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

Federal RegisterNov 22, 2019

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 423

[EPA-HQ-OW-2009-0819; FRL-10002-04-OW]

RIN 2040-AF77

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

AGENCY:

Environmental Protection Agency.

ACTION:

Proposed rule.

SUMMARY:

The Environmental Protection Agency (the EPA or the Agency) is proposing 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 proposal is estimated to save approximately $175 million dollars annually in pre-tax compliance costs and $137 million dollars annually in social costs as a result of less costly FGD wastewater technologies that could be used with the proposed relaxation of the Steam Electric Power Generating Effluent Guidelines 2015 rule (the 2015 rule) selenium limitation; less costly BA transport water technologies made possible by the proposed relaxation of the 2015 rule's zero discharge limitations; a two-year extension of compliance timeframes for meeting FGD wastewater limits, and additional proposed subcategories for both FGD wastewater and BA transport water. EPA also believes that participation in the voluntary incentive program would further reduce the pollutants that these steam electric facilities discharge in FGD wastewater by approximately 105 million pounds per year.

DATES:

Comments.

Comments on this proposed rule must be received on or before January 21, 2020.

Public Hearing.

The EPA will conduct an online public hearing about today's proposed rule on December 19, 2019. Following a brief presentation by EPA personnel, the Agency will accept oral comments that will be limited to three (3) minutes per commenter. The hearing will be recorded and transcribed, and the EPA will consider all of the oral comments provided, along with the written public comments submitted via the docket for this rulemaking. To register for the hearing, please visit the EPA's website at

https://www.epa.gov/eg/steam-electric-power-generating-effluent-guidelines-2019-proposed-revisions

ADDRESSES:

Submit your comments on the proposed rule, identified by Docket No. EPA-HQ-OW-2009-0819, by one of the following methods:

•

Federal eRulemaking Portal: https://www.regulations.gov/

(preferred method). Follow the online instructions for submitting comments.

•

Email: a-and-r-docket@epa.gov.

Include Docket ID No. EPA-HQ-OW-2009-0819 (specify the applicable docket number) in the subject line of the message.

•

Fax:

(202) 566-9744. Attention Docket ID No. EPA-HQ-OW-2009-0819 (specify the applicable docket number).

•

Mail:

U.S. Environmental Protection Agency, EPA Docket Center, Docket ID No. EPA-HQ-OW-2009-0819, Office of Science and Technology Docket, Mail Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460.

•

Hand Delivery/Courier:

EPA Docket Center, WJC West Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004. The Docket Center's hours of operations are 8:30 a.m.-4:30 p.m., Monday-Friday (except Federal Holidays).

Instructions:

All submissions received must include the Docket ID No. for this rulemaking. Comments received may be posted without change to

https://www.regulations.gov/,

including any personal information provided. For detailed instructions on sending comments and additional information on the rulemaking process,

see

the “Public Participation” heading of the

SUPPLEMENTARY INFORMATION

section of this document.

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, the EPA defines terms and acronyms used in Appendix A.

Supporting Documentation.

The rule proposed today is supported by a number of documents including:

•

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

(Supplemental TDD), Document No. EPA-821-R-19-009. This report summarizes the technical and engineering analyses supporting the proposed rule. The Supplemental TDD presents the EPA's updated analyses supporting the proposed revisions to FGD wastewater and BA transport water. These updates include additional data collection that has occurred since the publication of the 2015 rule, updates to the industry (

e.g.,

retirements, updates to FGD treatment and BA handling), cost methodologies, pollutant removal estimates, corresponding nonwater quality environmental impacts associated with updated FGD and BA methodologies, and calculation of the proposed effluent limitations. 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 the EPA's data collection, description of the industry, and underlying analyses supporting the 2015 rule.

•

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

(Supplemental EA), Document No. EPA-821-R-19-010. This report summarizes the potential environmental and human health impacts that are estimated to result from implementation of the proposed revisions to the 2015 rule.

•

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

(BCA Report), Document No. EPA-821-R-19-011. This report summarizes estimated societal benefits and costs that are estimated to result from implementation of the proposed revisions to the 2015 rule.

•

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

(RIA), Document No. EPA-821-R-19-012. This report presents a profile of the steam electric power generating industry, a summary of estimated costs and impacts associated with the proposed revisions to the 2015 rule, and an assessment of

the potential impacts on employment and small businesses.

•

Docket Index for the Proposed Revisions to the Steam Electric ELGs.

This document provides a list of the additional memoranda, references, and other information relied upon by the EPA for the proposed revisions to the ELGs.

Organization of this Document.

The information in this preamble is organized as follows:

I. Executive Summary

II. Public Participation

III. General Information

A. Does this action apply to me?

B. What action is the Agency Taking?

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

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

IV. Background

A. Clean Water Act

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 Rule

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

E. Other Ongoing Rules Impacting the Steam Electric Sector

1. Clean Power Plan (CPP) and Affordable Clean Energy (ACE)

2. Coal Combustion Residuals (CCR)

F. Scope of This Proposed Rulemaking

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. Proposed Regulation

A. Description of the BAT/PSES Options

1. FGD Wastewater

2. BA Transport Water

B. Rationale for the Proposed BAT

1. FGD Wastewater

2. BA Transport Water

3. Rationale for Voluntary Incentives Program (VIP)

C. Additional Proposed Subcategories

1. Subcategory for Facilities With High FGD Flows

2. Subcategory for Boilers With Low Utilization

3. Subcategory for Boilers Retiring by 2028

D. Availability Timing of New Requirements

E. Regulatory Sub-Options To Address Bromides

F. Economic Achievability

G. Non-Water Quality Environmental Impacts

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

I. Additional Rationale for the Proposed PSES

VIII. Costs, Economic Achievability, and Other Economic Impacts

A. Facility-Specific and Industry Total Costs

B. Social Costs

C. Economic Impacts

1. Screening-Level Assessment

a. Facility-Level Cost-to-Revenue Analysis

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

2. Electricity Market Impacts

a. Impacts on Existing Steam Electric Facilities

b. Impacts on Individual Facilities Incurring Costs

IX. Changes to Pollutant Loadings

A. FGD Wastewater

B. BA Transport Water

C. Summary of Incremental Changes of Pollutant Loadings From Proposed Regulatory Options

X. Non-Water Quality Environmental Impacts

A. Energy Requirements

B. Air Pollution

C. Solid Waste Generation and Beneficial Use

D. Changes in Water Use

XI. Environmental Assessment

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 Benefits From Changes in Surface Water Quality

2. Changes in Surface Water Quality

3. Effects on Threatened and Endangered Species

4. Changes in Benefits From Marketing of Coal Combustion Residuals

5. Changes in Dredging Costs

6. Changes in Air-Related Effects

7. Benefits From 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

2. Implementation for the Low Utilization Subcategory

a. Determining Boiler Net Generation

b. Tiering Limitations

3. Addressing Withdrawn or Delayed Retirement

a. Involuntary Retirement Delays

b. 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 facilities are impacted 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 where “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 flue gas desulfurization (FGD) wastewater, fly ash transport water, bottom ash transport water, flue gas mercury control wastewater, gasification wastewater, combustion residual leachate, and non-chemical metal cleaning wastes.

In the few years since the steam electric ELGs were revised in 2015, steam electric facilities have installed more affordable technologies which are capable of removing a similar amount of pollution as those which existed in 2015. This proposal would revise requirements for two of the waste streams addressed in the 2015 rule: Bottom ash (BA) transport water and flue gas desulfurization (FGD) wastewater—two of the facilities' largest sources of wastewater—while reducing industry costs as compared to the costs of the 2015 rule's controls. This proposal does not seek to revise the other waste streams covered by the 2015 rule.

B. Summary of Proposed Rule

For existing sources that discharge directly to surface water, with the exception of the subcategories discussed below, the proposed rule would establish the following effluent limitations based on Best Available Technology Economically Achievable (BAT):

• For flue gas desulfurization wastewater, there are two sets of proposed BAT limitations. The first set of limitations is a numeric effluent limitation on Total Suspended Solids (TSS) in the discharge of FGD wastewater. The second set of BAT limitations comprises numeric effluent limitations on mercury, arsenic, selenium, and nitrate/nitrite as nitrogen in the discharge of FGD wastewater.

• For bottom ash transport water, there are two sets of proposed BAT limitations. The first set of BAT limitations is a numeric effluent limitation on TSS in the discharge of these wastewaters. The second set of BAT limitations is a not-too-exceed 10 percent volumetric purge limitation.

The proposed rule includes separate requirements for the following subcategories: High flow facilities, low utilization boilers, and boilers retiring by 2028. The proposed rule does not seek to change the existing subcategories for oil-fired boilers and small generating units (50 MW or less) from the 2015 rule. For high flow facilities (FGD wastewater flows over four million gallons per day after accounting for that facility's ability to recycle the wastewater to the maximum limits for the FGD system materials of construction) or low utilization boilers (876,000 MWh per year or less), the proposed rule would establish the second set of BAT limitations in the discharge of FGD wastewater as numeric effluent limitations only on mercury and arsenic (and not on selenium and nitrate/nitrite as nitrogen). For low utilization boilers, the proposed rule would establish BAT limitations for BA transport water for TSS, and would also include standards for implementation of a best management practices (BMP) plan. For oil-fired boilers, small boilers (50 MW or less), and boilers retiring by 2028, the proposed rule would establish BAT limitations for TSS in FGD wastewater and bottom ash transport water.

The proposed rule would establish a voluntary incentives program that provides the certainty of more time (until December 31, 2028) for facilities to implement 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 total dissolved solids in FGD wastewater. The optional program offers environmental protections beyond those achieved by the proposed BAT limitations, while providing facilities that opt into the program more flexibility (such as additional time) than the current voluntary incentives program.

For indirect discharges (

i.e.,

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

Where BAT limitations in this rule are more stringent than previously established BPT limitations, the EPA proposes that those limitations do not apply until a date determined by the permitting authority that is as soon as possible on or after November 1, 2020, but that is no later than December 31, 2023 (for BA transport water) or December 31, 2025 (for FGD wastewater).

C. Summary of Costs and Benefits

The EPA has estimated costs and benefits of four different regulatory options. The EPA estimates that its proposed option (

i.e.,

Option 2) will save $136.3 million per year in social costs and result in between $14.8 million and $68.5 million in benefits, using a three percent discount, and will save $166.2 million per year in social costs and between $28.4 million and $74.4 million in benefits, using a seven percent discount. Table XV-1 summarizes the benefits and social costs for the four regulatory options at a three percent discount rates. The EPA's analysis reflects the Agency's understanding of the actions steam electric facilities will take to meet the limitations and standards in the final rule. The EPA based its analysis on a baseline that reflects the expected impacts of announced retirements and fuel conversions, impacts of relevant rules such as the Coal Combustion Residuals (CCR) rule that the Agency promulgated in April 2015 and the Affordable Clean Energy Rule (ACE) that the Agency promulgated in 2019, and the full implementation of the 2015 rule. The EPA understands that these modeled results have uncertainty and that the actual costs 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 Participation

Submit your comments, identified by Docket ID No. EPA-HQ-OW-2009-0819, at

https://www.regulations.gov

(our preferred method), or the other methods identified in the

ADDRESSES

section. Once submitted, comments cannot be edited or removed from the docket. The EPA may publish any comment received to its public docket. Do not submit electronically any information you consider to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Multimedia submissions (audio, video, etc.) must be accompanied by a written comment. The written comment is considered the official comment and should include discussion of all points you wish to make. The EPA will generally not consider comments or comment contents located outside of the primary submission (

i.e.,

on the web, cloud, or other file sharing system). For additional submission methods, the full EPA public comment policy, information about CBI or multimedia submissions, and general guidance on making effective comments, please visit

https://www.epa.gov/dockets/commenting-epa-dockets.

III. General Information

A. Does this action apply to me?

Entities potentially regulated by any final rule following this action 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 Impacting the Steam Electric Sector

1. Clean Power Plan (CPP) and Affordable Clean Energy (ACE)

The final 2015 CPP established carbon dioxide (CO

) emission guidelines for fossil-fuel fired facilities based in part on shifting generation at the fleet-wide level from one type of energy source to another. On February 9, 2016, the U.S. Supreme Court stayed implementation of the CPP pending judicial review.

West Virginia

EPA,

No. 15A773 (S.Ct. Feb. 9, 2016).

On June 19, 2019, the EPA issued the ACE rule, an effort to provide existing coal-fired electric utility generating units (EGUs) with achievable and realistic standards for reducing greenhouse gas emissions. This action was finalized in conjunction with two related, but separate and distinct rulemakings: (1) The repeal of the CPP, and (2) revised implementing regulations for ACE, ongoing emission guidelines, and all future emission guidelines for existing sources issued under the authority of Clean Air Act section 111(d). ACE provides states with new emission guidelines that will inform the state's development of standards of performance to reduce CO

emissions from existing coal-fired EGUs consistent with the EPA's role as defined in the CAA.

ACE establishes heat rate improvement (HRI), or efficiency improvement, as the best system of emissions reduction (BSER) for CO

from coal-fired EGUs.

By employing a broad range of HRI technologies and techniques, EGUs can more efficiently generate electricity with less carbon intensity.

The BSER is the best technology or other measure that has been adequately demonstrated to improve emissions performance for a specific industry or process (a “source category”). In determining the BSER, the EPA considers technical feasibility, cost, non-air quality health and environmental impacts, and energy requirements. The BSER must be applicable to, at, and on the premises of an affected facility. ACE lists six HRI “candidate technologies,” as well as additional operating and maintenance (O&M) practices.

For each candidate technology, the EPA has provided information regarding the degree of emission limitation achievable through application of the BSER as ranges of expected improvement and costs.

Heat rate is a measure of the amount of energy required to generate a unit of electricity.

An improvement to heat rate results in a reduction in the emission rate of an EGU (in terms of CO

emissions per unit of electricity produced).

These six technologies are: (1) Neural Network/Intelligent Sootblowers, (2) Boiler Feed Pumps, (3) Air Heater and Duct Leakage Control, (4) Variable Frequency Drives, (5) Blade Path Upgrade (Steam Turbine), and (6) Redesign/Replace Economizer.

The 2015 rule analyses incorporated compliance costs associated with the 2015 CPP, resulting in, among other things, baseline retirements associated with that rule in the Integrated Planning Model (IPM). As noted in the ACE RIA, while the final repeal of the CPP has been promulgated, the business-as-usual economic conditions achieved the carbon reductions laid out in the final CPP. The EPA used the IPM version 6 to analyze today's proposal to be consistent with the base case analyses done for the ACE final rule. The Agency also performed a sensitivity analysis on the proposed Option 2, following promulgation of the ACE final rule, that estimates the impacts of the proposed option relative to a baseline that includes the ACE rule. A similar sensitivity analysis was not conducted for Option 4. The EPA intends to perform IPM runs with the most up-to-date version of the model available for the final rule.

See

additional discussion of IPM in Section VIII of this preamble.

2. Coal Combustion Residuals (CCR)

On April 17, 2015, the Agency published the Disposal of Coal Combustion Residuals from Electric Utilities final rule. This rule finalized national regulations to provide a comprehensive set of requirements for the safe disposal of CCRs, commonly known as coal ash, from coal-fired facilities. The final 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 ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface

impoundments. Additionally, the CCR rule set out recordkeeping and reporting requirements as well as the requirement for each facility to establish and post specific information to a publicly-accessible website. This final CCR rule also supported the responsible recycling of CCRs by distinguishing safe, beneficial use from disposal.

As explained in the 2015 rule, the ELGs and CCR rules may affect the same boiler or activity at a facility. That being the case, when the EPA finalized both rules in 2015, the Agency coordinated them to facilitate and minimize the complexity of implementing engineering, financial, and permitting activities. The coordination of the two rules continues to be a consideration in the development of today's proposal. The EPA's analysis of this proposal incorporates the same approach used in the 2015 rule to estimate how the CCR rule may affect surface impoundments and the ash handling systems and FGD treatment systems that send wastes to those impoundments. However, 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), amendments to the CCR rule are being proposed which would establish a deadline of August 2020 by which all unlined surface impoundments

must cease receiving waste, subject to certain exceptions. This would not impact the ability of facilities to install new, composite lined surface impoundments. This CCR proposal and accompanying background documents are available at

www.regulations.gov

Docket EPA-HQ-OLEM-2019-0172, and comments on that proposal should be submitted to that docket.

Due to the Court vacatur of 40 CFR part 257.71(a)(1)(i) (provision for clay-lined surface impoundments) clay-lined surface impoundments are currently also considered unlined.

In order to account for the CCR rule proposed amendments in this proposed rule, the EPA conducted a sensitivity analysis to determine how the closure of unlined surfaced impoundments would impact the compliance cost and pollutant loading estimates for today's proposal. After conducting this sensitivity analysis, the EPA found that the capital and operation and maintenance compliance cost estimates decrease by 50 to 60 percent and the total industry pollutant loadings decrease by five percent (

see

DCN SE07233).

The EPA solicits comment on the overlap between these two rules, including whether the Agency's cost benefit and regulatory impact analyses appropriately capture the overlap of the two rules, and ways that the Agency could harmonize the timelines for regulatory requirements. The Agency also solicits comment on the extent to which facilities have chosen to construct new composite lined surface impoundments for the treatment of bottom ash transport water or FGD wastewater. Comments on the intersection of the two rules should be submitted to both dockets.

F. Scope of This Proposed Rulemaking

This proposal, if finalized, would revise the new, more stringent BAT effluent limitations guidelines and pretreatment standards for existing sources in the 2015 rule that apply to FGD wastewater and BA transport water. It does not propose otherwise to amend (nor is the EPA requesting comment on) the effluent limitations guidelines and standards for other wastes discharged by the steam electric power generating point source category. The EPA plans to address the Court's remand in

Southwestern Elec. Power Co.

EPA

with respect to the limitations for leachate and legacy wastewater in a subsequent action.

V. Steam Electric Power Generating Industry Description

A. General Description of Industry

The EPA provided a general description of the steam electric power generating industry in the 2013 proposed rule and the 2015 rule, and has continued to collect information and update that profile. The previous descriptions reflected the known information about the universe of steam electric facilities and incorporated applicable final environmental regulations at that time. For this proposal, as described in the Supplemental TDD Section 3, the 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 this proposal use an updated baseline that incorporates these changes in the industry. The analyses then compare the effect of today's proposed rules for FGD wastewater and bottom ash transport water to the effect of the 2015 rule's limitations for FGD wastewater and BA transport water on the industry as it exists today.

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

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 inexpensive natural gas, emergence of alternative fuel technologies, and continued aging of coal-fired facilities. These changes have resulted in coal-fired unit and facility 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 proposal, if finalized, would have no effect on the nuclear-powered sector, except as it might affect relative prices through its impacts on coal-fired generation.) In the coal-fired sector, the market forces are manifest as scaling back coal-fired power generation (including unit and facility closures) at an accelerated rate. The rate of coal capacity retirement is affected by regulation affecting coal-fired electricity generation as there have been regulations adopted, particularly in the last decade (

e.g.,

CCR, CPP and 2015 Steam Electric ELG), that are cited by some power companies when they announce unit or facility closures, fuel switching, or other operational changes. Among some utilities, there is also a general trend of supplementing or replacing traditional generation with alternative sources. As these changes happen in the industry, the electric power infrastructure adjusts and generally trends toward the optimal infrastructure and operations that deliver the country's power demand, with negative effects for some communities and positive effects for others. The negative distributional effects can be particularly difficult for communities affected by company decisions to scale back or retire a facility. 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 facilities with additional ways of meeting effluent limitations, in some instances at a lower cost. For this proposal, the EPA incorporated updated information and evaluated several technologies available to control and treat FGD wastewater and BA transport water produced by the steam electric

power generating industry.

See

Section VIII of this preamble for details on updated cost information.

1. FGD Wastewater

FGD scrubber systems, either dry or wet, are used to remove sulfur dioxide from flue gas so that sulfur dioxide is not emitted into the air. Dry FGD systems generally do not discharge wastewater, as the water they use is evaporated during operation; wet FGD systems do produce a wastewater stream.

As part of this proposed rule, the EPA is including two additional FGD wastewater treatment technologies among the suite of regulatory options that were not evaluated as main regulatory options 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 proposal as HRTR—high residence time biological reduction). The LRTR system is designed to operate with a shorter residence time (on the order of 1 to 4 hours, as compared to a residence time of 10-16 hours for HRTR), while still achieving significant removal of selenium and nitrate/nitrite. The LRTR technology option considered as part of this proposed rule includes chemical precipitation as a pretreatment stage prior to the bioreactor and ultrafiltration as a polishing step following the bioreactor.

• Membrane Filtration. A membrane filtration system designed specifically for high TDS and TSS wastestreams. These systems are designed to eliminate fouling and scaling associated with industrial wastewater. These systems typically combine 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 array 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.

Steam electric facilities discharging FGD wastewater currently employ a variety of wastewater treatment technologies and operating/management practices to reduce the pollutants associated with FGD wastewater discharges. As part of the 2015 rule, the 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. The EPA identified three types of biological treatment systems used to treat FGD wastewater: (1) Anoxic/anaerobic fixed-film bioreactors, which target removals of nitrogen compounds and selenium, as well as other metals; (2) anoxic/anaerobic suspended growth systems, which target removals of selenium and other metals; and (3) aerobic/anaerobic sequencing batch reactors, which target removals of 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 typical hydraulic residence time on the order 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, to 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 that produces a solid residue for landfill disposal and additional distillate that can be reused within the facility 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 involving wetland vegetation, soils, and microbial activity to reduce the concentrations of metals, nutrients, and TSS in wastewater. High temperature, chemical oxygen demand (COD), nitrates, sulfates, boron, and chlorides in the wastewater can adversely affect constructed wetlands' performance. To avoid this, facilities typically find it necessary to dilute the FGD wastewater with service water before it enters the wetland.

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

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

e.g.,

wallboard-grade gypsum). Because the facilities 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 facilities 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 facilities is greater than or equal to the flow rate of the FGD wastewater and amount of precipitation entering the impoundments; therefore, there is no discharge to surface water.

—Fly ash (FA) conditioning. Many facilities 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. The 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.

The 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 fullscale or pilotscale, 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 facilities 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 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. These systems use the same processes as wet-sluicing impoundment or dewatering bin systems to transport bottom ash to a remote mechanical drag system. 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 this proposed rule, under the high recycle rate option, facilities 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.

In some cases, additional treatment may be necessary to maintain a closed-loop system. This additional treatment could include polymer addition 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 facility 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 this reconsideration, the EPA identified the following BA handling systems that do not generate bottom ash transport water.

• Mechanical Drag System. These systems are located directly underneath the boiler. 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 are located directly underneath the boiler. The system uses ambient air to cool the bottom ash in the boiler and then transports the ash out of the boiler on a conveyor. No water is used in this process.

• Dry Vacuum or Pressure System. These systems transport bottom ash from the boiler 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.

• Submerged Grind Conveyor. These systems are located directly underneath the boiler 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 transport and dewater the bottom ash.

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, the EPA conducted seven site visits to facilities in five states. The EPA selected facilities to visit using information gathered in support of the 2015 rule, information from industry outreach, and publicly available facility-specific information. The EPA visited four facilities that were previously visited in support of the 2015 rule because they had recently conducted, or were currently conducting, FGD wastewater treatment pilot studies. The EPA also revisited facilities 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.

The specific objectives of these site visits were to gather general information about each facility's operations; their pollution prevention and wastewater treatment system operations; their ongoing pilot or laboratory scale studies for 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, the EPA requested the following 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 halogen concentration data 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.

After receiving each company's response, the EPA met with these companies to discuss the FGD-related data 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. The EPA used this information to learn more about the performance of treatment systems, inform the development of FGD wastewater limitations, learn more about facility-specific halogen usage (such as bromide), and obtain information useful for updating cost estimates of installing candidate treatment technologies. As needed, the 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, the EPA invited seven steam electric facilities 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. The EPA asked facilities to provide analytical data for

ash pond effluent and untreated BA transport water (

i.e.,

ash pond influent). The EPA selected the facilities 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 facilities 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 remove pollutants from wastestreams or eliminate wastestreams using zero discharge technologies. Following the 2015 rule, the EPA reviewed 35 reports published between 2011 and 2018 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. The 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, the 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. The EPA also met with the Utility Water Act Group (UWAG), an association comprising the trade associations above as well as individual electric utilities. The EPA met with each of these trade associations separately and together to discuss the technologies and the analyses presented in the 2015 rule and to hear suggestions for potential changes to the 2015 rule. The EPA also used information from these meetings to update industry profile data (

i.e.,

accounting for retirements, fuel conversions, and updated treatment technology installations).

B. Information From the Drinking Water Utility Industry and States

The EPA obtained additional information from the drinking water utility sector and states on the effects of bromide discharges from steam electric facilities on drinking water treatment processes. First, the 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, the EPA visited two drinking water treatment facilities 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 facility. Finally, the EPA obtained data on surface water bromide concentrations and data from drinking water monitoring from the two drinking water treatment facilities. The EPA also obtained existing state data from other drinking water treatment facilities from the states of North Carolina and Virginia.

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

The 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

The EPA gathered information on steam electric generating facilities 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). The EPA used the 2015 through 2017 data to update the industry profile prepared for the 2015 rule, including commissioning dates, energy sources, capacity, net generation, operating statuses, planned retirement dates, ownership, and pollution controls of the boilers.

The 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. The EPA also used the internet searches to identify or confirm reports of planned facility and boiler retirements, and reports of planned unit conversions to dry or closed-loop recycle ash handling systems. The EPA used this information to inform the industry profile and identify process modifications occurring in the industry.

The EPA received information from several environmental groups and other stakeholders following the 2015 rule. In general, these groups voiced concerns about extending the period that facilities could continue to discharge FGD wastewater and BA transport water pollutants subject to BPT limitations, as well as steam electric bromide discharges, their interaction with drinking water treatment facilities, and the associated human health effects. They also noted the improved availability of technological controls for reducing or eliminating pollutant discharges from FGD and BA handling systems. Finally, they provided examples where they believed that states had not properly considered the “as soon as possible date” for the new, more stringent BAT requirements in the 2015 rule when issuing permits.

VII. Proposed Regulation

A. Description of the BAT/PSES Options

The proposal evaluates four regulatory options and identifies one proposed option, as shown in Table VII-1. All options include similar technology bases for BA transport water, except that Option 2 allows surface impoundments and a BMP plan for low utilization boilers. In general, each successive option from Option 1 to 4 would achieve a greater reduction in FGD wastewater pollutant discharges. Each subcategorization is described further in Section VII.C below. In addition to some specific requests for comment included throughout this proposal, the EPA solicits comment on all aspects of this proposal, including the information, data and assumptions EPA relied upon to develop the proposed regulatory options, as well as the proposed BAT, effluent limitations, and alternate approaches included in this proposal.

Table VII-1—Main Regulatory Options

Wastestream

Subcategory

Technology basis for the BAT/PSES

regulatory options

FGD Wastewater

N/A

Chemical precipitation

Chemical precipitation + low hydraulic residence time biological treatment

Membrane filtration.

High FGD flow facilities

Chemical precipitation

Chemical precipitation.

Low utilization boilers

Chemical precipitation

NS.

Boilers retiring by 2028

Surface impoundments

Surface impoundments.

FGD Wastewater Voluntary Incentives Program (Direct Dischargers Only)

Membrane filtration

N/A.

BA Transport Water

N/A

Dry handling or High recycle rate systems

Dry handling or High recycle rate systems.

Low utilization boilers

Surface impoundments +BMP plan

NS.

Boilers retiring by 2028

Surface impoundments

Surface impoundments.

NS = Not Subcategorized.

Note:

The table above does not present existing subcategories included in the 2015 rule as the EPA is not proposing any changes to the existing subcategorization of oil-fired units or units with a nameplate capacity of 50 MW or less.

1. FGD Wastewater

Under Option 1, the EPA would establish BAT limitations and PSES for mercury and arsenic based on chemical precipitation. For Options 2 and 3, the EPA would establish BAT limitations and PSES for mercury, arsenic, selenium, and nitrate/nitrate based on chemical precipitation followed by LRTR and ultrafiltration. Option 2 subcategorizes boilers producing less than 876,000 MWh per year

and for those boilers would require mercury and arsenic limitations and pretreatment standards based on chemical precipitation.

Finally, for Option 4, the EPA would establish BAT limitations and PSES for mercury, arsenic, selenium, nitrate-nitrite, bromide, and TDS based on membrane filtration. Options 2, 3, and 4 would subcategorize facilities with high FGD flows, and for this subcategory would establish limitations and standards for mercury and arsenic based on chemical precipitation. Under all four options, boilers retiring by December 31, 2028, would be subcategorized, and for this subcategory BAT limitations would be set equal to BPT limitations for TSS based on the use of surface impoundments. Finally, the EPA would establish voluntary incentives program limitations for mercury, arsenic, selenium, nitrate-nitrite, bromide, and TDS based on membranes.

The equivalent of a 100 MW boiler operating at 100% capacity or a 400 MW boiler operating at 25% capacity.

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

2. BA Transport Water

Under all options described above, the EPA proposes to control 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 operated such that it periodically discharges (purges) a small portion of the process wastewater from the system. Under all options, boilers retiring by December 31, 2028, would be subcategorized, and for this subcategory, BAT limitations would be set equal to BPT limitations for TSS, based on gravity settling in surface impoundments. Under Option 2, for boilers producing less than 876,000 MWh per year, BAT effluent limitations for BA transport water would be set equal to the BPT effluent limitations based on gravity settling in surface impoundments to remove TSS.

Such facilities 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 analysis,

see

Section VII(C) of the 2015 rule preamble. Finally, the EPA proposes a slight modification of the definition of BA transport water to exclude water remaining in a tank-based high recycle rate system at the end of the useful life of the facility.

The EPA proposes not to characterize a technology basis for BAT/PSES applicable to such wastewater at this time.

Although TSS is a conventional pollutant, as it did in the 2015 rule, whenever EPA would be regulating TSS in any final rule following this proposal, it would be regulating it as an indicator pollutant for the particulate form of toxic metals.

Under this modified definition, the water at the end of the useful life of the facility would be at most the volume of a full system. Since the high recycle rate system being selected as BAT allows for a 10 percent purge of the system volume each day, this would be the equivalent of 10 days discharge, a marginal, one-time increase in pollution.

As illustrated above, there is a wide range of technologies currently in use for pollutant discharges associated with BA transport water, and new approaches continue to emerge. For the exclusion proposed today, permitting authorities would establish BAT limitations for such discharges on a site-specific, best professional judgement (BPJ) basis. 33 U.S.C. 1342 (a)(1)(B); 40 CFR 124.3. Pretreatment program control authorities would need to develop local limitations to address the introduction of pollutants from this wastewater to POTWs that cause pass through or interference, as specified in 40 CFR 403.5(c)(2).

B. Rationale for the Proposed 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), the EPA proposes to

establish BAT effluent limitations based on the technologies described in Option 2.

1. FGD Wastewater

This proposal 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 because after considering the factors specified in CWA section 304(b)(2)(B), the EPA proposes to find that this technology is available and economically achievable. More specifically, the technology basis for BAT would include the same chemical precipitation system described in the 2015 rule. Thus, it would employ equalization, hydroxide and sulfide (organosulfide) precipitation, iron coprecipitation, and removal of suspended and precipitated solids. This chemical precipitation system would be 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 would be followed by an ultrafilter to remove suspended solids exiting the bioreactor, including colloidal particles.

Similar to the 2015 rule and consistent with discussions with engineering firms and facility staff, EPA assumed that in order to meet the limitations and standards, facilities 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 of the Supplemental TDD.

Both chemical precipitation and biological treatment are well-demonstrated technologies that are available to steam electric facilities for use in treating FGD wastewater. In addition to the 39 facilities mentioned as using chemical precipitation in the 2015 rule preamble, facilities have installed, or begun installation of such systems, because they have taken steps to cease using surface impoundments to treat their FGD wastewater. In addition, chemical precipitation has been used at thousands of industrial facilities nationwide for the last several decades as described in the 2015 rule record. Ultrafilters downstream of the biological treatment stage are designed for the removal of suspended solids exiting the bioreactor, such as any reduced, insoluble selenium, mercury, and other particulates. 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 technology (

i.e.,

nanofiltration or reverse osmosis) that is the basis for option 4 and the VIP which is designed to remove dissolved metals and inorganics (

e.g.,

nutrients, bromides, etc.). Unlike the nanofiltration and reverse osmosis technologies, ultrafilters do not generate a brine that would require encapsulation with fly ash or other disposal techniques. The types and amount of solids removed by the ultrafilter in the CP+LRTR treatment system are identical to the solids removed by the sand filter in the CP+HRTR treatment technology and do not result in the same non-water quality environmental impacts that are associated with the brine generated by the membrane technology of Option 4 and proposed for the VIP program.

After accounting for the changes in the industry described in Section V of this preamble, fifteen steam electric facilities with wet scrubbers have technologies in place able to meet the proposed BAT effluent limitations for FGD wastewater.

Of these fifteen facilities, nine 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.

The EPA identified a tenth facility that previously operated an anoxic/anaerobic biological treatment system; however, more recently installed a thermal system for the treatment of FGD wastewater. Another five steam electric facilities are also operating thermal treatment systems for FGD wastewater.

These fifteen facilities represent 11 percent of steam electric facilities with wet scrubbers. The EPA notes that a further 40 percent of all steam electric facilities with wet scrubbers use FGD wastewater management approaches that eliminate the discharge of FGD wastewater altogether. But, although these technologies (which are described above in Section V.C.1) may be available for some facilities, none of them are available nationwide, and thus do not form the basis for the proposed BAT. For example, evaporation ponds are only available in certain climates. Similarly, complete recycle FGD systems are only available at facilities with appropriate FGD metallurgy. Facility conditions and availability of these technologies have not materially changed since the 2015 rule, and the EPA thus reaffirms that these technologies are not individually available nationwide and are not a basis for the proposed BAT.

In addition to these nine facilities, some facilities employ other types of biological treatment. Some of these systems are sequencing batch reactors (SBR), which treat nitrogen, and that technology can be operated to remove selenium. The SBR systems currently operating at power facilities, however, would likely not be able to meet the limitations discussed in today's proposal without reconfiguration.

In the 2015 rule, the EPA rejected three availability arguments made against biological treatment generally. The EPA is not proposing to change these findings based on record information received since the 2015 rule but solicits comment on whether, and to what extent, these findings should be retained for the final rule. First, the EPA rejected the argument that maintaining a biological system over the long run was infeasible. Of the ten full-scale systems discussed above, four facilities have used the biological technology to treat FGD wastewater for more than a decade under varying operating conditions, climate conditions, and coal sources. Many pilot tests of the biological technology have been conducted at various facilities, and data from these tests demonstrate that even in the face of major upsets within the chemical precipitation stage of treatment, the biological stage continues to reduce selenium and nitrogen.

In the 2015 rule, the EPA also rejected the argument that selenium removal efficacy was subject to the type of coal burned (specifically subbituminous coal) and coal-switching. Facilities have continued to operate biological treatment systems while switching coals and, in those cases, have maintained a consistent level of selenium removal. Furthermore, at least three pilot and two full-scale systems have now been successfully run or installed to treat FGD wastewater at facilities burning sub-bituminous coals or blends of bituminous and sub-bituminous coals, encompassing both HRTR and LRTR technologies.

Finally, in the 2015 rule the EPA rejected arguments that cycling of facilities up and down in production, and even out of service for various periods of time, would affect the ability of facilities to meet the effluent limitations. Industry provided data for two facilities 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 HRTR and LRTR technologies, the EPA proposes to establish BAT based on the LRTR technologies. LRTR reductions are comparable to HRTR reductions,

are less costly, and require significantly less process or facility footprint modifications than the HRTR option. As explained in Section XIII of this preamble, the long-term averages forming the basis of the selenium limitations for LRTR and HRTR are similar, and the higher selenium

limitations for the LRTR systems are largely driven by increased short-term variability around that average, rather than a meaningful difference in long-term pollutant removals.

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

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 [. . .]”).

LRTR is less costly than HRTR. Compared to the baseline of the 2015 rule, LRTR is estimated to save approximately $72 million per year in after-tax costs to industry.

LRTR requires fewer process changes than HRTR. Compared to HRTR, LRTR installations are less complex and require fewer modifications to a facility's footprint. The HRTR systems selected 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, requiring little more than a concrete foundation, electricity supply, and piping connections.

The EPA is not proposing to establish BAT limitations or PSES based on chemical precipitation alone (Option 1). As the EPA noted during the development of the 2015 rule, chemical precipitation is effective at removing mercury, arsenic, and certain other heavy metals. While basing BAT limitations and PSES on this technology alone could save industry $103 million per year in after-tax costs relative to the 2015 rule, this technology alone does not remove nitrogen, nor does it remove the majority of selenium. Furthermore, the data in the EPA's 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, the EPA proposes chemical precipitation followed by LRTR for BAT.

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

The EPA is not proposing to establish BAT limitations based on membrane filtration (Option 4). Based on the EPA's record, the EPA could not conclude that membrane filtration is technologically available nationwide at this time, as the term is used in the CWA, but may become “available” on a nationwide basis by 2028 (this is reflected in the date of compliance for the VIP program under Options 2 and 3). Furthermore, membrane filtration entails non-water-quality environmental impacts (associated with management of the brine) that the EPA proposes to find unacceptable.

At the time of the 2015 rule, the EPA had no record of information about membrane filtration technologies being used to treat FGD wastewater. Since that time, the 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 requiring further treatment or disposal. Microfiltration and ultrafiltration generate a solid waste residual which is disposed. Similarly, nanofiltration, reverse osmosis, forward osmosis, and EDR all produce a concentrated brine residual which must be disposed.

The EPA's current record includes information on seven pilot studies of FGD wastewater treatment at domestic facilities using four different membrane filtration technologies.

All of these technologies first employed some form of suspended solids removal such as microfiltration or chemical precipitation. This pretreated FGD wastewater was then fed into either nanofiltration or reverse osmosis 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 EPA has also learned of an eighth pilot on an EDR system, but no data have yet been provided (

https://www.filtsep.com/water-and-wastewater/news/saltworks-completes-fgd-pilot-in-us/

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

The EPA is not aware of any domestic facilities which have to date installed nanofiltration or reverse osmosis membrane filtration systems to remove dissolved pollutants in FGD wastewater, although EPA is aware of three facilities in China which have installed such membrane filtration systems.

The record contains limited information about these facilities. Two of the facilities employ pretreatment and a combination of reverse osmosis and forward osmosis. The EPA does not have detailed information about the specific configurations or the long-term performance of these two systems, nor is the EPA aware of how the resultant brine is being disposed.

Furthermore, the company that sold these two systems has since ceased commercial operations.

The third facility operating in China employs pretreatment followed by nanofiltration and reverse osmosis. At this facility, the brine is crystallized and the resulting salt is sold for industrial uses. The EPA does not have information on the long-term performance of this system.

Ultrafiltration has been installed as part of FGD wastewater treatment systems in the U.S.; however, these membranes are intended to remove suspended solids, not dissolved pollutants.

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.

The following story summarizes the forward osmosis company Oasys ceasing commercial operations:

https://www.bluetechresearch.com/news-blog/comment-oasys-hits-funding-drought/

While the EPA does have some information about the use of membrane filtration on FGD wastewater from pilot studies, uncertainty remains regarding operation of the suite of membrane filtration technologies evaluated by the EPA as the basis for Option 4. With respect to data from the pilot studies, these studies focused on membrane technologies that would remove dissolved pollutants. For the technologies designed to remove dissolved pollutants, several studies 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 they would install and 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. In both cases, this prevented the 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 the 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. However, the EPA 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 facilities using a single vendor's reverse osmosis technology.

These three data sets served as the basis of the proposed revisions to the 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 FGD wastewater. The EPA anticipates that additional pilots, tests and data collection could result in these technologies becoming available by the VIP compliance date of 2028. By contrast and for the reasons explained in section VII.2.B., the EPA proposes to conclude that ultrafiltration technology is available for use in the polishing stage for systems using LRTR biological systems as the primary treatment technology for FGD wastewater.

In addition, while the EPA does have information about membrane filtration application to FGD wastewater from bids and engineering documents, those sources express concerns about operating a technology on this wastewater that would be the first of its kind in the U.S. With respect to information from bids for full-scale installations and related documents, the EPA obtained copies of bids that represented a single vendor's reverse osmosis-based technology and that incorporated performance guarantees. Such guarantees, which are standard within the steam electric power generating industry, act to transfer the costs of specific performance issues from the purchaser of the equipment to the vendor. While the willingness of this vendor to take on these risks might suggest confidence in the long-term performance of its technology, third-party EPC firms with no vested interest in the technology are hesitant to recommend that a client be the first site in the U.S. to adopt membrane filtration for the treatment of FGD wastewater because of uncertainty related to system performance and the ability to operate successfully without frequent, if not excessive, chemical cleaning. This further supports EPA's proposal to find, at this time, that membrane filtration is not, technologically available or an appropriate basis for mandatory requirements for the entire industry. The EPA solicits comment on this availability finding, and whether membrane filtration may become nationally available sooner or later than 2028.

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

While there are several alternative ways to treat or dispose of the brine generated by membrane filtration, the method most likely to be employed (based on bids, engineering documents, and discussions with electric utilities) is encapsulation with FA and lime for disposal of the resulting solid in a landfill.

While the 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.

Bids also indicate that this would be the least-cost brine management alternative.

Landfilling an encapsulated material raises challenges. For instance, comingling might result in a leachate blowout. The King County Landfill in Virginia experienced a leachate blow out 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 CCRs 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.

Moreover, instead of disposing of their FA, facilities 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).

According to 2016 EIA data, the median percent of FA sold for beneficial use by the facilities with wet FGD systems is approximately fifty percent, with a range of zero to one hundred percent. The fact that encapsulation with FA and lime is the most likely, and least cost, brine management method that facilities could employ nationally, combined with the high percent of FA currently being beneficially used, indicates that selection of membrane filtration as BAT could discourage environmentally preferable beneficial uses of FA, such as replacement of Portland cement in concrete.

Specifically, the Agency estimated in U.S. EPA (2011) that each ton of fly ash used as a substitute for Portland cement would avoid 5,400 megajoules of nonrenewable energy use, 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, the EPA proposes to find that discouraging this beneficial use of FA would result in unacceptable non-water-quality environmental impacts.

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

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.

Finally, while the EPA views the foregoing reasoning as sufficient to find that membrane filtration is not BAT for all existing sources, the EPA notes that membrane filtration is projected to cost industry more than the proposed BAT option for FGD wastewater,

i.e.,

chemical precipitation plus LRTR. Added to these costs are the costs to facilities of disposing of the resulting brine. Some facilities that otherwise sell their FA may choose to use their FA to encapsulate the brine, thereby foregoing revenue from FA sales. Other facilities that choose to continue to sell their FA must dispose of the brine using another disposal alternative, such as crystallization, at an additional cost. Costs are a separate statutory factor that the 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, the additional costs associated with membrane filtration provide additional support for the EPA's proposal that membrane filtration is not BAT for all existing sources.

Although the EPA is proposing to reject membranes as the national technology basis for BAT, the EPA proposes to establish a VIP based on membrane technology, as discussed later in this section. The EPA solicits comment on this conclusion. Furthermore, the EPA solicits comment on whether there are early adopters who have already contracted for, purchased, or installed biological technology for compliance with the 2015 rule, and whether these facilities should be included as a subcategory not subject to the final BAT of Option 4, if finalized. The EPA solicits comment on whether such a subcategory could be based on the age of the new pollution control equipment that had not yet lived out its useful life, the disparate costs of purchasing two sets of equipment, or other statutory factors.

As described further below, the EPA is also not proposing to establish BAT limitations based on other technologies also evaluated in the 2015 rule.

First, except for the end of life boiler and low-utilization subcategories discussed below, the EPA is not proposing to establish BAT limitations based on surface impoundments. Surface impoundments are not as effective at controlling pollutants like dissolved metals and nutrients as available and achievable technologies like CP and LRTR. EPA drew a similar conclusion in the 2015 rule, and nothing in the record developed by the Agency since the 2015 rule would change this determination.

Second, the EPA is not proposing to establish BAT limitations based on thermal technologies, such as chemical precipitation (including softening) followed by a falling film evaporator, on the basis of high costs to industry. In the 2015 rule, the EPA rejected this technology as a basis for BAT limitations due to high costs to industry. Since the 2015 rule, the EPA has collected additional information on full-scale installations and pilots of thermal technologies to treat FGD wastewater. The EPA's record includes information about approximately 10 pilot studies conducted in the U.S., providing performance data for five different thermal technologies. In addition, full scale installations are operating at six facilities,

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

While 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 less costly than estimated for the 2015 rule, the thermal costs evaluated in the EPA's memorandum

FGD Thermal Evaporation Cost Methodology

(DCN SE07098) are still three to five times higher than any other option presented in Table VIII-1. As authorized by section 304(b) of the CWA, which allows the EPA to consider costs, the Agency is not proposing that thermal technologies are BAT due to the unacceptable costs to industry. Given the high costs associated with the 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, the EPA is not proposing to establish BAT limitations for FGD wastewater based on evaporation for all steam electric facilities. The EPA solicits comment on this finding, as well as the accuracy of the revised costs estimates.

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

This facility 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.

Furthermore, since membrane filtration technologies included in Option 4 appear to achieve similar pollutant removals for lower costs than thermal, the EPA is proposing to revise the basis for the VIP limitations adopted in the 2015 rule to membrane filtration, instead of thermal technologies, as discussed later in this section.

The EPA solicits comment on the extent to which membrane filtration technologies could be used in lieu of, or in combination with, thermal technologies.

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

Finally, the EPA is not proposing to decline to establish BAT and leave BAT effluent limitations for FGD wastewater to be established by the permitting authority using BPJ. The 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 its previous conclusion.

2. BA Transport Water

This proposal identifies treatment using high recycle rate systems as the BAT technology basis for control of pollutants discharged in BA transport water because, after evaluating the factors specified in CWA section 304(b)(2)(B), the EPA proposes to find that this technology is available and economically achievable. In the 2015 rule, the EPA selected dry BA handling or closed-loop wet ash handling systems as the technology basis for the “zero discharge” BAT requirements for BA transport water. The EPA established zero pollutant discharge limitations based on these technologies and included a limited allowance for pollutant discharges associated with certain maintenance activities.

See

40 CFR part 423.11(p).

At the time of the 2015 rule, the EPA estimated that more than 50 percent of facilities 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, that value is now over 75 percent, nearly evenly split between dry and wet systems. However, since the 2015 rule, the EPA's understanding of the types of available dry systems, and the ability of wet systems to achieve complete recycle has changed, as discussed below.

There have been advances in dry BA handling systems since the 2015 rule.

For example, in addition to under-boiler mechanical drag chain systems (described in the 2015 rule), pneumatic systems and submerged grinder conveyors are now available and in use at some facilities. Such systems often can be installed at facilities that are constrained from retrofitting a mechanical drag system due to insufficient vertical space under the boiler.

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 boiler. Such systems include pneumatic and mechanical processes (some mechanical processes use water to cool the BA or create a water seal between the boiler and ash hoppers, but the water does not act as the transport medium).

With respect to wet BA handling systems, in their petitions for reconsideration and in recent meetings with the EPA, utilities and trade associations informed the EPA that many existing remote wet systems are, in reality, “partially closed” rather than closed-loop, as indicated by the EPA in

the 2015 rule. Utilities and trade associations informed the EPA that these systems operate partially closed, rather than closed, due to small discharges associated with additional maintenance and repair activities not accounted for in the 2015 maintenance allowances,

water imbalances within the system such as those associated with stormwater,

and water chemistry imbalances including acidity and corrosiveness, scaling, and fines build-up. While some facilities 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/runoff from a certain size precipitation event, these events may occur back-to-back, or facilities may receive events with higher rates of accumulation beyond what the facility was designed to handle.

The EPA agrees that the new information indicates that some facilities with wet ash removal systems generally operate as zero discharge systems, but in many cases must operate as high recycle rate systems. While some facilities currently handle the challenges discussed above by discharging some portion of their BA transport water (as the zero discharge limitations in the 2015 rule are not yet applicable), the record demonstrates that facilities can likely eliminate such discharges with additional process changes and expenditures. Just as the EPA estimated costs of chemical additions in the 2015 rule to manage scaling, companies could add additional treatment chemicals (caustic) to manage acidity or other chemicals to control alkalinity, make use of reverse osmosis filters to treat a slip stream of the recycled water to remove dissolved solids, add polymer to enhance settling and removal of fine particulates (“fines”), and build storage tanks to hold water during infrequent maintenance or precipitation events. Industry-wide, the EPA estimates the costs of fully closing the loop to be $43 million per year in after-tax costs, above and beyond the costs of the systems themselves.

These additional costs and process changes were not accounted for in the 2015 rule; however, as discussed in Section 5.3 of the Supplemental TDD, in estimating the baseline costs of the BA limitations in the 2015 rule, the EPA now accounts for these costs. The EPA solicits comment on whether these assumptions and costs are appropriate and requests commenters identify and include available data or information to support their recommended approach.

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

The EPA also recognizes the need for facilities to consider the standards of multiple environmental regulations simultaneously. As discussed in Section IV above, the EPA is separately proposing changes to the CCR rule that, if finalized, would allow facilities to cease receiving waste in unlined surface impoundments by August 2020.

The challenges of operating a truly closed-loop system discussed above are compounded when considered in conjunction with the requirements of the CCR rule. Facilities 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 the EPA and conversations with electric utilities, several facilities have already begun the transition away from impoundments, and also use the BA treatment system for some of their non-CCR wastewaters.

This reportedly can lead to or exacerbate problems with scaling, corrosion, or plugging of equipment that complicate achievement of a closed-loop system and require additional process changes and expense to address. All of which problems could be avoided by purging the system from time to time, as necessary. While those facilities that have not yet installed a BA transport water technology (less than 25 percent) could potentially employ a dry system, and those facilities with existing wet systems could potentially segregate their BA transport water from their non-CCR wastewaters, short compliance timeframes under the CCR rule may limit the availability of such options.

As discussed 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.

In light of the foregoing process changes (and associated engineering challenges) that facilities would need to make to implement a true zero discharge BA transport water limitation in combination with the CCR rule, and to give facilities flexibilities that will facilitate orderly compliance with the fast-approaching CCR rule deadlines, the EPA proposes to base the BA transport water BAT limitations on the use of dry handling or high recycle rate systems rather than dry handling or closed-loop systems, the technologies on which the zero discharge BAT limitation adopted in the 2015 rule were based. The EPA's proposal is based on its discretion to give particular weight to the CWA Section 304(b) statutory factor of “process changes.” Process changes to existing high recycle rate systems that do not currently operate as closed loop, or that will be installed in the near-future, to comply with this rule in conjunction with the CCR rule as discussed above could be more challenging without a further discharge allowance, and in some cases could also result in the prolonged use of unlined surface impoundments.

The EPA considers that the factors discussed above are sufficient to support the Agency's decision not to select closed-loop systems as BAT for BA transport water. The EPA also notes that cost is a statutory factor that it must consider when establishing BAT, and that closed-loop systems cost more than high recycle rate systems for treatment of BA transport water. While the EPA does not find this higher cost to be economically unachievable, the higher cost of closed loop systems is an additional reason for the EPA to not select closed loop systems as BAT for treating BA transport water.

Under the proposed option, the EPA would allow facilities with a wet transport system, on an “as needed” basis, to discharge up to 10 percent of the system volume per day on a 30-day rolling average to account for the challenges identified above, including infrequent large precipitation and maintenance events. The EPA proposes that the term “30-day rolling average” means the series of averages using the measured values of the preceding 30 days for each average in the series. This does not mean that the EPA expects all facilities to discharge up to 10 percent on a regular basis, rather this option is designed to provide flexibility if and when needed to address site-specific challenges of operating the recirculating

ash system (for more on implementation,

see

Section XIV of this preamble).

The EPA also solicits comment on a facility-specific recycle rate alternative to the 10 percent 30-day rolling average option. Under such an alternative, each facility operating a high recycle rate system would take proactive measures (

e.g.,

acid or caustic addition for pH control, chemical addition to control alkalinity, polymer addition to remove fines) to maintain system water chemistry within control limitations established by the facility in a BMP plan similar to that proposed for low utilization units in Section VII.C.2 below. Under this approach, when reasonable active measures are insufficient to maintain system water chemistry or water balance within acceptable limitations, or to facilitate maintenance and repairs of the BA system, the facility would be authorized to purge a portion of the system volume. The purge volume would be determined based on plant-specific information and would be minimized to the extent feasible and limited to a maximum of 10 percent of the total system volume. The EPA solicits comment on whether these two options provide sufficient notice and regulatory certainty for facilities to understand potential obligations under the proposed rule and associated costs. The EPA solicits comment on an alternate approach that establishes a standard purge rate of 10 percent that can be adjusted upward or downward based on site-specific operating data. Finally, the EPA solicits comment on whether these discharges should be capped at a specific flow. The EPA requests commenters identify and include available data or information to support their recommended approach.

The EPA's pollutant loading analyses provided in Section IX.B of this preamble and described in detail in the BCA Report and Supplemental TDD were based on an assumed 10 percent purge at each affected facility.

Under either option discussed above for determining discharge allowances (10 percent 30-day rolling average or site-specific), there may be wastewater from whatever is purged by the high recycle rate system, and plants may wish to discharge this wastewater. Two considerations make determining a nationwide BAT for these discharges challenging and fact-specific. First, in the case of precipitation or maintenance-related purges, such purges would be potentially large volumes at infrequent intervals.

Each facility necessarily has different climates and maintenance needs that could make selecting a uniform treatment system more difficult. Second, utilities have stated that discharges of wastewater associated with high rate recycle systems are sent to low volume wastewater treatment systems, which are typically dewatering basins or surface impoundments. Many of these systems are in transition as a result of the CCR rule. New wastewater treatment systems installed for low volume wastewater and other wastestreams (which could be used to treat the wastewater purged from a high recycle rate system), as well as the types of wastestreams combined in such systems, are likely to vary across facilities.

In the case of precipitation, rainfall exceeding a 25 year, 24-hour event may only happen once during the 20-year lifetime of the equipment, if at all.

In light of the information discussed above, and the EPA's authority under section 304(b) to consider both the process employed (for maintenance needs) and process changes (for new treatment systems installed to comply with the CCR rule), the EPA proposes that BAT limitations for any wastewater that is purged from a high recycle rate system and then discharged be established by the permitting authority on a case-by-case basis using BPJ. The EPA assumes permitting authorities will be in a better position than the EPA to examine site-specific climate and maintenance factors for infrequent events. Permitting authorities will also be in a better position than the EPA to account for site-specific treatment technologies and their configurations already installed or being installed to comply with the CCR rule and other regulations which could accommodate the volumes of, and successfully treat, any discharges of wastewater from a high recycle rate system associated with the proposed allowance. The EPA also solicits comment on technologies that could serve as the basis for BAT for this discharge and what technologies state permitting authorities may consider as BPJ. For example, the EPA solicits comment on whether surface impoundments could be selected as BAT based on high costs to control the purge with other technologies. The EPA further solicits comment on whether delaying the selection of appropriate treatment technology though the BPJ process masks the true cost of this proposed rule for both the regulated entity and the regulatory agency that must undertake the evaluation and ultimately establish BPJ. The EPA also solicits comment on whether the EPA should constrain BPJ by precluding the consideration of some technologies (

e.g.,

zero discharge) using nationwide application of the statutory factors. The EPA solicits any data, information or methodologies that may be useful in evaluating the potential costs of establishing and complying with as yet undetermined BPJ requirements.

The EPA is not proposing to identify surface impoundments as BAT for BA transport water except for BATW purge water because surface impoundments are not as effective at removing dissolved metals as available and achievable technologies, such as high recycle rate systems. Furthermore, the record since the 2015 rule shows that facilities have continued to convert away from surface impoundments to the types of technologies described above, either voluntarily or due to the CCR rule, and in 2018, the U.S. Court of Appeals for the District of Columbia vacated that portion of the 2015 CCR rule that allowed both unlined and clay-lined surface impoundments to continue operating.

USWAG

EPA,

No. 15-1219 (D.C. Cir. 2018). Since very few CCR surface impoundments are composite-lined, the practical effect of this ruling is that the majority of facilities with operating ponds likely will cease sluicing waste to their ponds in the near future. In the 2015 CCR rule, the EPA estimated that it would be less costly for facilities to install under-boiler or remote drag chain systems and send BA to landfills rather than continue to wet sluice BA and replace unlined ponds with composite lined ponds. This supports the suggestion that surface impoundments are not BAT for all facilities. However, the EPA proposes to identify surface impoundments as BAT for two subcategories, as discussed later in this section.

3. Rationale for Voluntary Incentives Program (VIP)

As part of the BAT for existing sources, the 2015 rule established a VIP that provided the certainty of more time (until December 31, 2023 instead of a date determined by the permitting authority that is as soon as possible beginning November 1, 2018) for facilities to implement new BAT limitations if they adopted additional process changes and controls that achieve limitations on mercury, arsenic, selenium and TDS in FGD wastewater, based on thermal evaporation technology.

See

Section VIII(C)(13) of the 2015 rule preamble for a more complete description of the selection of the thermal technology basis, chemical precipitation (with softening) followed by a falling film evaporator. The EPA expected this additional time, combined with other factors (such as the possibility that a facility's NPDES

permit may need more stringent limitations to meet applicable water quality standards), would lead some facilities to choose this option for future implementation by incorporating the VIP limits into their permit during the permit application process. New information in several utilities' internal analyses and contractor reports provided to the EPA since the 2015 rule, as well as meetings with utilities, EPC firms, and vendors indicates that facility decisions to install the more expensive thermal systems were driven by water quality-based effluent limitations imposed by the NPDES permitting authority. Furthermore, such documents and meetings also show that several facilities considered installing membrane filtration technologies under the 2015 rule VIP as well, and thus the EPA evaluated membrane filtration as an alternative basis for VIP.

The EPA proposes to revise the VIP limitations established in the 2015 rule using membrane filtration as the technology basis because it costs less than half the cost of thermal technology and has comparable pollutant removal performance. Membrane filtration achieves pollutant removals comparable to thermal systems in situations where the thermal system would discharge. Engineering documents for some individual facilities evaluated this technology as a zero liquid discharge system which would recycle permeate into the plant. Due to the higher costs of thermal systems compared to chemical precipitation followed by LRTR, the EPA does not expect that any facility would install a new thermal system under the 2015 rule VIP as the least cost technology. As authorized by section 304(b) of the CWA, which allows the EPA to consider costs, the EPA proposes membrane filtration as the technology basis for the VIP BAT limitations, with limitations for mercury, arsenic, selenium, nitrate-nitrite, bromide, and TDS.

Note that the 2015 rule did not include limitations for nitrate/nitrite or bromide.

Second, as authorized by section 304(b) of the CWA, which allows the EPA to consider process changes and non-water quality environmental impacts, the EPA proposes to revise the compliance date for the VIP limitations to December 31, 2028. That is the date the EPA has determined that the membrane filtration technology will be available nationwide, as that term is used in the CWA, for those facilities who choose to adopt it. This timeframe is based on the amount of time necessary to pilot, design, procure, and install both the membrane filtration systems and the brine management systems. The EPA notes that this is similar to the eight-year period between promulgation of the 2015 rule and the 2023 deadline for the current voluntary incentives program. The EPA proposes to find that forthcoming changes in membrane filtration brine disposal options may significantly reduce the non-water quality environmental impacts associated with encapsulation, discussed in Section VII(b)(i) above. Through discussions with several utilities and EPRI, the EPA learned that a forthcoming paste technology may allow facilities to mix the brine with lower quantities of FA and lime and pump the resulting paste via pipes to an onsite landfill where the paste would self-level prior to setting as an encapsulated material. According to these discussions, such a process may be less costly than existing brine disposal alternatives. This process could also reduce non-water quality environmental impacts by reducing the amount of FA used, decreasing air emissions and fuel use associated with trucking and spreading, and, where FA is already being disposed of, could reduce the volumes and pollutant concentrations in leachate.

47 48

A compliance date of December 31, 2028, would have the advantage of allowing this forthcoming paste technology potentially enough time to become available, allow facilities more time to permit landfill cells for brine encapsulated with FA and lime if needed, and conduct pilot testing, demonstrations, and further analyses to fully understand and incorporate the process changes associated with membrane filtration operation, and understand the long term performance of the technology for treatment of FGD waste.

Sniderman, Debbie. 2017.

From Power Plant to Landfill: Encapsulation. Innovative Technology Offers Elegant Solution for Disposing of Multiple Types of Waste. EPRI Journal.

September 19. Available online at:

http://eprijournal.com/from-power-plant-to-landfill-encapsulation/.

Although the EPA is not establishing BAT for leachate in the current rulemaking, the vacatur and remand of BAT for leachate in

Southwestern Electric Power Co., et al.

EPA

means that decreasing volumes of leachate and the concentration of pollutants in that leachate might make more technologies available in a future BAT rulemaking.

One remaining challenge identified for this paste technology is developing approaches to manage wastes (

e.g.,

flush water) from periodic cleaning of the paste transportation piping, where such piping is used.

As authorized by section 304(b) of the CWA, which allows the EPA to consider the process employed, the EPA is proposing a modification of the definition of FGD wastewater and ash transport water to explicitly exclude water used to clean FGD paste piping so that facilities using paste piping for brine encapsulation and disposal in an on-site landfill can more easily clean residual paste from pipes.

Utilities described this process as water pushing a ball through the paste piping when not in use, based on cleaning done of concrete pipes at construction sites. While the ball would clean out the majority of the paste, water would still contact incidental amounts of ash and FGD materials, thus potentially subjecting it to regulations for those wastewaters.

Taken together, the EPA's proposed changes to the VIP would give facilities greater flexibility when choosing a technology, while continuing to achieve pollutant reductions beyond the BAT limitations that are generally applicable to the industry and currently available nationwide. Under Option 2, the EPA estimated that 18 plants (27 percent of plants estimated to incur FGD compliance costs) may opt into the VIP program and under Option 3 the number rises to 23 plants (34 percent of plants estimated to incur FGD compliance costs). The EPA solicits comment on the accuracy of the cost estimates indicating that these plants would opt into the revised VIP program, including data identifying costs that may be potentially excluded from this analysis. Specifically, the EPA solicits data and information on any potential technology limitations, commercial availability, and other limitations that may affect plants' ability to adopt the VIP limits by the proposed VIP compliance date of 2028.

C. Additional Proposed Subcategories

In the 2015 rule, the EPA established subcategories for small boilers (<50 MW nameplate capacity) and oil-fired units. The EPA subcategorized small boilers due to disproportionate costs when compared to the rest of the industry and subcategorized oil-fired boilers both because they generated substantially fewer pollutants and are generally older

(and more susceptible to early retirement). In the 2015 rule, the EPA stated:

Age is a statutory factor for BAT. CWA section 304(b), 233 U.S.C. 1304(b).

If these units shut down, EPA is concerned about resulting reductions in the flexibility that grid operators have during peak demand due to less reserve generating capacity to draw upon. But, more importantly, maintaining a diverse fleet of generating units that includes a variety of fuel sources is important to the nation's energy security. Because the supply/delivery network for oil is different from other fuel sources, maintaining the existence of oil-fired generating units helps ensure reliable electric

power generation, as commenters confirmed.

80 FR 67856.

For these subcategorized units, in the 2015 rule the EPA established differentiated limitations based on surface impoundments (i.e, setting BAT equal to BPT limitations for TSS).

As part of this proposal, the EPA is not proposing a change to the 2015 rule subcategorization of small and oil-fired boilers; therefore, these boilers have limitations for TSS. The EPA is incorporating and expanding on its previous analysis of characteristics and possible differences within the industry. The EPA proposes further subcategorization for FGD wastewater and BA transport water for boilers with low utilization and boilers with limited remaining useful life. In addition, for FGD wastewater, the EPA proposes to subcategorize units with high FGD flows. These proposed subcategories are discussed below.

1. Subcategory for Facilities With High FGD Flows

The EPA is proposing to establish a new subcategory for facilities with high FGD flows based on the statutory factor of cost. The 2015 rule discussed the ability of high-flow facilities to recycle FGD wastewater back into the air pollution control system to decrease FGD wastewater flows and treatment costs. After the 2015 rule, the Tennessee Valley Authority (TVA) submitted a request seeking a fundamentally different factors (FDF) variance for its Cumberland power facility.

This variance request relied primarily on two facts. First, TVA stated that Cumberland's FGD wastewater flow volumes are several million gallons per day,

approximately an order of magnitude higher than many other units with comparable generation capacity, and millions of gallons per day higher than the next highest flow rate in the entire industry.

TVA further stated that the FGD system at Cumberland is constructed of a steel alloy that is susceptible to chloride corrosion. Based on the typical chloride concentrations in the FGD scrubber, the facility would be able to recycle little, if any, of the wastewater back to the scrubber as a means for reducing the flow volume sent to a treatment system.

Second, as a result of the inability to recycle these high flows, TVA stated that the cost of a biological treatment system would be high.

Tennessee Valley Authority (TVA)

—Cumberland Fossil Plant—NPDES Permit No. TN0005789—TVA Request for Alternative Effluent Limitations for Wet FGD System Discharges Based on Fundamentally Different Factors Pursuant to 33 U.S.C. 1311(n).

April 28, 2016.

In the FDF variance, TVA cites to a hypothetical maximum flow of 9 MGD; however, based on survey responses and discussions with TVA staff, the company has never approached this flow rate and does not expect to.

Cumberland accounts for approximately one-sixth to one-seventh of all industry FGD wastewater flows.

Reducing the volume purged from the FGD system or recycling FGD wastewater back to the FGD system can be used to reduce the volume of wastewater requiring treatment, and thus reduce the cost of treating the wastes. However, reducing the flow sent to treatment also has the effect of increasing the concentration of chlorides in the wastewater, and FGD system metallurgy can impose constraints on the degree of recycle that is possible.

The EPA proposes to subcategorize facilities with FGD purge flows greater than four million gallons per day, after accounting for that facility's ability to recycle the wastewater to the maximum limits for the FGD system materials of construction to avoid placing a disproportionate cost on such facilities.

Such a flow reflects the reasonably predictable flow associated with actual and expected FGD operations.

Although it is theoretically possible that another coal facility could be built, or an FGD system installed, that resulted in flows of this volume, in practice, all FGD systems in the past decade have been built with materials that allow for recycling of the FGD wastewater. While facilities with these characteristics could potentially apply for an FDF variance, the EPA is proposing to subcategorize them instead because it currently has sufficient information to do so and because FDF variances are governed by strict timelines and procedural requirements set forth in 33 U.S.C. 1311(n).

According to TVA's analysis, chemical precipitation plus biological treatment would result in a capital cost of $171 million, and an O&M cost of approximately $20 million per year.

The EPA's cost estimates are even higher than TVA's (a $256 million dollar capital cost plus $21 million per year in O&M). These costs are five to six times higher than comparable costs at facilities selling similar numbers of MWh per year.

Passing these disparately higher costs on to consumers would likely put the facility at a competitive disadvantage with other coal-fired facilities not subject to the same capital and operating costs. As authorized by section 304(b) of the CWA, which allows the EPA to consider costs, the EPA proposes a new subcategory for FGD wastewater based on unacceptable disparate costs. For such facilities, the EPA proposes to establish BAT based on chemical precipitation alone, with effluent limitations for mercury and arsenic.

Email to Anna Wildeman. November 13, 2018.

This would generally also hold true for the costs of other FGD technology options at comparable facilities.

2. Subcategory for Boilers With Low Utilization

The EPA is proposing to establish a new subcategory for boilers with low utilization based on the statutory factors of cost and non-water quality environmental impacts (including energy requirements). Low natural gas prices and other factors have led to a decline in capacity utilization for the majority of coal-fired boilers. According to EIA 923 data,

overall coal-fired production for 2017 decreased by approximately one-third from 2009 levels, with the majority of boilers decreasing utilization, sometimes significantly. While the majority of boilers in 2009 were base load, making nameplate capacity a good indicator of electricity production, coal-fired boilers today often operate as cycling or peaking boilers, responding to changes in load demand.

https://www.eia.gov/electricity/data/eia923/

In conversations with electric utilities, several examples were given of former base load facilities which have since modified operations to be load-following, or which no longer produce except for peak days in summer or winter. These discussions tracked closely with changes in production reported in the EIA 923 data.

In light of these industry changes, the EPA examined the costs of the proposed BAT limitations and pretreatment standards for FGD wastewater and BA transport water on the basis of MWh produced, rather than the nameplate capacity used to subcategorize boilers less than or equal to 50 MW in the 2015 rule. Due to changed utilization, nameplate capacity has become less representative of electricity production. Nevertheless, the EPA is not proposing any changes to the 50 MW nameplate capacity subcategory of the 2015 rule as that subcategory applied to additional wastestreams not part of this proposal (

e.g.,

fly ash), and has already been implemented in some permits. Thus, the EPA focused on MWh production for boilers greater than 50 MW nameplate capacity, as discussed below.

Similar to the EPA's finding regarding small boilers in the 2015 rule, the record indicates that disparate costs to meet the proposed FGD wastewater and BA transport water BAT limitations and pretreatment standards are imposed on boilers with low capacity utilization. Figure VIII-1 below presents costs per MWh produced as measured against the status quo, rather than against the 2015 rule baseline. As can be seen in this figure, there is a significant difference between boilers above and below 876,000 MWh per year.

As a result of

these disparate costs, the EPA proposes an additional subcategory for low capacity utilization boilers producing less than 876,000 MWh per year. Many of these boilers are either close to the 50 MW nameplate capacity of the 2015 rule (

e.g.,

a 100 MW boiler running at 100% capacity), or somewhat larger units that have continued to reduce electricity generation due to market forces (

e.g.,

a 400 MW boiler running at 25% capacity). The latter group are expected to produce fewer and fewer MWh per year, moving those boilers further toward the high $/MWh costs over time. Attempting to pass on the higher costs per MWh produced would make these boilers increasingly uncompetitive, exacerbating the disparate cost impacts.

This is the equivalent of a 100 MW boiler running at 100 percent capacity or a 400 MW boiler running at 25 percent capacity.

EP22NO19.000

In addition to

disparate costs, the EPA considered non-water quality environmental impacts (including energy requirements). Low utilization boilers tend to operate only during peak loading. Thus, their continued operation is useful, if not necessary, for ensuring electricity reliability in the near term.

While the EPA only presents the disparate costs of one technology in this figure, a similar comparison could be made for the technologies comprising Options 1 or 4 for a final rule. No comparison is necessary for Option 2 as that option already incorporates the subcategorization that eliminates these disparate costs.

In light of the information discussed above, the EPA proposes to establish a subcategory for low utilization units producing less than 876,000 MWh per year. The EPA solicits comment on whether this subcategory should be based on alternative utilization thresholds. For this subcategory, the EPA proposes to select chemical precipitation as the technology basis for BAT for FGD wastewater, with effluent limitations for mercury and arsenic. The EPA solicits comment on whether chemical precipitation is appropriate and economical or if other approaches would be appropriate. The EPA requests commenters identify and include available data or information to support their recommended approach. Also, for this subcategory, as it did for the subcategories established in the 2015 rule, the EPA proposes to select surface impoundments as the BAT technology basis for BA transport water and establish limitations for TSS based on surface impoundments in combination with a BMP plan under section 304(e) of the Act. Although facilities are likely to meet these TSS limits using technologies other than surface impoundments once they have closed any unlined surface impoundments under the CCR rule, facilities may choose to retrofit a surface impoundment or construct a new surface impoundment. As authorized by section 304(b) of the CWA, which allows the EPA to consider costs, the EPA proposes to find that additional technologies are not BAT for this subcategory due to the unacceptable disproportionate costs per MWh those technologies would impose. Chemical precipitation for FGD wastewater and surface impoundments for BA transport water, along with a requirement to prepare and implement a BMP plan under section 304(e) of the Act to reduce pollutant discharges, are the only technologies the EPA proposes to find would not impose such disproportionate costs on this subcategory of boilers. While the Fifth Circuit in

Southwestern Electric Power Company

EPA,

920 F.3d 999, 1018 n.20 (5th Cir. 2019), found EPA's use of surface impoundments as the technology basis for effluent limitations on legacy wastewater to be arbitrary and capricious, the Court left open the possibility that surface impoundments could be used as the basis for BAT effluent limitations so long as the Agency identifies a statutory factor, such as cost, in its rationale for selecting surface impoundments. Finally, the EPA proposes to find that allowing permitting authorities to set BAT limitations for BA transport water on a case-by-case basis using BPJ for this subcategory would be equally problematic. The technologies a permitting authority would necessarily consider are the same dry handling and high recycle rate systems that result in unacceptable disproportionate costs per MWh, according to the EPA's analysis above. The EPA solicits comment on whether the impacts of the proposed revisions to the CCR rule could result in a different analysis from the disparate

costs presented above. The EPA also solicits comment on other options to address the disproportionate impacts identified above.

3. Subcategory for Boilers Retiring by 2028

The EPA is proposing to establish a new subcategory for boilers retiring by 2028 based on the statutory factors of cost, the age of the equipment and facilities involved, non-water quality environmental impacts (including energy requirements), and other factors as the Administrator deems appropriate. The EPA has continued to gather information about facility and boiler retirements, deactivations, and fuel conversions since the 2015 rule. Of the 107 facilities that the EPA identified in Section 3 of the Supplemental TDD that have announced, commenced or completed such actions, the most frequently stated reason was market forces, such as the continued low price of natural gas (49 facilities).

This was followed by environmental regulations (33),

consent decrees (10), and other reasons (46).

65 66

The fact that environmental regulations were cited by approximately one-third of these facilities and that ELGs were specifically mentioned by some respondents suggests that additional flexibility may help to avoid premature closures for some facilities and/or boilers.

This is consistent with recent analyses of the costs of coal-fired electric generation versus other sources. Examples include: (1)

https://www.bloomberg.com/news/articles/2018-03-26/half-of-all-u-s-coal-plants-would-lose-money-without-regulation;

(2)

https://insideclimatenews.org/news/25032019/coal-energy-costs-analysis-wind-solar-power-cheaper-ohio-valley-southeast-colorado

Approximately 31 percent of the facilities identified specific environmental regulations affecting the decision-making process. When specific environmental regulations were stated, they included CPP, MATS, ELGs, CCR Rule, and Regional Haze Rules.

Some announcements cited several rationales, hence the numbers do not add to 107.

“Other” includes age, reliability of the facility, emission reductions goals, decreased local electricity demand, facility site limitations, and company goals to invest in clean/renewable energy.

To further explore this, the EPA examined the cost implications of complying with the proposed limitations and standards on a dollar-per-MWh-produced basis under hypothetical boiler retirement scenarios. Cost estimates for this proposal assume that facilities will amortize capital and O&M costs across the 20-year life of the technologies (

see

Section 5 of the Supplemental TDD), so the EPA only examined retirement scenarios within the next 20 years. Furthermore, since O&M costs are already spread out over time, the EPA focused on capital costs, which also tended to make up a sizeable portion of costs in the EPA's estimates. Finally, the EPA looked at both three and seven percent discount rates. The analysis showed that a facility could be forced to pass on capital costs per MWh 10 to 15 times higher than those passed on with the assumed 20-year amortization in the EPA's cost estimates, and the costs per MWh remain more than double the EPA's estimates until amortization of six to eight years, depending on the discount rate.

In meetings with the EPA, utilities expressed two other concerns related to retiring units. First, several utilities discussed the potential for stranded assets where equipment would be purchased near the end of a facility's useful life and the public utility commission (PUC) would not allow cost recovery. Although the utilities indicated that PUCs have historically allowed for cost recovery even after the retirement of a boiler, they provided recent examples of PUCs rejecting cost recovery, which make the prospect of continued recovery after retirement less certain. Second, the utilities expressed the need for sufficient time to plan, construct, and obtain necessary permits and approvals for replacement generating capacity. In discussions of example Integrated Resource Plans (IRPs) and the associated process, utilities suggested timelines that would extend for five to eight years or longer.

Utilities also shared instances of very quick turnaround in some cases.

Finally, the North American Electric Reliability Corporation (NERC) recently conducted an aggressive stress test scenario identifying the reliability risks if large baseload coal and nuclear facilities were to bring their projected retirement dates forward.

That report found that if these retirements happen faster than the system can respond (

e.g.,

construction of new base load), significant reliability problems could occur. NERC cautions that, though this stress test is not a predictive forecast,

the findings are consistent with the concern that electric utilities conveyed to the EPA: That the well-planned construction of new generation capacity and orderly retirement of older facilities are vital to ensuring electricity reliability.

North American Electric Reliability Corporation (NERC). 2018.

Special Reliability Assessment: Generation Retirement Scenario.

Atlanta, GA 30326. December 18. Available online at:

https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_Retirements_Report_2018_Final.pdf.

“NERC's stress-test scenario is not a prediction of future generation retirements nor does it evaluate how states, provinces, or market operators are managing this transition. Instead, the scenario constitutes an extreme stress-test to allow for the analysis and understanding of potential future reliability risks that could arise from an unmanaged or poorly managed transition.”

In light of the information discussed above, and the EPA's authority under section 304(b) to consider cost, the age of equipment and facilities involved, non-water quality environmental impacts (including energy requirements), and other factors that the Administrator deems appropriate, the EPA proposes a new subcategory for boilers with a limited remaining useful life,

i.e.,

those intending to close no later than December 31, 2028, subject to a certification requirement (described in Section XIV). For this subcategory, the EPA proposes to identify surface impoundments as the technology basis for BAT, and establish BAT limitations for TSS for both FGD wastewater and BA transport water. As mentioned above, the Fifth Circuit's decision in

Southwestern Electric Power Company

EPA

left open the possibility that surface impoundments could be used as the basis for BAT effluent limitations, so long as the Agency identifies a statutory factor, such as cost, in its rationale for selecting surface impoundments. The EPA proposes to find that additional technologies such as chemical precipitation with or without LRTR for FGD wastewater, and the high recycle rate BA transport water technologies are not BAT for this subcategory due to the unacceptable disproportionate costs they would impose; the potential of such costs to accelerate retirements of boilers at this age of their useful life; the resulting increase in the risk of electricity reliability problems due to those accelerated retirements; and the harmonization with the CCR rule. EPA proposes to find that surface impoundments are the only technology that would not impose such disproportionate costs on this subcategory of boilers. Establishing surface impoundments as BAT for this subcategory would alleviate the choice for these facilities to either pass on disparately high capital costs over a shorter useful life or risk the possibility that post-retirement rate recovery would be denied for the significant capital and operating costs associated with the BAT options in this proposal. Creation of this subcategory would also allow electric utilities to continue the organized phasing out of boilers that are no longer economical, in favor of more efficient, newly constructed generating stations, and would help prevent the scenario described in the NERC stress test.

Additionally, it would ensure that facilities could make better use of the CCR rule's alternative closure provision, by which an unlined surface impoundment could continue to receive waste and complete closure by 2028.

The EPA notes that in order to complete closure by 2028, facilities may have to cease receiving waste well in advance of that date; however, a 2028 date ensures that the ELG will not restrict the use of this alternative closure provision regardless of when a facility ultimately ceases receipt of waste. Furthermore, the EPA proposes to find that allowing permitting authorities to set BAT limitations for either FGD wastewater or BA transport water on a case-by-case basis using BPJ would be problematic. The technologies a permitting authority would necessarily consider are the same systems that result in unacceptable disproportionate costs according to the EPA's analysis (described above). Since these boilers are already nearing the end of their useful life, and are susceptible to early retirement, losing the ability to use surface impoundments for any wastewater prior to currently planned closure dates would undermine the flexibility of the CCR alternative closure provisions and could hasten the retirement of units in a manner more closely resembling the reliability stress test discussed above, which resulted in unacceptable non-water quality environmental impacts (including energy requirements) of compromised electric reliability.

40 CFR part 257.103(b).

The EPA solicits comment on whether approaches to retirement in other rules have worked particularly well and might be adopted here. The EPA solicits comment on whether this subcategory would adversely incentivize coal-fired boilers planning to retire after 2028 to accelerate their retirement to 2028, as well as alternatives for addressing the disproportionate costs, energy requirements, and intersection with the CCR rule discussed above. The EPA also solicits comment on whether this subcategory should also be available for boilers that are planned to be repowered or replaced by 2028, not just those planned for retirement. For example, the EPA solicits comment on data and information demonstrating that boilers that are repowered with gas units are unable to finance both the repowering and the FGD and BA technology upgrades applicable to the rest of the industrial category, and whether BAT for such units should also be established based on surface impoundments as for retiring units described above. The EPA solicits comment on whether 2028 is the most appropriate target date for retirement or if a date earlier or later than 2028 would be more appropriate. The EPA also solicits comment on whether an additional subcategory for low utilization boilers retiring by a date certain that is after 2028 would be warranted, and what an appropriate retirement date might be. The EPA requests commenters identify and include available data or information to support their recommended approach.

D. Availability Timing of New Requirements

Where BAT limitations in the 2015 rule are more stringent than previously established BPT limitations for FGD wastewater and BA transport water, those limitations, under the compliance dates as amended by the 2017 postponement rule, do not apply until a date determined by the permitting authority that is “as soon as possible” beginning November 1, 2020.

The rule also specifies the factors that the permitting authority must consider in determining the “as soon as possible” date.

In addition, the 2017 postponement rule did not revise the 2015 rule's “no later than” date of December 31, 2023, for implementation because, as public commenters pointed out, without such a date, implementation could be substantially delayed, and a firm “no later than” date creates a more level playing field across the industry. As the EPA did in developing the 2015 rule, as part of the consideration of the technological availability and economic achievability of the BAT limitations in this proposal, the Agency considered the magnitude and complexity of process changes and new equipment installations that would be required at facilities to meet the proposed requirements. As discussed below, the EPA is considering availability of the technologies for FGD wastewater and BA transport water.

40 CFR 423.11(t).

These factors are: (a) Time to expeditiously plan (including to raise capital), design, procure, and install equipment to comply with the requirements of the final rule; (b) changes being made or planned at the facility in response to greenhouse gas regulations for new or existing fossil fuel-fired power facilities under the Clean Air Act, as well as regulations for the disposal of coal combustion residuals under subtitle D of the Resource Conservation and Recovery Act; (c) for FGD wastewater requirements only, an initial commissioning period to optimize the installed equipment; and (d) other factors as appropriate. 40 CFR 423.11(t).

In the 2015 rule, and as amended by the 2017 postponement rule, the EPA selected the time frames described above to enable many facilities to raise needed capital, plan and design systems, procure equipment, and then construct and test systems. The time frames also allow for consideration of facility changes being made in response to other Agency rules affecting the steam electric power generating industry (

e.g.,

the CCR rule). The EPA understands that some facilities may have already installed, or are now installing, technologies that could comply with the proposed limitations. While these facilities could therefore potentially comply with the proposed rule by the earliest date on which the limitations may become applicable (November 1, 2020), the EPA solicits comment on whether the earliest date on which facilities may have to meet the proposed limitations should

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