired Generating Units for the Steam Electric Effluent Guidelines Final Rule

(DCN SE08688), but does not include additional changes since this document was developed.

B. Current Market Conditions in the Electricity Generation Sector

Market conditions in the electricity generation sector have changed significantly and rapidly in the past decade. These changes include availability of abundant and relatively inexpensive natural gas, emergence of alternative fuel technologies, and continued aging of coal-fired steam electric power plants. These changes have resulted in coal-fired unit and plant retirements and switching of fuels. The lower cost of natural gas and technological advances in solar and wind power have had a depressive effect on both coal-fired and nuclear-powered generation. (This rule will have no direct effect on the nuclear-powered sector, except as it might affect relative prices through its effects on coal-fired generation.) In the coal-fired sector, the market forces manifest as scaling back coal-fired power generation (including unit and plant closures) at an accelerated rate. The rate of coal capacity retirement is affected by regulations adopted in the last decade (

e.g.,

CCR, CPP, and the 2015 Steam Electric ELG), that are cited by some power companies when they announce unit or plant closures, fuel switching, or other operational changes. Some utilities are also trending toward supplementing or replacing traditional generation with alternative sources. The electric power infrastructure adjusts to these changes and generally trends toward optimal infrastructure and operations to deliver the country's power demand. Some communities experience negative effects, while for others the effects are positive. The negative distributional effects can be particularly difficult for communities affected by company decisions to scale back or retire a plant. Also see Section 2.3 of the RIA.

C. Control and Treatment Technologies

In general, control and treatment technologies for some wastestreams have continued to advance since the 2015 rule. Often, these advancements provide plants with additional ways of meeting effluent limitations, sometimes at a lower cost. For this final rule, EPA incorporated updated information and evaluated several technologies available to control and treat FGD wastewater and BA transport water. See Section VIII of this preamble for details on updated cost information.

1. FGD Wastewater

FGD scrubber systems, either dry or wet, remove sulfur dioxide from flue gas, preventing sulfur dioxide emissions into the air. Dry FGD systems generally do not discharge wastewater, as the water they use evaporates during operation; wet FGD systems do produce a wastewater stream.

Steam electric power plants discharging FGD wastewater currently employ a variety of wastewater treatment technologies and operating/management practices to reduce the pollutants associated with discharged FGD wastewater. As part of the 2015 rule, EPA identified the following types of treatment and handling practices for FGD wastewater:

• Chemical precipitation systems that use tanks to treat FGD wastewater. Chemicals are added to help remove suspended solids and dissolved solids, particularly metals. The precipitated solids are then removed from solution by coagulation/flocculation, followed by clarification and/or filtration. The 2015 rule focused on a specific design that employs hydroxide precipitation, sulfide precipitation (organosulfide), and iron coprecipitation to remove suspended solids and to convert soluble metal ions to insoluble metal hydroxides or sulfides.

• Biological treatment systems that use microorganisms to treat FGD wastewater.

EPA identified three types of biological treatment systems used to treat FGD wastewater: (1) Anoxic/anaerobic fixed-film bioreactors, which remove nitrogen compounds and selenium, as well as other metals; (2) anoxic/anaerobic suspended growth systems, which remove selenium and other metals; and (3) aerobic/anaerobic sequencing batch reactors, which remove organics and nutrients. The 2015 rule focused on a specific design of anoxic/anaerobic fixed-film bioreactors that employs a relatively long residence time for the microbial processes. The bioreactor design used as the basis for the 2015 rule, with a typical hydraulic residence time of approximately 10 to 16 hours, is referred to in this rulemaking as high residence time reduction (HRTR). The BAT technology basis for the 2015 rule also included chemical precipitation as a pretreatment stage prior to the bioreactor and a sand filter as a polishing step following the bioreactor (

i.e.,

CP + HRTR).

• Thermal evaporation systems that use a falling-film evaporator (or brine concentrator). Following a softening pretreatment step, thermal evaporation systems produce a concentrated wastewater stream and a distillate stream to reduce the volume of wastewater by 80 to 90 percent and also reduce the discharge of pollutants. The concentrated wastewater is usually further processed in a crystallizer, which produces a solid residue for landfill disposal and additional distillate that can be reused within the plant or discharged. These systems are designed to remove the broad spectrum of pollutants present in FGD wastewater to very low effluent concentrations.

• Constructed wetland systems using natural biological processes. These systems involve 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 the wastewater can adversely affect constructed wetlands' performance. To avoid this, plants typically find it necessary to dilute the FGD wastewater with service water before it enters the wetland.

• Eliminating discharged FGD wastewater. Some plants operate their wet FGD systems using approaches that eliminate the discharge of FGD wastewater. These plants use a variety of operating and management practices to achieve this.

—Complete recycle. Plants that operate in this manner do not produce a saleable solid product from the FGD system (

e.g.,

wallboard-grade gypsum). Because the plants are not selling the FGD gypsum, they are able to allow the landfilled material to contain elevated levels of chlorides, and as a result do not need a separate wastewater purge stream.

—Evaporation impoundments. Some plants in warm, dry climates have been able to use surface impoundments as holding basins from which the FGD wastewater evaporates. The evaporation rate from the impoundments at these plants is greater than or equal to the flow rate of the FGD wastewater plus the rate at which precipitation enters the impoundments; therefore, there is no discharge to surface water.

—FA conditioning. Many plants that operate dry FA handling systems will add water to the FA to suppress dust or improve handling and/or compaction characteristics in an on-site landfill. EPA is not aware of any plants using FGD wastewater to condition ash that will be marketed.

—Combination of wet and dry FGD systems. The dry FGD process involves atomizing and injecting wet lime slurry, which ranges from approximately 18 to 25 percent solids, into a spray dryer. The water in the slurry evaporates from the heat of the flue gas within the system, leaving a dry residue that is removed from the flue gas by a fabric filter (

i.e.,

a baghouse) or electrostatic precipitator (ESP).

—Underground injection. These systems dispose of wastes by injecting them into an underground well as an alternative to discharging wastewater to surface waters.

As part of the proposed rule, EPA added two additional FGD wastewater treatment technologies to the suite of regulatory options that were evaluated in the 2015 rule: Low hydraulic residence time biological reduction (LRTR) and membrane filtration, which are further described below.

• LRTR system. A biological treatment system that targets removal of selenium and nitrate/nitrite using fixed-film bioreactors in smaller, more compact reaction vessels than those used in the biological treatment system evaluated in the 2015 rule (referred to in this rule as HRTR—high residence time biological reduction). The LRTR system is designed to operate with a shorter residence time (approximately 1 to 4 hours, as compared to a residence time of 10 to 16 hours for HRTR), while still removing significant volumes of selenium and nitrate/nitrite. The LRTR technology option selected for this final rule includes chemical precipitation as a pretreatment stage, followed by the bioreactor, then ultrafiltration as a polishing step.

• Membrane filtration. A membrane filtration system typically combines pretreatment for potential scaling agents such as calcium, magnesium, and sulfates, and one or more types of membrane technology (

e.g.,

nanofiltration or reverse osmosis) to remove a broad range of particulate and dissolved pollutants from FGD wastewater. The membrane filtration units may also employ advanced techniques, such as vibration or creation of vortexes, to mitigate fouling or scaling of the membrane surfaces. The membrane filtration technology option considered for this final rule includes a pretreatment stage.

EPA also collected new information on other FGD wastewater treatment technologies, including spray dryer evaporators, direct contact thermal evaporators, zero valent iron treatment, forward osmosis, absorption or adsorption media, ion exchange, electrocoagulation, and electrodialysis reversal. These treatment technologies have been evaluated at full scale or pilot scale, or are being developed to treat FGD wastewater. See Section 4.1 of the Supplemental TDD for more information on these technologies.

2. BA Transport Water

BA consists of heavier ash particles that are not entrained in the flue gas and fall to the bottom of the furnace. In most furnaces, the hot BA is quenched in a water-filled hopper.

Many plants use water to transport (sluice) the BA from the hopper to an impoundment system or a dewatering bin system. In both the impoundment and dewatering bin systems, the BA transport water is usually discharged to surface water as overflow from the system, after the BA has settled to the bottom. In both the impoundment and dewatering bin systems, the BA transport water is usually discharged to surface water as overflow from the system, after the BA has settled to the bottom. In addition to wet sluicing to an impoundment or dewatering bin system, the industry also uses the following BA handling systems that generate BA transport water:

Consistent with the 2015 rule, boiler slag is considered BA.

• Remote mechanical drag system (remote MDS). These systems use the same processes as wet sluicing to an impoundment or a dewatering bin system to transport bottom ash to a remote MDS. A drag chain conveyor dewaters the bottom ash by pulling it out of the water bath on an incline. The system can either be operated as a closed loop (evaluated during the 2015 rule)

or a high recycle rate system. For the high recycle rate system that serves as the basis for BAT in the final rule, plants would be permitted to purge a portion of the wastewater from the system to maintain a high recycle rate, as described in Section VII of this preamble.

Additional treatment may be necessary to maintain a true closed loop system. This additional treatment could include adding a polymer to enhance removal of suspended solids, or membrane filtration of a slip stream to remove dissolved solids.

• Dense slurry system. These systems use a dry vacuum or pressure system to convey the bottom ash to a silo (as described below for the dry vacuum or pressure system), but instead of using trucks to transport the bottom ash to a landfill, the plant mixes the bottom ash with water (a lower percentage of water compared to a wet sluicing system) and pumps the mixture to the landfill.

As part of the 2015 rule and the final rule, EPA identified the following BA handling systems that do not generate bottom ash transport water.

• Mechanical drag system. These systems operate directly underneath the EGU. The bottom ash is collected in a water quench bath. A drag chain conveyor dewaters the

bottom ash by pulling it out of the water bath on an incline.

• Dry mechanical conveyor. These systems operate directly underneath the EGU. The system uses ambient air to cool the bottom ash in the EGU and then transports the ash out of the EGU on a conveyor. No water is used in this process.

• Dry vacuum or pressure system. These systems transport bottom ash from the EGU to a dry hopper without using any water. Air is percolated 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.

• Vibratory belt system. These systems deposit bottom ash into a vibratory conveyor trough, where the ash is air-cooled and ultimately moved through the conveyor deck to an intermediate storage destination without using any water.

• Compact submerged conveyor.

These systems are located directly underneath the EGU and are designed to reuse slag tanks, ash gates, clinker grinders, and transfer enclosures from the existing wet sluicing systems. The system collects bottom ash from the discharge of each clinker grinder. A series of submerged drag chain conveyors transports and dewaters the bottom ash.

At proposal, EPA referred exclusively to one specific vendor's compact submerged conveyor technology (submerged grinder conveyors), but is using the more generic term for the technology (compact submerged conveyors) for this final rule because the Agency did not intend to limit its consideration to only one vendor's technology.

See Section 4.2 of the Supplemental TDD for more information on these technologies.

VI. Data Collection Since the 2015 Rule

A. Information From the Electric Utility Industry

1. Engineering Site Visits

During October and November 2017, EPA conducted seven site visits to plants in five states. EPA selected plants to visit using information gathered in support of the 2015 rule, information from industry outreach, and publicly available plant-specific information. EPA re-visited four plants that were previously visited in support of the 2015 rule because they had recently conducted, or were currently conducting, FGD wastewater treatment pilot studies. EPA also revisited plants that had implemented new FGD wastewater treatment technologies or BA handling systems (after the 2015 rule) to learn more about implementation timing, start-up and operation, and implementation costs. Following the proposal, EPA also conducted five teleconference calls in the spring of 2020. One of these plants was selected for a conference call because it had installed a compact submerged conveyor for management of BA. Two additional plants were selected for a conference call due to installed FGD wastewater technologies that EPA understood could potentially achieve the limitations in the VIP. The final two conference calls were with companies whose plants EPA believed were planning or constructing FGD wastewater technologies that could potentially achieve the limitations in the VIP, based on preliminary information provided by third parties.

In one case this preliminary information was provided by a membrane vendor and in the other the information was provided by a state permitting authority.

The specific objectives of these visits and calls were to gather general information about each plant's operations, pollution prevention and wastewater treatment system operations, ongoing pilot or laboratory scale studies of FGD wastewater treatment, and BA handling system conversions.

2. Data Requests, Responses, and Meetings

Under the authority of Section 308 of the Clean Water Act (CWA) (33 U.S.C. 1318), in January 2018, EPA requested supplemental information from nine steam electric power companies that own coal-fired facilities generating FGD wastewater:

• FGD wastewater characterization data associated with testing and implementation of treatment technologies, in 2013 or later.

• Information on halogen usage to reduce flue gas emissions, as well as data on halogen concentrations in FGD wastewater.

• Projected installations of FGD wastewater treatment technologies.

• Cost information for projected or installed FGD wastewater treatment systems, from bids received in 2013 or later.

EPA selected these nine companies to provide supplemental information because EPA became aware that these companies may be testing, piloting or otherwise investigating new wastewater treatment technologies and EPA was unable to obtain information about these studies on a voluntary basis. After receiving each company's response, EPA met with these companies to discuss the FGD-related data they submitted, other FGD and BA data outside the scope of the request that the company believed to be relevant, and suggestions each company had for potential changes to the 2015 rule with respect to FGD wastewater and BA transport water. EPA used this information to learn more about the performance of new treatment systems, inform the development of FGD wastewater limitations, learn more about plant-specific halogen usage (such as bromide), and obtain information useful for updating cost estimates for installing candidate treatment technologies. As needed, EPA conducted follow-up meetings and conference calls with industry representatives to discuss and clarify these data.

3. Voluntary BA Transport Water Sampling

In December 2017, EPA invited seven steam electric power plants to participate in a voluntary BA transport water sampling program designed to obtain data to supplement the wastewater characterization data set for BA transport water included in the record for the 2015 rule. EPA asked plants to provide analytical data for ash impoundment effluent and untreated BA transport water (

i.e.,

ash impoundment influent). EPA selected the plants based on their responses to its 2010 Questionnaire for the Steam Electric Power Generating Effluent Guidelines (see Section 3.2 of the 2015 TDD). Two plants chose to participate in the voluntary BA sampling program. These data were incorporated into the analytical data set used to estimate pollutant removals for BA transport water.

4. Electric Power Research Institute (EPRI) Voluntary Submission

EPRI conducts studies—funded by the steam electric power generating industry—to evaluate and demonstrate technologies that can potentially eliminate wastestreams or remove pollutants from them. Following the 2015 rule, and prior to the final rule, EPA reviewed 46 reports published between 2011 and 2020 that EPRI voluntarily provided regarding characteristics of FGD wastewater and BA transport water, FGD wastewater treatment pilot studies, BA handling practices, halogen addition rates, and the effect of halogen additives on FGD wastewater. These EPRI reports include those cited by EPRI in their comments on the proposed rule. EPA used information presented in these reports to inform the development of numeric effluent limitations for FGD wastewater and to update methods for estimating the costs and pollutant removals associated with candidate treatment technologies.

5. Meetings With Trade Associations

In May and June of 2018, EPA met with the Edison Electric Institute (EEI), the National Rural Electric Cooperatives Association (NRECA), and the American Public Power Association (APPA). These trade associations represent investor-owned utilities, electric

cooperatives, and community-owned utilities, respectively. EPA also met with the Utility Water Act Group (UWAG), an association comprising the trade associations above as well as individual electric utilities. EPA met with each of these trade associations separately and together to discuss the technologies and the analyses presented in the 2015 rule and receive information related to reconsidering the 2015 rule. EPA used information from these meetings to update industry profile data (

i.e.,

accounting for retirements, fuel conversions, and updated treatment technology installations). EPA also met with UWAG and EEI to discuss their comments with them after the close of the 2019 proposed rule comment period.

B. Information From the Drinking Water Utility Industry and States

EPA received additional information from the drinking water utility sector and states on the effects of bromide discharges from steam electric power plants on drinking water treatment processes. First, EPA received letters from, and met with, the American Water Works Association (AWWA), the Association of Metropolitan Water Agencies (AMWA), the National Association of Water Companies (NAWC), the Association of Clean Water Administrators (ACWA), and the Association of State Drinking Water Administrators (ASDWA). Second, EPA visited two drinking water treatment plants in North Carolina that have modified their treatment processes to address an increase in disinfection byproduct levels due to bromide discharges from an upstream steam electric power plant. Finally, EPA obtained data on surface water bromide concentrations and data from drinking water monitoring from the two drinking water treatment plants. EPA also obtained existing state data from other drinking water treatment plants from the states of North Carolina and Virginia.

C. Information From Technology Vendors and Engineering, Procurement, and Construction (EPC) Firms

EPA gathered data on availability and effectiveness from technology vendors and EPC firms through presentations, conferences, meetings, and email and phone contacts regarding FGD wastewater and BA handling technologies used in the industry. The data collected informed the development of the technology costs and pollutant removal estimates for FGD wastewater and BA transport water. The EPC firms also suggested potential changes to the 2015 rule.

D. Other Data Sources

EPA gathered information on steam electric power plants from the Department of Energy's (DOE's) Energy Information Administration (EIA), forms EIA-860 (Annual Electric Generator Report) and EIA-923 (Power Plant Operations Report). EPA used the 2017 and 2018 data to update the industry profile, including commissioning dates, energy sources, capacity, net generation, operating statuses, planned retirement dates, ownership, and pollution controls at the EGUs.

EPA conducted literature and internet searches to gather information on FGD wastewater treatment technologies, including information on pilot studies, applications in the steam electric power generating industry, and implementation costs and timelines. EPA also used the internet searches to identify or confirm reports of planned plant and EGU retirements, and reports of planned unit conversions to dry or closed-loop recycle ash handling systems. EPA used this information to inform the industry profile and identify process modifications occurring in the industry.

EPA received information from several environmental groups and other stakeholders following the 2015 rule. These groups provided examples of when, they believed, state permitting authorities had not properly implemented the “as soon as possible date” for the new, more stringent BAT requirements in the 2015 rule when issuing permits. EPA also met with these groups after the close of the comment period of the 2019 proposed rule to discuss those organizations' comments.

VII. Final Regulation

A. Description of the Main BAT/PSES Options

EPA analyzed four regulatory options at proposal, the details of which were discussed in the proposed rule (84 FR 64620). For the final rule, EPA evaluated four regulatory options, as shown in Table VII-1. Proposed regulatory options 1, 2, 3, and 4 correspond generally to regulatory options D, A, B, and C in this final rule, respectively, but contain certain differences, as detailed below. Public commenters generally supported three of the regulatory options that EPA proposed, or variants thereof.

The availability and achievability of technologies with better pollutant removals, as well as the general lack of public comments supporting proposed regulatory option 1, led EPA to focus updates to the Agency's analysis on the remaining three regulatory options. EPA did not update the analyses for regulatory option D, but rather retained the results of the proposed rule analysis for this option.

Some commenters also supported retaining the 2015 rule.

EPA is finalizing Option A in the final rule. All four options include the same technology bases for BA transport water, except Option A, which includes a different technology basis for the subcategorized low utilization EGUs and surface impoundments for EGUs permanently ceasing combustion of coal by 2028. In regards to FGD wastewater, Option D is based on chemical precipitation, Options A and B are based on a combination of chemical precipitation and low hydraulic residence time biological treatment, while Option C is based on membrane filtration; the difference between Options A and B is that the former includes three subcategories while the latter does not. Table VII-1 below summarizes the regulatory options considered in this rulemaking. The subcategories identified below are described further in Section VII.C, below.

Table VII-1—Main Regulatory Options

Wastestream

Subcategory

Technology basis for the BAT/PSES regulatory options

(final rule)

FGD Wastewater

N/A

Chemical precipitation

Chemical precipitation + low hydraulic residence time biological treatment

Membrane filtration.

High FGD flow plants

Chemical precipitation

NS.

Low utilization EGUs

Chemical precipitation

NS.

EGUs permanently ceasing the combustion of coal by 2028

Surface impoundments

NS.

FGD Wastewater Voluntary Incentives Program (Direct Dischargers Only)

Membrane filtration

N/A.

BA Transport Water

N/A

High recycle rate systems

High recycle rate systems.

Low utilization EGUs

Surface impoundments +BMP plan

NS.

EGUs permanently ceasing the combustion of coal by 2028

Surface impoundments

NS.

NS = Not Subcategorized.

Note:

The table above does not present subcategories included in the 2015 rule because EPA did not reopen the subcategorization of oil-fired units or units with a nameplate capacity of 50 MW or less.

1. FGD Wastewater

Under Option D, EPA would establish BAT limitations and PSES for mercury and arsenic based on chemical precipitation. Under Options A and B, EPA would establish BAT limitations and PSES for mercury, arsenic, selenium, and nitrate/nitrite based on chemical precipitation followed by LRTR and ultrafiltration. Option A contains three subcategories. The first subcategory under Option A is for plants with high FGD flows (defined as greater than four MGD). For these plants, Option A would establish limitations and standards for mercury and arsenic based on chemical precipitation. The second subcategory under Option A is for low utilization boilers with a capacity utilization rating (CUR) of less than 10 percent per year. This is a change from the proposed subcategory, which was based on a cutoff of 876,000 MWh utilization. For those low utilization EGUs, Option A would require mercury and arsenic limitations based on chemical precipitation.

The third subcategory under Option A is for EGUs permanently ceasing the combustion of coal by December 31, 2028. This is a change from the proposed subcategory, which only included EGUs retiring by December 31, 2028. For this subcategory of EGUs, Option A would establish BAT limitations equal to BPT limitations for TSS based on the use of surface impoundments with a best management plan for minimizing discharges. For Options A, B, and D, EPA would establish voluntary incentives program limitations for mercury, arsenic, selenium, nitrate-nitrite, bromide, and TDS based on membrane filtration preceded by pretreatment (

i.e.,

chemical precipitation).

For Option C, EPA would establish BAT limitations and PSES for mercury, arsenic, selenium, nitrate/nitrite, bromide, and TDS based on membrane filtration, which would be applicable to all steam electric power plants (except if they qualify for the subcategories contained in the 2015 rule). For Options B and C, the final rule preamble evaluates alternative technology bases for all units to address comments that the proposed rule preamble did not evaluate technology alternatives for high flow plants, retiring units, or repowering units.

As explained above, EPA did not propose to revise BAT limitations or PSES for oil-fired EGUs and/or small EGUs (50 MW or smaller).

The proposal relied on data from three data sets to establish limits for the VIP membrane technology—two using chemical precipitation as the pretreatment technology for a portion of the pilot and one using chemical precipitation as the pretreatment for some portions of the pilot and only microfiltration for other portions of the pilot. However, the cost estimates for membrane filtration technology at proposal were based on microfiltration (or comparable large particle filter) pretreatment technology for plants without existing FGD wastewater treatment, which is less costly than chemical precipitation. The final rule limits are based entirely on those data using chemical precipitation pretreatment, and the final rule costs are also based on chemical precipitation as pretreatment. See Section XIII for further discussion on the use of data to establish limits.

2. BA Transport Water

Under all options described above, the final rule controls the discharge of pollutants from BA transport water by establishing daily BAT limitations and PSES on the volume of BA transport water that can be discharged, based on high recycle rate systems. A high recycle rate system is a recirculating, wet ash handling system that periodically discharges (purges) a small portion of the process wastewater from its system. This is a correction of the proposal, in which the Agency in some instances identified “dry handling or high recycle rate systems” as the proposed technology basis. While plants are free to use dry handling technologies to achieve the limitations in the rule, the final rule limitations are based on high recycle rate systems (as were the proposed limitations).

The only difference between Options A through D for BA transport water is that Option A includes two subcategories. The first subcategory under Option A is for low utilization EGUs with a CUR of less than 10 percent per year. This is a change

from the proposed subcategory which was based on a cutoff at 876,000 MWh utilization. For these low utilization EGUs, Option A would establish BAT limitations for BA transport water equal to the BPT limitations based on gravity settling in surface impoundments to remove TSS.

Such plants would also be required to develop and implement a BMP plan to minimize the discharge of pollutants from BA transport water. Because POTWs are designed to treat conventional pollutants such as TSS, TSS is not considered to pass through, and EPA would establish PSES based on the inclusion of a BMP plan only. For additional information on pass through analyses, see Section VII(C) of the 2015 rule preamble.

Public comments focused on the appropriateness of high recycle rate systems and did not discuss or recommend dry handling or other zero discharge systems as the technology basis, which is consistent with EPA's intent that the technology basis be high recycle rate systems alone, rather than include dry handling or high recycle rate systems.

Although TSS is a conventional pollutant, regulation of TSS in this final rule is intended as regulation of the particulate form of toxic metals through the use of an indicator pollutant.

The second subcategory under Option A is for EGUs permanently ceasing the combustion of coal by December 31, 2028. This is a change from the proposed subcategory, which only included retiring EGUs. For this subcategory of EGUs in Option A, EPA would establish BAT limitations equal to BPT limitations for TSS, based on gravity settling in surface impoundments. For Options B and C, EPA evaluated high recycle rate systems for all units to address comments that technology options should have considered alternatives for retiring units or repowering units. This is a change from the original regulatory options presented at proposal.

Finally, EPA is not finalizing the proposed definitional change to exclude water remaining in a tank-based high recycle rate system when the plant permanently ceases coal combustion. Instead, facilities with high recycle rate systems may properly discharge this water as BA purge water subject to the BPJ limits established by the permitting authority, as discussed in section XIV(A)(2) of this preamble.

B. Rationale for the Final BAT

In light of the criteria and factors specified in CWA sections 304(b)(2)(B) and 301(b)(2)(A) (see Section IV of this preamble), EPA is establishing BAT effluent limitations based on the technologies described in Option A. EPA's selection of the generally applicable BAT (LRTR plus chemical precipitation for FGD wastewater and high recycle rate for BA transport water) in Option A is independently supported by this rulemaking record and not dependent upon the subcategories that are also included in Option A.

EPA's rationale for the final rule's limitations are discussed below. EPA is not finalizing the bromide sub-options proposed in 2019 and, as a result, this section does not include discussion of those sub-options. A more complete discussion of site-specific water quality-based effluent limitations for bromides provided in Section XIV(C) of this preamble.

If any provisions of this rule are reviewed and vacated by a court, it is EPA's intent that as many portions of this rule remain in effect as possible.

1. FGD Wastewater

This final rule identifies treatment using chemical precipitation followed by a low hydraulic residence time biological treatment, including ultrafiltration as the BAT technology basis for control of pollutants discharged in FGD wastewater. More specifically, the technology basis for BAT includes the same chemical precipitation system described in the 2015 rule, which employs equalization, hydroxide and organosulfide precipitation, iron coprecipitation, and removal of suspended and precipitated solids. This chemical precipitation system is followed by a low hydraulic residence time, anoxic/anaerobic biological treatment system designed to remove heavy metals, selenium, and nitrate-nitrite.

The LRTR bioreactor stage is followed by ultrafiltration to remove suspended solids, including colloidal particles, exiting the bioreactor.

Similar to the 2015 rule and consistent with discussions with engineering firms and plant staff, EPA assumed that in order to meet the limitations and standards, plants would take steps to optimize wastewater flows as part of their operating practices (by reducing the FGD purge rate or recycling a portion of their FGD wastewater back to the FGD system), where the FGD system metallurgy can accommodate an increase in chlorides. See Section 5.2.1 of the Supplemental TDD.

Both chemical precipitation and biological treatment are well-demonstrated technologies that are available to steam electric power plants for use in treating FGD wastewater. In addition to the 39 plants using chemical precipitation that were mentioned in the 2015 rule preamble, plants have installed, or have begun installation, of such systems, and have taken steps to cease using surface impoundments to treat their FGD wastewater. This trend is expected to continue in response to the April 11, 2021 cease receipt of waste date in the CCR Part A final rule. In addition, thousands of industrial plants nationwide have used chemical precipitation for the last several decades, as described in the 2015 rule record. Ultrafilters downstream of the biological treatment stage are designed to remove suspended solids—

i.e.,

any reduced, insoluble selenium, mercury, or other particulates—exiting the bioreactor. Ultrafiltration uses a membrane with pore size small enough to remove these smaller suspended particulates after the biological treatment stage, but still much larger than the pore size of the membrane filtration technology (which uses nanofiltration or reverse osmosis). Membrane filtration is the basis for Option C and the VIP under Options A and B, and is designed to remove dissolved metals and inorganics (

e.g.,

nutrients, bromides, etc.). Unlike the nanofiltration and reverse osmosis technologies included as the technology in Option C and the VIP, ultrafilters do not generate a brine that would require encapsulation with FA or other disposal techniques. The types and quantities of solids removed by the ultrafilter in the CP+LRTR treatment system are similar to the particulates captured in other multimedia filters (

e.g.,

sand filters), or settled out in HRTR or surface-impoundment-based systems with longer residence times. These systems do not result in the same non-water quality environmental impacts that are associated with the brine generated by the membrane filtration technology.

After accounting for the changes in the industry described in Section V of this preamble, at the time

Changes to Industry Profile for Coal-Fired Generating Units for the Steam Electric Effluent Guidelines Final Rule

(DCN SE08688) was developed 15 steam electric power plants with wet scrubbers that discharge FGD wastewater are expected to already have technologies in place that can meet the final BAT effluent limitations for FGD wastewater.

Of these 15 plants, seven are currently operating anoxic/anaerobic biological treatment designed to substantially reduce nitrogen compounds and selenium in their FGD wastewater. These biological treatment

systems are a mix of low and high hydraulic residence time.

EPA identified an eighth plant that previously operated an anoxic/anaerobic biological treatment system, but more recently installed a thermal system for the treatment of FGD wastewater. See DCN SE08964. A ninth plant is also operating an anoxic/anaerobic biological treatment system, but is expected to retire all generating units by 2028. Another six steam electric power plants are operating thermal treatment systems for FGD wastewater; one of these is expected to retire all generating units by 2028.

Two plants will retire or cease burning coal prior to 2028. The remaining 13 plants represent 14 percent of steam electric power plants with wet scrubbers. EPA notes that 35 percent of all steam electric power plants with wet scrubbers use FGD wastewater management approaches that eliminate the discharge of FGD wastewater altogether. But, although these technologies (described above in Section V.C.1) may be available to some plants, none of them are available nationwide, and thus do not form the basis for the final BAT limitation. For example, evaporation impoundments are only practical in certain climates. Similarly, complete recycle FGD systems are only available at plants with appropriate FGD metallurgy. Facility conditions and availability of these technologies have not materially changed since the 2015 rule, and EPA thus reaffirms that these technologies are not available nationwide and are not a basis for the final BAT limitations.

In addition to these seven plants, some plants employ other types of biological treatment. Some of these systems are sequencing batch reactors (SBR), which treat nitrogen and can be operated to remove selenium. The SBR systems currently operating at steam electric power plants, however, would likely not be able to meet the limitations discussed in the final rule without reconfiguration.

In the 2015 rule, EPA rejected three availability arguments made against biological treatment. EPA solicited comment on retaining its 2015 findings concerning biological treatment, and no new information was provided by commenters suggesting that EPA's 2015 analysis was incorrect. Instead, EPA has continued to confirm its prior findings concerning the availability of biological treatment. First, EPA rejected the argument that maintaining a biological system over the long run is infeasible. Of the nine full-scale systems mentioned above, three plants have used the biological technology for more than a decade, with varying operating conditions, climate conditions, and coal sources, to treat FGD wastewater. Many pilot tests of the biological technology have been conducted at various plants, and data from these tests demonstrate that, even in the face of major upsets during chemical precipitation, the biological stage continues to reduce selenium and nitrogen.

In the 2015 rule, EPA also rejected the argument that selenium removal efficacy is subject to the type of coal burned and coal-switching. Plants have continued to operate biological treatment systems while switching coals and, in those cases, have maintained selenium removal. Furthermore, at least three pilot- and one full-scale system have now been successfully run or installed to treat FGD wastewater at plants burning subbituminous coals or blends of bituminous and subbituminous coals, encompassing both HRTR and LRTR technologies.

Finally, in the 2015 rule, EPA rejected arguments that cycling plants up and down in production, and even out of service for various periods of time, would affect the ability of plants to meet the effluent limitations. Industry provided data for two plants showing that they successfully operated biological systems while cycling operations and undergoing shutdowns in the years since the 2015 rule.

While the rationale above applies to both CP+HRTR and CP+LRTR technologies, EPA is establishing BAT based on the CP+LRTR technologies rather than the CP+HRTR technologies. Some commenters pointed out that CP+HRTR technologies are still available and economically achievable,

and argued that EPA is thus obligated to select CP+HRTR. EPA agrees that CP+HRTR continues to be available and economically achievable; however, after considering the statutory factors in section 304 of the CWA (as EPA is required to do), EPA does not find that CP+HRTR is the

Best

Available Technology Economically Achievable. CP+LRTR pollutant reductions are comparable to CP+HRTR pollutant reductions,

are less costly, and require significantly less process or plant footprint modifications than the CP+HRTR option.

Without support, some commenters also suggested that CP+LRTR and CP+HRTR are the same technologies. A more detailed response is provided in

Response to Public Comments for Revisions to the Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category

(DCN SE08615).

For example, while the effluent from CP+LRTR is more variable than from CP+HRTR, both technologies achieve long-term average effluent concentrations for selenium lower than 20 mg/L.

As explained in Section XIII of this preamble, the long-term averages forming the basis of the selenium limitations for CP+LRTR and CP+HRTR are similar, and the higher selenium limitations for the CP+LRTR systems are largely driven by increased short-term variability around that average, rather than a meaningful difference in long-term pollutant removals.

Some commenters argued that CP+LRTR pollutant reductions are not comparable to HRTR pollutant reductions. EPA disagrees with these commenters and rejects this characterization for several reasons. First, these comments appear to be limited to a single pollutant: Selenium. When comparing the limitations of all four regulated pollutants (mercury, arsenic, selenium, and nitrate/nitrite) in the 2015 rule to this final rule, some limitations are more stringent, while others are less stringent.

Some commenters expected the limitations and long-term averages for all constituents to be less stringent with CP+LRTR as compared to CP+HRTR due to the shorter residence time. This is not the case. Indeed, some limitations become more stringent due, in part, to the different design of CP+LRTR systems, which include ultrafiltration in the prefabricated systems delivered for pilot studies and full-scale installations to date.

Thus, to the extent that commenters relied on the limitations and long-term averages to make this argument, EPA concludes it is reasonable and allowed by the Act to consider removals as a whole, which results in comparable removals for the suite of pollutants in FGD wastewater discharges.

Courts have recognized that while section 301 of the CWA is intended to help achieve the national goal of eliminating the discharge of all pollutants, at some point the technology-based approach has its limitations.

See Am. Petroleum Inst.

EPA,

787 F.2d 965, 972 (5th Cir. 1986) (“EPA would disserve its mandate were it to tilt at windmills by imposing BAT limitations which removed de minimis amounts of polluting agents from our nation's waters [. . .]”).

While these four indicator pollutants are regulated, the record for the 2015 rule and current final rule both indicate reductions in many other pollutants.

To the extent that limits become more stringent due to the use of data from pilot studies with chemical precipitation systems designed to meet the 2015 rule limits prior to the biological treatment components, CP+HRTR limits would also be expected to become more stringent to some extent.

Second, even taking selenium in isolation, EPA disagrees that a simple comparison of numeric limitations and long-term averages is the only way to identify pollutant removals attainable through the application of BAT. It can be misleading to look at the numeric limitations in isolation. Instead, EPA has considered pollutant concentrations in treated effluent as compared to those in raw FGD wastewater. In the 2015 rule TDD, EPA estimated the average selenium concentration in untreated FGD wastewater as 3,130 ug/L. Using this for comparison demonstrates that both the CP+LRTR and CP+HRTR treatment trains remove more than 99 percent of selenium initially present in FGD wastewater. Even were EPA to examine incremental removals, when compared to the performance of surface impoundments under existing BPT regulations, both treatment trains would remove more than 99 percent of the selenium remaining after physical settling. EPA also notes that both the long-term average and the actual limitations for selenium in this final rule are more stringent than they were in the proposed rule. In summary, CP+LRTR and CP+HRTR are two very effective selenium removal technologies. Between these two, EPA selected as BAT the technology that is also less costly and requires significantly less modification of a plant's process or footprint.

CP+LRTR is less costly than the CP+HRTR technology selected as the BAT basis of the 2015 rule. Compared to the baseline of the 2015 rule, CP+LRTR is estimated to save approximately $52 million per year in after-tax costs to industry

While the CP+HRTR costs are economically achievable, EPA finds those costs unreasonable for a treatment technology that would result in marginal additional reductions in selenium and that would result in marginal increases in other pollutants, such as mercury.

Due to the final rule's changed compliance dates, this estimate also includes discounting which may overstate the savings.

CP+LRTR requires fewer process changes than CP+HRTR. Compared to HRTR, LRTR installations are less complex and require fewer modifications to a plant's footprint. The HRTR systems used as the basis for BAT in the 2015 rule were large, concrete tanks, which, along with their associated piping and pumping and control equipment, would be fabricated on site. By contrast, new LRTR systems have smaller footprints, and in many cases come prefabricated as modular components, including the ultrafilter polishing stage, and require little more than a concrete foundation, electricity supply, and piping connections. For further public comments and responses regarding HRTR and LRTR, see DCN SE08615.

a. Membrane Filtration

Except for plants participating in the VIP discussed below, the final rule does not establish BAT limitations based on membrane filtration (Option C). EPA received many comments arguing both in favor and against the use of membrane filtration as BAT for treatment of FGD wastewater, including comments on the technology's availability, costs, economic achievability, and non-water quality environmental impacts. With respect to availability, some commenters argued that the technology is available, citing pilot studies, three full-scale foreign installations,

use in other industrial sectors, and vendor claims of product performance. Other commenters argued that this technology is not available due to uncertainties regarding the extent of pretreatment required to ensure reliable treatment performance and management of the resulting brine. With respect to costs, some commenters argued that costs were overestimated due to decreasing EGU use, resulting in reduced flow volumes that require treatment; while other commenters argued that costs were underestimated due to incomplete pretreatment costs (

e.g.,

microfiltration rather than full chemical softening), failure to analyze costs using maximum design flows, missing cost components, and underestimated ash needs for brine management. With respect to economic achievability, some commenters pointed to uncertainties about the costs and asserted that membrane filtration would not be economically available for some plants. Finally, with respect to non-water quality environmental impacts, some commenters argued that many plants currently make beneficial use of some or all of their FA (a practice that could be hindered if plants use membrane filtration); while other commenters argued that beneficial use of FA would not be affected by use of membrane filtration and that EPA failed to evaluate alternative brine management methods.

The record at proposal included three full-scale foreign installations.

As the summary of comments presented above makes clear, EPA received a wide range of comments on membrane filtration technology. After carefully considering the statutory factors for BAT and available data, EPA is rejecting membrane filtration as BAT. First, based on significant information gaps and uncertainties in EPA's record, EPA cannot conclude that membrane filtration is technologically available nationwide, as required by the CWA. Second, the Agency finds that, on a nationwide basis, membrane filtration entails unacceptable non-water quality environmental impacts associated with management of the membranes' byproduct, brine. Finally, while the factors above are sufficient to reject membrane filtration as BAT, EPA also notes that membrane filtration would result in higher costs to industry.

At the time of the 2015 rule, EPA had no record of information about membrane filtration technologies. Since that time, EPA collected information on several types of membrane filtration technologies. Microfiltration and ultrafiltration membranes are used primarily for removing suspended solids, including colloids. Nanofiltration, reverse osmosis, forward osmosis, and electrodialysis reversal (EDR) membranes are used to remove a broad range of dissolved pollutants. Each of these membrane filtration technologies generate both a treated effluent and a residual wastestream that requires further treatment or disposal. Microfiltration and ultrafiltration generate a solid waste residual, which is disposed of. Nanofiltration, reverse osmosis, forward osmosis, and EDR all produce a concentrated brine residual which must be disposed of. At proposal, EPA considered nanofiltration, reverse osmosis, forward osmosis, and EDR membranes and proposed effluent limitations for the VIP option based specifically on a combination of microfiltration and reverse osmosis membrane technologies.

Other industries use a variety of different types of membrane filtration technologies. EPA met with vendors that have installed membrane systems in several industries, including textiles,

chemical manufacturing,

mining,

and agriculture.

Within the steam electric power generation industry, reverse osmosis membranes are a technology used for treating EGU makeup water and cooling tower blowdown, and EDR membranes are a technology used for treating ash impoundment discharges.

Nevertheless, it cannot be assumed that membrane filtration technology is transferable, and the information presented below demonstrates that, despite its use in other industries, there may be technical issues constraining its use for treating FGD wastewater.

ERG. 2020. Final Notes from Call with Dupont. DCN SE08618.

ERG. 2019. Final Notes from Meeting with Pall Water. (5 March). EPA-HQ-OW-2009-0819-7613; Wolkersdorfer, Christian

et al.

2015. Intelligent mine water treatment—recent international developments. (21 July). DCN SE08581; U.S. EPA. 2014. Office of Superfund and Remediation and Technology Innovation. Reference Guide to Treatment Technologies for Mining-Influenced Water. EPA 542-R-14-001. (March). DCN SE08582.

CH2M Hill. 2010. Review of Available Technologies for the Removal of Selenium from Water. (June). DCN SE08583.

EPRI (Electric Power Research Institute). 2015.

State of Knowledge: Power Plant Wastewater Treatment—Membrane Technologies.

August. 3002002143.

EPA's record demonstrates that no domestic steam electric power plants have installed full-scale nanofiltration, reverse osmosis, or EDR membrane filtration systems to remove dissolved pollutants in FGD wastewater.

A vendor email cited by some commenters erroneously asserted that a full-scale installation of such a technology had begun at Georgia Power's Plant Scherer. Follow-up discussions with staff working on that project revealed that the plant is not installing a permanent full-scale membrane technology to treat FGD wastewater, but is performing a long-term pilot of both membrane filtration and biological treatment systems to

evaluate possible compliance alternatives under planned future changes to the plant (see DCN SE08619). The State of Maryland also informed EPA that three GenOn plants planned to install technologies to meet the 2015 rule VIP effluent limitations. In a teleconference call held to learn more about these plans, GenOn staff stated that one of these plants (Dickerson) had announced its retirement, but confirmed that the other two (Chalk Point and Morgantown) are currently considering reverse osmosis systems (see DCN SE08614).

EPA views GenOn's consideration of membrane technology similarly to the bids and engineering reports for full-scale systems that the agency was aware of at proposal. As discussed at proposal, the sources of the bids and engineering reports expressed concerns about operating a technology on this wastewater that would be the first of its kind in the U.S. While bids, engineering reports, and one company considering potential membrane installations are important considerations in evaluating the availability of a technology, they do not demonstrate that the technology is available under the CWA. Because no full-scale membrane filtration system for treatment of FGD wastewater is yet operating domestically, EPA carefully considered available data from pilots, foreign installations, and other industries.

Ultrafiltration has been installed as part of several FGD wastewater treatment systems in the U.S. and is included as a back-end component of the CP+LRTR BAT established in this final rule; however, these membranes are only capable of removing suspended solids, not dissolved pollutants.

The company indicated that plans for both units will depend on the requirements of this final rule, and also, for one of its units, changing electricity demand.

With respect to pilots, EPA is aware of at least 19 previous or ongoing domestic pilot studies and one foreign pilot study of FGD wastewater treatment using four different membrane filtration technologies.

All of these technologies first used some form of suspended solids removal, such as microfiltration or chemical precipitation. This pretreated FGD wastewater was then fed into either nanofiltration, reverse osmosis, or EDR membrane filtration systems. For several of the pilot studies, the resultant brines were mixed with FA and/or lime to test the potential for encapsulation of the concentrated brine wastestream.

Two of these pilot studies were completed in 2014, but information about these tests was not provided to EPA prior to the 2015 rule.

The record includes additional encapsulation studies and data not explicitly linked to these 19 pilots.

EPA is aware of 12 foreign installations: One in South Korea, one in Finland, and 10 in China. EPA's rulemaking record contains very limited information about these plants. When EPA contacted Doosan about its system in South Korea, the company declined to share plant operation, maintenance, or performance information, and indicated that it was not interested in the U.S. market. Similarly, EPA contacted Lenntech regarding its system in Finland, but has received no information about this plant's operation, maintenance, or performance.

Regarding the plants in China, EPA is generally aware that two of the plants employ pretreatment and a combination of reverse osmosis and forward osmosis. But EPA was not able to obtain further information about the specific configurations, maintenance, or long-term performance of these two systems.

EPA also has no information about how the resultant brine is being managed or disposed of. Furthermore, the company that sold these two systems has since ceased commercial operations.

EPA is aware that two other plants operating in China employ pretreatment followed by nanofiltration and reverse osmosis. As with the systems above, the vendors declined to provide plant operation, maintenance, or performance information to EPA. The remaining Chinese systems were developed by DuPont, which met with EPA after proposal to provide what limited information was available. While DuPont has sold six systems to Chinese plants to treat FGD wastewater, the company did not have access to operation, maintenance, or performance data for these systems.

This is in contrast to biological treatment systems for which EPA has long-term performance data. Although LRTR and HRTR systems differ in their configuration (

e.g.,

residence time), the underlying performance has been well demonstrated on this wastewater.

DCN SE08034 contains a story summarizing the forward osmosis company Oasys ceasing commercial operations.

Due to travel restrictions in place during the COVID-19 pandemic in spring and summer 2020, EPA representatives were unable to travel abroad to visit these plants. Because the vendor companies either ceased operations or declined to provide EPA with information about the operation, maintenance, or performance of their membrane filtration products, and EPA's lack of regulatory authority to compel the production of information from foreign plants, EPA's record has significant information gaps on the operation and performance of membranes used to treat FGD wastewater.

With respect to the use of membrane filtration in other industries and in connection with non-FGD power plant wastestreams, given what is known about FGD wastewater, EPA focused its evaluation on the more challenging wastewaters in other industries. In the mining industry, reverse osmosis is employed to treat mine-influenced water. For example, since 2006, the Bingham Canyon Water Treatment Plant (BCWTP) at the Kennecott South Superfund site treats 3,200 gallons per minute of mine-influenced water and has maintained a TDS removal efficiency of 98.9 percent, given an expected influent TDS of approximately 2,000 mg/L.

Mining wastewaters demonstrate some similar challenges seen in FGD wastewaters, but there are also differences in the two wastestreams. For example, both are highly scaling in gypsum,

but as the BCWTP example demonstrates, mining influent TDS concentrations can be an order of magnitude (or more) lower than the TDS concentrations found in some FGD wastewater streams.

In the mining industry, brine generated by reverse osmosis is typically disposed of through evaporation, deep well injection, or ocean discharge.

U.S. EPA (Environmental Protection Agency). 2014.

Reference Guide to Treatment Technologies for Mining-Influenced Water.

EPA 542-R-14-001. Office of Superfund Remediation and Technology Innovation. March. Available online at:

https://clu-in.org/download/issues/mining/Reference_Guide_to_Treatment_Technologies_for_MIW.pdf

(DCN SE09084).

Patel, S. 2020. Rethinking Wastewater Treatment for Better FGD Economics.

Power Magazine.

May 31. Available online at:

https://www.powermag.com/rethinking-wastewater-treatment-for-better-fgd-economics/

(DCN SE09085).

The FGD wastewater treatment system pilot tests that were highlighted in the petitions for reconsideration of this rule illustrate this point. EPRI. 2017.

Biological Treatment of Flue Gas Desulfurization Wastewater at a Power Plant Burning Powder River Basin Coal—Pilot Demonstration with the ABMet Technology.

EPA-HW-OW-2009-0819-6480.2.

U.S. EPA (Environmental Protection Agency). 2014.

Reference Guide to Treatment Technologies for Mining-Influenced Water.

EPA 542-R-14-001. Office of Superfund Remediation and Technology Innovation. March. Available online at:

https://clu-in.org/download/issues/mining/Reference_Guide_to_Treatment_Technologies_for_MIW.pdf

(DCN SE09084).

In the oil and gas industry, there are several applications and opportunities for membrane filtration, recently summarized by Adham et al. (2018).

For example, nanofiltration is used worldwide for sulfate removal in offshore oil and gas operations. Reverse osmosis is the standard treatment for coal seam gas water in Australia, where regulations restrict underground

injection. Reverse osmosis is also a standard treatment for desalination (

i.e.,

TDS removal) in this industry. In contrast to the uses for mining wastewaters discussed above, the oil and gas industry's use of membranes typically involves wastewaters with TDS concentrations at least as high as those found in FGD wastewater, but with different scaling potential. Within the oil and gas industry, underground injection, evaporation, and ocean discharge are common disposal methods for the resulting brine.

Adham, S., Hussain, A., Minier-Matar, J., Janson, A., Sharma, R. 2018.

Membrane applications and opportunities for water management in the oil and gas industry. Desalination.

440. 2-17. Available online at:

https://www.sciencedirect.com/science/article/pii/S0011916417321380

(DCN SE09087).

Membrane filtration technologies are also employed for other, non-FGD wastestreams at steam electric power plants. Reverse osmosis is a generally accepted, standard practice for treating EGU makeup water at steam electric power plants.

EGU makeup water is often treated groundwater or surface water which would, therefore, not have TDS or scaling potential similar to FGD wastewater. Reverse osmosis has also been used to treat cooling tower blowdown at several coal-fired and non-coal-fired steam electric power plants. According to one reverse osmosis technology vendor, cooling tower blowdown has similar scaling potential to FGD wastewater. EPA does not have information in this record to either confirm this statement or to extrapolate this finding to the industry more broadly; however, scaling is a known issue for cooling tower water, which is ultimately blown down.

The vendor that made this statement sold the system, comprising microfiltration followed by reverse osmosis, to a plant to treat high TDS cooling tower blowdown that was corroding its brine concentrators (thermal systems). This membrane filtration system was able to replace the brine concentrators, resulting in a reduction of parasitic load in cooling tower blowdown and substantial cost savings.

Finally, EDR has also been used at a power plant in South Korea to treat ash transport water for further use as FGD makeup water.

While ash transport water can have high variability, there is no information in the record suggesting that ash transport water has scaling potential or TDS concentrations similar to FGD wastewater.

EPRI (Electric Power Research Institute). 2015.

State of Knowledge: Power Plant Wastewater Treatment—Membrane Technologies.

August. 3002002143.

Daniels, D.G. 2015. Winning the Cooling Tower Trifecta: Controlling Corrosion, Scale, and Microbiological Fouling.

Power Magazine.

August 21. Available online at:

https://www.powermag.com/winning-the-cooling-tower-trifecta-controlling-corrosion-scale-and-aqmicrobiological-fouling/

(DCN SE09088).

Drake, M., Wise, S., Charan, N., and Venkatadri, R. 2012. ZLD Treatment of Cooling Tower Blowdown with Membranes.

WaterWorld.

December. Available online at:

https://www.watertechonline.com/process-water/article/16211541/zld-treatment-of-cooling-tower-blowdown-with-membranes

(DCN SE09089).

https://www.ge.com/in/sites/www.ge.com.in/files/GE_solves_ash%20pond_capacity_issue.pdf

(DCN SE09090).

After evaluating all available information on membrane filtration, EPA has concluded that critical uncertainties remain regarding operation of the suite of membrane filtration technologies that the Agency evaluated as the basis for Option C. With respect to data from the pilot studies, these studies focused on membrane technologies intended to remove dissolved pollutants. Several studies of the technologies designed to remove dissolved pollutants either did not include a second stage of membrane filtration (

i.e.,

a reverse osmosis polishing stage, which electric utilities and vendors indicated would need to be part of any potential future membrane filtration system that they would consider installing to operate with a discharge) or provided only summaries of effluent data because of nondisclosure agreements between EPRI, treatment technology vendors, and/or the plant operators. Both of these limitations prevented EPA from fully analyzing the pollutant removal efficacy and effluent variability associated with the treatment systems used in those studies. The pilot tests that omitted the second stage of membrane filtration do not provide sufficient insight into the performance capabilities of the membrane technology because the initial membrane filtration step (

e.g.,

a nanofilter unit) does not by itself remove the broad range of pollutants as effectively as would be achieved by the two-stage configuration. The pilot tests, for which EPA has only summary-level data, provide summary statistics, such as the observed range of pollutant concentrations, average influent and effluent pollutant concentrations, and duration of the testing periods. EPA, however, lacks the individual daily sample results that are needed to fully evaluate treatment system operation and calculate effluent limitations. Complete data sets were only available from three pilot plants using a single vendor's reverse osmosis technology.

EPA further finds that use of data from treatment of non-FGD wastewaters in this and other industries would not be appropriate because the other wastewaters that are currently being treated by membrane filtration systems at full scale differ in variability, scaling potential, TDS, or a combination thereof.

These three data sets served as the basis of the final VIP limitations, described further in Section XIII of this preamble. These limited data sets do not provide sufficient information to evaluate the performance of nanofiltration and reverse osmosis membrane filtration technology as the primary treatment for dissolved pollutants in FGD wastewater. Additional pilots, tests, and data collection could result in these technologies becoming available by the VIP compliance date of 2028; however, the VIP compliance date is not based on an assumption that the technology will be available by 2028.

Some commenters argue that certain data limitations are not sufficient to reject membrane filtration systems as BAT for FGD wastewater because such systems can be operated as no discharge systems. EPA agrees that membrane filtration systems can be operated as no discharge systems; however, due to the significant data gaps in the record, EPA cannot conclude that such systems can operate continuously as no discharge systems for FGD wastewater, nor that they can operate as no-discharge systems on FGD wastewater in all cases, nor that their continuous operation would not result in other unacceptable non-water quality impacts. Staff working on one current membrane filtration pilot indicated that, with additional flexibility to reuse membrane filtration permeate as EGU makeup water, the plant may consider a no-discharge alternative in the future. At present, however, the pilot is being conducted to determine the feasibility of operating a membrane filtration system with a discharge, including the evaluation of pretreatment and post-treatment to comply with the proposed VIP mercury limitations. Similarly, while GenOn indicated that it is considering installing membrane filtration systems that would recirculate permeate as a no discharge system, GenOn acknowledged that at least some discharges would eventually be necessary, for example when the EGU is not operating or is being retired.

While the limited information in EPA's record on foreign installations may suggest that these systems operate as no-discharge systems, EPA does not have information on these systems' long-term performance to confirm that they continually operate as no-discharge systems, whether there are some periods during which discharges occur, or whether their operation may result in other unacceptable non-water quality impacts. Furthermore, the information that EPA does possess on foreign installations indicates that pretreatment before membrane filtration is a challenge due to FGD wastewater

variability. This is consistent with the public comments received on the proposal, as well as the main focus of the long-term pilot at Plant Scherer. In contrast to the thermal system that EPA visited in Italy before the 2015 rule (and where EPA took samples and discussed the system with experienced engineers), EPA does not have access to the Chinese plants to resolve some of the critical unanswered questions discussed above.

Supplementing what is known about pilot studies and foreign plants with information about the use of membrane filtration on non-FGD wastestreams in this and other industries still does not address or resolve the uncertainties in EPA's record. Although EPA acknowledges that some of the other wastewaters discussed above are subject to operational variability, scaling potential, and high levels of TDS, the unique combination of these factors present in steam electric FGD wastewater favors EPA's conclusion that membrane filtration is not available for treatment of FGD wastewater at all plants in the steam electric power generating industry.

Nevertheless, like evaporation-based and thermal treatment technologies, FGD wastewater may be amenable to treatment with membrane filtration technologies in at least some circumstances. Thus, EPA's conclusion that membranes are not available nationwide, as required under the CWA, does not conflict with EPA's finding that membrane filtration may be available at specific sites for purposes of the VIP.

While one membrane vendor commented that FGD wastewater is no different than any other industrial wastewater, it did not provide any data or analysis to support this statement.

EPA also rejects membranes as the technology basis for BAT for all existing plants because it could discourage more valuable forms of beneficial reuse of FA (such as replacing Portland cement in concrete), causing more FA to be disposed of as waste.

While EPA agrees with comments that there may be several alternative ways to treat or dispose of the brine generated by membrane filtration, as discussed further below, plants are most likely to encapsulate the brine with FA and lime and dispose of the resulting solid in a landfill.

While EPA considers FA use for waste solidification and stabilization as beneficial use, the CCR waste being solidified or stabilized must still be disposed of in accordance with 40 CFR 257.

In concluding that the selection of membranes as BAT would result in unacceptable non-water quality environmental impacts, EPA evaluated brine management alternatives that were discussed with domestic plants employing thermal systems, foreign plants employing membrane filtration systems, and domestic plants in other industries employing membrane filtration systems.

EPA also evaluated whether FA is being disposed of or is being sold and productively reused. After careful review of the information in the record for this rulemaking, EPA projects that, in the United States, the least cost option if membrane filtration were selected would be encapsulation with FA and lime and disposal of the resulting solid in a landfill. The following paragraphs summarize the evaluations which led to EPA's conclusion that there is an unacceptable non-water quality environmental impact in selecting membrane filtration systems as BAT.

EPA did not evaluate alternatives which would not be available to the industry (

e.g.,

unlike offshore oil and gas facilities, ocean discharge would not be available to inland power plants).

There are no domestic plants operating membrane filtration systems for EPA to contact. EPA therefore contacted two domestic plants operating thermal FGD systems and examined information submitted to EPA's Region 1 regarding a third thermal FGD system. Thermal and membrane filtration systems generate similar brines, as both increase the concentration of TDS in FGD wastewater by removal of “clean” water. For the three domestic thermal systems treating FGD wastewater, the resultant brine is either used to condition (

i.e.,

wet) ash for disposal without encapsulation

or is crystallized and sent to a landfill. Thus, encapsulation of the brine using FA at these three plants is unnecessary. When asked about the availability of FA for sale, one of the three plants indicated that its particular market for FA is flush, and that plant was no longer able to maintain contracts for the sale of its FA, which would make it available for the plant to use to encapsulate the thermal system brine. In contrast, two of the plants with which EPA discussed possible future installations of membrane filtration systems stated that they sell 100 percent of the FA generated for beneficial reuse. Although some commenters suggested that there is more than sufficient FA available for reuse, the EPA's rulemaking record contains information to the contrary. According to 2017 and 2018 EIA data, the median percentage of FA that was sold for beneficial use by plants with wet FGD systems was approximately 14 percent, with some plants selling all of their fly ash and some plants selling none. Furthermore, these EIA estimates may be low, as one plant's staff represented that they were beneficially using 100 percent of their FA rather than the amount reported in the EIA data.

A quantitative comparison of EIA data for plants with FGD wastewater indicates that if plants currently disposing of their FA installed membrane filtration, they may have enough FA to encapsulate the quantities of brine produced by membrane filtration. Two assumptions underly EPA's comparison of EIA FA beneficial use and disposal data to FGD brine encapsulation. First, EPA assumes that the fraction of brine generated from all FGD wastewaters is the same at all plants that would install a membrane system. Second, it assumes that all plants that would install a membrane system would be able to make use of similar encapsulation blends as the bids and pilots which EPA reviewed. In practice, EPA expects the percent of brine generated by membrane systems to differ from plant to plant, based on FGD wastewater characteristics. EPA also expects the encapsulation blend to differ from plant to plant based on both the brine characteristics and the fly ash characteristics. This is consistent with public comments EPA received on the proposal. Thus, while EPA's assumption of a typical blend is reasonable for a nationwide assessment, the Agency anticipates that there will be sites where non-water quality environmental impacts are particularly unacceptable.

Ash conditioning with water or surfactants is a standard industry practice to control fugitive dust emissions, and also a standard component of fugitive dust plans required under the CCR rule.

EPA was unable to resolve the conflicting company-stated beneficial use rates at this plant with the plant-specific EIA data.

While there may be some sites where these non-water quality environmental impacts are acceptable, the Agency has not identified either information or a consistent basis upon which to subcategorize these plants. In any case, such a subcategorization approach may still not address the availability concerns raised in the discussion above.

But, while these assumptions are appropriate for nationwide cost estimates which are needed to demonstrate economic achievability for the industry as a whole, this does not necessarily mean that these assumptions should be used for analyzing the non-water quality environmental impacts associated with the resultant brine from membrane use, and in particular, estimating what plants are likely to do with this by-product in relation to available FA. Whether sufficient FA is present on site or available in the local market is a site-specific question. Should plants generate more brine than EPA estimated in its analysis, or should plants not have the quality of FA (

e.g.,

class C, class F) necessary for the

assumed blend, those plants would need to reduce the quantity of ash beneficially reused or acquire a substitute to encapsulate the brine byproduct of an installed membrane system.

Based on the limited available information, EPA understands that at least two foreign plants operating full-scale membrane systems send the resulting brine to a crystallizer to generate and sell a 95 percent high-purity industrial salt. However, there are too many uncertainties for EPA to estimate with confidence how many plants in the United States might be able do the same. EPA understands that these foreign plants engaged in negotiations with end-users prior to commissioning their membrane systems. At one example system, the plant generates and sells approximately 10,000 tons of industrial-grade salt per year. While a crystallizer would be a more expensive option than ash conditioning practiced at no-discharge plants in the U.S., the sale of industrial salt could generate additional revenue to offset those additional costs. Without salt revenue data from China, it is not possible to compare these specific scenarios either in terms of costs or non-water quality environmental impacts and any conclusions would be speculative and lack factual support in this rulemaking record. Furthermore, EPA cannot evaluate the practicality of such sales in the U.S. because the Agency does not know which industries are purchasing these salts, if these industries operate in the U.S., if they would be willing to purchase salts from the U.S., or what the specifications are for the salt product.

Finally, EPA examined brine management in other industries. In both the mining industry and in oil and gas, brine is managed through evaporation (including evaporation impoundments), deep well injection, and ocean discharge. Most steam electric power plants are not near enough to an ocean for ocean discharge to be a feasible alternative. Evaporation is more consistent with disposal methods at the domestic thermal and foreign membrane filtration plants discussed above. The use of evaporation impoundments is generally dependent upon climate and plant space, so not all steam electric power plants may be able to employ evaporation impoundments as is done at some mining and oil and gas establishments. However, crystallization is an evaporation means that is employed at some domestic and foreign plants to manage FGD wastewater brine. Finally, deep well injection is not known to be used at any steam electric power plants to manage FGD wastewater brine.

After consideration of the information above, EPA evaluated membrane filtration with three representative brine management alternatives to determine which could most likely represent future brine management. First, as it did for the proposed rule, EPA evaluated brine encapsulation with FA and lime, in a blend representative of the information in EPA's record.

Second, EPA conducted a sensitivity analysis which examined crystallization and disposal of the resultant salt.

Finally, EPA conducted a sensitivity analysis which examined deep well injection. While EPA received comments that the brine might be sold to oil and gas companies, commenters did not provide any examples where this is currently occurring, nor is the Agency aware of any. Thus, as it did for ocean discharge (see above), EPA concluded that direct sale of brine to oil and gas companies would not be representative of potential brine management in the steam electric power generating industry.

This scenario is representative not only of that blend, but also of blends that would use more or less fly ash and/or lime, as well as less expensive ash conditioning, in which ash is wetted just with the brine (in lieu of other water or surfactants) prior to disposal.

This scenario could also be representative of crystallization with sale of the resultant salt; however, EPA's rulemaking record lacks information with which to analyze potential sales.

After conducting these three representative brine management analyses, EPA concludes that the method most likely to be employed by steam electric power plants using membrane filtration to treat FGD wastewater would be encapsulation with FA and lime for disposal of the resulting solid in a landfill. This brine management alternative was the least cost solution in the bids and engineering documents examined, was the least cost solution in EPA's own cost estimates, and is the disposal approach discussed by both Georgia Power

and GenOn

as their most likely procedure if theyose ultimately choose to participate in the VIP and install membrane filtration systems by the 2028 compliance date.

In discussions about the potential for Plant Scherer to install a membrane filtration technology under the proposed VIP, Georgia Power staff indicated that should such an installation occur, it would make use of a paste landfill where encapsulation of brine would occur.

GenOn indicated that plans for Chalk Point and Morgantown included off-site disposal without FA from those plants because so much of that FA is already beneficially used.

As described in the proposal, landfilling an encapsulated material raises challenges. For instance, comingling encapsulated material with other landfill refuse could result in a leachate blowout. The King County Landfill in Virginia experienced a leachate blowout when compact CCR materials with a low infiltration rate were layered with normal municipal solid waste having a higher infiltration rate. Similarly, in the case of encapsulated brine paste, the paste would set and thereafter achieve a very low infiltration rate. When comingled with CCR having a higher infiltration rate, this would lead to layers with disparate infiltration rates akin to those experienced in the King County scenario. Thus, segregation of low infiltration rate encapsulated brine in a landfill cell separate from other, higher infiltration wastes could be necessary to prevent this layering and a potential leachate blowout. Such dedicated landfill cells do not exist today and would require time to permit and construct.

EPA also estimates that the volume of waste requiring disposal if membrane filtration was selected is 10 times the volume of waste estimated under the selected LRTR technology.

Moreover, instead of disposing of their FA, plants can sell it for beneficial use. As stated in the 2015 CCR rule:

The beneficial use of CCR is a primary alternative to current disposal methods. And as EPA has repeatedly concluded, it is a method that, when performed correctly, can offer significant environmental benefits, including greenhouse gas (GHG) reduction, energy conservation, reduction in land disposal (along with the corresponding avoidance of potential CCR disposal impacts), and reduction in the need to mine and process virgin materials and the associated environmental impacts.

80 FR 21329 (April 17, 2015).

Specifically, the Agency estimated (U.S. EPA 2011) that each ton of FA used as a substitute for Portland cement would avoid the use of 5,400 megajoules of nonrenewable energy, 690 liters of water use, 1,000,000 grams (g) of CO

emissions, 840 g of methane emissions, 1,400 g of CO emissions, 2,700 g of NO

emissions, 2,500 g of SO

emissions, 2,400 g of PM, 0.08 g of Hg, 490 g of TSS discharge, 23 g of BOD discharge, and 46 g of COD discharge.

After considering these cross-program environmental impacts, EPA finds that discouraging this beneficial use of FA on a nationwide basis would result in unacceptable non-water-quality

environmental impacts.

As discussed below in connection with the VIP, however, EPA finds that, based on site-specific circumstances, the non-water quality environmental impacts identified on a nationwide basis could exist to a lesser extent (thereby not resulting in unacceptable non-water quality environmental impacts).

U.S. EPA (Environmental Protection Agency). 2011.

Waste and Materials—Flow Benchmark Sector Report: Beneficial Use of Secondary Materials—Coal Combustion Products.

Office of Solid Waste and Emergency Response. Washington, DC 20460. April.

Although EPA evaluated FA and lime encapsulation as the least-cost nationally available brine disposal alternative, other alternatives with higher costs may also have adverse non-water quality environmental impacts. For example, if a plant chose to crystallize the resulting brine to continue selling its FA, this thermal crystallization process could have a higher cost and parasitic energy load.

The same would be true for other VIP-compliant technologies (

e.g.,

thermal) that might be installed.

While EPA views the foregoing reasoning as sufficient to find that membrane filtration is not BAT for existing sources, EPA notes that membrane filtration is projected to cost industry 26 percent more than estimated at proposal. As identified by commenters, the data used to establish limitations for membrane filtration for the proposed rule included pilots that preceded membrane filtration with chemical precipitation, while the cost estimates were based only on microfiltration as pretreatment. EPA agrees. Where EPA has information on pretreatment at foreign plants, none of those plants relies on microfiltration alone. To correct this inconsistency, in the final rule, EPA included the cost of chemical precipitation as the pretreatment method for the membrane filtration cost estimates and adjusted the set of data used to establish effluent limitations. For the final rule, both effluent limitations and cost estimates reflect data for systems using chemical precipitation as pretreatment before membrane filtration. EPA disagrees with comments that suggested the costs were not estimated correctly due to the use of incorrect flows and FA consumption rates. For a more detailed discussion of the membrane filtration public comments and responses, see DCN SE08615.

In addition to the estimated pretreatment costs, plants will also incur costs to dispose of the resulting brine. Some plants that may otherwise sell their FA may choose to use their FA to encapsulate the brine, thereby foregoing revenue from FA sales. Other plants that choose to continue to sell their FA will need to dispose of the brine using another disposal alternative, such as crystallization, at an additional cost. Costs are a separate statutory factor that EPA considers in selecting BAT (

see,

for example,

BP Exploration & Oil, Inc.

EPA,

66 F.3d 784, 796 (6th Cir. 1996)). Here, while these costs do not make the membrane filtration option economically unachievable across the point source category as a whole,

these estimated increased costs do weigh against selecting membranes as BAT.

See, e.g., Texas Oil and Gas Ass'n et al.

EPA,

161 F.3d 923, 927 (5th Cir. 1998).

b. Other Technologies Evaluated for BAT Limitations

As described further below, EPA is also not establishing BAT limitations based on other technologies evaluated in the 2019 proposed rule and 2015 rule.

First, except for the permanent cessation of coal combustion and low-utilization subcategories discussed below, EPA is not establishing BAT limitations based on surface impoundments. One commenter suggested that EPA should adopt a high recycle rate system for FGD wastewater if the purge from such a system would receive BAT limitations equal to BPT limitations. The commenter relied on EPA's proposed BAT for BA transport water for this suggestion. Even for the purged wastewater from a high recycle rate BA transport water system, however, the final rule does not establish BAT limitations equal to BPT limitations. Instead, EPA leaves the BAT limitations to be determined by the permitting authority on a case-by-case basis, subject to BPJ. Such a case-by-case determination is not warranted for FGD wastewater because EPA has determined that CP+LRTR is available and economically achievable for treatment of FGD wastewater. Furthermore, EPA confirms its previous findings that surface impoundments are not as effective at controlling pollutants (such as dissolved metals and nutrients) as available and achievable technologies like CP+LRTR; however, as described in Section X below, other statutory factors and EPA's rulemaking record support the use of surface impoundments for two subcategories.

Second, except for the low utilization EGU subcategory discussed below, the final rule does not establish BAT limitations or PSES based on chemical precipitation alone. As EPA noted during the development of the 2015 rule, chemical precipitation is effective at removing mercury, arsenic, and certain other heavy metals. This technology alone does not remove nitrogen, nor does it remove the majority of selenium. Furthermore, the data in EPA's rulemaking record demonstrate that both LRTR and HRTR remove approximately 90 percent of the mercury remaining in the effluent from chemical precipitation treatment.

Because the combination of chemical precipitation with LRTR provides substantial further reductions in the discharge of pollutants industry-wide, EPA has established BAT based on CP+LRTR.

Recall that the FGD mercury and arsenic limitations in the 2015 rule were based on chemical precipitation data alone because the plants operating biological systems were not using all of the chemical precipitation additives in the technology basis.

Third, the final rule does not establish BAT limitations based on thermal technologies, such as chemical precipitation (including softening) followed by a falling film evaporator, based on the statutory factors of total costs to industry and non-water quality environmental impacts. EPA received comments stating that thermal technologies are available, are unavailable, are economically achievable, and are not economically achievable. EPA agrees that these technologies are available but disagrees that these technologies are economically achievable. Although commenters arguing against availability raise a number of arguments, these arguments were considered and rejected in the 2015 rule, and no new information has been provided that warrants revisiting those findings. Since the 2015 rule, EPA has collected additional information on full-scale installations and pilots of thermal technologies to treat FGD wastewater. EPA's rulemaking record includes information about nine pilot studies conducted in the United States, providing performance data for five different thermal technologies. In addition, full-scale installations are operating at six domestic plants,

and a seventh purchased thermal equipment, but elected not to install it.

EPA is also now aware of seven foreign installations in Italy and China, five more foreign installations than at the time of the 2015 rule.

One of these plants successfully ran three different thermal systems to treat its wastewater, transitioning from a falling film evaporator to a direct-contact evaporator, which mixes hot gases in a high turbulence evaporation chamber, and finally to a spray dryer evaporator.

This plant purchased a falling film evaporator for the purpose of meeting water quality-based effluent limitations for boron, but then elected to instead pay approximately $1 million per year to send its wastewater to a local POTW.

With respect to economic achievability, in the 2015 rule EPA rejected thermal technology as a basis for BAT limitations due to high costs to industry. New thermal technologies have been pilot tested and used at full scale since the 2015 rule, and related

cost information demonstrates that thermal technologies are now less costly than when estimated for the 2015 rule. Nevertheless, the thermal costs evaluated in EPA's memorandum

FGD Thermal Evaporation Cost Methodology

(DCN SE08631) are still 2.4 times higher than the CP+LRTR technology selected as BAT, and 1.04 times higher than the membrane filtration costs in Option C. As authorized by section 304(b) of the CWA, which requires EPA to consider costs, as well as the discretion that the statute gives EPA to weigh the statutory factors, the Agency finds that, for this final rule, thermal technologies are not BAT due to the unreasonably high costs to industry.

Given the high costs associated with thermal technology, and the fact that the steam electric power generating industry continues to face costs associated with several other rules, in addition to this rule, EPA is not establishing BAT limitations for FGD wastewater based on thermal technologies.

Some industry comments asserted that EPA underestimated the cost for thermal technologies and that more accurate costs would make these technologies economically unachievable. However, as described above, EPA need not adjust its cost assumptions because the Agency's own cost estimates result in unreasonably high costs.

In addition to the unreasonably high costs, thermal technologies have unacceptable non-water quality environmental impacts associated with management of the resultant brine. Thermal technologies generate a brine similar to membrane filtration technologies. For this reason, portions of the discussion of membrane filtration brine above are based on brine management at plants with thermal systems. EPA also concludes that thermal technologies have unacceptable non-water quality environmental impacts. The reasoning is the same as for membrane filtration—unacceptable non-water quality environmental impacts would occur as a result of discouraging the beneficial use of FA, and additional disposal requirements would result from the production of a brine byproduct.

Furthermore, since the membrane filtration technologies evaluated in Option C appear to achieve similar pollutant removals at lower costs than thermal, as discussed later in this section, EPA is revising the basis for the VIP limitations adopted in the 2015 rule to membrane filtration, instead of thermal technologies.

EPA notes that thermal technologies could continue to be used to meet the voluntary incentives program limitations based on membrane filtration.

Finally, EPA is declining to establish BAT limitations for FGD wastewater as a case-by-case determination to be made by the permitting authority using BPJ. EPA explained in the 2015 rule why BPJ determinations would not be appropriate for FGD wastewater, particularly given the availability of several other technologies, and nothing in EPA's record would alter the Agency's previous conclusion.

2. BA Transport Water

Under the final rule, EPA has selected high recycle rate systems as the technology basis for establishing the BAT requirements to control pollutants discharged in BA transport water. EPA determines that this technology is available and economically achievable after evaluating the factors specified in CWA section 304(b)(2)(B). In the 2015 rule, EPA selected dry BA handling or closed-loop wet ash handling systems as the technology basis for the no-discharge BAT requirements for BA transport water. EPA established no discharge effluent limitations based on these technologies, while also creating a limited allowance for pollutant discharges associated with leaks and certain maintenance activities.

See

40 CFR 423.11(p).

At the time of the 2015 rule, EPA estimated that more than 50 percent of plants already employed dry handling systems or wet sluicing systems designed to operate closed-loop, or had announced plans to switch to such systems in the near future. Based on new information collected since the 2015 rule, EPA now estimates that number to be over 75 percent of the industry. However, since the 2015 rule, EPA's understanding has changed regarding the types of available dry systems, and the ability of wet systems to operate a true closed-loop system (or to achieve complete recycle) has changed.

EPA is aware of advances in dry BA handling systems since the 2015 rule.

For example, in addition to under-EGU mechanical drag chain systems (described in the 2015 rule), pneumatic systems and compact submerged conveyors (CSCs, which are referred to in the proposed rule and in many public comments as submerged grinder conveyors, the appellation of the most commonly sold system) are now in use at some plants. EPA received comments that it failed to consider whether plants could retrofit their operation using CSC systems, and that EPA should retain the zero discharge limitations established in the 2015 rule. EPA also received comments that CSCs could be more costly than other technologies and that CSCs are not available. These included comments that CSCs are not demonstrated, that CSCs cannot handle the high ash loading rates of larger EGUs, and that retrofit with CSCs are not feasible for EGUs below grade or with space constraints leaving the EGU.

The term “dry handling” is used to refer to ash handling systems that do not use water as the transport medium for conveying ash away from the EGU. Such systems include pneumatic and mechanical processes (some mechanical processes use water to cool the BA or create a water seal between the EGU and ash hoppers, but the water does not act as the transport medium).

EPA disagrees with commenters who asserted that it failed to consider zero discharge requirements for BA transport water. While the Agency acknowledges that it did not identify technologies that could achieve zero discharge of BA transport water among its “main” regulatory options at proposal, the 2015 rule required zero discharge, and EPA described the technologies forming the basis for the 2015 rule and considered them and others, including CSCs, in this rulemaking.

With respect to costs, since the proposal, EPA has conducted conference calls with two plants, one of which operates a vacuum system and one that operates a CSC. The Agency acknowledges that, at proposal, it did not estimate costs of installing pneumatic systems (which include both dry vacuum or pressure systems) or CSCs. In the case of pneumatic systems, these systems tend to be more expensive than alternatives, and third party EPCs have indicated that the decision to install such systems is often driven by a combination of space constraints and limitations on water withdrawals. EPA continues to view pneumatic systems as more expensive than alternatives. With respect to CSCs, the Agency did not have cost data at proposal to conduct a cost analysis; however, since proposal the Agency has obtained CSC cost information from one plant, which demonstrates that for that plant it was the least-cost technology alternative. The costs for this plant are comparable to other technologies that EPA evaluated, and this finding is consistent with the representations of electric utilities, vendors, and third-party EPC firms, which have found that, on a plant-specific basis, CSCs may be the least costly bottom ash conversion option. However, because CSCs serve only an individual EGU, the more EGUs a plant has, the less economical this technology becomes. One vendor suggested that plants with three or more EGUs would generally find remote MDSs to be a least-cost alternative.

With respect to availability, commenters disputed that CSCs are demonstrated, but did not make the

same claim for pneumatic systems. Two full-scale CSCs became operational in 2019,

while 50 plants employing pneumatic systems are currently operating, with retrofits dating back to 1992. EPA is aware of only two CSCs in operation domestically today; however, the Agency has identified three additional CSCs currently being installed. Furthermore, in a conference call with one plant, it appears that, while there were some challenges, especially during installation, this particular system has operated successfully since its commissioning. However, this plant did not experience the same space constraints discussed below. Similarly, commenters raised issues with the ability of CSCs to handle high ash loading rates. While staff at one plant indicated that they successfully ramped up the speed of their CSC to handle more tons of ash per hour, and constructed a 100 percent redundant system, AEP submitted comments that the installation of CSCs at a larger lignite EGU with high ash loading rates would be considered high “application risk.”

Specifically, the lignite coal burned in this EGU has a much higher ash content, and its bottom ash tends to be more abrasive, relative to the typical bituminous coals burned and bottom ash produced at other AEP EGUs. As a result, 100 percent redundant systems would be required, which would eliminate the cost savings potential of the CSC system.

In contrast, no commenters claimed that pneumatic systems had loading rate constraints. Finally, industry engineers, third-party EPC firms, and vendors have indicated that pneumatic systems and CSCs can be installed at plants that are constrained from retrofitting the larger under-EGU MDS due to insufficient vertical space under the EGU. EPA has identified five EGUs at three plants where MDS installation is precluded due to insufficient vertical space. Commenters stated that CSCs, while smaller, could not be installed at these space-constrained plants where MDS installation is precluded without dismantling and excavating beneath the EGU, and EPA finds that, at a minimum, these five EGUs could face such limitations. AEP additionally described EGUs where space constraints would not preclude installation of a single CSC, but would preclude the installation of AEP's required 100 percent redundant design basis.

Commenters did not argue that space constraints would preclude pneumatic systems.

EPA only had a conference call with one of these two plants because the second plant did not respond to EPA outreach.

AEP indicated that the vendor had found this application to be high risk as well.

See

DCNs SE08695 and SE08695A1.

See

DCNs SE08695 and SE08695A1.

With respect to wet BA handling systems, in their petitions for reconsideration and in recent meetings with EPA, utilities and trade associations informed EPA that many existing remote wet systems are, in reality, “partially closed” rather than fully closed-loop, as assumed by EPA in the 2015 rule. Utilities and trade associations informed EPA that these systems operate partially closed, rather than closed, due to small discharges associated with: (1) Additional maintenance and repair activities not accounted for in the 2015 maintenance allowances;

(2) water imbalances within the system, such as those associated with stormwater;

and (3) water chemistry imbalances, including acidity and corrosiveness, scaling, and fines buildup. While some plants have controlled or eliminated these challenges with relatively straightforward steps (

See

DCNs SE08179 and SE06963), others require more extensive process changes and associated increased costs or find them difficult to resolve (

See

DCNs SE08188, SE08180, and SE06920).

The 2015 rule maintenance discharges were characterized as not a significant portion of the system volume, compared to, for example, potential discharges resulting from maintenance of the remote MDS tank or the conveyor itself. Such maintenance could require draining the entire system, which would not be permissible under the 2015 rule maintenance discharge allowance.

The 2015 rule provided no exemption or allowance for discharges due to precipitation events. While systems are often engineered with extra capacity to handle rainfall and runoff from a certain size precipitation event, these events may occur back-to-back, or plants may receive events with higher rates of accumulation beyond what the plant was designed to handle.

EPA agrees that the new information indicates that some plants with wet ash removal systems can operate as zero discharge systems, but in many cases must operate as high recycle rate systems. While some plants currently handle the challenges discussed above by discharging some portion of their BA transport water, the record demonstrates that plants can likely eliminate such discharges with additional process changes and expenditures. For the 2015 rule, EPA estimated costs of chemical additions to manage scaling. Now, companies could be adding additional treatment chemicals (caustic) to manage acidity or other chemicals to control alkalinity, using reverse osmosis filters to remove dissolved solids from a slipstream of the recycled water, adding polymer to enhance settling and removal of fine particulates (“fines”), and building storage tanks to hold water during infrequent maintenance or precipitation events. Industry-wide, EPA conservatively estimates the costs of the additional measures needed to achieve and maintain a truly closed-loop system to be $63 million per year in after-tax costs, beyond the costs of the systems themselves.

78 79

These additional costs and process changes were not accounted for in the 2015 rule; however, as discussed in Section 5.3.3 of the Supplemental TDD, EPA has accounted for these costs in estimating the baseline costs of the BA limitations in the 2015 rule. Some commenters argued that EPA's costs were too conservative and asserted that these costs would not be necessary at most sites. While EPA agrees that it is not likely that all plants would incur these additional costs, EPA had no means to predict which plants would ultimately incur these additional costs, and thus the Agency reasonably assumed, for purposes of its economic achievability analysis, that each plant would incur these costs—in order to ensure that the costs upon which economic achievability are based are not underestimated. However, to the extent that necessary purges are smaller than this upper bound, EPA evaluated an alternate scenario in a Bottom Ash Alternate Purge Sensitivity Analysis (DCN SE09073). These lower costs were considered in addition to the costs presented above and would not change EPA's conclusion that high recycle rate systems, rather than closed-loop systems, are BAT. For further discussion of public comments and responses about closed loop and high recycle rate systems,

see

DCN SE08615.

Due to the final rule's changed compliance dates this estimate also includes discounting, which may overstate the savings.

Utilities and EPC firms have discussed the availability of new dry systems, such as the CSC or pressure systems, which at some plants would have costs similar to recirculating wet systems (which would require a purge). Because EPA did not have cost information to determine the subset of plants for which new dry systems might be least costly, some portion of the costs estimated for this rule may be based on selecting recirculating wet systems at plants that could ultimately choose to install dry handling technologies. Thus, EPA may overestimate costs or underestimate pollutant removals at the subset of plants where such a dry system would be selected.

EPA also recognizes the need for plants to consider their ability to comply with multiple environmental regulations simultaneously. As discussed in Section IV above, EPA has recently finalized the CCR Part A rule, requiring plants to cease receipt of waste in unlined surface impoundments by April 11, 2021 (with certain

exceptions).

The challenges of operating a truly closed-loop system, discussed above, are compounded by the requirements of the CCR rule. Plants often send various CCR and non-CCR wastestreams, such as coal mill rejects, economizer ash, etc., with BA transport water into their surface impoundments. According to reports provided to EPA and conversations with electric utilities, several plants have already begun (or even completed) the transition away from impoundments and use the BA treatment system for some of their non-CCR (

i.e.,

non-FA, BA, or FGD) wastewaters.

This can be beneficial where it reduces the discharge of the non-CCR wastewaters, which might otherwise be discharged subject only to the TSS limitations applicable to low volume wastewater. At the same time, however, doing so can lead to or exacerbate scaling, corrosion, or plugging of equipment, all of which require process changes and additional expense to address, thereby complicating establishment of a closed-loop system. These problems could be avoided by purging the system from time to time, as necessary. Fewer than 25 percent of plants have not yet installed a BA transport water technology beyond surface impoundments and could potentially employ a dry system. However, due to the fast approaching cease-receipt-of-waste date under the CCR rule, it is probable that the majority of these plants have already begun their conversions to wet ash handling systems, which makes switching to a wholly different BA handling technology infeasible so late into the process.

For EPA to not allow a purge may encourage more of the non-CCR wastewaters mentioned above to be discharged as low volume waste. In order to accommodate both compliance with this rule and the CCR Part A rule, EPA finds it necessary for the permitting authority to allow for a high recycle rate system with some purge rather than a truly closed-loop system.

As mentioned in Section IV of this preamble, further information about this proposal is available at

http://www.regulations.gov,

Docket EPA-HQ-OLEM-2019-0172.

In some cases, the treatment system predated even the proposed CCR rule.

The CCR Part A rule a

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