United States
Environmental Protection
Agency
Office of Water
Washington, DC 20460
EPA-821-R-19-009
November 2019
Supplemental Technical
Development Document for
Proposed Revisions to the
Effluent Limitations
Guidelines and Standards
for the Steam Electric Power
Generating Point Source
Category

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£EPA
United States
Environmental Protection
Agency
Supplemental Technical Development
Document for Proposed Revisions to the
Effluent Limitations Guidelines and
Standards for the Steam Electric Power
Generating Point Source Category
EPA-821-R-19-009
November 2019
U.S. Environmental Protection Agency
Office of Water (4303T)
Washington, DC 20460

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This document was prepared by the Environmental Protection Agency. Neither the United States
Government nor any of its employees, contractors, subcontractors, or their employees make any
warrant, expressed or implied, or assume any legal liability or responsibility for any third party's
use of or the results of such use of any information, apparatus, product, or process discussed in
this report, or represents that its use by such party would not infringe on privately owned rights.
Questions regarding this document should be directed to:
U.S. EPA Engineering and Analysis Division (4303T)
1200 Pennsylvania Avenue NW
Washington, DC 20460
(202) 566-1000
in

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Table of Contents
TABLE OF CONTENTS
Page
Section 1 Background	1-1
1.1	Legal Authority	1-2
1.2	Regulatory History of the Steam Electric Power Generating Point Source
Category	1-2
1.3	Other Key Regulatory Actions Affecting Management of Steam Electric
Power Generating Wastewaters	1-3
Section 2 Data Collection Activities	2-1
2.1	Site Visits	2-1
2.2	Industry-Submitted Data	2-2
2.2.1	Clean Water Act Section 308 Industry Request for FGD
Wastewater	2-2
2.2.2	Voluntary Sampling Program for Bottom Ash Transport Water	2-3
2.3	Technology Vendor Data	2-3
2.4	Other Data Sources	2-4
2.4.1	Trade Associations	2-4
2.4.2	Department of Energy	2-6
2.4.3	Literature and Internet Searches	2-7
2.4.4	Environmental Groups	2-7
2.5	Protection of Confidential Business Information	2-7
2.6	References	2-7
Section 3 Current State of the Steam Electric Power Generating Industry	3-1
3.1	Changes in the Steam Electric Power Generating Industry Since 2015 rule	3-1
3.2	Current Information on Evaluated Wastestreams	3-5
3.2.1	FGD Wastewater	3-5
3.2.2	Bottom Ash Transport Water	3-7
3.3	Other Regulations on the Steam Electric Power Generating Industry	3-11
3.4	References	3-12
Section 4 Treatment Technologies and Wastewater Management
Practices	4-1
4.1	FGD Wastewater Treatment Technologies	4-1
4.1.1	Biological Treatment	4-1
4.1.2	Zero Valent Iron	4-3
4.1.3	Membrane Filtration	4-4
4.1.4	Thermal Treatment	4-6
4.1.5	Solidification	4-7
4.1.6	Other Technologies Under Investigation	4-7
4.2	Bottom Ash Handling Systems and Transport Water Management and
Treatment Technologies	4-8
4.2.1 Mechanical Drag System	4-9
iv

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Table of Contents
TABLES OF CONTENTS (Continued)
Page
4.2.2	Remote Mechanical Drag System	4-9
4.2.3	Dry Mechanical Conveyor	4-10
4.2.4	Dry Vacuum or Pressure System	4-10
4.2.5	Submerged Grind Conveyor	4-10
4.3 References	4-11
Section 5 Engineering Costs	5-1
5.1	General Methodology for Estimating Incremental Compliance Costs	5-2
5.2	FGD Wastewater	5-3
5.2.1	FGD Cost Calculation Inputs	5-4
5.2.2	Cost Methodology for Chemical Precipitation	5-9
5.2.3	Cost Methodology for Chemical Precipitation followed by LRTR
(CP+LRTR)	5-15
5.2.4	Cost Methodology for Chemical Precipitation followed by HRTR
(CP+HRTR)	5-20
5.2.5	Cost Methodology for Membrane Filtration	5-25
5.2.6	Methodology for Estimating Cost Savings from Ceasing Use of
FGD Surface Impoundments	5-28
5.3	Bottom Ash Transport Water	5-32
5.3.1	Bottom Ash Cost Calculation Inputs	5-34
5.3.2	Cost Methodology for Mechanical Drag System	5-36
5.3.3	Cost Methodology for Remote Mechanical Drag Systems Operated
to Achieve Zero Discharge (No Purge)	5-41
5.3.4	Cost Methodology for Remote Mechanical Drag Systems Operated
with a Purge	5-51
5.3.5	Bottom Ash Management Cost Methodology	5-51
5.3.6	Bottom Ash BMP Plan Cost Methodology	5-51
5.3.7	Methodology for Estimating Cost Savings from Ceasing Use of
Surface Impoundments	5-55
5.4	Summary of National Engineering Cost for Regulatory Options	5-58
5.5	References	5-60
Section 6 Pollutant Loadings and Removals	6-1
6.1	General Methodology for Estimating Pollutant Removals	6-2
6.2	FGD Wastewater	6-5
6.2.1	Pollutants Present in FGD Wastewater	6-5
6.2.2	FGD Wastewater Flows	6-9
6.2.3	Baseline and Technology Option Loadings	6-9
6.3	Bottom Ash Transport Water	6-11
6.3.1	Pollutants Present in Bottom Ash Transport Water	6-11
6.3.2	Bottom Ash Transport Water Flows	6-13
6.3.3	Baseline and Technology Option Loadings	6-14
6.4	Summary of Baseline and Regulatory Option Loadings and Removals	6-15

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Table of Contents
TABLES OF CONTENTS (Continued)
Page
6.5 References	6-17
Section 7 Non-Water Quality Environmental Impacts	7-1
7.1	Energy Requirements	7-1
7.2	Air Emissions Pollution	7-2
7.3	Solid Waste Generation	7-6
7.4	Change in Water Use	7-7
7.5	References	7-7
Section 8 Effluent I .imitations	8-1
8.1	Selection of Regulated Pollutants for FGD Wastewater	8-1
8.1.1	Direct Dischargers	8-1
8.1.2	Indirect Dischargers	8-7
8.2	Calculation of Effluent Limitations for FGD Wastewater	8-9
8.2.1	Data Selection	8-9
8.2.2	Data Exclusions and Substitutions	8-13
8.2.3	Data Aggregation	8-15
8.2.4	Data Editing Criteria	8-16
8.2.5	Overview of Limitations	8-17
8.2.6	Calculation of The Limitations	8-19
8.2.7	Long-Term Averages and Effluent Limitations for FGD
Wastewater	8-22
8.3	Selection of Regulated Pollutants for Bottom Ash Transport Water	8-23
8.4	Effluent Limitations for Bottom Ash Transport Water	8-23
8.5	References	8-24
vi

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List of Tables
LIST OF TABLES
Page
Table 2-1. Site Visits Conducted Supporting the Proposed Rule	2-2
Table 2-2. EPRI Reports and Studies Reviewed by the EPA as Part of the
Reconsideration of the 2015 rule	2-4
Table 3-1. Industry Profile Updates Since August 2014 by Type of Change in Operation	3-3
Table 3-2. FGD Wastewater Discharges for the Steam Electric Power Plants	3-7
Table 3-3. Bottom Ash Handling Systems for Coal-Fired Generating Units	3-9
Table 3-4. Bottom Ash Transport Water Discharges for Steam Electric Power Plants	3-11
Table 5-1. ELG FGD Baseline Changes Accounting for CCR Rule	5-9
Table 5-2. Percentage of Chemical Precipitation Costs Incurred by Plants with Treatment
in Place	5-14
Table 5-3. Costs Incurred for Chemical Precipitation for Plants with Treatment in Place	5-14
Table 5-4. Costs Incurred for Chemical Precipitation plus LRTR for Plants with Existing
Treatment in Place	5-20
Table 5-5. Costs Incurred for Chemical Precipitation plus HRTR for Plants with Existing
Treatment in Place	5-24
Table 5-6. Membrane TIP Summary of Costs	5-28
Table 5-7. Technology Options for Bottom Ash Transport Water	5-32
Table 5-8. ELG Bottom Ash Baseline Changes Accounting for CCR Rule	5-35
Table 5-9. Estimated Cost of Implementation for FGD Wastewater by Regulatory Option
[In millions of pre-tax 2018 dollars]	5-59
Table 5-10. Estimated Cost of Implementation for Bottom Ash Transport Water by
Regulatory Option [In millions of pre-tax 2018 dollars]	5-60
Table 5-11. Estimated Cost of Implementation by Regulatory Option [In millions of pre-
tax 2018 dollars]	5-60
Table 6-1. Pollutants Present in Treated FGD Wastewater Effluent	6-7
Table 6-2. Pollutants Present in Bottom Ash Transport Water Effluent	6-12
Table 6-3. Estimated Industry-Level FGD Wastewater Pollutant Loadings and Estimated
Change in Loadings by Regulatory Option	6-16
Table 6-4. Estimated Industry-Level Bottom Ash Transport Water Pollutant Loadings
and Estimated Change in Loadings by Regulatory Option	6-16
Table 6-5. Estimated Industry-Level Pollutant Loadings and Estimated Change in
Loadings by Regulatory Option	6-17
vii

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List of Tables
LIST OF TABLES (Continued)
Page
Table 7-1. Net Change in Energy Use for the Proposed Regulatory Options Compared to
Baseline	7-2
Table 7-2. MOVES Emission Rates for Model Year 2010 Diesel-fueled, Short-haul
Trucks Operating in 2018	7-4
Table 7-3. Net Change in Industry-Level Air Emissions Associated with Power
Requirements and Transportation by Regulatory Option	7-5
Table 7-4. Net Change in Industry-Level Air Emissions for Regulatory Options 2 and 4	7-6
Table 7-5. Net Change in Industry-Level Solid Waste from Baseline, by Regulatory
Option	7-6
Table 7-6. Net Change in Industry-Level Process Water Use by Regulatory Option	7-7
Table 8-1. Pollutants Considered for Regulation for FGD Wastewater - Chemical
Precipitation	8-2
Table 8-2. Pollutants Considered for Regulation for FGD Wastewater - CP+LRTR	8-4
Table 8-3. Pollutants Considered for Regulation for FGD Wastewater - Membrane
Filtration	8-6
Table 8-4. POTW Pass-Through Analysis - CP	8-8
Table 8-5. POTW Pass-Through Analysis - CP+LRTR	8-8
Table 8-6. POTW Pass-Through Analysis - Membrane Filtration	8-9
Table 8-7. Aggregation of Field Duplicates	8-16
Table 8-8. Autocorrelation Values Used in Calculating Limitations for FGD Wastewater	8-21
Table 8-9. Long-Term Averages and Effluent Limitations for FGD Wastewater	8-23
Table 8-10. Thirty-Day Rolling Average Discharge Volume as a Percent of System
Volumea	8-24
viii

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List of Figures
LIST OF FIGURES
Page
Figure 3-1. Population of Coal-Fired Generating Units and Plants	3-4
Figure 3-2. Wet FGD Systems at Steam Electric Power Plants	3-6
Figure 3-3. Plant-Level Bottom Ash Handling Systems in the Steam Electric Power
Generating Industry	3-10
Figure 5-1. Chemical Precipitation Capital Cost Curve - On-site Transport/Disposal	5-11
Figure 5-2. Chemical Precipitation O&M Cost Curve - On-site Transport/Disposal	5-12
Figure 5-3. Chemical Precipitation Capital Cost Curve - Off-site Transport/Disposal	5-12
Figure 5-4. Chemical Precipitation O&M Cost Curve - Off-site Transport/Disposal	5-13
Figure 5-5. CP Pretreatment Capital Cost Curve - On-site Transport/Disposal	5-16
Figure 5-6. CP Pretreatment O&M Cost Curve - On-site Transport/Disposal	5-17
Figure 5-7. CP Pretreatment Capital Cost Curve - Off-site Transport/Disposal	5-17
Figure 5-8. CP Pretreatment O&M Cost Curve - Off-site Transport/Disposal	5-17
Figure 5-9. LRTR Capital Cost Curve - Low Nitrates	5-18
Figure 5-10. LRTR O&M Cost Curve - Low Nitrates	5-18
Figure 5-11. LRTR Capital Cost Curve - High Nitrates	5-19
Figure 5-12. LRTR O&M Cost Curve - High Nitrates	5-19
Figure 5-13. HRTR Capital Cost Curve - On-site Transport/Disposal	5-22
Figure 5-14. HRTR O&M Cost Curve - On-site Transport/Disposal	5-22
Figure 5-15. HRTR Capital Cost Curve - Off-site Transport/Disposal	5-23
Figure 5-16. HRTR O&M Cost Curve - Off-site Transport/Disposal	5-23
Figure 5-17. Membrane Capital Cost Curves - On-site Transport/Disposal	5-26
Figure 5-18. Membrane O&M Cost Curves - On-site Transport/Disposal	5-27
Figure 5-19. Membrane Capital Cost Curves - Off-site Transport/Disposal	5-27
Figure 5-20. Membrane O&M Cost Curves - Off-site Transport/Disposal	5-28
Figure 5-21. MDS Capital Cost Curve - On-site Transport/Disposal	5-38
Figure 5-22. MDS O&M Cost Curve - On-site Transport/Disposal	5-38
Figure 5-23. MDS Capital Cost Curve - Off-site Transport/Disposal	5-39
Figure 5-24. MDS O&M Cost Curve - Off-site Transport/Disposal	5-39
Figure 5-25. MDS Capital Cost Curve - Excluding Transport/Disposal	5-40
Figure 5-26. rMDS Capital Cost Curve - On-site Transport/Disposal	5-43
IX

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List of Figures
LIST OF FIGURES (Continued)
Page
Figure 5-27. rMDS O&M Cost Curve - On-site Transport/Disposal	5-43
Figure 5-28. rMDS Capital Cost Curve - Off-site Transport/Disposal	5-44
Figure 5-29. rMDS O&M Cost Curve - Off-site Transport/Disposal	5-44
Figure 5-30. rMDS Capital Cost Curve - Excluding Transport/Disposal	5-45
x

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Section 1—Background
SECTION 1
BACKGROUND
This Supplemental Technical Development Document describes the supporting information for
the Agency's reconsideration of effluent limitations guidelines and standards (ELGs) for the
Steam Electric Power Generating Point Source Category, promulgated on November 3, 2015
(referred to throughout this document as the "2015 rule"). Information on the 2015 Final Rule
can be found at 80 FR 67838 (November 3, 2015) and in the September 2015 Technical
Development Document for the Effluent Limitations Guidelines and Standards for the Steam
Electric Power Generating Point Source Category (821-R-15-007) (referred to throughout this
document as the "2015 TDD").
The EPA is conducting a new rulemaking regarding the appropriate technology bases and
associated limitations for the best available technology economically achievable (BAT) effluent
limitations and pretreatment standards for existing sources (PSES) applicable to flue gas
desulfurization (FGD) wastewater and bottom ash transport water discharged from steam electric
power plants. This document presents supporting information for proposed revisions to the 2015
rule, and supplements the 2015 TDD by summarizing the EPA's data collection efforts following
the promulgation of the 2015 rule, updates to the industry profile (e.g., retirements, FGD
wastewater treatment technology upgrades, and bottom ash handling system conversions) and
impacts from other rulemakings impacting the industry, adjustments to methodologies for
estimating the costs, pollutant removals, and non-water quality environmental impacts associated
with FGD wastewater treatment and management of bottom ash transport water, and the
derivation of the proposed effluent limitations.
In addition to this report, other supporting reports include:
•	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 potential 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 potential 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 regulatory options, and an assessment of the potential
impacts on employment and small businesses.
The ELGs for the Steam Electric Power Generating Category are based on data generated or
obtained in accordance with the EPA's Quality Policy and Information Quality Guidelines. The
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Section 1—Background
EPA's quality assurance (QA) and quality control (QC) activities for this rulemaking include
developing, approving, and implementing Quality Assurance Project Plans for the use of
environmental data generated or collected from sampling and analyses, existing databases, and
literature searches, and for developing any models that use environmental data.
1.1	Legal Authority
The EPA is proposing to revise the ELGs for the Steam Electric Power Generating Point Source
Category (40 CFR 423) under the authority of sections 301, 304, 306, 307, 308, 402, and 501 of
the Clean Water Act, 33 U.S.C. 1311, 1314, 1316, 1317, 1318, 1342, and 1361.
Under the Act, the EPA is required to establish the effluent limitations guidelines and standards
as summarized in the 2015 TDD.
1.2	Regulatory History of the Steam Electric Power Generating Point
Source Category
The EPA, on September 30, 2015, finalized the 2015 rule revising the regulations for the Steam
Electric Power Generating point source category (40 CFR 423). The 2015 rule set the first
federal limitations on the levels of toxic metals in wastewater that can be discharged from power
plants, based on technology improvements in the steam electric power industry.
Prior to the 2015 rule, regulations for the industry had last been updated in 1982. The 1982 rule
focused on settling out particulates rather than treating dissolved pollutants. New technologies
for generating electric power and the widespread implementation of air pollution controls have
altered wastewater streams or created new wastewater streams at many power plants, particularly
coal-fired power plants. Discharges of these wastestreams include arsenic, lead, mercury,
selenium, chromium, and cadmium.
The 2015 rule addressed effluent limitations and standards for multiple wastestreams generated
by new and existing steam electric power plants: bottom ash transport water, combustion residual
leachate, FGD wastewater, flue gas mercury control wastewater, fly ash transport water, and
gasification wastewater. The 2015 rule required most power plants with direct discharges to
comply with the effluent limitations "as soon as possible" after November 1, 2018, and no later
than December 31, 2023. Within that range, the particular compliance date(s) for each plant
would be determined by the plant's National Pollutant Discharge Elimination System permit,
which is typically issued by a state environmental agency. For power plants with indirect
discharges, the 2015 rule required power plants to comply with the pretreatment standards on
November 1, 2018.
Compared to the 1982 rule, the 2015 rule was estimated to reduce the annual amount of toxic
metals, nutrients, and other pollutants that steam electric power plants are allowed to discharge
by 1.4 billion pounds. Estimated annual compliance costs for the final rule were $480 million (in
2013 dollars). Estimated benefits associated with the rule were $451 to $566 million (in 2013
dollars).
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. On March 24, 2017, the
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Section 1—Background
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
(SB A) submitted an administrative petition for reconsideration of the 2015 rule.
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). 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 bottom ash transport water. The Fifth Circuit Court of Appeals heard the
consolidated petitions for review of the 2015 rule and subsequently granted the EPA's request to
sever and hold in abeyance aspects of the litigation related to the FGD wastewater and bottom
ash transport water 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.
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 bottom ash 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.
1.3 Other Key Regulatory Actions Affecting Management of Steam Electric
Power Generating Wastewaters
The EPA previously described other Agency actions to reduce emissions, discharges, and other
environmental impacts associated with steam electric power plants (see 2015 TDD). Since the
promulgation of the 2015 final rule, regulatory changes have been identified in the Clean Power
Plan (CPP), the Affordable Clean Energy (ACE) rule, and the Coal Combustion Residuals
(CCR) rule. This section provides a brief overview of these recent changes to the regulatory
requirements for steam electric power plants.
1. Clean Power Plan and Affordable Clean Energy
The final 2015 CPP established carbon dioxide (CO2) emission guidelines for fossil-
fuel fired power plants based in part on shifting from one type of energy source to
another at the fleet-wide level. On February 9, 2016, the U.S. Supreme Court stayed
implementation of the CPP pending judicial review.
On June 19, 2019, the EPA issued the ACE rule, an effort to provide existing coal-
fired electric utility generating units 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
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Section 1—Background
inform the state's development of standards of performance to reduce CO2 emissions
from existing coal-fired electric utility generating units 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 electric utility
generating units.1 By employing a broad range of HRI technologies and techniques,
electric utility generating units can more efficiently generate electricity with less
carbon intensity.2 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 practices.3 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.
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, following
promulgation of the ACE final rule, that estimates the impacts of the preferred option
relative to a baseline that includes the ACE rule. See additional discussion of IPM in
Section VIII of the preamble.
2. Coal Combustion Residuals (CCR) Final Rule
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 power plants. The final CCR rule is the culmination of
extensive study on the effects of coal ash on the environment and public health. The
rule establishes 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 address the risks from coal ash disposal: contaminants leaking into
ground water, contaminants blowing into the air as dust, and the catastrophic failure
1	Heat rate is a measure of the amount of energy required to generate a unit of electricity.
2	An improvement to heat rate results in a reduction in the emission rate of an electric utility generating unit (in
terms of CO2 emissions per unit of electricity produced).
3	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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Section 1—Background
of coal ash surface impoundments. The CCR rule also sets out recordkeeping and
reporting requirements, as well as requiring each power plant to establish and post
specific information on a publicly-accessible website. This final CCR rule also
supports 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 unit or
activity at a power plant. In finalizing both of those rules in 2015, the EPA
coordinated the two rules to minimize the overall complexity and to facilitate
implementation of engineering, financial, and permitting activities. The coordination
of the two rules continues to be a major consideration in the development of this
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 (DC Cir. 2018) and Waterkeeper Alliance Inc, et al. v. EPA, No.
18-1289 (DC Cir. 2019), amendments to the CCR rule are being proposed which
would establish a deadline of August 2020 by which date all unlined surface
impoundments4 must cease receiving waste, subject to certain exceptions.
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, see Section 3.3 for more details.
4 Due to the Court vacatur of 40 CFR 257.71(a)(l)(i) (provision for clay-lined surface impoundments) clay-lined
surface impoundments are currently considered unlined.
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Section 2—Data Collection Activities
SECTION 2
DATA COLLECTION ACTIVITIES
The EPA collected and evaluated information from various sources in the course of developing
the 2015 rule, as described in Section 3 of the 2015 TDD. As part of this proposed rule, the EPA
collected additional data to update the industry profile, identify the power plants affected by the
rule, reevaluate industry subcategorization, update plant-specific operations and wastewater
characteristics, and determine the technology options, compliance costs, baseline pollutant
loadings, changes in post-compliance pollutant loadings, and non-water-quality environmental
impacts. This section summarizes the following additional data collection activities for FGD
wastewater and bottom ash transport water as they relate to technical aspects of the proposed
rule:
•	Site visits (Section 2.1).
•	Industry-submitted data (Section 2.2).
•	Technol ogy vendor data (S ecti on 2.3).
•	Other data sources (Section 2.4).
•	Protection of confidential business information (Section 2.5).
2.1 Site Visits
After promulgating the 2015 rule, the EPA conducted seven site visits to power plants in five
states between October and December 2017 to update information on methods of managing FGD
wastewater and bottom ash transport water. Table 2-1 lists the site visits conducted following the
2015 rule. The EPA used information gathered in support of the 2015 rule, information from
industry outreach, and publicly available plant-specific information to identify power plant
operations of interest. The EPA prioritized plants engaged in FGD wastewater treatment pilot
studies or with updated FGD treatment or bottom ash handling systems. The EPA made pre-site-
visit phone calls to confirm plant operations and to select plants for site visits. The specific
objectives of these site visits were to:
•	Gather general information about each plant's operations.
•	Gather information on pollution prevention and wastewater treatment and
operations.
•	Gather information about FGD wastewater treatment from ongoing pilot studies
or laboratory-scale studies.
•	Gather information on conversions to bottom ash handling systems.
The EPA revisited four power plants that were previously visited in support of the 2015 rule
because they had recently conducted, or were currently conducting, FGD wastewater treatment
pilot studies. The EPA visited these plants to collect performance data and learn more about the
technologies they were testing to treat FGD wastewater. Following the 2015 rule, the EPA
visited plants that had implemented new FGD wastewater treatment technologies or bottom ash
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Section 2—Data Collection Activities
handling systems to learn more about implementation timing, start-up and operation, and
compliance costs.
Table 2-1. Site Visits Conducted Supporting the Proposed Rule
I'liiiil Niimo. l ocution
Monlh/Yciir of Silo Visit
Concmaugli, Pennsylvania
UaJMll"
Bowen, Georgia
Nov 2017
Miller, Alabama
Nov 2017
Belews Creek, North Carolina
Dec 2017
Mill Creek, Kentucky
Dec 2017
Sutton, North Carolina
Dec 2017
Trimble County, Kentucky
Dec 2017
The EPA also visited two North Carolina drinking water treatment plants downstream of steam
electric power plant outfalls in December 2017. The objective of the site visits was to investigate
the impacts to drinking water treatment plants as well as the efforts plants were making to
mitigate increased formation of disinfection byproducts (ERG, 2018). Refer to the 2019
Supplemental EA for a more detailed discussion on sources of bromides found in FGD
wastewater and their impacts to downstream drinking water intakes.
2.2 Industry-Submitted Data
The EPA obtained information on steam electric processes, wastewater treatment technologies,
and wastewater characteristics directly from the industry through a Clean Water Act (CWA)
Section 308 request, voluntary bottom ash sampling data request, and other industry data
provided during the reconsideration of the 2015 rule. Sections 2.2.1 and 2.2.2 summarize the
industry-submitted data collected.
2.2.1 Clean Water Act Section 308 Industry Request for FGD Wastewater
Under the authority of Section 308 of the CWA (33 U.S.C. 1318), the EPA requested the
following information for coal-fired power plants from nine steam electric power companies that
generate FGD wastewater:
•	FGD wastewater characterization data associated with testing and implementing
treatment technologies, in 2013 or later.
•	Planned installations of FGD wastewater treatment technologies.
•	Information on halogen usage to reduce flue gas emissions, as well as halogen
concentration data in FGD wastewater.
•	Cost information for planned or installed FGD wastewater treatment systems,
from bids received in 2013 or later.
The EPA used this information to learn more about the performance of FGD wastewater
treatment systems, inform FGD wastewater limitations development, learn more about plant-
2-2

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Section 2—Data Collection Activities
specific halogen usage, and obtain information useful for estimating the cost of installing
candidate treatment technologies. The EPA used this information to supplement the data
collected in support of the 2015 rule. As described in Section 3.4 of the 2015 TDD, between July
2007 and April 2011, the EPA conducted a sampling program at 17 different steam electric
power plants in the United States and Italy to collect wastewater characterization data and
treatment performance data. As needed, the EPA conducted follow-up meetings and conference
calls with industry representatives to discuss and clarify these data.
2.2.2 Voluntary Sampling Program for Bottom Ash Transport Water
In order to further supplement the bottom ash transport water characterization data set used to
support the 2015 rule analyses, the EPA invited seven steam electric power plants to participate
in a voluntary bottom ash transport water sampling program. The EPA requested information
from steam electric power plants operating impoundments that predominantly contain bottom
ash transport water. Plants were asked to provide analytical data for ash impoundment effluent
and untreated bottom ash transport water (i.e., ash impoundment influent). Two plants chose to
participate in the voluntary bottom ash sampling program and provided the EPA with the bottom
ash data requested.
2.3 Technology Vendor Data
The EPA gathered data from technology vendors through presentations, conferences, site visits,
meetings, and email and phone contacts regarding the FGD wastewater and bottom ash handling
technologies used in the industry. The data collected informed the development of the
technology costs and pollutant removal estimates for FGD wastewater and bottom ash transport
water. The EPA participated in multiple technical conferences and reviewed the papers presented
for relevant information to the proposed rule.
To gather FGD wastewater treatment information for the cost analyses, the EPA contacted
companies that manufacture, distribute, or install various components of biological wastewater
treatment, membrane filtration, or thermal evaporation systems. The EPA also contacted
consulting firms that design and implement FGD wastewater treatment technologies. The
vendors and consulting firms provided the following types of information for EPA's analyses:
•	Operating details.
•	Performance data where available.
•	Equipment used in the system.
•	Estimated capital and operating and maintenance (O&M) costs.
•	System energy requirements.
•	Timeline.
To gather information on bottom ash handling systems, the EPA also contacted vendors as well
as consulting firms that design and implement these systems. The vendors and consulting firms
provided the following types of information for EPA's analyses:
•	Systems available for reducing or eliminating ash transport water.
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Section 2—Data Collection Activities
•	Equipment, modifications, and demolition required to convert wet sluicing
systems to dry ash handling or closed-loop recycle systems.5
•	Equipment that can be reused as part of the conversion from wet to dry handling
or in a closed-loop recycle system.
•	Outage time estimated for the different types of ash handling systems.
•	Maintenance estimated for each type of system.
•	Estimated capital and operating and maintenance (O&M) costs.
Cost information collected from technology vendors is further detailed in Section 5.
2.4 Other Data Sources
The EPA obtained information on steam electric processes, wastewater treatment, wastewater
characteristics, and regulations from sources including trade associations such as UWAG and the
Electric Power Research Institute (EPRI), the U.S. Department of Energy (DOE), literature and
Internet searches, and environmental groups. Sections 2.4.1 through 2.4.4 summarize the data
collected from these additional sources during reconsideration of the 2015 rule.
2.4.1 Trade Associations
UWAG is an association of individual electric utilities and several national trade associations of
electric utilities, including the Edison Electric Institute, the National Rural Electric Cooperative
Association, and the American Public Power Association. The EPA met with UWAG to discuss
approaches for managing discharges of FGD wastewater and bottom ash transport water.
EPRI conducts studies funded by the steam electric power generating industry to evaluate and
demonstrate technologies that can potentially remove pollutants of concern from wastestreams or
eliminate wastestreams using zero discharge technologies. The EPA reviewed 35 reports that
EPRI voluntarily provided, or which already had been included in 308 responses, listed in Table
2-2. These reports were not part of the 2015 rule record, and contained information relevant to
characteristics of FGD wastewater, FGD wastewater treatment pilot studies, bottom ash transport
water characterization, bottom ash handling practices, and the effect of halogen additives on
FGD wastewater.
Table 2-2. EPRI Reports and Studies Reviewed by the EPA as Part of the Reconsideration
of the 2015 rule
Title of Report/Study
Date Published
Doeument Control
Number
Pilot-Scale Demonstration of Hybrid Zero-Valent Iron Water
Treatment Technology
April 2013
DCN SE06391A2
5 Throughout this report, the EPA refers to bottom ash systems that eliminate the use of ash transport water as dry
ash handling systems; however, some of these systems (e.g., mechanical drag system) still use water in a quench
bath and, therefore, are not completely dry systems.
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Section 2—Data Collection Activities
Table 2-2. EPRI Reports and Studies Reviewed by the EPA as Part of the Reconsideration
of the 2015 rule
Title of Rcport/Studv
Date Published
Doeument Control
Number
Flue Gas Desulfurization (FGD) Wastewater Chemical
Precipitation Bench-Scale Treatability Study
August 2015
DCN SE06391A2
Wastewater Minimization Using Water Pinch Analysis
November 2016
DCN SE06391A2
Physical/Chemical Treatment of Flue Gas Desulfurization
Wastewater - Case Study 1
July 2015
DCN SE06391A2
Laboratory Evaluation of Arsenic Adsorption Media for Flue Gas
Desulfurization Wastewater
October 2015
DCN SE06391A2
Field Evaluation of Online Selenium and Mercury Monitors
November 2017
DCN SE06391A2
Program on Technology Innovation: Review of Desalination
Technology for Power Plants
December 2017
DCN SE06391A2
Program on Technology Innovation: Mineralogical Investigation
of a Brine Encapsulated Monolith
December 2017
DCN SE06391A2
Biological Treatment of Flue Gas Desulfurization Wastewater at a
Power Plant Burning Powder River Basin Coal - Pilot
Demonstration with the ABMet Technology
March 2017
DCN SE06610A2
Conditions Impacting Treatment of Wet Flue Gas Desulfurization
Wastewater
August 2017
DCN SE06850A3
Closed-Loop Bottom Ash Transport Water: Costs and Benefits to
Managing Purges
September 201
DCN SE06920
Mercury Control Update 2011
December 2011
DCN SE06948
Performance Evaluation of a Radial Deionization System for Flue
Gas Desulfurization Wastewater Treatment
December 2013
DCN SE06949
Evaluation of Wet-to-Dry Retrofits for Bottom Ash Handling
Systems at Coal-fired Power Plants Owned by a Midwestern
Utility Company
November 2014
DCN SE06950
Effectiveness and Balance-of-Plant Impacts of Added Bromine
November 2013
DCN SE06951
State of Knowledge: Power Plant Wastewater Treatment -
Membrane Technologies
August 2015
DCN SE06952
Performance Evaluation of a Vibratory Sheer Enhanced
Processing Membrane System for FGD Wastewater Treatment
July 2014
DCN SE06953
Demonstration Development Project: Vortex-Based Antifouling
Membrane System Treating Flue Gas Desulfurization Wastewater
October 2014
DCN SE06954
Demonstration Development Project: Feasibility of an Adiabatic
Evaporator for Flue Gas Desulfurization Wastewater Zero Liquid
Discharge Treatment Using Flue Gas Heat
May 2015
DCN SE06955
Program on Technology Innovation: Bromine Usage, Fate, and
Potential Impacts for Fossil Fuel-Fired Power Plants
July 2014
DCN SE06956
2015 Impacts of Refined Coals and Additives
December 2015
DCN SE06957
Halogen Addition for Mercury Control and Related Balance-of-
Plant Issues
December 2015
DCN SE06958
Landfill Leachate Characterization, Management and Treatment
Options
November 2017
DCN SE06959
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Section 2—Data Collection Activities
Table 2-2. EPRI Reports and Studies Reviewed by the EPA as Part of the Reconsideration
of the 2015 rule
Title of Rcport/Studv
Date Published
Doeument Control
Number
Pilot Evaluation of Various Adsorption Media for FGD
Wastewater Treatment
August 2015
DCN SE06960
Evaluation of Vacom One-Step System for Concentrating Flue
Gas Desulfurization Wastewater
December 2015
DCN SE06961
Evaluating Pironox Advanced Reactive Media Process for
Treating Flue Gas Desulfurization Wastewater: Effect of Bromine
Addition of Wastewater Treatment
January 2016
DCN SE06962
Guidance Document for Management of Closed-Loop Bottom Ash
Handling Water in Compliance with the 2015 Effluent Limitations
Guidelines (ELGs)
December 2016
DCN SE06963
Characterizing Flue Gas Desulfurization Wastewater in Systems
with Mercury and Air Toxics Control
February 2017
DCN SE06964
Wet Flue Gas Desulfurization Wastewater Physical/Chemical
Treatment Guidelines
December 2016
DCN SE06965
Pilot Evaluation of the Sylvan Source Core Water Treatment
System
April 2017
DCN SE06966
Materials Selection of Alloys in Forced Oxidation Wet Flue Gas
Desulfurization Absorber Environments with Increased Halide
Content
September 2016
DCN SE06967
Program on Technology Innovation: Alternative and Innovative
Technologies for Coal Combustion Product Management
December 2016
DCN SE06968
Water Management—Evaluation of Treatment for Closed-Loop
Bottom Ash Purges to FGD
December 2017
DCN SE06969
Evaporation Treatment of Flue Gas Desulfurization Wastewater
October 2017
DCN SE06970
Thermal Evaporation Technologies for Treating Power Plant
Wastewater
September 2017
DCN SE06971
The Institute of Clean Air Companies (ICAC) is a national trade association of companies that
supply air pollution control and monitoring systems, equipment, and services for stationary
sources. The EPA met with ICAC to learn more about mercury air pollution control technologies
for coal-fired generating units, with a specific focus on the use of halogens and the impacts
halogens may have on drinking water plants located downstream of power plants.
2.4.2 Department of Energy
The EPA used information on steam electric generating plants from DOE's Energy Information
Administration (EIA) Form EIA-860, Annual Electric Generator Report, and Form EIA-923,
Power Plant Operations Report. The data collected in Form EIA-860 are associated with the
design and operation of generators at plants, and the data collected in Form EIA-923 are
associated with the design and operation of the entire plant (U.S. DOE, 2016a and 2016b). The
EPA used these data to update the industry profile from the 2015 rule, including commissioning
2-6

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Section 2—Data Collection Activities
dates, energy sources, capacity, net generation, operating statuses, planned retirement dates,
ownership, and pollution controls of the generating units.
2.4.3	Literature and Internet Searches
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 timeline. The EPA also used the
Internet searches to identify or confirm reports of planned plant/unit retirements or reports of
planned unit conversions to dry or closed-loop recycle ash handling systems. The EPA used
industry journals and company press releases obtained from Internet searches to inform the
industry profile and process modifications occurring in the industry. Updates made to the
industry profile are discussed further in Section 3.1.
The EPA also identified additional FGD wastewater treatment technologies that are being tested
and installed. The EPA met with several technology vendors to gather more information on these
technologies and examined published research articles describing FGD wastewater treatment
technologies at bench-, pilot-, and full-scale levels. The EPA's evaluation of FGD treatment
technologies is further discussed in the preamble.
2.4.4	Environmental Groups
The EPA received information from several environmental groups and other stakeholders
following the 2015 rule. In general, these groups provided information about bromide discharges
from steam electric power plants, their interaction with drinking water treatment plants, and the
associated human health effects. They also noted the advancement in the availability of
technological controls for reducing or eliminating pollutant discharges from FGD and bottom ash
handling systems. Finally, environmental groups and other stakeholders provided examples of
states which, when issuing permits, they believed had not properly considered the "as soon as
possible date" for the new, more stringent BAT requirements.
2.5	Protection of Confidential Business Information
Certain data in the rulemaking record have been claimed as confidential business information
(CBI). As required by federal regulations at 40 CFR 2, the EPA has taken precautions to prevent
the inadvertent disclosure of this CBI. The Agency has withheld CBI from the public docket in
the Federal Docket Management System. In addition, the EPA has found it necessary to withhold
from disclosure some data not claimed as CBI because the release of these data could indirectly
reveal CBI. Where necessary, the EPA has aggregated certain data in the public docket, masked
plant identities, or used other strategies to prevent the disclosure of CBI. The Agency's approach
to protecting CBI ensures that the data in the public docket explain the basis for the rule and
provide the opportunity for public comment without compromising data confidentiality.
2.6	References
1. ERG. 2018. Eastern Research Group, Inc. Memorandum of Site Visit to Harris
Treatment Plant. (18 July). DCN SE07225.
2-7

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Section 2—Data Collection Activities
2.	U.S. DOE. 2016a. U.S. Department of Energy. Annual Electric Generator Report
(collected via Form EIA-860). Energy Information Administration (EIA). The data
files are available online at: http://www.eia.gov/electricity/data/eia860/index.html.
DCN SE06751.
3.	U.S. DOE. 2016b. U.S. Department of Energy. Power Plant Operations Report
(collected via Form EIA-923). Energy Information Administration (EIA). The data
files are available online at: http://www.eia.gov/electricity/data/eia923/index.html.
DCN SE07241.
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Section 3—Current State of the Steam Electric Power Generating Industry
SECTION 3
CURRENT STATE OF THE STEAM ELECTRIC POWER
GENERATING INDUSTRY
The Agency is proposing revisions to the requirements established in 2015 applicable to FGD
wastewater and bottom ash transport water discharged from steam electric power plants. As part
of this proposed rule, the EPA updated the industry profile, evaluated changes in wastewater
management practices, and assessed impacts from other regulations affecting steam electric
power plants. Section 3.1 describes changes to the steam electric power plant population
following completion of the 2015 rule analyses. Section 3.2 summarizes current information on
discharges of FGD wastewater and bottom ash transport water from steam electric power plants.
Section 3.3 describes how other statutes and regulatory actions affecting management of steam
electric power plant wastewaters, such as the Coal Combustion Residuals (CCR) rule, are
accounted for in the Agency's updated analyses for the proposed rule.
3.1 Changes in the Steam Electric Power Generating Industry Since 2015 rule
The steam electric power generating industry is dynamic; the Agency recognizes that changes to
industry demographics and plant operations occurred following completion of the 2015 rule
analyses.6 Therefore, the EPA collected information on current plant operations and plans for
future modifications to augment industry profile data collected for the 2015 rule. This section
discusses changes in the number and operating status of coal-fired generating units and updates
to wet FGD systems, FGD wastewater treatment, and bottom ash handling systems at steam
electric power plants.
The EPA gathered readily available information from public sources, including company
announcements and Department of Energy (DOE) Energy Information Administration (EIA)
data, to account for the following types of operation changes that have occurred or been
announced since August 2014:
•	Commissioning of new coal-fired generating units.
•	Retirement of coal-fired generating units.7
•	Fuel conversions of coal-fired generating units from coal to another fuel source,
such as natural gas or hydrogen fuel cell.
•	Installation of wet FGD systems.
•	Modification or upgrade of an FGD wastewater treatment system.
6	The EPA accounted for all industry profile changes announced and verified as of August 2014 in the 2015 rule
analyses.
7	For the purposes of this analysis, the EPA accounted for generating units that will be indefinitely removed from
service (e.g., idled or mothballed) as retirements. See the preamble for discussion of EPA's evaluation of coal-fired
generating units nearing end of life.
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Section 3—Current State of the Steam Electric Power Generating Industry
• Installation of, or conversion to, dry, closed-loop recycle, or high recycle rate wet-
sluicing bottom ash handling system.8
The EPA has identified 382 coal-fired generating units at 171 plants with at least one significant
change in operation taking place between August 2014 and December 31, 2028 (the date by
which proposed revisions to BAT requirements for FGD wastewater and bottom ash transport
water would be fully implemented). Table 3-1 presents the count of steam electric generating
units and plants, broken out by type of operation change.
8 For the purpose of this discussion, dry bottom ash handling systems include all systems that do not generate
bottom ash transport water. Consistent with the 2015 rule, the EPA considers a mechanical drag system to be a form
of dry bottom ash handling. Although the system uses water in a quench bath to cool bottom ash, water is not used
to transport the ash. Closed-loop recycle and high recycle rate systems use water to transport bottom ash and recycle
all, or a majority of, the bottom ash transport water back to the bottom ash handling system, respectively.
3-2

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Section 3—Current State of the Steam Electric Power Generating Industry
Table 3-1. Industry Profile Updates Since August 2014 by Type of Change in Operation
Change in Operation
Count"
Generating Units''
Power Plants1
Commissioning of New Coal-Fired Generating Unitd
18
16
Retirement of Coal-Fired Generating Unit
160
78
Fuel Conversion to Non-Coal Fuel Typee
43
26
Installation of Wet FGD System
16
8
Modification or Upgrade of FGD Wastewater Treatment
System
53
18
Installation or Conversion to Dry, Closed-Loop Recycle, or
High Recycle Rate Bottom Ash Handling System
138
61
Source: ERG, 2019a.
Note: EPA's analysis accounted for all changes in operation announced and verified by October 2018. Any changes
in operation or planned modifications identified after October 2018 were considered only in a sensitivity analysis.
See the memorandum titled "Changes to Industry Profile for Coal-Fired Generating Units for the Steam Electric
Effluent Guidelines Proposed Rule" for additional information on plants identified with industry profile changes and
the EPA's sensitivity analysis (ERG, 2019a).
a - Counts are not additive because there may be multiple changes in operation at a single steam electric generating
unit or plant (e.g., installation of a dry bottom ash handling system and a wet FGD system),
b - A physical combination of prime movers, including steam turbines and/or combined cycle systems, that utilize
steam to drive an electric generator.
c - An establishment that operates a generating unit, whose 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, or gas), fuel derived from fossil fuel (e.g., petroleum coke, synthesis gas), or
nuclear fuel in conjunction with a thermal cycle employing the steam water system as the thermodynamic medium
(40 CFRPart 423.10).
d - Includes seven coal-fired generating units at seven power plants, plus 11 coal-fired generating units
commissioned at nine new plants (i.e., plants not accounted for in the 2015 rule analyses),
e - Includes 28 coal-fired generating units at 17 plants converting to natural gas, 1 coal-fired generating unit at one
plant converting to hydrogen fuel, 1 coal-fired generating unit at one plant converting to biomass, and 13 coal-fired
generating units at 8 plants ceasing to burn coal (announcement does not specify type of fuel conversion).
The EPA updated the industry profile to account for coal-fired generating units subject to the
steam electric power generating ELGs that began operation after the Questionnaire for the Steam
Electric Power Generating Effluent Guidelines (Steam Electric Survey). The Agency used
information from two EIA data collection forms, Form EIA-860 (Annual Electric Generator
Report) and Form EIA-923 (Power Plant Operations Report), for the calendar year 2016 to
identify generating units commissioned since 2009 (U.S. DOE, 2016a and 2016b). Those active
coal-fired generating units that began operating after 2009, operate at least one prime mover
utilizing steam, use a form of coal or petroleum coke as the primary energy source, and could be
classified as utilities or non-industrial non-utilities were added to the industry profile (unless they
were already captured in the 2015 rule analyses). The EPA added new generating units
commissioned at both existing power plants (i.e., plants in the 2015 rule population) and new
power plants (i.e., those not accounted for in the 2015 rule analyses) to the industry profile for
this proposed rule. The EPA collected information on unit operations and wastewater
management practices for these generating units from EPA's National Electric Energy Data
3-3

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Section 3—Current State of the Steam Electric Power Generating Industry
System (NEEDS), National Pollutant Discharge Elimination System (NPDES) permits, and
regional EPA offices to account for these generating units in corresponding analyses (U.S. EPA,
2018).
The EPA removed coal-fired generating units that will retire or convert fuel type prior to
December 31, 2028, from the analyses supporting this proposed rule because they will cease
discharging FGD wastewater or bottom ash transport water prior to the date of compliance
included with this proposed rule. As shown in Table 3-1, the number of coal-fired generating
units and plants expected to retire or convert fuels prior to December 31, 2028 is greater than the
number being commissioned, causing an overall decrease in the number of operations.
Subsequently, the population of coal-fired generating units and plants decreased to 550
generating units at 284 plants, 25 percent fewer generating units than the 2015 rule population.9
Figure 3-1 illustrates the change in the number of operating coal-fired steam electric generating
units and plants since the Steam Electric Survey and 2015 rule.
Steam Electric
Survey (2009)
2019 Proposed Rule
Generating Units
1099
735
550
^^"Power Plants
471
347
284
Source: ERG, 2019a.
Figure 3-1. Population of Coal-Fired Generating Units and Plants
To meet air quality requirements, power plants use a variety of FGD systems to control sulfur
dioxide (SO2) emissions from flue gas generated in the plant's boiler. For this proposed rule, the
EPA updated the profile to account for wet FGD systems on coal-fired generating units that were
not reported in the Steam Electric Survey and to account for upgrades to FGD wastewater
treatment systems. The Agency used information available in NEEDS to identify wet FGD
systems that began operating after 2009. The EPA collected information on FGD wastewater
9 The 2015 rule analyses accounted for industry profile changes to be completed before December 31, 2023 (the date
that power plants were subject to the established BAT effluent limitations).
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Section 3—Current State of the Steam Electric Power Generating Industry
generation, management, and treatment for these FGD systems from NPDES permits and
regional EPA offices.
Through company announcements and conversations with power plant operators and vendors,
the EPA identified plants upgrading or planning to upgrade their bottom ash handling practices
or FGD wastewater treatment systems. The EPA collected information on bottom ash handling
conversions and FGD wastewater treatment upgrades made at each plant and corresponding
generating units, and incorporated changes that would be completed by December 31, 2028 into
the industry profile and corresponding technical analyses.
Section 5 and Section 6 describe how the EPA accounted for the changes in operation identified
in Table 3-1 in estimating compliance costs, pollutant loadings, and pollutant removals for this
proposed rule. Additional information regarding specific coal-fired generating units and plants
identified as implementing each type of operation change is discussed in the memorandum titled
"Changes to Industry Profile for Coal-Fired Generating Units for the Steam Electric Effluent
Guidelines Proposed Rule" (ERG, 2019a).
3.2 Current Information on Evaluated Wastestreams
The EPA is proposing revised discharge requirements for FGD wastewater and bottom ash
transport water generated by steam electric power plants. This section summarizes current
information on the generation, characteristics, and discharge of these wastestreams collected by
the EPA for this proposed rule.
3.2.1 FGD Wastewater
As discussed in Section 3.1, the EPA updated the industry profile and corresponding analyses to
reflect coal-fired generating units that will retire, convert fuels, or upgrade FGD wastewater
treatment prior to December 31, 2028. The EPA also updated the industry profile to reflect wet
FGD systems that began operating after the Steam Electric Survey. Of the 550 coal-fired
generating units at 284 coal-fired power plants in the updated profile, 270 generating units at 119
plants are serviced by a wet FGD system. The EPA estimates generating units with wet FGD
systems have a total wet-scrubbed capacity of 148,000 MW, representing 64 percent of the total
industry coal-fired capacity. Figure 3-2 shows the location of plants operating wet FGD systems
on at least one coal-fired generating unit in the United States.
3-5

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Section 3—Current State of the Steam Electric Power Generating Industry
° Plant with Wet FGD System(s)
Sources: ERG. 2015 and 2019a.
Note: Steam electric power plants shown operate a wet FGD system on at least one generating unit as of June 2018,
excluding generating units that will retire or convert fuels by December 31, 2028.
Figure 3-2. Wet FGD Systems at Steam Electric Power Plants
Although the number of wet FGD systems operated at steam electric power plants has decreased
since promulgation of the 2015 rule, current FGD scrubber technologies are the same as those
used at the time of the 2015 rule. These wet FGD systems typically use a limestone slurry with
forced oxidation and service generating units burning bituminous coal. Often, plants also operate
selective catalytic reduction (SCR) systems on these generating units to control nitrogen oxide
(NOx) emissions.
Following promulgation of the 2015 rule, the EPA collected new information on air pollution
control practices at steam electric power plants that may impact characteristics of FGD
wastewater. Specifically, the EPA found that steam electric power plants may use bromide or
other halogenated compounds to reduce mercury air emissions. While all coal contains at least
some naturally-occurring bromide, steam electric power plant operators can augment coal
bromide concentrations at various points in the plant operations to enhance mercury oxidation
for mercury capture (e.g., directly injecting bromide during combustion; mixing bromide with
coal to produce refined coal; and using brominated activated carbon to control air emissions).
3-6

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Section 3—Current State of the Steam Electric Power Generating Industry
Bromide in flue gas at steam electric power plants is captured by wet FGD systems and
discharged in FGD wastewater. For this proposed rule, the EPA characterized bromide
discharges in FGD wastewater and estimated the corresponding pollutant loadings and removals,
as discussed in Section 6.10
Since the 2015 rule, steam electric power plants have conducted on-site testing and/or installed
additional technologies to treat FGD wastewater. These technologies include, but are not limited
to, low residence time reduction (LRTR) biological treatment, high residence time reduction
(HRTR) biological treatment, advanced membrane filtration, and thermal evaporative systems.
The EPA has identified that approximately ten percent of steam electric power plants with wet
scrubbers have technologies in place able to meet the proposed BAT effluent limitations for FGD
wastewater, including LRTR, HRTR, and thermal evaporation systems. As described in Section
VII of the preamble, a further forty percent of all steam electric power plants with wet scrubbers
use FGD wastewater management approaches that eliminate the discharge of FGD wastewater
altogether. See Section 4 for more details on these treatment technologies employed by steam
electric power plants to treat or reduce FGD wastewater discharges. Table 3-2 summarizes FGD
wastewater discharged by the steam electric power generating industry.
Table 3-2. FGD Wastewater Discharges for the Steam Electric Power Plants
Nil ill hoi' of
Phi Ills
Number of
(ioiioi'iiliiiu
I nils
l-'(il) \\ ;isIc\\;iIit Dischsirgi* How K;iu*
l oliil l);iil\
l)isch;ir;iO I'low
K;i(o(M(.D)
Pliinl .\\er«iiie
l);iil\ Dischiiriic
l low Kiiio
(MCI) per pliinl)
1 oliil Aniiiiiil
Dischiiriic I'low
RiilelMCY)
Pliinl A\er;i«ie
Aniiiiiil Dischiiriic
l low Kiiic
(\1(.Y per pliinl)
70
167
35.3
0.504
12,900
184
Source: ERG, 2019b.
MGY = million gallons per year.
Note: Counts and flow rates presented account for generating units that will retire or convert fuels by December 31,
2028 and wet FGD systems that began operating after the Steam Electric Survey.
3.2.2 Bottom Ash Transport Water
Based on the Steam Electric Survey, approximately two-thirds of coal-fired power plants
operated wet bottom ash handling systems in 2009. Some plants operating the wet bottom ash
handling systems recycled bottom ash transport water from impoundments, dewatering bins, or
other handling systems back to the wet-sluicing system; however, most bottom ash transport
water was discharged to surface water. At the time of the Steam Electric Survey, less than 40
percent of generating units operated dry, closed-loop recycle, or high recycle rate bottom ash
handling systems. Because of changes happening in the industry in the years following the Steam
Electric Survey, by 2015 more than half of generating units operated or planned to convert to
dry, closed-loop recycle, or high recycle rate bottom ash handling systems.
10 Additional information about sources of bromide at steam electric power plants, impacts of bromide on drinking
water treatments, and potential impacts of brominated disinfection byproducts is provided in the Supplemental
Environmental Assessment for Proposed Revisions to the Effluent Limitations Guidelines and Standards for the
Steam Electric Power Generating Point Source Category (U.S. EPA, 2019).
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Section 3—Current State of the Steam Electric Power Generating Industry
As discussed in Section 3.1, the EPA updated the industry profile and corresponding analyses to
estimate coal-fired generating units that will retire, convert fuels, or install dry, closed-loop
recycle, or high recycle rate bottom ash handling systems prior to December 31, 2028. Since
completion of the 2015 rule analyses, more plants have converted or are converting to dry,
closed-loop recycle, or high recycle rate bottom ash handling systems, thereby eliminating or
minimizing discharge of bottom ash transport water. In addition, based on data from the Steam
Electric Survey, generating units commissioned after 2009 are likely to operate dry or closed-
loop recycle bottom ash handling systems.11 Further, the number of coal-fired generating units
operating wet sluicing systems has decreased due to plant retirements and fuel conversions.
Table 3-3 presents the count and total generating capacity of the generating units operating wet
sluicing, closed-loop recycle, high recycle rate, and/or dry bottom ash handling systems. The
EPA estimates that more than 75 percent of generating units operate either dry, closed-loop
recycle, or high recycle rate bottom ash handling systems.12 Figure 3-3 illustrates the geographic
distribution of plants operating the systems noted in Table 3-3.
11	Data from the Steam Electric Survey show that more than 80 percent of generating units built in the 20 years
preceding the survey (1989-2009) installed dry bottom ash handling at the time of construction. Since 2009, it has
been clear to all power companies and their engineering, procurement, and construction (EPC) firms that the EPA's
ELGs and rulemaking efforts would address discharges of bottom ash transport water. Because dry bottom ash
technologies are less expensive to operate than wet-sluicing systems and facilitate beneficial use of the bottom ash,
it is unlikely that power companies would find it advantageous to install and operate a wet-sluicing bottom ash
handling system.
12	Counts presented in this paragraph and Table 3-3 do not reflect bottom ash handling conversions expected as a
result of the CCR rule.
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Section 3—Current State of the Steam Electric Power Generating Industry
Table 3-3. Bottom Ash Handling Systems for Coal-Fired Generating Units
Bottom Ash Handling System
Number of Plants
Number of
Generating Units
Nameplate Capacity
(MW)
Wet Sluicing System with Limited or No
Recycle
62
126
54,800
Wet Sluicing Closed-Loop/High Recycle
Rate System
56
140
75,000
Dry Bottom Ash Handling System b
173
284
101,000
Total
284a
550
230,000
Source: ERG, 2019a.
Note: Counts and capacities presented account for coal-fired generating unit retirements, fuel conversions, and
bottom ash handling conversions that will have been completed by December 31, 2028. Values do not reflect
additional bottom ash handling system conversions that plants will implement to comply with the CCR rule,
a - Plant counts are not additive because plants may operate multiple types of bottom ash handling systems,
b - The dry bottom ash handling system counts presented in this table reflect conversions identified by the EPA in
the Steam Electric Survey and publicly available information since 2009. Where data were available, the EPA
tracked the specific types of bottom ash handling conversions, such as mechanical drag systems (MDS) and remote
mechanical drag systems (rMDS). However, the EPA identified 63 generating units, corresponding to 25,000 MW at
33 plants, where the data confirmed the plant was not discharging bottom ash transport water but did not confirm the
specific type of non-discharging system.
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Section 3—Current State of the Steam Electric Power Generating Industry
Bottom Ash Handling System Type
•	Wet Sluicing System with Limited or No Recycle
E Wet Sluicing Closed-Loop/High Recycle Rate System
~	Dry Bottom Ash Handling System
Sources: ERG. 2015 and 2019a.
Note: Excludes power plants that will retire or convert fuels for all coal-fired generating units by December 31.
2028.
Figure 3-3. Plant-Level Bottom Ash Handling Systems in the Steam Electric Power
Generating Industry
Table 3-4 summarizes bottom ash transport water discharges by the steam electric power
generating industry.
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Section 3—Current State of the Steam Electric Power Generating Industry
Table 3-4. Bottom Ash Transport Water Discharges for Steam Electric Power Plants
Nil ill hoi' of
PhllllS
Number of
(ioiioi'iilinu
I nils
lioll
Tolsil l)siil\
Dischiiriic How
Rsile (M(.D)
mi Ash 1 rsinsporl \\
Plsinl A\er;iiie
l);iil\ Dischiiriic
How Rsile
(MCI) per plsinl)
silcr Dischsirsic How
l olsil AiiiiiisiI
Dischiiriic How
KsilclMCY)
Ksilc
Plsinl A\ersiiie
AiiiiiisiI Dischsir^o
How Ksilc
(\1(.Y per plsinl)
62
126
107
1.73
39,100
631
Source: ERG, 2019c.
Note: Counts and capacities presented account for retirements, fuel conversions, and bottom ash handling
conversions at coal-fired generating units that will be complete by December 31, 2028. Values do not reflect bottom
ash handling system conversions the EPA expects plants to implement to comply with the CCR rule.
3.3 Other Regulations on the Steam Electric Power Generating Industry
The Agency recognizes that effluent guidelines on steam electric power plants do not exist in
isolation - other EPA regulations set requirements for control of pollution emissions, discharges,
and other releases from steam electric power plants. For the 2015 rule, the EPA assessed and
incorporated impacts from the Clean Power Plan (CPP) and CCR rule into the supporting
analyses. Specifically, in the 2015 TDD, the EPA presented the results for the following two
scenarios: (1) incorporating expected changes to the industry profile due to the CCR rule, and (2)
incorporating expected changes to the industry profile due to both the CCR rule and the CPP.
In 2017, the EPA proposed to repeal the CPP and the regulation was indefinitely stayed by the
U.S. Supreme Court. Due to this development, the EPA's analyses for baseline and the proposed
regulatory options do not consider expected profile changes associated with the CPP.13
The EPA has continued to account for industry profile changes associated with the CCR rule.
The EPA coordinated the requirements of the CCR rule and the 2015 rule to mitigate potential
impacts from the overlapping regulatory requirements and to facilitate implementation of
engineering, financial, and permitting activities. Based on the CCR rule requirements established
in 2015, the EPA expected plants would alter how they operate their CCR surface
impoundments, such as by undertaking the following changes:
•	Close the disposal surface impoundment and open a new disposal surface
impoundment in its place.
•	Convert the disposal surface impoundment to a new storage impoundment.
•	Close the disposal surface impoundment and convert to dry handling operations.
13 On August 21, 2018, the EPA proposed the Affordable Clean Energy (ACE) Rule which would establish emission
guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants.
The ACE Rule would replace the 2015 CPP. The EPA's costs and pollutant loadings estimates do not reflect any
industry profile updates (i.e., retirements) expected from the final ACE Rule since these analyses were completed
prior to that rule being finalized, however, a supplemental IPM run including that rule is presented in the preamble
and RIA.
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Section 3—Current State of the Steam Electric Power Generating Industry
• Make no changes to the operation of the disposal surface impoundment.
For the 2015 rule, the EPA developed a methodology to use the yearly probabilistic model output
analysis of the CCR rule to predict which of the four potential operational changes could likely
occur at each coal-fired power plant that operates a disposal impoundment under the CCR rule.
The EPA then updated its population and associated treatment in place to account for the plant-
level decisions for operational changes each plant is estimated to make to comply with the CCR
rule. Section 9.4.1 of the 2015 TDD describes how the EPA used the classifications to adjust
compliance costs, pollutant loadings/removals, and other analyses for each wastestream.
As discussed in Section 1.3, the EPA is proposing revisions to multiple aspects of the 2015 CCR
rule. For this proposed ELG, the EPA determined that the plant-specific operational changes
estimated in support of the 2015 rule are still valid and useful for this proposed rule. Using the
2015 rule methodology, the EPA expects that 18 plants would convert to mechanical drag or
remote mechanical drag bottom ash handling systems because of the CCR rule, and as a result
would not incur bottom ash transport water compliance costs attributable to the ELGs.14 In
addition, the EPA estimates 8 plants would modify their FGD wastewater treatment because of
the CCR rule and, as a result, their costs to comply with the ELGs would be reduced.
Section 5 and Section 6 describe how the EPA accounted for CCR rule impacts in estimating
compliance costs, pollutant loadings, and pollutant removals for this proposed rule. The EPA
also conducted a sensitivity analysis using company-posted liner and leak status data, required as
part of the CCR rule, to account for additional surface impoundment closures and corresponding
changes in operation, discussed in the memorandum titled "Sensitivity Analysis for Estimating
the Impacts of the Proposed Amendments to the CCR Rule" (ERG, 2019d).
3.4 References
1.	ERG. 2015. Eastern Research Group, Inc. Final Steam Electric Technical
Questionnaire Database. (September 30). DCN SE05924.
2.	ERG. 2019a. Eastern Research Group, Inc. Changes to Industry Profile for Coal-Fired
Generating Units for the Steam Electric Effluent Guidelines Proposed Rule. (July 31).
DCN SE07207.
3.	ERG. 2019b. Eastern Research Group, Inc. FGD Loads Database. (July 18). DCN
SE07103.
4.	ERG. 2019c. Eastern Research Group, Inc. Bottom Ash Transport Water Pollutant
Loadings Model. (August 30). DCN SE06870.
14 Plants that install rMDS to comply with the CCR rule may incur costs to install a reverse osmosis system to treat a
slipstream of the recirculating bottom ash transport water, as a way to remove dissolved solids and facilitate long-
term operation of the system as a closed loop to comply with the bottom ash zero discharge requirements of the
2015 rule (i.e., baseline). There are other approaches that can also be used to remove dissolved solids from the
bottom ash system without using reverse osmosis treatment, such as using the transport water as makeup water for
the FGD system. Dissolved solids will also be removed from the system along with the bottom ash, which is wet as
it is removed from the rMDS. As appropriate, the EPA will update the compliance cost estimates for these plants in
future analyses.
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Section 3—Current State of the Steam Electric Power Generating Industry
5.	ERG. 2019d. Eastern Research Group, Inc. Sensitivity Analysis for Estimating
Impacts of the Proposed Amendments to the Coal Combustion Residual (CCR) Rule.
(October). DCN SE07233.
6.	U.S. DOE. 2016a. U.S. Department of Energy. Annual Electric Generator Report
(collected via Form EIA-860). Energy Information Administration (EIA). The data
files are available online at: http://www.eia.gov/electricitv/data/eia860/index.html.
DCN SE06751.
7.	U.S. DOE. 2016b. U.S. Department of Energy. Power Plant Operations Report
(collected via Form EIA-923). Energy Information Administration (EIA). The data
files are available online at: http://www.eia.gov/electricitv/data/eia923/index.html.
DCN SE07241.
8.	U.S. EPA. 2015. U.S. Environmental Protection Agency. Technical Development
Document for the Effluent Limitations Guidelines and Standards for the Steam
Electric Power Generating Point Source Category (2015 TDD). (September 30).
DCN SE05904.
9.	U.S. EPA. 2018. U.S. Environmental Protection Agency. National Electric Energy
Data System (NEEDS) - Version 6. (November 30). Available online at:
https://www.epa.gov/airmarkets/national-electric-energv-data-svstem-needs-v6. DCN
SE07223.
10.	U.S. EPA. 2019. U.S. Environmental Protection Agency. Supplemental
Environmental Assessment for Proposed Revisions to the Effluent Limitations
Guidelines and Standards for the Steam Electric Power Generating Point Source
Category (Supplemental EA). (October). DCN SE07243.
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Section 4—Treatment Technologies and Wastewater Management Practices
SECTION 4
TREATMENT TECHNOLOGIES AND WASTEWATER
MANAGEMENT PRACTICES
This section provides an overview of treatment technologies and wastewater management
practices at steam electric power plants for flue gas desulfurization (FGD) wastewater and
bottom ash handling wastewater. All technologies evaluated as part of the 2015 rule are still
being used in the industry; see the 2015 TDD for a full description of these technologies. This
section focuses primarily on technologies identified for the treatment of FGD wastewater and
bottom ash handling wastewater since the 2015 rule.
4.1 FGD Wastewater Treatment Technologies
In promulgating the 2015 rule, the EPA identified surface impoundments as the most prevalent
treatment technology for plants discharging FGD wastewater, and chemical precipitation (i.e.,
tank-based systems designed primarily to remove suspended solids) as the second most common
treatment technology. These technologies are described in the 2015 TDD. While approximately
half of the industry discharging FGD wastewater still relies on these technologies, with the most
prevalent now being chemical precipitation, more advanced treatment technologies have become
more common since the 2015 rule. Several plants have upgraded their FGD wastewater treatment
by installing either biological or thermal treatment systems. The biological systems installed
have been either the high residence time anoxic/anaerobic biological technology—used as the
basis for the FGD BAT limitations in the 2015 rule— or a similar process that targets removal of
the same pollutants in a smaller system with a shorter hydraulic residence time in the bioreactor.
Thermal systems installed have been either a spray dryer evaporator or the falling-film
evaporator design, which was used as the basis for the NSPS limitations and the BAT Voluntary
Incentive Program in the 2015 rule. See the 2015 TDD for a description of thermal treatment
technologies and other zero discharge technologies.
The EPA also identified several additional treatment technologies that were developed (or
adapted from other industry sectors) in recent years and have been tested at some power plants.
This section provides a summary of the treatment technologies evaluated as part of this proposal.
•	Biological treatment.
•	Zero-valent iron (ZVI).
•	Membrane filtration.
•	Thermal treatment.
•	Solidification.
•	Other pilot-scale tested technologies.
4.1.1 Biological Treatment
Several types of biological treatment systems are currently used to treat FGD wastewater. These
biological technologies include:
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Section 4—Treatment Technologies and Wastewater Management Practices
•	Anoxic/anaerobic biological treatment systems, designed to remove selenium and
other pollutants.
•	Sequencing batch reactors, which alternate between aerobic and anaerobic stages
to remove nitrates and ammonia.
•	Aerobic bioreactors for reducing BOD.
These biological treatment processes are typically operated downstream of a chemical
precipitation system or a solids removal system (e.g., clarifier, surface impoundment).
The anoxic/anaerobic biological technology is designed to remove selenium, nitrate-nitrite,
mercury and other pollutants. This process uses an anoxic/anaerobic fixed-film bioreactor that
consists of an activated carbon bed or other permanent porous substrate that is inoculated with
naturally occurring, beneficial microorganisms. The microorganisms grow within the substrate,
creating a fixed film that retains the microorganisms and precipitated solids within the
bioreactor. The system uses microorganisms chosen specifically for use in FGD systems because
of their hardiness in the extreme water chemistry, as well as selenium respiration and reduction.
The microorganisms reduce the selenate and selenite to elemental selenium, which forms
nanospheres that adhere to the cell walls of the microorganisms. The microorganisms can also
reduce other metals, including arsenic, cadmium, nickel, and mercury, by forming metal sulfides
within the system (Pickett, 2006).
High Residence Time Reduction Biological Treatment
High residence time reduction (HRTR) biological treatment systems consist of chemical
precipitation followed by an anoxic/anaerobic fixed-film bioreactor. This technology was the
basis for effluent limitations established by the 2015 rule. Plants usually employ multiple
bioreactors to provide the necessary residence time to achieve the specified removals. This
technology, as it has been applied at power plants for treating FGD wastewater, uses equipment
that is large enough to provide for hydraulic residence times in the bioreactor that are typically
on the order of 10 to 16 hours.
The bioreactor is designed for plug flow to ensure that the feed water is evenly distributed and
has maximum contact with the microorganisms in the fixed film. As wastewater passes through
the bioreactor, it goes through zones operating at have differing oxidation-reduction potential
(ORP). Plants operate the bioreactors to achieve a negative ORP, which provides the optimal
environment to reduce selenium to its elemental form. The top part of the bioreactor, where the
plant feeds the wastewater, is aerobic with a positive ORP, which allows nitrification and organic
carbon oxidation to occur. As the wastewater moves down through the bioreactor, it enters an
anoxic zone (negative ORP) where denitrification and chemical reduction of selenium (both
selenate and selenite) occur (Pickett, 2006; Sonstegard, 2010).
The HRTR biological technology is described in detail in Section 7.1.3 of the 2015 TDD. The
EPA identified at least five plants that have operated this system at full-scale in the steam electric
power generating industry. One of these plants no longer operates HRTR and has installed an
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Section 4—Treatment Technologies and Wastewater Management Practices
evaporation system. A number of other plants have conducted pilot tests of this technology in
preparation for making upgrades to comply with the 2015 Rule requirements.
Low Residence Time Reduction Biological Treatment
In the years since the EPA first identified the HRTR biological technology during the
development of the 2015 rule, power companies and technology vendors have worked to develop
processes that target removals of the same pollutants in a smaller system with a lower hydraulic
residence time in the bioreactor. These technologies, described here as low residence time
reduction (LRTR) technologies, use some of the same treatment mechanisms (e.g.,
anoxic/anaerobic fixed-film bioreactors) to remove selenium, nitrate, nitrite, and other pollutants
in less time, typically on the order of 1 to 4 hours hydraulic residence in the bioreactor.
One LRTR technology includes a chemical precipitation pretreatment system followed by an
anoxic, upflow bioreactor followed by a second-stage downflow biofilter. The shorter hydraulic
residence time of this system requires smaller bioreactors and other equipment, resulting in a
treatment system that is physically much smaller than the HRTR system. Data provided by the
power industry and an independent research organization show that the LRTR system
performance is comparable to that achieved by HRTR technology. Much of the LRTR
bioreactor and related equipment is fabricated off-site as modular components. Modular,
prefabricated, skid-mounted components, coupled with the smaller physical size of the system,
results in lower installation costs and shorter installation times, relative to HRTR systems, which
are usually constructed on-site. At least four coal fired steam electric power plants have installed
full-scale LRTR systems currently being used to treat FGD wastewater and this technology has
been pilot tested using FGD wastewater at more than a dozen steam electric power plants since
2012.
Another LRTR technology, fluidized bed reactors (FBRs), has historically been used to treat
selenium in mining wastewaters; however, is now being tested on FGD wastewater. The FBR
system is also an anoxic/anaerobic fixed-film bioreactor design. It relies on an attached growth
process, in which microbial growth forms on granular activated carbon media that is fluidized by
an upflow of FGD wastewater through the suspended carbon media. The EPA identified 12 pilot
studies of the FBR technology for selenium removal in mining, refining/petrochemical, and
steam electric industries. Three of these pilot-study tests involved FGD wastewater.
4.1.2 Zero Valent Iron
ZVI, in combination with other systems such as chemical and physical treatment, can be used to
target specific inorganics, including selenium, arsenic, nitrate, and mercury in FGD wastewater.
The technology entails mixing influent wastewater with ZVI (iron in its elemental form), which
reacts with oxyanions, metal cations, and some organic molecules in wastewater. ZVI causes a
reduction reaction of these pollutants, after which the pollutants are immobilized through surface
adsorption onto iron oxide coated on the ZVI or generated from oxidation of elemental iron. The
coated, or spent, ZVI, is separated from the wastewater with a clarifier. Spent ZVI can be
disposed of in a non-hazardous landfill. The quantity of ZVI required and number of reaction
vessels can be varied based on the composition and amount of wastewater being treated.
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Section 4—Treatment Technologies and Wastewater Management Practices
Treatment configurations for FGD wastewater would typically include chemical precipitation
followed by ZVI treatment and may also include pretreatment to partially reduce influent nitrate
concentrations at plants with high nitrate levels in the FGD purge.15 The purpose of the nitrate
pretreatment is to reduce the consumption rate of the ZVI media, which reacts with both the
nitrates and selenium in the wastewater. A potential application for FGD wastewater would
employ four reactors in series. This configuration provides extra treatment capacity that allows
the operator to bypass and isolate individual units whenever maintenance is needed without
having to shut down the entire treatment system. This configuration, by including an extra ZVI
reactor in the treatment train, also provides additional polishing treatment capability that can be
appealing for some plants.
The EPA identified seven completed pilot-scale studies of ZVI used for FGD wastewater
treatment.16 At least four additional pilot-scale studies for FGD wastewater treatment at power
plants were in the planning stage for power plants located in the eastern United States, as of
2016. The data in the record from a subset of these pilots indicates that the combination of
chemical precipitation and ZVI technology, along with nitrate pretreatment, where warranted,
can produce effluent quality comparable to chemical precipitation followed by LRTR
(CP+LRTR) and chemical precipitation followed by HRTR (CP+HRTR) technologies.
4.1.3 Membrane Filtration
These systems are specifically designed to treat high TDS and TSS wastestreams, using thin
semi-permeable filters or film membranes. Membrane filtration is a treatment process used for
the removal of dissolved materials from industrial wastewater and includes microfiltration,
ultrafiltration, nanofiltration, forward osmosis, and reverse osmosis (RO) membrane systems.
The size of the particle that can pass through the membrane is determined by the membrane pore
size, with RO membranes being the most restrictive and microfiltration being the least
restrictive. Most membrane filtration systems use pumps to apply pressure to the solution from
one side of the semi-permeable membrane to force wastewater through the membrane, leaving
behind dissolved solids retained ("rejected") by the membrane and a portion of the water. The
rate that water passes through the membrane depends on the operating pressure, concentration of
dissolved materials, and temperature, as well as the permeability of the membrane.
Forward osmosis (FO) uses a semi-permeable membrane and differences in osmotic pressures to
achieve separation. These FO systems use a draw solution at a higher concentration than the
feed, (e.g., FGD wastewater) to induce a net flow of water through the membrane. This results in
15	FGD purge with nitrate/nitrite concentrations at or above 100 mg/L typically require additional denitrification
before ZVI treatment.
16	The EPA has also observed ZVI technology in treating ash transport water during impoundment dewatering. In
this application, the impoundment water was first treated by reverse osmosis membrane filtration, and the membrane
reject stream was sent to ZVI reactors for treatment. The membrane permeate and ZVI effluent streams were both
discharged by the plant to surface waters. Although this application was not treating FGD wastewater, many of the
pollutants present in FGD wastewater are also present in ash impoundments and these pollutants were effectively
removed by the ZVI process (ERG, 2019). A similar treatment process has been suggested for FGD wastewater,
whereby the treatment train would be configured as chemical precipitation followed by reverse osmosis membrane
filtration, and the membrane reject stream would be sent to a ZVI stage consisting of three reactors in series. Similar
to the treatment system for the impoundment, the RO permeate and ZVI effluent would be discharged (unless the
RO permeate was reused within the plant).
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Section 4—Treatment Technologies and Wastewater Management Practices
diluting the draw solution and concentrating the feed stream. This technology is different from
RO, which utilizes hydraulic pressure to drive separation. FO technology is typically better
suited for high-fouling streams than traditional RO because external pumps are not needed to
drive treatment.
Membrane systems separate feed wastewater into two product streams: a permeate stream, which
is the "clean" water that has passed through the membrane, and the concentrate stream, which is
the water (or brine) rejected by the membrane. The percentage of membrane system feed that
emerges from the system as permeate is known as the water recovery. Depending on wastewater
characteristics, membrane systems may require pretreatment to remove excess TSS and organics
to prevent scaling and fouling in industrial applications. Fouling occurs when either dissolved or
suspended solids deposit onto a membrane surface or a microbial biofilm grows on the
membrane surface and degrades its overall performance.
As part of the reconsideration of the 2015 rule, the Agency identified and further reviewed
several new uses of membrane filtration technologies currently being studied in the industry.
Depending on the FGD wastewater characteristics, these membrane systems typically include
nanofiltration membranes, RO, or FO. To reduce fouling, membrane filtration systems have been
designed with vortex generating blades or vibratory movement. Other technologies focus on a
microfiltration pretreatment step that targets scale-forming ions where FGD wastewater
characteristics indicate potential fouling.
Incorporating membranes into existing chemical precipitation systems can improve the
efficiency of the membrane system and may help lower the capital and operation and
maintenance costs. Many of the systems piloted for FGD wastewater to date have included some
type of pretreatment to reduce TSS before entering the membrane system (e.g., surface
impoundment, chemical precipitation). Membrane systems can also be configured with a post-
processing RO system to further remove pollutants from the permeate. Additionally, membrane
systems can be used in combination with other technologies (e.g., thermal evaporation) to treat
FGD wastewater or achieve zero discharge.
Permeate streams from these systems can be reused within the plant or discharged, while reject
streams (i.e., concentrated brine) would be disposed of in a landfill using solidification (See
Section 4.1.5) or another process, such as thermal system treatment.
Membrane filtration has been piloted for FGD wastewater treatment at some plants in the steam
electric power generating industry. The EPA spoke with several vendors that have tested the
technology in the past and are actively pursuing additional testing. The EPA also identified three
plants in China that have installed membrane filtration systems to treat FGD wastewater. Two of
the plants employ pretreatment and a combination of RO and forward osmosis. The EPA does
not have information on how the brine is handled at these two plants. The third plant operates
pretreatment followed by nanofiltration and RO. At this plant, the brine undergoes thermal
treatment to produce a crystallized salt which is sold for industrial use.
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Section 4—Treatment Technologies and Wastewater Management Practices
4.1.4 Thermal Treatment
Thermal technologies include a variety of treatment technologies that use heat to evaporate water
and concentrate solids and other contaminants. Some of these systems can be operated to achieve
full evaporation of all liquid, resulting in only a solid product, or achieve partial evaporation of
liquid. These thermal technologies can also be used in combination with other technologies to
treat FGD wastewater or achieve zero discharge.
One type of thermal treatment uses brine concentrators followed by crystallizers, which
generates a distillate stream and solid by-product that can be disposed of in a landfill. This
treatment configuration was evaluated as part of the 2015 rule, see Section 7.1.4 of the 2015
TDD for a detailed description of this treatment configuration. As part of this proposed rule, the
EPA identified several additional thermal technologies that rely on this same premise, i.e., using
heat to evaporate water and concentrate contaminants.
Spray dryers are an example of a technology that is being applied to FGD wastewater treatment.
These systems utilize a hot gas stream to quickly evaporate liquid resulting in a dry solid or
powder. For FGD applications, a slipstream of hot flue gas from upstream of the air heater can
be used to evaporate FGD wastewater in a vessel. The FGD solids are carried along with the flue
gas slipstream which is recombined with the main flue gas stream. All solids are then removed
with the fly ash in the main particulate control equipment (e.g., electrostatic precipitator or fabric
filter) and disposed of in a landfill. In cases where fly ash is marketable, and contamination is a
concern, a separate particulate control system can be operated on the flue gas slipstream to
capture FGD solids alone. While these spray dryer systems can be an efficient treatment of FGD
wastewater, retrofitting these systems into existing plants could be difficult.
One vendor has developed a proprietary technology that combines concepts of the brine
concentrator and spray dryer to achieve zero discharge without a crystallizer. The system,
referred to as an adiabatic evaporator technology, injects wastewater into a hot feed gas stream to
form water vapor and concentrated wastewater. The air-water mixture is separated in an
entrainment separator. Water vapor is exhausted, and wastewater is sent to a solid-liquid
separator. The concentrated wastewater is recycled and sent back through the system while the
solids can be landfilled. An alternative configuration would be to not recycle the concentrated
wastewater and instead reject it from the system. This reject stream could be solidified, by
mixing with fly ash, and landfilled. Pretreatment of FGD wastewater is not required but, for
situations where TSS exceeds 5 percent it maybe be cost-effective to operate a clarifier upstream
of the evaporator to decrease solids. This system was operated at full-scale at a coal-fired power
plant for three years. FGD wastewater was pretreated using a clarifier then sent to the adiabatic
evaporator where 100 percent of the FGD wastewater was evaporated and solids deposited in a
landfill. Because propane was used as the heat source, operation and maintenance costs proved to
be too costly and the system was replaced.
Another vendor has developed a modular brine concentration technology. This system uses
thermal energy to heat FGD wastewater and facilitate evaporation. As the wastewater boils,
steam is collected, compressed, and directed into proprietary technology that allows the heat to
transfer from the steam to the concentrated wastewater stream; causing it to become superheated.
As water evaporates from the superheated wastewater, the steam is collected and condensed.
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Section 4—Treatment Technologies and Wastewater Management Practices
This distillate stream can be reused in the plant as cooling tower make up or within the FGD
scrubber. The concentrated wastewater, referred to as brine, is discharged from the system once
it reaches a set TDS concentration (not to exceed 200,000 parts per million (ppm)). This brine
stream is treated through hydrocyclones to remove suspended solids. The resulting liquid can be
solidified and landfilled. Pretreatment of FGD wastewater is only required when TSS
concentrations exceed 30 ppm. Chemicals are added to maintain pH and inhibit crystal and scale
formation. This technology has been pilot tested at four coal-fired power plants in 2015 and
2017.
4.1.5	Solidification
Solidification is a technology option that may prevent FGD wastewater discharge. Solidification
is process by which temperature and chemical reactions are used to bond materials together. This
process can also be referred to as fixation. This technology has been used by plants operating
inhibited oxidation scrubber systems, where byproducts from the scrubber are mixed with fly ash
and lime to produce a non-hazardous landfillable material. This same approach is being tested
with pretreated FGD wastewater by mixing concentrated FGD wastewater, from membrane
systems or thermal systems that only achieve partial evaporation. The concentrated FGD
wastewater is mixed with various combinations of fly ash, hydrated lime, sand, and/or Portland
cement to encapsulate contaminants. Tests of these materials have confirmed that the solids
generated meet solid waste leaching requirements (toxicity characteristic leaching procedure
(TCLP), and other local landfill regulations (Pastore and Martin, 2017; Martin, 2019).
4.1.6	Other Technologies Under Investigation
The EPA also identified several emerging technologies for FGD wastewater treatment. The EPA
reviewed EPRI reports, industry sources, and published research articles describing alternative
FGD wastewater treatment technologies being evaluated to date and identified several that are in
the early stages of development. While the technologies described in this section have not been
implemented at full-scale levels in the steam electric power generating industry to date, these
technologies have been evaluated in pilot-scale testing for FGD wastewater at power plants.
Electrodialysis Reversal and Reverse Osmosis Technology
Electrodialysis reversal (EDR) is a technology that uses an electric current to migrate dissolved
ions through stacks of alternating cationic and anionic ion exchange membranes. While this
process is typically used to desalinate water, it is now being used to treat FGD wastewater in
pilot-scale tests. The EDR technology results in three wastestreams, one permeate stream and
two wastestreams. The permeate stream can be further treated with a RO system to remove
additional metals and conventional pollutants. Reject from the RO is recycled through the EDR
process while the RO permeate can be reused as cooling tower make up or within the FGD
scrubber. The two wastestreams, one a calcium chloride rich brine stream and one a sodium
sulfate rich brine stream, can be recombined to produce gypsum (CaS04), solidified, or treated
using a crystallizer. This system has been bench-scale tested using FGD wastewater and pilot-
scale tested at least once, in 2017.
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Closed-Loop Mechanical Vapor Recompression
Mechanical vapor compression is a technology that can be used to treat FGD wastewater, as well
as other wastestreams, and was evaluated as a technology option under the 2015 rule. A vendor
has come up with a proprietary application of this technology that operates as a closed-loop
system. The system uses four interconnecting loops to pre-heat process wastewater, concentrate
and crystalize wastewater using turbulent flow heat exchangers, and recover and condense steam
to produce a clean distillate stream. This technology is currently used in full-scale operations in
metal working and manufacturing applications. EPRI and the technology vendor operated a pilot
test of the system to treat FGD wastewater from power plants at the Plant Bowen Water
Research Center in 2015 (EPRI, 2015).
Distillation-Based Thermal Transfer System
One vendor has developed a proprietary combination of technologies that operate as one
thermally-balanced system to treat industrial wastewater streams. This technology combines
degassing, distillation, and demisting to heat industrial wastewater streams, generating a clean
water stream and gray water or brine stream. The gray water or brine stream is a concentrated
wastewater stream that either flash crystallizes upon discharge or crystallizes upon cooling,
resulting in zero liquid discharge. Energy required to drive degassing and distillation can come
from steam, natural gas, flue gas, waste heat, or other renewable sources such as solar or
geothermal, depending on availability. The vendor has conducted bench scale testing using FGD
wastewater and is currently pursuing pilot testing opportunities with industry trade groups and
individual plants. This technology has also been tested on produced water from the oil and gas
industry and cooling tower blowdown.
4.2 Bottom Ash Handling Systems and Transport Water Management and
Treatment Technologies
As part of this reconsideration, the EPA reviewed bottom ash handling systems designed to
minimize or eliminate the discharge of bottom ash transport water that are operated by coal-fired
power plants or marketed by bottom ash handling vendors. As part of the 2015 rule, the EPA
determined that almost 60 percent of the coal-fired power plants in the industry operate wet-
sluicing systems on one or more of their coal-fired generating units. As described in Section 3,
many plants have installed, or are installing, bottom ash handling systems that minimize or
eliminate the discharge of bottom ash transport water. Specifically, the EPA now estimates that
just 22 percent of coal-fired power plants in the industry operate wet sluicing systems (see the
2015 TDD for more details on wet sluicing systems). The bottom ash handling technologies
evaluated by the EPA are listed below
•	Mechanical Drag System.
•	Remote Mechanical Drag System.
•	Dry Mechanical Conveyor.
•	Dry Vacuum or Pressure System.
•	Submerged Grinder Conveyor.
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Section 4—Treatment Technologies and Wastewater Management Practices
4.2.1	Mechanical Drag System
A mechanical drag system collects bottom ash from the bottom of the boiler through a transition
chute and sends it into a water-filled trough. The water bath in the trough quenches the hot
bottom ash as it falls from the boiler and seals the boiler gases. The drag system uses a parallel
pair of chains attached with crossbars at regular intervals. In a continuous loop, the chains move
along the bottom of the water bath, dragging the bottom ash toward the far end of the bath, then
begin moving up an incline, dewatering the bottom ash by gravity and draining the water back to
the trough. Because the bottom ash falls directly into the water bath from the bottom of the boiler
and the drag chain moves constantly on a loop, bottom ash removal is continuous. The dewatered
bottom ash 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.
See Section 7.3.3 of the 2015 TDD for more specific system details.
The mechanical drag system does generate some wastewater (i.e., residual water that collects in
the storage area as the bottom ash continues to dewater). This wastewater is either recycled back
to the quench water bath or directed to the low volume waste system. This wastewater is not
bottom ash transport water because the transport mechanism is the drag chain, not the water.17
This system may not be suitable for all boiler configurations and may be difficult to install in
situations where there is limited space below the boiler. These systems are not able to combine
and collect bottom ash from multiple boilers and most installations require a straight exit from
the boiler to the outside of the building. In addition, these systems may be susceptible to
maintenance outages due to bottom ash fragments falling directly onto the drag chain.
4.2.2	Remote Mechanical Drag System
Remote mechanical drag systems collect bottom ash using the same operations and equipment as
wet-sluicing systems at the bottom of the boiler. However, instead of sluicing the bottom ash
directly to an impoundment, the plant pumps the bottom ash transport water to a remote
mechanical drag system. This type of system has the same configuration as a mechanical drag
system, but with additional dewatering equipment in the trough. Also, it does not operate under
the boiler, but rather in an open space on the plant property. See Section 7.3.4 in the 2015 TDD
for more specific system design details.
Plants converting their current bottom ash handling systems can use this system if space or other
restrictions limit the changes that can be made to the bottom of the boiler. Currently, over 50
coal-fired power plants have installed, or are planning to install, remote mechanical drag systems
to handle bottom ash.
Because of the chemical properties of bottom ash transport water, some plants may have to treat
the overflow (or a slipstream of the overflow) before recycling, to prevent scaling and fouling in
the system. Plants that require treatment to achieve complete recycling of bottom ash transport
17 The mechanical drag system does not need to operate as a closed-loop system because it does not use water as the
transport mechanism to remove the bottom ash from the boiler; the conveyor is the transport mechanism. Therefore,
any water leaving with the bottom ash does not fall under the definition of "bottom ash transport water," but rather,
is a low volume waste.
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Section 4—Treatment Technologies and Wastewater Management Practices
water could install a pH adjustment system or an RO membrane (as described in EPA's cost
methodology in Section 5).
Similar to the mechanical drag system, the drag chain conveys the ash to a collection area and
the plant then sells or disposes of it in a landfill. There is also an opportunity for multiple unit
synergies and redundancy with remote mechanical drag systems because they are not operating
directly underneath the boiler. This system requires less maintenance compared to the
mechanical drag system because the bottom ash particles entering the system have already been
through the grinder prior to sluicing.
4.2.3	Dry Mechanical Conveyor
Dry mechanical conveyor systems operate similarly to a mechanical drag system, but instead of
collecting the bottom ash in a water bath, it is collected directly onto a dry conveyor. The system
introduces ambient air countercurrent to the direction of the bottom ash using the negative
pressure in the furnace. Adding more air activates reburning, which reduces unburned carbon
and adds thermal energy to the steam electric power generating process in the boiler, making the
boiler more efficient. The dry conveyor then takes the bottom ash to an intermediate storage
destination. The modular design of the system allows it to be retrofitted into plants with space or
headroom limitations and a wide range of steam electric generating unit capacities (from 5 MW
to 1,000 MW). See Section 7.3.5 of the 2015 TDD for more details.
4.2.4	Dry Vacuum or Pressure System
Dry vacuum or pressure bottom ash handling systems transport bottom ash from the bottom of
the boiler into a dry hopper, without using any water. The system percolates air into the hopper
to cool the ash, combust additional unburned carbon, and increase the heat recovery to the boiler.
Periodically, the grid doors at the bottom of the hopper open to allow the bottom ash to pass into
a crusher. The system then conveys the crushed bottom ash by vacuum or pressure to an
intermediate storage location. See Section 7.3.6 of the 2015 TDD for more details.
Dry vacuum or pressure systems eliminate water requirements and improve heat recovery and
boiler efficiency. These systems are also less complicated to retrofit because there are fewer
structural limitations (e.g., headspace requirements below the boiler) and the systems can be
installed to collect bottom ash from multiple boilers and send it to one intermediate storage
location.
4.2.5	Submerged Grind Conveyor
Submerged grind conveyors collect bottom ash from the bottom of the boiler. The system uses
existing equipment—bottom ash hoppers or slag tanks, the bottom ash gate, clinker grinders, and
a transfer enclosure—to remove bottom ash from the hopper continuously. From the bottom of
the boiler, bottom ash falls into the water impounded hopper or slag tank. It is then directed to
the existing grinders to be ground into smaller pieces and is then transferred to a water-tight
chain and flight conveyor system. Similar to a mechanical drag system, except for the water-tight
design, a drag chain continuously carries and dewaters bottom ash up an incline, away from the
boiler. The dewatered bottom ash is transferred to a second conveyor, which transports it to a
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bottom ash silo. The system can be designed to avoid existing structures or with equipment to
transfer the bottom ash out of the boiler house.
Using the existing transfer enclosures, the systems can be isolated from the hopper to perform
maintenance while the generating unit remains on-line (made possible by the bottom ash storage
capacity of the hopper). The system also has low auxiliary power requirements and maintenance
costs due to the mechanical transfer conveyor design. In addition, because the system reuses the
wet sluicing equipment, installation and outage times are shorter compared to other under-the-
boiler bottom ash handling systems.
The EPA is aware of two plants that have installed and are operating this type of bottom ash
handling system in the United States.
4.3 References
1.	EPRI, 2015. Electric Power Research Institute. Evaluation of Vacom One-Step
System for Concentrating Flue Gas Desulfurization Wastewater: Pilot Testing at the
Water Research Center. 3002007212. Palo Alto, CA. (December). DCN SE06961.
2.	ERG, 2019. Eastern Research Group, Inc. Sutton Site Visit Notes. (7 June). DCN
SE07139.
3.	Martin, 2019. Concrete Solidification Report. (March) DCN SE07368.
4.	Pastore and Martin, 2017. Advanced Micro Filtration and Reverse Osmosis for ELG
Compliance and ZLD. (November) DCN SE07369.
5.	Pickett, Tim et al. 2006. "Using Biology to Treat Selenium." Power Engineering.
(November). Available online at:
http://pepei.pennnet.com/display _article/278443/6/ARTCL/none/none/Using-
Biology-to-Treat-Selenium/. Date accessed: May 16, 2008. DCN SE02926.
6.	Sonstegard, Jill et al. 2010. ABMet®: Setting the Standard for Selenium Removal.
(January). DCN SE02040.
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Section 5—Engineering Costs
SECTION 5
ENGINEERING COSTS
This section presents EPA's methodology for estimating capital costs and operation and
maintenance (O&M) costs for steam electric power plants to comply with regulatory options
being considered for discharges of flue gas desulfurization (FGD) wastewater and bottom ash
transport water. The BAT/PSES regulatory options described in the preamble comprise various
combinations of treatment technologies evaluated for controlling pollutants in each of the
wastestreams. The regulations promulgated by the 2015 rule remain codified in 40 CFR Part
423; the costs associated with the regulatory options for this proposed rulemaking are the
incremental changes in costs (additional costs or cost savings) relative to the costs for plants to
meet the requirements of the 2015 rule. As such, the EPA is presenting cost estimates for
baseline and post-compliance, defined as follows:
•	Baseline Compliance Costs. The costs for plants to comply with the 2015 rule
requirements for FGD wastewater and bottom ash transport water, relative to the
conditions currently present or planned at each plant. For those plants where
upgrades would be needed to meet the requirements established by the 2015 rule,
the EPA estimated baseline costs of installing the technologies selected as the
BAT/PSES basis of that rule (i.e., chemical precipitation followed by high
residence time reduction (CP+HRTR) for FGD wastewater; dry or closed-loop
handling for bottom ash).
•	Post-Compliance Costs. These are the costs for plants to comply with effluent
limitations based on the technologies considered in this proposed rule for FGD
wastewater and bottom ash transport water, relative to the conditions currently
present or planned at each plant. For those plants where upgrades would be
needed, the EPA estimated post-compliance costs based on plants installing the
technologies that would be the basis for BAT/PSES (e.g., chemical precipitation
followed by low residence time reduction (CP+LRTR) for FGD wastewater; High
Recycle Rate for bottom ash transport water).
•	Incremental Costs. The incremental costs are the difference between the baseline
compliance costs and post-compliance costs for each regulatory option. Since the
2015 rule is currently codified in the Code of Federal Regulations, the
incremental costs reflect the cost savings (or increases) estimated to result from
modifying the requirements established by the 2015 rule.
Section 5.1 describes the general methodology for estimating incremental compliance costs.
Sections 5.2 and 5.3 describe the methodologies the EPA used to estimate costs to achieve the
proposed limitations and standards based on the technology options selected. These sections also
present information on the specific cost elements included in EPA's methodology. Finally,
Section 5.4 summarizes national engineering costs associated with the considered regulatory
options.
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Section 5—Engineering Costs
5.1 General Methodology for Estimating Incremental Compliance Costs
For FGD wastewater and bottom ash transport water, the EPA assessed the operational practices
and treatment system components in place at each plant, identified equipment and process
changes that each plant would likely make to meet the proposed effluent limitations guidelines
and standards (ELGs), and estimated the incremental cost or savings to meet each of the
regulatory options considered for the proposed rule, relative to the costs to comply with the 2015
rule.
While plants are not required to implement the specific technologies that form the basis for the
options considered for the proposed rule, the EPA based its calculations on plants implementing
these technologies to estimate incremental compliance costs incurred by the industry. The EPA
summed plant-specific costs to represent industry-wide compliance costs for each regulatory
option considered for the proposed rule.
The EPA estimated compliance costs associated with each regulatory option from data collected
through responses to the Questionnaire for the Steam Electric Power Generating Effluent
Guidelines (hereinafter Steam Electric Survey), site visits, sampling episodes, and from
individual power plants and equipment vendors. Data sources include the data used during the
development of the 2015 rule, as well as additional cost information collected from industry and
technology vendors (see Section 2).
The EPA's cost estimates include the following components:
•	Capital costs (one-time costs).
•	Annual O&M costs (which are incurred every year).
•	Other one-time or recurring costs.
Capital costs comprise the direct and indirect costs associated with purchasing, delivering, and
installing pollution control technologies. Capital cost elements are specific to the industry and
commonly include purchased equipment and freight, equipment installation, buildings, site
preparation, engineering costs, construction expenses, contractor's fees, and contingencies.
Annual O&M costs comprise all costs related to operating and maintaining the pollution control
technologies for a period of one year. O&M costs are also specific to the industry and commonly
include costs associated with operating labor, maintenance labor, maintenance materials (routine
replacement of equipment due to wear and tear), chemical purchases, energy requirements,
residuals disposal, and compliance monitoring. In some cases, the technology options may also
result in costs that recur less frequently than annually (e.g., three-year recurring costs for
equipment replacement) or one-time costs other than capital investment (e.g., one-time
engineering costs).
For the analysis of these technology capital costs on an annualized basis, or when performing
other cost and impact analyses that account for the service life of the installed equipment (e.g.,
electricity rate impact analysis), the number of years reflect the reasonably expected service life
of the equipment. The EPA based its estimate of service life of equipment that may be installed
for FGD wastewater or bottom ash transport water on a review of reported performance
characteristics of compliance technology components. From this review, the EPA concluded that
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Section 5—Engineering Costs
the equipment could reasonably be expected to operate for 20 years or more, and thus further
concluded that 20 years is an appropriate basis for cost and economic impact analyses that
account for the estimated operating life of compliance technology. See the Regulatory Impact
Analysis for Proposed Revisions to the Effluent Limitations Guidelines and Standards for the
Steam Electric Power Generating Point Source Category for more information on the EPA's
economic impact analyses (U.S. EPA, 2019).
5.2 FGD Wastewater
The EPA estimated costs for plants discharging FGD wastewater to install and operate the
following technologies: chemical precipitation, CP+LRTR, CP+HRTR, membrane filtration, and
thermal treatment.18 The EPA also estimated the cost savings associated with plants ceasing
operation of impoundments currently used to treat FGD wastewater.
For chemical precipitation (Section 5.2.2), the EPA included costs for the plants to install and
operate the following:
•	Treatment equipment (equalization and storage tanks, pumps, reaction tanks,
solids-contact clarifier, and gravity sand filter).
•	Chemical feed systems for lime, organosulfide, ferric chloride, and polymers.
•	Solids-contact clarifier to remove suspended solids.
•	Pollutant monitoring and analysis.
•	Solids handling (sludge holding tank and filter press).
•	Transportation and disposal of solids in a landfill.
For CP+LRTR (Section 5.2.3), the EPA included all the costs described above for the chemical
precipitation system and included costs for the following:
•	Treatment equipment (anoxic/anaerobic bioreactor, flow control, backwash
supply, storage tanks).
•	Chemical feed system for nutrients.
•	Pretreatment system (for plants with nitrate/nitrite concentrations greater than 50
parts per million (ppm)).
•	Heat exchanger.
•	Ultrafilter.
•	Pollutant monitoring and analysis.
•	Transportation and disposal of solids in a landfill.
18 The EPA estimated compliance costs for thermal treatment; however, the EPA did not use that estimate as a basis
for an FGD technology option for the proposed rule. See the "Thermal Evaporation Cost Methodology
Memorandum" for more information (ERG, 2018).
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Section 5—Engineering Costs
For CP+HRTR (Section 5.2.4), the same technology basis as the 2015 rule BAT, the EPA
included all the costs described above for the chemical precipitation system, and included costs
for the following:
•	Treatment equipment (anoxic/anaerobic biological treatment system, storage
tanks, and backwash system).
•	Chemical feed system for nutrients.
•	Pretreatment system (for plants with nitrate/nitrite concentrations greater than 100
ppm).
•	Heat exchanger (for plants in certain geographic locations).
•	Pollutant monitoring and analysis.
•	Transportation and disposal of solids in a landfill.
For membrane filtration (Section 5.2.5), the EPA included costs for the plants to install and
operate the following:
•	Treatment equipment (membrane filtration, reverse osmosis, and storage tanks).
•	Pretreatment system (microfiltration skid).
•	Concentrate management (brine mixing skid for solidification).
•	Transportation and disposal of solids in a landfill.
Section 5.2.1 describes the cost inputs and the process for updating the FGD wastewater flow
rates from the 2015 rule, Section 5.2.2 through Section 5.2.5 describe the cost methodologies for
each of the technology options, and Section 5.2.6 describes the impoundment operation cost
savings methodology.
5.2.1	FGD Cost Calculation Inputs
To calculate plant-level engineering costs associated with implementing FGD wastewater
treatment technologies, the EPA developed a cost calculation database containing a set of input
values and a set of equations that define relationships between costs and FGD wastewater flow
rates (ERG, 2019a). To establish the input values, the EPA compiled plant-specific details on
FGD wastewater flow rates and discharge destinations, existing FGD wastewater treatment
details, and use of on-site and off-site landfills by steam electric power plants operating wet FGD
systems. As part of the 2015 rule, the EPA developed a similar set of input information from the
Steam Electric Survey data, site visits, sampling episodes, and other industry-provided data to
calculate compliance costs. For this proposed rule, the EPA updated the input values using
additional information gathered from industry and available from the Department of Energy (see
Section 2). The EPA developed a list of generating units expected to incur FGD wastewater
treatment compliance costs by identifying plants that operate wet FGD systems, taking into
account changes made to their FGD treatment system, and generating units that, since the 2015
rule, have retired or converted to a fuel other than coal. The EPA also identified generating units
that have announced plans to retire or convert their fuel source before December 31, 2028. This
section describes the updates to cost inputs from the 2015 rule.
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Section 5—Engineering Costs
The EPA modified the overall cost methodology to account for two FGD wastewater flow rates
for each plant discharging FGD wastewater: (1) the FGD purge flow rate and (2) the optimized
FGD flow rate. The FGD purge flow rate is the typical amount of wastewater from the FGD
scrubber that is sent to FGD wastewater treatment. The optimized FGD flow is a reduced FGD
wastewater flow that takes into account a reduction in FGD wastewater purged from the system,
where equipment metallurgy could accommodate increased chloride concentration in the FGD
system. The EPA used the FGD purge flow rate (i.e., the pre-optimized flow rate) to calculate
capital costs and the optimized FGD flow rate to estimate O&M costs, recognizing that well-
operated plants would take steps to optimize the volume of water to be treated and normalize the
flow where possible.
FGD Purge Flow Rate
For plants where there were no retirements or fuel conversions of wet-scrubbed generating units,
the EPA calculated the non-optimized FGD purge flow rates using the same methodology that
was used for the 2015 rule (ERG, 2019b). For those plants where one or more wet-scrubbed
generating units have been retired or converted to a non-coal fuel source (or have plans to do so
by 2028), the EPA updated FGD purge flow rates, taking into account that FGD wastewater
would no longer be produced by the retired/converted generating units.
The EPA used NPDES permit data to calculate FGD purge flow rates for new wet FGD systems
that began operation since the 2015 rule. For plants whose permits were not available or did not
specify a flow rate, the EPA estimated FGD purge flows using the amount of coal burned in a
year and a factor for the median FGD flow rate per ton of coal burned per year. The EPA used
data from Form EIA-923 to determine the type and amount of coal burned by each scrubbed unit
and calculated the unit-level FGD purge flows using Equation 5-1.
Unit-Level FGD Purge Flow (GPD) = Coal Burned x Median Flow per Ton of Coal
Equation 5-1
Where:
Coal Burned	= The reported coal burned by the steam electric
generating units serviced by a wet FGD system (in tons
per year). Data from 2016 Form EIA-923.
The calculated median FGD wastewater flow rate per
ton of coal burned, by the type of coal burned at the
generating unit: 0.1454 for bituminous, 0.0392 for
subbituminous, 0.2313 for lignite, and 0.1017 for any
coal blend (in GPD/ton/year). Values were developed
using data collected from the Steam Electric Survey
(ERG, 2019b).
The EPA summed the unit-level FGD purge flow rates to estimate plant-level FGD purge flow
rates for new steam electric power plants and new wet FGD systems.
Median Flow per Ton of
Coal
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Section 5—Engineering Costs
The EPA used the FGD purge flow rates to calculate capital costs, which may overestimate the
size and cost of the treatment system that plants would actually install; however, the EPA chose
to use this flow rate for capital costs to ensure that installed treatment technologies would be able
to accommodate the maximum possible FGD purge flow.
Optimized FGD Flow Rate
The EPA's cost analyses for the 2015 rule took into account that certain higher-flow plants
would find it beneficial to take steps to optimize FGD purge flow as a way to reduce the size and
associated cost of the FGD wastewater treatment system. During the 2015 rulemaking, the EPA
recognized that flow optimization was a viable approach for plants of all sizes; however, at that
time, the EPA accounted for such actions only for those plants with FGD purge flows greater
than 1 million gallons per day (MGD) and where equipment metallurgy could accommodate the
resulting increased chloride concentration in the FGD system. Since the 2015 rule, site visits,
meetings with industry representatives, and other information EPA has confirmed that flow
optimization is a realistic step that plants can take to reduce compliance costs. Many plants,
including those with FGD purge flow rates well below 1 MGD, anticipate implementing flow
optimization approaches as they upgrade their FGD wastewater treatment. Because of this,
EPA's cost analyses for this proposed rule incorporate flow optimization for all wet-scrubbed
plants where FGD system metallurgy can accommodate it.
In the cost analyses, the EPA adjusted the FGD purge flow described above by the flow
optimization algorithm to determine the plant-level optimized FGD flow rate. For these
optimized FGD flow rates, the EPA concluded that plants would optimize the FGD flow through
the treatment system by either throttling down the purge flow or recycling a portion of the purge
stream back to the FGD system. One effect of this reduced discharge flow is that chloride
concentrations will increase somewhat (the mass of chlorides discharged would remain
unchanged while the volume of water decreases; thus, the lower flow rate will contain a higher
concentration of chlorides). The EPA used the Steam Electric Survey data to determine plant-
specific FGD system constraints for maximum design chloride concentrations and operating
chloride concentrations. Consistent with the flow minimization methodology used for the 2015
rule, the EPA identified individual plants as having the potential to optimize FGD purge flow if
the operating chloride concentration is lower than 80 percent of the maximum design
concentration. If the operating chloride concentration is not lower than 80 percent of the
maximum design concentration, the EPA assumed that further flow optimization was not
practical and the resulting optimized FGD flow rate is equal to the FGD purge flow. The EPA
calculated the degree of flow optimization using Equation 5-2; this represents the percent by
which the FGD purge can easily be reduced without threatening the metallurgical integrity of the
FGD system.
Plant-Specific Degree of Flow Optimization = (Design Max CI Level x 0.8
- Operating CI Level) / (0.8 x Design CI Level)
Equation 5-2
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Section 5—Engineering Costs
Where:
Design Max CI Level
Design maximum chlorides concentration as reported
in Part B, Section 4 of the Steam Electric Survey (B4-
3), or a design concentration specified in comments
during the rulemaking for the 2015 rule (in ppm).
Operating CI Level
Chlorides concentration in the FGD scrubber purge as
reported in Part B, Section 5 of the Steam Electric
Survey (B5-3) (in ppm). Where data were not
available in Part B, Section 5, the maximum operating
chloride concentration from Part B, Section 4 of the
Steam Electric Survey (B4-2) was used.
The EPA limited the degree of flow optimization for each plant so that the resulting operating
chloride level would not exceed 30,000 ppm or 80 percent of the plant-specific design maximum
chloride level, whichever is lower.19
For any existing plant that did not have sufficient information in the Steam Electric Survey to
calculate a plant-specific degree of flow optimization, or where data were available but
considered confidential business information (CBI), the median plant-specific degree of flow
optimization was used, 0.375.20 the EPA calculated optimized FGD flows using the plant-
specific degree of flow optimization in Equation 5-3.
Optimized FGD Flow (GPD) = FGD Purge Flow x (1 - Plant-Specific Degree of Flow
Optimization)
19	Data in the record shows that biological treatment systems operate without impairment at chloride concentrations
well above 30,000 ppm and TDS concentrations well over 100,000 ppm. Nevertheless, recognizing that power
companies have expressed preference to operate such systems at moderate chloride levels, EPA's cost analyses are
based on operating the FGD system so that chloride concentrations in the FGD purge do not routinely exceed 30,000
ppm.
20	The EPA calculated the median plant-specific degree of flow optimization using the 2015 rule FGD population.
Equation 5-3
Where:
FGD Purge Flow
For FGD systems included in 2015 rule population,
plant-level FGD purge flow updated for retirements
and refuels; for new FGD systems, plant-level FGD
purge flow (sum of unit-level flows, calculated using
Equation 5-1) in GPD.
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Section 5—Engineering Costs
Plant-Specific Degree of = The smallest system-level degree of flow optimization
Flow Optimization	for each plant (calculated using Equation 5-2 or the
median plant-specific degree of flow reduction,
0.375).
All new FGD systems identified since the 2015 rule were not adjusted to reflect any degree of
flow optimization; instead, because they are expected to be operating as designed, the EPA set
the optimized FGD flow equal to the FGD purge flow.
To estimate O&M costs, the EPA used optimized FGD flow rates, recognizing that well-operated
plants would take steps to optimize the volume of water to be treated and normalize the flow
where possible, which will allow for more realistic annual cost estimates. Implementing flow
optimization is the more cost-effective approach for operating the treatment systems, and also
has commensurate benefits such as enhanced worker safety since smaller volumes of treatment
chemicals will require reduced handling by the operators.
FGD Treatment-In-Place Data
The EPA identified data on each plant's current level of treatment for its FGD wastewater
(ERG, 2019c). For plants that are already treating the FGD wastewater using some form of
chemical precipitation, biological treatment, or evaporation treatment, the EPA identified which
specific treatment system components would still be needed to comply with the proposed rule
and based estimates of the compliance costs on the specific equipment upgrades. The cost
methodologies in Section 5.2.2 through Section 5.2.5 discuss treatment-in-place considerations
for the different technology options evaluated for the proposed rule.
Landfill Data
Like the 2015 rule, the EPA used data from the Steam Electric Survey and other public sources
to identify which plants operate on-site active/inactive landfills containing FGD solids. Plants
without an on-site active/inactive landfill with combustion residuals were identified as off-site
landfills. The EPA anticipates plants with on-site inactive landfills will resume disposal of FGD
solids to the landfill if needed for implementation of an FGD technology option.
Final CCR Decision Data
As discussed in Section 3.3, the EPA applied the same methodology used in the 2015 rule to
update the FGD population for changes in plant operations as a result of the CCR rule. The CCR
rule sets requirements for managing impoundments and landfills containing CCRs. Based on the
CCR requirements, the EPA expects that some plants will alter how they operate their current
CCR impoundments, including by undertaking the following potential changes:
5-8

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Section 5—Engineering Costs
•	Close the disposal surface impoundment21 and open a new composite-lined
disposal surface impoundment in its place.
•	Convert the disposal surface impoundment to a new composite-lined storage
impoundment.22
•	Close the disposal surface impoundment and convert to dry handling operations.
•	Make no changes to the operation of the disposal surface impoundment.
Consistent with the 2015 methodology, described in Section 9.4.1 of the 2015 TDD, the EPA
developed a methodology to use the output analysis of the CCR rule to predict which of the four
potential operational changes would likely occur at each coal-fired power plant that operates
FGD disposal impoundments under the CCR rule, see Table 5-1.
Table 5-1. ELG FGD Baseline Changes Accounting for CCR Rule
CCU Rule
Decision
Adjustment Hi I I C.
liiisolino
r.lTecl on l-'.I.Ci Cosls
l-'.ITecl on l-'.I.Ci l.oiidiniis
New disposal
impoundment
No changes
No changes
No changes
New storage
impoundment
No changes
No changes
No changes
Convert to dry
handling
Plant has a BAT chemical
precipitation system in
place
Plant incurs the following costs:
Mercury analyzer
Compliance monitoring
All biological treatment system
costs (including
transportation/disposal)
Baseline loadings are
based on chemical
precipitation treatment in
place
No decision
No changes
No changes
No changes
a - Changes described are compared to the costs and loads that would have been calculated if the EPA was not
accounting for the CCR rule.
5.2.2 Cost Methodology for Chemical Precipitation
The design basis used to estimate costs for chemical precipitation treatment systems is consistent
with the 2015 rule and includes the following process steps:
•	Flow equalization.
•	Hydroxide precipitation, sulfide precipitation and iron coprecipitation using lime,
organosulfide, and ferric chloride chemical addition in separate reaction tanks.
21	For the CCR rule, a disposal surface impoundment is generally defined as an impoundment that is not dredged
and all CCRs are left in place in perpetuity.
22	For the CCR rule, a storage impoundment is generally defined as an impoundment that is periodically dredged and
has its CCR disposed elsewhere such that it can continue operating indefinitely.
5-9

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Section 5—Engineering Costs
•	Polymer addition and clarification to remove precipitants and other suspended
solids.
•	Acid addition for pH neutralization.
•	Sand filtration for additional removal of suspended solids.
The EPA used data from the 2015 rule to develop cost curves representing the capital and O&M
costs for the chemical precipitation treatment system. The cost curves presented below include
the following components:
•	Purchased Equipment Costs.
-	Pumps.
-	Tanks and mixers.
-	Reactors.
-	Chemical feed systems.
-	Clarifiers.
-	Filter presses.
-	Sand filters.
-	Pollutant monitoring and analysis (including a mercury analyzer).
•	Direct Capital Costs.
-	Purchased equipment (including fabricated equipment and process
machinery).
-	Freight.
-	Purchased equipment installation.
-	Instrumentation and controls (installed).
-	Piping (installed).
-	Electrical (installed).
-	Buildings (including services).
-	Site preparation.
•	Indirect Capital Costs.
-	Engineering and supervision.
-	Construction expenses.
-	Contractor's fees.
-	Contingency.
•	O&M Costs.
-	Operating labor.
-	Maintenance materials and labor.
-	Chemical purchase.
-	Energy.
5-10

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Section 5—Engineering Costs
-	Sludge transportation and disposal.
-	Compliance monitoring.
Section 9.6.1 of the 2015 TDD provides additional details on the design basis for chemical
precipitation wastewater treatment systems. The EPA also calculated 6-year recurring costs to
replace the mercury analyzer separately from the cost curves, as described below.
Plant-Level Capital and O&M Cost
The EPA used 2015 rule cost data and FGD purge flows to generate cost curves for estimating
plant-level capital and O&M costs as a function of FGD purge flow rate and optimized FGD
flow rate in GPD, respectively.23 Because costs are affected by the solids disposal location (i.e.,
on-site landfill or off-site transportation and disposal), the EPA generated a set of cost curves for
each transportation and disposal method (see Figure 5-1 and Figure 5-3 for capital costs and
Figure 5-2 and Figure 5-4 for O&M costs). These cost curves reflect the costs to design, procure,
install, and operate chemical precipitation treatment at plants where all components of the
treatment system will need to be acquired, such as at plants operating surface impoundments to
treat the FGD wastewater. To estimate plant-specific capital and O&M costs, the EPA used the
appropriate curves based on whether or not the plant is identified as having an on-site or off-site
landfill, as described in Section 5.2.1.
$80,000,000
$60,000,000
$40,000,000
$20,000,000
$0
0	500,000 1,000,000 1,500,000 2,000,000
FGD Purge Flow (GPD)
Chemical Precipitation Capital Cost with On-site Transport/Disposal
(2018$) = 34.96 x FGD Purge Flow + 7,042,075
Figure 5-1. Chemical Precipitation Capital Cost Curve - On-site Transport/Disposal
23 The EPA adjusted the 2015 rule original cost data basis from 2010 to 2018 dollars using RS Means Historical
Cost Indexes.
00
O
o
O
a.
C3
O
5-11

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Section 5—Engineering Costs
^ $10,000,000
$8,000,000
$6,000,000
$4,000,000	"
$2,000,000
$0
0	500,000 1,000,000 1,500,000 2,000,000
Optimized FGD Flow (GPD)
Chemical Precipitation O&M Cost with On-site Transport/Disposal
(2018$/yr) = 4.0466 x Optimized FGD Flow + 229,640
Figure 5-2. Chemical Precipitation O&M Cost Curve - On-site Transport/Disposal
$50,000,000
00
O $40,000,000				
(N
'$ $30,000,000
* **
-g $20,000,000
o
U
3 $10,000,000
a
ca
U
$0
0	400,000	800,000	1,200,000
FGD Purge Flow (GPD)
Chemical Precipitation Capital Cost with Off-site Transport/Disposal
(2018S) = 34.34 x FGD Purge Flow + 7,431,513
Figure 5-3. Chemical Precipitation Capital Cost Curve - Off-site Transport/Disposal
oo
o
ts
U
=%j
o
5-12

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Section 5—Engineering Costs
^ $8,000,000
' L.
00
© $6,000,000
(N
p
zn
£ $4,000,000
O
O $2,000,000
0	400,000	800,000	1,200,000
Optimized FGD Flow (GPD)
Chemical Precipitation O&M Cost with Off-site Transport/Disposal
(2018$/yr) = 5.53 x Optimized FGD Flow + 219,087
Figure 5-4. Chemical Precipitation O&M Cost Curve - Off-site Transport/Disposal
Recurring Costs
The EPA's cost analyses include additional costs for the chemical precipitation system that
would be incurred periodically after installation but less frequently than annually. The EPA
determined that a prudently designed treatment system would include a continuous water quality
monitor for measuring mercury concentrations in the treatment system effluent. The mercury
analyzer technology has been demonstrated as highly effective for FGD wastewater, and by
providing near real-time results, it has enabled plant operators to proactively take steps to adjust
the chemical precipitation process as needed to optimize pollutant removal. The EPA assumed
that the expected life of a mercury analyzer is 6 years and that each plant will operate one
analyzer for FGD wastewater. Plants with full or partial chemical precipitation costs incur a cost
of $100,000 (2018$) to replace the mercury analyzer every 6 years.
Treatment-In Place Adjustment for Capital and O&M Costs
For each plant that already has components of chemical precipitation treatment in place as part of
its treatment system, the EPA used Steam Electric Survey data to identify any upgrades needed
to make the treatment system comport with the chemical precipitation design basis considered
for this proposed rule. Depending on the capital upgrades needed or additional O&M costs that
would be incurred, the EPA used guidelines presented in Table 5-2 to classify the plant as
incurring high, medium, or low capital costs and high, medium, or low O&M costs. Then, for
each classification, the EPA used cost data from the 2015 rule to calculate the median percentage
of costs incurred by the plant compared to a full chemical precipitation treatment system (ERG,
2019d). The median percentages are presented in Table 5-2; these values were used to estimate
the compliance costs that would be incurred by plants that already operate some components of
the model chemical precipitation treatment system.
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Section 5—Engineering Costs
Table 5-2. Percentage of Chemical Precipitation Costs Incurred by Plants with
Treatment in Place
Cosl
CsiU'fion
( iiniliil ( osls
O&M CoMs
( nk'lion (.iiidcliiK'N
Percenl of
lull
1 iviilmonl
Stslcm
Cosl
Incurred
( nk'lion (.uidcliiK'N
Percenl of
lull
1 iviilmonl
Stslcm
Cosl
Inciirml
nigh
Planls o\|Xvk'd lo man' a»s>ls> for
an equalization tank and other
equipment such as a sand filter or
chemical addition system.
27%
Planls o\|Xvk'd lo man' more limn
two chemical costs in addition to
a mercury analyzer and
monitoring (e.g., three chemical
costs or two chemical costs and
another O&M cost).
31%
Medium
Plants expected to incur costs for
only an equalization tank (all or
partial) or plants costed for a sand
filter and chemical addition
systems.
17%
Plants expected to incur costs for
up to two chemicals, in addition to
a mercury analyzer and
monitoring.
13%
Low
Plants expected to incur costs for
a mercury analyzer and for up to
two chemical addition systems.
1%
Plants expected to incur costs for
a mercury analyzer, monitoring,
and minimal chemical costs.
6%
For plants with existing tank-based FGD wastewater treatment (i.e., not an impoundment
system), the EPA calculated costs following the framework shown in Table 5-3. Partial capital
and O&M costs were calculated using the appropriate percentage of full treatment system cost
incurred from Table 5-2 for each plant. Compliance monitoring costs include sampling labor and
materials as well as the costs associated with sample preservation, shipping, and analysis. The
EPA estimated the annual cost for compliance monitoring to be $73,600 (in 2018 dollars).
Table 5-3. Costs Incurred for Chemical Precipitation for Plants with Treatment in Place
1 iviilmonl in Phicc
Cosl Inciirml
Partial Chemical Precipitation
Partial capital and O&M costs (see Table 5-2)
Full Chemical Precipitationa
Compliance monitoring costs
Chemical Precipitation followed by LRTR, HRTR
or other biological process (e.g., Suspended
Growth Biological Treatment)
Compliance monitoring costs
Evaporation b
Zero costs
a - A Ml chemical precipitation treatment system includes ferric chloride, organosulfide, polymer, and acid
addition, and/or meets the mercury and arsenic limitations established for chemical precipitation.
b - Reusing the treated effluent from evaporation treatment systems as scrubber makeup water or in other
applications is more cost-effective than discharging this wastestream.
5-14

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Section 5—Engineering Costs
5.2.3 Cost Methodology for Chemical Precipitation followed by LRTR (CP+LRTR)
The design basis to estimate costs for CP+LRTR includes both chemical precipitation cost
components (see Section 5.2.2) and LRTR cost components. The LRTR components of the
model treatment technology include the following:
•	Purchased Equipment Costs.
-	Anoxic/anaerobic bioreactors.
-	Control skids.
-	Backwash skids.
-	Tanks.
-	Pumps.
-	Heat exchanger.
-	Pretreatment system (for denitrification at applicable plants).
-	Ultrafilter.
-	Chemical feed skids.
-	Pollutant monitoring and analysis (including a mercury analyzer).
•	Direct Costs.
-	Purchased equipment (including fabricated equipment and process
machinery).
-	Freight.
-	Instrumentation and controls (installed).
-	Piping (installed).
-	Electrical (installed).
-	Buildings (including services).
-	Site preparation.
•	Indirect Costs.
-	Engineering and supervision.
-	Contingency.
•	O&M Costs.
-	Operating labor.
-	Maintenance labor.
-	Chemical purchase.
-	Energy.
Plant-Level Capital and O&M Cost
The EPA's approach for estimating capital and O&M costs for the chemical precipitation
pretreatment stage of the CP+LRTR model technology is similar to the methodology described
5-15

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Section 5—Engineering Costs
in Section 5.2.2.24 Cost curves for the pretreatment stage with on-site disposal of treatment
residuals are presented in Figure 5-5 and Figure 5-6; Figure 5-7 and Figure 5-8 present costs for
pretreatment at plants that dispose of treatment residuals off site. To estimate plant-specific
capital and O&M costs, the EPA used the appropriate curves based on whether the plant is
identified as having an on-site or off-site landfill, as described in Section 5.2.1.
$80,000,000
&
00
E $60,000,000
w	..**
I
o $40,000,000
I	•**
o
o
•g $20,000,000
E.
CO
u
$0
0	500,000 1,000,000 1,500,000 2,000,000
FGD Purge Flow (GPD)
CP Pretreatment Capital Cost with On-site Transport/Disposal (2018$) =
36.17 x FGD Purge Flow + 6,909,668
Figure 5-5. CP Pretreatment Capital Cost Curve - On-site Transport/Disposal
-$10,000,000 I
&
5 $8,000,000
1 $6,000,000
c	I •***
o
^ $4,000,000
o
U
S $2,000,000
$
O
$0
0	500,000 1.000,000 1,500,000 2,000,000
Optimized FGD Flow (GPD)
CP Pretreatment O&M Cost with On-site Transport/Disposal (2018$/yr) =
4.112 x Optimized FGDFlow+ 152361
Figure 5-6. CP Pretreatment O&M Cost Curve - On-site Transport/Disposal
24 These costs differ slightly from those presented in Section 8.2.2 due to additional components, including
additional pumps, tanks, and piping, to account for holding and transporting partially treated water before further
treatment in the LRTR system.
5-16

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Section 5—Engineering Costs
$50,000,000
00
O $40,000,000
Cn	-
D
J $30,000,000
O
-g $20,000,000
o
u
3 $10,000,000
—
CB
u
$0
0	400,000	800,000	1,200,000
FGD Purge Flow (GPD)
CP Pretreatment Capital Cost with Off-site Transport/Disposal (2018S) =
35.97 x FGD Purge Flow + 7,309,923
Figure 5-7. CP Pretreatment Capital Cost Curve - Off-site Transport/Disposal
e $7,500,000
¦f
~ $6,000,000
(N
1 $4,500,000
O
^ $3,000,000
on
O
U
g $1,500,000
o
$0
0	400,000	800,000	1,200,000
Optimized FGD Flow (GPD)
CP Pretreatment O&M Cost with Off-site Transport/Disposal (2018$/yr) =
5.5875 x Optimized FGD Flow + 145,418
Figure 5-8. CP Pretreatment O&M Cost Curve - Off-site Transport/Disposal
The EPA used cost information compiled for the 2015 rule, combined with additional data
collected since then from power companies, treatment equipment vendors, engineering firms,
and publicly available engineering cost references to develop capital and O&M cost curves for
the LRTR stage of the CP+LRTR model technology (ERG, 2019e). The resulting cost curves
differentiate between plants that may need to include an additional partial denitrification
pretreatment step (for the model LRTR treatment technology, this was defined as plants with
5-17

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Section 5—Engineering Costs
influent nitrate concentrations higher than 50 mg/L in untreated FGD purge). The EPA used low
nitrates curves to estimate costs for all plants, except for the subset of plants where sampling data
from the Analytical Database (ERG, 2015) and the Steam Electric Survey (ERG, 2019e)
demonstrated nitrate/nitrite concentrations at or above 50 mg/L in FGD purge.
ffi
CO
O
-------
Section 5—Engineering Costs
fs>
CO
o
CI

$30,000,000
$24,000,000
$18,000,000
¦Bfc $12,000,000
$6,000,000
o
U
a
cc
U
$o
500,000 1,000,000 1,500,000
FGD Purge Flow (GPD)
2,000,000
LRTR Capital Cost High Nitrates (2018$) = 12.145 x FGD
Purge Flow + 4.000.000
Figure 5-11. LRTR Capital Cost Curve - High Nitrates
$3,000,000
£
if)
oo
o
-------
Section 5—Engineering Costs
equivalent to the median cost for a field erected equalization tank with a hydraulic residence time
of 24 hours for flows between 70,000 GPD and 1,000,000 GPD for the 2015 rule costed
population ($823,000). Compliance monitoring O&M costs for the CP+LRTR technology option
include costs to conduct annual compliance monitoring for arsenic, mercury, selenium, and
nitrate/nitrite ($75,600).
Table 5-4. Costs Incurred for Chemical Precipitation plus LRTR for Plants with Existing
Treatment in Place
1 iviilmonl in Pliicc
( osi Incurred
Partial Chemical Precipitation
Partial chemical precipitation as pretreatment capital and
O&M costs (see Section 5.2.2 and Table 5-3), full LRTR
capital and O&M costs based on plant-specific
nitrate/nitrite concentrations.
Full Chemical Precipitationa
Full LRTR capital and O&M costs based on plant-specific
nitrate/nitrite concentrations.
Chemical Precipitation followed by Suspended
Growth Biological Treatment
Equalization tank capital cost and compliance monitoring
costs.
Chemical Precipitation followed by LRTR or
HRTR
Compliance monitoring costs.
Evaporation b
Zero costs
a - A Ml chemical precipitation treatment system includes ferric chloride, organosulfide, polymer, and acid
addition, and/or meets the mercury and arsenic limitations established for chemical precipitation.
b - Reusing the treated effluent from evaporation treatment systems as scrubber makeup water or in other
applications is more cost-effective than discharging this waste stream.
5.2.4 Cost Methodology for Chemical Precipitation followed by HRTR (CP+HRTR)
The CP+HRTR technology basis presented here is consistent with the BAT technology basis for
the 2015 rule, chemical precipitation followed by anoxic/anaerobic biological treatment. The
cost estimates for this technology option include the chemical precipitation cost components
described in Section 5.2.2, as well as the following HRTR cost components:
•	Purchased Equipment Costs.
-	Anoxic/anaerobic biological system.
-	Tanks.
-	Pumps.
-	Heat exchanger (for applicable plants).
-	Backwash system.
-	Chemical feed systems.
-	Pretreatment system (for denitrification at applicable plants).
-	Pollutant monitoring and analysis (including a mercury analyzer ORP
monitor).
•	Direct Capital Costs.
5-20
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Section 5—Engineering Costs
-	Purchased equipment (including fabricated equipment and process
machinery).
-	Freight.
-	Purchased equipment installation.
-	Instrumentation and controls (installed).
-	Piping (installed).
-	Electrical (installed).
-	Buildings (including services).
-	Site preparation.
•	Indirect Capital Costs.
-	Engineering and supervision.
-	Construction expenses.
-	Contractor's fees.
-	Contingency.
•	O&M Costs.
-	Operating labor.
-	Maintenance materials and labor.
-	Chemical purchase.
-	Energy.
-	Sludge transportation and disposal.
-	Compliance monitoring.
Section 9.6.2 of the 2015 TDD provides additional details on the design basis for HRTR.
Plant-Level Capital and O&M Cost
The EPA estimated pretreatment costs for a chemical precipitation system using the equations
found in Section 5.2.3. Like the method described in Section 5.2.2 for chemical precipitation, the
EPA used the 2015 rule data to establish cost curves for HRTR capital and O&M costs as a
function of FGD purge flows and optimized FGD flows, respectively (ERG, 2019f). Based on
data received following promulgation of the 2015 rule, the EPA adjusted HRTR costs to account
for increased installation costs. The EPA also converted the 2015 rule costs from a cost basis of
2010 dollars to 2018 dollars. The EPA generated a set of cost curves for both on-site and off-site
transportation and disposal (see Figure 5-13 and Figure 5-15 for capital costs and Figure 5-14
and Figure 5-16 for O&M costs). To estimate plant-specific capital and O&M costs, the EPA
used the appropriate curves based on whether the plant is identified as having an on-site or off-
site landfill, as described in Section 5.2.1.
5-21
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Section 5—Engineering Costs
_ $60,000,000
&
oc
O $48,000,000
CN
T $36,000,000
O
tii $24,000,000
0	A.-*
1	$12,000,000
CL
CO
U
$0
0	500,000 1,000,000 1,500,000 2,000,000
FGD Purge Flow (GPD)
HRTR Capital Costwith On-site Transport/Disposal (2018$) = 24.03 x
FGD Purge Flow + 4,897,052
Figure 5-13. HRTR Capital Cost Curve - On-site Transport/Disposal
$2,000,000
$1,600,000
$1,200,000		
$800,000
$400,000
$0
0	500,000 1,000,000 1,500,000 2,000,000
Optimized FGD Flow (GPD )
HRTR O&M Costwith On-site Transport/Disposal (2018$/yr)= 0.6265 x
Optimized FGD Flow + 412,355
Figure 5-14. HRTR O&M Cost Curve - On-site Transport/Disposal
00
o
-------
Section 5—Engineering Costs
_ $40,000,000
oo
o
w $30,000,000
0	$20,000,000
1	I .•* *
in
O
^ $10,000,000
E.
a
O
$0
0	400,000	800,000	1,200,000
FGD Purge Flow (GPD)
HRTR Capital Cost with Off site Transport/Disposal (2018S) = 25.72 *
FGD Purge Flow + 5,230,612
Figure 5-15. HRTR Capital Cost Curve - Off-site Transport/Disposal
_ $1,200,000
' i—
00
5 $900,000
(N
O
$600,000
o
5 $300,000
0	400,000	800,000	1,200,000
Optimized FGD Flow (GPD)
HRTR O&M Cost with Off-site Transport/Disposal (2018$/yr) = -5xl0~7x
Optimized FGD Flow2 + 1.2533 x Optimized FGD Flow + 332,703
Figure 5-16. HRTR O&M Cost Curve - Off-site Transport/Disposal25
For plants with a nitrate/nitrite concentration in the FGD purge at or above 100 mg/L, the EPA
estimated additional capital and O&M costs for a denitrification treatment step using the 2015
rule methodology (Equation 5-4 and Equation 5-5). The EPA used low nitrates curves to
estimate costs for all plants except for the subset of plants where sampling data from the
25 The EPA anticipates updating this relationship between HRTR O&M costs with off-site transportation and
disposal to a linear relationship for future cost analyses. Based on the current population, this would affect 12 plants
that transport and dispose of solids in off-site landfills and result in an increase in O&M costs of approximately
$305,000 for the industry.
5-23
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Section 5—Engineering Costs
Analytical Database and the Steam Electric Survey demonstrated nitrate/nitrite concentrations at
or above 50 mg/L in FGD purge (ERG, 2015).
Denitrification Capital Costs (2018$) = -1.091 x [(FGD Purge Flow) / (24 hr/day) / (60 min/hr)]2
+ 3,601.1 x [(FGD Purge Flow) / (24 hr/day) / (60 min/hr)] + 501,971
Equation 5-4
Denitrification O&M Costs (2018$) = 2,699 x [(Optimized FGD Flow) / (24 hr/day) / (60
min/hr)] + 275,333
Equation 5-5
Recurring Costs
For all plants that are expected to incur costs beyond monitoring, the EPA calculated the 6-year
recurring cost for a mercury analyzer, as discussed in Section 5.2.2.
Treatment in Place Adjustment for Plant-Level Capital and O&M Costs
For plants with existing FGD wastewater treatment more advanced than a surface impoundment,
the EPA calculated the plant cost based on the costs listed in Table 5-5. Equalization tank capital
costs are equivalent to the median cost for a field erected equalization tank with a hydraulic
residence time of 24 hours for flows between 70,000 GPD and 1,000,000 GPD for the 2015 rule
costed population ($823,000). Compliance monitoring costs for the CP+HRTR technology
option include costs to collect and analyze effluent samples for arsenic, mercury, selenium, and
nitrate/ni trite, following the cost methodology used for the 2015 rule and converting to 2018
dollars ($75,600).
Table 5-5. Costs Incurred for Chemical Precipitation plus HRTR for Plants with
Existing Treatment in Place
1 IVillllHMII ill PliICO
( osi Incurred
Partial Chemical Precipitation
Partial chemical precipitation as pretreatment capital and
O&M costs (see Section 5.2.2 and Table 5-2), full HRTR
capital and O&M costs based on plant-specific
nitrate/nitrite concentrations
Full Chemical Precipitationa
Full HRTR capital and O&M costs based on plant-specific
nitrate/nitrite concentrations
Chemical Precipitation followed by LRTR or
Suspended Growth Biological Treatment
Equalization tank capital cost and compliance monitoring
costs
Chemical Precipitation followed by HRTR
Compliance monitoring costs
Evaporation b
Zero costs
a - A full chemical precipitation treatment system includes ferric chloride, organosulfide, polymer, and acid
addition, and/or meets the mercury and arsenic limitations established for chemical precipitation.
b - Reusing the treated effluent from evaporation treatment systems as scrubber makeup water or in other
applications is more cost-effective than discharging this wastestream.
5-24
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Section 5—Engineering Costs
5.2.5 Cost Methodology for Membrane Filtration
The design basis for the membrane technology option includes pretreatment for removing
suspended solids, membrane filtration, and encapsulation of the membrane reject stream (i.e.,
brine) using a solidification process. The membrane filtration process produces a permeate
stream that is higher quality than the water used in the FGD system for limestone slurry makeup,
mist eliminator wash, and other processes. Because the FGD system is a net water consumer,
plants using this treatment technology would most likely recycle the permeate within the FGD
process operations; therefore, no compliance monitoring costs would be incurred.
The EPA used capital and O&M cost data collected from industry sources and technology
vendors to develop cost methodologies that estimate plant-specific costs for pretreatment,
membrane filtration, brine management, and disposal of solidification solids. The membrane
treatment technology basis includes the following cost components:
•	Purchased Equipment Costs.
-	Membrane filtration skids.
-	Tanks.
-	Pumps.
-	Pretreatment system (for reverse osmosis at applicable plants).
-	Brine mixing skid for concentrate management.
•	Direct Capital Costs.
-	Purchased equipment (including fabricated equipment and process
machinery).
-	Freight.
-	Purchased equipment installation.
-	Instrumentation and controls (installed).
-	Piping (installed).
-	Electrical (installed).
-	Buildings (including services).
-	Site preparation.
•	Indirect Capital Costs.
-	Engineering and supervision.
-	Construction expenses.
-	Contractor's fees.
-	Contingency.
•	O&M Costs.
-	Operating labor.
-	Maintenance materials and labor.
-	Chemical purchase.
5-25
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Section 5—Engineering Costs
-	Energy.
-	Sludge transportation and disposal.
Plant-Level Capital and O&M Cost
The cost data were used to establish relationships between capital costs and FGD purge flow
rates, and between O&M costs and optimized FGD flow rates, respectively (ERG, 2019g).
Similar to methodologies for other treatment technologies, the EPA constructed curves to
differentiate between on-site and off-site transportation and disposal. For each set of curves, the
EPA also differentiated between costs for systems that require pretreatment for solids (identified
as "Pretreatment and Membrane" in the figures below) and systems that do not require
pretreatment for solids (identified as "Membrane Only" in the figures below). Plants with
existing treatment more advanced than surface impoundments were considered to have sufficient
pretreatment for the membrane and costs were estimated using the Membrane Only cost curves.
Costs for all other plants were estimated using the Pretreatment and Membrane curves to account
for solids pretreatment costs (see Figure 5-17 and Figure 5-19 for capital cost curves and Figure
5-18 and Figure 5-20 for O&M cost curves). To estimate plant-specific capital and O&M costs,
the EPA used the appropriate curves based on whether the plant is identified as having an on-site
or off-site landfill, as described in Section 5.2.1.
	Pretreatment and Membrane	Membrane Only
2 $100,000,000
O
CN
2 $75,000,000
M
I
O $50,000,000
I
0	$25,000,000
1	$0
0 500,000 1,000,000 1,500,000 2,000,000 2,500,000
FGD Purge Flow (GPD)
Pretreatment and Membrane Capital Cost with On-site Transport/Disposal
(2018S) = 45.5 x FGD Purge Flow + 1,652,455
Membrane Only Capital Cost with On-site Transport/Disposal (2018$) =
39.9 x FGD Purge Flow + 1,616,978
Figure 5-17. Membrane Capital Cost Curves - On-site Transport/Disposal
5-26
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Section 5—Engineering Costs
Pretreatment and Membrane
Membrane Only
55 $12,000,000
CO	'
o
o
o
o
$9,000,000
$6,000,000
$3,000,000
$0
500,000 1,000,000 1,500,000
Optimized FGD Flow (GPD)
2,000,000
Pretreatment and Membrane O&M Cost with On-site Transport/Disposal
(2018$/yr) = 6.95 x Optimized FGD Flow + 450,548
Membrane Only O&M Cost with On-site Transport/Disposal (2018$/yr) =
6.00 x Optimized FGD Flow + 467,045
Figure 5-18. Membrane O&M Cost Curves - On-site Transport/Disposal
09
00
Pretreatment and Membrane
Membrane Only
$50,000,000
cs
2 $37,500,000
o $25,000,000
o $12,500,000
u
$o
£1.
a
U
400,000	800,000
FGD Purge Flow (GPD)
1,200,000
Pretreatment and Membrane Capital Cost with Off-site Transport/Disposal
(2018$) = 41.7 x FGD Purge Flow + 873,629
Membrane Only Capital Cost with Off-site Transport/Disposal (2018$) =
37.2 x FGD Purge Flow + 1,457,975
Figure 5-19. Membrane Capital Cost Curves - Off-site Transport/Disposal
5-27
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Section 5—Engineering Costs
-p		Pretreatment and Membrane	Membrane Only
5? $10,000,000
oo ' '
§, $7,500,000
-------
Section 5—Engineering Costs
on-site impoundments and subtracted these costs from the estimated compliance costs for the
technologies described above in this section, consistent with the 2015 methodology. The FGD
impoundment operating cost savings quantified by the EPA include costs associated with the
following:
•	Wastewater transport system (i.e., pipelines, vacuum source) used to pump
wastewater from the FGD scrubber to the impoundment.
•	Impoundment site (i.e., general operation of the impoundment and inspections).
•	Wastewater treatment processes (e.g., pH control).
•	Water recycle system at the impoundment (if applicable).
•	FGD earthmoving costs (e.g., front-end loader, removing/stacking combustion
residuals at the impoundment site).
The EPA used Steam Electric Survey data to identify plants that have at least one impoundment
containing FGD wastewater and at least one generating unit not designated as retired or planned.
For those plants that have upgraded the FGD wastewater treatment system since the 2015 rule,
the EPA assumed that their impoundments would cease operation.26 The EPA estimated plant-
level costs for operating impoundments based on the total amount of FGD solids currently
handled wet at the plant. The EPA estimated the total FGD impoundment O&M cost savings
using Equation 5-6.
Total FGD Impoundment O&M Cost Savings (2018$/yr) = (FGD Impoundment Operating Cost
Savings + FGD Earthmoving Cost Savings) x (2018 Cost Index / 2010 Cost Index)
Equation 5-6
Where:
FGD Impoundment
Operating Cost Savings
FGD Earthmoving Cost
Savings
Impoundment operating cost savings (in 2010$) (see
Equation 5-9).
O&M cost associated with the earthmoving equipment
required (in 2010$) (see Equation 5-11).
2010 Cost Index
2018 Cost Index
183.5, the RSMeans Historical Cost Index for 2010.
215.8, the RSMeans Historical Cost Index for 2018.
26 Once the FGD wastewater treatment system is upgraded to a more advanced technology (e.g., CP+LRTR), the
impoundment provides little value with respect to pollutant removal and remains a substantial liability (for example,
due to structural integrity failure).
5-29
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Section 5—Engineering Costs
FGD Impoundment Operating Annual Cost Savings
The EPA estimated the FGD impoundment operating cost savings by first calculating the plant
MW factor and the plant-specific unitized cost using Equation 5-7 and Equation 5-8.
Plant MW Factor (MW) = 7.569 x (Plant Size)"0 32
Equation 5-7
Where:
Plant Size	= Plant size (in MW). The plant nameplate capacity for
only those generating units serviced by a wet FGD
system from responses to Question Al-13 in the Steam
Electric Survey.
Plant-Specific Unitized Cost (2010$/ton) = (Impoundment Operating Unitized Cost) x
(Plant MW Factor)
Equation 5-8
Where:
Impoundment Operating = The unitized annual cost to operate a combustion
Unitized Cost	residual impoundment. The EPA used the unitized cost
value of $7.35 (in 2010$/ton).
Plant MW Factor	= Factor to adjust combustion residual handling costs
based on plant capacity (in MW) (see Equation 5-7).
Next, the EPA estimated the total amount of FGD solids handled wet using the optimized FGD
flow rate in GPD described in Section 5.2.1 and the average total suspended solids (TSS)
concentration from EPA's Field Sampling Program, which was conducted in support of the 2015
rule. The EPA calculated the FGD impoundment operating cost savings by multiplying the plant-
specific unitized cost (see Equation 5-8) by the amount of wet FGD solids using Equation 5-9.
FGD Impoundment Operating Cost Savings (2010$/year) = (Plant-Specific Unitized Cost) x
[(Optimized FGD Flow) x (Average TSS Concentration) x (3.785 L/gal) x (0.001 g/mg) x
(1.102 x 10"6tons/g) x (365 days/year)]
Equation 5-9
Where:
Optimized FGD Flow	= Optimized FGD flow rate (in GPD) (see Equation 5-3).
5-30
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Section 5—Engineering Costs
Average TSS	= The average influent TSS concentration for FGD
Concentration	wastewater treatment influent sampled as part of the
2015 rule (16,513 mg/L) (ERG, 2015).
FGD Earthmoving Annual Cost Savings
To calculate FGD earthmoving cost savings, the EPA first calculated the plant-specific front-end
loader unitized cost by multiplying the plant MW factor and the front-end loader unitized cost
using Equation 5-10.
Plant-Specific Front-End Loader Unitized Cost (2010$) =
(Front-End Loader 2010 Unitized O&M Cost) x (Plant MW Factor)
Equation 5-10
Where:
Front-End Loader Unitized = The unitized cost value that represents the operation
O&M Cost	and maintenance of the front-end loader used to
redistribute FGD solids at an impoundment. This value
was calculated to be $2.49 (in 2010$/ton).
Plant MW Factor	= Factor to adjust combustion residual handling costs
based on plant capacity (in MW) (see Equation 5-7).
Next, the EPA estimated the amount of combustion residuals (in tons) using the plant's
optimized FGD flow, in gallons per day, and the average TSS concentration from EPA's Field
Sampling Program. The EPA calculated the FGD earthmoving cost savings using Equation 5-11.
FGD Earthmoving Cost Savings (2010$/yr) = (Plant-Specific Front-End Loader Unitized Cost) x
[(Optimized FGD Flow) x (Average TSS Concentration) x
(3.785 L/gal) x (0.001 g/mg) x (1.102 x 10"6 tons/g) x (365 days/year)]
Equation 5-11
Where:
Optimized FGD Flow	=
Average TSS Concentration =
5-31
Optimized FGD flow rate (in GPD) (see Equation 5-3
in Section 5.2.1).
The average influent TSS concentration for FGD
wastewater treatment influent sampled as part of the
EPA Steam Electric Rulemaking effort (16,513 mg/L)
(ERG, 2015).
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Section 5—Engineering Costs
FGD Earthmoving Recurring Costs
The EPA calculated 10-year recurring cost savings associated with operating the earthmoving
equipment (i.e., front-end loader) by determining the cost and average expected life of a front-
end loader. The EPA determined the 2018 cost of the earthmoving equipment to be $474,000 and
assumed that the expected life of a front-end loader is 10 years. The EPA anticipated that each
plant will operate one front-end loader if the plant is identified for impoundment savings.
5.3 Bottom Ash Transport Water
The EPA estimated costs associated with zero discharge and high recycle rate technology options
for this proposed rule. As described in the preamble, one proposed subcategorization option
includes a generating unit utilization threshold (MWh). For the generating units falling below
this threshold, and identified as low utilization, the EPA estimated costs associated with a best
management practices (BMP) plan instead of the high recycle rate technology option. For each
technology option considered, the EPA estimated the costs associated with installing additional
handling or treatment technologies that eliminate or reduce the discharge of bottom ash transport
water. The EPA then compared these costs to the cost to comply with the 2015 rule
requirements, equivalent to the zero discharge technology options, to estimate incremental costs
and savings to the steam electric power generating industry. Table 5-7 lists the technologies the
EPA used as the basis for the three bottom ash technology options considered. The EPA also
estimated the cost savings associated with plants ceasing operation of impoundments currently
used for the treatment of bottom ash transport water (see Section 5.3.7).
Table 5-7. Technology Options for Bottom Ash Transport Water
Technologies
Ti'clinolou\ Options
Zero Dischiii'ue
lli»h Kcocle
Kiilo
lli»h Reoclc
Kiilc/liMP I'liin
Mechanical Drag System (MDS)
(Section 5.3.2)
V
V
V
Remote MDS (rMDS) with Reverse Osmosis
(RO) treatment of a slipstream
(Section 5.3.3)
V


rMDS with a purge
(Section 5.3.4)

V
V
Bottom ash improved management
(Section 5.3.5)
V
V
V
Bottom ash BMP plan3
(Section 5.3.6)


V
a - Applied only to plants with generating units with a 2016 EIA net generation less than or equal to 876,000
MWh, excluding those with a generation capacity less than or equal to 50 MW.
The EPA used MDS and rMDS as the two main bases for estimating compliance costs for the
technology options evaluated. For all generating units discharging bottom ash transport water
from impoundment-based wet sluicing systems, the EPA first estimated costs to convert to an
MDS and to an rMDS. The EPA evaluated both technologies because the MDS is the most
commonly used dry handling/closed-loop system operating in the industry, but some plants have
opted for the rMDS either because of economies of scale when used for multiple units, less
5-32
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Section 5—Engineering Costs
disruption of plant operations while converting the ash handling system, or constraints imposed
by boiler house configuration.27 The EPA then selected the technology with the lowest
annualized costs for each plant to determine the technology likely to be installed, and considered
any additional costs and cost savings associated with each technology option.28
For the MDS, the EPA included costs to replace the existing boiler hopper and associated
equipment, and to install and operate a semi-dry silo for temporary storage of the bottom ash.
For the rMDS, the EPA included the costs to install and operate the following:
•	rMDS (away from the boiler).
•	Sump.
•	Recycle pumps.
•	Chemical feed system.29
•	Semi-dry silo.
For the zero discharge option only, the EPA included additional costs for the treatment of a
slipstream from the rMDS using a reverse osmosis membrane in order to operate the system to
achieve zero discharge. The EPA applied these costs to plants currently operating an rMDS as
well as any other plants estimated to install the technology.
The EPA estimated a cost to prepare and implement a BMP plan for generating units with low
utilization.30 These costs include the initial development and annual review of a BMP plan to
recycle as much bottom ash transport water determined practicable, and capital and operation
and maintenance (O&M) costs for pumps and piping associated with the recycle system.
The EPA identified several plants that operate bottom ash wet handling systems as closed-loop
systems. These plants did not report any discharge of bottom ash transport water in the Steam
Electric Survey. However, based on other information in the survey responses, the EPA
determined that these plants have retained the capability to discharge bottom ash transport water
from emergency outfalls. The cost methodology approach used for these plants is described in
Section 5.3.5.
27	There are alternative ash handling technologies to the MDS and rMDS that can alleviate these issues (e.g.,
pneumatic bottom ash handling) and these alternatives have been used at plants in the U.S. and internationally;
however, EPA's cost analyses are based on MDS and rMDS. Estimates based on MDS and rMDS are sufficiently
comparable to alternative bottom ash handling approaches to use for evaluating costs and economic achievability.
28	Consistent with the approach used for the 2015 rule, for plants where the EPA is aware that physical constraints
preclude installation of the MDS technology, the EPA based costs on rMDS.
29	The EPA included costs for a chemical feed system to control pH, should that become necessary to prevent
scaling within the system. Information in the record indicates that few, if any, plants are likely to need to use such
systems. However, because the EPA could not conclusively determine that none of the plants would need the
chemical feed system to control pH of the recirculating system, nor which of the plants would be more likely to need
the system; costs were included for all plants. This likely overestimates the compliance costs for most plants;
however, the cost for chemical addition is relatively small in relation to other costs for the rMDS.
30	Applied only to plants with generating units with a 2016 EIA net generation less than or equal to 876,000 MWh,
excluding those with a generation capacity less than or equal to 50 MW.
5-33
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Section 5—Engineering Costs
The EPA also included the capital and O&M costs of transporting and disposing of all bottom
ash to a landfill for the technology options considered.
5.3.1 Bottom Ash Cost Calculation Inputs
To calculate plant-level engineering costs associated with implementing bottom ash transport
water technologies, the EPA developed a cost calculation database containing a set of input
values as well as a set of equations that define relationships between costs and generating unit
capacity or bottom ash generation (ERG, 2019h). To establish the set of inputs, the EPA
compiled generating-unit-specific details on bottom ash production, current bottom ash handling
system details, and information on the use of on-site and off-site landfills by steam electric
power plants discharging bottom ash transport water.
As part of the 2015 rule, the EPA developed a similar set of input information from the Steam
Electric Survey data, site visits, sampling episodes, and other industry-provided data to calculate
compliance costs. For this proposed rule, the EPA updated the input values using additional
information gathered from industry and available from the Department of Energy and NPDES
permits (see Section 2). The EPA developed a list of generating units expected to incur bottom
ash compliance costs by identifying plants that discharge bottom ash transport water, taking into
account changes made to handling systems, as well as retirements and conversions (to a fuel
other than coal) of generating units since the 2015 rule. The EPA also identified generating units
that have announced plans to retire or convert their fuel source before December 31, 2028. This
section describes the updates to cost inputs from the 2015 rule.
Bottom Ash Production Data
For each applicable generating unit, the EPA estimated the amount of wet bottom ash produced
in tons per year (TPY), generating capacity in MW, and net generation in MWh. The EPA used
bottom ash production and capacity values reported in the Steam Electric Survey as input values
for estimating implementation costs for the proposed rule. The EPA used generating unit-level
net generation values reported in the 2016 EIA data to identify low utilization generating units.
Bottom Ash Cost Type Flags
The EPA used data from the Steam Electric Survey, site visits, and other industry-provided data,
discussed in Section 2, to identify the type of bottom ash handling systems currently operating at
each plant. The EPA used this information to determine what equipment or services the plants
would have to acquire to apply each technology option. The EPA flagged plants for one or more
of the following:
•	Steam electric generating units equipped with only wet bottom ash handling
systems that discharge bottom ash transport water.
•	Steam electric generating units equipped with only wet bottom ash handling
systems that discharge bottom ash transport water and have space constraints
preventing the installation of an MDS.
•	Steam electric generating units already operating an rMDS system.
5-34
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Section 5—Engineering Costs
•	Steam electric generating units equipped with only wet bottom ash handling
systems that recycle all of their bottom ash sluice, but have the ability to
discharge bottom ash transport water from emergency outfalls.
•	Steam electric generating units operating a dry bottom ash handling system.
Landfill Data
Like the 2015 rule, the EPA used data from the Steam Electric Survey and other public sources
to identify which plants operate on-site active/inactive landfills containing bottom ash. Plants
without an on-site active/inactive landfill with combustion residuals were identified as off-site
landfills. The EPA anticipates plants with inactive on-site landfills will resume disposal of
bottom ash to the landfill if necessitated by implementation of a bottom ash transport water
technology option.
Final CCR Decision Input Data
As discussed in Section 3.3, the EPA applied the same methodology used in the 2015 rule to
update the bottom ash population for changes in plant operations as a result of the CCR rule. The
CCR rule sets requirements for managing impoundments and landfills containing CCRs. Based
on the CCR requirements, the EPA expects that some plants will potentially undertake the
following changes in how they operate their current CCR impoundments:
•	Close the disposal surface impoundment31 and open a new composite-lined
disposal surface impoundment in its place.
•	Convert the disposal surface impoundment to a new composite-lined storage
impoundment.32
•	Close the disposal surface impoundment and convert to dry handling operations.
•	Make no changes to the operation of the disposal surface impoundment.
Consistent with the 2015 methodology, described in Section 9.4.1 of the 2015 TDD, the EPA
developed a method to use the output analysis of the CCR rule to predict which of the four
potential operational changes would likely occur at each coal-fired power plant that operates
bottom ash disposal impoundments under the CCR rule, see Table 5-8.
Table 5-8. ELG Bottom Ash Baseline Changes Accounting for CCR Rule
CCU Rule
Decision
Adjiislmonl lo l l.(.
liiisolinc
r.nvci on iK, Cosis ¦'
l-'.ITccl on l-'.I.Ci l.o;i(liniis
New disposal
impoundment
No changes
No changes
No changes
31	For the CCR rule, a disposal surface impoundment is generally defined as an impoundment that is not dredged
and all CCRs are left in place in perpetuity.
32	For the CCR rule, a storage impoundment is generally defined as an impoundment that is periodically dredged and
has its CCR disposed elsewhere such that it can continue operating indefinitely.
5-35
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Section 5—Engineering Costs
Table 5-8. ELG Bottom Ash Baseline Changes Accounting for CCR Rule
CCR Rule
Decision
Adjustment to ELG
Baseline
Effect on ELG Costs"
Effect on ELG Loadings"
New storage
impoundment
Plant dredges bottom ash
from impoundment and
disposes of it.
Plant incurs capital and
O&M costs for the bottom
ash handling system, but
does not incur
transport/disposal costs.
No changes
Convert to dry
handling
Plant operates a dry bottom
ash handling or closed-loop
recycle system for all
generating units.
Plant incurs no bottom ash
compliance costs.b
Plant has a baseline bottom
ash loading of zero.
No decision
No changes
No changes
No changes
a - Changes described are compared to the costs and loads that would have been calculated if the EPA was not
accounting for the CCR rule.
b - Plants that install remote mechanical drag systems to comply with the CCR rule may also incur costs to install a
reverse osmosis system to treat a slipstream of the recirculating bottom ash transport water, as a way to remove
dissolved solids and facilitate long-term operation of the system as a closed loop to comply with the bottom ash zero
discharge requirements of the 2015 rule (i.e., baseline). There are other approaches that can also be used to remove
dissolved solids from the bottom ash system without using reverse osmosis treatment, such as using the transport
water as makeup water for the FGD system. Dissolved solids will also be removed from the system along with the
bottom ash, which is wet as it is removed from the rMDS. As data become available on how specific plants comply
with CCR, the EPA will update the compliance cost estimates as appropriate in future analyses.
5.3.2 Cost Methodology for Mechanical Drag System
The EPA estimated capital, O&M, and 3-year recurring costs associated with installing an MDS
for all steam electric generating units equipped with wet bottom ash handling systems that
discharge bottom ash transport water. The EPA used cost data from the 2015 rule to develop
capital cost curves for on-site and off-site disposal as a function of generating unit capacity. The
EPA developed O&M cost curves for on-site and off-site disposal as a function of the amount of
wet bottom ash produced. The EPA also developed a separate set of cost curves for those plants
currently operating a storage impoundment for their bottom ash rather than a disposal
impoundment. Plants with storage impoundments periodically dredge the impoundment to
remove the ash and haul it away for disposal or beneficial use rather than leaving the bottom ash
in the impoundment for long-term disposal. Because these plants with storage impoundments
already incur transport and disposal costs (see Table 5-8) as part of their current ash handling
practices, the MDS cost curves for these plants do not include incremental transport and disposal
costs.
The MDS capital cost curves account for the purchase and installation of conveyance equipment,
a semi-dry bottom ash intermediate storage silo, and motors required to operate the system. They
include the following components:
• Direct Capital Costs.
- Purchased equipment (including fabricated equipment and process
machinery).
5-36
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Section 5—Engineering Costs
-	Freight.
-	Purchased equipment installation.
-	Instrumentation and controls (installed).
-	Piping (installed).
-	Electrical (installed).
-	Buildings (including services).
-	Site preparation (including land purchase, if required).
•	Indirect Capital Costs.
-	Engineering and supervision.
-	Construction expenses.
-	Contractor's fees.
-	Contingency.
MDS O&M curves account for the operation and maintenance of the MDS system, intermediate
storage, bottom ash disposal for plants with on-site or off-site landfill disposal, as well as cost
savings associated with elimination of wet sluicing operations, and include the following cost
elements:
•	Conveyance Costs.
-	Operating labor.
-	Maintenance materials and labor.
-	Energy.
•	Intermediate Storage Costs.
-	Operating labor.
-	Maintenance materials and labor.
-	Energy.
•	Bottom Ash Disposal Costs.
•	Wet Sluicing O&M Cost Savings.
-	Operating labor.
-	Maintenance materials and labor.
-	Energy.
Plant-Level Capital and O&M Costs
Using the 2015 rule cost data and the bottom ash production data, the EPA generated cost curves
for estimating unit-level MDS capital and O&M costs as a function of unit-level capacity and
unit-level bottom ash production, respectively. Because costs are affected by the solids disposal
location (i.e., on-site landfill or off-site transportation and disposal), the EPA generated a set of
cost curves for each transportation and disposal method (see Figure 5-21 and Figure 5-23 for
capital costs and Figure 5-22 and Figure 5-24 for O&M costs).
5-37
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Section 5—Engineering Costs
$60,000,000
» $50,000,000
O
~ $40,000,000
ISA
g $30,000,000
¦
$20,000,000
$10,000,000
$0
o
u
Cl
CO
u
0	300	600	900	1,200 1,500
Generating Unit Capacity (MW)
\IDS Capital Costwith On-site Transport/Disposal (2018S) = 35,814 x
Generating Unit Capacity- + 4,967,594
Figure 5-21. MDS Capital Cost Curve - On-site Transport/Disposal
$2,500,000
co $2,000,000	I.-"""
o	.••*''"1
£ $1,500,000	<	J
o $1,000,000
w	.•*"***
U $500,000
s
<*i
°	$0
0 20,000 40,000 60,000 80,000 100,000
Generating Unit Bottom Ash Tonnage (TPY)
MDS O&M Costwith On-Site Transport/Disposal (2018$)/yr)= 17.159 x
Generating Unit Wet Bottom Ash Produced + 524,969
Figure 5-22. MDS O&M Cost Curve - On-site Transport/Disposal
5-38
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Section 5—Engineering Costs

$35,000,000
$30,000,000





QO





o





Ci
$25,000,000





Hi





w
, i
$20,000,000
$15,000,000





o











O
o
$10,000,000











$5,000,000
$0





Cl
C3
u






) 200 400 600 800 1,000
Generating Unit Capacity (MW)

MDS Capital Costwith Off-site Transport/Disposal (2018$) = 33,500 x
Generating Unit Capacity + 5,004,227
Figure 5-23. MDS Capital Cost Curve - Off-site Transport/Disposal

$6,000,000


00
$5,000,000
O

&
$4,000,000
VI
, i
$3,000,000
o
1
w
$2,000,000
u

>
$1,000,000


o
$0
0	20,000	40,000	60,000	80,000
Generating Unit Bottom Ash Tonnage (TPY)
MDS O&M Cost with Off-site Transport/Disposal (2018$/yr) = 73.713 x
Generating Unit Wet Bottom Ash Produced + 528,126
Figure 5-24. MDS O&M Cost Curve - Off-site Transport/Disposal
Plants currently operating a CCR impoundment for bottom ash storage already incur costs for
transporting and disposing bottom ash. Therefore, these plants do not incur incremental costs for
transport and disposal under the proposed rule. The EPA calculated the unit-level MDS capital
costs for plants operating CCR storage impoundments using the cost curve in Figure 5-25 below.
5-39
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Section 5—Engineering Costs
$60,000,000
— $50,000,000
.***
00	J'*
O $40,000,000
o $30,000,000
¦¦a $20,000,000
Q-
,-r
$10,000,000
$0
0	300	600	900 1,200 1,500
Generating Unit Capacity (MW)
MDS Capital Cost Excluding Transport/Disposal (2018S) =33,500 *
Generating Unit Capacity + 5,004,227
Figure 5-25. MDS Capital Cost Curve - Excluding Transport/Disposal
The EPA estimated MDS O&M costs for plants operating CCR impoundments for bottom ash
storage using the average compliance cost from the 2015 rule Equation 5-12.
MDS O&M Cost Excluding Transport/Disposal (2018$/yr) = $534,000
Equation 5-12
In addition, plants that currently discharge bottom ash transport water to a POTW receive a cost
savings for eliminating bottom ash transport water discharges and ceasing discharges to the
POTW. The EPA identified two plants from the Steam Electric Survey data that discharge
bottom ash wastewater to a POTW and are expected to install an MDS. Using the POTW-
specific rate structures, the EPA estimated the annual costs incurred by these plants for
discharging to a POTW and deducted these annual costs (ERG, 2019i).
For each generating unit, the EPA selected the MDS capital and O&M cost curves based on the
identified bottom ash transportation and disposal method at the plant using the landfill data
described in Section 5.3.1. The EPA calculated the MDS capital and O&M compliance costs
using the generating-unit-specific data and corresponding equations.
Recurring Costs
The EPA estimated 3-year recurring costs associated with MDS drag chain replacement. The
drag chain is the component of the system that drags the bottom ash from the water bath, up the
incline to intermediate storage. Based on vendor data, this chain should be replaced every three
years and costs approximately $206,000. See Equation 5-13.33
33 The generating unit can continue to operate during replacement of the drag chain components.
5-40
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Section 5—Engineering Costs
MDS 3-Year Cost (2018$) = $206,000
Equation 5-13
The EPA calculated plant-level MDS costs by summing the MDS capital, MDS O&M, and 3-
year recurring costs for all units at each plant.
5.3.3 Cost Methodology for Remote Mechanical Drag Systems Operated to Achieve Zero
Discharge (No Purge)
The EPA estimated capital, O&M, and 5-year recurring costs associated with installing a rMDS
for all plants except those currently operating an rMDS system. The EPA used cost data from the
2015 rule to develop capital cost curves for on-site and off-site disposal as a function of
generating unit capacity. The EPA developed O&M cost curves for on-site and off-site transport
and disposal as a function of the amount of wet bottom ash produced. The EPA also developed a
separate set of cost curves for those plants currently operating a storage impoundment for their
bottom ash, rather than a disposal impoundment. Plants with storage impoundments periodically
dredge the impoundment to remove the ash and haul it away for disposal or beneficial use, rather
than leaving the bottom ash in the impoundment for long-term disposal. Because these plants
with storage impoundments already incur transport and disposal costs as part of their current ash
handling practices, see Table 5-8, the rMDS cost curves for these plants do not include
incremental transport and disposal costs.
The rMDS capital cost curves account for the purchase and installation of the rMDS unit
equipment, a semi-dry bottom ash intermediate storage silo, a chemical feed system to control
recycle pH and suspended solids, and recycle pumps. The capital cost curves include the
following components:
•	Direct Capital Costs.
-	Purchased equipment (including fabricated equipment and process
machinery).
-	Freight.
-	Purchased equipment installation.
-	Instrumentation and controls (installed).
-	Piping (installed).
-	Electrical (installed).
-	Buildings (including services).
-	Yard improvements.
-	Service facilities (installed).
-	Land (if purchase is required).
•	Indirect Capital Costs.
-	Engineering and supervision.
5-41
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Section 5—Engineering Costs
-	Construction expenses.
-	Contractor's fees.
-	Contingency.
The rMDS O&M cost curves account for the operation and maintenance of the rMDS,
intermediate storage, and the cost to purchase acid or caustic for the chemical feed system for pH
control. The chemical feed system could also be used to add polymers to enhance removal of
suspended solids, if warranted. The rMDS O&M cost curves include the following components:
•	Conveyance Costs.
-	Operating labor.
-	Maintenance materials and labor.
-	Energy.
•	Chemical Purchase Cost.
•	Intermediate Storage Costs.
-	Operating labor.
-	Maintenance materials and labor.
-	Energy.
•	5-year maintenance cost associated with the wear-plate.
Plant-Level Capital and O&M Cost for Remote Mechanical Drag Systems
Using the 2015 rule cost data and the bottom ash production data, the EPA generated cost curves
for estimating unit-level rMDS capital and O&M costs as a function of unit-level capacity and
unit-level bottom ash production, respectively. Because costs are affected by the solids disposal
location (i.e., on-site landfill or off-site transportation and disposal), the EPA generated a set of
cost curves for each transportation and disposal method (see Figure 5-26 and Figure 5-28 for
capital costs and Figure 5-27 and Figure 5-29 for O&M costs).
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Section 5—Engineering Costs
$50,000,000
00
s $40,000,000
(S	|
% $30,000,000
« $20,000,000
o
u
! $10,000,000
CL
CO
u
$0
0	300	600	900 1,200 1,500
Generating Unit Capacity (MW)
rMDS Capital Cost with On-site Transport/Disposal (2018S) = 26,242 x
Generating Unit Capacity +3,449,512
Figure 5-26. rMDS Capital Cost Curve - On-site Transport/Disposal
00
O
r~)
o
U
O
$3,000,000
$2,500,000
$2,000,000
$1,500,000
$1,000,000
$500,000
$0
20,000 40,000 60,000 80,000 100,000
Generating Unit Bottom Ash Tonnage (TPY)
rMDS O&M Cost with On-site Transport/Disposal (2018S/yr) = 17.671 x
Generating Unit Wet Bottom Ash Produced + 779,590
Figure 5-27. rMDS O&M Cost Curve - On-site Transport/Disposal
5-43
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Section 5—Engineering Costs

S30.000.000
S25.000.000






o

!.•*
#
e»
520,000,000

	1	1 1

K




S 15,000,000



J,



o
U
S 10,000,000






65
EL
55,000,000



r3




SO
(




200 4 00 600 S00
Generating Unit Capacity (MW)
1,000

rMDS Capital Cost with Off-site Transport/Disposal (2018S) =
Generating Unit Capacity + 3,653,540
23,796 *
Figure 5-28. rMDS Capital Cost Curve - Off-site Transport/Disposal
$6,000,000
$5,000,000
$4,000,000	I..'"''
$3,000,000
$2,000,000
$1,000,000
$0
0	20,000	40,000	60.000 80,000
Generating Unit Bottom Ash Tonnage (TPY)
rMDS O&M Cost with Off-site Transport/Disposal (2018$/yi) = 74.326 x
Generating Unit Wet Bottom Ash Produced + 794,285
Figure 5-29. rMDS O&M Cost Curve - Off-site Transport/Disposal
As stated previously in Section 5.3.2, plants currently operating a CCR impoundment already
incur costs for transporting and disposing bottom ash. Therefore, these plants do not incur
incremental costs for rMDS transport and disposal under the proposed rule. The EPA calculated
the unit-level MDS capital costs for plants operating CCR storage impoundments using the cost
curve in Figure 5-30 below.
£
CO
o
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Section 5—Engineering Costs
$40,000,000
% $30,000,000
o
ts
g $20,000,000
o
'§• $10,000,000
u
$0
0	300	600	900 1,200 1,500
Generating Unit Capacity (MW)
rMDS Capital Cost Excluding Transport/Disposal (2018$) = 23,874 *
Generating Unit Capacity + 3,548,689
Figure 5-30. rMDS Capital Cost Curve - Excluding Transport/Disposal
The EPA estimated rMDS O&M costs for plants operating CCR impoundments using the
average compliance cost from the 2015 rule (Equation 5-14).
Total rMDS O&M Cost Excluding Transport/Disposal (2018$/yr) = $804,000
Equation 5-14
For each generating unit in the costed population, the EPA selected the rMDS capital and O&M
cost curves based on the identified bottom ash transportation and disposal method at the plant
using the landfill data described in Section 5.3.1. The EPA calculated the rMDS capital and
O&M compliance costs using the generating unit-specific data and corresponding equations.
Additional Zero Discharge Costs
The cost methodology for all rMDS systems includes chemical addition equipment to manage
pH of the transport water so that potential corrosion or scaling is minimized, and to allow for
polymer addition if needed to enhance removal of suspended solids. For the zero discharge
technology option, the EPA has also estimated costs for plants to install more robust treatment
should it be necessary to prevent the buildup of dissolved solids to levels that may interfere with
effectively controlling corrosion and scale formation by the chemical addition processes. This
additional treatment entails the use of reverse osmosis to treat a slipstream of transport water.
The data in the record indicates that most plants would not experience such TDS-related
interferences or that managing alkalinity would resolve potential issues and obviate the need for
RO treatment. However, since the EPA does not have sufficient plant-specific data to determine
which plants may need RO treatment, the EPA's cost methodology assumes that all new and
current rMDS systems would install RO treatment to ensure the plant could manage the closed-
loop recycle for the bottom ash transport water.
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Section 5—Engineering Costs
The treated effluent from the RO unit is of higher quality than other makeup water sources used
at power plants; therefore, plants are likely to reuse the treated effluent within the bottom ash
handling system. Based on industry-provided data, the EPA estimated the daily slipstream flow
rate to be 10 percent of the primary active wet bottom ash system volume (i.e., the plant-level
volume associated with the bottom ash hoppers, rMDS, sluice pipes, and surge tanks, but not
installed spares, redundancies, maintenance tanks, or other secondary bottom ash system
equipment not used on a daily or near-daily basis).
The EPA identified the population of plants likely to install the rMDS system as those plants that
(1) have already installed rMDS; (2) previously provided information indicating that MDS is not
a viable retrofit option because of insufficient height under the boiler or other boiler house
impediment; or (3) the cost to install rMDS is lower than the cost for MDS. The EPA then
calculated the additional capital costs (including equipment, instrumentation, and installation)
and O&M costs associated with the handling and treatment of a recycled slipstream at the plant
level using Equation 5-15 and Equation 5-16. The EPA calculated these additional costs at the
plant level because plants with multiple rMDS units will treat all bottom ash transport water
slipstreams generated at the plant with one treatment system (ERG, 2019i)
Additional Zero Discharge rMDS Capital Costs = Total RO Capital Costs + Total
Tank/Pipe/Pump Capital Costs
Equation 5-15
Additional Zero Discharge rMDS O&M Costs = Total RO O&M Costs + Total Tank/Pipe/Pump
O&M Costs
Equation 5-16
RO Capital and O&M Costs
To calculate the plant-level RO capital and O&M costs, the EPA first estimated the total volume
of the rMDS systems expected to be operating at the plant, based on the plant-level capacity and
information provided by the industry (ERG, 2019i). For plants with a total capacity less than or
equal to 200 MW, the EPA estimated a total rMDS volume of 175,000 gallons. For plants with a
total generating capacity greater than 200 MW, the EPA estimated total rMDS volume using
Equation 5-17.
Total rMDS Volume (gal) = 347.29 x Plant-Level Capacity (MW) + 146,398
Equation 5-17
Where:
Plant-Level Capacity = The sum of all plant generating unit capacities flagged for
bottom ash compliance costs (in MW).
Based on information provided by industry, the EPA estimated the daily flow of the slipstream
sent to RO treatment prior to recycle to be 10 percent of the total rMDS volume (Equation 5-18).
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Section 5—Engineering Costs
Slipstream Flow (GPM) = (Total rMDS Volume x 0.1/day) / 24 hr /day /
60 min/hr
Equation 5-18
Where:
Total rMDS Volume	= Total volume of all rMDS expected to be operating
the plant (in gallons).
The EPA estimated plant-level RO capital and O&M costs as a function of the slipstream flow
rate using the Equation 5-19 and Equation 5-20.
Total RO Capital Cost (2018$) = 58,838 x Slipstream Flow (GPM) + 2, 298,650
Equation 5-19
Total RO O&M Cost (2018$) = $0.01 x Slipstream Flow x 60 minutes/hour x 24 hr/day x 365
days/year
Equation 5-20
Where:
Slipstream Flow	= Daily flow rate of rMDS slipstream (in GPM) (see Equation
5-18).
The EPA then assigned a portion of the total RO capital and O&M costs to each generating unit
by multiplying the plant-level costs by the ratio of generating unit capacity to plant-level
capacity in MW.
Surge Tank, Pipe, and Pump Costs
The EPA estimated the total capital costs associated with operating the surge tank, pumps, and
piping needed to hold and recirculate RO distillate, or any bottom ash transport water from a
maintenance or precipitation event, back to the plant for reuse, based on the 2015 rule cost
methodology or information provided by tank vendors, using Equation 5-21 and Equation 5-22.
Total Tank/Pipe/Pump Capital Costs = Total Purchased Equipment Cost + Direct Capital Costs +
Indirect Capital Costs
Equation 5-21
Total Purchased Equipment Costs = Tank Cost + Pipe Cost + Pump Cost
Equation 5-22
The EPA estimated the surge tank purchased equipment costs using the relationship between
tank size and cost, developed from vendor-provided data, and adjusted the cost basis from 2011
dollars to 2018 dollars using RSMeans Historical Cost Indices (Gordian, 2018).
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Section 5—Engineering Costs
To estimate tank cost, the EPA first estimated the size of the required surge tank using Equation
5-23. Tank size is based on the largest generating unit at the plant (defined by capacity in MW)
and the expectation that only one generating unit will need to empty the bottom ash hopper at
any one time. The EPA also accounted for an additional 50 percent capacity for the surge tank by
multiplying the relationship by a tank sizing factor of 1.5.
Tank Size (gallons) = 63 x Unit Capacity x Tank Sizing Factor
Equation 5-23
Where:
Unit Capacity	= Capacity of the generating unit (in MW).
Tank Sizing Factor = 1.5.
The EPA then estimated the cost as a function of tank size based on information provided by
tank vendors. For tanks less than 50,000 gallons in size, see Equation 5-24.
Tank Cost (2018$) = (2.16 x Tank Size + 22.7 x (Tank Size x 1.5) °-548) x (20 1 8 Cost Index /
2011 Cost Index)
Equation 5-24
Where:
Tank Size	= Size of the surge tank (in gallons)
2011 Cost Index = 185
2018 Cost Index = 215.8
For tanks greater than 50,000 gallons in size, see Equation 5-25:
Tank Cost (2018$) = (3.45 x Tank Size + 22.7 x (Tank Size x 1.5) °-548)
(2018 Cost Index / 2011 Cost Index)
Equation 5-25
Where:
Tank Size	= Size of surge tank (in gallons)
2011 Cost Index = 185
2018 Cost Index = 215.8
The EPA developed a relationship between pump equipment costs and bottom ash slipstream
flow, using vendor-provided information, to estimate plant-specific pump costs, then adjusted the
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Section 5—Engineering Costs
cost basis from 2011 dollars to 2018 dollars using RSMeans Historical Cost Indices (Gordian,
2018). Pump costs include the cost of four pumps: one to pump water from the hopper to the
tank plus one spare, and one to return water back to the hopper plus one spare.
The EPA first estimated the flow from the surge tank using Equation 5-26.
Flow = Tank Size / (60 min/hr x 5 hrs/day)
Equation 5-26
Where:
Tank Size	= Size of the surge tank (in gallons).
The EPA then calculated the pump as a function of this flow, using Equation 5-27.
Pump Cost (2018$) = (2,940 x In (Flow) - 1,957) x 4.16 x (2018 Cost Index / 2011 Cost Index)
Equation 5-27
Where:
2011 Cost Index = 185.
2018 Cost Index = 215.8.
Flow	= Tank size (in gallons).
The EPA estimated the cost of 2,640 feet of piping using an assumed distance of 0.25 miles
between the surge tank and bottom ash hopper: $37,000 (2018$).
The EPA estimated the total plant-level direct capital costs by multiplying the sum of the
purchased equipment costs for the tank, pumps, and piping by 2, using Equation 5-28.
Direct Capital Costs = 2 x Total Purchased Equipment Cost
Equation 5-28
The EPA estimated the indirect capital costs by multiplying the sum of the total purchased
equipment and direct capital costs by 0.43, using Equation 5-29.
Indirect Capital Costs = 0.43 x (Total Purchased Equipment Cost + Direct Capital Costs)
Equation 5-29
The EPA calculated plant-level O&M costs associated with operating the surge tank, pumps, and
pipe. Total O&M costs include the cost of energy to operate the pumps and the maintenance cost
associated with the surge tank, pumps, and pipes.
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Section 5—Engineering Costs
Total Tank/Pump/Pipe O&M Costs = Energy Cost + Maintenance Cost
Equation 5-30
To calculate the energy cost, the EPA first estimated the annual energy requirement to operate
the pumps, based on the 2015 rule cost methodology, using Equation 5-31.
Annual Energy Requirement (kWh/yr) = 145 x Flow + 13,200
Equation 5-31
Where
Flow = Daily flow rate from the surge tank (in GPM) (see Equation 5-26).
The EPA then estimated the cost of operating the pumps using the pump energy requirement and
the national energy cost per kWh, based on data reported by the U.S. Energy Information
Administration (EIA) (U.S. DOE, 2011), in 2018 dollars, using Equation 5-32.
Energy Cost (2018$) = National Energy Cost x Annual Energy Requirement
Equation 5-32
Where:
Annual Energy Requirement = Annual energy requirement to operate
pumps (in kWh/yr) (see Equation 5-31).
National Energy Cost	= $0.0485/kWh (in 2018$).
The EPA developed a relationship between bottom ash slipstream flow and the cost to maintain
the surge tank, pumps, and piping to estimate total maintenance costs.
Maintenance Cost (2018$) = 457 x Flow
Equation 5-33
Where:
Flow = Daily flow rate from the surge tank (in GPM) (see Equation 5-26).
Recurring Costs
The EPA estimated 5-year recurring costs associated with rMDS drag chain replacement. The
drag chain is the component of the system that drags the bottom ash from the water bath, up the
incline to intermediate storage; based on vendor data this chain should be replaced every five
years and costs approximately $206,000 (Equation 5-34).
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Section 5—Engineering Costs
rMDS 5-Year Cost (2018$) = $206,000
Equation 5-34
The EPA calculated plant-level MDS costs by summing the rMDS capital, rMDS O&M, and 5-
year recurring costs for all units at each plant.
5.3.4	Cost Methodology for Remote Mechanical Drag Systems Operated with a
Purge
As discussed in Section 5.3.3 above, the EPA estimated capital, O&M, and 5-year recurring
costs associated with installing an rMDS for all plants except those currently operating an rMDS
system. The EPA anticipates that operating rMDS with a purge stream, rather than as zero
discharge, will prevent plants from experiencing a buildup of dissolved solids to levels that may
interfere with effective corrosion and scale control, and subsequently, the need for RO treatment
of a slipstream. Therefore, to estimate compliance costs for the purge option, the EPA included
all zero discharge option rMDS costs except costs classified as additional zero discharge costs
(see Additional Zero Discharge Costs). The EPA included all capital and O&M costs (see Plant-
Level Capital and O&M Cost for Remote Mechanical Drag Systems) as well as recurring costs
(see Recurring Costs) associated with rMDS for this option.
5.3.5	Bottom Ash Management Cost Methodology
The EPA identified several plants that operate bottom ash wet-sluicing systems as closed-loop
systems. These plants did not report any discharge of bottom ash transport water in the Steam
Electric Survey. However, based on other information in the survey responses, the EPA
determined that these plants have retained the capability to discharge bottom ash transport water
from emergency outfalls. Therefore, the EPA estimated additional costs associated with
eliminating the potential future discharge of bottom ash transport water, which survey data
confirm is not typical practice. The EPA estimated a one-time cost associated with consulting an
engineer to eliminate the need and the capacity to discharge bottom ash transport water via
emergency outfalls—thereby achieving a completely closed bottom ash recycle system. The one-
time cost includes contractor labor and travel. For each bottom ash management plant, the EPA
estimated a one-time cost of $26,400, in 2018 dollars.
In addition to one-time costs, the EPA estimated capital and O&M costs for a chemical feed
system. This additional cost was estimated (although it may not be needed) so that plants would
have a system in place to regulate pH of the recycled bottom ash transport water. Using the 2015
rule cost data and EPA's methodology for estimating rMDS chemical feed system costs, the EPA
estimated capital and O&M costs associated with operating a chemical feed system at bottom ash
management plants and converted the cost to 2018 dollars.
5.3.6	Bottom Ash BMP Plan Cost Methodology
For plants operating one or more units with a 2016 EIA net generation of less than or equal to
876,000 MWh, the EPA estimated costs associated with the development and implementation of
a BMP plan to recycle as much bottom ash transport water determined to be achievable. These
costs include (1) the initial development of the BMP plan, (2) capital and operation and
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Section 5—Engineering Costs
maintenance (O&M) costs for pumps and piping associated with any recirculation, and (3) the
annual review of and revision to the BMP plan.
One-time Costs
The EPA calculated the one-time cost for developing the BMP plan using Equation 5-35. The
one-time cost includes the cost of an outside contractor34 reviewing current operations and
developing a BMP plan, which includes four weeks on site at the plant, and plant review and
acceptance of plan.
BMP Plan One-Time Cost (2018$) = Contractor Labor Cost
+ Contractor Travel Cost + Plant Review Cost
Equation 5-35
Contractor Labor Cost (2018$) = Number of Hours
x Contractor Rate = $33,600
Equation 5-36
Where:
Number of Hours = EPA estimated number of hours for the contractor to
develop the BMP plan, 280 hours.
Contractor Rate = EPA estimate of the contractor rate, $120/hr (in 2018$).
Contractor Travel Cost (2018$) = (Number of Travel Days x Hotel Cost x Escalation Rate) +
(Number of Travel Days x Food Cost) + (Number of Travel Weeks x Car Rental Cost) +
(Number of Trips x Airfare Costs) = $6,549
Equation 5-37
Where:
Number of Travel Days = Number of work days in a four-week period, 24 days.
Hotel Cost	= The 2018 federal per diem rate for hotels based on
standard continental United States (CONUS) rates,
$93/day (in 2018$).
Escalation Rate	= An escalation factor to account for potential increases
in hotel costs based on location and hotel taxes, 1.40
(i.e., 25 percent for potential increases, 15 percent for
hotel taxes).
34 Some plants may incur different costs by using company environmental or operations staff instead of an outside
contractor. For the purpose of this cost methodology, the EPA assumed that plants would incur costs associated with
an outside contractor.
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Section 5—Engineering Costs
Food Cost
The 2018 federal per diem rate for meals and
incidentals based on standard CONUS rates, $51/day
(in 2018$).
Number of Travel Weeks = Number of weeks on site, 4.
Car Rental Cost
Number of Trips
Airfare Costs
= Estimate of a full-size rental car cost per week, $250
(in 2018$).
= Estimated number of trips required, 2.
= Estimate of the round-trip airfare for the contractor to
travel to the plant, $600 (in 2018$).
Plant Review Cost (2018$) = Number of Hours x Environmental Coordinator Labor Rate =
$2,091
Equation 5-38
Where:
Number of Hours
Environmental Coordinator
Labor Rate
= EPA estimated number of hours for the plant to
review and accept the plan, 48 hours.
= $43.56/hr (in 2018$).
Capital Costs for Piping and Pumps
The EPA calculated the capital and O&M costs associated with piping and pumps to
accommodate recycling bottom ash transport water from the bottom ash impoundment or
dewatering bins back to the bottom ash sluicing system. For the purpose of the BMP cost
estimate, the EPA calculated average capital and O&M costs using Equation 5-39.
Total Recycle Equip Capital (2018$) = Total Pipe Capital Costs (2018$) + Total Pump Capital
Costs (2018$) = $295,200
Equation 5-39
The EPA assumed that 2,472 feet of piping are required (based on the average distance bottom
ash transport water was sluiced to an impoundment reported in the Steam Electric Survey) and
calculated the median piping costs to be $148,700 (2018$).
The EPA assumed that two pumps are required, one for pumping the water from the bottom ash
impoundment back to the bottom ash sluice system, and one for redundancy. Based on the
maximum bottom ash sluice flow rates within steam electric power generating industry
population, the EPA calculated a pump capital cost of $146,500 (2018$).
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Section 5—Engineering Costs
The EPA estimated the total annual O&M costs associated with pumping the bottom ash
transport water back to the bottom ash sluice system. Only one pump will be operating at a time
and calculated a total recycled equipment O&M cost of $2,200 (2018$) per year.
Annual Costs for BMP Review
The EPA calculated the annual costs associated with reviewing the BMP plan and making any
updates or revisions to the plan, as necessary. The annual costs include the cost of an outside
contractor reviewing the BMP and incorporating revisions, which includes a one-day site visit to
the plant, and plant review and acceptance using Equation 5-40.
BMP Plan Annual Cost (2018$/yr) = Annual Contractor Labor Cost
+ Annual Contractor Travel Cost + Plant Annual Review Cost
Equation 5-40
Annual Contractor Labor Cost (2018$/yr) = Number of Hours x Contractor Rate = $4,800
Equation 5-41
Where:
Number of Hours = EPA estimated number of hours for the contractor to
complete the BMP, 40.
Contractor Rate = EPA estimate of the contractor rate, $120/hr (in 2018$).
Annual Contractor Travel Cost (2018$/yr) = (Number of Travel Days x Hotel Cost x Escalation
Rate) + (Number of Travel Days x Food Cost) + (Number of Travel Weeks x Car Rental Cost) +
(Number of Trips x Airfare Costs) = $831
Equation 5-42
Where:
Annual Contractor Travel =
Cost
Number of Travel Days =
Hotel Cost	=
Escalation Rate	=
5-54
The annual travel cost for a contractor to visit the plant
to review the BMP Plan once per year.
Number of work days required for travel, 1 day.
The 2018 federal per diem rate for hotels based on
standard continental United States (CONUS) rates,
$93/day (in 2018$).
An escalation factor to account for potential increases
in hotel costs based on location and hotel taxes, 1.40
(i.e., 25 percent for potential increases, 15 percent for
hotel taxes).
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Section 5—Engineering Costs
Food Cost
The 2018 federal per diem rate for meals and
incidentals based on standard CONUS rates, $51/day
(in 2018$).
Number of Travel Weeks = Number of weeks on-site, 0.2.
Car Rental Cost
Number of Trips
Airfare Costs
= Estimate of a full-size rental car cost per week, $250
(in 2018$).
= Estimated number of trips required, 1.
= Estimate of the round-trip airfare for the contractor to
travel to the plant, $600 (in 2018$).
Plant Annual Review Cost (2018$/yr) = Number of Hours x Environmental Coordinator Labor
Rate = $697
Where:
Plant Annual Review Cost
Number of Hours
Environmental Coordinator
Labor Rate
Equation 5-43
= The annual cost for the plant to review the BMP
plan annually (in 2018$ per year).
= EPA estimated annual number of hours for the
plant to review the plan, 16 hours.
= $43.56/hr (in 2018$).
5.3.7 Methodology for Estimating Cost Savings from Ceasing Use of Surface
Impoundments
When plants install bottom ash handling systems that no longer require the use of surface
impoundments, they will experience some cost savings associated with ceasing operations of
these bottom ash surface impoundments). This decrease in impoundment operations costs will
offset the cost to operate the new treatment system, to some degree. The EPA estimated the
annual O&M and recurring costs associated with on-site impoundments and subtracted these
costs from the estimated compliance costs for the technologies described above in this section,
consistent with the 2015 methodology. The impoundment operating cost savings quantified by
the EPA include costs associated with the following:
•	Wastewater transport system (i.e., pipelines, vacuum source) pumping the
wastewater from the bottom ash hopper to the impoundment.
•	Impoundment site (i.e., general operation of the impoundment and inspections).
•	Wastewater treatment system (e.g., pH control).
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Section 5—Engineering Costs
•	Water recycle system at the impoundment (if applicable).
•	Bottom ash earthmoving costs (e.g., front-end loader, removing/stacking
combustion residual materials at the impoundment site).
The EPA used Steam Electric Survey data to identify plants that have at least one impoundment
containing bottom ash transport wastewater and not designated as retired or planned. Where the
EPA had data indicating plants had installed a dry or closed-loop bottom handling systems since
the 2015 rule, the EPA anticipated these plants no longer operate an impoundment for bottom
ash handling. The EPA also anticipates that plants whose impoundments are expected to close
due to CCR rule requirements will not use impoundments for bottom ash handling. The EPA
estimated plant-level costs for operating impoundments based on the total amount of bottom ash
solids currently handled wet at the plant. The EPA estimated the total bottom ash impoundment
O&M cost savings using Equation 5-44.
Total Bottom Ash Impoundment O&M Cost Savings (2018$/yr) = (Bottom Ash Impoundment
Operating Cost Savings + Bottom Ash Earthmoving Cost Savings) x (2018 Cost Index / 2010
Cost Index)
Equation 5-44
Where:
Bottom Ash Impoundment
Operating Cost Savings
Bottom Ash Earthmoving
Cost Savings
= Total impoundment operating cost savings (in 2010$)
see Equation 5-47.
= O&M cost associated with the earthmoving equipment
required (in 2010$) see Equation 5-49.
2010 Cost Index
= 183.5.
2018 Cost Index	= 215.8.
Bottom Ash Impoundment Operating Annual Cost Savings
The EPA estimated the bottom ash impoundment operating cost savings by first calculating the
plant MW factor using Equation 5-45 and the plant-specific unitized cost using Equation 5-46.
Plant MW Factor = 7.569 x (Plant Size)"0 32
Equation 5-45
Where:
Plant Size = Plant size (in MW). The plant nameplate capacity for only those
generating units in the bottom ash costed population.
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Section 5—Engineering Costs
Plant-Specific Unitized Cost = (Impoundment Operating Unitized Cost) x
(Plant MW Factor)
Equation 5-46
Where:
Plant-Specific Unitized Cost = The plant-specific cost to operate a front-end loader (in
2010$/ton).
Impoundment Operating = The 2010 unitized annual cost to operate a combustion
Unitized Cost	residual impoundment. The EPA used the unitized cost
value $7.35 per ton (in 2010$).
Plant MW Factor	= Factor to adjust combustion residual handling costs
based on plant capacity.
Next, the EPA calculated the bottom ash impoundment operating cost savings by multiplying the
plant-specific unitized cost using Equation 5-47 by the amount of bottom ash tonnage produced
by the plant tons per year (TPY), discussed in Section 5.3.1.
Bottom Ash Impoundment Operating Cost Savings (2010$/yr) = (Plant-Specific Unitized Cost) x
(Plant Bottom Ash Tonnage)
Equation 5-47
Where:
Plant-Specific Unitized = The plant-specific cost to operate a front-end loader (in
Cost	2010$/ton).
Plant Bottom Ash Tonnage = The total bottom ash tonnage, dry basis, for each plant
(in TPY). This value is calculated by multiplying the
wet bottom ash generation rate (in TPY) for each
generating unit, and then summing the generating unit-
level values to the plant level.
Bottom Ash Earthmoving Annual Cost Savings
To calculate bottom ash earthmoving cost savings, the EPA first calculated the plant-specific
front-end loader unitized cost by multiplying the plant MW factor and the front-end loader
unitized cost using Equation 5-48.
5-57
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Section 5—Engineering Costs
Plant-Specific Front-End Loader Unitized Cost (2010$/ton) =
(Front-End Loader 2010 Unitized O&M Cost) x (Plant MW Factor)
Equation 5-48
Where:
Front-End Loader 2010 = The 2010 unitized cost value that represents the
Unitized O&M Cost	operation and maintenance of the front-end loader used
to redistribute ash at an impoundment. This value was
calculated to be $2.49 per ton (in 2010$).
Plant MW Factor	= Factor to adjust combustion residual handling costs
based on plant capacity.
Next, the EPA calculated the bottom ash earthmoving cost savings by multiplying the plant-
specific unitized cost using Equation 5-49 by the amount of bottom ash tonnage produced by the
plant in TPY discussed in Section 5.3.1.
Bottom Ash Impoundment Earthmoving Cost Savings = (Plant-Specific Front-End Loader
Unitized Cost) x (Plant Bottom Ash Tonnage)
Equation 5-49
Where:
Plant Bottom Ash Tonnage = The total bottom ash tonnage, dry basis, for each plant
(in TPY). This value is calculated by multiplying the
wet bottom ash generation rate in TPY for each
generating unit, and then summing the generating-unit-
level values to the plant level.
Bottom Ash Earthmoving Recurring Costs
The EPA calculated 10-year recurring costs associated with operating the earthmoving
equipment (i.e., front-end loader) by determining the cost and average expected life of a front-
end loader. The EPA determined the 2018 cost of the earthmoving equipment to be $474,000 and
assumed that the expected life of a front-end loader is 10 years.
5.4 Summary of National Engineering Cost for Regulatory Options
As described in the preamble, the EPA evaluated four regulatory options comprising various
combinations of the treatment technologies considered for control of each wastestream. The EPA
estimated different compliance costs for steam electric generating units with a specific steam
electric power generating capacity, generating units with a specific net power generation, and
"high-flow" FGD wastewater plants. In calculating the compliance cost estimates for each
regulatory option, the EPA considered the subcategorizations established by each option and
whether the plant may elect to participate in the voluntary incentive program (VIP) based on
5-58
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Section 5—Engineering Costs
annualized compliance costs of the technology options, as described in further detail in the
preamble.
To estimate total industry compliance costs for each regulatory option with subcategories, the
EPA first estimated plant-level FGD and bottom ash technology option compliance costs. The
EPA then estimated unit-level costs (including capital, O&M, 3-, 5-, 6-, and 10-year recurring
costs) using Equation 5-50.
Unit-Level Cost = Plant-Level Cost x (Unit-Level Capacity / Plant-Level Capacity)
Equation 5-50
Where:
Plant-Level Cost
Unit-Level Capacity
Plant-Level Capacity
Technology option plant-level cost in 2018$. Includes
capital, O&M, one-time, and recurring costs.
Unit-level generating nameplate capacity in MW (from
the Steam Electric Survey and 2016 Form EIA-860
data for new generating units).
Plant-level generating nameplate capacity in MW
(from Form EIA-860 data for 2016).
The EPA then summed the unit-level costs for only those units included in each regulatory
option to estimate total industry-level regulatory option costs. See the "Generating Unit-Level
Regulatory Option Costs and Loads Memorandum" for the FGD wastewater and bottom ash
transport water technologies selected as basis for each plant's regulatory option compliance cost
estimates (ERG, 2019j).
Table 5-9 and Table 5-10 present the total industry compliance cost estimates for FGD
wastewater and bottom ash transport water, respectively, by regulatory option. Table 5-11
presents the aggregated, industry-level compliance costs by regulatory option. All cost estimates
are expressed in terms of pre-tax 2018 dollars.
Table 5-9. Estimated Cost of Implementation for FGD Wastewater by Regulatory Option
[In millions of pre-tax 2018 dollars]
Ki'Uiihilon
Option
Nil in her
ol' I'liiiils
( iipiliil
Cosl
Aiimiiil
O&M Com
One-Time
CoMs
Keeiii'i'inu CoMs
3-\e;ir
5-\e;ir
(>-\e;ir
IO-\e;ir
Baseline
70
$1,770
$79.2
NA
NA
NA
$4.41
($14.2)
1
70
$675
$42.4
NA
NA
NA
$4.41
($14.2)
2
70
$934
$74.1
NA
NA
NA
$2.81
($14.2)
3
70
$948
$81.1
NA
NA
NA
$2.31
($14.2)
4
70
$1,500
$172
NA
NA
NA
$0,100
($14.2)
Note: Costs and cost savings are rounded to three significant figures.
NA: Not applicable.
a - The values in this column are negative, and presented in parentheses, because they represent cost savings.
5-59
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Section 5—Engineering Costs
Table 5-10. Estimated Cost of Implementation for Bottom Ash Transport Water by
Regulatory Option [In millions of pre-tax 2018 dollars]
Ke^iihilon
Option
Nil in her
(if PlillllS
( iipiliil
Cosl
Anniiiil
O&M Com
One-Time
Costs
Keen rrinu Cosls
3-u'sir
5-u'sir
(•-u'.ir
10-M'sir '
Baseline
94
$1,680
$96.1
$0,132
$1.03
$18.3
NA
($23.0)
1
94
$1,330
$80.4
$0,132
$1.03
$18.3
NA
($23.0)
2
94
$1,070
$53.5
$0,977
$0.00
$12.6
NA
($16.5)
3
94
$1,330
$80.4
$0,132
$1.03
$18.3
NA
($23.0)
4
94
$1,330
$80.4
$0,132
$1.03
$18.3
NA
($23.0)
Note: Costs and cost savings are rounded to three significant figures.
NA: Not applicable.
a - The values in this column are negative, and presented in parentheses, because they represent cost savings.
Table 5-11. Estimated Cost of Implementation by Regulatory Option
[In millions of pre-tax 2018 dollars]
Ke^nliilon
Option
Nil in her of
Phi ills
(iipiliil
Cosl
Anniiiil
O&M Cosl
One-1 inie
Cosls
Keen rrinu Cosls
3-\eiir
5-\eiir
(>-\enr
IO-\e;ir '
Baseline
116
$3,450
$175
$0,132
$1.03
$18.3
$4.41
($37.2)
1
116
$2,009
$123
$0,132
$1.03
$18.3
$4.41
($37.2)
2
116
$2,002
$128
$0,977
$0.00
$12.6
$2.81
($30.7)
3
116
$2,282
$162
$0,132
$1.03
$18.3
$2.31
($37.2)
4
116
$2,834
$252
$0,132
$1.03
$18.3
$0,100
($37.2)
Note: Costs and cost savings are rounded to three significant figures.
a - The values in this column are negative, and presented in parentheses, because they represent cost savings.
5.5 References
1.	Gordian. 2018. RSMeans Cost Index. (6 April). DCN SE06922.
2.	ERG. 2015. Eastern Research Group, Inc. Analytical Database for the Steam Electric
Rulemaking. (30 September). EPA-HQ-OW-2009-0819-5640.
3.	ERG. 2018. Eastern Research Group, Inc. Thermal Evaporation Cost Methodology
Memorandum. (20 November). DCN SE07098.
4.	ERG. 2019a. Eastern Research Group, Inc. FGD Cost Database. (9 July). DCN
SE07102.
5.	ERG. 2019b. Eastern Research Group, Inc. FGD Purge Flow Methodology. (8 July).
Memorandum. DCN SE07091.
6.	ERG. 2019c. Eastern Research Group, Inc. FGD Treatment in Place Memorandum. (8
July). DCN SE07092.
7.	ERG. 2019d. Eastern Research Group, Inc. Chemical Precipitation Cost Methodology
Memorandum. (15 August). DCN SE07093.
5-60
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Section 5—Engineering Costs
8.	ERG. 2019e. Eastern Research Group, Inc. LRTR Cost Methodology Memorandum.
(23 August). DCN SE07094.
9.	ERG. 2019f. Eastern Research Group, Inc. HRTR Cost Methodology Memorandum.
(20 August). DCN SE07095.
10.	ERG. 2019g. Eastern Research Group, Inc. Membrane Filtration Cost Methodology
Memorandum - NonCBI. (23 August). DCN SE07096.
11.	ERG, 2019h. Eastern Research Group, Inc. Bottom Ash Cost Calculation Database.
(August). DCN SE07151.
12.	ERG, 2019i. Bottom Ash Cost Methodology Memorandum (29 August). DCN
SE07099.
13.	ERG, 2019j. Eastern Research Group, Inc. Generating Unit-Level Regulatory Option
Costs and Loads Memorandum. (8 August). DCN SE07090.
14.	U.S. DOE. 2011. U.S. Department of Energy, Energy Information Administration
(EIA). Electric Power Annual 2009. Washington, D.C. (January). DCN SE02023.
15.	U.S. EPA. 2019. Regulatory Impact Analysis for Proposed Revisions to the Effluent
Limitations Guidelines and Standards for the Steam Electric Power Generating Point
Source Category (RIA). (October). DCN SE07400.
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Section 6—Pollutant Loadings and Removals
SECTION 6
POLLUTANT LOADINGS AND REMOVALS
This section discusses types and amounts of pollutants discharged by the steam electric power
generating industry, and the pollutant removals that would be achieved by the regulatory options
considered for flue gas desulfurization (FGD) wastewater and bottom ash transport water
discharges from steam electric power plants. The BAT/PSES regulatory options described in the
preamble comprise various combinations of treatment technologies for controlling pollutants in
each of these wastestreams. The regulations established by the 2015 rule remain codified in 40
CFR Part 423; the pollutant removals associated with the regulatory options for this proposed
rulemaking are the incremental change in loadings (pollutant increases or reductions) relative to
the loadings for plants to comply with the requirements of the 2015 rule. As such, the EPA is
presenting pollutant loadings for baseline and post-compliance, defined as follows:
•	Baseline Loadings. Pollutant loadings, in pounds per year, in FGD wastewater
and/or bottom ash transport water discharged to surface water or through publicly
owned treatment works (POTWs) to surface water under 2015 rule conditions.
For the proposed rule, the EPA estimates baseline pollutant loadings based on
plants installing the technologies selected as the BAT/PSES basis of the 2015 rule
(i.e., baseline assumes full compliance with the 2015 rule, accounting for the Coal
Combustion Residual (CCR) rule impacts).35
•	Post-Compliance Loadings. Pollutant loadings, in pounds per year, in FGD
wastewater and/or bottom ash transport water discharged to surface water or
through POTWs to surface water after full implementation of the proposed rule
technology options. The EPA estimates post-compliance pollutant loadings with
the expectation that all steam electric power plants subject to the requirements of
the proposed rule will install and operate wastewater treatment and pollution
prevention technologies equivalent to the technology bases for the regulatory
options.
•	Pollutant Removals. The difference between the baseline loadings and post-
compliance loadings for each regulatory option.
Section 6.1 describes the methodology the EPA used to estimate pollutant loadings and removals
for each of the technology options evaluated for the proposed rule. Sections 6.2 and 6.3 discuss
wastewater discharge flow rates and pollutant characteristics for effluent from FGD wastewater
treatment systems and for bottom ash transport water, respectively. Section 6.4 presents a
summary of the industry-level pollutant loadings and removals estimates for the regulatory
options evaluated by the EPA.
35 Sections 5.2.1 and 5.3.1 describe the EPA's methodology to account for CCR rule impacts in the costs and
pollutant loadings analyses for FGD wastewater and bottom ash transport water.
6-1
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Section 6—Pollutant Loadings and Removals
6.1 General Methodology for Estimating Pollutant Removals
For each plant discharging FGD wastewater and/or bottom ash transport water, the EPA
estimated plant-level pollutant loadings for baseline and each technology option discussed in the
preamble. For example, for any plant discharging FGD wastewater, the EPA calculated baseline
loadings (based on chemical precipitation followed by high residence time reduction
(CP+HRTR)) and post-compliance loadings associated with each technology evaluated for this
proposed rule (i.e., chemical precipitation, chemical precipitation followed by low residence time
reduction (CP+LRTR), and membrane filtration). For each of the pollutants identified in Table
6-1 for FGD wastewater and Table 6-2 for bottom ash transport water, the EPA estimated
pollutant loadings by multiplying the discharge pollutant concentration by a plant-specific
discharge flow rate to estimate the mass of pollutant discharged per year (in pounds/year).
The EPA used data collected for the 2015 rule, as well as the data described in Section 2, to
characterize pollutant concentrations for FGD wastewater and bottom ash transport water. The
EPA evaluated these data sources to identify analytical data that meet the EPA's acceptance
criteria for inclusion in analyses for characterizing discharges of FGD wastewater and bottom
ash transport water. The EPA's acceptance criteria for both FGD wastewater and bottom ash
transport water characterization data are listed below:
•	Sample locations must be unambiguous and clearly described such that the
sample can be categorized as FGD wastewater or bottom ash transport water and
level of treatment (e.g., untreated, partially treated).
•	Analytical data must provide sufficient information to identify units of measure
and determine usability in the EPA's analyses.
•	Analytical data must represent individual sample results rather than average
results representing multiple plants or plant-specific long-term averages.36
•	Analytical data must not be duplicative of other accepted data.
•	Sample analyses must be completed using accepted analytical methods.37
•	Nondetect results were not accepted if no detection or quantitation limit was
provided.
•	Sample results must represent total results for a pollutant (i.e., dissolved results
were not accepted except for total dissolved solids (TDS)).
•	For biphasic samples, sample analysis must provide results for both phases.
In addition to those noted above, the EPA reviewed all FGD wastewater data sets to confirm that
the samples were representative of a BAT treatment system collected during typical plant
operations. See "Development Memo for FGD Wastewater Data in the Analytical Database" for
36	Where individual sample results and plant-level average sample concentrations were both available for a dataset,
the EPA preferentially used the individual sample results.
37	See the memorandum titled "Development of the Bottom Ash Transport Water Analytical Dataset and Calculation
of Pollutant Loadings for the Steam Electric Effluent Guidelines Proposed Rule" (ERG, 2019a) for a list of the
EPA's accepted analytical methods.
6-2
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Section 6—Pollutant Loadings and Removals
more specific details on the acceptance criteria used to generate EPA's FGD analytical data set
(ERG, 2015a).
Data for bottom ash transport water are typically collected from surface impoundments that
receive multiple wastestreams and these different wastestreams have the potential to dilute or
otherwise alter the characteristics of the impoundment effluent. Because of this, the EPA's
additional acceptance criteria specific to bottom ash transport water samples include:
•	Sample must be at least 75 percent by volume bottom ash transport water and not
include any contribution of fly ash transport water.
•	Sample must be representative of actual bottom ash surface impoundment effluent
collected during full-scale, typical plant operations.38
To ensure analytical data are representative of FGD wastewater or bottom ash transport water,
the EPA excluded data that did not meet the acceptance criteria and, therefore, were not useable
in pollutant loadings. Sections 6.2.1 and 6.3.1 present the average discharge pollutant
concentrations for baseline and each technology option evaluated for FGD wastewater and
bottom ash transport water, respectively.
For each plant discharging FGD wastewater or bottom ash transport water, the EPA used data
from the Steam Electric Survey (ERG, 2015b) and/or industry-submitted data to determine the
discharge flow rates for FGD wastewater and bottom ash transport water, and the corresponding
contribution from each individual steam electric generating unit. 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
3, that will eliminate or alter the discharge of an applicable wastestream.39 Finally, the Agency
adjusted the discharge flow rates to account for changes in plant operations impacted by the CCR
rule. For FGD wastewater, loadings were estimated using the optimized FGD flow rate described
in Section 5.2.1; that section also describes how the EPA accounted for the CCR rule. Section
5.3.1 describes the development of bottom ash transport water discharge flow rates and how the
EPA accounted for the CCR rule.
38	The EPA did not accept simulated surface impoundment effluent (i.e., settled ash sluice) samples or samples
collected from ash-settling tests conducted in a column for characterization of bottom ash transport water. Data
provided by industry has shown that these simulated samples are not good surrogates for characterizing the pollutant
concentrations in effluent from surface impoundments. The surface impoundment may also receive other types of
wastewater (e.g., low volume wastewaters, cooling water).
39	The EPA determined that baseline and post-compliance pollutant loadings are equal to zero for steam electric
generating units that announced plans to retire, convert to a non-coal fuel source, or change/upgrade ash handling
practices by the time the steam electric generating units are required to meet the requirements of the proposed rule.
See the memorandum titled "Changes to Industry Profile for Coal-Fired Generating Units for the Steam Electric
Effluent Guidelines Proposed Rule" (ERG, 2019b) for a list of the plants and generating units that were identified as
retiring, converting to a non-coal fuel, or changing/upgrading ash handling practices.
6-3
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Section 6—Pollutant Loadings and Removals
The EPA calculated baseline and post-compliance pollutant loadings for each plant discharging
FGD wastewater or bottom ash transport water using the following equation:
Loadingpoiiutant (lb/year) = Flow Rate x Discharge Days x Concpoiiutant x (2.20462 lb/109 |ig) x
(1000 L/264.17 gallons)
Equation 6-1
Where:
Flow Rate	= The reported flow rate of the wastestream being discharged, in
gallons per day from the plant.
Discharge Days = The number of days per year the wastestream is discharged
from the plant.
Concpoiiutant	= The concentration of a specific pollutant present in the
wastestream, in micrograms per liter (|ig/L).
The EPA calculated pollutant removals (i.e., the change in pollutant loadings) for each plant by
subtracting the baseline loadings from the post-compliance loadings from the baseline loadings,
as shown in the following equation:40
RemOValpollutant (lb/year) Loadingpost-compliance — Loadingbaseline
Equation 6-2
Where:
Loadingbaseline	= The estimated pollutant loadings discharged for a specific
pollutant for the baseline technology option, in pounds per
year.
Loadingpost-compliance = The estimated pollutant loadings discharged for a specific
pollutant for the post-compliance technology option, in pounds
per year.
The EPA identified several plants that reported transferring wastewater to a POTW rather than
discharging directly to surface water. For these plants, the EPA adjusted the baseline and post-
compliance loadings to account for pollutant removals expected during treatment at the POTW
for each pollutant. The 2015 TDD presents the percent removals expected from well-operated
POTWs. The EPA used the following equation to adjust baseline and post-compliance loadings
estimates for each pollutant to account for removals achieved by the POTW:
40 Where post-compliance discharge loadings are greater than baseline loadings, the pollutant removals are presented
as a negative value (indicating a decrease in pollutant removals relative to baseline).
6-4
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Section 6—Pollutant Loadings and Removals
LOcldingpollutant indirect (1 by Cell) [ . Ocld i n Upol I ulanl x (1 Removal POTw)
Equation 6-3
Where:
LOcldingpollutant
Removal potw
6.2 FGD Wastewater
The EPA has identified 70 coal-fired power plants that operate wet FGD systems and discharge
the FGD wastewater to surface water or to a POTW, and that are not expected to retire or convert
to a non-coal fuel source by December 31, 2028. For these plants, the EPA estimated pollutant
loadings for baseline conditions (based on implementation of CP+HRTR or, for those plants
where it is already in operation, more advanced treatment such as evaporation) and for the three
technologies evaluated as the potential basis for FGD wastewater discharge requirements:
chemical precipitation, CP+LRTR, and membrane filtration for the pollutants determined to be
present in FGD wastewater (see Table 6-1). These technologies form the basis for the regulatory
options presented in the preamble.
Section 6.2.1 identifies the pollutants present in FGD wastewater and the estimated
concentrations at which they are found in the effluent from the treatment technologies evaluated
for the regulatory options. Section 6.2.2 discusses the flow rates used in combination with the
pollutant concentration data to estimate pollutant removals for the plants that discharge FGD
wastewater. Section 6.2.3 describes the calculations used to estimate pollutant loadings for
baseline and each technology option.
6.2.1 Pollutants Present in FGD Wastewater
For the proposed rule, the EPA used the analytical data set that was used to characterize pollutant
concentrations in FGD wastewater for the 2015 rule. The EPA supplemented the 2015 data set
with additional pollutant concentration data regarding the presence of bromide in FGD
wastewater and treatment system performance data associated with CP+LRTR and membrane
filtration technologies.
Table 6-1 presents the calculated average effluent concentrations for the following FGD
wastewater treatment technologies: surface impoundments, chemical precipitation, CP+HRTR,
CP+LRTR, membrane filtration, and evaporation for those pollutants that have been found with
sufficient frequency and concentration to be recognized as typically present in FGD wastewater
from steam electric power plants. The EPA used data from the 2015 rule to characterize pollutant
concentrations in the effluent from surface impoundments, chemical precipitation, CP+HRTR,
and thermal evaporation treatment systems (see Section 10.2.1 of the 2015 TDD for more
information on the average effluent pollutant concentrations estimated for these technologies).
The estimated pollutant loadings from a specific pollutant if it
was being discharged directly to surface water, in pounds per
year.
The estimated percentage of the pollutant loading that will be
removed by a POTW (see Table 10-1 of the 2015 TDD).
6-5
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Section 6—Pollutant Loadings and Removals
The information collected by the EPA since the 2015 rule shows that although the shorter
hydraulic residence time provided by CP+LRTR can result in slightly higher variability in
effluent concentrations than achieved by CP+HRTR, the overall average effluent quality of the
two treatment technologies is comparable. Because of this, the pollutant concentrations used to
characterize CP+HRTR effluent are reasonable estimates for the effluent pollutant concentrations
following CP+LRTR. Similarly, the EPA found that the effluent quality from membrane
filtration is comparable to the effluent quality attained by the thermal evaporation treatment
technology. Therefore, the EPA determined that the pollutant concentrations used to characterize
the effluent from thermal evaporation are reasonable estimates for the effluent pollutant
concentrations following membrane treatment.
In estimating pollutant removals, the EPA also used information for bromide collected since the
2015 rule to supplement the data sets described above. For baseline and post-compliance
technology options, the EPA estimated plant-specific bromide loadings for each plant using a
mass balance approach. The mass balance approach estimates the plant-specific bromide
loadings that result from both the naturally-occurring bromine in the coal being burned and any
bromide additives that are being used for mercury emission control at the plant. The EPA used
the mass balance approach for bromide because the use of refined coals and bromide additives
can substantially increase the mass of bromides discharged, and the data in the record enabled
the EPA to evaluate whether specific plants were relying on native coals or using approaches that
increase the halogens (bromides) in the combustion and post-combustion air pollution control
system. As a result, the mass balance approach provides a better estimate of the mass of
bromides discharged by power plants. Additional information on the Agency's methodology for
estimating bromide loadings associated with FGD wastewater discharges is discussed in the
memorandum titled "Mass Balance Approach to Estimating Bromide Loadings from Steam
Electric Power Plants" (ERG, 2019c).
6-6
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Section 6—Pollutant Loadings and Removals
Table 6-1. Pollutants Present in Treated FGD Wastewater Effluent
Pnlliilanl
.\\craiic ( onccnlralion (jiii/l.)
1 CI) Surface
Impoundments
Chemical Prccipilalinn
( P+IIRTR and ( P+I.RTR
r.\aporalion and
Mcmhranc 1 Miration
Conventional Pollutants
Total Suspended Solids (TSS)
27,900
8,590
8,590
2,000
Priority Pollutants
Antimony
12.9
4.25
4.25
1.00
Arsenic
7.59
5.83
5.83
2.00
Beryllium
1.92
1.34
1.34
1.00
Cadmium
113
4.21
4.21
2.00
Chromium
17.8
6.45
6.45
4.00
Copper
21.8
3.78
3.78
2.00
Cyanide, Total
949
949
949
949
Lead
4.66
3.39
3.39
1.00
Mercury
7.78
0.139
0.0507
0.0103
Nickel
878
9.11
6.30
2.00
Selenium
1,170
928
5.72
2.00
Thallium
13.7
9.81
9.81
1.00
Zinc
1,390
20.0
20.0
28.5
Nonconventional Pollutants
Aluminum
2080
120
120
100
Ammonia as N
6,850
6,850
6,850
24,300
Barium
303
140
140
10.0
Boron
243,000
225,000
225,000
3,750
Bromidea
-
-
-
-
Calcium
2,050,000
1,920,000
1,920,000
200
Chloride
7,120,000
7,120,000
7,120,000
1,500
6-7
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Section 6—Pollutant Loadings and Removals
Table 6-1. Pollutants Present in Treated FGD Wastewater Effluent
Pulliiliinl
.\\er.iiie C cinceiilr;ilion
1 CI) Surfiice
1 in poll ikImollis
( hcmk'iil Pivcipiliiliun
( P+IIRTR «ilid ( P+I.RTR
r.\;ipoi'iilioii iind
Moiiihriino 1-illr;ilioii
Cobalt
183
9.30
9.30
10.0
Iron
1,510
110
110
100
Magnesium
3,370,000
3,370,000
3,370,000
200
Manganese
93,400
12,500
12,500
10.0
Molybdenum
125
125
125
20.0
Nitrate Nitrite as N
96,000
96,000
647
100
Phosphorus, Total
319
319
319
25.0
Sodium
276,000
276,000
276,000
5,000
Titanium
27.1
9.30
9.30
10.0
Total Dissolved Solids (TDS)
32,500,000
24,100,000
24,100,000
10,800
Vanadium
16.4
12.6
12.6
5.00
Source: (U.S. EPA, 2015).
Note: Concentrations are rounded to three significant figures.
a - The EPA estimated bromide loadings for each plant discharging FGD wastewater using a mass balance approach, as discussed in the memorandum titled
"Mass Balance Approach to Estimating Bromide Loadings from Steam Electric Power Plants" (ERG, 2019c). The average total concentration is presented as a
calculated value based on two values, one representing the average total concentration of plants not burning refined coal and not applying brominated compounds
(59,100 |ig/L) and one representing the average total concentration of plants burning refined coal or applying brominated compounds (167,000 |ig/L).
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Section 6—Pollutant Loadings and Removals
6.2.2	FGD Wastewater Flows
The EPA used industry-submitted data, Steam Electric Survey data, and other data sources
discussed in Section 2 to characterize FGD wastewater discharge flows. As described in Section
5.2.1, the EPA calculated plant-specific FGD purge flow rates and optimized FGD flow rates to
estimate compliance costs for each of the 70 coal-fired power plants discharging FGD
wastewater. To be consistent with the EPA's methodology for estimated plant-level O&M
compliance costs, the EPA used plant-specific optimized FGD flow rates to estimate baseline
and post-compliance loadings.
6.2.3	Baseline and Technology Option Loadings
The EPA estimated plant-specific loadings for baseline discharges and each treatment
technology option considered for control of FGD wastewater, as shown in the FGD Loads
Database (ERG, 2019d). As discussed in Section 6.1, the EPA multiplied the average effluent
pollutant concentrations for the applicable FGD wastewater treatment technology with the plant-
specific FGD discharge flow rate to calculate the pollutant loadings discharged to surface water
for each plant.41 The EPA used the same plant-specific flow rate for baseline and each
technology option evaluated, only changing the pollutant concentration based on the technology
option.
In estimating pollutant loadings, the EPA assumed the following:
Baseline Loadings TCP+HRTRV
•	The EPA used CP+HRTR concentrations from Table 6-1 for plants not currently
operating, or planning to operate, CP+HRTR or other treatment (such as
evaporation) targeting selenium, nitrate/nitrite, arsenic, and mercury removal. The
EPA assumes that these plants would install a CP+HRTR system to comply with
effluent requirements established under the 2015 rule.
•	The EPA used the corresponding concentrations from Table 6-1 for CP+HRTR
for plants already operating CP+HRTR systems, or otherwise in compliance with
the 2015 rule. EPA assumes that these plants will continue to operate their
existing FGD wastewater treatment technologies.
Based on discussions with industry representatives and engineering firms, plants that currently
operate evaporation systems are estimated to have zero baseline pollutant loadings. Because the
effluent quality from evaporation treatment is far superior to the water sources (e.g., river water)
typically used by plants for scrubber makeup water purposes42, and because reusing the
evaporation effluent within the FGD system obviates the need to monitor treatment system
effluent quality for compliance with NPDES permit limitations (and thereby saves money and
41	The EPA adjusted loadings for plants discharging to a POTW to account for additional removals that will take
place at the POTW.
42	For example, mist eliminator wash water or limestone slurry preparation.
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Section 6—Pollutant Loadings and Removals
avoids potential for noncompliance), the EPA determined that it is reasonable to assume plants
will choose to reuse the treated effluent within the FGD scrubber system.
Chemical Precipitation:
•	The EPA used chemical precipitation concentrations from Table 6-1 for plants
currently treating FGD wastewater with a surface impoundment, or other
treatment technologies that do not meet the requirements for this option. EPA
assumes that these plants will install a chemical precipitation treatment system to
meet the effluent requirements.
•	The EPA used chemical precipitation concentrations from Table 6-1 for plants
already operating all or any part of a chemical precipitation system.
The discharge loadings for all plants operating FGD wastewater treatment more advanced than
surface impoundments or chemical precipitation (e.g., CP+LRTR or CP+HRTR) remain
unchanged from baseline.
CP+LRTR:
•	The EPA used CP+LRTR concentrations from Table 6-1 for plants with existing
surface impoundments or chemical precipitation systems without additional
treatment for selenium and nitrate/nitrite.
Plants currently treating their FGD wastewater with a CP+LRTR, CP+HRTR or evaporation
system will continue doing so; thus, their loadings remain unchanged from baseline.
Membrane Filtration:
•	The EPA assumes plants with a surface impoundment, chemical precipitation
system, or biological treatment system (i.e., HRTR or LRTR systems) will install
and operate a membrane filtration system with brine encapsulation to meet the
effluent requirements.
•	EPA assumes that plants already operating evaporation systems, or otherwise in
compliance with this technology option, will continue to operate their current
FGD wastewater treatment technologies.
Plants installing membrane filtration are estimated to have zero post-compliance loadings
because these plants are likely to reuse treatment system effluent (i.e., membrane permeate)
within the FGD scrubber system, rather than discharge and monitor this effluent stream.43 Plants
43 The effluent quality from membrane filtration (i.e., membrane permeate) is far superior to the water sources
typically used by plants for scrubber makeup water purposes. Reusing the membrane permeate stream within the
FGD system obviates the need to monitor treatment system effluent quality for compliance with NPDES permit
limitations (saving money and avoiding potential for noncompliance); therefore, the EPA determined that it is
reasonable to assume plants will choose to reuse the treated effluent within the FGD scrubber system.
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Section 6—Pollutant Loadings and Removals
currently treating their FGD wastewater with an evaporation system will continue doing so; thus,
their loadings remain unchanged from baseline.
The EPA identified two plants transferring FGD wastewater to a POTW. The EPA expects that
these plants will continue to transfer the wastewater to a POTW for all technology options other
than membrane filtration. Therefore, the EPA adjusted the baseline and post-compliance
loadings to account for pollutant removals associated with POTW treatment, as described in
Section 6.1.
6.3 Bottom Ash Transport Water
This section discusses the EPA's method for estimating annual pollutant loadings and removals
for steam electric power plants that discharge bottom ash transport water and are not expected to
retire or convert fuel sources by December 31, 2028. The EPA identified 71 coal-fired power
plants that operate wet bottom ash handling systems and discharge the bottom ash transport
water to surface water or to a POTW, and that are not expected to retire or convert to a non-coal
fuel source by December 31, 2028. For these plants, the EPA estimated pollutant loadings for
baseline conditions (based on dry handling or operating a closed-loop recycle bottom ash system
that complies with a zero discharge standard) and for the two technology options evaluated as the
basis for bottom ash transport water discharge requirements: (1) dry handling or high rate recycle
bottom ash system with a purge (high recycle rate); and (2) dry handling or high rate recycle
bottom ash system with a purge or, for certain plants, a best management practices (BMP) plan
(high recycle rate/BMP plan). These technologies form the basis for the regulatory options
presented in the preamble.
Section 6.3.1 identifies the pollutants present and estimated concentrations in bottom ash
transport water. Section 6.3.2 discusses the flow rates used in combination with the pollutant
concentration data to estimate pollutant loadings for the plants that discharge bottom ash
transport water. Section 6.3.3 describes the calculations used to estimate pollutant loadings for
baseline and each technology option.
6.3.1 Pollutants Present in Bottom Ash Transport Water
For the proposed rule, the EPA updated the analytical data set used to characterize pollutant
concentrations in bottom ash transport water for the 2015 rule. The EPA supplemented the data
for the 2015 rule with new industry-submitted analytical data collected by plants as part of the
EPA's voluntary bottom ash transport water sampling program and data submitted by industry
during the final stage of the 2015 rulemaking.44 The EPA evaluated these data sources to identify
analytical data that meet the EPA's acceptance criteria for inclusion in analyses for
characterizing discharges of bottom ash transport water.
The EPA also removed certain data and corrected a small number of data in the 2015 rule
analytical data set. One source of data used to characterize bottom ash surface impoundment
effluent during the previous rulemaking was a set of sampling data collected for a rulemaking
44 In December 2017, the EPA requested seven plants operating surface impoundments primarily containing bottom
ash transport water to participate in a voluntary sampling program. Two plants agreed to participate in the sampling
program and submitted bottom ash surface impoundment data to the EPA (CPS Energy, 2018; TEC, 2018).
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Section 6—Pollutant Loadings and Removals
promulgated in 1982; the EPA has excluded these data from the data set used to estimate
pollutant removals for the proposed revisions to the 2015 rule. The EPA also identified sample-
specific errors present in the 2015 rule analytical data and made corrections as warranted.
Additional information on evaluated data sources, EPA's acceptance criteria, and development
of the analytical data set for characterization of bottom ash transport water is provided in the
memorandum titled "Development of the Bottom Ash Transport Water Analytical Data set and
Calculation of Pollutant Loadings for the Steam Electric Effluent Guidelines Proposed Rule"
(ERG, 2019a).
The EPA used the updated bottom ash transport water analytical data set to calculate an industry
average concentration for each pollutant present in the bottom ash transport water using the same
methodology as the 2015 rule, described in Section 10 of the 2015 TDD.45 Table 6-2 presents the
average effluent concentrations for pollutants present in bottom ash transport water.
Table 6-2. Pollutants Present in Bottom Ash Transport Water Effluent
Pollutant
Unit
Average Concentration
Conventional Pollutants
Chemical Oxygen Demand (COD)
Hg/L
20,800
Total Suspended Solids (TSS)
Hg/L
13,400
Priority Pollutants
Antimony
Hg/L
17.3
Arsenic
Hg/L
9.32
Cadmium
Hg/L
0.721
Chromium
Hg/L
5.08
Copper
Hg/L
3.95
Lead
Hg/L
10.4
Mercury
Hg/L
0.102
Nickel
Hg/L
17.5
Selenium
Hg/L
12.3
Thallium
Hg/L
1.13
Zinc
Hg/L
33.8
Nonconventional Pollutantsa
Aluminum
Hg/L
854
Barium
Hg/L
106
Boron
Hg/L
5,310
45 The data associated with bottom ash surface impoundments typically include other wastestreams (e.g., low
volume wastewaters, cooling water); as a result, the effluent concentrations due to bottom ash transport water are
likely suppressed somewhat due to dilution. Because of this, the baseline pollutant loadings and post-compliance
pollutant removals are underestimated to some degree. Nevertheless, the EPA determined that the pollutant removal
estimates calculated for this rule represent a reasonable estimate of the degree of pollutant removal that would be
achieved by the B AT/PSES limitations.
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Section 6—Pollutant Loadings and Removals
Table 6-2. Pollutants Present in Bottom Ash Transport Water Effluent
Pollutant
Unit
Average Concentration
Bromide
Hg/L
5,100
Calcium
Hg/L
154,00
Chloride
Hg/L
321,000
Cobalt
Hg/L
9.19
Iron
Hg/L
676
Magnesium
Hg/L
55,700
Manganese
Hg/L
153
Molybdenum
Hg/L
28.3
Nitrate-Nitrite (as N)
Hg/L
1,670
Phosphorus
Hg/L
222
Potassium
Hg/L
19,600
Silica
Hg/L
8,160
Sodium
Hg/L
119,000
Strontium
Hg/L
1,430
Sulfate
Hg/L
504,000
Sulfite
Hg/L
3,920
Titanium
Hg/L
35.9
Total Dissolved Solids (TDS)
Hg/L
1,290,000
Total Kjeldahl Nitrogen (TKN)
Hg/L
968
Vanadium
Hg/L
10.1
Source: U.S. EPA, 2015; ERG, 2019e.
Note: Loadings are rounded to three significant figures. The EPA did not generate an average pollutant
concentration for pollutants where all sample results are less than the quantitation limit,
a - The EPA identified ammonia (as N) as a pollutant present in bottom ash transport water; however, the EPA
excluded this parameter from the calculation of pollutant loadings to avoid double-counting of nitrogen
compounds.
6.3.2 Bottom Ash Transport Water Flows
The EPA used industry-submitted data and data from the Steam Electric Survey, discussed in
Section 2, to calculate bottom ash transport water flow rates for baseline conditions and each
technology option evaluated for this proposed rule.
For baseline conditions, the EPA estimated bottom ash transport water flow rates as zero for
generating units subject to the BAT/PSES effluent limitations requiring zero discharge of bottom
ash transport water. For generating units for which the zero discharge standard does not apply
(i.e., generating units with nameplate capacity equal to 50 megawatts (MW) or less), the EPA
used information from the Steam Electric Survey to calculate a normalized bottom ash transport
water discharge flow rate using the same approach outlined in Section 10.3.2 of the 2015 TDD.
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Section 6—Pollutant Loadings and Removals
For the high recycle rate technology option, which would allow for plants to discharge a portion
of their bottom ash transport water, the EPA estimated the post-compliance bottom ash transport
water flow rates for two compliance approaches available to most plants:
•	Zero Flow - For the compliance approach that uses a dry bottom ash handling
system (e.g., under-boiler mechanical drag system (MDS)), the discharge flow
rate would equal zero.
•	Purge Flow - For the compliance approach that uses a recirculating bottom ash
handling system (i.e., remote mechanical drag system (rMDS) operated with a
purge instead of completely closed-loop), the EPA estimated a purge volume for
each plant. The EPA calculated bottom ash transport water purge flow rates for
rMDS installations based on a relationship between the plant generating capacity
and the volume of the total wetted, active components of the rMDS, consistent
with the methodology described in Section 5.3.3.
The bottom ash transport water flow rate used to estimate post-compliance pollutant removals is
based on the lowest cost control technology selected for each plant.46
For the high recycle rate/BMP plan technology option, the EPA estimated bottom ash transport
water flow rates as described above and also estimated a bottom ash transport water flow
associated with the BMP plan alternative. For plants subject to the implementation of a BMP
plan, the EPA assumed that the plant will continue to discharge bottom ash transport water
consistent with current operations. The EPA used information from the Steam Electric Survey to
calculate a normalized bottom ash transport water discharge flow rate consistent with the
methodology described in Section 10.3.2 of the 2015 TDD.
6.3.3 Baseline and Technology Option Loadings
The EPA estimated generating unit-specific loadings for baseline discharges and each post-
compliance technology option considered for control of bottom ash transport water, see the
Bottom Ash Transport Water Pollutant Loadings Model (ERG, 2019e). To calculate the mass of
pollutants discharged from each plant, the EPA multiplied the average concentration of each
pollutant in Table 6-2 with the generating unit-specific discharge flow rate associated with the
bottom ash handling technology basis, described in Section 6.3.2, for the baseline and post
compliance technology options. Using the generating unit-level loadings, the EPA then
calculated the baseline and post-compliance loadings for each plant as the sum of pollutant
loadings for all generating units and at the industry level for each evaluated technology option.
Based on Steam Electric Survey data, six plants in the current population operate their wet-
sluicing bottom ash handling systems with a surface impoundment managed as a closed-loop
recycle process. The record indicates that these plants have designated outfalls for bottom ash
46 As described in Section 8.3, the EPA estimated costs associated with converting to both an MDS and remote MDS
with a purge, and then selected the most affordable of the technologically available system for each plant. However,
for instances where the MDS is the lowest cost approach for a generating unit but the EPA has information showing
that the unit is unable to convert to that system (e.g., insufficient space under the boiler). EPA's methodology
assumes the generating unit will install the remote MDS.
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Section 6—Pollutant Loadings and Removals
transport water; however, did not use these outfalls for emergency discharges from the closed-
loop recycle process. As described in Section 5.3.5, the EPA estimates a one-time cost associated
with consulting and engineering to completely close the bottom ash recycle system. These
actions would eliminate the potential for future discharges of bottom ash transport water. As a
result, the EPA's analysis assumes that there are no baseline pollutant loadings or post
compliance pollutant removals for these plants.
The EPA identified two plants transferring bottom ash transport water to a POTW. For these
plants, the EPA adjusted the baseline and post-compliance loadings to account for pollutant
removals associated with POTW treatment, as described in Section 6.1.
6.4 Summary of Baseline and Regulatory Option Loadings and Removals
As described in the preamble, the EPA evaluated four regulatory options comprising various
combinations of technology options to control FGD wastewater and bottom ash transport water.
The EPA estimated the pollutant loadings for baseline and each regulatory option, as well as
removals associated with steam electric power plants to achieve compliance for each of the main
regulatory options. This section discusses the specific loadings and removals calculations for
each regulatory option evaluated by the EPA. This section also presents the aggregated industry-
level loadings and removals for each wastestream and regulatory option.
The EPA applied different effluent limitations to steam electric generating units with a specific
steam electric power generating capacity, generating units with a specific net power generation,
and "high-flow" FGD wastewater plants. In calculating the pollutant loadings estimates for each
regulatory option, the EPA considered the subcategorizations established by each option and
whether the plant may elect to participate in the voluntary incentive program (VIP) based on
annualized compliance costs of the technology options.47 For example, for all regulatory options
the EPA applied different effluent limitations for generating units with a capacity of 50 MW or
less. In this case, the plant will not face more stringent requirements than preexisting regulations;
therefore, baseline and post-compliance loadings are estimated based on the treatment
technology currently in place and removals are not estimated for all regulatory options. The
preamble describes the subcategorizations and requirements applicable for each of the four
regulatory options evaluated by the EPA.
In order to estimate the total industry pollutant loadings and removals for each regulatory option
(accounting for subcategories), the EPA first estimated plant-level FGD wastewater and bottom
ash transport water pollutant loadings based on the technology bases selected for each plant. The
EPA then estimated pollutant loadings for each generating unit by applying a generating unit
flow fraction to the flow rates calculated for each plant. See the "FGD Purge Flow
Methodology" memorandum for the FGD wastewater and the Bottom Ash Transport Water
Pollutant Loadings Model for bottom ash transport water flow rates used to estimate each plant's
regulatory option loadings (ERG, 2019e and 2019f).
47 For Regulatory Option 2 and Regulatory Option 3, the EPA considered whether each plant's annualized cost for
the VIP technology basis (membrane filtration) is less than the annualized cost for chemical precipitation followed
by LRTR. Where the annualized cost for membrane filtration is less than the other regulatory options, the EPA
assumed the plant will install membrane treatment and estimated zero post-compliance loadings.
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Section 6—Pollutant Loadings and Removals
Table 6-3 and Table 6-4 present the total industry pollutant loadings and removals for FGD
wastewater and bottom ash transport water, respectively, in pounds per year for baseline and
each regulatory option. Table 6-5 presents the aggregated, industry-level pollutant loadings and
removals at baseline and each of the four regulatory options. Pollutant loadings and removals are
presented in pounds per year and account for the CCR rule. Pollutant loadings and removals
presented in these tables are calculated as the sum of TDS and TSS. The EPA estimated the
pollutant removals by subtracting the baseline loadings from the post-compliance loadings. The
memorandum titled "Generating Unit-Level Costs and Loadings Estimates by Regulatory
Option" presents the baseline and post-compliance pollutant loadings for each wastestream and
each regulatory option at the plant-level (ERG, 2019g).
Table 6-3. Estimated Industry-Level FGD Wastewater Pollutant Loadings and Estimated
Change in Loadings by Regulatory Option
Ki'Uiihilon Option ;l
I'.sliniiilcd loiiil Indusin l.oiulinii
(ll)Aciir)
llsliiiiiilod ( hinitio in l oiiil Indusin
loiidiniis
(ll)/\o;ii ) •'
Baseline
1,660,000,000
-
1
1,660,000,000
-
2
1,470,000,000
-195,000,000
3
1,380,000,000
-289,000,000
4
328,000,000
-1,340,000,000
Source: ERG, 2019h.
Note: Loadings and removals 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.
Table 6-4. Estimated Industry-Level Bottom Ash Transport Water Pollutant Loadings
and Estimated Change in Loadings by Regulatory Option
Ki'Uiiliilon Option
llsliiiiiilod loiiil Indusin Londinii
(lb/\e;ir)
llsliiiiiilod ( hiiiiiiciii loiiil Indusin
l.niidiiiiis (Ib/u'iir)''
Baseline
984,000
-
1
14,300,000
13,400,000
2
91,900,000
91,000,000
3
14,300,000
13,400,000
4
14,300,000
13,400,000
Source: ERG, 2019h.
Note: Loadings and removals 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.
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Section 6—Pollutant Loadings and Removals
Table 6-5. Estimated Industry-Level Pollutant Loadings and Estimated Change in
Loadings by Regulatory Option
Regulatory Option
Estimated Total Industry Loading
(lb/year)
Estimated Change in Total Industry
Loadings (lb/year)"
Baseline
1,670,000,000
--
1
1,680,000,000
13,400,000
2
1,560,000,000
-104,000,000
3
1,390,000,000
-276,000,000
4
342,000,000
-1,320,000,000
Source: ERG, 2019h.
Note: Loadings and removals 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.
6.5 References
1.	CPS Energy. 2018. CPS Energy J.T. Deely Power Plant Response to EPA Voluntary
Bottom Ash Transport Water Sampling Program. (May 11). DCN SE06861.
2.	ERG. 2015 a. Eastern Research Group, Inc. "Development Memo for FGD
Wastewater Data in the Analytical Database." (September 30). DCN SE05880.
3.	ERG. 2015b. Eastern Research Group, Inc. Final Steam Electric Technical
Questionnaire Database. (September 30). DCN SE05924.
4.	ERG. 2019a. Eastern Research Group, Inc. Development of the Bottom Ash
Transport Water Analytical Dataset and Calculation of Pollutant Loadings for the
Steam Electric Effluent Guidelines Proposed Rule. (August 6). DCN SE07208.
5.	ERG. 2019b. Eastern Research Group, Inc. Changes to Industry Profile for Coal-
Fired Generating Units for the Steam Electric Effluent Guidelines Proposed Rule.
(July 31). DCN SE07207.
6.	ERG. 2019c. Eastern Research Group, Inc. Mass Balance Approach to Estimating
Bromide Loadings from Steam Electric Power Plants. (October). DCN SE07260.
7.	ERG. 2019d. Eastern Research Group, Inc. FGD Loads Database. (July 18). DCN
SE07103.
8.	ERG. 2019e. Eastern Research Group, Inc. Bottom Ash Transport Water Pollutant
Loadings Model. (August 30). DCN SE06870.
9.	ERG, 2019f. Eastern Research Group, Inc. FGD Purge Flow Methodology
Memorandum. (July 8). DCN SE07091.
10.	ERG. 2019g. Eastern Research Group, Inc. Generating Unit-Level Costs and
Loadings Estimates by Regulatory Option. (June 15). DCN SE07090.
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Section 6—Pollutant Loadings and Removals
11.	ERG. 2019h. Eastern Research Group, Inc. Analyte Level Pollutant Loadings by
Regulatory Option Memorandum. (October 1). DCN SE07121.
12.	TEC. 2018. Tampa Electric Company. Tampa Electric Company Big Bend Station
Response to EPA Voluntary Bottom Ash Transport Water Sampling Program. (March
29). DCN SE06860.
13.	U.S. EPA. 2015. U.S. Environmental Protection Agency. Technical Development
Document for the Effluent Limitations Guidelines and Standards for the Steam
Electric Power Generating Point Source Category (2015 TDD). (September 30).
DCN SE05904.
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Section 7—Non-Water Quality Environmental Impacts
SECTION 7
NON-WATER QUALITY ENVIRONMENTAL IMPACTS
The elimination or reduction of one form of pollution has the potential to aggravate other
environmental problems, an effect frequently referred to as cross-media impacts. Sections 304(b)
and 306 of the Clean Water Act (CWA) require the EPA to consider non-water-quality
environmental impacts (NWQEIs), including energy impacts, associated with effluent limitations
guidelines and standards (ELGs). Accordingly, the EPA has considered the potential impacts of
the proposed regulatory options for flue gas desulfurization (FGD) wastewater and bottom ash
transport water discharged from steam electric power plants on energy consumption (including
fuel usage), air emissions, solid waste generation, and water use. The regulations promulgated by
the 2015 rule remain codified in 40 CFR Part 423; the NWQEIs associated with the regulatory
options for this proposed rulemaking are the incremental changes in NWQEIs (an increase or
decrease) relative to the NWQEIs for plants to meet the requirements of the 2015 rule.
7.1 Energy Requirements
Steam electric power plants use energy (including fuel) when transporting ash and other solids
on or off site, operating wastewater treatment systems, or operating ash handling systems. For
those plants that are estimated to incur costs associated with the proposed rule, the EPA
considered whether there would be an associated incremental change in energy need compared to
the 2015 rule requirements (baseline). That need varies depending on the regulatory option
evaluated and the current operations of the plant. Therefore, as applicable, the EPA estimated the
change in energy usage in megawatt hours (MWh) for equipment added to the plant systems or
in consumed fuel (gallons) for transportation or equipment operation. Specifically, the EPA
estimated energy usage associated with operating equipment for the FGD wastewater treatment
systems and bottom ash handling system considered for this proposed rule.
To estimate changes in plant-specific energy usages associated with operating FGD wastewater
treatment equipment, the EPA developed relationships between FGD wastewater flow and
energy usage for the following technologies: chemical precipitation, low residence time
reduction (LRTR) biological treatment, high residence time reduction (HRTR) biological
treatment, and membrane filtration. To estimate plant-specific energy usages for operating
bottom ash handling systems, the EPA developed relationships between generating unit capacity
and energy usage for the following technologies: mechanical drag system (MDS), remote
mechanical drag system (rMDS) with a purge, and rMDS with RO treatment of a slipstream to
achieve complete recycle. The EPA estimated electrical energy use from horsepower ratings of
system equipment (e.g., pumps, mixers, silo unloading equipment) and energy usage data
provided by wastewater treatment vendors. See EPA's memorandum "Non-Water Quality
Environmental Impacts for Proposed Revisions to the Steam Electric Effluent Limitations
Guidelines and Standards" for additional details (ERG, 2019).
Similarly, as applicable, the EPA also estimated the change in energy use that would result from
ceasing wet-sluicing of bottom ash and reduced use of earthmoving equipment in order to
comply with the 2015 rule requirements and all proposed regulatory options. The EPA estimated
electrical energy use from horsepower ratings of wet-sluicing system pumps and the earthmoving
7-1
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Section 7—Non-Water Quality Environmental Impacts
equipment engine. The EPA estimated energy savings associated with only earthmoving
equipment for plants sending FGD solids or bottom ash to surface impoundments.
The EPA summed plant-specific energy usage estimates to calculate the net change in energy
requirements for the regulatory options considered for the proposed rule, presented in Table 7-1.
Energy usage also includes the fuel consumption associated with the changes in transportation
needed to landfill solid waste and combustion residuals (e.g., ash) at steam electric power plants
to on-site or off-site landfills, based on plant-specific data, using open dump trucks. In general,
the EPA calculated fuel usage based on the estimated amount of time spent loading and
unloading solid waste and combustion residuals into dump trucks and the fuel consumption
during idling plus the estimated total transportation distance, number of trips required per year to
dispose of the solid waste and combustion residuals, and fuel consumption. The frequency and
distance of transport depends on a plant's operation and configuration. For example, the volume
of waste generated per day determines the frequency with which trucks will be travelling to and
from the storage sites. The availability of either an on-site or off-site landfill, and its estimated
distance from the plant, determines the length of travel time. See EPA's memorandum "Non-
Water Quality Environmental Impacts for Proposed Revisions to the Steam Electric Effluent
Limitations Guidelines and Standards" for more information on the specific calculations used to
estimate fuel consumption associated with the transport and disposal of solid waste and
combustion residuals (ERG, 2019). Table 7-1 shows the net change in national annual fuel
consumption associated with the regulatory options considered for the proposed rule and the
2015 baseline.
Table 7-1. Net Change in Energy Use for the Proposed Regulatory Options Compared to
Baseline
\on-\\ ;ik'r-Qn;ili(\ lmp;ic(
\e( ( hiiniio in r.iierjij I so Assocink'd willi l-'.I.Ci
Option 1
Option 2
Opliun 3
Option 4
Electrical Energy Usage
(Megawatt Hours)
-82,300
-54,500
-26,600
94,300
Fuel
(Gallons Per Year)
0
-47,400
40,300
243,000
Note: Negative values represent a decrease in energy use compared to baseline. Positive values represent
an increase in energy use compared to baseline.
7.2 Air Emissions Pollution
The final rule is expected to affect air pollution through three main mechanisms:
•	Changes in power requirements by steam electric power plants to operate
wastewater treatment and bottom ash handling systems needed to comply with the
proposed regulatory options.
•	Changes to transportation-related emissions due to the trucking of combustion
residual waste to landfills.
7-2
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Section 7—Non-Water Quality Environmental Impacts
• Changes in the profile of electricity generation due to the proposed regulatory
options.
This section provides greater detail on air emission changes associated with the first two
mechanisms and presents the estimated net change in air emissions associated with all three
mechanisms. See EPA's Benefit and Cost Analysis for Proposed Revisions to the Effluent
Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source
Category for additional discussion of the third mechanism (U.S. EPA, 2019).
Air pollution is generated when fossil fuels burn. Steam electric power plants also generate air
emissions from operating vehicles such as dump trucks, vacuum trucks, dust suppression water
trucks, and earthmoving equipment, which all release criteria air pollutants and greenhouse
gases. Criteria air pollutants are those pollutants for which a national ambient air quality standard
(NAAQS) has been set and include sulfur dioxide (SO2) and nitrogen oxides (NOx). Greenhouse
gases are gases such as carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) that
absorb radiation, thereby trapping heat in the atmosphere, and contributing to a wide range of
domestic effects.48 Conversely, decreasing energy use or less vehicle operation will result in
decreased air pollution.
The EPA calculated air emissions resulting from the change in power requirements49 using year-
explicit emission factors estimated by the Integrated Planning Model (IPM)50 for CO2, NOx, and
SO2. The IPM output provides estimates of electricity generation and resulting emissions by
plant and North American Electric Reliability Corporation (NERC) region. The EPA used
detailed outputs for the 2030 IPM run year to estimated plant- and NERC-level emission factors
(mass of pollutant emitted per kilowatt-hour of electricity generated) over the period of analysis.
This run year represents steady-state conditions after rule implementation, when all plants are
estimated to meet the revised BAT limits and pretreatment standards associated with each
analyzed regulatory option.
The EPA calculated NOx, CO2, and SO2 emissions resulting from changes in power
requirements based on the incremental auxiliary power electricity consumption, the pollutant-
and year-specific emission factors, and the timing plants are assumed to install the compliance
technology and start incurring additional electricity consumption.
The EPA assumed that plants with capacity utilization rates (CUR) of 90.4 percent or less would
generate the additional auxiliary electricity on site and therefore estimated emissions using plant-
specific and year-explicit emission factors obtained from IPM outputs.51
48	The EPA did not specifically evaluate nitrous oxide emissions as part of the NWQEI analysis. To avoid double
counting air emission estimates, the EPA calculated only nitrogen oxide emissions, which would include nitrous
oxide emissions.
49	Power requirements refers to the electricity needed to operate FGD wastewater treatment and/or bottom ash
handling technologies. Plants may generate this electricity on site or purchase the electricity from the grid.
50	IPM is a comprehensive electricity market optimization model that can evaluate cost and economic impacts within
the context of regional and national electricity markets. IPM is used by the EPA to analyze the estimated impact of
environmental policies on the U.S. power sector.
51	Emission factors are calculated as plant-level emissions divided by plant-level generation.
7-3
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Section 7—Non-Water Quality Environmental Impacts
The EPA assumed that plants with CUR greater than 90.4 percent would draw additional
electricity from the grid within the NERC region, instead of generating it on site. These plants
will be using part of their existing generation to power equipment; however, other plants within
the same NERC region would need to generate electricity to compensate for this reduction and
meet electricity demands. Therefore, for these high CUR plants, the EPA used NERC-average
emission factors instead of plant-specific emissions factors.
Because the EPA ran IPM for Regulatory Options 2 and 4 only, the EPA used IPM emission
factors calculated for Regulatory Option 2 to estimate changes in power requirements air
emissions for Regulatory Options 1 and 3.
To estimate air emissions associated with operation of transport vehicles, the EPA used the
MOVES2014b model to generate air emission factors for NOx, SO2, CO2, and CH4. The EPA
assumed the general input parameters such as the year of the vehicle and the annual mileage
accumulation by vehicle class to develop these factors (U.S. EPA, 2018b). Table 7-2 lists the
transportation emission factors for each air pollutant considered in the NWQEI analysis.
Table 7-2. MOVES Emission Rates for Model Year 2010 Diesel-fueled, Short-haul
Trucks Operating in 2018

NOx
SO;
CO2
ch4
Ko:i(l\\ii> l \|K'
(Ion/mi)
(Ion/mi)
(Ion/mi)
(Ion/mi)
Highway (restricted




access)
1.34E-06
1.18E-08
0.00141
4.23E-08
Local (unrestricted




access)
1.51E-06
1.23E-08
0.00147
6.80E-08
Source: U.S. EPA, 2018b. MOVES2014 (database versionmovesdb20180517).
Vehicle types: Single and Combination Unit Short-haul Trucks
The EPA calculated the air emissions associated with the operation of transport vehicles
estimated for the regulatory options using the transportation pollutant-specific emission rate per
mile, the estimated round trip distance to and from the on-site or off-site landfill, and the number
of calculated trips for one year in the transportation methodology to truck all solid waste or
combustion residuals to the on-site or off-site landfill.
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 to comply with limitations associated
with the regulatory options. See EPA's memorandum "Non-Water Quality Environmental
Impacts for Proposed Revisions to the Steam Electric Effluent Limitations Guidelines and
Standards" for more information on the specific calculations used to estimate transport distance
and number of trips per year (ERG, 2019). The changes in national annual air emissions
associated with auxiliary electricity and transportation for each of the regulatory options are
shown in Table 7-3.
7-4
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Section 7—Non-Water Quality Environmental Impacts
Table 7-3. Net Change in Industry-Level Air Emissions Associated with Power
Requirements and Transportation by Regulatory Option
Non-Water Quality Impact
Air Emissions Associated with the ELG
Option 1
Option 2"
Option 3
Option 4b
NOx
(tons/year)
-49.3
-33.2
-16.0
32.7
SOx
(tons/year)
-81.9
-54.3
-26.9
20.4
CO2
(metric tons/year)
-66,500
-44,500
-21,600
60,600
CH4
(tons/year)
0
-0.015
0.009
0.051
Note: Negative values represent a decrease in air emissions compared to baseline. Positive values
represent an increase in air emissions compared to baseline.
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.
The EPA estimated the change in the profile of electricity generation under Regulatory Options 2
and 4 using IPM. IPM predicts changes in electricity generation across all electricity generating
units, including those at plant to which the ELGs apply and which see changes in compliance
costs under the proposed regulatory options. The EPA predicts that these changes, either
increases or decreases, in electricity generation affect the air emissions from steam electric
power plants. The net changes in total annual air emissions attributable to the selected regulatory
options, compared to baseline, are shown in Table 7-4.
7-5
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Section 7—Non-Water Quality Environmental Impacts
Table 7-4. Net Change in Industry-Level Air Emissions for Regulatory Options 2 and 4.

\c( Change in Air l-'.missituis Associated willi 1 lie l-'.I.Ci
\on-\\ alcr Ou;ilil> Impacl
Option 2'1
Option 41'
NOx
5,000
1,030
(tons/year)
SOx
5,000
1,890
(tons/year)
CO2
(metric tons/year)
5,660,000
1,240,000
CH4
-0.015
0.051
(tons/year)
Note: Negative values represent a decrease in air emissions compared to baseline. Positive values
represent an increase in air emissions compared to baseline.
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.
7.3 Solid Waste Generation
Steam electric power plants generate solid waste associated with sludge from wastewater
treatment systems (e.g., chemical precipitation, biological treatment, membrane filtration). The
EPA estimated the amount of solids generated from the selected technology under each
regulatory option for each plant.
Bottom ash solids are also generated at steam electric power plants. The proposed regulatory
options are not expected to alter the amount of bottom ash generated by the steam electric power
generating industry because the type of bottom ash transport system installed to handle the ash
does not change the amount of bottom ash generated during combustion. Therefore, the
estimated amount of bottom ash solids generated under the proposed regulatory options are
comparable to the baseline. See EPA's memorandum "Non-Water Quality Environmental
Impacts for Proposed Revisions to the Steam Electric Effluent Limitations Guidelines and
Standards" for the specific calculations of solids generated (ERG, 2019). The net change in
national annual solid waste production associated with the regulatory options are shown in Table
7-5.
Table 7-5. Net Change in Industry-Level Solid Waste from Baseline, by Regulatory
Option
Non-W alcr Qu;ili(> 1111 pact
Change ii
Option 1
Inrinsln Solid \\ a<
Option 2
-------
Section 7—Non-Water Quality Environmental Impacts
7.4 Change in Water Use
Steam electric power plants generally use water for handling solid waste, including bottom ash,
and for operating wet FGD scrubbers. The technology options for bottom ash transport water
will eliminate or reduce water use associated with wet ash sluicing operating systems. Baseline
required zero discharge of bottom ash transport water; therefore, the EPA estimated an increase
in water use associated with all regulatory options compared to baseline, due to the purge bottom
ash transport water from rMDS under the options. The EPA estimated the increase in water use
based on plant-specific rMDS purge flows. Two of the three technology options for FGD
wastewater discharges—chemical precipitation and chemical precipitation plus LRTR—are not
expected to reduce the amount of intake water. Plants expected to install a membrane filtration
system for FGD wastewater treatment under Regulatory Options 2, 3, and 4 are expected to
experience a decrease in water use compared to baseline because the EPA assumes they will
reuse the membrane permeate in the FGD scrubber. The EPA estimated the reduction in water
use resulting from membrane filtration treatment to be 70 percent of the optimized FGD flow for
each plant expected to install membrane filtration.
Table 7-6 presents the estimated incremental change in process water use for each regulatory
option evaluated for the ELGs compared to baseline. The change in water use for each regulatory
option is assumed to be equivalent to the change in wastewater discharge.
Table 7-6. Net Change in Industry-Level Process Water Use by Regulatory Option
Non-Water Quality Impact
Change in Water Use from Baseline with the Option
Option 1
Option 2
Option 3
Option 4
Water Reduction
(MGD)
3.370
21.1
0.613
-9.38
Note: Negative values represent a decrease in water use compared to baseline. Positive values represent
an increase in water use compared to baseline.
7.5 References
1.	ERG. 2019. "Steam Electric Effluent Guidelines Non-Water Quality Environmental
Impacts Memorandum to the Steam Electric Rulemaking Record." (August). DCN
SE08483.
2.	U.S. EPA. 2018. U.S. Environmental Protection Agency. MOVES2014b Motor
Vehicle Emission Simulator (database version movesdb20180517). Available online
at: https://www.epa.gov/moves/latest-version-motor-vehicle-emission-simulator-
moves#manuals.
3.	U.S. EPA, 2019. U.S. Environmental Protection Agency. 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). (October).
DCN SE07401.
7-7
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Section 8—Effluent Limitations
SECTION 8
EFFLUENT LIMITATIONS
This section describes the pollutants selected for regulation for each wastestream evaluated as
part of this reconsideration and the methodology used to calculate the proposed effluent
limitations and standards. This section also describes the derivation of the allowable purge
volume for discharges of bottom ash transport water from power plants operating recirculating
bottom ash handling systems. As used in this section, regulated pollutants are pollutants for
which the EPA would establish numerical effluent limitations and standards.
8.1 Selection of Regulated Pollutants for FGD Wastewater
Effluent limitations and standards for all pollutants present in a wastestream often are not
necessary to ensure that wastewater pollution is adequately controlled because many of the
pollutants originate from similar sources, have similar treatability, and are removed by similar
mechanisms. Therefore, in some instances, it may be sufficient to establish effluent limitations or
standards for one or more indicator pollutants, which will ensure the removal of other pollutants
present in the wastewater. Based on the information in the record, this approach of establishing
effluent limitations and standards on a subset of the pollutants is appropriate for the discharge of
FGD wastewater.
The EPA considered the following when selecting a subset of pollutants as indicators for all
regulated pollutants:
•	The EPA would not set limitations for pollutants associated with treatment system
additives because regulating these pollutants could interfere with efforts to
optimize treatment system operation.
•	The EPA would not set limitations for pollutants for which the treatment
technology was ineffective (e.g., pollutant concentrations remained approximately
unchanged or increased across the treatment system).
•	The EPA would not set limitations for pollutants that are adequately controlled
through the regulation of another indicator pollutant because they have similar
properties and are treated by similar mechanisms as the regulated pollutant.
The following sections describe EPA's pollutant selection analysis for each of the technology
options evaluated for FGD wastewater based on the type of discharge (i.e., direct and indirect).
8.1.1 Direct Dischargers
As described in the preamble, the proposed rule would establish BAT limitations for the
discharge of FGD wastewater based on three different treatment technologies, depending on
various subcategorization factors (e.g., low utilization, FGD flow rate). The pollutants
considered for regulation by each treatment technology are discussed below.
8-1
-------
Section 8—Effluent Limitations
Chemical Precipitation
The EPA would establish BAT limitations for two pollutants (arsenic and mercury) based on
treatment with chemical precipitation. The regulated pollutant selection criteria matrix for the 32
pollutants present in FGD wastewater is illustrated in Table 8-1. EPA's rationale for selecting
which of the pollutants present in FGD wastewater to regulate is described below:
•	Conventional Pollutants. The EPA identified total suspended solids (TSS) as a
pollutant present in FGD wastewater. The existing BPT limitations adequately
control TSS in discharges of FGD wastewater.
•	Treatment Chemicals. The EPA identified and eliminated four pollutants present
in FGD wastewater that often are used as treatment chemicals in chemical
precipitation systems: aluminum, calcium, iron, and sodium.
•	Pollutants Not Effectively Treated. The EPA identified nine pollutants which are
not reliably removed by chemical precipitation. These pollutants are ammonia,
boron, bromide, chloride, cyanide, nitrate/nitrite as N, phosphorus, selenium, and
total dissolved solids (TDS).52
•	Pollutants Directly Regulated or Controlled by Regulation of Other Pollutants.
The remaining pollutants are metals, metalloids, or other nonmetals. Chemical
precipitation systems use chemicals to alter the physical state of dissolved and
suspended solids to help settle and remove solids from the wastewater. The metals
present in the wastewater form insoluble hydroxides and/or sulfide complexes.
The solubilities of these complexes vary by pH; therefore, reaction vessels can be
operated at specific pH to enhance removal of specific metals. Most metals are
precipitated to some degree in the chemical precipitation system, thereby resulting
in the removal of a wide range of metals. The EPA's design basis for the chemical
precipitation system includes both hydroxide and sulfide precipitation, as well as
iron coprecipitation. For this technology basis, the EPA selected arsenic and
mercury as regulated pollutants and as indicators of effective removal of many
other pollutants present in FGD wastewater, such as cadmium and chromium.
Table 8-1. Pollutants Considered for Regulation for FGD Wastewater - Chemical
Precipitation
Polliiliini Present in l-'(il)
\\ ;is(e\\;iler
Treiilmenl ( heniienl
\ol r.lTee(i\el\
1 'resiled
l)iree(l> Reiiiihiled or
( onI rolled In Ke^iihilion of
Another P;ir;imeler
Aluminum



Ammonia

V

Antimony


V
52 While EPA's pollutant-specific treatment effectiveness analysis performed for FGD wastewater accounts for some
removal of ammonia, boron, cyanide, chloride, nitrate/nitrite as N, selenium, and TDS in the chemical precipitation
system (see Section 10.2.1.2 for additional details), the EPA has determined that the chemical precipitation system is
not demonstrated to reliably treat these pollutants.
8-2
-------
Section 8—Effluent Limitations
Table 8-1. Pollutants Considered for Regulation for FGD Wastewater - Chemical
Precipitation
Polliiliini Presell( in l-'(il)
\\ ;is(e\\;Ker
1 iviilmonl ( heniienl
\o( 1'. ITeel i\el\
Tienled
l)iree(l> Reiiiihiled or
Coil I rolled In Reiiiihilion of
Another P;ir;ime(er
Arsenic


V
Barium


V
Beryllium


V
Boron

V

Bromide

V

Cadmium


V
Calcium
V


Chloride

V

Chromium


V
Cobalt


V
Copper


V
Cyanide

V

Iron
V


Lead


V
Magnesium


V
Manganese


V
Mercury


V
Molybdenum


V
Nickel


V
Nitrate/Nitrite as N

V

Phosphorus

V

Selenium

V

Sodium



Thallium


V
Titanium


V
Total Dissolved Solids

V

Vanadium


V
Zinc


V
8-3
-------
Section 8—Effluent Limitations
Chemical Precipitation followed by Low Residence Time Reduction (CP+LRTR)
The EPA included BAT limitations for four pollutants (arsenic, mercury, selenium, and
nitrate/nitrite as N) based on treatment with CP+LRTR. The regulated pollutant selection criteria
matrix for the 32 pollutants present in FGD wastewater is illustrated in Table 8-2. EPA's
rationale for selecting which of the pollutants present in FGD wastewater to regulate is described
below:
•	Conventional Pollutants, the EPA identified TSS as a pollutant present in FGD
wastewater. The existing BPT limitations adequately control TSS in discharges of
FGD wastewater.
•	Treatment Chemicals. The EPA identified and eliminated five pollutants present
in FGD wastewater that are often used as treatment chemicals in CP+LRTR
systems: aluminum, calcium, iron, phosphorus, and sodium.
•	Pollutants Not Effectively Treated, the EPA identified six pollutants which are not
reliably removed by CP+LRTR. These pollutants are ammonia, boron, bromide,
chloride, cyanide, and TDS.
•	Pollutants Directly Regulated or Controlled by Regulation of Other Pollutants.
The remaining pollutants are metals, metalloids, or other nonmetals and
nitrate/ni trite as N. Chemical precipitation systems use chemicals to alter the
physical state of dissolved and suspended solids to help settle and remove solids
from the wastewater. The CP+LRTR technology basis includes all removal
processes identified above for CP, as well as the biological treatment stage.
Adding the biological treatment stage provides additional removals of metals (and
other pollutants). For example, the bioreactor removes approximately 90 percent
of the mercury that remains in FGD wastewater following chemical precipitation
treatment. The EPA selected arsenic and mercury as regulated pollutants and as
indicators of effective removals of many other pollutants present in FGD
wastewater, such as cadmium and chromium. Pollutants such as selenium and
nitrate/ni trite as N are not effectively removed by the chemical precipitation
process and require additional treatment (e.g., biological treatment) to reliably
achieve removal. Anaerobic/anoxic biological treatment is effective at removing
both selenium and nitrate/ni trite as N. The EPA selected both of these pollutants,
in addition to arsenic and mercury, for regulation under the CP+LRTR technology
option.
Table 8-2. Pollutants Considered for Regulation for FGD Wastewater - CP+LRTR
Pulliiliinl Presell( in
1 CI) \\ ;is(e\\;Ker
1 roiilmonl (heinie;il
\ol r.l'fec(i\el\ 1 iv.ik'il
l)iree(l> Reiiiihiled or
( milrolled In Reiiiihilion of
Another P;ir;ime(er
Aluminum



Ammonia



Antimony


V
Arsenic


V
8-4
-------
Section 8—Effluent Limitations
Table 8-2. Pollutants Considered for Regulation for FGD Wastewater - CP+LRTR
Pulliiliinl Presell( in
1 CI) \\ ;is(e\\;Ker
1 roiilmonl (heinie;il
\ol r.l'fec(i\el\ 1 iv.ik'il
l)iree(l> Reiiiihiled or
( milrolled In Reiiiihilion of
Another P;ir;ime(er
Barium


V
Beryllium


V
Boron

V

Bromide

V

Cadmium


V
Calcium
V


Chloride

V

Chromium


V
Cobalt


V
Copper


V
Cyanide

V

Iron
V


Lead


V
Magnesium


V
Manganese


V
Mercury


V
Molybdenum


V
Nickel


V
Nitrate/Nitrite as N


V
Phosphorus
V


Selenium


V
Sodium
V


Thallium


V
Titanium


V
Total Dissolved Solids

V

Vanadium


V
Zinc


V
Membrane Filtration
The EPA included BAT limitations for six pollutants (arsenic, mercury, selenium, nitrate/nitrite
as N, bromide, and TDS) based on treatment with membrane filtration. The regulated pollutant
selection criteria matrix for the 32 pollutants present in FGD wastewater is illustrated in Table
8-3. EPA's rationale for selecting which of the pollutants present in FGD wastewater to regulate
is described below:
8-5
-------
Section 8—Effluent Limitations
•	Conventional Pollutants. The EPA identified TSS as a pollutant present in FGD
wastewater. The existing BPT limitations adequately control TSS in discharges of
FGD wastewater.
•	Pollutants Not Effectively Treated: Based on data for thermal systems and process
knowledge and performance data for membrane systems, all pollutants present in
FGD wastewater would be effectively treated by membrane filtration.
•	Pollutants Directly Regulated or Controlled by Regulation of Other Pollutants.
The remaining pollutants are metals, metalloids, other nonmetals, nitrate-nitrite as
N, chloride, bromide, and TDS. As described in the preamble, the membrane
technology evaluated as the technology basis removes pollutants based on their
molecular size and solubility. The EPA selected six pollutants (arsenic, mercury,
selenium, nitrate-nitrite as N, bromide, and TDS) as regulated pollutants and as
indicators of effective removals of all other pollutants present in FGD wastewater.
Table 8-3. Pollutants Considered for Regulation for FGD Wastewater - Membrane
Filtration
Polliiliini Presell( in
I-CI) \\ ;isk'\\;ik'r
1 iviilmonl
( hcmiciil
\o( r.lTec(i\cl>
1 iviilod
l)iivcll> RciiiihiU'd or
Coin rolled In
Rc'liiihKion of AiioMkt
Piiriimolor
Aluminum


V
Ammonia


V
Antimony


V
Arsenic


V
Barium


V
Beryllium


V
Boron


V
Bromide


V
Cadmium


V
Calcium


V
Chloride


V
Chromium


V
Cobalt


V
Copper


V
Cyanide


V
Iron


V
Lead


V
Magnesium


V
Manganese


V
Mercury


V
Molybdenum


V
8-6
-------
Section 8—Effluent Limitations
Table 8-3. Pollutants Considered for Regulation for FGD Wastewater - Membrane
Filtration
Polliiliini Presell( in
I-CI) \\ ;is(e\\;Ker
1 iviilmonl
(hemieiil
\»( 1'. ITeel i\el\
Trented
l)iree(l> Reiiiilnled or
( on(rolled In
Kevin hi 1 ion of Another
P;ir;imeler
Nickel


V
Nitrate/Nitrite as N


V
Phosphorus


V
Selenium


V
Sodium


V
Thallium


V
Titanium


V
Total Dissolved Solids


V
Vanadium


V
Zinc


V
8.1.2 Indirect Dischargers
As part of establishing pretreatment standards for existing sources (PSES) for a pollutant, the
EPA examines whether the pollutant "passes through" a POTW to waters of the U.S. or
interferes with the POTW operation or sludge disposal practices. In determining whether a
pollutant passes through POTWs for these purposes, the EPA compared the percentage of a
pollutant removed by well-operated POTWs performing secondary treatment to the percentage
removed by the BAT technology basis. A pollutant is determined to pass through POTWs when
the median percentage removed by well-operated U.S. POTWs is less than the median
percentage removed by the BAT technology basis. Pretreatment standards are established for
those pollutants regulated under BAT that pass through POTWs.
Section 11 of the 2015 TDD describes EPA's methodology for conducting the pass-through
analysis used for the 2015 rule. As described in Section 6.2.1, the EPA used data from the 2015
rule to characterize pollutant concentrations in the effluent from all three treatment technologies
used as the basis for the proposed regulatory option, CP, CP+LRTR, and membrane filtration. As
a result, the EPA used the results of the 2015 pass-through analysis to determine which
pollutants to regulate for indirect dischargers for this proposed rule.
The data characterizing CP effluent remains unchanged from the 2015 rule; therefore the EPA
used the BAT percent removals for mercury and arsenic determined as part of the 2015 rule to
determine POTW pass-through based on treatment of FGD wastewater using CP. Table 8-4
presents the current BAT treatment technology removals and POTW removals for FGD
wastewater treated using CP. The EPA determined that mercury and arsenic passed through
POTW secondary treatment and selected them both as regulated pollutants for PSES based on
CP treatment.
8-7
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Section 8—Effluent Limitations
Table 8-4. POTW Pass-Through Analysis - CP
Pollutant
Median BAT %
Removal
POTW % Removal
BAT % Removal >
POTW %
Removal?
Does Pollutant
Pass Through?
Arsenic
98.9%
65.8%
Yes
Yes
Mercury
99.9%
90.2%
Yes
Yes
Source: U.S. EPA, 2015a.
As described in Section 6.2.1, the overall average effluent quality for CP+LRTR and CP+HRTR
technologies is comparable and the EPA applied the pollutant concentrations used to characterize
CP+HRTR as estimates for the effluent pollutant concentrations following CP+LRTR. The EPA
used the BAT percentage removals for mercury, arsenic, nitrate/nitrite as N, and selenium for
PSES from the 2015 rule to determine POTW pass-through based on treatment of FGD
wastewater using CP+LRTR. Table 8-5 presents the present BAT treatment technology removals
and POTW removals for FGD wastewater treated using CP+LRTR. All four pollutants were
determined to pass through POTW secondary treatment and the EPA selected them as regulated
pollutants for PSES based on CP+LRTR treatment.
Table 8-5. POTW Pass-Through Analysis - CP+LRTR
Pollulanl
Median BAT "i.
Remo\al
POTW V i. Remo\ al
liAT V ii Remo\ al >
PO'l'W "i.
Remo\al?
Does Pollulanl
Pass Through?
Arsenic
98.9%a
65.8%
Yes
Yes
Mercury
99.9%a
90.2%
Yes
Yes
Nitrate/Nitrite as N
98.7%
90.0%
Yes
Yes
Selenium
99.8%
34.3%
Yes
Yes
Source: U.S. EPA, 2015a.
a - The arsenic and mercury BAT percent removals presented in this table are based on the chemical precipitation
treatment. The CP+LRTR treatment technology will provide even greater removals of these pollutants; however,
since pass-through is already demonstrated using CP data, EPA determined that the CP pass-through analysis is
sufficient for demonstrating pass-through for CP+LRTR.
As described in Section 6.2.1, the overall average effluent quality for membrane filtration and
thermal technologies is comparable and the EPA used the pollutant concentrations used to
characterize thermal technologies as estimates for the effluent pollutant concentrations following
membrane filtration. The EPA used the BAT percent removals for mercury, arsenic, TDS, and
selenium for PSNS from the 2015 rule to determine POTW pass-through based on treatment of
FGD wastewater using membrane filtration. The EPA used effluent concentrations from Section
6.2.1 to estimate the BAT removals for bromide and nitrate/ni trite. Table 8-6 presents the current
BAT treatment technology removals and POTW removals for FGD wastewater treated using
CP+LRTR. All four pollutants were determined to pass through POTW secondary treatment and
the EPA selected them as regulated pollutants for PSES based on CP+LRTR treatment.
-------
Section 8—Effluent Limitations
Table 8-6. POTW Pass-Through Analysis - Membrane Filtration
Pollutant
Median BAT %
Removal
POTW % Removal
BAT % Removal >
POTW %
Removal?
Does Pollutant
Pass Through?
Arsenic
96.3%
65.8%
Yes
Yes
Bromide
>98.3% a
1.89% b
Yes
Yes
Mercury
99.9%
90.2%
Yes
Yes
TDS c
99.9%
0%
Yes
Yes
Nitrate/Nitrite as N
>98.7% d
90.0%
Yes
Yes
Selenium
99.2%
34.3%
Yes
Yes
Source: U.S. EPA, 2015a.
a - The EPA estimated plant-specific bromide loadings for each plant discharging FGD wastewater using a mass
balance approach, as discussed in the memorandum "Mass Balance Approach for Estimating Bromide Loadings in
FGD Wastewater" (ERG, 2019). The average total concentration of bromide in discharges from plants that are not
burning refined coal and not applying brominated compounds is 59,100 |ig/L. and the average total concentration of
plants burning refined coal or applying brominated compounds is 167,000 |ig/L. Data show that membrane filtration
technologies can reduce bromide concentrations to less than 1,000 |ig/L. Based on these average concentrations, the
EPA calculated a minimum BAT percent removal of 98.3 percent.
b - The EPA expects POTWs may achieve some removal of bromide (e.g., entrainment in treatment residuals);
therefore, the EPA set POTW percent removal for bromide equal to the POTW percent removal for bromine,
c -POTWs have not been shown to effectively remove TDS. For this analysis the EPA set POTW percent removal
for TDS to zero and assumed this pollutant passes through POTW secondary treatment.
d - The average effluent concentration (Section 6.2.1) and long-term average (Section 8.2.7) for nitrate/nitrite as N
in membrane filtration effluent is lower than the average effluent concentration and long-term average calculated for
CP+LRTR. As a result BAT removal of nitrate/nitrite as N using membrane filtration will be greater than the BAT
removal achieved by CP+LRTR.
8.2 Calculation of Effluent Limitations for FGD Wastewater
The effluent limitations guidelines and standards are based on long-term average effluent values
and variability factors that account for reasonable variation in treatment performance within a
particular treatment technology over time. For simplicity, in the remainder of this section, the
effluent limitations and/or standards are referred to as "limitations." Also, the term "option long-
term average" and "option variability factor" are used to refer to the long-term averages and
variability factors of the treatment technology options for an individual wastestream, rather than
the regulatory options described in the preamble.
This section describes the data sources, data selection, and statistical methodology the EPA used
to calculate the long-term average, variability factors, and effluent limitations for FGD
wastewater.
8.2.1 Data Selection
In developing the long-term averages, variability factors, and limitations for a particular
wastestream and technology option, the EPA used wastewater data from plants operating the
model treatment technology forming the basis of a particular technology option. The data sources
evaluated include: (1) a sampling program during which the EPA collected samples (hereinafter
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referred to as "EPA sampling"); (2) a sampling program during which the EPA, pursuant to
section 308 of the Clean Water Act, directed plants to collect samples (hereinafter referred to as
"CWA 308 sampling"); and (3) self-monitoring data that plants collected and analyzed
(hereinafter referred to as "plant self-monitoring").
Data Selection Criteria
This section describes the criteria that the EPA applied in selecting plants and data to use as the
basis for the numeric limitations for FGD wastewater. The EPA has used these, or similar
criteria, in developing limitations for other industries. The EPA uses these criteria to select data
that reflect performance of the model technology in treating the industrial wastes under normal
operating conditions.
The first criterion requires that the plant have the model technology and that it is generally well
operated. Applying this criterion typically eliminates any plant with treatment other than the
model technology. The EPA generally determines whether a plant meets this criterion based on
site visits, discussions with plant management, engineering reports, and/or comparison to the
characteristics, operation, and performance of treatment systems at other plants. When
warranted, the EPA also contacts plants as it evaluates whether data submitted represented
normal operating conditions for the plant and equipment.
The second criterion requires that the influents and effluents from the treatment components
represent typical wastewater from the industry, without incompatible wastewater from other
sources. Applying this criterion enables the EPA to select only those plants where the
commingled wastewaters are not characterized by substantial dilution, sudden large variation in
wastewater flow rates (i.e., slug loads) that can result in frequent upsets and/or overloads, or
wastewaters with different types of pollutants than those generated by the waste stream for which
the EPA is establishing effluent limitations.
The third criterion ensures that the pollutants are present in the influent at sufficient
concentrations to evaluate treatment technology effectiveness. To evaluate whether the data meet
this criterion for the final rule, the EPA often uses a long-term average test (or LTA test) for
plants where the EPA possesses both influent and effluent data. The EPA has used this test in
developing regulations for other industries (e.g., the ELGs for the Iron and Steel Point Source
Category) (U.S. EPA, 2002) and was also used when developing effluent limitations for the 2015
rule. The test measures the influent concentrations to ensure a pollutant is present at
concentrations high enough to evaluate treatment effectiveness. If a data set for a pollutant fails
the test, the EPA excludes the data for that pollutant at that plant when calculating the
limitations.
The fourth criterion 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 such data do not reflect the performance of
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 loadings, plant logs, and other available information. As part of this
evaluation, the EPA reviews the process or treatment conditions that may have resulted in
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extreme values (high and low). Consequently, 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 EPA also applies the fourth criterion in its review of data corresponding to the initial
commissioning period for treatment systems. When installing a new treatment system, most
industries undergo a commissioning period to acclimate and optimize the system. During this
acclimation and optimization process, the effluent concentration values can be highly variable
with occasional extreme values (high and low). This occurs because the treatment system
typically requires some "tuning" as the plant staff and equipment and chemical vendors work to
determine the optimum chemical addition locations and dosages, vessel hydraulic residence
times, internal treatment system recycle flows (e.g., filter backwash frequency, duration, and
flow rate; return flows between treatment system components), and other operational conditions,
including clarifier sludge wasting protocols. The initial commissioning period may be as short as
several days, but depending on the technology employed, it may also take treatment system
operators several weeks or months to gain expertise in operating the new treatment system. This
contributes to treatment system variability during the commissioning period. After this initial
adjustment period, the system should operate at steady state with relatively low variability
around a long-term average over many years. Because commissioning periods typically reflect
operating conditions unique to the first time the treatment system begins operation, the EPA
typically excludes such data in developing the limitations.53
Similarly, power plant decommissioning periods represent unique operating conditions
associated with the permanent shutdown of the power plant, FGD system, and FGD wastewater
treatment system,54 and do not represent best available control technology economically
53	Examples of conditions that are typically unique to the initial commissioning period include operator unfamiliarity
or inexperience with the system and how to optimize/adjust its performance to deal with influent wastewater
variability and changing conditions, as well as the initial startup of newly installed equipment to ensure components
operate as intended. 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 (e.g., on the order of days, weeks, or even months). In this latter situation, the plant has already
established typical operating practices and set points for treatment system components and operators have
experience operating the treatment system and adjusting its operation to deal with changing conditions. Any
variability unique to restarting the treatment system can be accommodated, if necessary, by operational practices
that include closer monitoring of treatment system operating parameters and recirculating any off-specification
effluent back through the treatment system.
54	Note that decommissioning periods for an individual generating unit at a multi-unit plant are not the same as a
plant decommissioning period because wastes from normal operation of the remaining unit(s) will continue.
Examples of conditions that are unique to the power plant decommissioning periods include the complete shutdown,
cleaning, decommissioning, and possibly dismantling of the equipment and processes used to generate electricity
(e.g., boiler operations) which is likely to cause erratic operation of the treatment system. In addition, plant
decommissioning would include draining and decommissioning the treatment system itself. These conditions differ
from those associated with the periodic shutdown of generating units and other systems at a plant, whether they be for
short or extended duration shutdown (e.g., on the order of days, weeks, or even months). In this latter situation, the
plant has already established typical operating practices and set points for treatment system components and
operators have experience operating the treatment system and adjusting its operation to deal with changing
conditions. Any variability unique to the shutdown period can be accommodated, if necessary, by operational
practices that include closer monitoring of treatment system operating parameters and recirculating any off-
specification effluent back through the treatment system.
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achievable (BAT) level of performance for treatment of FGD wastewater at an operating steam
electric power plant. Therefore, the EPA also excludes data collected during the plant
decommissioning period in calculating the limitations.
Data Selection for Each Technology Option
This section summarizes the data used in developing the proposed limitations for each FGD
wastewater technology option. See the preamble for a description of the technology options.
Three technology options were evaluated for this proposed rule: chemical precipitation; the
combination of chemical precipitation and LRTR biological treatment; and membrane filtration.
In certain instances, the proposed rule would establish limitations for wastewater discharges that
are equal to previously established best practicable control technology currently available
limitations for total suspended solids (TSS). The EPA used no new effluent concentration data to
establish these limitations and therefore, such limitations are not discussed in this section. The
data sources listed below were used to calculate the proposed effluent limitations for each
technology option.
•	Chemical Precipitation Technology. Four plants operating installed chemical
precipitation treatment systems that include hydroxide precipitation, sulfide
precipitation, and iron coprecipitation.
•	CP+LRTR Technology. Five data sets from plants operating a pilot treatment
system that includes chemical precipitation followed by LRTR anoxic/anaerobic
biological treatment designed to remove selenium and nitrate-nitrite.
•	Membrane Filtration Technology. Three data sets from plants operating a pilot
membrane filtration treatment systems that include pretreatment (largely to reduce
suspended solids before reverse osmosis) and reverse osmosis.
Combining Data from Multiple Sources within a Plant
For this rulemaking, data for plants used for chemical precipitation limitations came from
multiple sources, including the EPA sampling, CWA 308 sampling, and plant self-monitoring.
For three plants (Hatfield's Ferry, Miami Fort, and Pleasant Prairie), data from multiple sources
were collected during overlapping time periods and the EPA combined these data into a single
data set for the plant. For one plant (Keystone), the multiple sources of data were collected
during non-overlapping time periods. At Keystone, the EPA and CWA 308 samples were
collected from September 2010 through January 2011 and arsenic self-monitoring data were
available from January 2012 through April 2014. The EPA has no information to indicate that
these time periods represent different operating conditions; therefore, the EPA also combined the
multiple sources of data for Keystone into a single data set for the plant. This approach is
consistent with EPA's traditional approach for other effluent guidelines rulemakings.55 For each
55 When the EPA obtains data from multiple sources (such as the EPA sampling, CWA 308 sampling, and plant
self-monitoring data in this rulemaking) from a plant for the same time period, the EPA usually combines the data
from these sources into a single data set for the plant for the statistical analyses. In some cases where the sampling
data from a plant are collected over two or more distinct time periods, the EPA may analyze the data from each
time period separately. In some past effluent guideline rulemakings, the EPA analyzed data as if each time period
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of the plants used for the CP+LRTR and membrane filtration limitations, the data were collected
from a single source (i.e., plant self-monitoring), so it was not necessary to combine data.
8.2.2 Data Exclusions and Substitutions
The sections below describe why and how the EPA either excluded or substituted certain data in
calculating the limitations.
Data Exclusions
After selecting the model plant(s), the EPA applied the data selection criteria described in
Section 8.2.1 by evaluating all available data for each model plant. The EPA identified certain
data that warranted exclusion from calculating the limitations because: (1) the samples were
analyzed using an analytical method that is not approved in 40 CFR 136 for National Pollutant
Discharge Elimination System (NPDES) purposes; (2) the samples were analyzed using a
method that was not a sufficiently sensitive analytical method (e.g., the EPA Method 245.1 for
mercury in effluent samples); (3) the samples were analyzed in a manner that resulted in an
unacceptable level of analytical interferences; (4) the samples were collected prior to steady state
operation, during the initial commissioning period for the treatment system, or during the plant
decommissioning period; (5) the analytical results were identified as questionable due to quality
control issues, abnormal conditions or treatment upsets, or were analytical anomalies; (6) the
samples were collected from a location that is not representative of treated effluent (e.g.,
secondary clarifier instead of final effluent); or (7) the treatment system was operating in a
manner that does not represent BAT/NSPS level of performance.
Data Substitutions
In general, the EPA used detected values or, for non-detected values, sample-specific detection
limits (i.e., sample-specific quantitation limit, or QL) in calculating the limitations.56 However,
there were some instances in which the EPA substituted a baseline value for a detected value or a
sample-specific detection limit that was lower than the baseline value. Baseline substitution
accounts for the possibility that certain detected or non-detected results may be at a lower
concentration than generally can be reliably quantified by well-operated laboratories. This
approach is consistent with how the EPA has calculated limitations in previous effluent
guidelines rulemakings and is intended to avoid establishing an effluent limitation that could be
biased toward a lower concentration than plants can reliably demonstrate compliance.57 After
represented a different plant when the data were considered to represent fundamentally different operating
conditions. This was not the case for the Keystone data, so the EPA combined all data for the plant into a single
data set.
56	For the purpose of the discussion of calculating the long-term averages, variability factors, and effluent limitations,
the term "detected" refers to analytical results measured and reported above the sample-specific quantitation limit
(QL). The term "non-detected" refers to values that are below the method detection limit (MDL) and also those
measured by the laboratory as being between the MDL and the QL.
57	For example, if a limit were established at a concentration lower than the baseline value, although some
laboratories might be able to achieve sufficiently low quantitation levels, it is possible that typical well-operated
laboratories could not reliably measure down to that level. In such cases, a plant would not be able to demonstrate
compliance with the limit. The EPA does not suggest that the baseline value should be established at a level that
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excluding all the necessary data as described above, the EPA compared each reported result to a
baseline value. Whenever a detected value or sample-specific detection limit was lower than the
baseline value, the EPA used the baseline value instead and classified the value as non-detected
(even if the actual reported result was a detected value). For example, if the baseline value was 5
micrograms/liter (ng/L) and the laboratory reported a detected value of 3 ng/L, EPA's
calculations would treat the sample result as being non-detected with a sample-specific detection
limit of 5 |-ig/L.
The EPA used the following baseline values for each pollutant in the development of the effluent
limitations for the steam electric rulemaking:
•	Arsenic: 2 |ig/L.
•	Mercury: 0.5 nanogram/liter (ng/L).
•	Nitrate-nitrite as N: 0.05 milligram/liter (mg/L).
•	Selenium: 5 |ig/L.
•	TDS: 10 mg/L
•	Bromide: 0.01 mg/L.
The EPA determined the baseline values for mercury, nitrate-nitrite as N, and TDS using the
minimum levels (MLs) established by the analytical methods used to obtain the reported values
or a comparable analytical method where an ML was not specified by the method.58 The baseline
values for arsenic and selenium are based on the results of MDL studies conducted by well-
operated commercial laboratories using the EPA Method 200.8 to analyze samples of synthetic
FGD wastewater (CSC, 2013).
In cases when all concentration values are above the baseline value, then the baseline value has
no effect on the concentration values and subsequent calculated limitations.
In addition to calculating the limitations for each technology option (adjusting for the baseline
values shown above, when appropriate), the EPA also calculated effluent limitations using all the
valid reported results (i.e., without substituting baseline values and/or changing the censoring
classification of the result). As noted above, the reason for substituting baseline values is to
prevent establishing an effluent limitation that is biased toward a lower concentration than plants
can reliably demonstrate compliance with. Because the EPA wanted to ensure that plants can
achieve the effluent limitations established by the rule, the EPA calculated and evaluated both
every laboratory in the country can measure to, nor that limitations established for the ELGs must be established
sufficiently high that every laboratory in the country must be able to measure to that concentration; however, it is
appropriate to use baseline values that generally can be reliably quantified by well-operated laboratories. This
approach achieves a reasonable balance in establishing limitations that are representative of treatment system
performance and protective of the environment, while at the same time ensuring that plants have adequate access to
laboratories with the analytical capabilities necessary to reliably demonstrate compliance with the limitations.
58 The baseline values for mercury and nitrate-nitrite as N are equal to the MLs specified in the EPA Methods 163 IE
and 353.2, respectively. The method the EPA used to analyze for TDS (Standard Method 2540C) does not explicitly
state an MDL or ML. However, the EPA Method 160.1 is similar to Standard Method 2540C and the lower limit of
its measurement range is 10 mg/L (i.e., the nominal quantitation limit). Thus, the EPA used 10 mg/L as the baseline
value for TDS. The baseline value for bromide is based on EPA Method 300.0.
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the baseline-adjusted and unadjusted limitations for each technology option and used the higher
of the two results for the final ELGs.
8.2.3 Data Aggregation
The EPA used daily values in developing the limitations. In cases with at least two samples per
day, the EPA aggregated the sample results to obtain a single value for that day. There are
instances where the sampling data used in this rulemaking includes multiple sample results for a
given day. This occurred with field duplicates, overlaps between plant self-monitoring and the
EPA sampling, or overlaps between plant self-monitoring and CWA 308 sampling.
When aggregating the data, the EPA took into account whether each value was detected (D) or
non-detected (ND). Measurements reported as being less than the sample-specific detection limit
(or baseline values, as appropriate) are designated as non-detected (ND) for the purpose of
statistical analyses to calculate the limitations. In the tables and data listings in this document and
in the rulemaking record, the EPA uses the indicators D and ND to denote the censoring type for
detected and non-detected values, respectively.
The sections below describe each of the different aggregation procedures. They are presented in
the order that the aggregation was performed (i.e., field duplicates were aggregated first and then
any overlaps between plant self-monitoring and the EPA sampling data or CWA 308 sampling
were aggregated).
Aggregation of Field Duplicates
During the EPA sampling, the EPA collected duplicate field samples as part of the quality
assurance/quality control activities. Field duplicates are two samples collected for the same
sampling point at approximately the same time. The duplicates are assigned different sample
numbers, and they are flagged as duplicates for a single sampling point at a plant. Because the
analytical data from a duplicate pair are intended to characterize the same conditions at a given
time at a single sampling point, the EPA averaged the data to obtain one value for each duplicate
pair.
For arsenic at Hatfield's Ferry and arsenic and mercury from Miami Fort, there were a few days
with two or three reported self-monitoring samples. These self-monitoring samples from the
same day were treated as duplicate samples in the calculations.
In most cases, the duplicate samples had the same censoring type, so the censoring type of the
aggregated value was the same as that of the duplicates. In some instances, one duplicate was a
detected (D) value and the other duplicate was a non-detected (ND) value. When this occurred,
the EPA determined that the aggregated value should be treated as detected (D) because the
pollutant is confirmed to be present at a level above the sample-specified detection limit in one
of the duplicates.
Table 8-7 summarizes the procedure for aggregating the sample measurements from the field
duplicates. Aggregating the duplicate pairs was the first step in the aggregation procedures for
both influent and effluent measurements.
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Table 8-7. Aggregation of Field Duplicates
If the Field
Duplicates Arc:
Censoring Type
of Average Is:
Aggregated Values
Formulas for Aggregated
Values
Both Detected
D
Arithmetic average of measured values.
(Di + D2)/2
Both Non-Detected
ND
Arithmetic average of sample-specific
detection limit (or baseline).
(DLi + DL2)/2
One Detected and
One Non-Detected
D
Arithmetic average of measured value and
sample-specific detection limit (or baseline).
(D + DL)/2
D - Detected.
ND - Non-detected.
DL - Sample-specific detection limit.
Aggregation of Overlapping Samples
For the chemical precipitation data collected from the Hatfield's Ferry, Miami Fort, and Pleasant
Prairie plants, sampling data were available from the EPA sampling, CWA 308 sampling, and
plant self-monitoring. As explained in Section 8.2.1, there was some overlap between the data
from these sources. On some days at a given plant, samples were available from two sources,
specifically plant self-monitoring and either the EPA sampling or CWA 308 sampling. When
these overlaps occurred, the EPA aggregated the measurements from the available samples by
averaging them to obtain one value for that day.
When both measurements had the same censoring type, then the censoring type of the aggregate
was the same as that of the overlapping values. When one or more measurements were detected
(D), the EPA determined that the appropriate censoring type of the aggregate was detected
because the pollutant was confirmed to be present at a level above the sample-specific detection
limit in one of the samples. The procedure for obtaining the aggregated value and censoring type
is similar to the procedure shown in Table 8-7.
8.2.4 Data Editing Criteria
After excluding and aggregating the data, the EPA applied data editing criteria on a pollutant-by-
pollutant basis to select the data sets to be used for developing the limitations for each
technology option. These criteria are referred to as the long-term average test (LTA test). The
EPA often uses the LTA test to ensure that the pollutants are present in the influent at sufficient
concentrations to evaluate treatment effectiveness at the plant for the purpose of calculating
effluent limitations. By applying the LTA test, the EPA ensures that the limitations result from
treatment of the wastewater and not simply the absence or substantial dilution of that pollutant in
the wastestream. For each pollutant for which the EPA calculated a limitation, the influent first
had to pass a basic requirement: the pollutant had to be detected—at any concentration— by 50
percent of the influent measurements. If the data set at a plant passed the basic requirement, then
the data had to pass one of the following two criteria to pass the LTA test:
• Criterion 1. At least 50 percent of the influent measurements in a data set at a
plant were detected at levels equal to or greater than 10 times the baseline value
described in Section 8.2.2.
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•	Criterion 2. At least 50 percent of the influent measurements in a data set at a
plant were detected at any concentration and the influent arithmetic average was
equal to or greater than 10 times the baseline value (described in Section 8.2.2).
If the data set at a plant failed the basic requirement, then the EPA automatically set both Criteria
1 and 2 to "fail," and it excluded the plant's effluent data for that pollutant when calculating
limitations. If the data set for a plant failed the basic requirement, or passed the basic
requirement but failed both criteria, the EPA would exclude the plant's effluent data for that
pollutant when calculating limitations.
After performing the LTA test for the regulated pollutants at each model plant representing the
relevant technology option, the EPA found all chemical precipitation data sets passed the LTA
test and all LRTR and membrane filtration data sets passed the LTA test, except for the
following:
•	Arsenic failed the LTA test at plants 2027 and 2066 in the LRTR data sets.
•	Nitrate-nitrite as N failed the LTA test for plant 2097 in the LRTR data sets.
•	Arsenic failed the LTA test for plants 4058 and 4060 in the membrane data sets.
For those plants where a pollutant failed the LTA test, the associated effluent data for that plant
was excluded from the calculation of the long-term average, variability factors, and effluent
limitations.
8.2.5 Overview of Limitations
The preceding sections discussed the data selection, data exclusions and substitutions, data
aggregation, as well as the data editing procedures that the EPA used to identify the daily values
for calculating effluent limitations. This section describes EPA's objectives for the daily
maximum and monthly average effluent limitations, the selection of percentiles for those
limitations, and compliance with the limitations.
Objectives
The EPA's objective in establishing daily maximum limitations is to restrict discharges on a
daily basis at a level that is achievable for a plant that targets its treatment at the long-term
average.59 the EPA recognizes that variability around the long-term average occurs during
normal operations, which means that plants might, at times, discharge at a level that is higher (or
lower) than the long-term average. To allow for occasional discharges that are at a higher
concentration than the long-term average, the EPA establishes a daily maximum limitation. A
plant that consistently discharges at a level near the daily maximum limitation would not be
operating its treatment system to achieve the long-term average. Targeting treatment to achieve
59 Put simply, the long-term average is the average concentration that is achieved over a period of time. Statistically,
the long-term average is the mean of the underlying statistical distribution of the daily effluent values. The long-
term average is used along with other information about the distribution of the effluent data to calculate the effluent
limitations.
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the daily maximum limitations, rather than the long-term average, might result in values that
frequently 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 plants 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 to achieve the daily maximum limitation. To meet the
monthly average limitation, a plant must counterbalance a value near the daily maximum
limitation with one or more values well below the daily maximum limitation. For the plant to
achieve compliance, these values must result in a monthly average value that is equal to or below
the monthly average limitation.
Selection of Percentiles
The EPA calculates effluent limitations based on percentiles that should be both high enough to
accommodate reasonably anticipated variability within control of the plant, and low enough to
reflect a level of performance consistent with the CWA requirement that these effluent
limitations be based on the best available technology or best available demonstrated control
technology. The daily maximum limitation is an estimate of the 99th percentile of the distribution
of the daily measurements. The monthly average limitation is an estimate of the 95th percentile of
the distribution of the monthly averages of the daily measurements.
The EPA uses the 99th and 95th percentiles to draw a line at a definite point in the statistical
distributions that would ensure that plant operators work to establish and maintain the
appropriate level of control. These percentiles reflect a longstanding Agency policy judgment
about where to draw the line. The development of the limitations takes into account the
reasonably anticipated variability in discharges that may occur at a well-operated plant. By
targeting its treatment at the long-term average, a well-operated plant will be able to comply with
the effluent limitations at all times because the EPA has incorporated an appropriate allowance
for variability in the limitations.
The EPA's methodology for establishing effluent limitations based on certain percentiles of the
statistical distributions may give the impression that the EPA expects occasional exceedances of
the limitations. This conclusion is incorrect. The EPA promulgates limitations that plants are
capable of complying with at all times by properly operating and maintaining their treatment
technologies. These limitations are based on statistical modeling of the data and engineering
review of the limitations and data.
Statistical methodology is used as a framework to establish limitations based on percentiles of
the effluent data. Statistical methods provide a logical and consistent framework for analyzing a
set of effluent data and determining values from the data that form a reasonable basis for effluent
limitations. In conjunction with the statistical methods, the EPA performs an engineering review
to verify that the limitations are reasonable based on the design and expected operation of the
treatment technologies and the plant process conditions. As part of that review, the EPA
examines the range of performance reflected in the plant data sets used to calculate the
limitations. The plant data sets represent operation of a treatment technology that represents the
best available technology or best available demonstrated control technology. In some cases,
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however, although these plants were operating a model technology, these data sets, or periods of
time within a data set, may not necessarily represent the optimized performance of the
technology. As described in Section 8.2.2, the EPA excluded certain data from the data sets used
to calculate the effluent limitations. At the same time, however, the data sets used to calculate
effluent limitations still retain some observations that likely reflect periods of less than optimal
performance. The EPA retained these data in developing the limitations because they help to
characterize the variability in treatment system effluent. Based on the combined statistical
modeling and engineering review used to establish the limitations, plants are expected to design
and operate their treatment systems in a manner that will ensure compliance with the limitations.
The EPA does not expect plants to operate their treatment systems to violate the limitations at
some pre-set rate merely because probability models are used to develop limitations.
8.2.6 Calculation of The Limitations
The EPA calculated the limitations by multiplying the long-term average by the appropriate
variability factors. In deriving the limitations for a pollutant, the EPA first calculates an average
performance level (the "option long-term average," discussed below) that a plant with well-
designed and well-operated model technology is capable of achieving. This long-term average is
calculated using data from the model plant (plants with the model technologies) for the
technology option.
In the second step of developing a limitation for a pollutant, the EPA determines an allowance
for the variation (the "option variability factor" discussed below) in pollutant concentrations for
wastewater that has been processed through a well-designed and well-operated treatment
system(s). This allowance for variation incorporates all components of potential variability,
including sample collection, sample shipping and storage, and analytical variability. The EPA
incorporates this allowance into the limitations by using the variability factors that are calculated
using data from the model plants. If a plant operates its treatment system to meet the relevant
long-term average, the EPA expects the plant will be able to meet the limitations. Variability
factors provide an additional assurance that normal fluctuations in a plant's treatment process are
appropriately accounted for in the limitations. By accounting for these reasonable excursions
above the long-term average, EPA's use of variability factors results in effluent limitations that
are above the long-term averages.
The following sections describe derivation of the option long-term averages, option variability
factors and limitations, and the adjustment made for autocorrelation in the calculation of the
limitations for this proposed rulemaking. For information regarding the derivation of limitations
for the 2015 rule, see Section 13 of the 2015 TDD.
Calculation of Technology Option Long-Term Average
The EPA calculated the technology option long-term average for a pollutant in two steps. First,
the EPA calculated the plant-specific long-term average for each pollutant that had enough
distinct detected values by fitting a statistical model to the daily concentration values. In cases
when a data set for a specific pollutant does not have enough distinct detected values to use the
statistical model, the plant-specific long-term average for each pollutant is the arithmetic mean of
the available daily concentration values. Appendix B of the 2015 TDD presents an overview of
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Section 8—Effluent Limitations
the statistical model and describes the procedures the EPA used to estimate the plant-specific
long-term average.
Second, the EPA calculated the option long-term average for a pollutant as the median of the
plant-specific long-term averages for that pollutant. The median is the midpoint of the values
when ordered (i.e., ranked) from smallest to largest. If there are an odd number of values, then
the value of the mth ordered observation is the median (where m=(n+l)/2 and n=number of
values). If there are an even number of values, then the median is the average of the two values
in the nl2'h and [(n/2)+ l J'''positions among the ordered observations.
Calculation of Option Variability Factors and Limitations
The following describes the calculations performed to derive the option variability factors and
limitations. First, the EPA calculated the plant-specific variability factors for each pollutant that
had enough distinct detected values by fitting a statistical model to the daily concentration
values. Each plant-specific daily variability factor for each pollutant is the estimated 99th
percentile of the distribution of the daily concentration values divided by the plant-specific long-
term average. Each plant-specific monthly variability factor for each pollutant is the estimated
95th percentile of the distribution of the 4-day average concentration values divided by the plant-
specific long-term average. The calculation of the plant-specific monthly variability factor
assumes that the monthly averages are based on the pollutant being monitored weekly
(approximately four times each month). In cases when there were not enough distinct detected
values for a specific pollutant at a specific plant, then the statistical model was not used to obtain
the variability factors for that plant. In these cases, the EPA excluded the data for the pollutant at
the plant from the calculation of the option monthly variability factors. Appendix B of the 2015
TDD describes the procedures used to estimate the plant-specific daily and monthly variability
factors.
Next, the EPA calculated the option daily variability factor for a pollutant as the mean of the
plant-specific daily variability factors for that pollutant. Similarly, the option monthly variability
factor was the mean of the plant-specific monthly variability factors for that pollutant.
Finally, the EPA calculated the daily maximum limitations for each pollutant for each
technology option by multiplying the option long-term average and option daily variability
factors. The monthly average limitations for each pollutant for each technology option are the
product of the option long-term average and option monthly variability factors.
Adjustment for Autocorrelation
Effluent concentrations that are collected over time may be autocorrelated. The data are
positively autocorrelated when measurements taken at specific time intervals, such as one or two
days apart, are more similar than measurements taken far apart in time. For example, positive
autocorrelation would occur if the effluent concentrations were relatively high one day and were
likely to remain high on the next and possibly succeeding days. Because the autocorrelated data
affect the true variability of treatment performance, the EPA typically adjusts the variance
estimates for the autocorrelated data, when appropriate.
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Section 8—Effluent Limitations
For this rulemaking, whenever there were sufficient data for a pollutant at a plant to evaluate the
autocorrelation reliably, the EPA estimated the autocorrelation and incorporated it into the
calculation of the limitations. For a plant without enough data to reliably estimate the
autocorrelation, when there was a correlation of a pollutant available from a similar technology
and wastestream and the pollutant removal processes were similar, the EPA transferred the
autocorrelation estimates from that treatment technology. Otherwise, the EPA set the
autocorrelation to zero in calculating the limitations, because the Agency did not have sufficient
data to reliably evaluate whether the data were autocorrelated or to determine whether a valid
autocorrelation estimate could be transferred from a similar technology and wastestream. The
following paragraphs describe the instances where the EPA was able to estimate autocorrelation
and the assumptions made about the autocorrelation when there were too few observations to
estimate the possible autocorrelation.
For the chemical precipitation treatment option for FGD wastewater, the EPA was able to
perform a statistical evaluation of the autocorrelation and obtain a reliable estimate of the
autocorrelation. Table 8-8 lists the autocorrelation values used in the limitations calculation for
arsenic and mercury for the chemical precipitation option.
For the LRTR treatment technology for FGD wastewater, the EPA was able to perform a
statistical evaluation and obtain a reliable estimate of the autocorrelation for selenium and
mercury because enough data were available for these pollutants. Because of the similarities
between the pollutant removal processes, the EPA determined that it would be appropriate to
also use the values estimated for selenium and mercury as the autocorrelation estimates for
nitrate-nitrite as N and arsenic, respectively. Table 8-8 below lists the autocorrelation values
used in the limitations calculation for arsenic, mercury, nitrate-nitrite as N and selenium for the
LRTR treatment option.
For the membrane treatment option for FGD, the EPA was not able to perform a statistical
evaluation of the autocorrelation and obtain a reliable estimate of the autocorrelation because
there were too few detected observations available. Thus, for this technology option, the EPA set
the autocorrelation to zero in the calculation of the limitations. The EPA did so because there
were not sufficient data to reliably evaluate the autocorrelation, nor did the EPA have a valid
correlation estimate available that could be transferred from a similar technology and
wastestream.
Table 8-8. Autocorrelation Values Used in Calculating Limitations for FGD Wastewater
1 iViiliiionl Techn»lo»\
Polliiliinl
( orivliilion Value I sod In ( ;ileul;ile
l.iiniliilion
CP+LRTR
Arsenic
0.53
Mercury
0.53
Selenium
0.66
Nitrate-nitrite as Na
0.66
Chemical Precipitation
Arsenic b
0.86
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Section 8—Effluent Limitations
Table 8-8. Autocorrelation Values Used in Calculating Limitations for FGD Wastewater
Treatment Technology
Pollutant
Correlation Value Used to Calculate
Limitation

Mercury
0.89
a - There were not enough detected values for nitrate-nitrite as N, so the EPA was not able to directly calculate the
autocorrelation. However, the EPA transferred the autocorrelation from selenium because these two chemicals
behave similarly in the biological treatment system.
b - There were not enough detected values for arsenic, so the EPA was not able to directly calculate the
autocorrelation. However, the EPA transferred the autocorrelation from mercury because these two chemicals
behave similarly in a properly operated chemical-biological treatment system using all aspects of the CP+LRTR
technology.
8.2.7 Long-Term Averages and Effluent Limitations for FGD Wastewater
Table 8-9 presents the proposed effluent limitations for discharges of FGD wastewater. As
described in Section 8.2.2, the EPA evaluated what the limitations would be using baseline
substitution, as well as what the limitations would be without adjusting for baseline substitution.
The limitations presented for the proposed rule use the higher result. Table 8-9 also presents the
long-term average treatment performance calculated for the selected treatment technology
option. Due to routine variability in treated effluent, a power plant that targets its treatment to
achieve pollutant concentrations at a level near the values of the daily maximum limitation or the
monthly average limitation may experience frequent values exceeding the limitations. For this
reason, the EPA recommends that plants design and operate the treatment system to achieve the
long-term average for the model technology. In doing so, a system that is designed to represent
the BAT level of control would be expected to meet the limitations.
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Section 8—Effluent Limitations
Table 8-9. Long-Term Averages and Effluent Limitations for FGD Wastewater
1 iviilmonl
Tc'chnol(>ti\ ISiisis
Polliiliini
l.ong-1 orin
A\oi'iijie
l);iil\
M ;i\iiiin in
l.iiniliilioii
Monthly A\cr;i^c
l.iiniliilioii
CP+LRTR3
Arsenic (ug/L)
5.07
18
9
Mercury (ng/L)
13.5
85
31
Nitrate-nitrite as N (mg/L)
2.62
4.6
3.2
Selenium (ug/L)
16.6
76
31
Memb ranc Fi 11 ratio n
(Voluntary Incentives
Program)
Arsenic (ug/L)
5.0 b
5 0
	d
Mercurv (ng/L)
5.08
21
9
Nitrate-nitrite as N (mg/L)
0.40
1.1
0.6
Selenium (ug/L)
5.0
21
11
Bromide (mg/L)
0.163
0.6
0.3
TDS (mg/L)
88.0
351
156
Chemical Precipitation
(High Flow and Low
Utilization
Subcategories)
Arsenic (ug/L)
5.98
11
8
Mercury (ng/L)
159
788
356
a - The CP+LRTR effluent limitations would apply to all plants not in the Voluntary Incentives Program, High
Flow Subcategory, or Low Utilization Subcategory.
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 evaluated data set(s).
d - The EPA is not establishing monthly average limitations when the daily maximum limitation is based on the
quantitation limit.
8.3	Selection of Regulated Pollutants for Bottom Ash Transport Water
Section 6.3.1 describes the pollutants present in bottom ash transport water. To the extent that the
proposed regulatory options are eliminating or nearly eliminating the discharge of bottom ash
transport water through high rate recycle, the discharge of all pollutants present in bottom ash
transport water will decrease and therefore be regulated.
8.4	Effluent Limitations for Bottom Ash Transport Water
As described in the preamble, the EPA is proposing a pollutant discharge allowance in the form
of a maximum percentage purge rate for bottom ash transport water. To develop this allowance,
the EPA first collected data that could be used to estimate the volume of wastewater that a plant
operating a high recycle rate system may need to discharge to either better facilitate managing
the water balance or to adjust water chemistry by diluting the transport water remaining in the
bottom ash system.60
Specifically, the EPA reviewed at a report that presents discharge data from seven currently
operating wet bottom ash transport water systems at six plants. These plants were able to recycle
most or all bottom ash transport water from these seven systems, resulting in discharges of
60 Although the technology basis includes dry handling, the limitation is based on the necessary purge volumes of a
wet, high recycle rate bottom ash system.
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Section 8—Effluent Limitations
between zero and two percent of the system volume (EPRI, 2016). In order to account for
infrequent precipitation and maintenance events, in addition to the proposed purge rate, the EPA
reviewed hypothetical maximum discharge volumes and the estimated frequency associated with
such infrequent events for wet bottom ash systems (EPRI, 2018).61
To estimate the allowance percentage associated with such infrequent events, the EPA divided
the hypothetical discharge associated with an assumed maintenance and precipitation event by
the volume of the transport water system, and then averaged the resulting percent over 30 days.
Finally, the EPA added each reported regular discharge percent for the seven operating systems
to the hypothetical infrequent discharge percent under four scenarios: (l)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 hypothetical discharge scenarios are reported in Table 8-10 below.
The EPA selected a 95th percentile of the data distribution (approximately 10 percent of total
system volume) as representative of the 30-day rolling average.
Table 8-10. Thirty-Day Rolling Average Discharge Volume as a Percent of System
Volume3
Inl'miiicul l)isch;iriic Needs
Ko'^uliii' Dischiiriio l-'or Purpose of Ad justing \\ ;i(cr ( lu'inisln ;md/or
\\ ;iK-r liiihinci-
Type of Infrequent
Discharge Event
30-Day
Average
Plant A
Plant B
Plant C
Plant D
Plant E
Plant F-
Systeml
Plant F-
System2
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%
Source: EPRI, 2016; EPRI, 2018.
a - These estimates sum actual, reported, plant-specific regular discharge needs with varying combinations of
hypothetically estimated, infrequent discharge needs.
This proposed rule includes BAT effluent limitations and standards on any wastewater purged
from a high recycle rate system established by the permitting authority on a case-by-case basis
using BPJ.
8.5 References
1.	CSC. 2013. Computer Sciences Corporation. Results of the ICP/MS Collision Cell
Method Detection Limit Studies in the Synthetic Flue Gas Desulfurization Matrix.
(16 January). DCN SE03872.
2.	EPRI. 2016. Electric Power Research Institute. Guidance Document for Management of
Closed-Loop Bottom Ash Handling Water in Compliance with the 2015 Effluent
Limitations Guidelines (ELGs). Palo Alto, CA. (December). DCN SE06963.
61 The EPA did not consider events such as pipe leaks as these would not be reflective of proper system operation.
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Section 8—Effluent Limitations
3.	EPRI. 2018. Electric Power Research Institute. Closed-Loop Bottom Ash Transport
Water: Costs and Benefits to Managing Purges. Palo Alto, CA. (September). DCN
SE06920.
4.	U.S. EPA. 2002. U.S. Environmental Protection Agency. Development Document for
Final Effluent Limitations Guidelines and Standards for the Iron and Steel
Manufacturing Point Source Category. Washington, DC. (April). EPA-821-R-02-004.
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