[Federal Register Volume 84, Number 226 (Friday, November 22, 2019)]
[Proposed Rules]
[Pages 64620-64677]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2019-24686]
[[Page 64619]]
Vol. 84
Friday,
No. 226
November 22, 2019
Part II
Environmental Protection Agency
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40 CFR Part 423
Effluent Limitations Guidelines and Standards for the Steam Electric
Power Generating Point Source Category; Proposed Rule
Federal Register / Vol. 84 , No. 226 / Friday, November 22, 2019 /
Proposed Rules
[[Page 64620]]
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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.
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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: [email protected]. 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: [email protected]. For economic information, contact
James Covington, Engineering and Analysis Division, Telephone: 202-566-
1034; Email: [email protected].
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
[[Page 64621]]
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
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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:
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------------------------------------------------------------------------
North American Industry
Category Example of regulated Classification System
entity (NAICS) code
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Industry............... Electric Power 22111
Generation
Facilities--Electric
Power Generation.
Electric Power 221112
Generation
Facilities--Fossil
Fuel Electric Power
Generation.
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This section is not intended to be exhaustive, but rather provides
a guide regarding entities likely to be regulated by any final rule
following this action. Other types of entities that do not meet the
above criteria could also be regulated. To determine whether your
facility is regulated by any final rule following this action, you
should carefully examine the applicability criteria listed in 40 CFR
423.10 and the definitions in 40 CFR 423.11 of the 2015 rule. If you
still have questions regarding the applicability of any final rule
following this action to a particular entity, consult the person listed
for technical information in the preceding FOR FURTHER INFORMATION
CONTACT section.
B. What action is the Agency taking?
The agency is proposing to revise certain Best Available Technology
Economically Achievable (BAT) effluent limitations guidelines and
pretreatment standards for existing sources in the steam electric power
generating point source category that apply to FGD wastewater and BA
transport water.
C. What is the Agency's authority for taking this action?
The EPA is proposing to promulgate this rule under the authority of
sections 301, 304, 306, 307, 308, 402, and 501 of the Clean Water Act
(CWA), 33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342, and 1361.
D. What are the monetized incremental costs and benefits of this
action?
This action is estimated to save $136.3 million per year in social
costs and result in between $14.8 million and $68.5 million in
benefits, using a 3 percent discount rate. Using a 7 percent discount
rate, the estimated savings are $166.2 million per year and benefits
are between $28.4 million and $74.4 million.
IV. Background
A. Clean Water Act
Among its core provisions, the CWA prohibits the discharge of
pollutants from a point source to waters of the U.S., except as
authorized under the CWA. Under section 402 of the CWA, 33 U.S.C. 1342,
discharges may be authorized through a National Pollutant Discharge
Elimination System (NPDES) permit. The CWA establishes a dual approach
for these permits: (1) Technology-based controls that establish a floor
of performance for all dischargers, and (2) water quality-based
effluent limitations, where the technology-based effluent limitations
are insufficient to meet applicable water quality standards (WQS). As
the basis for the technology-based controls, the CWA authorizes the EPA
to establish national technology-based effluent limitations guidelines
and new source performance standards for discharges into waters of the
United States from categories of point sources (such as industrial,
commercial, and public sources).
The CWA also authorizes the EPA to promulgate nationally applicable
pretreatment standards that control pollutant discharges from sources
that discharge wastewater indirectly to waters of the U.S., through
sewers flowing to POTWs, as outlined in sections 307(b) and (c) of the
CWA, 33 U.S.C. 1317(b) and (c). The EPA establishes national
pretreatment standards for those pollutants in wastewater from indirect
dischargers that pass through, interfere with, or are otherwise
incompatible with POTW operations. Pretreatment standards are designed
to ensure that wastewaters from direct and indirect industrial
dischargers are subject to similar levels of treatment. See CWA section
301(b), 33 U.S.C. 1311(b). In addition, POTWs are required to implement
local treatment limitations applicable to their industrial indirect
dischargers to satisfy any local requirements. See 40 CFR 403.5.
Direct dischargers (those discharging to waters of the U.S. rather
than to a POTW) must comply with effluent limitations in NPDES permits.
Indirect dischargers, who discharge through POTWs, must comply with
pretreatment standards. Technology-based effluent limitations and
standards in NPDES permits are derived from effluent limitations
guidelines (CWA sections 301 and 304, 33 U.S.C. 1311 and 1314) and new
source performance standards (CWA section 306, 33 U.S.C. 1316)
promulgated by the EPA, or are based on best professional judgment
(BPJ) where EPA has not promulgated an applicable effluent limitation
guideline or new source performance standard (CWA section 402(a)(1)(B),
33 U.S.C. 1342(a)(1)(B)). Additional limitations are also required in
the permit where necessary to meet WQS. CWA section 301(b)(1)(C), 33
U.S.C. 1311(b)(1)(C). The ELGs are established by EPA regulation for
categories of industrial dischargers and are based on the degree of
control that can be achieved using various levels of pollution control
technology, as specified in the Act (e.g., BPT, BCT, BAT; see below).
EPA promulgates national ELGs for industrial categories for three
classes of pollutants: (1) Conventional pollutants (total suspended
solids (TSS), oil and grease, biochemical oxygen demand (BOD5), fecal
coliform, and pH), as outlined in CWA section 304(a)(4), 33 U.S.C.
1314(a)(4), and 40 CFR 401.16; (2) toxic pollutants (e.g., toxic metals
such as arsenic, mercury, selenium, and chromium; toxic organic
pollutants such as benzene, benzo-a-pyrene, phenol, and naphthalene),
as outlined in CWA section 307(a), 33 U.S.C. 1317(a); 40 CFR 401.15 and
40 CFR part 423, appendix A; and (3) nonconventional pollutants, which
are those pollutants that are not categorized as conventional or toxic
(e.g., ammonia-N, phosphorus, and total dissolved solids (TDS)).
B. Relevant Effluent Guidelines
The EPA establishes ELGs based on the performance of well-designed
and well-operated control and treatment technologies. The legislative
history also supports that the EPA need not consider water quality
impacts on individual water bodies as the guidelines are developed; see
Statement of Senator Muskie (principal author) (October 4, 1972),
reprinted in Legislative History of the Water Pollution Control Act
Amendments of 1972, at 170. (U.S. Senate, Committee on Public Works,
Serial No. 93-1, January 1973).
There are four types of standards applicable to direct dischargers
and two types of standards applicable to indirect dischargers. The
three standards relevant to this rulemaking are described in detail
below.
[[Page 64624]]
1. Best Practicable Control Technology Currently Available (BPT)
Traditionally, the EPA establishes effluent limitations based on
BPT by reference to the average of the best performances of facilities
within the industry, grouped to reflect various ages, sizes, processes,
or other common characteristics. The EPA promulgates BPT effluent
limitations for conventional, toxic, and nonconventional pollutants. In
specifying BPT, the EPA looks at a number of factors. The EPA first
considers the cost of achieving effluent reductions in relation to the
effluent reduction benefits. The Agency also considers the age of
equipment and facilities, the processes employed, engineering aspects
of the control technologies, any required process changes, non-water
quality environmental impacts (including energy requirements), and such
other factors as the Administrator deems appropriate. See CWA section
304(b)(1)(B), 33 U.S.C. 1314(b)(1)(B). If, however, existing
performance is uniformly inadequate, the EPA may establish limitations
based on higher levels of control than those currently in place in an
industrial category, when based on an Agency determination that the
technology is available in another category or subcategory and can be
practically applied.
2. Best Available Technology Economically Achievable (BAT)
BAT represents the second level of control for direct discharges of
toxic and nonconventional pollutants. As the statutory phrase intends,
the EPA considers the technological availability and the economic
achievability in determining what level of control represents BAT. CWA
section 301(b)(2)(A), 33 U.S.C. 1311(b)(2)(A). Other statutory factors
that the EPA must consider in assessing BAT are the cost of achieving
BAT effluent reductions, the age of equipment and facilities involved,
the process employed, potential process changes, non-water quality
environmental impacts (including energy requirements), and such other
factors as the Administrator deems appropriate. CWA section
304(b)(2)(B), 33 U.S.C. 1314(b)(2)(B); Texas Oil & Gas Ass'n v. EPA,
161 F.3d 923, 928 (5th Cir. 1998). The Agency retains considerable
discretion in assigning the weight to be accorded each of these
required consideration factors. Weyerhaeuser Co. v. Costle, 590 F.2d
1011, 1045 (D.C. Cir. 1978). Generally, the EPA determines economic
achievability based on the effect of the cost of compliance with BAT
limitations on overall industry and subcategory (if applicable)
financial conditions. BAT is intended to reflect the highest
performance in the industry, and it may reflect a higher level of
performance than is currently being achieved based on technology
transferred from a different subcategory or category, bench scale or
pilot studies, or foreign facilities. Am. Paper Inst. v. Train, 543
F.2d 328, 353 (D.C. Cir. 1976); Am. Frozen Food Inst. v. Train, 539
F.2d 107, 132 (D.C. Cir. 1976). BAT may be based upon process changes
or internal controls, even when these technologies are not common
industry practice. See Am. Frozen Food Inst., 539 F.2d at 132, 140;
Reynolds Metals Co. v. EPA, 760 F.2d 549, 562 (4th Cir. 1985); Cal. &
Hawaiian Sugar Co. v. EPA, 553 F.2d 280, 285-88 (2nd Cir. 1977).
One way that EPA may take into account differences within an
industry when establishing BAT limitations is through
subcategorization. The Supreme Court has recognized that the
substantive test for subcategorizing an industry is the same as that
which applies to establishing fundamentally different factor
variances--i.e., whether the plants are different with respect to
relevant statutory factors. See Chem. Mfrs. Ass'n v. EPA, 870 F.2d 177,
214 n.134 (5th Cir. 1989) (citing Chem. Mfrs. Ass'n v. NRDC, 470 U.S.
116, 119-22, 129-34 (1985)). Courts have stated that there need only be
a rough basis for subcategorization. See Chem. Mfrs. Ass'n v. EPA, 870
F.2d at 215 n.137 (summarizing cases).
3. Pretreatment Standards for Existing Sources (PSES)
Section 307(b) of the CWA, 33 U.S.C. 1317(b), authorizes the EPA to
promulgate pretreatment standards for discharges of pollutants to
POTWs. PSES are designed to prevent the discharge of pollutants that
pass through, interfere with, or are otherwise incompatible with the
operation of POTWs. Categorical pretreatment standards are technology-
based and are analogous to BPT and BAT effluent limitations guidelines,
and thus the Agency typically considers the same factors in
promulgating PSES as it considers in promulgating BPT and BAT.
Legislative history indicates that Congress intended for the
combination of pretreatment and treatment by the POTW to achieve the
level of treatment that would be required if the industrial source were
discharging to a water of the U.S. Conf. Rep. No. 95-830, at 87 (1977),
reprinted in U.S. Congress. Senate Committee on Public Works (1978), A
Legislative History of the CWA of 1977, Serial No. 95-14 at 271 (1978).
The General Pretreatment Regulations, which set forth the framework for
the implementation of categorical pretreatment standards, are found at
40 CFR 403. These regulations establish pretreatment standards that
apply to all non-domestic dischargers. See 52 FR 1586 (January 14,
1987).
C. 2015 Rule
The EPA, on September 30, 2015, finalized a rule revising the
regulations for the Steam Electric Power Generating point source
category (40 CFR part 423) (hereinafter the ``2015 rule''). The rule
set the first federal limitations on the levels of toxic metals in
wastewater that can be discharged from steam electric facilities, based
on technology improvements in the steam electric power industry over
the preceding three decades. Prior to the 2015 rule, regulations for
the industry had been last updated in 1982.
New technologies for generating electric power and the widespread
implementation of air pollution controls over the last 30 years have
altered existing wastewater streams or created new wastewater streams
at many steam electric facilities, particularly coal-fired facilities.
Discharges of these wastestreams include arsenic, lead, mercury,
selenium, chromium, and cadmium. Many of these toxic pollutants, once
in the environment, remain there for years, and continue to cause
impacts.
The 2015 rule addressed effluent limitations and standards for
multiple wastestreams generated by new and existing steam electric
facilities: BA transport water, combustion residual leachate, FGD
wastewater, flue gas mercury control wastewater, fly ash (FA) transport
water, and gasification wastewater. The rule required most steam
electric facilities to comply with the effluent limitations ``as soon
as possible'' after November 1, 2018, and no later than December 31,
2023. Within that range, except for indirect dischargers, the
particular compliance date(s) for each facility would be determined by
the facility's National Pollutant Discharge Elimination System permit,
which is typically issued by a state environmental agency.
On an annual basis, the 2015 rule was projected to reduce the
amount of metals defined in the Act as toxic pollutants, nutrients, and
other pollutants that steam electric facilities are allowed to
discharge by 1.4 billion pounds and reduce water withdrawal by 57
billion gallons. At the time, the EPA estimated annual compliance costs
for the final rule to be $480 million (in 2013
[[Page 64625]]
dollars) and estimated benefits associated with the rule to be $451 to
$566 million (in 2013 dollars).
D. Legal Challenges, Administrative Petitions, Section 705 Action,
Postponement Rule, and Reconsideration of Certain Limitations and
Standards
Seven petitions for review of the 2015 rule were filed in various
circuit courts by the electric utility industry, environmental groups,
and drinking water utilities. These petitions were consolidated in the
U.S. Court of Appeals for the Fifth Circuit, Southwestern Electric
Power Co., et al. v. EPA.\1\ On March 24, 2017, the Utility Water Act
Group (UWAG) submitted to the EPA an administrative petition for
reconsideration of the 2015 rule. Also, on April 5, 2017, the Small
Business Administration (SBA) submitted an administrative petition for
reconsideration of the final rule.
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\1\ Case No. 15-60821.
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On April 25, 2017, the EPA responded to these petitions by
publishing a postponement of the 2015 rule compliance deadlines that
had not yet passed, under Section 705 of the Administrative Procedure
Act (APA). This Section 705 Action drew multiple legal challenges.\2\
The Administrator then signed a letter on August 11, 2017, announcing
his decision to conduct a rulemaking to potentially revise the new,
more stringent BAT effluent limitations and pretreatment standards for
existing sources in the 2015 rule that apply to FGD wastewater and BA
transport water. The Fifth Circuit subsequently granted EPA's request
to sever and hold in abeyance aspects of the litigation related to
those limitations and standards. With respect to the remaining claims
related to limitations applicable to legacy wastewater and leachate,
which are not at issue in this proposed rulemaking, the Fifth Circuit
issued a decision on April 12, 2019, vacating those limitations as
arbitrary and capricious under the Administrative Procedure Act and
unlawful under the CWA, respectively. The EPA plans to address this
vacatur in a subsequent action.
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\2\ See Clean Water Action. v. EPA, No. 17-0817 (D.D.C.), appeal
docketed, No. 18-5149 (D.C. Cir.); see also Clean Water Action. v.
EPA, No. 18-60619 (5th Cir.) (case dismissed for lack of
jurisdiction on October 18, 2018).
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In September 2017, the EPA finalized a rule, using notice-and-
comment procedures, postponing the earliest compliance dates for the
new, more stringent BAT effluent limitations and PSES for FGD
wastewater and BA transport water in the 2015 rule, from November 1,
2018 to November 1, 2020. The EPA also withdrew its prior action taken
pursuant to Section 705 of the APA. The rule received multiple legal
challenges, but EPA prevailed, and the courts did not sustain any of
them.\3\
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\3\ See Center for Biological Diversity v. EPA, No. 18-cv-00050
(D. Ariz. filed Jan. 20, 2018); see also Clean Water Action. v. 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.
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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 (CO2)
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 v.
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
CO2 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
CO2 from coal-fired EGUs.\4\ By employing a broad range of
HRI technologies and techniques, EGUs can more efficiently generate
electricity with less carbon intensity.\5\ 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.\6\ 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.
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\4\ Heat rate is a measure of the amount of energy required to
generate a unit of electricity.
\5\ An improvement to heat rate results in a reduction in the
emission rate of an EGU (in terms of CO2 emissions per
unit of electricity produced).
\6\ 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.
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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
[[Page 64626]]
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 v. EPA, No. 15-1219 (D.C. Cir.
2018) and Waterkeeper Alliance Inc, et al. v. 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 \7\ 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.
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\7\ 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. v. 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.\8\ 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.
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\8\ 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.
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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
[[Page 64627]]
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
[[Page 64628]]
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.\9\ 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:
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\9\ Consistent with the 2015 rule, boiler slag is considered BA.
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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.\10\
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\10\ 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.
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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
[[Page 64629]]
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.
[[Page 64630]]
Table VII-1--Main Regulatory Options
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Technology basis for the BAT/PSES regulatory options
Wastestream Subcategory --------------------------------------------------------------------------------------------
1 2 3 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
FGD Wastewater..................... N/A................... Chemical precipitation Chemical Chemical Membrane filtration.
precipitation + low precipitation + low
hydraulic residence hydraulic residence
time biological time biological
treatment. treatment.
High FGD flow NS.................... Chemical Chemical Chemical
facilities. precipitation. precipitation. precipitation.
Low utilization NS.................... Chemical NS................... NS.
boilers. precipitation.
Boilers retiring by Surface impoundments.. Surface impoundments. Surface impoundments. Surface impoundments.
2028.
--------------------------------------------------------------------------------------------------------------------------------------------------------
FGD Wastewater Voluntary Incentives Program (Direct Membrane filtration... Membrane filtration.. Membrane filtration.. N/A.
Dischargers Only).
--------------------------------------------------------------------------------------------------------------------------------------------------------
BA Transport Water................. N/A................... Dry handling or High Dry handling or High Dry handling or High Dry handling or High
recycle rate systems. recycle rate systems. recycle rate systems. recycle rate
systems.
Low utilization NS.................... Surface impoundments NS................... NS.
boilers. +BMP plan.
Boilers retiring by Surface impoundments.. Surface impoundments. Surface impoundments. Surface impoundments.
2028.
--------------------------------------------------------------------------------------------------------------------------------------------------------
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 \11\ and for those boilers
would require mercury and arsenic limitations and pretreatment
standards based on chemical precipitation.\12\ 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.
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\11\ The equivalent of a 100 MW boiler operating at 100%
capacity or a 400 MW boiler operating at 25% capacity.
\12\ 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).
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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.\13\
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.\14\ The EPA
proposes not to characterize a technology basis for BAT/PSES applicable
to such wastewater at this time.\15\
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\13\ 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.
\14\ 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.
\15\ 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).
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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
[[Page 64631]]
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.\16\ The LRTR bioreactor stage would be followed by an
ultrafilter to remove suspended solids exiting the bioreactor,
including colloidal particles.
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\16\ 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.
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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.\17\ 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.\18\ 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.
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\17\ 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.
\18\ 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.
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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,\19\
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
[[Page 64632]]
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.\20\
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\19\ 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.
\20\ 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. v. 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.\21\ 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.
---------------------------------------------------------------------------
\21\ 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.\22\ 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.\23\ 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.\24\
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\22\ Two of these pilot studies were completed in 2014, but
information about these tests was not provided to EPA prior to the
2015 rule.
\23\ 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/).
\24\ 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.\25\ 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.\26\ Furthermore, the company
that sold these two systems has since ceased commercial operations.\27\
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.
---------------------------------------------------------------------------
\25\ 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.
\26\ 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.
\27\ The following story summarizes the forward osmosis company
Oasys ceasing commercial operations: https://www.bluetechresearch.com/news-blog/comment-oasys-hits-funding-drought/.
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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
[[Page 64633]]
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.\28\
---------------------------------------------------------------------------
\28\ 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.\29\ 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.\30\
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\29\ 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.
\30\ Bids also indicate that this would be the least-cost brine
management alternative.
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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.\31\
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\31\ 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.\32\ 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 CO2
emissions, 840 g of methane emissions, 1,400 g of CO emissions, 2,700 g
of NOX emissions, 2,500 g of SOX 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.\33\ 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.
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\32\ 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.
\33\ 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.
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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. v. EPA, 66
F.3d 784, 796 (6th Cir. 1996).
[[Page 64634]]
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,\34\ and a seventh
purchased thermal equipment, but elected not to install it.\35\ 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.
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\34\ 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.
\35\ 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.
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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.\36\ The EPA
solicits comment on the extent to which membrane filtration
technologies could be used in lieu of, or in combination with, thermal
technologies.
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\36\ The EPA notes that thermal technologies could continue to
be used to meet the voluntary incentives program limitations based
on membrane filtration.
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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.\37\
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\37\ See 40 CFR part 423.11(p).
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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.\38\ 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.
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\38\ 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).
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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
[[Page 64635]]
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,\39\
water imbalances within the system such as those associated with
stormwater,\40\ 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).
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\39\ 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.
\40\ 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.
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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.\41\ 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.
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\41\ 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.
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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.\42\ 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.\43\ 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.
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\42\ 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.
\43\ In some cases, the treatment system predated even the
proposed CCR rule.
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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
[[Page 64636]]
ash system (for more on implementation, see Section XIV of this
preamble).\44\ 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.
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\44\ 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.
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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.\45\ 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.
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\45\ 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.
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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 v. 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
[[Page 64637]]
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.\46\
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\46\ Note that the 2015 rule did not include limitations for
nitrate/nitrite or bromide.
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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.
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\47\ 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/.
\48\ 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. v. 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.
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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.\49\ 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.
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\49\ 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.
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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 \50\ (and more susceptible to early retirement). In
the 2015 rule, the EPA stated:
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\50\ 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
[[Page 64638]]
power generation, as commenters confirmed. \51\
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\51\ 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.\52\ This variance request relied primarily on two facts.
First, TVA stated that Cumberland's FGD wastewater flow volumes are
several million gallons per day,\53\ 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.\54\ 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.\55\
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.
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\52\ 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.
\53\ 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.
\54\ Cumberland accounts for approximately one-sixth to one-
seventh of all industry FGD wastewater flows.
\55\ 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.
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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.\56\ Such a flow reflects the
reasonably predictable flow associated with actual and expected FGD
operations.
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\56\ 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).
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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.\57\ 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.\58\ 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.
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\57\ Email to Anna Wildeman. November 13, 2018.
\58\ This would generally also hold true for the costs of other
FGD technology options at comparable facilities.
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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,\59\ 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.\60\
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\59\ https://www.eia.gov/electricity/data/eia923/.
\60\ 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.
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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.\61\ As a result of
[[Page 64639]]
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.
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\61\ This is the equivalent of a 100 MW boiler running at 100
percent capacity or a 400 MW boiler running at 25 percent capacity.
[GRAPHIC] [TIFF OMITTED] TP22NO19.000
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.
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\62\ 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.
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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 v. 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
[[Page 64640]]
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).\63\ This was followed by environmental
regulations (33),\64\ 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.
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\63\ 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.
\64\ 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.
\65\ Some announcements cited several rationales, hence the
numbers do not add to 107.
\66\ ``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.
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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.\67\
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\67\ Utilities also shared instances of very quick turnaround in
some cases.
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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.\68\ 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,\69\ 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.
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\68\ 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.
\69\ ``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.''
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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 v. 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.
[[Page 64641]]
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.\70\ 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.
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\70\ 40 CFR part 257.103(b).
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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.\71\ The rule also specifies the factors
that the permitting authority must consider in determining the ``as
soon as possible'' date.\72\ 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.
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\71\ 40 CFR 423.11(t).
\72\ 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).
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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 be later
than November 1, 2020.\73\
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\73\ The EPA received a request on behalf of two Maryland
facilities that the EPA issue a rule postponing the earliest
compliance date from November 1, 2020 to November 1, 2022. See Feb.
26, 2019 memorandum entitled EPA's Ongoing Reconsideration of the
Effluent Limitation Guidelines and Standards for the Steam Electric
Generating Point Source Category (the ``ELG Rule'' or ``the ELGs''),
available on EPA's Docket at No. EPA-HQ-OW-2009-0819.
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As described previously, the industry continues to shift away from
the use of surface impoundments for handling BA. Information collected
since the 2015 rule, as well as conversations with electric utilities,
EPA understands that facilities may be able to complete design,
procurement, installation, and operation of BA transport water
technologies by December 31, 2023.\74\ The CCR rule proposal would
require the majority of unlined surface impoundments to stop receiving
waste by August 2020. This would necessarily require installation by
August 2020 of an alternative system to meet those ELG standards. As
described earlier, because the record for the 2015 CCR rule found 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.
Flexibility for facilities to comply with BAT limitations for BA
transport water beyond 2023 is not necessary because the process
changes should already have occurred due to CCR rule requirements.
Therefore, for BA transport water, the EPA proposes to continue the
current timing for implementation. The EPA solicits comment on whether
these assumptions are appropriate. The EPA also solicits comment on
whether it should modify the existing language
[[Page 64642]]
which explicitly allows permitting authorities to consider extensions
granted under the CCR rule in establishing compliance dates for BA
transport water. The EPA requests commenters identify and include
available data or information to support their recommended approach.
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\74\ Information in the record indicates a typical timeframe of
15-23 months to raise capital, plan and design systems, procure
equipment, and construct a dry handling or closed-loop or high rate
recycle BA system.
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For FGD wastewater, the EPA proposes to continue the existing
``beginning'' date, but proposes a different ``no later than'' date.
The EPA collected updated information regarding the technical
availability of the proposed FGD BAT technology basis, including the
proposed VIP alternative. Based on the engineering dependency charts,
bids, and other analytical documents in the current record, individual
facilities may need two to three years from the effective date of any
rule to install and begin operating a treatment system to achieve
BAT.\75\ While three years may be appropriate for a facility on an
individual basis, several utilities and EPC firms pointed out
difficulties in retrofitting on a company-wide or industry-wide basis.
Moreover, the same engineers, vendors, and construction companies are
often used across facilities. As was the case with BA transport water
above, facilities with FGD wastewater have continued to convert away
from surface impoundments, and the majority of facilities with unlined
surface impoundments would have to stop receiving waste in those
unlined surface impoundments by August 2020, under the CCR proposal. To
stop receiving waste in an unlined surface impoundment, a facility
would need to construct a treatment system to meet applicable ELGs,
such as a tank-based system that meets the BPT limitations. However,
biological treatment is not necessary to remove TSS, and therefore more
time for implementation of the proposed BAT limitations will help to
accommodate the process changes necessitated by combining chemical
precipitation and LRTR, and alleviate competition for resources.
Considering all the factors described above, the EPA proposes to extend
the ``no later than'' date for compliance with BAT FGD wastewater
limitations to December 31, 2025, based on the proposed technology
basis. Thus, for FGD wastewater, where BAT limitations are more
stringent than previously established BPT limitations, BAT limitations
would not apply until a date determined by the permitting authority
that is as soon as possible beginning November 1, 2020, but no later
than December 31, 2025. The EPA solicits comment on whether these
assumptions are appropriate and whether these compliance dates should
be harmonized with the compliance dates for BA transport water. The EPA
requests commenters identify and include available data or information
to support their recommended approach.
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\75\ Information in the record indicates a typical time frame of
26 to 34 months to raise capital, plan and design systems (including
any necessary pilot testing), procure equipment, and construct and
then test systems (including a commissioning period for FGD
wastewater treatment systems). Many facilities have already
completed initial steps of this process, having evaluated water
balances and conducted pilot testing to prepare for implementing the
2015 rule.
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In addition, as discussed earlier, the EPA is proposing to give
facilities that elect to use the VIP until December 31, 2028, to meet
the VIP limitations, which are based on membrane filtration technology.
That is the date on which the EPA proposes to determine that the
membrane filtration-based limitations are ``available'' (as that term
is used in the CWA) to all plants that might choose to participate in
the voluntary incentives program. The EPA is proposing to give
facilities sufficient time to work out operational issues related to
being the first facilities in the U.S. to treat FGD wastewater using
membrane filtration at full scale, as well as having to dispose of the
resulting brine. Both issues contribute to the EPA's proposed decision
that membrane filtration is not BAT on a nationwide basis at this time.
The EPA also wants to incentivize facilities to opt into a program that
can achieve significant pollutant reductions.
E. Regulatory Sub-Options To Address Bromides
The 2015 rule rejected thermal evaporation technology as the basis
for BAT and therefore did not establish limitations for bromides in FGD
wastewater. Section XVI.D of the preamble noted that the VIP
established in the 2015 rule would address bromide through the
limitations for TDS. The newly proposed VIP includes limits for
bromide. Because the EPA proposes to provide more flexible VIP limits
on other pollutants and more flexible VIP timing, the EPA estimates
that selecting the proposed VIP may be the least-cost option for some
facilities. The facilities that the EPA estimates VIP may be the least-
cost option range in FGD wastewater flows, nameplate capacity, capacity
utilization, and location. The EPA cost estimates for the VIP tend to
be lower at facilities where no treatment has been installed beyond
surface impoundments, however even for this group of facilities
biological systems are still often least-cost. Thus, while the EPA
estimates that the proposed revisions to the VIP may address bromide at
more facilities than the 2015 VIP, it is still a voluntary program, and
concerns about costs, availability, and disposal of the resultant brine
are still present.
The EPA suggested in the preamble to the 2015 rule that water-
quality-based effluent limitations may be appropriate on a site-
specific basis to address the potential impacts of bromides on
downstream drinking water treatment facilities, as determined by state
permitting authorities. Since that time, few states have begun to
monitor bromide discharges and it is unclear how many have acted to
address such discharges.\76\
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\76\ The EPA is aware that Pennsylvania, Alabama, and North
Carolina conduct bromide monitoring at multiple facilities with FGD
discharges.
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On June 8, 2018, drinking water utilities sent a letter to the EPA
requesting that the Agency consider three regulatory BAT/PSES
technology options to reduce bromide discharges in FGD wastewater: (1)
Zero liquid discharge technologies (ZLD), such as membrane filtration
or thermal treatment; (2) treatment with reverse osmosis; or (3) a
requirement that facilities provide data to the state permitting
authority for use in calculating a site-specific discharge limitation.
For the reasons explained earlier in this section, the EPA is not
proposing to base BAT limitations or PSES for FGD wastewater at all
existing units based on membrane filtration or thermal treatment. The
EPA proposes a water quality-based approach as the most appropriate
approach and solicits comment on that alternative, including ways that
such an alternative could be strengthened. However, in light of the
letter from the drinking water utilities and the limited state action
since the 2015 rule to address this potential issue, the EPA is
requesting comment on three bromide-specific regulatory sub-options in
addition to the proposed approach of retaining the 2015 rule's approach
of leaving bromides to be limited by permitting authorities where
appropriate using water quality-based effluent limitations: \77\ (1) A
monitoring requirement under CWA section 308; (2) a bromide
minimization plan using narrative or non-numeric limitations under CWA
sections 301(b) and 304(b); or (3) a numeric limit under CWA sections
301(b) and 304(b) based on product substitution. Each of these are
described in more detail below.
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\77\ These sub-options would not be applicable to the VIP
limitations as those limitations would control bromide (and other
halogens) in FGD wastewater discharges.
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[[Page 64643]]
In the case of FGD wastewater monitoring, the EPA solicits comment
on two approaches suggested by electric utilities. Under the first
approach, bromide would be monitored monthly for two years, and
thereafter only after specific changes in facility operations that
could alter bromide concentrations in FGD wastewater. Such operational
changes could include changing to a brominated refined coal, a bromide
addition process, a coal feedstock with higher bromide levels, or use
of brominated powdered activated carbon (PAC). Under the second
approach, bromide would be monitored monthly for five years in two
locations to better capture bromide variability. The first monitoring
location would be of intake water not affected by the site's discharge
to capture what fraction of bromide is present from background surface
water. The second would be of discharge water to capture the amount of
bromide added by various wastewaters. The monitoring point for the FGD
wastewater discharge could be at the final outfall. The EPA also
solicits comment on whether monitoring should be longer or shorter
duration than proposed and if additional monitoring locations may be
appropriate to capture other operational changes that the EPA has not
identified.
The EPA solicits comment on whether a facility should develop a
plan to minimize its use of bromide on a site-specific basis. Such a
plan could allow a facility to consider the costs of potential
approaches to minimizing bromide use in conjunction with its efforts to
meet other standards (e.g., MATS). Otherwise, facilities would minimize
the bromide in their discharges by switching to lower-bromide coals,
reducing bromide addition, and/or cutting back on refined coal use. The
EPA solicits comment on whether such a plan is appropriate for all
steam electric generators and, if so, the elements that might be
included in such a plan.
Regarding a bromide limitation based on product substitution, the
EPA solicits comment on whether a limitation could be established that
reflects the difference in concentrations naturally occurring in coal
as opposed to levels found in refined coal or from other halogen
applications. Alternatively, the EPA solicits comment on whether
facilities could certify that they do not burn refined coal and/or use
bromide addition processes. The EPA solicits data that supports
development of a numerical bromide limitation, or that demonstrates a
specific numerical bromide limitation to be inappropriate.
The Agency solicits input on the pros and cons of each of these
bromide sub-option approaches. Finally, the Agency solicits comment on
other pollutants, including other halides, discharged from steam
electric facilities that may impact the formation of disinfection
byproducts (DBPs).
F. Economic Achievability
As the EPA did for the 2015 rule, the Agency performed cost and
economic impact assessments using the Integrated Planning Model (IPM)
to determine the effect of the proposed ELGs, using a baseline that
incorporates impacts from other relevant environmental regulations (see
Chapter 5 in RIA). At the time of the 2015 rule, the IPM model showed a
total incremental closure of 843 MW of coal-fired generation as a
result of the ELGs, corresponding to a net effect of two boiler
closures.\78\ However, since that time, natural gas prices have
remained low, additional coal facilities have retired or refueled, and
changes that have been proposed to several environmental regulations
have been included in those model runs. Due to these changes, the EPA
ran an updated version of IPM. (See Section VIII.C.2 for additional
discussion on these updates.) This update showed that the 2015 rule
resulted in the closure of 1.8 GW of coal-fired generation,
corresponding to a net effect of approximately four boiler closures,
based on the average capacity of coal-fired electric boilers.
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\78\ In meetings with EPA since the 2015 rule, electric
utilities have expressed concerns that IPM underpredicts closures by
not accounting for the ability of facilities in regulated states to
cost recover even if they would otherwise lose money or are not
economical to operate.
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The EPA similarly ran the IPM model to determine the effect of the
regulatory options presented in Table VII-1. Options 2 and 4 bound the
costs to industry of these four options, IPM results from these options
alone reflect the range of impacts associated with all four regulatory
options.\79\ The IPM models for these two options were run prior to
finalization of the ACE rule (the impact of ACE is analyzed in a
separate sensitivity scenario) and ranged from a total net increase of
0.7 GW to 1.1 GW in coal-fired generating capacity compared to the 2015
rule, reflecting full compliance by all facilities. This capacity
increase corresponds to a net effect of one to two boiler closures
avoided as a result of this reconsideration action. These IPM results
indicate that the proposed Option 2 is economically achievable for the
steam electric power generating industry as a whole, as required by CWA
section 301(b)(2)(A). Following the promulgation of the ACE rule, the
EPA also conducted a sensitivity analysis that includes the effects of
that rule in the ELG analytic baseline. The results of this sensitivity
analysis, which are detailed in Appendix C of the RIA, also indicate
that the proposed Option 2 is economically achievable. The EPA will use
the latest IPM baseline, including the ACE rule as part of existing
regulations, when analyzing the ELG final rulemaking.
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\79\ Although Option 1 includes the less stringent chemical
precipitation technology, Option 2 has a greater savings due to
subcategorization of low utilization boilers.
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The EPA's economic achievability analysis for this and other
options is described in Section VIII, below.
G. Non-Water Quality Environmental Impacts
For the 2015 rule, the EPA performed an assessment of non-water
quality environmental impacts, including energy requirements, air
impacts, solid waste impacts, and changes in water use and found them
to be acceptable. The EPA has reevaluated these impacts in light of the
changed industry profile, as well as the proposed changes to BAT. Based
on the results of these analyses the EPA determined that Options 1, 2,
and 3 have acceptable non-water quality impacts. Option 4, however,
would result in unacceptable non-water quality environmental impacts
where management of the brine could divert FA that might otherwise be
sold for use in products (e.g., replacing Portland cement in concrete)
back toward placement in a landfill. See additional information in
Section 7 of the Supplemental TDD, as well as Section X of this
preamble.
H. Impacts on Residential Electricity Prices and Low-Income and
Minority Populations
As the EPA did for the 2015 rule, the Agency examined the effects
of today's regulatory options on consumers as an additional factor that
might be appropriate when considering what level of control represents
BAT. If all annualized compliance cost savings were passed on to
residential consumers of electricity, instead of being borne by the
operators and owners of facilities, the average monthly cost savings
under any of the options would be between $0.01 and 0.04 per month as
compared to the 2015 rule.
The EPA similarly evaluated the effect of today's regulatory
options on minority and low-income populations. As explained in Section
XII, the EPA used demographic data for populations potentially impacted
by steam electric power plant discharges due to their proximity (i.e.,
within 50 miles) to one
[[Page 64644]]
or more plants. For those populations, the EPA evaluated both
recreational and subsistence fisher populations. The analysis described
in Section XII indicates that absolute changes in human health impacts
are smaller than the overall impacts resulting from the 2015 rule.
However, low-income and minority populations are potentially affected
to a greater degree than the general population by discharges from
steam electric facilities and are expected to also accrue to a greater
degree than the general population the benefits of the proposed rule,
positive or negative.
I. Additional Rationale for the Proposed PSES
The EPA is continuing to rely on the pass-through analysis as the
basis of the limitations and standards in the 2015 rule. With respect
to FGD wastewater, as discussed above, the long-term averages for low
residence time biological treatment are very similar to or lower than
those achieved with high residence time biological systems. On this
basis, the EPA proposes to conclude that mercury, arsenic, selenium,
and nitrate/nitrite pass-through POTWs, as it concluded in the 2015
rule.
With respect to BA, the EPA notes that facilities converting to dry
handling or recycling all of their BA transport water would continue to
perform as the zero discharge systems the EPA used in its 2015 rule
pass-through analysis. As explained in Section VII.b.ii, for those
facilities using high rate recycle systems, the EPA proposes to allow a
discharge up to 10 percent of the system volume per day on a 30-day
rolling average and to subject such direct discharges to TSS
limitations of BPT. Consistent with the 2015 rule pass through
analysis, TSS is not considered to pass through and the EPA would not
establish TSS limitations under PSES.
Thus, like BAT, the EPA proposes to establish PSES based on Option
2: PSES for FGD wastewater based on chemical precipitation plus low
hydraulic residence time biological treatment, and PSES for BA
transport water based on dry handling or high recycle rate systems.\80\
The EPA proposes these technologies as the bases for PSES for the same
reasons that the EPA proposes the technologies as the bases for BAT,
and also proposes the same subcategories proposed for BAT.\81\
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\80\ Only two facilities currently discharge BA transport water
to POTWs, and EPA believes that both facilities qualify for the
proposed subcategorization for low utilization boilers. Thus, this
PSES may ultimately not apply to any facilities.
\81\ Where any of the subcategories would establish BAT based on
surface impoundments, with a restriction on TSS, there would be no
such parallel restriction for the analogous PSES subcategory because
POTWs effectively treat TSS.
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As with the final BAT effluent limitations, in considering the
availability and achievability of the final PSES, the EPA concluded
that existing indirect dischargers need some time to achieve the final
standards, in part to avoid forced outages (see Section VIII.C.7).
However, in contrast to the BAT limitations (which apply on a date
determined by the permitting authority that is as soon as possible
beginning November 1, 2020, but no later than December 31, 2023, for BA
transport water, and no later than December 31, 2025, for FGD
wastewater), facilities must meet the PSES no later than three years
after the effective date of any final rule. Under CWA section
307(b)(1), pretreatment standards shall specify a time for compliance
not to exceed three years from the date of promulgation, so the EPA
cannot establish a longer implementation period. Moreover, unlike
limitations on direct discharges, limitations on indirect discharges
are not implemented through an NPDES permit and thus are specified
clearly for the discharger without delay, without waiting some time for
the next permit issuance. The EPA has determined that all current
indirect dischargers can meet the standards within three years of the
effective date of any final rule (which the EPA projects will be issued
in the summer of 2020).
VIII. Costs, Economic Achievability, and Other Economic Impacts
The EPA evaluated the costs and associated impacts of the proposed
regulatory options on existing boilers at steam electric facilities.
These costs are analyzed within the context of compounding regulations
and other industry trends that have affected steam electric facilities
profitability and generation. These include the impacts of existing
environmental regulations (e.g., Cross-State Air Pollution Rule,
Mercury and Air Toxics Standards, CWA section 316(b) rule, final CCR
rule, final ACE rule), as well as other market conditions described in
Section V.B.\82\ This section provides an overview of the methodology
the EPA used to assess the costs and the economic impacts and
summarizes the results of these analyses. See the RIA in the docket for
additional detail.
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\82\ As discussed above, impacts of the final ACE rule will be
incorporated into this analysis after proposal, but were not
included here as the analyses for these proposed ELGs were completed
prior to the ACE rule being finalized.
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In developing ELGs, and as required by CWA section 301(b)(2)(A),
the EPA evaluates the economic achievability of regulatory options to
assess the impacts of applying the limitations and standards on the
industry as a whole, which typically includes an assessment of
incremental facility closures attributable to a regulatory option. As
described in more detail below, this proposed ELG is expected to
provide cost savings when compared to the baseline. Like the prior
analysis of the 2015 rule, the cost and economic impact analysis for
this proposed rulemaking focuses on understanding the magnitude and
distribution of compliance cost savings across the industry, and the
broader market impacts.
The EPA used certain indicators to assess the impacts of the
proposed regulatory options on the steam electric power generating
industry as a whole. These indicators are consistent with those used to
assess the economic achievability of the 2015 rule (80 FR 67838);
however, for this proposal, the EPA compared the values to a baseline
that reflects implementation of existing environmental regulations (as
of this proposal), including the 2015 rule. In the 2015 rule analysis,
the costs of achieving the 2015 rule requirements were reflected in the
policy cases analyzed rather than the baseline. Here, the baseline
appropriately includes costs for achieving the 2015 rule limitations
and standards, and the policy cases show the impacts resulting from
changes to those existing 2015 limitations and standards. More
specifically, the EPA considered the total cost to industry and change
in the number and capacity of specific boilers and facilities expected
to close under the options in this proposal (including proposed Option
2) compared to the estimated baseline costs. The EPA also analyzed the
ratio of compliance costs to revenue to see how the proposed regulatory
options change the number of facilities and their owning entities that
exceed certain thresholds indicating potential financial strain.
In addition to the analyses supporting the economic achievability
of the regulatory options, the EPA conducted other analyses to (1)
characterize other potential impacts of the regulatory options (e.g.,
on electricity rates), and (2) to meet the requirements of Executive
Orders or other statutes (e.g., Executive Order 12866, Regulatory
Flexibility Act, Unfunded Mandates Reform Act).
A. Facility-Specific and Industry Total Costs
The EPA estimated facility-specific costs to control FGD wastewater
and BA transport water discharges at existing boilers at steam electric
facilities to
[[Page 64645]]
which the ELGs apply.\83\ The EPA assessed the operations and treatment
system components currently in place at a given unit (or expected to be
in place as a result of other existing environmental regulations),
identified equipment and process changes that facilities would likely
make to meet the 2015 rule (for baseline) and each of the four
regulatory options presented in Table VII-1, and estimated the cost to
implement those changes. As explained in the Supplemental TDD, the
baseline also accounts for additional announced unit retirements,
conversions, and relevant operational changes that have occurred since
the EPA promulgated the 2015 rule. The EPA thus derived facility-level
capital and O&M costs for controlling FGD wastewater and BA transport
water using the technologies that form the bases of the 2015 rule, and
for each regulatory option presented in Table VII-1 for existing
sources. See Section 5 of the Supplemental TDD for a more detailed
description of the methodology the EPA used to estimate facility-level
costs for this proposal.
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\83\ The EPA did not estimate costs for other wastestreams not
in this proposal.
---------------------------------------------------------------------------
Following the same methodology used for the 2015 rule analysis, the
EPA used a rate of seven percent to annualize one-time costs and costs
recurring on other than on an annual basis over a specific useful life,
implementation, and/or event recurrence period. For capital costs and
initial one-time costs, the EPA used 20 years. For O&M costs incurred
at intervals greater than one year, EPA used the interval as the
annualization period (3 years, 5 years, 6 years, 10 years). The EPA
added annualized capital, initial one-time costs, and the non-annual
portion of O&M costs to annual O&M costs to derive total annualized
facility costs. The EPA then calculated total industry costs by summing
facility-specific annualized costs. For the assessment of industry
costs, the EPA considered costs on both a pre-tax and after-tax basis.
Pre-tax annualized costs provide insight on the total expenditure as
incurred, while after-tax annualized costs are a more meaningful
measure of impact on privately owned for-profit facilities and
incorporate approximate capital depreciation and other relevant tax
treatments in the analysis. The EPA uses pre- and/or after-tax costs in
different analyses, depending on the concept appropriate to each
analysis (e.g., social costs are calculated using pre-tax costs whereas
cost-to-revenue screening-level analyses are conducted using after-tax
costs).
Table VIII-1 summarizes estimates of incremental pre- and post-tax
industry costs for the four regulatory options presented in Table VII-1
as compared to the baseline. All four options provide cost savings
(negative incremental costs) as compared to the costs that the industry
would incur under the 2015 rule. Under all four options, some savings
are attributable to cheaper high recycle rate BA systems. Under Options
1, 2, and 3, additional savings are due to lower cost FGD wastewater
treatment systems (chemical precipitation and LRTR). Under Option 2,
further savings are attributable to the subcategorization of low
utilization boilers. Finally, some cost savings are due to the changes
in compliance timeframes discussed above in Section VII.D. The after-
tax savings range from approximately $26 million under Option 4 to $147
million under Option 2.\84\
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\84\ In response to additional information the EPA received from
a vendor showing installed costs of LRTR were lower than EPA's
predicted costs, and to account for the small difference in cost
between the sand filter and ultrafiltration polishing stage
technologies, the EPA conducted a sensitivity analysis (DCN
SE07120). Based on this analysis, the costs to install LRTR may be
approximately five percent lower than the LRTR cost estimates used
for developing the total costs presented in Table VIII-1.
Table VIII-1--Estimated Total Annualized Industry Costs
[Million of 2018$, seven percent discount rate]
------------------------------------------------------------------------
Regulatory option Pre-tax After-tax
------------------------------------------------------------------------
Option 1...................................... -$165.6 -$136.6
Option 2...................................... -175.6 -146.5
Option 3...................................... -126.3 -105.9
Option 4...................................... -25.5 -26.4
------------------------------------------------------------------------
B. Social Costs
Social costs are the costs of the proposed rule from the viewpoint
of society as a whole, rather than the viewpoint of regulated
facilities (which are private costs). In calculating social costs, the
EPA tabulated the pre-tax costs in the year when they are estimated to
be incurred. As described in Section VII.D of this preamble, the
proposed compliance deadlines and therefore the expected technology
implementation years vary across the regulatory options. The EPA
performed the social cost analysis over a 27-year analysis period of
2021-2047, which combines the length of the period during which
facilities are anticipated to install the control technologies (which
could be as late as 2028 under Option 4) and the useful life of the
longest-lived technology installed at any facility (20 years). The EPA
calculated the social cost of the proposed rule using both a three
percent discount rate and an alternative discount rate of seven
percent.
Social costs include costs incurred by both private entities and
the government (e.g., in implementing the regulation). As described
further in Chapter 10 of the RIA, the EPA did not evaluate the
incremental increase in the cost to state governments to evaluate and
incorporate BPJ into NPDES permits. EPA solicits comments on whether
these incremental costs are significant enough to be included.
Consequently, the only category of costs used to calculate social costs
are those pre-tax costs estimated for steam electric facilities. Note
that the annualized social costs presented in Table VIII-2 for the
seven percent discount rate differ from comparable pre-tax industry
compliance costs shown in Table VIII-1. The costs in TableVIII-1
represent the annualized costs of each option if they were incurred in
2020, whereas the annualized costs in Table VIII-2 are estimated based
on the stream of future costs starting in the year that individual
facilities are projected to actually comply with the requirements of
the proposed options under the availability timing proposed in Section
VII.D.
Table VIII-2 presents the total annualized social costs of the four
regulatory options presented in Table VII-1, compared to the baseline
and calculated using three percent and seven percent discount rates.
All four options provide cost savings (negative incremental costs)
compared to the baseline using a seven percent discount rate, and
Options 1, 2, and 3 also show cost savings using a three percent
discount rate. Option 2 has estimated annualized cost savings of $166.2
million using a seven percent discount rate and $136.3 million using a
three percent discount rate.
Table VIII-2--Estimated Total Annualized Social Costs
[Million of 2018$, three and seven percent discount rate]
------------------------------------------------------------------------
3% Discount 7% Discount
Regulatory option rate rate
------------------------------------------------------------------------
Option 1...................................... -$130.6 -$154.0
Option 2...................................... -136.3 -166.2
Option 3...................................... -90.1 -119.5
Option 4...................................... 11.9 -27.3
------------------------------------------------------------------------
C. Economic Impacts
The EPA assessed the economic impacts of this proposed rule in two
ways: (1) A screening-level assessment of the cost impacts on existing
boilers at steam electric facilities and the entities
[[Page 64646]]
that own those facilities, based on comparison of costs to revenue; and
(2) an assessment of the impact of the regulatory options presented in
Table VII-1 within the context of the broader electricity market, which
includes an assessment of changes in predicted facility closures
attributable to the options. The following sections summarize the
results of these analyses. The RIA discusses the methods and results in
greater detail.
The first set of cost and economic impact analyses--at both the
facility and parent company levels--provide screening-level indicators
of the impacts of costs for FGD wastewater and BA transport water
controls relative to historical operating characteristics of steam
electric facilities incurring those costs (i.e., level of electricity
generation and revenue). The EPA conducted these analyses for the
baseline and for the four regulatory options presented in Table VII-1,
and then compared these impacts to understand the incremental effects
of the regulatory options in this proposal. The second set of analyses
look at broader electricity market impacts considering the
interconnection of regional and national electricity markets. It also
looks at the distribution of impacts at the facility and boiler level.
This second set of analyses provides insight on the impacts of the
regulatory options in this proposal on steam electric facilities, as
well as the electricity market as a whole, including changes in
generation capacity, generation, and wholesale electricity prices. The
market analysis compares model predictions for the options to a base
case that includes the predicted and observed economic and market
effects of the 2015 rule. The EPA used results from the screening
analysis of facility- and entity-level impacts, together with changes
in projected capacity closure from the market model, to understand the
impacts of the regulatory options in this proposal relative to the
baseline.
1. Screening-Level Assessment
The EPA conducted a screening-level analysis of each regulatory
option's potential impact to existing boilers at steam electric
facilities and parent entities based on cost-to-revenue ratios. For
each of the two levels of analysis (facility and parent entity), the
Agency assumed, for analytic convenience and as a worst-case scenario,
that none of the compliance costs would be passed on to consumers
through electricity rate increases and would instead be absorbed by the
steam electric facilities and their parent entities. This assumption
overstates the impacts of compliance expenditures since steam electric
facilities that operate in a regulated market may be able to pass on
changes in production costs to consumers through changes in electricity
prices. It is, however, an appropriate assumption for a screening-level
estimate of the potential cost impacts.
a. Facility-Level Cost-to-Revenue Analysis
The EPA developed revenue estimates for this analysis using EIA
data. The EPA then calculated the change in the annualized after-tax
costs of the four regulatory options presented in Table VII-1 as a
percent of baseline annual revenues. See Chapter 4 of the RIA for a
more detailed discussion of the methodology used for the facility-level
cost-to-revenue analysis.
Cost-to-revenue ratios are used to describe impacts to entities
because they provide screening-level indicators of potential economic
impacts. Just as for the facilities owned by small entities under
guidance in U.S. EPA (2006),\85\ the full range of facilities incurring
costs below one percent of revenue are unlikely to face economic
impacts, while facilities with costs between one percent and three
percent of revenue have a higher chance of facing economic impacts, and
facilities incurring costs above three percent of revenue have a still
higher probability of economic impacts.
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\85\ U.S. EPA (Environmental Protection Agency). 2006. EPA's
Action Development Process: Final Guidance for EPA Rulewriters:
Regulatory Flexibility Act as amended by the Small Business
Regulatory Enforcement Fairness Act. November 2006. Available online
at: https://www.epa.gov/reg-flex/epas-action-development-process-final-guidance-epa-rulewriters-regulatory-flexibility-act.
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As a result of the 2015 rule (baseline), the EPA estimated that 18
facilities incur costs greater than or equal to one percent of revenue,
including six facilities that have costs greater than or equal to three
percent of revenue, and an additional 96 facilities incur costs that
are less than one percent of revenue. By contrast, the four regulatory
options the EPA analyzed for this proposal are estimated to provide
cost savings that reduce this impact to various degrees, with Option 2
showing the largest reductions in cost. Options 1, 3, and 4 show an
estimated 16 to 19 facilities with costs greater than or equal to one
percent of revenue, including four or five facilities with costs
greater than or equal to three percent of revenue. Under Option 2, the
EPA estimated that eight facilities incur costs greater than or equal
to one percent of revenue, including two facilities that have costs
greater than or equal to three percent of revenue, and an additional
100 facilities incur costs that are less than one percent of revenue.
b. Parent Entity-Level Cost-to-Revenue Analysis
The EPA also assessed the economic impact of the regulatory options
presented in Table VII-1 at the parent entity level. The screening-
level cost-to-revenue analysis at the parent entity level provides
insight on the impact on those entities that own existing boilers at
steam electric facilities. In this analysis, the domestic parent entity
associated with a given facility is defined as that entity with the
largest ownership share in the facility. For each parent entity, the
EPA compared the incremental change in the total annualized after-tax
costs and the total revenue for the entity compared to the baseline
(see Chapter 4 of the RIA for details). Following the methodology
employed in the analyses for the 2015 rule (80 FR 67838), the EPA
considered a range of estimates for the number of entities owning an
existing boiler at a steam electric power facility to account for
partial information available for steam electric facilities that are
not expected to incur ELG compliance costs.
Similar to the facility-level analysis above, cost-to-revenue
ratios provide screening-level indicators of potential economic
impacts, this time to the owning entities; higher ratios suggest a
higher probability of economic impacts. The EPA estimated that the
number of entities owning existing boilers at steam electric facilities
ranges from 243 (lower-bound estimate) to 478 (upper-bound estimate),
depending on the assumed ownership structure of facilities not
incurring ELG costs and not explicitly analyzed. The EPA estimates that
in the baseline 236 to 470 parent entities, respectively, would either
incur no costs or the annualized cost they incur to meet the 2015 rule
BAT limitations and pretreatment standards would represent less than
one percent of their revenues.
Compared to the baseline, all four regulatory options reduce the
impacts on the small number of entities incurring costs. The changes
are greatest for Option 2, which has five fewer entities with costs
exceeding one percent of revenue, including one less entity with costs
exceeding three percent of revenue, with the remaining entities either
having no cost, or costs that are less than one percent of revenue.
Options 1 and 3 each have two fewer entities in the one to three
percent of revenue category, and Option 4 has
[[Page 64647]]
one fewer entity in the one to three percent of revenue category.
2. Electricity Market Impacts
In analyzing the impacts of regulatory actions affecting the
electric power sector, the EPA used IPM, a comprehensive electricity
market optimization model that can evaluate such impacts within the
context of regional and national electricity markets. The model is
designed to evaluate the effects of changes in boiler-level electric
generation costs on the total cost of electricity supply, subject to
specified demand and emissions constraints. Use of a comprehensive,
market analysis system is important in assessing the potential impact
of any power facility regulation because of the interdependence of
electric boilers in supplying power to the electric transmission grid.
Changes in electricity production costs at some boilers can have a
range of broader market impacts affecting other boilers, including the
likelihood that various units are dispatched, on average. The analysis
also provides important insight on steam electric capacity closures
(e.g., retirements of boilers that become uneconomical relative to
other boilers), or avoided closures, based on a more detailed analysis
of market factors than in the screening-level analyses above. The
results further inform the EPA's understanding of the potential impacts
of the regulatory options presented in Table VII-1. For the current
analyses, the EPA used version 6 (V6) of IPM to analyze the impacts of
the regulatory options. IPM V6 is based on an inventory of U.S.
utility- and non-utility-owned boilers and generators that provide
power to the integrated electric transmission grid, including
facilities to which the ELGs apply. IPM V6 embeds an energy demand
forecast that is derived from DOE's ``Annual Energy Outlook 2018'' (AEO
2018). IPM V6 also incorporates the expected compliance response to
existing regulatory requirements for regulations affecting the power
sector (e.g., Cross-State Air Pollution Rule (CSAPR) and CSAPR Update
Rule, Mercury and Air Toxics Rule (MATS), the Cooling Water Intake
Structure (CWIS) rule, and 2015 CCR rule, as well as the 2015 rule).
Federal CO2 standards for existing sources are not modeled
in IPM V6, owing to ongoing litigation.
The EPA analyzed proposed Option 2 and Option 4 using IPM V6. As
discussed in Section VIII.A, these two options have the greatest and
least cost savings, respectively, compared to the baseline, and
therefore reflect the full range of potential impacts from the
regulatory options in this proposal. In addition, following
promulgation of the ACE final rule, EPA also analyzed proposed Option 2
relative to a baseline that includes the ACE rule. See Appendix C in
the RIA for details of these results.
In contrast to the screening-level analyses, which are static
analyses and do not account for interdependence of electric boilers in
supplying power to the electricity transmission grid, IPM V6 accounts
for potential changes in the generation profile of steam electric and
other boilers and consequent changes in market-level generation costs,
as the electric power market responds to changes in generation costs
for steam electric boilers due to the regulatory options. Additionally,
in contrast to the screening-level analyses, in which the EPA assumed
no cost pass through of ELG compliance costs, IPM V6 depicts production
activity in wholesale electricity markets where the specific increases
in electricity prices for individual markets would result in some
recovery of compliance costs for plants in those markets.
In analyzing the regulatory options presented in Table VII-1, the
EPA estimated changes in fixed and variable costs for the steam
electric facilities and boilers already incurring costs in the baseline
to instead incur costs (or avoid incurring costs) to comply with Option
2 and Option 4. Because IPM is not designed to endogenously model the
selection of wastewater treatment technologies as a function of
electricity generation, effluent flows, and pollutant discharge, the
EPA estimated these costs exogenously for each steam electric
generating unit and input these costs into the IPM model as fixed and
variable O&M cost adders. The EPA then ran IPM V6 including these new
cost estimates to determine the dispatch of electric boilers that would
meet projected demand at the lowest costs, subject to the same
constraints as those present in the baseline analysis. The estimated
changes in facility- and boiler-specific production levels and costs--
and, in turn, changes in total electric power sector costs and
production profile--are key data elements in evaluating the expected
national and regional effects of the regulatory options in this
proposal, including closures or avoided closures of steam electric
boilers and facilities. The EPA considered impact metrics of interest
at three levels of aggregation: (1) Impact on national and regional
electricity markets (all electric power generation, including steam and
non-steam electric facilities); (2) impact on steam electric facilities
as a group, and (3) impact on individual steam electric facilities
incurring costs. Chapter 5 of the RIA discusses the first analysis; the
sections below summarize the last two, which are further described in
Chapter 5 and in Appendix C of the RIA. All results presented below are
representative of modeled market conditions in the years 2028-2033,
when the rule would either be implemented or plans for implementation
by the end of 2028 would be well underway at all facilities.
a. Impacts on Existing Steam Electric Facilities
The EPA used IPM V6 results for 2030 \86\ to assess the potential
impact of the regulatory options presented in Table VII-1 on existing
boilers at steam electric facilities. The purpose of this analysis is
to assess any fleetwide changes from baseline impacts on boilers at
steam electric facilities. Table VIII-3 reports estimated results for
existing boilers at steam electric facilities, as a group. The EPA
looked at the following metrics: (1) Incremental (and avoided) early
retirements and capacity closures, calculated as the difference between
capacity under the regulatory option and capacity under the baseline;
(2) incremental capacity closures as a percentage of baseline capacity;
(3) change in electricity generation from facilities regulated by ELGs;
(4) changes in variable production costs per MWh, calculated as the sum
of total fuel and variable O&M costs divided by net generation; and (5)
changes in annual costs (fuel, variable O&M, fixed O&M, and capital).
Note that changes in electricity generation presented in Table VIII-3
are attributable both to changes in retirements, as well as changes in
capacity utilization at boilers and plants whose retirement status does
not change.
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\86\ IPM model year 2030 represents years 2028-2033.
[[Page 64648]]
Table VIII-3--Estimated Impact on Steam Electric Facilities as a Group at the Year 2030
----------------------------------------------------------------------------------------------------------------
Change attributable to regulatory option as compared to
baseline
---------------------------------------------------------------
Metric Baseline value Option 2 Option 4
---------------------------------------------------------------
Value Percent Value Percent
----------------------------------------------------------------------------------------------------------------
Total capacity (MW)............. 336,872 2,880 0.9 3,194 0.9
Early retirements or closures 58,192 -2,880 -4.9 -3,194 -5.5
\a\ (MW).......................
Early retirements or closures 79 0 0.0 -1 -1.3
\a\ (number of plants).........
Total generation (GWh).......... 1,570,513 4,676 0.3 1,235 0.1
Variable production cost (2018$/ $26.00 $0.02 0.1 $0.05 0.2
MWh)...........................
Annual costs (million 2018$).... $60,298 $98 0.2 $103 0.1
----------------------------------------------------------------------------------------------------------------
\a\ Values for incremental early retirements or closures represent change relative to the baseline. IPM may show
partial (unit) or full facility early retirements (closures). It may also show avoided closures (negative
closure values) in which a boiler or facility that is projected to close in the baseline is estimated to
continue operating in the policy case.
Under proposed Option 2, generation at steam electric facilities is
projected to increase by 4,676 GWh (0.3 percent) nationally, when
compared to the baseline. IPM V6 projects a net increase in total steam
electric capacity by 2,880 MW or approximately 0.9 percent of total
baseline capacity, but no net change in the number of full facility
retirements and the net avoidance of three partial retirements (unit
closures) nationwide indicating a higher capacity utilization by these
facilities. See Section 5.2.2.2 in the RIA for details.
IPM V6 projects generation at steam electric facilities increases
under Option 4 by 1,235 GWh (0.1 percent) nationally, which is smaller
in magnitude than the increase under Option 2. National level results
for steam electric facilities under Option 4 show an increase in total
steam electric capacity of 3,194 MW (0.9 percent of the baseline). At
the national level, IPM projects one net avoided full facility closure
and the same three avoided partial retirements as for Option 2. See
Section 5.2.2.2 in the RIA for details.
These findings suggest that all of the regulatory options in this
proposal can be expected to have small economic consequences for the
steam electric facilities as a group. Options 2 and 4 also affect the
operating status of very few steam electric facilities, with no net
change in facility closures under Option 2, and one net avoided closure
under Option 4.\87\ For further discussion of closures and related
distributional impacts, see Chapter 5 of the RIA.
---------------------------------------------------------------------------
\87\ The additional closure under Option 2 is not a result of
the facility incurring costs under this proposed rule. The IPM model
predicts this facility becomes uneconomical due to the increased
generation from other coal facilities in the same NERC region.
---------------------------------------------------------------------------
Because the analysis of the proposed options discussed in the RIA
was completed before the EPA finalized the ACE rule, this analysis does
not include the projected effects of the ACE rule. Thus, the EPA
conducted a supplemental IPM run with the costs of Option 2 on a
baseline that includes the ACE illustrative case presented in the ACE
final rule (see Appendix C in RIA). A summary of these results is
presented in Table VIII-4.
Table VIII-4--Estimated Impact of ELG Option 2 on Steam Electric Power Plants as a Group at the Year 2030, for
Sensitivity Analysis Including ACE Final Rule
----------------------------------------------------------------------------------------------------------------
Option 2 with ACE rule
Metric Baseline with -----------------------------------------------
ACE rule Value Difference Percent change
----------------------------------------------------------------------------------------------------------------
Early retirements or closures \a\ (MW).......... 336,547 339,654 -3,107 -0.9
Early retirements or closures \a\ (number of 78 79 1 1.3
plants)........................................
Total generation (GWh).......................... 1,569,109 1,576,455 7,345 0.5
Variable production cost (2018$/MWh)............ $25.85 $25.87 $0.02 0.1
Annual costs (million 2018$).................... $60,387 $60,578 $191 0.3
----------------------------------------------------------------------------------------------------------------
\a\ Values for incremental early retirements or closures represent change relative to the baseline. IPM may show
partial (unit) or full facility early retirements (closures). It may also show avoided closures (negative
closure values) in which a boiler or facility that is projected to close in the baseline is estimated to
continue operating in the policy case.
Examining the incremental impacts of Option 2 on a baseline
including ACE, generation at steam electric facilities is projected to
increase by 3,107 GWh (0.9 percent) nationally. IPM V6 projects a net
increase in total steam electric capacity by 7,345 MW or approximately
0.5 percent of total baseline capacity. There is one incremental full
facility retirement as well as the net avoidance of four partial
retirements (unit closures) nationwide indicating a higher capacity
utilization by these facilities. See Appendix C of the RIA for further
details.
b. Impacts on Individual Facilities Incurring Costs
To assess potential facility-level effects, the EPA also analyzed
facility-specific changes attributable to the regulatory options in
Table VII-1 for the following metrics: (1) Capacity utilization
(defined as annual generation (in MWh) divided by [capacity (MW) times
8,760 hours]) (2) electricity generation, and (3) variable production
costs per MWh, defined as variable O&M cost plus fuel cost divided by
net generation. The analysis of changes in individual facilities is
detailed in Chapter 5 of the RIA.
The results for both Option 2 and Option 4 show no change, or less
than a one percent reduction or one percent increase for steam electric
facilities projected to incur ELG compliance costs. For Option 2, a
greater number of facilities see improving operating
[[Page 64649]]
conditions (i.e., higher capacity utilization or generation, lower
variable production costs) than deteriorating conditions. Effects under
Option 4 are similar, although approximately the same number of
facilities see positive changes in operating conditions as negative
changes. Thus, the results for the subset of facilities incurring costs
further support the conclusion that the effects of any of the
regulatory options in this proposed rule on the steam electric power
generating industry will be less than that of the 2015 rule. This
conclusion holds when including the effects of the ACE final rule, as
detailed in Appendix C of the RIA for proposed Option 2.
IX. Changes to Pollutant Loadings
In developing ELGs, the EPA typically evaluates the pollutant
loading reductions of regulatory options to assess the impacts of the
compliance requirements on discharges from the industry as a whole. In
estimating pollutant reductions associated with this proposal, the EPA
took the same approach as described above for facility-specific costs.
That is, the EPA compared the values to a baseline that reflects
implementation of existing environmental regulations, including the
2015 rule. In the 2015 rule, the baseline did not reflect pollutant
loading reductions for achieving the 2015 rule requirements as that
impact is what EPA analyzed. Here, the baseline appropriately includes
pollutant loading reductions for achieving the 2015 rule requirements
as the EPA is analyzing the impact resulting from any changes to those
requirements. More specifically, the EPA considered the change in the
pollutant loading reductions associated with the regulatory options in
this proposal to those projected under the baseline.
The general methodology that the EPA used to calculate pollutant
loadings is the same as that described in the 2015 rule. The EPA used
data collected for the 2015 rule, as well as the data described in
Section VI, to characterize pollutant concentrations for FGD wastewater
and bottom ash transport water. The EPA evaluated these data sources to
identify analytical data that meet EPA's acceptance criteria for
inclusion in analyses for characterizing discharges of FGD wastewater
and bottom ash transport water. For each plant discharging FGD
wastewater or bottom ash transport water, the EPA used data from the
2009 survey and/or industry-submitted data to determine the discharge
flow rates for FGD wastewater and bottom ash transport water. The EPA
adjusted the discharge flow rates used in the pollutant loadings
estimates to account for retirements, fuel conversions, and other
changes in operations scheduled to occur by December 31, 2028,
described in Section 6 of the Supplemental TDD, that will eliminate or
alter the discharge of an applicable wastestream. Finally, the Agency
adjusted the discharge flow rates to account for changes in plant
operations to optimize FGD wastewater flows and to comply with the CCR
rule. For further discussion of these adjustments see Section 6.2.2 and
6.3.2 of the Supplemental TDD, respectively.
The EPA first estimated--on an annual, per facility basis--the
pollutant discharge load for FGD wastewater and BA transport water
associated with the technology basis evaluated for facilities to comply
with the 2015 rule requirements for FGD wastewater and BA transport
water relative to the conditions currently present or planned at each
facility. The EPA similarly estimated facility-specific post-compliance
pollutant loadings associated with the technology bases for facilities
to comply with effluent limitations based on each of the regulatory
options in this proposal. For each regulatory option, the EPA then
calculated the changes in pollutant loadings at a particular facility
as the sum of the differences between the estimated baseline and post-
compliance discharge loadings for each applicable wastestream.
For those facilities that discharge indirectly to POTWs, the EPA
adjusted the baseline and option loadings to account for pollutant
removals expected from POTWs. These adjusted pollutant loadings for
indirect dischargers therefore approximate the resulting discharges to
receiving waters. For additional details on the methodology the EPA
used to calculate pollutant loading reductions, see Section 6 of the
Supplemental TDD.
A. FGD Wastewater
For FGD wastewater, the EPA continued to use the average pollutant
effluent concentration with facility-specific discharge flow rates to
estimate the mass pollutant discharge per facility for baseline and
each regulatory option in Table VII-1. The EPA used data compiled for
the 2015 rule as the initial basis for estimating discharge flow rates
and updated the data to reflect retirements or other relevant changes
in operation. For example, the EPA reviewed state and EIA data to
identify flow rates for new scrubbers that have come online since the
2015 rule. The EPA also accounted for increased rates of recycle
through the scrubber that would affect the discharge flow.
The EPA assigned pollutant concentrations for each analyte based on
the operation of a treatment system designed to comply with the
baseline or the regulatory options considered. The EPA used data
compiled for the 2015 rule to characterize untreated FGD purge,
chemical precipitation effluent, and chemical precipitation plus high
hydraulic residence time biological reduction effluent. The EPA used
data provided by industry to characterize effluent quality for chemical
precipitation plus LRTR and membrane filtration effluent. In addition,
the EPA used data provided by industry and other stakeholders as
described in Section VI of this preamble to quantify bromide in FGD
wastewater under baseline conditions and for the regulatory options.
B. BA Transport Water
The EPA estimated baseline and post-compliance loadings for each
regulatory option in Table VII-1 using pollutant concentrations for BA
transport water and facility-specific flow rates. The EPA used data
compiled for the 2015 rule as the basis for estimating BA transport
water discharge flows and updated the data set to reflect retirements
and other relevant changes in operation (e.g., ash handling
conversions, fuel conversions) that occurred after the 2015 rule data
were collected. For the high recycle rate technology option, the EPA
also estimated discharge flows associated with the purge from remote
MDS operation, based on the boiler capacity and the volume of the
remote MDS. Under the baseline, which reflects the 2015 rule limitation
of zero discharge, the EPA estimated a flow rate of zero.
For this proposed rule, in response to the administrative petitions
discussed in Section IV of this preamble, the EPA was able to use a
revised set of the 2015 rule analytical data to characterize BA
transport water effluent from steam electric facilities. As an example,
the EPA re-evaluated and revised, as appropriate, its data sets in
light of questions petitioners raised about the inclusion and validity
of certain data due, in part, to what the petitioners assert are flaws
in data acceptance criteria, obsolete analytical methods, and the
treatment of non-detect analytical results, which petitioners believed
resulted in an overestimation of pollutant loadings resulting from
current practices for BA transport water, in turn resulting in an
overestimation of pollutant removals under the 2015 rule. The EPA also
updated the data set and incorporated BA transport water
[[Page 64650]]
sampling data submitted by industry during the final months of the 2015
rule and as part of a voluntary sampling program described in Section
VI of this preamble. For a detailed discussion, see Section 6 of the
Supplemental TDD.
C. Summary of Incremental Changes of Pollutant Loadings From Proposed
Regulatory Options
Table IX-1 summarizes the net change to annual pollutant loadings,
compared to baseline, associated with each regulatory option in Table
VII-1.
Table IX-1--Estimated Incremental Changes to Annual Pollutant Loading
for Proposed Regulatory Options 1, 2, 3, and 4 [in pounds/year] Compared
to Baseline
------------------------------------------------------------------------
Changes in pollutant
Regulatory option \a\ loadings
------------------------------------------------------------------------
1......................................... 13,400,000
2......................................... -104,000,000
3......................................... -276,000,000
4......................................... -1,320,000,000
------------------------------------------------------------------------
Note: Changes in pollutant loadings are rounded to three significant
figures.
\a\ Negative values represent an estimated decrease in loadings to
surface waters compared to baseline. Positive values represent an
estimated increase in loadings to surface waters compared to baseline.
Compared to the 2015 rule, Options 2, 3 and 4 result in decreased
pollutant loadings to surface waters. Reductions under Options 2 and 3
would be realized to the extent that operators chose to meet the
limitations based on membrane filtration under the proposed revisions
of VIP for FGD wastewater. Under Option 2, the EPA estimated that 18
plants (27 percent of plants estimated to incur FGD compliance costs)
would 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).
X. Non-Water Quality Environmental Impacts
The elimination or reduction of one form of pollution may create or
aggravate other environmental problems. Therefore, Sections 304(b) and
306 of the Act require the EPA to consider non-water quality
environmental impacts (including energy impacts) associated with ELGs.
Accordingly, the EPA has considered the potential impact of the
regulatory options in today's proposal on air emissions, solid waste
generation, and energy consumption. For the reasons described in
Section IX of this preamble, the baseline for these analyses
appropriately includes non-water quality environmental impacts
associated with achieving the 2015 rule requirements, and the EPA is
analyzing the incremental impacts resulting from the regulatory options
presented in Table VII-1 compared to those projected under the
baseline. In general, the EPA used the same methodology to conduct the
current analysis (with updated data as applicable) as it did for the
analysis supporting the 2015 rule. The following summarizes the
methodology and results. See Section 7 of the Supplemental TDD for
additional details.
A. Energy Requirements
Steam electric facilities use energy when transporting ash and
other solids on or off site, operating wastewater treatment systems
(e.g., chemical precipitation, biological treatment), or operating ash
handling systems. For today's proposal, the EPA considered whether
there would be an associated change in the incremental energy
requirements compared to baseline. Energy requirements vary depending
on the regulatory option evaluated and the current operations of the
facility. Therefore, as applicable, the EPA estimated the increase in
energy usage in megawatt hours (MWh) for equipment added to the
facility systems or in consumed fuel (gallons) for transportation/
operating equipment for baseline and all regulatory options. The EPA
summed the facility-specific estimates to calculate the net change in
energy requirements from baseline for the regulatory options.
The EPA estimated the amount of energy needed to operate wastewater
treatment systems and ash handling systems based on the horsepower
rating of the pumps and other equipment. The EPA also estimated the
fuel consumption associated with the changes in transportation needed
to landfill solid waste and combustion residuals (e.g., ash) at steam
electric facilities (on-site or off-site). The frequency and distance
of transport depends on a facility's operation and configuration;
specifically, the volume of waste generated and the availability of
either an on-site or off-site non-hazardous landfill and its distance
from the facility. Table X-1 shows the net change in annual electrical
energy usage associated with the regulatory options compared to
baseline, as well as the net change in annual fuel consumption
requirements associated with the regulatory options compared to
baseline.
Table X-1--Estimated Incremental Change in Energy Requirements Associated With Regulatory Options Compared to
Baseline
----------------------------------------------------------------------------------------------------------------
Energy use associated with regulatory options \a\
Non-water quality impact ---------------------------------------------------------------
Option 1 Option 2 Option 3 Option 4
----------------------------------------------------------------------------------------------------------------
Electrical Energy Used (MWh).................... -82,300 -54,570 -27,000 94,000
Fuel Used (Thousand Gallons).................... 0 -48,000 40,000 243,000
----------------------------------------------------------------------------------------------------------------
\a\ Negative values represent a decrease in energy use compared to baseline. Positive values represent an
increase in energy use compared to baseline.
[[Page 64651]]
B. Air Pollution
The regulatory options are expected to affect air pollution through
three main mechanisms: (1) Changes in auxiliary electricity use by
steam electric facilities to operate wastewater treatment, ash
handling, and other systems needed to meet regulatory standards; (2)
changes to transportation-related emissions due to the trucking of CCR
waste to landfills; and (3) the change in the profile of electricity
generation due to any regulatory requirements. This section discusses
air emission changes associated with the first two mechanisms and
presents the corresponding estimated net change in air emissions. See
Section XII of this preamble for additional discussion of the third
mechanism.
Steam electric facilities generate air emissions from operating
transport vehicles, such as dump trucks, which release criteria air
pollutants and greenhouse gases when operated. Similarly, a decrease in
energy use or vehicle operation would result in decreased air
pollution.
To estimate the net air emissions associated with changes in
electrical energy use projected as a result of the regulatory options
in today's proposal compared to baseline, the EPA combined the energy
usage estimates with air emission factors associated with electricity
production to calculate air emissions associated with the incremental
energy requirements. The EPA used emission factors projected by IPM V6
(ton/MWh) for nitrogen oxides, sulfur dioxide, and carbon dioxide to
generate estimates of the changes in air emissions associated with
changes in energy production for Options 2 and 4 compared to
baseline.\88\
---------------------------------------------------------------------------
\88\ Only Options 2 and 4 were run through IPM; however,
extrapolated net benefits from air impacts for Options 1 and 3 are
available in Chapter 8 of the Benefit Cost Analysis report.
---------------------------------------------------------------------------
To estimate net air emissions associated with the change in
operation of transport vehicles, the EPA used the MOVES2014b model to
identify air emission factors (grams per mile) for the air pollutants
of interest. The EPA estimated the annual number of miles that dump
trucks moving ash or wastewater treatment solids to on- or off-site
landfills would travel for the regulatory options. The EPA used these
estimates to calculate the net change in air emissions for the Options
2 and 4 compared to baseline. Table X-2 presents EPA's estimated net
change in air emissions associated with auxiliary electricity and
transportation.
Table X-2--Estimated Net Change in Industry-Level Air Emissions Associated With Auxiliary Electricity and
Transportation for Options Compared to Baseline a b
----------------------------------------------------------------------------------------------------------------
Change in emissions-- Change in emissions--
Non-water quality impact Option 2 (tons/year) Option 4 (tons/year)
\b\ \c\
----------------------------------------------------------------------------------------------------------------
NOX........................................................... -32.7 32.7
SOX........................................................... -54.3 20.4
CO2........................................................... -44,600 60,600
----------------------------------------------------------------------------------------------------------------
\a\ Negative values represent a decrease in energy use compared to baseline. Positive values represent an
increase in energy use compared to baseline.
\b\ Option 2 estimates are based on the IPM sensitivity analysis scenario that includes the ACE rule in the
baseline (IPM-ACE).
\c\ Option 4 estimates are based on IPM analysis scenario that does not include the ACE rule in the baseline.
The modeled output from IPM V6 predicts changes in electricity
generation due to compliance costs attributable to Options 2 and 4
compared to baseline. These changes in electricity generation are, in
turn, predicted to affect the amount of NOX, SO2,
and CO2 emissions from steam electric facilities. A summary
of the net change in annual air emissions under Options 2 and 4 for all
three mechanisms is shown in Table X-3. Similar to costs, the IPM V6
results from these options reflect the range of NWQEI associated with
all four regulatory options. To provide some perspective on the
estimated changes in annual air emissions, EPA compared the estimated
change in air emissions to the net amount of air emissions generated in
a year by all electric power facilities throughout the United States.
For a more details on the sources of air emission changes, see Section
7 of the Supplemental TDD.
Table X-3--Estimated Net Change in Industry-Level Air Emissions Associated With Changes in Electricity
Generation for Options Compared to Baseline
----------------------------------------------------------------------------------------------------------------
2016 Emissions by
Change in emissions-- Change in emissions-- electric power
Non-water quality impact Option 2 (million tons) Option 4 (million tons) generating industry
\a\ \b\ (million tons)
----------------------------------------------------------------------------------------------------------------
NOX.................................. 0.005 0.001 1.47
SOX.................................. 0.005 0.002 1.63
CO2.................................. 5.66 1.24 2,030
----------------------------------------------------------------------------------------------------------------
\a\ Option 2 emissions are based on the IPM sensitivity analysis scenario that includes the ACE rule in the
baseline.
\b\ Option 4 emissions are based on the IPM sensitivity analysis scenario that does not include the ACE rule in
the baseline.
C. Solid Waste Generation and Beneficial Use
Steam electric facilities generate solid waste associated with
sludge from wastewater treatment systems (e.g., chemical precipitation,
biological treatment). The EPA estimated the change in the amount of
solids generated under each regulatory option for each facility in
comparison to the baseline. For FGD wastewater treatment, Regulatory
Options 2, 3, and 4 result in an increase in the amount of solid waste
generated compared to baseline. The
[[Page 64652]]
solid waste generation associated with Option 1 is comparable to
baseline. While BA solids are also generated at steam electric
facilities, all of the BA solids accounted for in the waste volumes
disposed in the 2015 rule analysis were suspended solids from
combustion, and therefore the regulatory options in today's proposal do
not alter the amount of BA or other combustion residuals generated.
Table X-4 shows the net change in annual solid waste generation,
compared to baseline, associated with the proposed regulatory options.
Table X-4--Estimated Incremental Changes to Solid Waste Generation Associated With Regulatory Options Compared
to Baseline
----------------------------------------------------------------------------------------------------------------
Solid waste generation associated with regulatory options
Non-water quality impact -------------------------------------------------------------------
Option 1 Option 2 Option 3 Option 4
----------------------------------------------------------------------------------------------------------------
Solids Generated (tons/year)................ 0 328,000 487,000 2,326,000
----------------------------------------------------------------------------------------------------------------
The EPA also evaluated the potential impacts of diverting FA from
current beneficial uses toward encapsulation of brine (from membrane
filtration) for disposal in landfills. According to the latest ACAA
survey,\89\ over half of the FA generated by coal-fired facilities is
being sold for beneficial uses rather than disposed of, and the
majority of this beneficially used FA is replacing Portland cement in
concrete. This also holds true for the specific facilities currently
discharging FGD wastewater, as seen by sales of FA in the 2016 EIA-923
Schedule 8A.\90\ Summary statistics of the FA beneficial use percentage
for these facilities are displayed in Table X-5 below.
---------------------------------------------------------------------------
\89\ Available online at: https://www.acaa-usa.org/Portals/9/Files/PDFs/2016-Survey-Results.pdf.
\90\ Available online at: https://www.eia.gov/electricity/data/eia923/.
Table X-5--Percent of FA Sold for Beneficial Use by Facilities
Discharging FGD Wastewater
------------------------------------------------------------------------
Percent of FA
Statistic sold for
beneficial use
------------------------------------------------------------------------
Min..................................................... 0
10th percentile......................................... 0
25th percentile......................................... 3
Mean.................................................... 48
Median.................................................. 50
75th percentile......................................... 88
90th percentile......................................... 98
Max..................................................... 100
------------------------------------------------------------------------
In the EPA's coal combustion residuals disposal rule,\91\ the EPA
noted that FA replacing Portland cement in concrete would result in
significant avoided environmental impacts to energy use, water use,
greenhouse gas emissions, air emissions, and waterborne wastes.
Although the EPA cannot tie specific facilities selling their FA to
this specific beneficial use, over half of the FA beneficially used
currently replaces Portland cement in concrete. Therefore, where sale
for this particular beneficial use occurs by facilities that may
otherwise use their fly ash to encapsulate membrane filtration brine
under Option 4, the EPA proposes to find that unacceptable air and
other non-water quality environmental impacts will result.
---------------------------------------------------------------------------
\91\ Available online at: http://www.regulations.gov Docket ID:
EPA-HQ-RCRA-2009-0640.
---------------------------------------------------------------------------
D. Changes in Water Use
Steam electric facilities generally use water for handling solid
waste, including ash, and for operating wet FGD scrubbers. The BA
handling technologies associated with baseline and the regulatory
options in today's proposal for BA transport water eliminate or reduce
water use associated with wet sluicing BA operating systems. The 2015
rule baseline requires zero discharge of pollutants in BA transport
water, and because the use of other wastewater could significantly
increase the necessary purge flow to maintain water chemistry, the EPA
estimated the increase in water use for BA handling associated with
Options 1, 2, 3, and 4 compared to baseline as equal to the BA purge
flow.
Two of the three technology bases for FGD wastewater included in
the regulatory options in today's proposal, chemical precipitation and
chemical precipitation plus LRTR, are not expected to reduce or
increase the amount of water use. Facilities that install a membrane
filtration system for FGD wastewater treatment under Option 2 or 3 as
part of the VIP option, or under Option 4, are assumed to decrease
water use compared to baseline by recycling all permeate back into the
FGD system, which would avoid costs of pumping or treating new makeup
water. Therefore, the EPA estimated this reduction in water use
resulting from membrane filtration treatment based on the estimated
volume of the permeate stream from the membrane filtration system.
Table X-6 sums the changes for FGD wastewater and BA transport water
and shows the net change in water use, compared to baseline, for the
proposed regulatory options.
[[Page 64653]]
Table X-6--Estimated Incremental Changes to Water Use Associated With Regulatory Options Compared to Baseline
----------------------------------------------------------------------------------------------------------------
Changes to water use associated with regulatory options
Non-water quality impact -------------------------------------------------------------------
Option 1 Option 2 Option 3 Option 4
----------------------------------------------------------------------------------------------------------------
Changes in Water Use (gallons/year)......... 3,370,000 21,100,000 613,000 -9,380,000
----------------------------------------------------------------------------------------------------------------
XI. Environmental Assessment
A. Introduction
The EPA conducted an environmental assessment for this proposed
rule. The environmental assessment reviewed currently available
literature on the documented environmental and human health impacts of
steam electric power facility FGD wastewater and BA transport water
discharges and conducted modeling to determine the impacts of pollution
from the universe of steam electric facilities to which the steam
electric ELGs apply. For the reasons described in Section VIII of this
preamble, in conducting these analyses, the baseline appropriately
evaluates environmental and human health impacts of achieving the 2015
rule requirements as the EPA is analyzing the impact resulting from any
changes to those requirements compared to the 2015 rule (the same
baseline used to evaluate costs). More specifically, the EPA considered
the change in impacts associated with the regulatory options presented
in Table VII-1 in relation to those projected under the baseline.
Information from the EPA's review of the scientific literature and
documented cases of impacts of steam electric power facility FGD
wastewater and BA transport water discharges on human health and the
environment, as well as a description of the EPA's modeling methodology
and results, are provided in the Supplemental Environmental Assessment
(Supplemental EA). The Supplemental EA contains information on
literature that the EPA has reviewed since the 2015 rule, updates to
the modeling methodology and modeling results for each of the
regulatory options in today's proposal. The 2015 EA provides
information from the EPA's earlier review of the scientific literature
and documented cases of the full spectrum of impacts associated with
the wider range of steam electric power facility wastewater discharges
addressed in the 2015 rule on human health and the environment, as well
as a full description of the EPA's modeling methodology.
Current scientific literature indicates that untreated steam
electric power facility wastewaters, such as FGD wastewater and BA
transport water, contain large amounts of a wide range of pollutants,
some of which are toxic and bioaccumulative, and which cause
detrimental environmental and human health impacts. For additional
information, see Section 2 of the Supplemental EA. The EPA also
considered environmental and human health effects associated with
changes in air emissions, solid waste generation, and water
withdrawals. Sections X and XII discuss these effects.
B. Updates to the Environmental Assessment Methodology
The environmental assessment modeling for today's proposed rule
consisted of the steady-state, national-scale immediate receiving water
(IRW) model that was used to evaluate the direct and indirect
discharges from steam electric facilities in the 2015 final ELG rule
and 2015 final CCR rule.\92\ The model focused on impacts within the
immediate surface waters where the discharges occur (approximately 0.5
to 6 miles from the outfall). The EPA also modeled receiving water
concentrations downstream from steam electric power facility discharges
using a downstream fate and transport model (see Section XII of this
preamble).
---------------------------------------------------------------------------
\92\ These rules modeled the same waterbodies for which the
model was peer reviewed in 2008.
---------------------------------------------------------------------------
The environmental assessment also incorporates changes to the
industry profile outlined in Section V of this preamble. Additionally,
the EPA updated and improved several input parameters for the IRW
model, including receiving water boundaries and volumetric flow data
from National Hydrography Dataset Plus (NHDPlus) Version 2, updated
national recommended water quality criteria (WQC) for cadmium and
selenium, updated benchmarks for ecological impacts in benthic
sediment, and an updated bioconcentration factor for cadmium.
C. Outputs From the Environmental Assessment
The EPA estimates small environmental and ecological changes
associated with changes in pollutant loadings for the regulatory
options presented in Table VII-1 as compared to the baseline, including
small changes in impacts to wildlife and humans. More specifically, in
addition to other unquantified environmental changes, the environmental
assessment evaluated changes in (1) surface water quality, (2) impacts
to wildlife, (3) number of receiving waters with potential human health
cancer risks, (4) number of receiving waters with potential to cause
non-cancer human health effects, and (5) nutrient impacts.
The EPA focused its quantitative analyses on the changes in
environmental and human health impacts associated with exposure to
toxic bioaccumulative pollutants via the surface water pathway. The EPA
modeled changes in discharges of toxic, bioaccumulative pollutants from
both FGD wastewater and BA transport water into rivers and streams and
lakes and ponds, including reservoirs. The EPA addressed environmental
impacts from nutrients in a separate analysis discussed in Section XII
of this preamble.
The environmental assessment concentrates on impacts to aquatic
life based on changes in surface water quality; impacts to aquatic life
based on changes in sediment quality within surface waters; impacts to
wildlife from consumption of contaminated aquatic organisms; and
impacts to human health from consumption of contaminated fish and
water. The Supplemental EA discusses, with quantified results, the
estimated environmental changes projected within the immediate
receiving waters due to the estimated pollutant loading changes
associated with the regulatory options in today's proposal compared to
the 2015 rule. All of the modeled changes are small in magnitude.
XII. Benefits Analysis
This section summarizes the EPA's estimates of the changes in
national environmental benefits expected to result from potential
changes in steam electric facility wastewater discharges described in
Section IX of this preamble, and the resultant environmental effects,
summarized in Section XI. The Benefit Cost Analysis
[[Page 64654]]
(BCA) report provides additional details on the benefits methodologies
and analyses, including uncertainties and limitations. The analysis
methodology for quantified benefits is generally the same as that used
by the EPA for the 2015 rule, but with revised inputs and assumptions
that reflect updated data. The EPA has updated the methodology from the
Stage 2 Disinfection Byproduct Rule for estimating benefits of reducing
bladder cancer incidence related to bromide discharges from steam
electric facilities and associated brominated disinfection by-product
formation at drinking water treatment facilities.
A. Categories of Benefits Analyzed
Table XII-1 summarizes benefit categories associated with the
proposed regulatory options and notes which categories the EPA was able
to quantify and monetize. Analyzed benefits fall into six broad
categories: Human health benefits from surface water quality
improvements, ecological conditions and effects on recreational use
from surface water quality changes, market and productivity benefits,
air-related effects, and changes in water withdrawal. Within these
broad categories, the EPA was able to assess changes in the benefits
projected for the regulatory options in today's proposal with varying
degrees of completeness and rigor. Where possible, the EPA quantified
the expected changes in effects and estimated monetary values. However,
data limitations, modeling limitations, and gaps in the understanding
of how society values certain environmental changes prevent the EPA
from quantifying and/or monetizing some benefit categories. In the
following discussion, positive benefit values represent improvements in
environmental conditions and negative values represent forgone benefits
of the proposed options compared to the baseline.
Table XII-1--Summary of Benefits Categories Associated With Changes in Pollutant Discharges From Steam Electric
Facilities
----------------------------------------------------------------------------------------------------------------
Quantified but not Neither quantified nor
Benefit category Quantified and monetized monetized monetized
----------------------------------------------------------------------------------------------------------------
Human Health Benefits from Surface Water Quality Changes
----------------------------------------------------------------------------------------------------------------
Changes in incidence of bladder [check]................. ........................ ........................
cancer from exposure to total
trihalomethanes (TTHM) in
drinking water.
Changes in incidence of cancer [check]................. ........................ ........................
from arsenic exposure via fish
consumption.
Changes in incidence of ........................ ........................ [check]
cardiovascular disease from lead
exposure via fish consumption.
Changes in incidence of other ........................ [check]................. [check]
cancer and non-cancer adverse
health effects (e.g.,
reproductive, immunological,
neurological, circulatory, or
respiratory toxicity) due to
exposure to arsenic, lead,
cadmium, and other toxics from
fish consumption or drinking
water.
Changes in IQ loss in children [check]................. ........................ ........................
from lead exposure via fish
consumption.
Changes in need for specialized [check]................. ........................ ........................
education for children from lead
exposure via fish consumption.
Changes in in utero mercury [check]................. ........................ ........................
exposure via maternal fish
consumption.
Changes in health hazards from ........................ ........................ [check]
exposure to pollutants in waters
used recreationally (e.g.,
swimming).
----------------------------------------------------------------------------------------------------------------
Ecological Conditions and Effects on Recreational Use from Surface Water Quality Changes
----------------------------------------------------------------------------------------------------------------
Benefits from changes in surface [check]................. ........................ ........................
water quality, including: Aquatic
and wildlife habitat; water-based
recreation, including fishing,
swimming, boating, and nearwater
activities; aesthetic benefits,
such as enhancement of adjoining
site amenities (e.g., residing,
working, traveling, and owning
property near the water; \a\ and
non-use value (existence, option,
and bequest value from improved
ecosystem health) \a\.
Benefits from protection of ........................ [check]................. ........................
threatened and endangered
species.
Changes in sediment contamination. ........................ ........................ [check]
----------------------------------------------------------------------------------------------------------------
Market and Productivity Benefits
----------------------------------------------------------------------------------------------------------------
Changes in impoundment failures. ........................ ........................ [check]
Changes in water treatment costs ........................ ........................ [check]
for municipal drinking water,
irrigation water, and industrial
process.
Changes in commercial fisheries ........................ ........................ [check]
yields.
Changes in tourism and ........................ ........................ [check]
participation in water-based
recreation.
Changes in property values from ........................ ........................ [check]
water quality changes.
Changes in ability to market coal ........................ ........................ [check]
combustion byproducts.
Changes in maintenance dredging of [check]................. ........................ ........................
navigational waterways and
reservoirs due to changes in
sediment discharges.
----------------------------------------------------------------------------------------------------------------
Air-Related Effects
----------------------------------------------------------------------------------------------------------------
Human health benefits from changes ........................ [check]................. ........................
in morbidity and mortality from
exposure to NOX, SO2 and
particulate matter (PM2.5).
Avoided climate change impacts [check]................. ........................ ........................
from CO2 emissions.
----------------------------------------------------------------------------------------------------------------
Changes in Water Withdrawal
----------------------------------------------------------------------------------------------------------------
Changes in the availability of [check]................. ........................ ........................
groundwater resources.
Changes in impingement and ........................ ........................ [check]
entrainment of aquatic organisms.
[[Page 64655]]
Changes in susceptibility to ........................ ........................ [check]
drought.
----------------------------------------------------------------------------------------------------------------
\a\ These values are implicit in the total willingness-to-pay (WTP) for water quality improvements.
The following section summarizes the EPA's analysis of the benefit
categories that the Agency was able to quantify and/or monetize
(identified in the second and third columns of Table XII-1,
respectively). Benefits are a function of not only the changes in
pollutant loadings under the various options, but also the timing of
those options. For example, although loadings increase more under
Option 1, treatment technologies are in place sooner, resulting in
fewer forgone lead, mercury, and arsenic-related human health benefits
under Option 1 than under more stringent options that may be installed
in the future. The regulatory options would also affect additional
benefit categories that the Agency was not able to monetize. The BCA
Report further describes some of these additional nonmonetized
benefits.
B. Quantification and Monetization of Benefits
1. Changes in Human Health Benefits From Changes in Surface Water
Quality
Changes in pollutant discharges from steam electric facilities
affect human health benefits in multiple ways. Exposure to pollutants
in steam electric power facility discharges via consumption of fish
from affected waters can cause a wide variety of adverse health
effects, including cancer, kidney damage, nervous system damage,
fatigue, irritability, liver damage, circulatory damage, vomiting,
diarrhea, brain damage, IQ loss, and many others. Exposure to drinking
water containing brominated disinfection by-products could cause
adverse health effects such as cancer and reproductive and fetal
development issues. Because the regulatory options in this proposal
would change discharges of steam electric pollutants into waterbodies
that receive or are downstream from these discharges, they may alter
incidence of associated illnesses, even if by small amounts. These
analyses, which are detailed in Chapters 4 and 5 of the BCA, find that
the incremental changes in exposure between the baseline and regulatory
options are minimal compared to the absolute changes for those same
pollutants evaluated in the 2015 rule.
Due to data limitations and uncertainties, the EPA is able to
monetize only a subset of the changes in health benefits associated
with changes in pollutant discharges from steam electric facilities
resulting from the regulatory options in this proposal as compared to
the baseline. The EPA monetized these changes in human health effects
by estimating the change in the expected number of individuals
experiencing adverse human health effects in the populations exposed to
steam electric discharges and/or altered exposure levels for the
regulatory options relative to the baseline, and valuing these changes
using different monetization methods for different benefit endpoints.
The EPA estimated changes in health risks from the consumption of
contaminated fish from waterbodies within 50 miles of households. The
EPA used Census Block population data and state-specific average
fishing rates to estimate the exposed population. The EPA used cohort-
specific fish consumption rates and waterbody-specific fish tissue
concentration estimates to calculate potential exposure to steam
electric pollutants. Cohorts were defined by age, sex, race/ethnicity,
and fishing mode (recreational or subsistence). The EPA used these data
to quantify and monetize changes in the following five categories of
human health effects, which are further detailed in the BCA Report:
Changes in IQ Loss in Children Aged Zero to Seven from
Lead Exposure via Fish Consumption.
Changes in Need for Specialized Education for Children
from Lead Exposure via Fish Consumption.
Changes in In Utero Mercury Exposure via Maternal Fish
Consumption and Associated IQ Loss.
Changes in Incidence of Cancer from Arsenic Exposure via
Fish Consumption.
Table XII-2 summarizes the monetary value of changes in all
estimated health outcomes associated with consumption of contaminated
fish tissue for the ELG options compared to the baseline. Chapter 5 of
the BCA provides additional detail on the methodology. The EPA solicits
comment on the assumptions and uncertainties included in this analysis.
Table XII-2--Estimated Total Monetary Values of Changes in Human Health Outcomes for ELG Options (Millions of
2018$) Compared to Baseline a
----------------------------------------------------------------------------------------------------------------
Reduced
Reduced lead mercury Reduced cancer
Discount rate (%) Option exposure for exposure for cases from Total
children \b\ children arsenic
----------------------------------------------------------------------------------------------------------------
3............................... 1 $0.00 -$0.31 $0.00 -$0.31
2 -0.01 -2.84 0.00 -2.85
3 0.00 -2.85 0.00 -2.85
4 0.00 -1.49 0.00 -1.49
7............................... 1 0.00 -0.06 0.00 -0.06
2 0.00 -0.57 0.00 -0.575
3 0.00 -0.58 0.00 -0.58
4 0.00 -0.30 0.00 -0.30
----------------------------------------------------------------------------------------------------------------
\a\ Negative values represent forgone benefits.
\b\ ``$0.00'' indicates that monetary values are greater than -$0.01 million but less than $0.00 million.
Benefits to children from exposure to lead range from -$9.1 to $0.7 thousands per year, using a 3 percent
discount rate, and from -$2.1 to $0.2 thousands, using a 7 percent discount rate.
[[Page 64656]]
The EPA also estimated changes in bladder cancer incidence from the
use and consumption of drinking water contaminated with total
trihalomethanes (TTHMs) derived from changes in pollutant loadings of
bromide associated with the four regulatory options in today's proposal
relative to the baseline. This qualitative relationship between bladder
cancer and bromide demonstrates the relative size of the benefit to
other benefits associated with this proposal. Should this analysis be
used to justify an economically significant rulemaking, the EPA intends
to peer review the analysis consistent with OMB's Information Quality
Bulletin for Peer Review. That review would include robust examination
of the strengths and limitations of the methods and an exploration of
the sensitivity of the results to the assumptions made. If the analysis
is designated a highly influential scientific assessment (HISA), one
way the EPA may seek such a review is via the EPA's Science Advisory
Board (SAB), which is particularly well suited to provide a peer review
of HISAs. The EPA's SAB is a statutorily established committee with a
broad mandate to provide advice and recommendations to the Agency on
scientific and technical matters.
The EPA estimated changes in cancer risks within populations served
by drinking water treatment facilities with intakes on surface waters
influenced by bromide discharges from steam electric facilities. The
EPA used Safe Drinking Water Information System (SDWIS) and US Census
data to estimate the exposed population. The EPA used estimates of
changes in waterbody-specific bromide concentrations and estimates of
drinking water treatment facility-specific TTHM concentrations to
calculate potential changes in exposure to TTHM and associated adverse
health outcomes.
The TTHM MCL is set higher than the health-based trihalomethane
Maximum Contaminant Level Goals (MCLGs) in order to balance protection
from human health risks from DBP exposure with the need for adequate
disinfection to control human health risks from microbial pathogens.
Actions that reduce TTHM levels below the MCL can therefore further
reduce human health risk. The EPA's analysis quantifies the human
health effects associated with incremental changes between the MCL and
the MCLG. Recent TTHM compliance monitoring data indicate that the
drinking water treatment facilities contributing most significantly to
the total estimated benefits for the regulatory options have TTHM
levels below the MCL but in excess of the MCLGs for trihalomethanes.
Table XII-3 summarizes the estimated monetary value of estimated
changes in bromide-related human health outcomes from modeled surface
water quality improvements under Options 2, 3, and 4 or degradation
under Option 1. As described in Chapter 4 of the BCA Report,
approximately 90 percent of these benefits derive from a small number
of steam electric facilities (6 facilities under Option 2, 7 facilities
under Option 3, and 17 facilities under Option 4). Bromide reduction
benefits under Options 2 and 3 derive from estimated facility
participation in the VIP.
The formation of TTHM in a particular water treatment system is a
function of several site-specific factors, including chlorine, bromine,
organic carbon, temperature, pH and the system residence time. The EPA
did not collect site-specific information on these factors at each
potentially affected drinking water treatment facility. Instead, the
EPA conducted a site-based analysis which only addresses the estimated
site-specific changes in bromides. To account for the changes in TTHM,
and subsequently bladder cancer incidence, using only the estimated
site-specific changes in bromides, the EPA used the national
relationship from Regli et al (2015).\93\ Using this relationship the
analysis held all of the other site-specific factors constant at the
measured values at the approximately 200 drinking water treatment
facilities in that study. Thus, while the national changes in TTHM and
bladder cancer incidence given estimated changes in bromide are the
EPA's best estimate on a nationwide basis, the EPA cautions that for
any specific drinking water treatment facility the estimates could be
over- or underestimated. The EPA solicits comment on the extent to
which uncertainty surrounding site-specific estimated benefits
associated with bromides reductions impact the national estimates
presented in this analysis, as well as data that would assist the EPA
in evaluating this uncertainty. Additional details and uncertainties of
this analysis are provided in Chapter 4 of the BCA Report.
---------------------------------------------------------------------------
\93\ Regli, S., Chen, J., Messner, M., Elovitz, M.S.,
Letkiewicz, F.J., Pegram, R.A., Pepping, T.J., Richardson, S.D.,
Wright, J.M., 2015. Estimating potential increased bladder cancer
risk due to increased bromide concentrations in sources of
disinfected drinking waters. Environmental Science & Technology,
49(22), 13094-13102.
Table XII-3--Estimated Human Health Benefits of Changing Bromide
Discharges Under the ELG Options Compared to Baseline
[Million of 2018$, three and seven percent discount rate]
------------------------------------------------------------------------
Annualized human health
benefits over 27 years
(millions of 2018$, discounted
Regulatory option to 2020) \a\
-------------------------------
3% Discount 7% Discount
rate rate
------------------------------------------------------------------------
Option 1................................ -$0.36 -$0.23
Option 2................................ 37.61 24.21
Option 3................................ 42.57 27.48
Option 4................................ 84.32 54.30
------------------------------------------------------------------------
\a\ The analysis accounts for the persisting health effects (up until
2121) from changes in TTHM exposure during the period of analysis
(2021-2047).
[[Page 64657]]
2. Changes in Surface Water Quality
The EPA evaluated whether the regulatory options in today's
proposal would alter aquatic habitats and human welfare by changing
concentrations of harmful pollutants such as arsenic, cadmium,
chromium, copper, lead, mercury, nickel, selenium, zinc, nitrogen,
phosphorus, and suspended sediment relative to the baseline. As a
result, the usability of some of the waters for recreation relative to
baseline discharge conditions could change under each option, thereby
affecting recreational users. Changes in pollutant loadings can also
change the attractiveness of waters usable for recreation by making
recreational trips more or less enjoyable. The regulatory options may
also change nonuse values stemming from bequest, altruism, and
existence motivations. Individuals may value water quality maintenance,
ecosystem protection, and healthy species populations independent of
any use of those attributes.
The EPA uses a water quality index (WQI) to translate water quality
measurements, gathered for multiple parameters that are indicative of
various aspects of water quality, into a single numerical indicator
that reflects achievement of quality consistent with the suitability
for certain uses. The WQI includes seven parameters: Dissolved oxygen,
biochemical oxygen demand, fecal coliform, total nitrogen, total
phosphorus, TSS, and one aggregate subindex for toxics. The EPA modeled
changes in four of these parameters, and held the remaining parameters
(dissolved oxygen, biochemical oxygen demand, and fecal coliform)
constant for the purposes of this analysis. Table XII-4 summarizes
water quality change ranges relative to the baseline under the four
regulatory options. Under Options 1 through 3, 78 to 84 percent of
potentially affected reaches have a negative change in the WQI. Another
16 to 22 percent of reaches show no change under these options. Under
Option 4, 61 percent of reaches would experience a negative change in
the WQI, and another 12 percent of reaches show no change.
Table XII-4--Estimated Ranges of Water Quality Changes Under Regulatory Options Compared to Baseline
----------------------------------------------------------------------------------------------------------------
[Delta]WQI
Regulatory option Minimum Maximum Median interquartile
[Delta]WQI \a\ [Delta]WQI [Delta]WQI range
----------------------------------------------------------------------------------------------------------------
Option 1........................................ -5.29 0.00 -0.00102 0.01000
Option 2........................................ -2.95 1.30 -0.00047 0.00168
Option 3........................................ -2.95 1.30 -0.00023 0.00078
Option 4........................................ -2.62 1.31 -0.00002 0.00125
----------------------------------------------------------------------------------------------------------------
\a\ Negative changes in WQI values indicate degrading water quality.
The EPA estimated the change in monetized benefit values using the
same meta-regressions of surface water valuation studies used in the
benefit analysis for the 2015 rule. The meta-regressions quantify
average household WTP for incremental improvements in surface water
quality. This WTP is the maximum amount of money a person is willing to
give up to obtain an improvement in water quality. Chapter 6 of the BCA
provides additional detail on the valuation methodology. Overall,
Option 1 results in water quality degradation, which is reflected in
negative annual household WTP values ranging from -$0.11 to -$0.62.
Under Options 2, 3, and 4, the net water quality improvements
(accounting for all increases and decreases of pollutant loadings)
result in positive net benefits to households affected by water quality
changes from the regulatory options proposed. The estimated annual
household WTP for water quality changes ranges from $0.10 to $0.56 for
Option 2, $0.16 to $0.87 for Option 3, and $0.19 to $1.04 for Option 4.
Table XII-5 presents annualized total WTP values for water quality
changes associated with modified metal (arsenic, cadmium, chromium,
copper, lead, mercury, zinc, and nickel), non-metal (selenium),
nutrient (phosphorus and nitrogen), and sediment pollutant discharges
to the approximately 10,393 reach miles affected by the regulatory
options in this proposal. An estimated 85 million households reside in
Census block groups within 100 miles of affected reaches. The central
tendency estimate of the total annualized benefits of water quality
changes for Option 2 range from $14.3 million (7 percent discount rate)
to $16.7 million (3 percent discount rate).
Table XII-5--Estimated Total Willingness-To-Pay for Water Quality Changes (Millions 2018$) Compared to Baseline a
--------------------------------------------------------------------------------------------------------------------------------------------------------
Number of 3% Discount rate 7% Discount rate
affected -----------------------------------------------------------------------------
Regulatory option households
(millions) Low Central High Low Central High
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 1..................................................... 85.2 -$10.0 -$12.5 -$55.5 -$8.6 -$10.9 -$48.1
Option 2..................................................... 86.9 11.8 16.7 65.6 10.1 14.3 56.1
Option 3..................................................... 84.6 16.3 22.5 90.7 14.0 19.4 77.8
Option 4..................................................... 86.5 19.8 27.3 110.2 17.0 23.6 94.6
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Negative values represent forgone benefits and positive values represent realized benefits.
3. Effects on Threatened and Endangered Species
To assess the potential for impacts on T&E species (both aquatic
and terrestrial) relative to the 2015 baseline, the EPA analyzed the
overlap between waters expected to change their wildlife WQC exceedance
status under a particular option and the known critical habitat
locations of high-vulnerability T&E species. The EPA examined the life
history traits of potentially affected T&E species and categorized them
by potential for population impacts due to surface water quality
changes. Chapter 7
[[Page 64658]]
of the BCA Report provides additional detail on the methodology. The
EPA determined that there are 24 species whose known critical habitat
overlaps with surface waters that may be affected by the proposed
options when compared to the baseline, including three fish species,
two amphibian and reptile species, one bird species, 17 clam and mussel
species, and one snail species. Six of these species have known
critical habitat overlapping surface waters that are expected to see
reduced exceedances of NRWQC under proposed Options 2, 3, or 4, while
23 species (including 5 species that may see reduced exceedances of
NRWQC under proposed Options 2, 3, or 4, depending on habitat location)
have known critical habitat overlapping surface waters that may see
increased exceedances of NRWQC under one or more of the proposed
options. Under Option 2, there are two species whose known critical
habitat overlaps with surface waters that may see reduced exceedances
of NRWQC, and 12 species whose known critical habitat overlaps with
surface waters that may see increased exceedances of NRWQC. Option 1 is
expected to result in increased exceedances of NRWQC across all habitat
locations. Principal sources of uncertainty include the specifics of
how these proposed options will impact threatened and endangered
species, exact spatial distribution of the species, and additional
species of concern not considered.
4. Changes in Benefits From Marketing of Coal Combustion Residuals
The proposed rule options could affect the ability of steam
electric facilities to market coal combustion byproducts for beneficial
use by converting from wet to dry handling of BA. In particular, the
EPA evaluated the potential effects from changes in marketability of BA
as a substitute for sand and gravel in fill applications. Among the
regulatory options considered for this proposal, EPA estimates that
only Option 2 would affect the quantity of BA handled wet when compared
to the baseline, and for that option the estimated increase in BA
handled wet is small (total of 310,671 tons per year at 20 facilities).
Given these small changes and the uncertainty associated with
projecting facility-specific changes in marketed ash, the EPA chose not
to monetize this benefit category in the analysis of the proposed
regulatory options. See Chapter 2 in the BCA report for additional
details.
5. Changes in Dredging Costs
The proposed regulatory options would affect discharge loadings of
various categories of pollutants, including TSS, thereby changing the
rate of sediment deposition to affected waterbodies, including
navigable waterways and reservoirs that require dredging for
maintenance.
Navigable waterways, including rivers, lakes, bays, shipping
channels and harbors, are an integral part of the United States
transportation network. They are prone to reduced functionality due to
sediment build-up, which can reduce the navigable depth and width of
the waterway. In many cases, costly periodic dredging is necessary to
keep them passable. Reservoirs serve many functions, including storage
of drinking and irrigation water supplies, flood control, hydropower
supply, and recreation. Streams can carry sediment into reservoirs,
where it can settle and cause buildup of silt layers over time.
Sedimentation reduces reservoir capacity and the useful life of
reservoirs unless measures such as dredging are taken to reclaim
capacity. Chapter 10 of the BCA provides additional detail on the
methodology.
The EPA expects that Option 4 would provide cost savings ranging
from $0.48 million (7 percent discount rate) to $0.72 million (3
percent discount rate) by reducing required dredging maintenance for
both navigable waterways and reservoirs. Estimated increases in
sediment loadings under Options 1, 2, and 3 would result in cost
increases. Cost increases range from $0.05 million to $0.09 million for
Option 1, $0.12 million to $0.21 million for Option 2, and $0.04
million to $0.07 million for Option 3.
6. Changes in Air-Related Effects
The EPA expects the proposed options to affect air pollution
through three main mechanisms: (1) Changes in auxiliary electricity use
by steam electric facilities to operate wastewater treatment, ash
handling, and other systems that the EPA predicts facilities would use
under each proposed option; (2) changes in transportation-related air
emissions due to changes in trucking of CCR waste to landfills; and (3)
change in the profile of electricity generation due to the relatively
higher or lower costs to generate electricity at steam electric
facilities incurring compliance costs under the proposed options.
Changes in the electricity generation profile can increase or
decrease air pollutant emissions because emission factors vary for
different types of electric boilers. For this analysis, the changes in
air emissions are based on the change in dispatch of generation units
as projected by IPM V6 given the overlaying of costs for complying with
the proposed options onto steam electric boilers' production costs. As
discussed in Section VIII of this preamble, the IPM V6 analysis
accounts for the effects of other regulations on the electric power
sector.
The EPA evaluated potential effects resulting from net changes in
air emissions of three pollutants: NOX, SO2, and
CO2. NOX and SOX are precursors to
fine particles sized 2.5 microns and smaller (PM2.5), this
air pollutant causes a variety of adverse health effects including
premature death, non-fatal heart attacks, hospital admissions,
emergency department visits, upper and lower respiratory symptoms,
acute bronchitis, aggravated asthma, lost work days, and acute
respiratory symptoms. CO2 is a key greenhouse gas linked to
a wide range of domestic effects.\94\
---------------------------------------------------------------------------
\94\ U.S. EPA. Integrated Science Assessment (ISA) for
Particulate Matter (Final Report, Dec 2009). U.S. Environmental
Protection Agency, Washington, DC, EPA/600/R-08/139F, 2009.
---------------------------------------------------------------------------
The EPA used domestic social cost of carbon estimates to value
changes in CO2 emissions (SC-CO2). The Agency
quantified changes in emissions of PM2.5 precursors,
NOX, and SO2. To map those emission changes to
air quality changes across the country, air quality modeling is needed.
Prior to this proposal, the EPA's modeling capacity was fully allocated
to supporting other regulatory and policy efforts.
Table XII-6 shows the changes in emissions of NOX,
SO2, and CO2 based on the estimated increases in
electricity generation (see Table VIII-3) for options 2 and 4 (the two
regulatory options that the EPA analyzed for these increased emission
effects). Table XII-7 shows the total annualized monetary values
associated with changes in emissions of CO2 for options 2
and 4. All total monetary values are negative, indicating that the
proposed rule results in net forgone CO2-related benefits
when compared to the baseline. While not monetized, additional forgone
benefits associated with PM2.5 would also occur. The
majority of the forgone benefits are due to changes in the profile of
electricity generation. Smaller shares of the changes in total benefits
are attributable to changes in energy use to operate wastewater
treatment systems. Benefits from changes in trucking emissions are
negligible. The EPA did not analyze benefits from changes in air
emissions for Options 1 and 3 but instead extrapolated values by
scaling air-related benefits under Option 2 in
[[Page 64659]]
proportion to the total social costs of each option. Chapter 8 of the
BCA Report provides additional details on the analysis of air-related
benefits.
Table XII-6--Estimated Changes in Air Emissions Compared to Baseline a
----------------------------------------------------------------------------------------------------------------
CO2 (metric
Regulatory option Category of emissions tons/year) NOX (tons/ SO2 (tons/
year) year)
----------------------------------------------------------------------------------------------------------------
Option 2.............................. Electricity generation b 5,656,000 4,650 4,930
c.
Trucking................ -490 0 0
Energy use b c.......... -44,080 -32 -54
-----------------------------------------------
Total \d\............ 5,611,000 4,620 4,870
rrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrrr
Option 4.............................. Electricity generation b 1,244,000 1,900 1,020
e.
Trucking................ 1,440 1 0
Energy use b e.......... 59,320 31 20
-----------------------------------------------
Total \d\............ 1,305,000 1,940 1,040
----------------------------------------------------------------------------------------------------------------
\a\ Negative values represent emission reductions.
\b\ Estimated changes in emissions shown for 2028-2032 based on the estimated increase in electricity generation
of 0.3% for Option 2 and 0.1% for Option 4.
\c\ Option 2 estimates are based on the IPM sensitivity analysis scenario that includes the ACE rule in the
baseline (IPM-ACE).
\d\ Values may not sum to the total due to independent rounding.
\e\ Option 4 estimates are based on IPM analysis scenario that does not include the ACE rule in the baseline.
Table XII-7--Estimated Annualized Benefits From Changes in CO2 Air Emissions (Millions; 2018$) Compared to
Baseline a
----------------------------------------------------------------------------------------------------------------
3% Discount 7% Discount
Regulatory option Category of emissions rate rate
----------------------------------------------------------------------------------------------------------------
Option 2...................................... Electricity generation \b\...... -$32.0 -$5.2
Trucking........................ 0.0 0.0
Energy use \b\.................. 0.4 0.1
-------------------------------
Total \c\.................... -31.6 -5.2
-------------------------------
Option 4...................................... Electricity generation \d\...... -4.3 -0.8
Trucking........................ 0.0 0.0
Energy use \d\.................. -0.5 0.0
-------------------------------
Total \c\.................... -4.8 -0.9
----------------------------------------------------------------------------------------------------------------
\a\ Negative values represent forgone benefits.
\b\ Option 2 estimates are based on the IPM sensitivity analysis scenario that includes the ACE rule in the
baseline (IPM-ACE).
\c\ Values may not sum to the total due to independent rounding.
\d\ Option 4 estimates are based on IPM analysis scenario that does not include the ACE rule in the baseline.
7. Benefits From Changes in Water Withdrawals
Steam electric facilities use water for handling BA and operating
wet FGD scrubbers. By reducing water used in sluicing operations or
prompting the recycling of water in FGD wastewater treatment systems,
Option 4 is expected to reduce water withdrawals from surface waters,
whereas proposed Options 1, 2, and 3 are expected to increase water
withdrawals from surface waterbodies. Option 2 is also expected to
increase water withdrawal from aquifers. Using the same methodology
used for the 2015 rule, the EPA estimated the monetary value of
increased ground water withdrawals based on increased costs of ground
water supply. For each relevant facility, the EPA multiplied the
increase in ground water withdrawal (in gallons per year) by water
costs of about $1,192 per acre-foot. Chapter 9 of the BCA Report
provides the details of this analysis. The EPA estimates the changes in
annualized benefits of increased ground water withdrawals are less than
$0.2 million annually. Due to data limitations, the EPA was not able to
estimate the monetary value of changes in surface water withdrawals.
Chapter 9 of the BCA Report and Section 7 of the Supplemental TDD
provide additional details on the estimated changes in surface water
withdrawals.
C. Total Monetized Benefits
Using the analysis approach described above, the EPA estimated the
total monetary value of annual benefits of the proposed rule for all
monetized categories. Table XII-8 and Table XII-9 summarize the total
annualized monetary value of social welfare effects using 3 percent and
7 percent discount rates, respectively. The total monetary value of
benefits under Option 2 range from $14.8 million to $68.5 million using
a 3 percent discount rate and from $28.4 million to $74.4 million using
a 7 percent discount rate.
[[Page 64660]]
Table XII-8--Summary of Total Annualized Benefits at 3 Percent
[Millions; 2018$] a
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 1 Option 2 Option 3 Option 4
Benefit category -----------------------------------------------------------------------------------------------------------------
Low Mid High Low Mid High Low Mid High Low Mid High
--------------------------------------------------------------------------------------------------------------------------------------------------------
Human Health \d\...................... -$0.7
$34.8
$39.7
$82.8
Changes in IQ losses in children
from exposure to lead \b\........ <0.0
<0.0
<0.0
<0.0
Changes in IQ losses in children
from exposure to mercury......... -0.3
-2.84
-2.85
-1.49
Reduced cancer risk from DBPs in
drinking water................... -0.4
37.6
42.6
84.3
-----------------------------------------------------------------------------------------------------------------
Ecological Conditions and Recreational -$10.0 -$12.5 -$55.5 $11.8 $16.7 $65.6 $16.3 $22.5 $90.7 $19.8 $27.3 $110.2
Uses Changes.........................
Use and nonuse values for water -10.0 -12.5 -55.5 11.8 16.7 65.6 16.3 22.5 90.7 19.8 27.3 110.2
quality changes..................
Market and Productivity \d\........... -0.1 -0.1 -0.1 -0.2 -0.2 -0.2 -0.1 -0.1 -0.1 0.6 0.6 0.7
Changes in dredging costs......... -0.1 -0.1 -0.1 -0.1 -0.2 -0.2 -0.1 -0.1 -0.1 0.6 0.6 0.7
-----------------------------------------------------------------------------------------------------------------
Reduced water withdrawals \b\..... $0.0
<$0.0
$0.0
$0.0
Air-related effects................... -30.3
-31.6
-20.9
-4.8
Changes in CO2 air emissions \c\.. -30.3
-31.6
-20.9
-4.8
-----------------------------------------------------------------------------------------------------------------
Total \d\..................... -$41.0 -$43.6 -$86.6 $14.8 $19.6 $68.5 $35.1 $41.3 $109.4 $98.4 $105.9 $188.9
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Negative values represent forgone benefits and positive values represent realized benefits.
\b\ ``<$0.0'' indicates that monetary values are greater than -$0.1 million but less than $0.00 million.
\c\ The EPA estimated the air-related benefits for Option 2 using the IPM sensitivity analysis scenario that includes the ACE rule in the baseline (IPM-
ACE). EPA extrapolated estimates for Options 1 and 3 air-related benefits from the estimate for Option 2 that is based on IPM-ACE outputs. The values
for Option 4 air-related benefits were estimated using the IPM analysis scenario that does not include the ACE rule in the baseline.
\d\ Values for individual benefit categories may not sum to the total due to independent rounding.
Table XII-9--Summary of Total Annualized Benefits at 7 Percent
[Millions; 2018$] a
--------------------------------------------------------------------------------------------------------------------------------------------------------
Option 1 Option 2 Option 3 Option 4
Benefit category -----------------------------------------------------------------------------------------------------------------
Low Mid High Low Mid High Low Mid High Low Mid High
--------------------------------------------------------------------------------------------------------------------------------------------------------
Human Health \d\...................... -$0.3
$23.6
$26.9
$54.0
Changes in IQ losses in children
from exposure to lead \b\........ <0.0
<0.0
<0.0
<0.0
Changes in IQ losses in children
from exposure to mercury......... -0.1
-0.6
-0.6
-0.3
Reduced cancer risk from DBPs in
drinking water................... -0.2
24.2
27.5
54.3
-----------------------------------------------------------------------------------------------------------------
Ecological Conditions and Recreational -$8.6 -$10.9 -$48.1 $10.1 $14.3 $56.1 $14.0 $19.4 $77.8 $17.0 $23.6 $94.6
Uses Changes.........................
Use and nonuse values for water -8.6 -10.9 -48.1 10.1 14.3 56.1 14.0 19.4 77.8 17.0 23.6 94.6
quality changes..................
Market and Productivity \d\........... -0.1 -0.1 -0.1 -0.1 -0.2 -0.2 0.0 -0.1 -0.1 0.5 0.5 0.7
Changes in dredging costs......... -0.1 -0.1 -0.1 -0.1 -0.1 -0.2 0.0 -0.1 -0.1 0.5 0.5 0.7
-----------------------------------------------------------------------------------------------------------------
Reduced water withdrawals \b\..... $0.0
<$0.0
$0.0
$0.0
Air-related Effects................... -4.8
-5.2
-3.7
-0.9
Changes in CO2 air emissions \c\.. -4.8
-5.2
-3.7
-0.9
-----------------------------------------------------------------------------------------------------------------
Total \d\..................... -$13.7 -$16.0 -$53.3 $28.4 $32.6 $74.4 $37.1 $42.5 $100.9 $70.6 $77.2 $148.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Negative values represent forgone benefits and positive values represent realized benefits.
\b\ ``<$0.0'' indicates that monetary values are greater than -$0.1 million but less than $0.00 million.
\c\ The EPA estimated the air-related benefits for Option 2 using the IPM sensitivity analysis scenario that includes the ACE rule in the baseline (IPM-
ACE). EPA extrapolated estimates for Options 1 and 3 air-related benefits from the estimate for Option 2 that is based on IPM-ACE outputs. The values
for Option 4 air-related benefits were estimated using the IPM analysis scenario that does not include the ACE rule in the baseline.
\d\ Values for individual benefit categories may not sum to the total due to independent rounding.
D. Unmonetized Benefits
The monetary value of the proposed rule's effects on social welfare
does not account for all effects of the proposed options because, as
described above, the EPA is unable to monetize some categories.
Examples of effects not reflected in these monetary estimates include
health and other effects from changes in NOX and
SO2 air emissions; changes in certain non-cancer health
risks (e.g., effects of cadmium on kidney functions and bone density);
impacts of pollutant load changes on threatened and endangered species
habitat; and ash marketing changes. The BCA Report discusses changes in
these effects qualitatively, indicating their potential magnitude where
possible.
XIII. Development of Effluent Limitations and Standards
A. FGD Wastewater
The proposed rule contains new numeric effluent limitations and
pretreatment standards that apply to discharges of FGD wastewater at
existing sources.\95\ The EPA is
[[Page 64661]]
proposing several sets of effluent limitations and pretreatment
standards for FGD wastewater discharges; the specific set of
limitations that would apply to any particular facility are determined
by which subcategory the facility falls within, or whether it chooses
to participate in the voluntary incentives program. The EPA developed
the numeric effluent limitations and pretreatment standards in this
proposed rule using long-term average effluent values and variability
factors that account for variations in performance at well-operated
facilities that employ the technologies that constitute the bases for
control. The EPA's methodology for derivation of limitations in ELGs is
longstanding and has been upheld in court. See, e.g., Chem. Mfrs. Ass'n
v. EPA, 870 F.2d 177 (5th Cir. 1989); Nat'l Wildlife Fed'n v. EPA, 286
F.3d 554 (D.C. Cir. 2002). The EPA establishes the final effluent
limitations and standards as ``daily maximums'' and ``maximums for
monthly averages.'' Definitions provided in 40 CFR 122.2 state that the
daily maximum limitation is the ``highest allowable `daily discharge'
'' and the maximum for monthly average limitation is the ``highest
allowable average of `daily discharges' over a calendar month,
calculated as the sum of all `daily discharges' measured during a
calendar month divided by the number of `daily discharges' measured
during that month.'' Daily discharges are defined to be the ``
`discharge of a pollutant' measured during a calendar day or any 24-
hour period that reasonably represents the calendar day for purposes of
sampling.''
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\95\ Effluent limitations for boilers with nameplate capacity of
50 MW or smaller and for boilers that will retire by December 31,
2028, are not discussed in this section. The proposed limitations
for these generating units are based on the previously established
BPT limitations on TSS.
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1. Overview of the Limitations and Standards
The EPA's objective in establishing daily maximum limitations is to
restrict the discharges on a daily basis at a level that is achievable
for a facility that designs and operates its treatment to achieve the
long-term average performance that the EPA's statistical analyses show
the BAT/PSES technology can attain (i.e., the mean of the underlying
statistical distribution of daily effluent values). The EPA recognizes
that variability around the long-term average occurs during normal
operations. This variability means that facilities occasionally may
discharge at a level that is higher than the long-term average, and at
other times will discharge at a level that is lower than the long-term
average. To allow for these possibly higher daily discharges and
provide an upper bound for the allowable concentration of pollutants
that may be discharged, while still targeting achievement of the long-
term average, the EPA has established the daily maximum limitation. A
facility consistently discharging at a level near the daily maximum
limitation would be symptomatic of a facility that is not operating its
treatment to achieve the long-term average. Targeting treatment to
achieve the daily limitation, rather than the long-term average, is not
consistent with the capability of the BAT/PSES technology basis and may
result in values that periodically exceed the limitations due to
routine variability in treated effluent.
The EPA's objective in establishing monthly average limitations is
to provide an additional restriction to help ensure that facilities
target their average discharges to achieve the long-term average. The
monthly average limitation requires dischargers to provide ongoing
control, on a monthly basis, that supplements controls imposed by the
daily maximum limitation. In order to meet the monthly average
limitation, a facility must counterbalance a value near the daily
maximum limitation with one or more values well below the daily maximum
limitation.
2. Criteria Used To Select Data
In developing effluent limitations guidelines and standards for any
industry, the EPA qualitatively reviews all the data before selecting
data that represents proper operation of the technology that forms the
basis for the limitations. The EPA typically uses four criteria to
assess the data. The first criterion requires that the facilities have
the model treatment technology identified as a candidate basis for
effluent limitations (e.g., chemical precipitation with LRTR) and
demonstrate consistently diligent and optimal operation. Application of
this criterion typically eliminates any facility with treatment other
than the model technology. The EPA generally determines whether a
facility meets this criterion based upon site visits, discussions with
facility management, and/or comparison to the characteristics,
operation, and performance of treatment systems at other facilities.
The EPA reviews available information to determine whether data
submitted were representative of normal operating conditions for the
facility and equipment. As a result of this review, the EPA typically
excludes the data in developing the limitations when the facility has
not optimized the performance of its treatment system.
A second criterion generally requires that the influents and
effluents from the treatment components represent typical wastewater
from the industry, without incompatible wastewater from other sources.
Application of this criterion results in the EPA selecting those
facilities where the commingled wastewaters did not result in
substantial dilution, unequalized slug loads resulting in frequent
upsets and/or overloads, more concentrated wastewaters, or wastewaters
with different types of pollutants than those generated by the
wastestream for which the EPA is proposing effluent limitations and
pretreatment standards.
A third criterion typically ensures that the pollutants are present
in the influent at sufficient concentrations to evaluate treatment
effectiveness. If a data set for a pollutant shows that the pollutant
was not present at a treatable concentration at sufficient frequency
(e.g., the pollutant was below the level of detection in all influent
samples), the EPA excludes the data for that pollutant at that facility
when calculating the limitations.
A fourth criterion typically requires that the data are valid and
appropriate for their intended use (e.g., the data must be analyzed
with a sufficiently sensitive method). Also, the EPA does not use data
associated with periods of treatment upsets because these data would
not reflect the performance from well-designed and well-operated
treatment systems. In applying the fourth criterion, the EPA may
evaluate the pollutant concentrations, analytical methods and the
associated quality control/quality assurance data, flow values, mass
loading, facility logs, test reports, and other available information.
As part of this evaluation, the EPA reviews the process or treatment
conditions that may have resulted in extreme values (high and low). As
a consequence of this review, the EPA may exclude data associated with
certain time periods or other data outliers that reflect poor
performance or analytical anomalies by an otherwise well-operated site.
The fourth criterion also is applied in the EPA's review of data
corresponding to the initial commissioning period for treatment systems
(and startup periods for pilot test equipment). Most industries incur
commissioning periods during the adjustment period associated with
installing new treatment systems. During this acclimation and
optimization process, the effluent concentration values tend to be
highly variable with occasional extreme values (high and low). This
occurs because the treatment system typically requires
[[Page 64662]]
some ``tuning'' as the facility staff and equipment and chemical
vendors work to determine the optimum chemical addition locations and
dosages, vessel hydraulic residence times, internal treatment system
recycle flows (e.g., filter backwash frequency, duration and flow rate,
return flows between treatment system components), and other
operational conditions including clarifier sludge wasting protocols. It
may also take time for treatment system operators to gain expertise on
operating the new treatment system, which also contributes to treatment
system variability during the commissioning period. After this initial
adjustment period, the systems should operate at steady state with
relatively low variability around a long-term average over many years.
Because commissioning periods typically reflect one-time operating
conditions unique to the first time the treatment system begins
operation, the EPA generally excludes such data in developing the
limitations.\96\
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\96\ Examples of conditions that are typically unique to the
initial commissioning period include operator unfamiliarity or
inexperience with the system and how to optimize its performance;
wastewater flow rates that differ significantly from engineering
design, altering hydraulic residence times, chemical contact times,
and/or clarifier overflow rates, and potentially causing large
changes in planned chemical dosage rates or the need to substitute
alternative chemical additives; equipment malfunctions; fluctuating
wastewater flow rates or other dynamic conditions (i.e., not steady
state operation); and initial purging of contaminants associated
with installation of the treatment system, such as initial leaching
from coatings, adhesives, and susceptible metal components. These
conditions differ from those associated with the restart of an
already-commissioned treatment system, such as may occur from a
treatment system that has undergone either short or extended
duration shutdown.
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3. Data Used To Calculate Limitations and Standards
The Supplemental TDD provides a description of the data and
methodology used to develop long-term averages, variability factors,
and limitations and standards for this proposed rule. The effluent
limitations and pretreatment standards for the low utilization
subcategory and high flow subcategory are based on chemical
precipitation. The derivation of the limitations for these
subcategories and the data used are described in Section 13 of the 2015
TDD. The new limitations and pretreatment standards proposed today for
facilities not in those subcategories and for the voluntary incentives
plan were derived from a statistical analysis of effluent data
collected by facilities during extended testing of the LRTR technology
and membrane filtration technology, respectively. The duration of the
test programs at these facilities spanned from approximately one month
for membranes to more than a year for LRTR, enabling the EPA to
evaluate long-term performance of these technologies under conditions
that can contribute to influent variability, including varying power
demand, changes in coal suppliers, and changes in operation of the air
pollution control system. The tests occurred over different seasons of
the year and demonstrate that the technologies operate effectively
under varying climate conditions.
During the development of these new limitations and pretreatment
standards, the EPA identified certain data that warranted exclusion
because: (1) The samples were analyzed using a method that is not
sensitive enough to reliably quantify the pollutants present (e.g., use
of EPA Method 245.1 to measure the concentration of mercury in effluent
samples); (2) the analytical results were identified as questionable
due to quality control issues associated with the laboratory analysis
or sample collection, or were analytical anomalies; (3) the samples
were collected prior to steady-state operating condition and do not
represent BAT/PSES level of performance; (4) the samples were collected
during a period where influent composition did not reflect the FGD
wastewater (e.g., untreated FGD wastewater was mixed with large volume
of non-FGD wastewater prior to the treatment system); (5) the treatment
system was operating in a manner that does not represent BAT/PSES level
of performance; or (6) the samples were collected from a location that
is not representative of treated effluent.
4. Long-Term Averages and Effluent Limitations and Standards for FGD
Wastewater
Table XIV-1 presents the proposed effluent limitations and
standards for FGD wastewater. For comparison, the table also presents
the long-term average treatment performance calculated for each
parameter. Due to routine variability in treated effluent, a power
facility that targets discharging its wastewater at a level near the
values of the daily maximum limitation or the monthly average
limitation may periodically experience values exceeding the
limitations. For this reason, the EPA recommends that facilities design
and operate the treatment system to achieve the long-term average for
the model technology. In doing so, a system that is designed and
operated to achieve the BAT/PSES level of control would meet the
limitations.
The EPA expects that facilities will be able to meet their effluent
limitations or standards at all times. If an exceedance is caused by an
upset condition, the facility would have an affirmative defense to an
enforcement action if the requirements of 40 CFR 122.41(n) are met.
Exceedances caused by a design or operational deficiency, however, are
indications that the facility's performance does not represent the
appropriate level of control. For these proposed limitations and
pretreatment standards, the EPA proposes to determine that such
exceedances can be controlled by diligent process and wastewater
treatment system operational practices, such as regular monitoring of
influent and effluent wastewater characteristics and adjusting dosage
rates for chemical additives to target effluent performance for
regulated pollutants at the long-term average concentration for the
BAT/PSES technology. Additionally, some facilities may need to upgrade
or replace existing treatment systems to ensure that the treatment
system is designed to achieve performance that targets the effluent
concentrations at the long-term average. This is consistent with the
EPA's costing approach and its engineering judgment, developed over
years of evaluating wastewater treatment processes for steam electric
facilities and other industrial sectors. The EPA recognizes that some
dischargers, including those that are operating technologies
representing the technology basis for the proposed rule, may need to
improve their treatment systems, process controls, and/or treatment
system operations in order to consistently meet the proposed effluent
limitations and pretreatment standards. This is consistent with the
CWA, which requires that BAT/PSES discharge limitations and standards
reflect the best available technology economically achievable.
See Section 8 of the Supplemental TDD for more information about
the calculation of the limitations and pretreatment standards presented
in the tables below.
[[Page 64663]]
Table XIV-1--Long-Term Averages and Effluent Limitations and Pretreatment Standards for FGD Wastewater for
Existing Sources (BAT/PSES) a
----------------------------------------------------------------------------------------------------------------
Monthly
Subcategory Pollutant Long-term Daily maximum average
average limitation limitation
----------------------------------------------------------------------------------------------------------------
Requirements for all facilities not in Arsenic ([mu]g/L)....... 5.1 18 9
the VIP or subcategories specified Mercury (ng/L).......... 13.5 85 31
below (BAT & PSES). Nitrate/nitrite as N (mg/ 2.6 4.6 3.2
L).
Selenium ([mu]g/L)...... 16.6 76 31
Voluntary Incentives Program for FGD Arsenic ([mu]g/L)....... \b\ 5.0 \c\ 5 (\d\)
Wastewater (BAT only). Mercury (ng/L).......... 5.1 21 9
Nitrate/nitrite as N (mg/ 0.4 1.1 0.6
L).
Selenium ([mu]g/L)...... 5.0 21 11
Bromide (mg/L).......... 0.16 0.6 0.3
TDS (mg/L).............. 88 351 156
Low utilization subcategory--AND--High Arsenic ([mu]g/L)....... 5.98 11 8
flow subcategory (BAT & PSES). Mercury (ng/L).......... 159 788 356
----------------------------------------------------------------------------------------------------------------
\a\ BAT effluent limitations for boilers with nameplate capacity of 50 MW or smaller, and boilers that will
retire by December 31, 2028, are based on the previously established BPT limitations on TSS and are not shown
in this table. The BAT effluent limitations for TSS for these retiring boilers is daily maximum of 100 mg/L;
monthly average of 30 mg/L.
\b\ Long-term average is the arithmetic mean of the quantitation limitations since all observations were not
detected.
\c\ Limitation is set equal to the quantitation limit for the data evaluated.
\d\ Monthly average limitation is not established when the daily maximum limitation is based on the quantitation
limit.
The EPA notes that while some limitations are higher than
corresponding limits in the 2015 rule, in other cases limitations of
additional pollutants or lower limitations for pollutants regulated in
the 2015 rule have also been calculated. The EPA solicits comment on
the demonstrated ability or inability of existing systems to meet the
limitations in this proposal, the costs associated with modifying
existing systems or with modifying the operation of existing systems to
meet these limits, and whether any existing systems with demonstrated
issues meeting these limits would be best addressed through FDF
variances or through subcategorization. Furthermore, should the EPA
determine subcategorization of facilities with existing FGD treatment
systems is warranted, the EPA solicits comment on what limitations
should apply to those facilities, including whether the 2015 rule
limits would be appropriate for such facilities.
B. BA Transport Water Limitations
1. Maximum 10 Percent 30-Day Rolling Average Purge Rate
In contrast to the limitations estimated for specific pollutants
above, the EPA is proposing a pollutant discharge allowance in the form
of a maximum percentage purge rate for BA transport water. To develop
this allowance, the EPA first collected data on the discharge needs of
the model treatment technology (high recycle rate systems) to maintain
water chemistry or water balance.\97\ EPRI (2016) presents discharge
data from seven currently operating wet BA transport water systems at
six facilities. These facilities were able to recycle most or all BA
transport water from these seven systems, resulting in discharges of
between zero and two percent of the system volume. The EPA's goal in
establishing the proposed purge rate was to provide an allowance to
address the challenges that would be incorporated in the EPRI (2016)
data, as well as infrequent precipitation and maintenance events, the
EPA also needed a way to account for such infrequent events. While EPRI
(2016) noted that infrequent discharges happened at some facilities, it
did not include such events in its discharge calculations. As a result,
EPA looked to EPRI (2018), which presents hypothetical maximum
discharge volumes and the estimated frequency associated with such
infrequent events for currently operating wet BA systems.\98\ Since
these calculations are only estimates, the EPA solicits data on actual
precipitation and maintenance-related discharges. For purposes of
calculating the allowance percentage associated with such infrequent
events, the EPA divided the discharge associated with an estimated
maintenance and precipitation event by the volume of the system, and
then averaged the resulting percent over 30 days.
---------------------------------------------------------------------------
\97\ Although the technology basis includes dry handling, the
limitation is based on the necessary purge volumes of a wet, high
recycle rate BA system.
\98\ Although presented in EPRI (2018), the EPA did not consider
events such as pipe leaks, as these would not be reflective of
proper system operation (see DCN SE06920).
---------------------------------------------------------------------------
Finally, the EPA added each reported regular discharge percent from
EPRI (2016) to the averaged infrequent discharge percent under four
scenarios: (1) With no infrequent discharge event, (2) with only a
precipitation-related discharge event, (3) with only a maintenance-
related discharge event, and (4) with both a precipitation-related and
maintenance-related discharge event. These potential discharge needs
are reported in Table XIV-2 below. Consistent with the statistical
approach used to develop limitations and pretreatment standards for
individual pollutants, the EPA selected a 95th percentile of 10 percent
of total system volume as representative of the 30-day rolling
average.\99\
---------------------------------------------------------------------------
\99\ While there were further decimal points for the actual
calculated 95th percentile, the EPA notes that 10 percent is two
significant digits, consistent with the limitations for FGD
wastewater pollutants. Furthermore, a 10 percent volumetric limit
will be easier for implementation by the permitting authority as it
results in a simple decimal point movement for calculations.
[[Page 64664]]
Table XIV-2--30-Day Rolling Average Discharge Volume as a Percent of System Volume a
--------------------------------------------------------------------------------------------------------------------------------------------------------
Infrequent discharge needs as estimated in EPRI (2018) Regular discharge needs to maintain water chemistry and/or water balance as characterized
-------------------------------------------------------------- in EPRI (2016)
30-Day ------------------------------------------------------------------------------------------
Type of infrequent discharge event rolling Facility F-- Facility F--
average Facility A Facility B Facility C Facility D Facility E System 1 System 2
(%) (%) (%) (%) (%) (%) (%) (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
0.1 0.0 1.0 0.0 0.8 2.0 2.0
Neither Event................................... 0.0 0.1 0.0 1.0 0.0 0.8 2.0 2.0
Precipitation Only.............................. 5.4 5.5 5.4 6.4 5.4 6.2 7.4 7.4
Maintenance Only................................ 3.3 3.4 3.3 4.3 3.3 4.1 5.3 5.3
Both Events..................................... 8.7 8.8 8.7 9.7 8.7 9.5 10.7 10.7
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ These estimates sum actual/reported, facility-specific regular discharge needs with varying combinations of hypothetically estimated, infrequent
discharge needs.
The EPA recognizes that some facilities may need to improve their
equipment, process controls, and/or operations to consistently meet the
zero discharge standard established by the 2015 rule. However, with the
discharge allowance included in this proposed rule, the EPA expects
that facilities would be able to avoid these costs in most
circumstances. For example, in the table above, only when the Facility
F systems experience both high-end precipitation- and maintenance-
related discharge events could the required discharge potentially
exceed the 30-day rolling average of 10 percent. This is consistent
with the CWA, which requires that BAT/PSES discharge limitations and
standards reflect the best available technology economically
achievable. For further discussion of costs associated with managing a
fully-closed-loop system, see Section 5 of the Supplemental TDD.
2. Best Management Practices Plan
As described in Section VII of this preamble, one of the regulatory
options presented in today's proposed rule would require a subcategory
of facilities discharging BA transport water and having low MWh
production to develop and implement a BMP plan to recirculate BA
transport water back to the BA handling system (see Section VII of this
preamble for more details).
The proposed BMP provisions would require applicable facilities to
develop a plan to minimize the discharge of pollutants by recycling as
much BA transport water as practicable back to the BA handling system.
For example, if a facility could recycle 80 percent of its BA transport
water for a few thousand dollars, but recycling 81 percent would
require the installation of a multi-million dollar system, the former
would be practicable, but the latter would not.\100\ After determining
the amount of BA transport water that could be easily recycled and
developing a facility-specific BMP plan, facilities are required to
implement the plan and annually review and revise the plan as
necessary.
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\100\ The limit of what is practicable at a facility may change
drastically after making changes to comply with the CCR rule. For
instance, if a facility closes its unlined surface impoundment and
installs a remote MDS, the recycle rate that is practicable may
approach that of the high recycle systems that the EPA used to
establish BAT for units not falling into this subcategory.
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XIV. Regulatory Implementation
A. Implementation of the Limitations and Standards
The requirements in this rule apply to discharges from steam
electric facilities through incorporation into NPDES permits issued by
the EPA or by authorized states under Section 402 of the Act, and
through local pretreatment programs under Section 307 of the Act.
Permits or control mechanisms issued after this rule's effective date
must incorporate the ELGs, as applicable. Also, under CWA section 510,
states can require effluent limitations under state law as long as they
are no less stringent than the requirements of this rule. Finally, in
addition to requiring application of the technology-based ELGs in this
rule, CWA section 301(b)(1)(C) requires the permitting authority to
impose more stringent effluent limitations, as necessary, to meet
applicable water quality standards.
1. Timing
The direct discharge limitations proposed in this rule would apply
only when implemented in an NPDES permit issued to a discharger. Under
the CWA, the permitting authority must incorporate these ELGs into
NPDES permits as a floor or a minimum level of control. The proposed
rule would allow a permitting authority to determine a date when the
new effluent limitations for FGD wastewater and BA transport water will
apply to a given discharger. As proposed, the permitting authority
would make these effluent limitations applicable on or after November
1, 2020. For any final effluent limitation that is specified to become
applicable after November 1, 2020, the specified date must be as soon
as possible, but in no case later than December 31, 2023, for BA
transport water, or December 31, 2025, for FGD wastewater. For
dischargers choosing to meet the voluntary incentives program effluent
limitations for FGD wastewater, the date for meeting those limitations
is December 31, 2028.
For FGD wastewater and BA transport water from boilers retiring by
2028, the proposed BAT limitations would apply on the date that a
permit is issued to a discharger. The proposed rule does not build in
an implementation period for meeting these limitations, as the BAT
limitation on TSS is equal to the previously promulgated BPT limitation
on TSS. Pretreatment standards are self-implementing, meaning they
apply directly, without the need for a permit. As defined by the
statute, the pretreatment standards for existing sources must be met by
three years after the effective date of any final rule.
Regardless of when a facility's NPDES permit is ready for renewal,
the EPA recommends that each facility immediately begin evaluating how
it intends to comply with the requirements of any final rule. In cases
where significant changes in operation are appropriate, the EPA
recommends that the facility discuss such changes with its permitting
authority and evaluate appropriate steps and a timeline for the changes
as soon as a final rule is issued, even prior to the permit renewal
process.
In cases where a facility's final NPDES permit is issued before
these ELGs are finalized, and includes limitations for BA transport
water and/or FGD wastewater from the 2015 rule, EPA recommends such a
permit be reopened as soon as practicable, and modified consistent with
any new rule provisions.
For permits that are issued on or after November 1, 2020, the
permitting
[[Page 64665]]
authority would determine the earliest possible date that the facility
can meet the limitations (but in no case later than December 31, 2023,
for BA transport water or December 31, 2025, for FGD wastewater), and
apply the proposed limitations as of that date (BPT limitations or the
facility's other applicable permit limitations would apply until such
date).
As proposed, the ``as soon as possible'' date determined by the
permitting authority is November 1, 2020, unless the permitting
authority determines another date after receiving facility-specific
information submitted by the discharger.\101\ EPA is not proposing to
revise the specified factors that the permitting authority must
consider in determining the as soon as possible date. Assuming that the
permitting authority receives relevant, site-specific information from
each discharger, in order to determine what date is ``as soon as
possible'' within the implementation period, the factors established in
the 2015 rule are:
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\101\ Information in the record indicates that most facilities
should be able to complete all steps to implement changes needed to
comply with proposed BA transport water requirements within 15-23
months, and the FGD wastewater requirements within 26 to 34 months.
---------------------------------------------------------------------------
(a) Time to expeditiously plan (including to raise capital),
design, procure, and install equipment to comply with the requirements
of the final rule.\102\
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\102\ Cooperatives and municipalities presented information to
the EPA suggesting that obtaining financing for these projects can
be more challenging than for investor-owned utilities. Under this
factor, permitting authorities may consider whether the type and
size of owner and difficulty in obtaining the expected financing
might warrant additional flexibility up to the ``no later than''
date.
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(b) Changes being made or planned at the facility in response to
greenhouse gas regulations for new or existing fossil fuel-fired
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.
(d) Other factors as appropriate.
The EPA proposes to clarify that the discharger must provide
relevant, site-specific information for consideration of these factors
by the permitting authority. Environmental groups informed the EPA that
facilities had filed permit applications for, and states had granted,
delayed applicability dates based on information about a facility other
than the one being permitted. This was not the intent of the 2015 rule,
and the EPA solicits comment on other potential misunderstandings of
the factors presented in the 2015 rule that may have caused confusion
or led to misunderstandings.
As specified in factor (b), the permitting authority must also
consider scheduling for installation of equipment, which includes a
consideration of facility changes planned or being made to comply with
certain other key rules that affect the steam electric power generating
industry. As specified in factor (c), for the FGD wastewater
requirements only, the permitting authority must consider whether it is
appropriate to allow more time for implementation in order to ensure
that the facility has appropriate time to optimize any relevant
technologies.
The ``as soon as possible'' date determined by the permitting
authority may or may not be different for each wastestream. The
permitting authority should provide a well-documented justification of
how it determined the ``as soon as possible'' date in the fact sheet or
administrative record for the permit. If the permitting authority
determines a date later than November 1, 2020, the justification should
explain why allowing additional time to meet the proposed limitations
is appropriate, and why the discharger cannot meet the effluent
limitations as of November 1, 2020. In cases where the facility is
already operating the proposed BAT technology basis for a specific
wastestream (e.g., dry FA handling system), operates the majority of
the proposed BAT technology basis (e.g., FGD chemical precipitation and
biological treatment, without sulfide addition), or expects that
relevant treatment and process changes would be in place prior to
November 1, 2020 (for example due to the CCR rule), it would not
usually be appropriate to allow additional time beyond that date.
Regardless, in all cases, the permitting authority would make clear in
the permit by what date the facility must meet the proposed
limitations, and that date, as proposed, would be no later than
December 31, 2023, for BA transport water, or December 31, 2025, for
FGD wastewater.
Where a discharger chooses to participate in the VIP and be subject
to effluent limitations for FGD wastewater based on membranes, the
permitting authority must allow the facility up to December 31, 2028,
to meet those limitations. Again, the permit must make clear that the
facility must meet the limitations by December 31, 2028.
2. Implementation for the Low Utilization Subcategory
The EPA is proposing to establish a new subcategory for low
utilization boilers with net generation below 876,000 MWh per year. The
EIA defines net generation as, ``The amount of gross generation less
the electrical energy consumed at the generating station(s) for station
service or auxiliaries. Note: Electricity required for pumping at
pumped-storage plants is regarded as electricity for station service
and is deducted from gross generation.'' \103\ Unlike other
subcategories, which often require that a facility possess some static
characteristic (e.g., less than 50 MW nameplate capacity), the proposed
low utilization subcategory is based on the fluctuating net generation
reported annually to the EIA. Thus, the EPA is clarifying how
permitting authorities can determine whether a facility qualifies for
this subcategorization, and how limitations for boilers in this
subcategorization are to be implemented.
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\103\ See EIA Glossary, available online at: https://www.eia.gov/tools/glossary/index.php?id=N.
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a. Determining Boiler Net Generation
When a facility seeks to have limitations for one or more
subcategorized boilers incorporated into its permit, the EPA is
proposing that the facility provide the permitting authority its
calculation of the average of the most recent two calendar years of net
generation for that boiler(s). A facility wishing to seek this
subcategory, must operate below this threshold before the latest
implementation dates, but a permitting authority should also refrain
from establishing a ``no later than date'' which would restrict a
facility from demonstrating two years of reduced net generation. This
average should primarily be collected and calculated using data
developed for reporting to the EIA, since using net generation
information already collected for the EIA will both eliminate the
potentially unnecessary paperwork burden of a separate information
gathering and calculations and allow the permitting authority to more
easily verify the accuracy of the reported values. If it is necessary
for a facility to apportion facility-wide energy consumption not
specifically attributable to individual boilers, the facility must
apportion this consumption proportionally, by boiler nameplate
capacity, unless it adequately documents a sufficient rationale for an
alternate apportionment. The use of a two-year average will ensure that
a low utilization boiler responding to a single extreme demand event in
one year (e.g.,
[[Page 64666]]
unexpectedly high peak demand in summer or winter) can still qualify
for this subcategory if its average net generation over the two years
remains below 876,000 MWh. Furthermore, the facility must annually
provide the permitting authority an updated two-year average net
generation for each subcategorized boiler within 60 days of submitting
annual net generation information to the EIA.
b. Tiering Limitations
In cases where a facility seeks to have limitations for this
subcategory incorporated into its permit, the EPA is proposing that a
permitting authority incorporate two additional features. First, the
EPA is proposing that the limitations for this subcategory be included
as the first of two sets of limitations. The second set of limitations
would be those applicable to the rest of the steam electric generation
point source category. Second, the EPA is proposing that these tiered
limits have a two-year timeframe to be implemented for a facility
exceeding the two-year net generation requirements as measured per
calendar year. For example, if a facility reported it exceeded a two-
year average net generation of 876,000 MWh for a unit, it would have
two years before discharges of FGD wastewater and BA transport water
would henceforth be subject to the second tier of limitations.\104\
Application of the second tier would preclude future use of the low
utilization subcategory.
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\104\ Once a facility installs the capital equipment needed to
meet the second tier of limitations, O&M costs will be proportional
to the utilization of the boiler, and thus would no longer result in
disproportionate costs.
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These tiered limitations would ensure that, if a boiler that
qualified for this subcategorization changes its operation such that it
no longer qualifies, it would be automatically subject to the second
set of limitations. An automatic feature makes sense for several
reasons. Tiered limitations are beneficial to the regulated facility
because they provide certainty that the facility would not be
considered in violation of its permit initially, when exceeding the
required net generation, nor subsequently, during the two-year
timeframe over which it has to meet the second tier of effluent
limitations. Two years is also consistent with the engineering
documents provided to the EPA for the installation of the appropriate
technologies. Tiered limitations are beneficial to the state because
they avoid the potentially onerous permit modification process and its
burden to the permitting authority. Finally, tiered limitations are
beneficial to the environment because they ensure a timely transition
to more stringent limitations as soon as the reason for the less
stringent limitations (disproportionate cost) is gone. The EPA solicits
comment on the inclusion of tiered limitations.
3. Addressing Withdrawn or Delayed Retirement
Since the 2015 rule, the EPA has learned of several instances when
facilities have withdrawn or delayed retirement announcements for coal-
fired boilers and facilities. These instances can be grouped into two
categories. First, some delays were involuntary, resulting from orders
issued by the Department of Energy (DOE) or Public Utility Commissions
(PUCs). The remaining announcements were withdrawn or delayed
voluntarily due to changed circumstances. While both the voluntary and
involuntary changes to announced retirements were infrequent, the EPA
acknowledges that such changes will necessarily impact a facility's
status with regard to some of the new subcategories in today's
proposal. These situations are discussed below. For further information
on announced retirements, see DCN SE07207.
a. Involuntary Retirement Delays
At least five facilities with announced retirement dates had those
dates involuntarily delayed as a result of the DOE issuing orders under
Section 202(c) of the Federal Power Act, or a PUC issuing a reliability
must-run agreement. Such involuntary operations have raised questions
about the conflict between legal obligations to produce electricity and
legal obligations under environmental statutes.\105\ Today's proposal
would subcategorize low utilization boilers and boilers retiring by
2028, subjecting those subcategories to less stringent limitations.
However, both utilization and retirement could be impacted by
involuntary orders and agreements. Thus, the EPA proposes a savings
clause that would be included in all permits where a facility seeks
limitations under one of these two subcategories. Such a savings clause
would protect a facility which involuntarily fails to qualify for the
subcategory for low utilization or retiring boilers, and would allow
that facility to prove that, but for the order or agreement, it would
have qualified for the subcategory. The EPA solicits comment on whether
the proposed savings clause is broad enough to address all scenarios
that may result in a mandatory order to operate a boiler.
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\105\ Moeller, James. 2013. Clean air vs. electric reliability:
The case of the Potomac River Generating Station. September.
Available online at: https://scholarlycommons.law.wlu.edu/cgi/viewcontent.cgi?referer=https://www.google.com/&httpsredir=1&article=1077&context=jece.
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b. Voluntary Retirement Withdrawals and Delays
Units at five facilities with announced retirement dates had those
dates voluntarily withdrawn or delayed due to changed situations,
including market conditions, unavailability of natural gas pipelines,
changes in environmental regulations, and sale of the facility. Like
the involuntary retirement delays discussed in the section above, these
situations could impact a facility's qualification for the proposed
subcategories for low utilization boilers and boilers retiring by 2028.
Unlike the involuntary retirement delays, these voluntary delays and
withdrawals can be accounted for through the normal integrated resource
planning process. Thus, the EPA does not propose a similar savings
clause for such units. Instead, a facility should carefully plan its
implementation of the ELGs.
B. Reporting and Recordkeeping Requirements
This proposal includes five new reporting and recordkeeping
standards. First, the EPA is proposing a reporting and recordkeeping
standard for facilities operating high recycle rate BA systems. The EPA
is proposing that such facilities submit the calculation of the primary
active wetted BA system volume, which means the maximum volumetric
capacity of BA transport water in all piping (including recirculation
piping) and primary tanks of a wet bottom ash system, excluding the
volumes of installed spares, redundancies, maintenance tanks, other
secondary bottom ash system equipment, and non-bottom ash transport
systems that may direct process water to the bottom ash system. This
ensures that the permitting authority can verify the volume of
discharge allowed for a high recycle rate system. The EPA solicits
comment on the specific components of the BA transport water system
that should be included and/or excluded from the calculation of primary
active wetted BA system volume.
Second, the EPA is proposing a reporting and recordkeeping
requirement for facilities seeking subcategorization of low utilization
boilers. The EPA is proposing that, as part of any permit renewal or
re-opening, such facilities submit a calculation of the two-year
average net generation for each applicable boiler to
[[Page 64667]]
the permitting authority, including underlying information. Once any
limitations of this subcategory are applicable, the EPA is proposing
that such a facility annually recertify that the boiler continues to
meet the requirements of this subcategory, along with an updated two-
year average net generation calculation and information for each
applicable boiler. As proposed, if a boiler exceeds the MWh
requirements of this subcategory, no further recordkeeping or reporting
would be required, as this boiler would be treated the same as the rest
of the steam electric point source category after the necessary
treatment equipment was installed and operational at the end of two
years.
Third, as described in Section VII.C.2, facilities with boilers
that qualify for the low-utilization subcategory and that discharge BA
transport water, would be required to develop and implement a BMP plan
to minimize the discharge of pollutants by recycling as much BA
transport water as practicable back to the BA handling system. As part
of any permit renewal or any re-opening, such facilities would need to
submit their facility-specific plan (certified that it meets the
proposed requirements of 40 CFR 423.13(k)(3)) along with a
certification that the plan is being implemented. For each permit
renewal, the plan and PE certification should be updated and provided
to the permitting authority.
Fourth, the EPA is proposing reporting and recordkeeping
requirements for facilities seeking subcategorization for a boiler(s)
retiring by December 31, 2028. The EPA is proposing that, as part of
the permit renewal or re-opening, which are when a facility would make
this request, such facilities submit a one-time certification to the
permitting authority stating the date of expected retirement from the
combustion of coal, and provide a citation to any filing, integrated
resource plan, or other documentation in support of that date. This
citation is meant to provide the permitting authority further evidence
that a boiler will, in fact, cease the production of electricity by
that date.
Finally, the EPA is proposing reporting and recordkeeping
requirements for facilities invoking the proposed savings clause. The
EPA is proposing that such facilities must demonstrate that a boiler
would have qualified for the subcategory at issue, if not for the
emergency order issued by the DOE under Section 202(c) of the Federal
Power Act or PUC reliability must-run agreement. Furthermore, the EPA
is proposing to require a copy of such order or agreement as an
attachment to the submission.
C. Site-Specific Water Quality-Based Effluent Limitations
The EPA regulations at 40 CFR 122.44(d)(1) require that each NPDES
permit shall include any requirements, in addition to or more stringent
than effluent limitations guidelines or standards promulgated pursuant
to sections 301, 304, 306, 307, 318 and 405 of the CWA, necessary to
achieve water quality standards established under section 303 of the
CWA, including state narrative criteria for water quality. Furthermore,
those same regulations require that limitations must control all
pollutants, or pollutant parameters (either conventional,
nonconventional, or toxic pollutants) which the Director determines are
or may be discharged at a level which will cause, have the reasonable
potential to cause, or contribute to an excursion above any state water
quality standard, including state narrative criteria for water quality.
Bromide was discussed in the preamble to the 2015 rule as a
parameter for which water quality-based effluent limitations may be
appropriate. The EPA stated its recommendation that permitting
authorities carefully consider whether water quality-based effluent
limitations on bromide or TDS would be appropriate for FGD wastewater
discharges from steam electric facilities upstream of drinking water
intakes. The EPA also stated its recommendation that the permitting
authority notify any downstream drinking water treatment plants of the
discharge of bromide.
The EPA is not proposing additional limitations on bromide for FGD
wastewater beyond the removals that might be accomplished by facilities
choosing to implement the VIP limitations, though the EPA is soliciting
comment on the three potential bromide-specific sub-options presented
in Section VII of this preamble. The record continues to suggest that
state permitting authorities should consider establishing water
quality-based effluent limitations that are protective of populations
served by downstream drinking water treatment facilities. As described
in Section XII, the analysis of changes in human health benefits
associated with changes in bromide discharges are concentrated at a
small number of sites. This supports the EPA's determination that
potential discharges are best addressed using site-specific, water
quality-based effluent limitations established by permitting
authorities for the small number of steam electric facilities that may
impact downstream drinking water treatment facilities.
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)
This proposed rule is an economically significant regulatory action
that was submitted to the Office of Management and Budget (OMB) for
review. Any changes made in response to OMB recommendations have been
documented in the docket. The EPA prepared an analysis of the potential
social costs and benefits associated with this action. This analysis is
contained in Chapter 13 of the BCA, available in the docket. The
analysis in the BCA builds on compliance costs and certain other
assumptions regarding compliance years discussed in the RIA to estimate
the incremental social costs and benefits of the four proposed options
relative to the baseline. Analyzing the options against the baseline
enables the Agency to characterize the incremental impact of ELG
revisions proposed by this action.
Table XV-1 presents the annualized value of the social costs and
benefits over 27 years and discounted using a three percent discount
rate as compared to the updated baseline. Table XV-2 presents
annualized values using a seven percent discount rate. In both tables,
negative costs indicate avoided costs (i.e., cost savings) and negative
benefits indicate forgone benefits.
Table XV-1--Total Monetized Annualized Benefits and Costs of Proposed Regulatory Options
[Million of 2018$, three percent discount rate] a
----------------------------------------------------------------------------------------------------------------
Total monetized benefits c d e
Regulatory option Total social -----------------------------------------------
costs b Low estimate Mid estimate High estimate
----------------------------------------------------------------------------------------------------------------
Option 1........................................ -$130.6 -$41.0 -$43.6 -$86.6
Option 2........................................ -136.3 14.8 19.6 68.5
[[Page 64668]]
Option 3........................................ -90.1 35.1 41.3 109.4
Option 4........................................ 11.9 98.4 105.9 188.9
----------------------------------------------------------------------------------------------------------------
\a\ All social costs and benefits were annualized over 27 years using a 3% discount rate. Negative costs
indicate avoided costs and negative benefits indicate forgone benefits. All estimates are rounded to one
decimal point, so figures may not sum due to independent rounding.
\b\ Total social costs are compliance costs to facilities accounting for the timing those costs are incurred.
\c\ Total monetized benefits exclude other benefits discussed qualitatively.
\d\ The EPA estimated the air-related benefits for Option 2 using the IPM sensitivity analysis scenario that
includes the ACE rule in the baseline (IPM-ACE). EPA extrapolated estimates for Options 1 and 3 air-related
benefits from the estimate for Option 2 that is based on IPM-ACE outputs. The values for Option 4 air-related
benefits were estimated using the IPM analysis scenario that does not include the ACE rule in the baseline.
See Chapter 8 in the BCA for details). The EPA estimated air-related benefits for Options 1 and 3 by
multiplying the total costs for each option by the ratio of [air-related benefits/total social costs] for
Option 2. The EPA did not monetize benefits of changes in NOX and SO2 emissions and associated changes in
PM2.5 levels for any option.
\e\ The EPA estimated use and nonuse values for water quality improvements using two different meta-regression
models of WTP. One model provides the low and high bounds while a different model provides a central estimate
(included in this table under the mid-range column). For this reason, the mid benefit estimate differs from
the midpoint of the benefits range. For details, see Chapter 5 in the BCA.
Table XV-2--Total Monetized Annualized Benefits and Costs of Proposed Regulatory Options
[Million of 2018$, seven percent discount rate] a
----------------------------------------------------------------------------------------------------------------
Total monetized benefits c d e
Regulatory option Total social -----------------------------------------------
costs \b\ Low estimate Mid estimate High estimate
----------------------------------------------------------------------------------------------------------------
Option 1........................................ -$154.0 -$13.7 -$16.0 -$53.3
Option 2........................................ -166.2 28.4 32.6 74.4
Option 3........................................ -119.5 37.1 42.5 100.9
Option 4........................................ -27.3 70.6 77.2 148.4
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\a\ All social costs and benefits were annualized over 27 years using a 7% discount rate. Negative costs
indicate avoided costs and negative benefits indicate forgone benefits. All estimates are rounded to one
decimal point, so figures may not sum due to independent rounding.
\b\ Total social costs are compliance costs to facilities accounting for the timing those costs are incurred.
\c\ Total monetized benefits exclude other benefits discussed qualitatively.
\d\ The EPA estimated the air-related benefits for Option 2 using the IPM sensitivity analysis scenario that
includes the ACE rule in the baseline (IPM-ACE). EPA extrapolated estimates for Options 1 and 3 air-related
benefits from the estimate for Option 2 that is based on IPM-ACE outputs. The values for Option 4 air-related
benefits were estimated using the IPM analysis scenario that does not include the ACE rule in the baseline.
See Chapter 8 in the BCA for details). The EPA estimated air-related benefits for Options 1 and 3 by
multiplying the total costs for each option by the ratio of [air-related benefits/total social costs] for
Option 2. The EPA did not monetize benefits of changes in NOX and SO2 emissions and associated changes in
PM2.5 levels for any option.
\e\ The EPA estimated use and nonuse values for water quality improvements using two different meta-regression
models of WTP. One model provides the low and high bounds while a different model provides a central estimate
(included in this table under the mid-range column). For this reason, the mid benefit estimate differs from
the midpoint of the benefits range. For details, see Chapter 5 in the BCA.
B. Executive Order 13771 (Reducing Regulation and Controlling
Regulatory Costs)
The proposed regulatory options would be an Executive Order 13771
deregulatory action. Details on the estimated cost savings of the
regulatory options are located in the RIA, and in Tables XV-1 and XV-2
above.
C. Paperwork Reduction Act
OMB has previously approved the information collection requirements
contained in the existing regulations 40 CFR part 423 under the
provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and
has assigned OMB control number 2040-0281. The OMB control numbers for
the EPA's regulations in 40 CFR are listed in 40 CFR part 9.
The EPA estimated small changes in monitoring costs at steam
electric facilities under the regulatory options presented in today's
proposal relative to the baseline. As proposed, these changes would
apply to facilities for which the proposed subcategories are
applicable. In some cases, in lieu of these monitoring requirements,
facilities would have additional paperwork burden such as that
associated with certifications and applicable BMP plans. See Section
VII of this preamble. However, some facilities would also realize
savings, relative to the baseline, by no longer monitoring pollutants
for some subcategories of boilers (and because their applicable
limitations and standards are based on less costly technologies). The
EPA projects that the burden associated with the new proposed paperwork
requirements would be largely off-set by the reduced burden associated
with less monitoring; therefore, the Agency projects that the proposal
would have no net effect on the burden of the approved information
collection requirements. With respect to permitting authorities, based
on the information in its record, the EPA also does not expect any of
the regulatory options in today's proposal to increase or decrease
their burden. The proposed options would not change permit application
requirements or the associated review; they would not affect the number
of permits issued to steam electric facilities; nor would the options
change the efforts involved in developing or reviewing such permits.
Accordingly, the EPA estimated no net change (i.e., no increase or
decrease) in the cost burden to federal or state governments or
dischargers associated with any of the regulatory options in this
proposed rule.
D. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice-and-comment
[[Page 64669]]
rulemaking requirements under the Administrative Procedure Act or any
other statute, unless the agency certifies that the rule will not have
a significant economic impact on a substantial number of small
entities. Small entities include small businesses, small organizations,
and small governmental jurisdictions.
The Agency certifies that this action will not have a significant
economic impact on a substantial number of small entities under the
RFA. The basis for this finding is documented in Chapter 8 of the RIA,
included in the docket and summarized below.
The EPA estimates that 243 to 478 entities own steam electric
facilities to which the regulatory options would apply, of which 79 to
127 are small. These small ownership entities own a total of 139 steam
electric facilities. The EPA considered the impacts of the regulatory
options presented in this proposal on small businesses using a cost-to-
revenue test. The analysis compares the cost of implementing controls
for BA and FGD wastewater under the four regulatory options to those
under the baseline (which reflects the 2015 rule as explained in
Section V of this preamble). Small entities estimated to incur
compliance costs exceeding one or more of the one percent and three
percent impact thresholds were identified as potentially incurring a
significant impact. The EPA's analysis shows that four small entities
(municipalities) are expected to incur costs equal to or greater than
one percent of revenue to meet the 2015 rule; for two of these
municipalities, the costs to meet the 2015 rule exceed three percent of
revenue. Cost savings provided under the regulatory options reduce the
impacts on these small entities to varying degrees. Option 2 has the
greatest mitigating effect on small entities, reducing to 2 the number
of small entities incurring costs equal to or greater than one percent
of revenue, and to 1 the entities with costs greater than three percent
of revenue. Options 1, 3, and 4 have similar mitigating effects, with
one fewer small entity incurring costs equal to or greater than one
percent of revenue. The number of small entities exceeding either the
one or three percent impact threshold in the baseline is small in the
absolute and represents small percentages of the total estimated number
of small entities; the cost savings provided by the regulatory options
further support the EPA's finding of no significant impact on a
substantial number of small entities (No SISNOSE).
E. Unfunded Mandates Reform Act
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2
U.S.C. 1531-1538, requires federal agencies, unless otherwise
prohibited by law, to assess the effects of their regulatory actions on
state, local, and tribal governments, and the private sector. An action
contains a federal mandate if it may result in expenditures of $100
million or more (annually, adjusted for inflation) for state, local,
and tribal governments, in the aggregate, or the private sector in any
one year ($160 million in 2018).
The EPA finds that this action is not subject to the requirements
of UMRA section 203 because the expenditures are less than $160 million
or more in any one year. As detailed in Chapter 9 of the RIA, for its
assessment of the impact of potential changes in compliance
requirements on small governments (governments for populations of less
than 50,000), the EPA estimated the changes in costs for compliance
with the regulatory options relative to the baseline for different
categories of entities. All four regulatory options presented in this
proposal result in lower compliance costs (cost savings) when compared
to the baseline. Compared to $44.1 million in the baseline, the Agency
estimates that the change in maximum cost in any one year to state,
local, or tribal governments range from -$23.5 million under Option 1
to -$6.0 million under Option 4, with an incremental cost for Option 2
of -$23.0 million. Compared to $841.3 million in baseline, the
incremental cost in any given year to the private sector ranges from -
$444.5 million under Option 4 to -$327.5 million under Option 1, with
Option 2 having an incremental cost of -$405 million. From these
incremental cost values, the EPA determined that none of the regulatory
options would constitute a federal mandate that may result in
expenditures of $160 million (in 2018 dollars) or more for state,
local, and tribal governments in the aggregate, or the private sector
in any one year. Chapter 9 of the RIA report provides details of these
analyses.
This action is also not subject to the requirements of UMRA section
203 because it contains no regulatory requirements that might
significantly or uniquely affect small governments. To assess whether
the regulatory options presented in this proposal would affect small
governments in a way that is disproportionately burdensome in
comparison to the effect on large governments, the EPA compared total
incremental costs and incremental costs per facility for small
governments and large governments. The EPA also compared the changes in
per facility costs incurred for small-government-owned facilities with
those incurred by non-government-owned facilities. The Agency evaluated
both average and maximum annualized incremental costs per facility.
These analyses, which are detailed in Chapter 9 of the RIA, find that
small governments would not be significantly or uniquely affected by
the regulatory options presented in this proposal.
F. Executive Order 13132: Federalism
Under Executive Order (E.O.) 13132, the EPA may not issue an action
that has federalism implications, that imposes substantial direct
compliance costs, and that is not required by statute, unless the
federal government provides the funds necessary to pay the direct
compliance costs incurred by state and local governments or the EPA
consults with state and local officials early in development of the
action.
The EPA anticipates that none of the regulatory options presented
in this proposed rule would impose incremental administrative burden on
states due to issuing, reviewing, and overseeing compliance with
discharge requirements. Nevertheless, the EPA solicits comment on
examples and data that demonstrate net impacts compared to the 2015
rule baseline which would allow the Agency to evaluate these impacts
for the final rule.
As detailed in Chapter 9 of the RIA in the docket for this action,
the EPA has identified 160 steam electric facilities owned by state or
local governments, of which 16 facilities are estimated to incur costs
to comply with the BA transport water and FGD limitations in the 2015
rule. However, all four regulatory options presented in this proposal
provide cost savings as compared to the baseline. The difference in the
maximum costs of the options as compared to the baseline ranges from -
$6 million under Option 4 to -$23.5 million under Option 2. Based on
this information, the EPA proposes to conclude that this action would
not impose substantial direct compliance costs on state or local
governments.
G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in E.O.
13175 (65 FR 67249, November 9, 2000). It will not have substantial
direct effects on tribal governments, on the relationship between the
federal government and the
[[Page 64670]]
Indian tribes, or on the distribution of power and responsibilities
between the federal government and Indian tribes, as specified in E.O.
13175.
The EPA assessed potential tribal implications for the regulatory
options presented in this proposed rule arising from three main
changes: (1) Direct compliance costs incurred by facilities; (2)
impacts on drinking water systems downstream from steam electric
facilities; and (3) administrative burden on governments that implement
the NPDES program.
Regarding direct compliance costs, the EPA's analyses show that no
steam electric facilities with BA transport water or FGD discharges are
owned by tribal governments. Regarding impacts on drinking water
systems, the EPA identified 15 public water systems operated by tribal
governments that may be affected by bromide discharges from steam
electric facilities. These systems serve a total of 18,917 people. The
EPA estimated changes in bladder cancer risk and the resulting health
benefits for the four regulatory options in comparison to the baseline.
This analysis, which is detailed in Chapter 4 of the BCA, finds very
small changes in exposure between the baseline and regulatory options,
amounting to very small changes in risk for this population. Finally,
regarding administrative burden, no tribal governments are currently
authorized pursuant to section 402(b) of the CWA to implement the NPDES
program. Based on this information, the EPA concluded that none of the
regulatory options presented in the proposed rule would have
substantial direct effects on tribal governments.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is not subject to E.O. 13045 (62 FR 19885, April 23,
1997) because the EPA does not expect that the environmental health
risks or safety risks associated with steam electric facility
discharges addressed by this action present a disproportionate risk to
children. This action's health risk assessments are in Chapters 4 and 5
of the BCA and are summarized below.
The EPA identified several ways in which the regulatory options
presented in this proposal could affect children, including by
potentially increasing health risks from changes in exposure to
pollutants present in steam electric facility FGD wastewater and BA
transport water discharges, or through impacts of the discharges on the
quality of source water used by public water systems. This increase
arises from less stringent pollutant limitations or later deadlines for
meeting effluent limitations under certain regulatory options presented
in this proposal as compared to the baseline. In particular, the EPA
quantified the changes in IQ losses from lead exposure among pre-school
children and from mercury exposure in utero resulting from maternal
fish consumption under the four regulatory options, as compared to the
baseline. The EPA also estimated changes in the number of children with
very high blood lead concentrations. Finally, the EPA estimated changes
in the lifetime risk of developing bladder cancer due to exposure to
trihalomethanes in drinking water. The EPA did not estimate children-
specific risk because these adverse health effects normally follow
long-term exposure. These analyses show that all of the regulatory
options presented in this proposal would have a small, and not
disproportionate, impact on children.
I. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This action is not a ``significant energy action,'' as defined by
E.O. 13211 (66 FR 28355, May 22, 2001) because it is not likely to have
a significant adverse effect on the supply, distribution, or use of
energy.
The Agency analyzed the potential energy effects of the regulatory
options presented in this proposal relative to the baseline and found
minimal or no impacts on electricity generation, generating capacity,
cost of energy production, or dependence on a foreign supply of energy.
Specifically, the Agency's analysis found that none of the regulatory
options would reduce electricity production by more than 1 billion
kilowatt hours per year or by 500 megawatts of installed capacity under
either of the options analyzed, nor would the option increase U.S.
dependence on foreign supplies of energy. For more detail on the
potential energy effects of the regulatory options in this proposal,
see Section 10.7 in the RIA, available in the docket.
J. National Technology Transfer and Advancement Act
This proposed rulemaking does not involve technical standards.
K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
The EPA conducted the analysis in three ways. First, the EPA
summarized the demographic characteristics of individuals living in
proximity to steam electric facilities with BA transport water or FGD
discharges and thus are likely to be affected by the facility
discharges and changes in air emissions resulting from the regulatory
options presented in this proposal. This first analysis focuses on the
spatial distribution of minority and low-income groups to determine
whether these groups are more or less represented in the populations
that are expected to be affected by the regulatory options, based on
their proximity to steam electric facilities. The results show that,
when compared to state averages, all affected communities are poorer
and a large majority of affected communities have more minority
residents than average.
Second, the EPA summarized the demographic characteristics of
individuals served by public water systems (PWS) downstream from steam
electric facilities and potentially affected by bromide discharges. The
results show that the majority of county populations potentially
affected by changes in drinking water quality as a result of steam
electric facility discharges are poorer and have more minority
residents than the state average.
Finally, the EPA conducted analyses of populations exposed to steam
electric power facility FGD wastewater and BA transport water
discharges through consumption of recreationally caught fish by
estimating exposure and health effects by demographic cohort. Where
possible, the EPA used analytic assumptions specific to the demographic
cohorts--e.g., fish consumption rates specific to different racial
groups. Recreational anglers and members of their households, including
children, are expected to experience forgone benefits from an increase
in pollutant concentrations in fish tissue under all of the regulatory
options. EPA estimated forgone benefits to children (i.e., IQ
decrements) from increased mercury exposure in the populations that
live below the poverty line and/or minority populations.
The results show that the regulatory options would result in
forgone benefits to these populations and that these changes may
disproportionately affect communities in cases where the regulatory
options increase pollutant exposure compared to the baseline. Overall
however, the EPA's analysis, which is detailed in Chapter 14 of the
BCA, finds very small changes in exposure between the baseline and
regulatory options, amounting to very small changes in risk for this
population. The EPA solicits comment on the assumptions and
uncertainties included in this analysis.
[[Page 64671]]
L. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action is a ``major rule'' as defined by 5
U.S.C. 804(2).
Appendix A to the Preamble: Definitions, Acronyms, and Abbreviations
Used in This Preamble
The following acronyms and abbreviations are used in this
preamble.
Administrator. The Administrator of the U.S. Environmental
Protection Agency.
Agency. U.S. Environmental Protection Agency.
BAT. Best available technology economically achievable, as
defined by CWA sections 301(b)(2)(A) and 304(b)(2)(B).
Bioaccumulation. General term describing a process by which
chemicals are taken up by an organism either directly from exposure
to a contaminated medium or by consumption of food containing the
chemical, resulting in a net accumulation of the chemical by an
organism due to uptake from all routes of exposure.
BMP. Best management practice.
BA. The ash, including boiler slag, which settles in the furnace
or is dislodged from furnace walls. Economizer ash is included when
it is collected with BA.
BPT. The best practicable control technology currently available
as defined by sections 301(b)(1) and 304(b)(1) of the CWA.
CBI. Confidential Business Information.
CCR. Coal Combustion Residuals.
Clean Water Act (CWA). The Federal Water Pollution Control Act
Amendments of 1972 (33 U.S.C. 1251 et seq.), as amended, e.g., by
the Clean Water Act of 1977 (Pub. L. 95-217), and the Water Quality
Act of 1987 (Pub. L. 100-4).
Combustion residuals. Solid wastes associated with combustion-
related power facility processes, including fly and BA from coal-,
petroleum coke-, or oil-fired units; FGD solids; FGMC wastes; and
other wastewater treatment solids associated with combustion
wastewater. In addition to the residuals that are associated with
coal combustion, this also includes residuals associated with the
combustion of other fossil fuels.
Direct discharge. (a) Any addition of any ``pollutant'' or
combination of pollutants to ``waters of the United States'' from
any ``point source,'' or (b) any addition of any pollutant or
combination of pollutant to waters of the ``contiguous zone'' or the
ocean from any point source other than a vessel or other floating
craft which is being used as a means of transportation. This
definition includes additions of pollutants into waters of the
United States from: Surface runoff which is collected or channeled
by man; discharges though pipes, sewers, or other conveyances owned
by a State, municipality, or other person which do not lead to a
treatment works; and discharges through pipes, sewers, or other
conveyances, leading into privately owned treatment works. This term
does not include an addition of pollutants by any ``indirect
discharger.''
Direct discharger. A facility that discharges treated or
untreated wastewaters into waters of the U.S.
DOE. Department of Energy.
Dry BA handling system. A system that does not use water as the
transport medium to convey BA away from the boiler. It includes
systems that collect and convey the ash without any use of water, as
well as systems in which BA is quenched in a water bath and then
mechanically or pneumatically conveyed away from the boiler. Dry BA
handling systems do not include wet sluicing systems (such as remote
MDS or complete recycle systems).
Effluent limitation. Under CWA section 502(11), any restriction,
including schedules of compliance, established by a state or the
Administrator on quantities, rates, and concentrations of chemical,
physical, biological, and other constituents which are discharged
from point sources into navigable waters, the waters of the
contiguous zone, or the ocean, including schedules of compliance.
EIA. Energy Information Administration.
ELGs. Effluent limitations guidelines and standards.
E.O. Executive Order.
EPA. U.S. Environmental Protection Agency.
FA. Fly Ash
Facility. Any NPDES ``point source'' or any other facility or
activity (including land or appurtenances thereto) that is subject
to regulation under the NPDES program.
FGD. Flue Gas Desulfurization.
FGD Wastewater. Wastewater generated specifically from the wet
FGD scrubber system that comes into contact with the flue gas or the
FGD solids, including, but not limited to, the blowdown or purge
from the FGD scrubber system, overflow or underflow from the solids
separation process, FGD solids wash water, and the filtrate from the
solids dewatering process. Wastewater generated from cleaning the
FGD scrubber, cleaning FGD solids separation equipment, cleaning FGD
solids dewatering equipment, or that is collected in floor drains in
the FGD process area is not considered FGD wastewater.
Fly Ash. The ash that is carried out of the furnace by a gas
stream and collected by a capture device such as a mechanical
precipitator, electrostatic precipitator, and/or fabric filter.
Economizer ash is included in this definition when it is collected
with fly ash. Ash is not included in this definition when it is
collected in wet scrubber air pollution control systems whose
primary purpose is particulate removal.
Groundwater. Water that is found in the saturated part of the
ground underneath the land surface.
Indirect discharge. Wastewater discharged or otherwise
introduced to a POTW.
IPM. Integrated Planning Model.
Landfill. A disposal facility or part of a facility where solid
waste, sludges, or other process residuals are placed in or on any
natural or manmade formation in the earth for disposal and which is
not a storage pile, a land treatment facility, a surface
impoundment, an underground injection well, a salt dome or salt bed
formation, an underground mine, a cave, or a corrective action
management unit.
MDS. Mechanical drag system.
Mechanical drag system. BA handling system that collects BA from
the bottom of the boiler in a water-filled trough. The water bath in
the trough quenches the hot BA as it falls from the boiler and seals
the boiler gases. A drag chain operates in a continuous loop to drag
BA from the water trough up an incline, which dewaters the BA by
gravity, draining the water back to the trough as the BA moves
upward. The dewatered BA is often conveyed to a nearby collection
area, such as a small bunker outside the boiler building, from which
it is loaded onto trucks and either sold or transported to a
landfill. The MDS is considered a dry BA handling system because the
ash transport mechanism is mechanical removal by the drag chain, not
the water.
Mortality. Death rate or proportion of deaths in a population.
NAICS. North American Industry Classification System.
NPDES. National Pollutant Discharge Elimination System.
ORCR. Office of Resource Conservation and Recovery.
Paste. A substance containing solids in a fluid which behaves as
a solid until a force is applied which causes it to behave like a
fluid.
Paste Landfill. A landfill which receives any paste designed to
set into a solid after the passage of a reasonable amount of time.
Point source. Any discernable, confined, and discrete
conveyance, including but not limited to, any pipe, ditch, channel,
tunnel, conduit, well, discrete fissure, container, rolling stock,
concentrated animal feeding operation, or vessel or other floating
craft from which pollutants are or may be discharged. The term does
not include agricultural stormwater discharges or return flows from
irrigated agriculture. See CWA section 502(14), 33 U.S.C. 1362(14);
40 CFR 122.2.
POTW. Publicly owned treatment works. See CWA section 212, 33
U.S.C. 1292; 40 CFR 122.2, 403.3.
PSES. Pretreatment Standards for Existing Sources.
Publicly Owned Treatment Works. Any device or system, owned by a
state or municipality, used in the treatment (including recycling
and reclamation) of municipal sewage or industrial wastes of a
liquid nature that is owned by a state or municipality. This
includes sewers, pipes, or other conveyances only if they convey
wastewater to a POTW providing treatment. CWA section 212, 33 U.S.C.
1292; 40 CFR 122.2, 403.3.
RCRA. The Resource Conservation and Recovery Act of 1976, 42
U.S.C. 6901 et seq.
Remote MDS. BA handling system that collects BA at the bottom of
the boiler, then uses transport water to sluice the ash to a remote
MDS that dewaters BA using a similar configuration as the MDS. The
remote MDS is considered a wet BA handling system because the ash
transport mechanism is water.
RFA. Regulatory Flexibility Act.
SBA. Small Business Administration.
[[Page 64672]]
Sediment. Particulate matter lying below water.
Surface water. All waters of the United States, including
rivers, streams, lakes, reservoirs, and seas.
Toxic pollutants. As identified under the CWA, 65 pollutants and
classes of pollutants, of which 126 specific substances have been
designated priority toxic pollutants. see appendix A to 40 CFR part
423.
Transport water. Wastewater that is used to convey FA, BA, or
economizer ash from the ash collection or storage equipment, or
boiler, and has direct contact with the ash. Transport water does
not include low volume, short duration discharges of wastewater from
minor leaks (e.g., leaks from valve packing, pipe flanges, or
piping) or minor maintenance events (e.g., replacement of valves or
pipe sections).
UMRA. Unfunded Mandates Reform Act.
Wet BA handling system. A system in which BA is conveyed away
from the boiler using water as a transport medium. Wet BA systems
typically send the ash slurry to dewatering bins or a surface
impoundment. Wet BA handling systems include systems that operate in
conjunction with a traditional wet sluicing system to recycle all BA
transport water (remote MDS or complete recycle system).
Wet FGD system. Wet FGD systems capture sulfur dioxide from the
flue gas using a sorbent that has mixed with water to form a wet
slurry, and that generates a water stream that exits the FGD
scrubber absorber.
List of Subjects in 40 CFR Part 423
Environmental protection, Electric power generation, Power
facilities, Waste treatment and disposal, Water pollution control.
Dated: November 4, 2019.
Andrew R. Wheeler,
Administrator.
For the reasons stated in the preamble, the Environmental
Protection Agency proposes to amend 40 CFR part 423 as follows:
PART 423--STEAM ELECTRIC POWER GENERATING POINT SOURCE CATEGORY
0
1. The authority citation for part 423 continues to read as follows:
Authority: Secs. 101; 301; 304(b), (c), (e), and (g); 306; 307;
308 and 501, Clean Water Act (Federal Water Pollution Control Act
Amendments of 1972, as amended; 33 U.S.C. 1251; 1311; 1314(b), (c),
(e), and (g); 1316; 1317; 1318 and 1361).
0
2. Amend Sec. 423.11 by revising paragraphs (n), (p), and (t) and
adding paragraphs (u), (v), (w), (x), (y), (z), (aa), (bb), (cc), and
(dd).
Sec. 423.11 Specialized definitions.
* * * * *
(n) The term flue gas desulfurization (FGD) wastewater means any
wastewater generated specifically from the wet flue gas desulfurization
scrubber system that comes into contact with the flue gas or the FGD
solids, including but not limited to, the blowdown from the FGD
scrubber system, overflow or underflow from the solids separation
process, FGD solids wash water, and the filtrate from the solids
dewatering process. Wastewater generated from cleaning the FGD
scrubber, cleaning FGD solids separation equipment, cleaning FGD solids
dewatering equipment, cleaning FGD paste transportation piping, or that
is collected in floor drains in the FGD process area is not considered
FGD wastewater.
* * * * *
(p) The term transport water means any wastewater that is used to
convey fly ash, bottom ash, or economizer ash from the ash collection
or storage equipment, or boiler, and has direct contact with the ash.
Transport water does not include low volume, short duration discharges
of wastewater from minor leaks (e.g., leaks from valve packing, pipe
flanges, or piping), minor maintenance events (e.g., replacement of
valves or pipe sections), cleaning FGD paste transportation piping,
wastewater present in equipment when a facility is retired from
service, or maintenance purge water.
* * * * *
(t) The phrase ``as soon as possible'' means November 1, 2018
(except for purposes of Sec. 423.13(g)(1)(i) and (k)(1)(i), and Sec.
423.16(e) and (g), in which case it means November 1, 2020), unless the
permitting authority establishes a later date, after receiving site-
specific information from the discharger, which reflects a
consideration of the following factors:
(1) Time to expeditiously plan (including to raise capital),
design, procure, and install equipment to comply with the requirements
of this part.
(2) Changes being made or planned at the plant in response to:
(i) New source performance standards for greenhouse gases from new
fossil fuel-fired electric generating units, under sections 111, 301,
302, and 307(d)(1)(C) of the Clean Air Act, as amended, 42 U.S.C. 7411,
7601, 7602, 7607(d)(1)(C);
(ii) Emission guidelines for greenhouse gases from existing fossil
fuel-fired electric generating units, under sections 111, 301, 302, and
307(d) of the Clean Air Act, as amended, 42 U.S.C. 7411, 7601, 7602,
7607(d); or
(iii) Regulations that address the disposal of coal combustion
residuals as solid waste, under sections 1006(b), 1008(a), 2002(a),
3001, 4004, and 4005(a) of the Solid Waste Disposal Act of 1970, as
amended by the Resource Conservation and Recovery Act of 1976, as
amended by the Hazardous and Solid Waste Amendments of 1984, 42 U.S.C.
6906(b), 6907(a), 6912(a), 6944, and 6945(a).
(3) For FGD wastewater requirements only, an initial commissioning
period for the treatment system to optimize the installed equipment.
(4) Other factors as appropriate.
(u) The term ``FGD paste'' means any combination of FGD wastewater
treated with fly ash and/or lime prior to being landfilled, that is
engineered to form a solid through pozzolanic reactions.
(v) The term ``FGD paste transportation piping'' means any pipe,
valve, or related item used for transporting FGD paste from its point
of generation to a landfill.
(w) The term ``retired from service'' means the owner or operator
of a boiler no longer has, or is no longer required to have, the
necessary permission through a permit, license, or other legally
applicable form of permission to conduct electricity generation
activities under Federal, state, or local law, irrespective of whether
the owner and operator is subject to this part.
(x) The term ``high FGD flow'' means the maximum daily volume of
FGD wastewater that could be discharged by a facility is above 4
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.
(y) The term ``net generation'' means the amount of gross
electrical generation less the electrical energy consumed at the
generating station(s) for station service or auxiliaries as calculated
in paragraph 423.19(e) of this subpart.
(z) The term ``low utilization boiler'' means any boiler for which
the facility owner certifies, and annually recertifies, under 423.19(e)
that the two-year average annual net generation is below 876,000 MWh
per year.
(aa) The term ``primary active wetted bottom ash system volume''
means the maximum volumetric capacity of bottom ash transport water in
all piping (including recirculation piping) and primary tanks of a wet
bottom ash system, excluding the volumes of installed spares,
redundancies, maintenance tanks, other secondary bottom ash system
equipment, and non-bottom ash transport systems that may direct process
water to the bottom ash system as certified to in paragraph 423.19(c).
(bb) The term ``tank'' means a stationary device, designed to
contain
[[Page 64673]]
an accumulation of wastewater which is constructed primarily of non-
earthen materials (e.g., wood, concrete, steel, plastic) which provide
structural support.
(cc) The term ``maintenance purge water'' means any water being
discharged subject to paragraphs Sec. 423.13(k)(2)(i) or Sec.
423.16(g)(2)(i).
(dd) 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.
0
3. Amend Sec. 423.12 by revising paragraph (b)(11).
Sec. 423.12 Effluent limitations guidelines representing the degree
of effluent reduction attainable by the application of the best
practicable control technology currently available (BPT).
* * * * *
(b) * * *
(11) The quantity of pollutants discharged in FGD wastewater, flue
gas mercury control wastewater, combustion residual leachate,
gasification wastewater, or bottom ash maintenance purge water shall
not exceed the quantity determined by multiplying the flow of the
applicable wastewater times the concentration listed in table 1:
Table 1 to Paragraph (b)(11)
----------------------------------------------------------------------------------------------------------------
BPT effluent limitations
---------------------------------------------------
Pollutant or pollutant property Average of daily values
Maximum for any 1 day for 30 consecutive days
(mg/l) shall not exceed (mg/l)
----------------------------------------------------------------------------------------------------------------
TSS......................................................... 100.0 30.0
Oil and grease.............................................. 20.0 15.0
----------------------------------------------------------------------------------------------------------------
* * * * *
0
4. Amend Sec. 423.13 by:
0
a. Revising paragraph (g)(1)(i);
0
b. Redesignating paragraph (g)(2) as paragraph (g)(2)(i) and revising
the newly redesignated paragraph (g)(2)(i);
0
c. Adding paragraphs (g)(2)(ii) and (g)(2)(iii);
0
d. Revising paragraphs (g)(3)(i) and paragraph (k)(1)(i);
0
e. Redesignating paragraph (k)(2) as (k)(2)(ii) and revising newly
redesignated (k)(2)(ii); and
0
f. Adding paragraphs (k)(2)(i), (k)(2)(iii), and (k)(3).
The additions and revisions to read as follows.
Sec. 423.13 Effluent limitations guidelines representing the degree
of effluent reduction attainable by the application of the best
available technology economically achievable (BAT).
* * * * *
(g)(1)(i) FGD wastewater. Except for those discharges to which
paragraph (g)(2) or (g)(3) of this section applies, the quantity of
pollutants in FGD wastewater shall not exceed the quantity determined
by multiplying the flow of FGD wastewater times the concentration
listed in the table following this paragraph (g)(1)(i). Dischargers
must meet the effluent limitations for FGD wastewater in this paragraph
by a date determined by the permitting authority that is as soon as
possible beginning November 1, 2020, but no later than December 31,
2025. These effluent limitations apply to the discharge of FGD
wastewater generated on and after the date determined by the permitting
authority for meeting the effluent limitations, as specified in this
paragraph.
Table 1 to Paragraph (g)(1)(i)
----------------------------------------------------------------------------------------------------------------
BAT effluent limitations
---------------------------------------------------
Pollutant or pollutant property Average of daily values
Maximum for any 1 day for 30 consecutive days
shall not exceed
----------------------------------------------------------------------------------------------------------------
Arsenic, total (ug/L)....................................... 18 9
Mercury, total (ng/L)....................................... 85 31
Selenium, total (ug/L)...................................... 76 31
Nitrate/nitrite as N (mg/L)................................. 4.6 3.2
----------------------------------------------------------------------------------------------------------------
* * * * *
(2)(i) For any electric generating unit with a total nameplate
capacity of less than or equal to 50 megawatts, that is an oil-fired
unit, or for which the owner has certified pursuant to 423.19(f) will
be retired from service by December 31, 2028, the quantity of
pollutants discharged in FGD wastewater shall not exceed the quantity
determined by multiplying the flow of FGD wastewater times the
concentration listed for TSS in Sec. 423.12(b)(11).
(ii) For FGD wastewater discharges from a high FGD flow facility,
the quantity of pollutants in FGD wastewater shall not exceed the
quantity determined by multiplying the flow of FGD wastewater times the
concentration listed in the table following this paragraph (g)(2)(ii).
Dischargers must meet the effluent limitations for FGD wastewater in
this paragraph by a date determined by the permitting authority that is
as soon as possible beginning November 1, 2020, but no later than
December 31, 2023. These effluent limitations apply to the discharge of
FGD wastewater generated on and after the date determined by the
permitting authority for meeting the effluent limitations, as specified
in this paragraph (g)(2)(ii).
[[Page 64674]]
Table 1 to Paragraph (g)(2)(ii)
----------------------------------------------------------------------------------------------------------------
BAT effluent limitations
---------------------------------------------------
Pollutant or pollutant property Average of daily values
Maximum for any 1 day for 30 consecutive days
shall not exceed
----------------------------------------------------------------------------------------------------------------
Arsenic, total (ug/L)....................................... 11 8
Mercury, total (ng/L)....................................... 788 356
----------------------------------------------------------------------------------------------------------------
(iii)(A) For FGD wastewater discharges from a low utilization
boiler, the quantity of pollutants in FGD wastewater shall not exceed
the quantity determined by multiplying the flow of FGD wastewater times
the concentration listed in the Table 1 to paragraph (g)(2)(ii).
Dischargers must meet the effluent limitations for FGD wastewater in
this paragraph by a date determined by the permitting authority that is
as soon as possible beginning November 1, 2020, but no later than
December 31, 2023. These effluent limitations apply to the discharge of
FGD wastewater generated on and after the date determined by the
permitting authority for meeting the effluent limitations, as specified
in this paragraph (g)(2)(iii)(A).
(B) If any low utilization boiler fails to timely recertify that
the two year average net generation of such a boiler is below 876,000
MWh per year as specified in Sec. 423.19(e), regardless of the reason,
within two years from the date such a recertification was required, the
quantity of pollutants in FGD wastewater shall not exceed the quantity
determined by multiplying the flow of FGD wastewater times the
concentration listed in the Table 1 to paragraph (g)(1)(i).
(3)(i) For dischargers who voluntarily choose to meet the effluent
limitations for FGD wastewater in this paragraph, the quantity of
pollutants in FGD wastewater shall not exceed the quantity determined
by multiplying the flow of FGD wastewater times the concentration
listed in the table following this paragraph (g)(3)(i). Dischargers who
choose to meet the effluent limitations for FGD wastewater in this
paragraph must meet such limitations by December 31, 2028. These
effluent limitations apply to the discharge of FGD wastewater generated
on and after December 31, 2028.
Table 1 to Paragraph (g)(3)(i)
----------------------------------------------------------------------------------------------------------------
BAT Effluent limitations
-------------------------------------------------
Pollutant or pollutant property Average of daily values
Maximum for any 1 day for 30 consecutive days
shall not exceed
----------------------------------------------------------------------------------------------------------------
Arsenic, total (ug/L)......................................... 5 .......................
Mercury, total (ng/L)......................................... 21 9
Selenium, total (ug/L)........................................ 21 11
Nitrate/Nitrite (mg/L)........................................ 1.1 0.6
Bromide (mg/L)................................................ 0.6 0.3
TDS (mg/L).................................................... 351 156
----------------------------------------------------------------------------------------------------------------
* * * * *
(k)(1)(i) Bottom ash transport water. Except for those discharges
to which paragraph (k)(2) of this section applies, or when the bottom
ash transport water is used in the FGD scrubber, there shall be no
discharge of pollutants in bottom ash transport water. Dischargers must
meet the discharge limitation in this paragraph by a date determined by
the permitting authority that is as soon as possible beginning November
1, 2020, but no later than December 31, 2023. This limitation applies
to the discharge of bottom ash transport water generated on and after
the date determined by the permitting authority for meeting the
discharge limitation, as specified in this paragraph (k)(1)(i). Except
for those discharges to which paragraph (k)(2) of this section applies,
whenever bottom ash transport water is used in any other plant process
or is sent to a treatment system at the plant (except when it is used
in the FGD scrubber), the resulting effluent must comply with the
discharge limitation in this paragraph. When the bottom ash transport
water is used in the FGD scrubber, the quantity of pollutants in bottom
ash transport water shall not exceed the quantity determined by
multiplying the flow of bottom ash transport water times the
concentration listed in Table 1 to paragraph (g)(1)(i) of this section.
* * * * *
(2)(i)(A) The discharge of pollutants in bottom ash transport water
from a properly installed, operated, and maintained bottom ash system
is authorized under the following conditions:
(1) To maintain system water balance when precipitation-related
inflows within any 24-hour period resulting from a 25-year, 24-hour
storm event, or multiple consecutive events cannot be managed by
installed spares, redundancies, maintenance tanks, and other secondary
bottom ash system equipment; or
(2) To maintain water balance when regular inflows from
wastestreams other than bottom ash transport water exceed the ability
of the bottom ash system to accept recycled water and segregating these
other wastestreams is not feasible; or
(3) To conduct maintenance not otherwise exempted from the
definition of transport water in Sec. 423.11(p) when water volumes
cannot be managed by installed spares, redundancies, maintenance tanks,
and other secondary bottom ash system equipment; or
(4) To maintain system water chemistry where installed equipment at
the facility is unable to manage pH, corrosive compounds, and fine
particulates to below levels which impact system operations.
(B) The total volume necessary to be discharged for the above
activities shall be reduced or eliminated to the extent
[[Page 64675]]
achievable using control measures (including best management practices)
that are technologically available and economically achievable in light
of best industry practice, and in no instance shall it exceed a 30-day
rolling average of ten percent of the primary active wetted bottom ash
system volume. Discharges shall be measured by computing daily
discharges by totaling daily flow discharges.
(ii) For any electric generating unit with a total nameplate
generating capacity of less than or equal to 50 megawatts, that is an
oil-fired unit, or for which the owner has certified pursuant to
423.19(f) will be retired from service by December 31, 2028, the
quantity of pollutants discharged in bottom ash transport water shall
not exceed the quantity determined by multiplying the flow of the
applicable wastewater times the concentration for TSS listed in Sec.
423.12(b)(4).
(iii)(A) For bottom ash transport water generated by a low
utilization boiler, the quantity of pollutants discharged in bottom ash
transport water shall not exceed the quantity determined by multiplying
the flow of the applicable wastewater times the concentration for TSS
listed in Sec. 423.12(b)(4),and shall incorporate the elements of a
best management practices plan as described in (k)(3) of this section.
(B) If any low utilization boiler fails to timely recertify that
the two year average net generation of such a boiler is below 876,000
MWh per year as specified in 423.19(e), regardless of the reason,
within two years from the date such a recertification was required, the
quantity of pollutants discharged in bottom ash transport water shall
be governed by paragraphs (k)(1) and (k)(2)(i) of this section.
(3) Where required in paragraph (k)(2)(iii) of this section, the
discharger shall prepare, implement, review, and update a best
management practices plan for the recycle of bottom ash transport
water, and must include:
(i) Identification of the low utilization coal-fired generating
units that contribute bottom ash to the bottom ash transport system.
(ii) A description of the existing bottom ash handling system and a
list of system components (e.g., remote mechanical drag system (rMDS),
tanks, impoundments, chemical addition). Where multiple generating
units share a bottom ash transport system, the plan shall specify which
components are associated with low utilization generating units.
(iii) A detailed water balance, based on measurements, or estimates
where measurements are not feasible, specifying the volume and
frequency of water additions and removals from the bottom ash transport
system, including:
(A) Water removed from the BA transport system:
(1) To the discharge outfall.
(2) To the FGD scrubber system.
(3) Through evaporation.
(4) Entrained with any removed ash.
(5) Other mechanisms not specified herein.
(B) Entering or recycled to the BA transport system:
(1) Makeup water added to the BA transport water system.
(2) Bottom ash transport water recycled back to the system in lieu
of makeup water.
(3) Other mechanisms not specified herein.
(iv) Measures to be employed by all facilities:
(A) Implementation of a comprehensive preventive maintenance
program to identify, repair and replace equipment prior to failures
that result in the release of bottom ash transport water.
(B) Daily or more frequent inspections of the entire bottom ash
transport water system, including valves, pipe flanges and piping, to
identify leaks, spills and other unintended bottom ash transport water
escaping from the system, and timely repair of such conditions.
(C) Documentation of preventive and corrective maintenance
performed.
(v) Evaluation of options and feasibility, accounting for the
associated costs, for eliminating or minimizing discharges of bottom
ash transport water, including:
(A) Segregating bottom ash transport water from other process
water.
(B) Minimizing the introduction of stormwater by diverting (e.g.,
curbing, using covers) storm water to a segregated collection system.
(C) Recycling bottom ash transport water back to the bottom ash
transport water system.
(D) Recycling bottom ash transport water for use in the FGD
scrubber.
(E) Optimizing existing equipment (e.g., pumps, pipes, tanks) and
installing new equipment where practicable to achieve the maximum
amount of recycle.
(F) Utilizing ``in-line'' treatment of transport water (e.g., pH
control, fines removal) where needed to facilitate recycle.
(vi) Description of the bottom ash recycle system, including all
technologies, measures, and practices that will be used to minimize
discharge.
(vii) A schedule showing the sequence of implementing any changes
necessary to achieve the minimized discharge of bottom ash transport
water, including the following:
(A) The anticipated initiation and completion dates of construction
and installation associated with the technology components or process
modifications specified in the plan.
(B) The anticipated dates that the discharger expects the
technologies and process modifications to be fully implemented on a
full-scale basis, which in no case shall be later than December 31,
2023.
(C) The anticipated change in discharge volume and effluent quality
associated with implementation of the plan.
(viii) Description establishing a method for documenting and
demonstrating to the permitting/control authority that the recycle
system is well operated and maintained.
(ix) The discharger shall perform weekly flow monitoring for the
following:
(A) Make up water to the bottom ash transport water system.
(B) Bottom ash transport water sluice flow rate (e.g., to the
surface impoundment(s), dewatering bins(s), tank(s), rMDS).
(C) Bottom ash transport water discharge to surface water or POTW.
(D) Bottom ash transport water recycle back to the bottom ash
system or FGD scrubber.
* * * * *
0
5. Amend Sec. 423.16 by:
0
a. Revising paragraph (e)(1);
0
b. Adding paragraph (e)(2);
0
c. Revising paragraph (g)(1); and
0
d. Adding paragraph (g)(2).
The additions and revisions to read as follows
Sec. 423.16 Pretreatment standards for existing sources (PSES).
* * * * *
(e)(1) FGD wastewater. Except as provided for in paragraph (e)(2)
of this section, for any electric generating unit with a total
nameplate generating capacity of more than 50 megawatts, that is not an
oil-fired unit, and that the owner has not certified pursuant to Sec.
423.19(f) will be retired from service by December 31, 2028, the
quantity of pollutants in FGD wastewater shall not exceed the quantity
determined by multiplying the flow of FGD wastewater times the
concentration listed in the table following this paragraph (e).
Dischargers must meet the standards in this paragraph by [DATE 3 YEARS
AFTER DATE OF FINAL RULE] except as provided for in paragraph (e)(2) of
this section. These standards apply to the discharge of FGD wastewater
generated on and after [DATE 3 YEARS AFTER DATE OF FINAL RULE].
[[Page 64676]]
Table 1 to Paragraph (e)(1)
----------------------------------------------------------------------------------------------------------------
PSES
-------------------------------------------------
Pollutant or pollutant property Average of daily values
Maximum for any 1 day for 30 consecutive days
shall not exceed
----------------------------------------------------------------------------------------------------------------
Arsenic, total (ug/L)......................................... 18 9
Mercury, total (ng/L)......................................... 85 31
Selenium, total (ug/L)........................................ 76 31
Nitrate/nitrite as N (mg/L)................................... 4.6 3.2
----------------------------------------------------------------------------------------------------------------
(2)(i) For FGD wastewater discharges from a low utilization boiler,
the quantity of pollutants in FGD wastewater shall not exceed the
quantity determined by multiplying the flow of FGD wastewater times the
concentration listed in the table following this paragraph (e)(2).
Dischargers must meet the standards in this paragraph by [DATE 3 YEARS
AFTER DATE OF FINAL RULE].
(ii) If any low utilization boiler fails to timely recertify that
the two year average net generation of such a boiler is below 876,000
MWh per year as specified in Sec. 423.19(e), regardless of the reason,
within two years from the date such a recertification was required, the
quantity of pollutants in FGD wastewater shall not exceed the quantity
determined by multiplying the flow of FGD wastewater times the
concentration listed in Table 1 to paragraph (e)(1).
Table 1 to Paragraph (e)(2)(ii)
----------------------------------------------------------------------------------------------------------------
PSES
-------------------------------------------------
Pollutant or pollutant property Average of daily values
Maximum for any 1 day for 30 consecutive days
shall not exceed
----------------------------------------------------------------------------------------------------------------
Arsenic, total (ug/L)......................................... 11 8
Mercury, total (ng/L)......................................... 788 356
----------------------------------------------------------------------------------------------------------------
* * * * *
(g)(1) Except for those discharges to which paragraph (g)(2) of
this section applies, or when the bottom ash transport water is used in
the FGD scrubber, for any electric generating unit with a total
nameplate generating capacity of more than 50 megawatts, that is not an
oil-fired unit, that is not a low utilization boiler, and that the
owner has not certified pursuant to Sec. 423.19(f) will be retired
from service by December 31, 2028, there shall be no discharge of
pollutants in bottom ash transport water. This standard applies to the
discharge of bottom ash transport water generated on and after [DATE 3
YEARS AFTER DATE OF FINAL RULE]. Except for those discharges to which
paragraph (g)(2) of this section applies, whenever bottom ash transport
water is used in any other plant process or is sent to a treatment
system at the plant (except when it is used in the FGD scrubber), the
resulting effluent must comply with the discharge standard in this
paragraph. When the bottom ash transport water is used in the FGD
scrubber, the quantity of pollutants in bottom ash transport water
shall not exceed the quantity determined by multiplying the flow of
bottom ash transport water times the concentration listed in Table 1 to
paragraph (e)(1) of this section.
(2)(i)(A) The discharge of pollutants in bottom ash transport water
from a properly installed, operated, and maintained bottom ash system
is authorized under the following conditions:
(1) To maintain system water balance when precipitation-related
inflows within any 24-hour period resulting from a 25-year, 24-hour
storm event, or multiple consecutive events cannot be managed by
installed spares, redundancies, maintenance tanks, and other secondary
bottom ash system equipment; or
(2) To maintain water balance when regular inflows from
wastestreams other than bottom ash transport water exceed the ability
of the bottom ash system to accept recycled water and segregating these
other wastestreams is feasible; or
(3) To conduct maintenance not otherwise exempted from the
definition of transport water in Sec. 423.11(p) when water volumes
cannot be managed by installed spares, redundancies, maintenance tanks,
and other secondary bottom ash system equipment; or
(4) To maintain system water chemistry where current operations at
the facility are unable to currently manage pH, corrosive compounds,
and fine particulates to below levels which impact system operations.
(B) The total volume necessary to be discharged to a POTW for the
above activities shall be reduced or eliminated to the extent
achievable using control measures (including best management practices)
that are technologically available and economically achievable in light
of best industry practice, and in no instance shall it exceed a 30-day
rolling average of ten percent of the primary active wetted bottom ash
system volume. Discharges shall be measured by computing daily
discharges by totaling daily flow discharges.
(ii)(A) For bottom ash transport water generated by a low
utilization boiler, the quantity of pollutants discharged in bottom ash
transport water shall incorporate the elements of a best management
practices plan as described in Sec. 423.13(k)(3).
(B) If any low utilization boiler fails to timely recertify that
the two year average net generation of such a boiler is below 876,000
MWh per year as specified in Sec. 423.19(e), regardless of the reason,
within two years from the date such a recertification was required, the
quantity of pollutants discharged in bottom ash transport water shall
be governed by paragraphs (g)(1) and (g)(2)(i) of this section.
0
6. Add Sec. 423.18 to read as follows.
Sec. 423.18 Permit conditions.
All permits subject to this part shall include the following permit
conditions:
(a) In case of an emergency order issued by the Department of
Energy under Section 202(c) of the Federal Power Act or a Public
Utility Commission reliability must run agreement, a boiler shall be
deemed to qualify as a low utilization boiler or
[[Page 64677]]
boiler that will be retired from service by December 31, 2028 if such
qualification would have been demonstrated absent such order or
agreement.
(b) Any facility providing the required documentation pursuant to
Sec. 423.19(g) may avail itself of the protections of this permit
condition.
0
7. Add Sec. 423.19 to read as follows.
Sec. 423.19 Reporting and recordkeeping requirements.
(a) Discharges subject to this part must comply with the following
reporting requirements in addition to the applicable requirements in 40
CFR 403.12(b), (d), (e), and (g).
(b) Signature and certification. Unless otherwise provided below,
all certifications and recertifications required in this part must be
signed and certified pursuant to 40 CFR 122.22 for direct dischargers
or 40 CFR 403.12(l) for indirect dischargers.
(c) Requirements for facilities discharging bottom ash transport
water pursuant to Sec. 423.13(k)(2)(i) or Sec. 423.16(g)(2)(i).
(1) Initial Certification Statement. For sources seeking to
discharge bottom ash transport water pursuant to Sec. 423.13(k)(2)(i)
or Sec. 423.16(g)(2)(i), an initial certification shall be submitted
to the permitting authority by the as soon as possible date determined
under Sec. 423.11(t), or the control authority by [DATE 3 YEARS AFTER
DATE OF FINAL RULE] in the case of an indirect discharger.
(2) Signature and certification. The certification statement must
be signed and certified by a professional engineer.
(3) Contents. An initial certification shall include the following:
(A) A statement that the professional engineer is a licensed
professional engineer.
(B) A statement that the professional engineer is familiar with the
regulation requirements.
(C) A statement that the professional engineer is familiar with the
facility.
(D) The primary active wetted bottom ash system volume in Sec.
423.11(aa).
(E) All assumptions, information, and calculations used by the
certifying professional engineer to determine the primary active wetted
bottom ash system volume.
(d) Requirements for a bottom ash best management practices plan.
(1) Initial and Annual Certification Statement. For sources
required to develop and implement a best management practices plan
pursuant to Sec. 423.13(k)(3), an initial certification shall be made
to the permitting authority with a permit application, or to the
control authority no later than [DATE 3 YEARS AFTER DATE OF FINAL RULE]
in the case of an indirect discharger, and an annual recertification
shall be made to the permitting authority, or control authority in the
case of an indirect discharger, within 60 days of the anniversary of
the original plan.
(2) Signature and Certification. The certification statement must
be signed and certified by a professional engineer.
(3) Contents for Initial Certification. An initial certification
shall include the following:
(A) A statement that the professional engineer is a licensed
professional engineer.
(B) A statement that the professional engineer is familiar with the
regulation requirements.
(C) A statement that the professional engineer is familiar with the
facility.
(D) The approved best management practices plan.
(E) A statement that the best management practices plan is being
implemented.
(4) Additional Contents for Annual Certification. In addition to
the required contents of the initial certification in paragraph (d)(3)
of this section an annual certification shall include the following:
(A) Any updates to the best management practices plan.
(B) An attachment of weekly flow measurements from the previous
year.
(C) The average amount of recycled bottom ash transport water in
gallons per day.
(D) Copies of annual inspection reports and a summary of
preventative maintenance performed on the system.
(E) A statement that the plan and corresponding flow records are
being maintained at the office of the plant.
(e) Requirements for low utilization boilers. (1) Initial and
Annual Certification Statement. For sources seeking to apply the
limitations or standards for low utilization boilers, an initial
certification shall be made to the permitting authority with a permit
application, or to the control authority no later than [DATE 3 YEARS
AFTER DATE OF FINAL RULE] in the case of an indirect discharger, and an
annual recertification shall be made to the permitting authority, or
control authority in the case of an indirect discharger, within 60 days
of submitting annual net generation data to the Energy Information
Administration.
(2) Contents. A certification or annual recertification shall be
based on the information submitted to the Energy Information
Administration and shall include copies of the underlying forms
submitted to the Energy Information Administration, as well as any
supplemental information and calculations used to determine the two
year average annual net generation. Where station-wide energy
consumption must otherwise be apportioned to multiple boilers, the
facility shall attribute such consumption to each boiler proportional
to that boiler's nameplate capacity unless the facility can demonstrate
the energy consumption is specific to a boiler.
(f) Requirements for units that will be retired from service by
December 31, 2028 pursuant to Sec. Sec. 423.13(k)(2)(ii) and
423.13(g)(1).
(1) Initial Certification Statement. For sources seeking to apply
the limitations or standards for units that will be retired from
service by December 31, 2028, a one-time certification to the
permitting authority must be submitted with the permit application, or
where a permit has already been issued, by the as soon as possible date
determined under paragraph 423.11(t), or to the control authority by
[promulgation date + 3 years] in the case of an indirect discharger.
(2) Contents. A certification shall include the estimated date that
boiler will be retired from service, a brief statement as to the reason
for retirement, as well as a copy of the most recent integrated
resource plan, certification of boiler cessation under 40 CFR
257.103(b), or other legally binding submission supporting that the
boiler will be retired from service by December 31, 2028.
(g) Requirements for facilities seeking the protections of Sec.
423.18.
(1) Certification Statement. For sources seeking to apply the
protections of the permit conditions in Sec. 423.18, a one-time
certification shall be submitted to the permitting authority, or
control authority in the case of an indirect discharger, no later than
30 days from receipt of the order or agreement attached pursuant to
paragraph (f)(2) of this section.
(2) Contents. A certification statement must demonstrate that a
boiler would have qualified for the subcategory at issue absent the
emergency order issued by the Department of Energy under Section 202(c)
of the Federal Power Act or Public Utility Commission reliability must
run agreement; and a copy of such order or agreement shall be attached.
[FR Doc. 2019-24686 Filed 11-21-19; 8:45 am]
BILLING CODE 6560-50-P