Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

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Regulation of Power Plant Wastewater

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February 3, 2016

Congressional Research Service

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R43169

Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

Summary

To implement the Clean Water Act (CWA), the Environmental Protection Agency (EPA) issues

effluent limitation guidelines (ELG), or technology-based standards, for categories of industrial

dischargers. These standards are implemented through permits issued by states or EPA to

individual facilities. In November 2015, EPA promulgated revised effluent limitations for the

steam electric power industry to replace rules that were issued in 1982. The new rule was

effective on January 4, 2016.

Two factors have altered existing wastestreams or created new wastestreams from many power

plants since promulgation of the 1982 ELG. These factors are the development of new

technologies for generating electric power, such as coal gasification, and, as a result of federal

and state requirements, the widespread implementation of air pollution controls to reduce

emissions of hazardous air pollutants and acid gases, such as flue gas desulfurization (scrubber)

systems. While scrubbers dramatically reduce emissions of harmful pollutants into the air, some

create a significant liquid waste stream. As a result, pollutant discharges from this industry to

surface waters have increased in volume, with additional chemical constituents, and EPA believes

that many current CWA permits for power plants do not fully address potential water quality

impacts of these discharges.

Based on studies of the industry and to settle litigation brought by environmental advocates, EPA

proposed a rule in April 2013 to revise the steam electric ELG and issued a final rule in

November 2015. A total of 1,080 steam electric plants that burn fossil fuels and whose primary

purpose is generating electricity are subject to the ELG. Only a subset of these plants is likely to

incur compliance costs as a result of the 2015 rule—only 133—because a large portion of the

industry has already implemented processes or technologies that are required by the rule. All of

the plants that are expected to incur compliance costs are coal- or petroleum coke-fired. EPA

estimates that the annualized compliance costs for the rule are $496 million pre-tax and $340

million after-tax, costs that the agency believes are economically achievable and would have

minimal effects on the electricity market, both nationally and regionally. The rule also would

reduce pollutant discharges by 385 million pounds annually and reduce water use by 57 billion

gallons per year. Estimated costs of the rule exceed estimates of monetized benefits; however, the

CWA does not require that the benefits of regulation exceed or even equal the costs.

An EPA rule under the Resource Conservation and Recovery Act (RCRA) on managing coal

combustion residuals (CCR) also relates to the CWA ELG rule, because both statutes address coal

ash that is generated by power plants and released to the environment. The scope of the CWA and

RCRA rules differ. While both address disposal of CCR in surface impoundments at power

plants, only the RCRA rule regulates disposal of CCRs in landfills. To coordinate the two rules, in

the final CCR rule, EPA extended by one year that rule’s deadline for owners or operators of

covered facilities to prepare a closure plan. This would give owners or operators 24 months after

publication of the CCR rule, or slightly more than 6 months after the effective date of the revised

ELG, to understand the requirements of both regulations and to make the appropriate business

decisions and prepare closure and post-closure plans.

Many in industry are concerned that the 2015 rule will impose new requirements and compliance

timelines at the same time that power plants are implementing other EPA rules. One issue

concerns impacts of the proposal on small entities, including small businesses and small

governmental jurisdictions. Environmental advocates view the ELG differently from industry and

reportedly are generally satisfied with the final rule, but many do have concerns with issues such

as compliance deadlines in the rule. Both industry groups and environmental groups have

challenged the rule in federal court.

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

EPA rules affecting steam electric power plants have been scrutinized and criticized based on

their stringency, feasibility, and projected compliance costs. Congressional interest has been

evident in legislation to alter the direction and substance of some of EPA’s regulatory actions and

initiatives. To this point, discussion of the power plant ELG has centered on the administrative

proceedings at EPA and has not drawn specific attention of lawmakers.

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

Contents

Introduction ..................................................................................................................................... 1

Background ..................................................................................................................................... 1

Steam Electric Power Industry ELG ............................................................................................... 3

Overview of Sources Regulated under the Final Rule .............................................................. 4

Overview of the 1982 and 2015 Revised Rules ........................................................................ 5

Revised Requirements for Direct Discharges ..................................................................... 7

Revised Requirements for Indirect Discharges to Publicly Owned Treatment

Works (POTWs) .............................................................................................................. 9

Relationship of the ELG to Other EPA Rules and Rulemakings ............................................. 10

The ELG and the CCR Rule under RCRA ....................................................................... 10

BMPS for CCR Impoundments ......................................................................................... 11

Timing of New Requirements ................................................................................................. 12

“Legacy” Wastewater .............................................................................................................. 12

Costs and Benefits of the ELG ...................................................................................................... 13

Compliance Costs.................................................................................................................... 13

Environmental Benefits/Pollutant Reductions Compared with Costs ..................................... 16

Issues ............................................................................................................................................. 17

Conclusion ..................................................................................................................................... 19

Tables

Table 1. Pollutant Discharge Limitations and Technology Basis for 2015 Steam Electric

Generating Point Source Category Effluent Limitations Guidelines and Standards .................... 6

Appendixes

Appendix. Steam Electric Power Plant Wastestreams Regulated under the 2015 Revised

ELG ............................................................................................................................................ 20

Contacts

Author Contact Information .......................................................................................................... 24

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

Introduction

Since 2009, the Environmental Protection Agency (EPA) has proposed, promulgated, and is

developing a number of regulations affecting the operation of the nation’s steam electric power

plants. Given the central role of electric power in the nation’s economy, concerns have been

raised about the cost and potential impact of many of these regulations.

Industry and environmental advocacy groups have been keenly interested in both the substance of

these rules and schedules for their implementation. A particular issue has been whether the

regulations, especially the cumulative impact of implementing multiple rules, will lead to

retirement of a significant number of electric generating units, with negative effects on the

reliability of the nation’s power supply. All together, these rules have been characterized by critics

as a regulatory “train wreck” that would impose excessive costs and lead to plant retirements that

could threaten the adequacy of electricity capacity across the country. EPA and many other

analysts maintain that this will not be the case.

Much of the criticism addressed to EPA’s actions has concerned Clean Air Act rules, but Clean

Water Act (CWA) rules also have been part of the discussion, such as a 2014 rule to regulate

cooling water intake structures at power plants and some industrial sources.1 The most recent

major rule affecting power plants that EPA has promulgated concerns limits on discharges of

wastewater, and it is the subject of this report. It is the last of a suite of Obama Administration

utility sector rules that also includes greenhouse gas standards for utilities and a rule for disposal

of coal combustion residuals from power plants. The CWA power plant rule is a complex

regulation, involving limits on six pollutant wastestreams. Finalized in November 2015, it

updates standards that were issued more than 30 years ago, which did not reflect today’s power

plant technology.

Background

The 1972 CWA established a comprehensive program to “restore and maintain the chemical,

physical and biological integrity of the Nation’s waters.” To implement the act, EPA was directed

to issue effluent limitation guidelines and standards, or technology-based regulations, for

industrial dischargers. The effluent limitation guidelines (ELG) are to reflect pollutant reductions

that can be achieved by categories or subcategories of industrial point sources using technologies

that represent appropriate levels of control. Since 1972, EPA has promulgated effluent limitation

guidelines for 57 industrial categories, including for the steam electric power industry.

For point sources that introduce pollutants directly into U.S. waters (termed direct dischargers),

limits on specific pollutants set in effluent guidelines are implemented through National Pollutant

Discharge Elimination System (NPDES) permits that are issued by EPA or states. For sources that

discharge to publicly owned treatment works, or POTWs (termed indirect dischargers), EPA

promulgates pretreatment standards that apply to those sources and are enforced by POTWs, and

state and federal authorities. The guidelines and standards apply to direct and indirect discharges

of conventional pollutants;2 toxic pollutants, including toxic metals and toxic organic pollutants;

For information, see CRS Report R41786, Cooling Water Intake Structures: Summary of the EPA Rule, by (name re

dacted) .

CWA §304(a)(4) designates the following as conventional pollutants: biochemical oxygen demand (BOD5), total

suspended solids, fecal coliform, pH, and any additional pollutants defined by EPA as conventional; EPA designated

oil and grease as an additional conventional pollutant in 1979.

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

and non-conventional pollutants, which are all other pollutants that are not categorized as

conventional or toxic (e.g., ammonia-N, phosphorus, and total dissolved solids).

The CWA established several different kinds of effluent limitations, four for new and existing

direct dischargers and two for new and existing indirect dischargers. Effluent limitations are

based on performance of specific technologies, but regulations do not require use of a specific

control technology. In establishing effluent limitations, EPA considers the cost and/or economic

achievability of the controls. The economic test differs based on the level of control specified in

the ELG.



Best Practicable Control Technology Currently Available (BPT)—BPT

limitations generally are based on the average of the best existing performance of

plants within the industry or subcategory. In specifying BPT, EPA considers the

total cost of applying the control technology in relation to the effluent reduction

benefits, as well as the age of the equipment and facilities, processes employed,

and other factors. BPT limitations can cover conventional, toxic, and nonconventional pollutant discharges.

Best Available Technology Economically Achievable (BAT)—BAT limitations

generally represent the best existing performance in the industrial category or

subcategory. BAT is the principal national means of controlling toxic and

nonconventional pollutant discharges. Factors considered in assessing BAT

include the cost of achieving BAT effluent reductions, processes employed, and

other factors. The EPA Administrator has considerable discretion in assigning the

weight accorded to these factors. BAT limitations may be based on effluent

reductions attainable through changes in a facility’s processes and operations.

Best Conventional Pollutant Control Technology (BCT)—BCT is not an

additional limitation, but it replaces BAT for the control of conventional pollutant

discharges from existing industrial sources. The statute specifies factors to be

assessed in determining BCT, including a two-part “cost reasonableness” test.

New Source Performance Standards (NSPS)—NSPS are based on the best

available demonstrated control technology (BADCT) and represent the most

stringent control attainable through the application of technology. New plants

have the opportunity to install the best and most efficient production processes

and wastewater treatment technologies. EPA is directed to take into consideration

the cost of achieving the effluent reduction and any non-water quality

environmental impacts and energy requirements.

Pretreatment Standards for Existing Sources (PSES)—PSES are designed to

control the discharge of pollutants that pass through, interfere with, or are

otherwise incompatible with the operation of a POTW. PSES standards are

analogous to BAT for direct dischargers.

Pretreatment Standards for New Sources (PSNS)—Like PSES, PSNS are

designed to control the discharge of pollutants that pass through, interfere with,

or are otherwise incompatible with the operation of a POTW. EPA considers the

same factors in promulgating PSNS that it does in promulgating NSPS.

The requirements of the statute embody the concept that, over time, industrial sources will

achieve greater pollutant removal by employing progressively more stringent technologies. Thus,

the 1972 law required sources to achieve effluent limitations based on BPT by July 1, 1977, and

effluent limitations based on BAT by July 1, 1983 (in 1987 Congress modified the BAT

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

compliance date to March 31, 1989). New sources are expected to comply with applicable

effluent limitations when they commence operation.

Requirements of ELGs apply to direct discharges through incorporation into NPDES permits

issued by EPA or authorized states under CWA Section 4023 and to indirect discharges through

local pretreatment programs under CWA Section 307.4

Steam Electric Power Industry ELG

EPA initially promulgated effluent limitation guidelines for the steam electric industry in 1974

and issued revised standards in 1982.5 The 1982 rules apply to about 1,100 nuclear- and fossilfueled steam electric power plants nationwide, 495 of which are coal-fired.

Under CWA Section 301(d), EPA has a duty to review existing effluent limitation guidelines at

least every five years and, if appropriate, revise them. EPA had been studying the ELG for the

steam electric power generating category since the mid-1990s and on several occasions indicated

that a preliminary study of discharges from this category was necessary. During the 2005 review

of the existing effluent guidelines for all categories, EPA identified the rules governing the steam

electric power point source category for possible revision, based in part on data showing that the

industry ranked high in discharges of toxic and nonconventional pollutants. Power plant

discharges account for about 30% of all toxic pollutants discharged into U.S. surface waters by all

industrial categories that are regulated under the CWA.6

Broadly speaking, two factors have altered existing wastestreams or created new wastestreams at

many power plants since promulgation of the 1982 power plant ELG. The first is the development

of new technologies for generating electric power, such as coal gasification. The second, a result

of federal and state requirements, is the widespread implementation of air pollution controls to

reduce emissions of hazardous air pollutants and acid gases (e.g., flue gas desulfurization [FGD],

selective catalytic reduction [SCR], and flue gas mercury controls [FGMC]). In particular, the use

of wet FGD systems (the kind that generate liquid discharges) to control sulfur dioxide air

emissions has increased significantly since 1982. Consequently, each year the pollutant

discharges from this industry are increasing in volume, with additional chemical constituents.

They account for 50%-60% of all toxic pollutants discharged into surface waters by all industrial

categories currently regulated under the CWA, according to EPA. The main pollutants of concern

for these discharges include metals (mercury, arsenic, selenium), nitrogen, and total dissolved

solids (TDS).

EPA initiated a study, completed in 2009,7 which found that the 1982 regulations did not

adequately address the pollutants being discharged and have not kept pace with changes that have

occurred in the electric power industry over the last three-plus decades, specifically the increase

of FGD systems, or scrubbers, at coal-fired power plants to control air pollution. According to

EPA, as of 2008, 30% of coal-fired power plants were using FGD systems to control sulfur

33 U.S.C. §1342. EPA has authorized 46 states to administer the NPDES permit program. See http://www.epa.gov/

npdes/npdes-state-program-information.

33 U.S.C. §1317. EPA has authorized 36 states to administer pretreatment programs.

40 CFR Part 423.

U.S. Environmental Protection Agency, Office of Water, Final Effluent Limitations Guidelines and Standards for the

Steam Electric Power Generating Industry, Fact sheet, September 2015.

U.S. Environmental Protection Agency, Steam Electric Power Generating Point Source Category: Final Detailed

Study Report, EPA 821-R-09-008, October 2009.

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

dioxide emissions from the flue gas generated in the plants’ boilers and prevent buildup of certain

corrosive constituents such as chlorides, and by 2025, nearly 80% of coal-fired generating

capacity is expected to employ FGD systems. While scrubbers dramatically reduce emissions of

harmful pollutants into the air, some create a significant liquid waste stream (especially wet

scrubbers). In addition, discharges from coal combustion residual (CCR) surface impoundments

at steam electric power plants have a potential to degrade water quality. EPA believes that many

current CWA permits for power plants do not fully address potential water quality impacts of

these discharges through appropriate pollutant limits and monitoring and reporting requirements.

In addition, EPA identified several wastestreams that are relatively new to the industry (e.g.,

carbon capture wastewater) and others for which there is little characterization data (e.g.,

gasification wastewater).

In 2009, environmental groups sued EPA to compel the agency to commit to a schedule for

issuing revised guidelines for this industry. Pursuant to a 2010 consent decree that it entered into

with these litigants, EPA agreed to propose the revised power plant ELG by July 23, 2012, and to

finalize the rule by January 31, 2014. These dates were subsequently modified and required EPA

to propose revised effluent limitations by April 2013, and publish a final rule 13 months later.8

Pursuant to that agreement, EPA proposed revised standards on April 19, 2013. Public comments

on the proposal were accepted until September 20, 2013. In April 2014, EPA and the

environmental litigants agreed to give the agency an additional 16 months—until September 30,

2015—to finalize the effluent guidelines for the power plant sector. EPA announced the final rule

on September 30, 2015; it was published in the Federal Register on November 3, 2015, and

became effective on January 4, 2016.9

Overview of Sources Regulated under the Final Rule

The revised ELG applies to two broad categories of firms in the electric generating industry,

electric utilities and non-industrial non-utilities. Both categories produce electric power for

distribution and/or sale. Non-industrial non-utilities (which generally operate in a non-regulated

pricing environment) account for 49% of plants but represent only 30% of total U.S. generating

capacity. Utilities, which generally operate in a rate regulation framework, consist of investor

owned utilities that account for about 50% of all U.S. electric generating capacity; publicly

owned utilities (federal, state, and municipalities) that represent 13% of U.S. electric generation

capacity; and rural electric cooperatives, representing 4% of U.S. generating capacity.

Consent decree in Defenders of Wildlife and Sierra Club v. EPA, Case No. 10-cv-1915, D.C. D.C., December 12,

2012. Electric utility industry groups, which were not parties to the consent decree, attempted to challenge the dates in

the consent decree, but a federal appeals court ruled that the industry lacked standing to intervene in the consent decree

that compelled EPA to follow a timeline for the rulemaking. Defenders of Wildlife v. EPA, D.C. Cir., No. 12-5122,

April 23, 2013.

U.S. Environmental Protection Agency, “Effluent Limitations Guidelines and Standards for the Steam Electric Power

Generating Point Source Category, Final Rule,” 80 Federal Register 67838-67903, November 3, 2015. EPA also issued

several supporting documents in connection with the final rule. Technical Development Document for the Effluent

Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category, Document No.

821-R-15-007, September 2015, hereinafter, TDD; Environmental Assessment for the Effluent Limitations Guidelines

and Standards for the Steam Electric Generating Point Source Category, Document No. 821-R-15-006, September

2015; Benefit and Cost Analysis for the Effluent Limitations Guidelines and Standards for the Steam Electric Power

Generating Point Source Category, Document No. 821-R-15-005, September 2015, hereinafter, Benefit-Cost; and

Regulatory Impact Analysis for the Effluent Limitations Guidelines and Standards for the Steam Electric Power

Generating Point Source Category, Document No. 821-R-15-004, September 2015, hereinafter, RIA. See

http://www.epa.gov/eg/steam-electric-power-generating-effluent-guidelines-2015-final-rule-documents.

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

The number of steam electric plants subject to the ELG is 1,080 (units that do not burn fossil

fuels or plants with a primary purpose other than generating electricity are not subject to the

ELG). These plants operate approximately 1,210 generating units with total capacity of 741,000

megawatts (MW) of electricity. According to data compiled by EPA for the rulemaking, the 1,080

steam electric plants represent about 19% of the total number of plants in the power generation

sector, but represent about 70% of the total national electric generating capacity. The vast

majority (93%) burn at least some amount of either coal or natural gas, and 74% of the steam

electric units in the industry burn more than one type of fuel (e.g., coal and oil, coal and gas).

Coal- and petroleum-coke fired plants comprise 44% of the 1,080 plants subject to the ELG. Coal

is the most common primary fuel type for stand-alone steam turbines, while gas is the primary

fuel for nearly all combined cycle systems. Oil-fired units account for about 5% of generating

units, and nuclear plants account for about 4.5%.10

The largest capacity plants (>500 MW) comprise 63% of all steam electric power plants and 92%

of the steam electric generating capacity for all plants regulated by the ELG. Most steam electric

power plants are either gas- or coal-fired and have a generating capacity greater than 500 MW.

The smallest plants, under 100 MW, comprise about 10% of plants and provide less than 1% of

generating capacity, according to the industry data used in the rulemaking.11

Overview of the 1982 and 2015 Revised Rules

The 1982 pollutant discharge limitations apply to the following wastestreams: once-through

cooling water, cooling tower blowdown, bottom ash transport water, fly ash transport water,

boiler blowdown, metal cleaning wastes, low volume wastes,12 and material storage and

construction site runoff (including coal pile runoff). The 1982 ELG contains standards for BPT,

BAT, and PSES for existing sources and NSPS and PSNS for new sources.

The 2013 proposal addressed BAT and PSES for existing sources, and NSPS and PSNS

requirements for new sources.13 EPA proposed to establish new or additional requirements for

seven processes utilized by steam electric power plants and byproducts of those processes. EPA

had found that these wastestreams, some of which were not evaluated or were evaluated to only a

limited extent during the previous rulemakings, contain pollutants in concentrations and mass

loadings that cause documented environmental impacts. EPA also determined that treatment

technologies to reduce or eliminate the pollutant discharges are available, economically

achievable, and have acceptable non-water quality environmental impacts.

In developing the 2013 proposal, EPA evaluated eight regulatory options14 and ultimately

identified four preferred alternatives out of the eight for regulation of existing discharges and one

preferred alternative for regulation of new sources. In the proposed rule, EPA did not express a

preference for any one of the four options for existing sources that discharge directly to surface

water. The options differed in the wastestreams controlled by the regulation, the size of the units

TDD, p. 4-17, Table 4-3.

TDD, pp. 4-16–4-17, Table 4-4.

Under the 1982 ELG, low volume wastes meant wastewater from all sources except those for which specific

limitations are included, such as wastewater from boiler blowdown or floor drains.

EPA did not propose to revise the 1982 BPT effluent guidelines, because the statutory deadline for compliance with

BPT limits is long passed, and the same wastestreams would be controlled at the more stringent BAT and NSPS levels

of the rule.

The eight regulatory options are shown in 78 Federal Register 34458 (June 7, 2013), Table VII-1.

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

controlled, and the types of controls. Each of the options was successively more stringent in terms

of pollutant removal, as well as more costly to implement.

The 2015 revised rule contains BAT and PSES standards for existing sources and NSPS and

PSNS requirements for new sources, which apply to the following wastestreams: FGD

wastewater, fly ash transport water, bottom ash transport water, flue gas mercury control (FGMC)

system wastewater, gasification wastewater, and combustion residual leachate from landfills or

surface impoundments. The requirements for these wastestreams are summarized in Table 1 and

are described below. (The six wastestreams are described in more detail in the Appendix to this

report.)15

In developing the 2015 revised rule, EPA evaluated five regulatory options for existing sources—

three were identical to options in the 2013 proposal, and two were variants of options in the

proposed rule.16 The BAT and PSES requirements for existing sources in the final rule are one of

the variants. These requirements are most similar to the proposed rule’s preferred option for new

sources—and thus, most stringent—with the exception of one wastestream—combustion residual

leachate. For that wastestream, the final rule establishes BAT standards equivalent to BPT

requirements contained in the 1982 ELG.17 For new sources (NSPS and PSNS), the final rule

establishes standards at levels generally similar to the 2013 proposed rule. A new source is one

that begins operation on November 17, 2015, or later.18

Table 1. Pollutant Discharge Limitations and Technology Basis for 2015 Steam

Electric Generating Point Source Category Effluent Limitations Guidelines and

Standards

Wastestreams

Flue Gas Desulfurization (FGD)

Wastewater

Fly Ash Transport Water

Pollutant Discharge Limitations

and Technology Basis for

Existing Sources (BAT and

PSES)

Pollutant Discharge Limitations

and Technology Basis for New

Sources (NSPS and PSNS)

Numeric limitations on mercury,

arsenic, selenium, and nitrate/nitrite

as N

Numeric limitations on mercury,

arsenic, selenium, and Total

Dissolved Solids (TDS)

Chemical precipitation + biological

control technology

Evaporation control technology

Zero discharge of pollutants

Dry handling control technology

The 2013 proposed rule also included provisions to establish BAT/NSPS/PSES/PSNS standards for a seventh

wastestream, non-chemical metal cleaning wastes, and to set those standards equal to BPT limits in the 1982 rules for

chemical metal cleaning wastes. However, because EPA determined that it did not have sufficient information on

discharges of non-chemical cleaning wastes or available control technologies, the 2015 revised rule reserves

BAT/NSPS/PSES/PSNS for non-chemical metal cleaning wastes, as the previous regulations did. TDD, p. 8-37.

EPA believes that none of the additional regulatory options considered for the final rule involves regulation of

different pollutants or wastestreams, or the application of different control technologies, than those explicitly

considered and presented in the proposed rule. 80 Federal Register 67848.

A more stringent standard for combustion residual leachate that EPA considered but rejected would have required

technology based on chemical precipitation, rather than surface impoundments, as in the final rule.

Sources that were subject to the 1982 NSPS/PSNS will continue to be subject to such standards under the 2015 rule.

In addition, sources to which the 1982 NSPS/PSNS apply are also subject to the newly promulgated BAT/PSES

requirements of the 2015 rule, because they are existing sources with respect to requirements of the revised rule.

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

Wastestreams

Bottom Ash Transport Water

Flue Gas Mercury Control

(FGMC) Wastewater

Gasification Wastewater

Combustion Residual Leachate

Pollutant Discharge Limitations

and Technology Basis for

Existing Sources (BAT and

PSES)

Pollutant Discharge Limitations

and Technology Basis for New

Sources (NSPS and PSNS)

Zero discharge of pollutants

Dry handling or closed loop control

technology

Dry handling or closed loop control

technology

Zero discharge of pollutants

Dry handling control technology

Numeric limitations on mercury,

arsenic, selenium, and TDS

Numeric limitations on mercury,

arsenic, selenium, and TDS

Evaporation control technology

Impoundment control technology

(equal to BPT standard)

Numeric limitations on mercury and

arsenic

Chemical precipitation control

technology

Source: TDD, Table 8-1, page 8-3, and U.S. Environmental Protection Agency, “Effluent Limitations Guidelines

and Standards for the Steam Electric Power Generating Point Source Category; Final Rule,” 80 Federal Register

67838-67903, November 3, 2015.

Revised Requirements for Direct Discharges

For generating units that are existing sources and that discharge directly to surface waters, the

final rule establishes BAT requirements as follows:



For fly ash transport water, bottom ash transport water, and FGMC wastewater,

the rule establishes a zero discharge limitation for all pollutants in these

wastewaters. The BAT technology basis for fly ash transport water and FGMC

wastewater is dry handling. The BAT technology basis for bottom ash transport

water is dry handling or closed-loop systems.

For FGD wastewater, the rule establishes numeric effluent limitations on

mercury, arsenic, selenium, and nitrate/nitrite as N in the discharge. The numeric

limits for these pollutants in the final rule are less stringent than the limits in the

2013 proposal.19 The BAT technology for controlling this wastestream is based

on chemical precipitation plus biological treatment.

The final rule includes an option for existing dischargers of FGD wastewater that

voluntarily choose to have extended time to achieve compliance with more

stringent numeric limits for mercury, arsenic, selenium, and nitrate/nitrite as N.

That is, rather than having to comply with the FGD standards as soon as possible

after November 1, 2018 (see “Timing of New Requirements”), these sources will

For example, under the 2013 proposal, direct discharges of FGD wastewater would have had to meet a limit of 242

nanograms per liter (ng/L) of mercury, maximum for any one day, and 119 ng/L for a 30-day average. The final rule

establishes a limit of 788 ng/L for the same pollutant, maximum for any one day, and 356 ng/L for a 30-day average.

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule



be required to comply with the more stringent standards, but not until December

31, 2023. The more stringent BAT limits under the voluntary option will require

dischargers to use technology—chemical precipitation followed by

evaporation—that EPA determined was too expensive to require for all steam

electric power plants.20

For gasification wastewater, the rule establishes numeric effluent limitations on

mercury, arsenic, selenium, and Total Dissolved Solids (TDS) in the discharge.

The BAT technology for controlling this wastestream is based on evaporation.

The 1982 ELG included combustion residual leachate within the definition of

low volume waste sources, which were subject to BPT limitations on TSS and oil

and grease. In the final rule, EPA established a separate definition for combustion

residual leachate; thus, no longer is it considered a low volume waste source. The

BAT technology for managing combustion residual leachate in the revised rule is

based on surface impoundments, the same as the 1982 BPT regulations.

For all of the regulated wastestreams, the 2015 final rule retains BPT limits

established in the 1982 rule for discharges of Total Suspended Solids (TSS) and

oil and grease.

The final rule, like the 2013 proposed rule, establishes BAT effluent limits for existing oil-fired

generating units and small electric generating units (EGUs), that is, those 50 MW or smaller, that

differ from the effluent limits for all other generating units. For these facilities, EPA set BAT

effluent limits equal to existing BPT effluent limits for all of the wastestreams addressed by the

rule. According to EPA, oil-fired units generate substantially fewer pollutants, are generally older

and operate less frequently, and in many cases are more susceptible to early retirement when

faced with compliance costs attributable to the ELG. Likewise, small EGUs are more likely to

incur compliance costs that are proportionately higher than those incurred by large units, because

they are not as able to take advantage of economies of scale, while the amount of pollutants

collectively discharged by small units is a small portion of pollutants discharged collectively by

all power plants.

The final rule includes a provision to prevent existing facilities from circumventing the effluent

limitation standards and guidelines. This anti-circumvention provision would prevent facilities

from mixing wastewater from one of the more highly regulated waste streams with another that

would be subject to a lower standard and disposing of the waste under the less stringent limit. The

anti-circumvention provision applies only to those wastestreams for which the final rule

establishes zero discharge limitations or standards (fly ash transport water, bottom ash transport

water, and FGMC wastewater).

For all generating units that are new sources and will discharge directly to surface waters

(including oil-fired and small generating units), the final rule establishes NSPS as follows:



For fly ash transport water, bottom ash transport water, and FGMC wastewater,

the rule establishes a zero discharge standard for all pollutants. The NSPS

technology basis for fly ash transport water and FGMC wastewater is dry

handling, and the technology basis for bottom ash transport water is dry handling

The voluntary option in the final rule differs from a voluntary option under the proposed rule. The proposal included

a voluntary incentives program with incentives in the form of additional implementation for plants that eliminate the

discharge of all process wastewater (except cooling water). Because the final rule contains zero discharge limits for

several wastestreams, EPA decided that the voluntary incentives program should focus on FGD wastewater. TDD, pp.

8-25–8-27.

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

or closed-loop systems. These are the same as the technology bases for the BAT

limitations for direct discharges in the final rule.

For discharges of FGD wastewater, the rule establishes numeric standards on

mercury, arsenic, selenium, and TDS. The numeric limits for these pollutants are

the same as the BAT limits for existing sources, described above. The NSPS

technology is based on chemical precipitation followed by evaporation—the

same basis as for BAT limitations for direct discharges in the voluntary

incentives program described above.

For discharges of gasification wastewater, the rule establishes numeric standards

on arsenic, mercury, selenium, and TDS, which are the same as the BAT limits

for existing sources, described above. Similarly, the NSPS technology is based on

evaporation, the same basis as for BAT limitations for direct dischargers in the

final rule.

For discharges of combustion residual leachate, the rule establishes numeric

standards on mercury and arsenic. The numeric limits for these pollutants are the

same as the BAT limits for direct discharges from existing sources, described

above. The NSPS technology basis of these requirements is chemical

precipitation.

Revised Requirements for Indirect Discharges to Publicly Owned Treatment

Works (POTWs)

As described above, EPA prescribes pretreatment standards for existing sources (PSES) and new

sources (PSNS) that discharge wastewater to publicly owned treatment works (POTWs), rather

than fully treating their wastes and discharging directly to nearby surface waters. Under CWA

Section 307(b), pretreatment standards are intended to prevent the discharge of pollutants that

would pass through, interfere with, or otherwise be incompatible with the operation of the POTW.

For discharges from existing sources to POTWs (PSES), the final rule establishes standards as

follows:



For fly ash transport water, bottom ash transport water, and FGMC wastewater,

the 2015 rule establishes a zero discharge standard for all pollutants. The PSES

technology basis of the standard for these wastestreams is dry handling (fly ash

transport water and FGMC wastewater) and dry handling or closed-loop systems

(bottom ash transport water).

For discharges of FGD wastewater, the rule establishes numeric standards on

mercury, arsenic, selenium, and nitrate/nitrite as N. The PSES technology basis

for this wastestream is chemical precipitation plus biological treatment, the same

as for BAT limitations for direct discharges in the final rule.

For discharges of gasification wastewater, the rule establishes numeric standards

on mercury, arsenic, selenium, and TDS. The PSES technology basis is

evaporation.

For discharges from new sources to POTWs (PSNS), the 2015 revised rule establishes PSNS that

are the same as the rule’s NSPS, described above. EPA believes that the technology for new

indirect discharging sources to meet these requirements is available and is economically

achievable, because the costs to install technologies at new units are typically less than the costs

to retrofit existing units. A key factor that affects compliance costs for existing sources is the need

to retrofit new pollution controls to replace existing pollution controls, but new sources do not

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trigger retrofit costs because pollution controls are installed at the time the new source is

constructed.

Relationship of the ELG to Other EPA Rules and Rulemakings

The steam electric power sector is a source of significant pollutant emissions and discharges to

the environment,21 and thus is subject to pollution control requirements under a number of federal

environmental laws. In the preamble to the final rule and documents supporting it, EPA discusses

how the ELG relates to several existing EPA rules and pending rulemakings. These include

regulations under the Clean Air Act (such as Mercury and Air Toxics Standards promulgated in

2012 and the 2015 Clean Power Plan)22 and other provisions of the CWA (such as the 2014

cooling water intake rule).23 A 2014 rule under the Resource Conservation and Recovery Act

(RCRA)24 on managing coal combustion residuals (CCR) also relates to the CWA ELG rule,

because both statutes address coal combustion waste such as coal ash that is generated by electric

utilities and independent power producers and is released to the environment.

The ELG and the CCR Rule under RCRA

Disposal of CCR onsite at individual power plants may involve decades-long accumulation of

tons of dry ash (in a landfill) or wet ash slurry (in a surface impoundment) deposited at the site. In

December 2008, national attention was turned to risks associated with managing CCR when a

breach in a surface impoundment pond at the Tennessee Valley Authority’s Kingston, TN, plant

released 1.1 billion gallons of coal fly ash slurry that damaged or destroyed homes and property.

Beyond the potential for a sudden, catastrophic release from a surface impoundment, a more

common threat associated with CCR management is the leaching of contaminants commonly

present in the waste, primarily heavy metals, resulting in surface or groundwater contamination.

This risk is particularly high at unlined surface impoundments, which are in common use today.

The Kingston release also brought attention to how the waste is managed and regulated. CCR

management is primarily regulated by individual states. For several years, EPA considered

whether and how to establish national standards to regulate CCR and address potential threats of

improper CCR management to human health and the environment, because of concerns about

inconsistencies and deficiencies in some state regulatory programs. In December 2014, EPA

finalized a rule that establishes national criteria applicable to landfills and surface impoundments

under RCRA’s Subtitle D non-hazardous solid waste requirements.25 The rule establishes

EPA estimates that the total pollutant loadings associated with combustion wastewater discharges from steam electric

power plants alone contribute 50%-60% of the reported toxic-weighted pollutant loadings of the combined discharges

of all industrial categories currently regulated in the United States. 78 Federal Register 34505.

For information, see CRS Report R42144, EPA’s Utility MACT: Will the Lights Go Out?, by (name redacted) ,

and CRS Report R44341, EPA’s Clean Power Plan for Existing Power Plants: Frequently Asked Questions, by (name

redacted) et al.

For information, see CRS Report R41786, Cooling Water Intake Structures: Summary of the EPA Rule, by (name re

dacte d) .

RCRA established the federal program for regulating solid and hazardous waste management (42 U.S.C. §§ 6901 et

seq.). For information, see CRS Report RL30798, Environmental Laws: Summaries of Major Statutes Administered by

the Environmental Protection Agency, coordinated by (name redacted) .

U.S. Environmental Protection Agency, “Hazardous and Solid Waste Management System; Disposal of Coal

Combustion Residuals from Electric Utilities,” 80 Federal Register 21302-21501, April 17, 2015. Although this rule

was finalized by EPA in December 2014, it was not published in the Federal Register until April 2015. The effective

date of the CCR rule is October 14, 2015.

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technical requirements for CCR landfills and surface impoundments under Subtitle D of RCRA to

address the risk of coal ash disposal. Under Subtitle D, EPA does not have the authority to

implement or enforce its requirements. Instead, EPA will continue to rely on states to operate

approved regulatory programs or citizen suits to enforce the new standards.

The scope of the CWA ELG and RCRA rule differ. While both address disposal of CCR in

surface impoundments at power plants, only the RCRA rule regulates disposal of CCRs in

landfills. In the preamble to the 2013 proposed ELG, EPA said that it would seek to effectively

coordinate any final RCRA and CWA requirements to ensure that the rules work together while

minimizing the potential for overlap of two regulatory structures, especially concerning surface

impoundments. For example, the RCRA rule could potentially require a surface impoundment to

either undergo closure or retrofit. But a decision on what action to take with that unit may

ultimately be directly influenced by requirements of the revised ELG. One possible consequence

of the requirements in the ELG is that many power plants will convert from wet to dry fly ash

handling systems and will no longer send such wastes to surface impoundments. If this occurs, it

might affect the time frames for closure of impoundments under a RCRA rule, according to EPA.

In the final CCR rule, EPA extended by one year, compared to the proposed rule, that rule’s

deadline for owners or operators of covered facilities to prepare a closure plan. This would give

owners or operators 24 months after publication of the CCR rule, or slightly more than 6 months

after the effective date of the revised ELG, to understand the requirements of both regulations and

to make the appropriate business decisions and prepare closure and post-closure plans.26

BMPS for CCR Impoundments

CWA Section 304(e) authorizes EPA to supplement effluent limitation guidelines with Best

Management Practices (BMPs) for toxic or hazardous pollutants in order to control plant site

runoff, spillage or leaks, sludge or waste disposal, and drainage from raw material storage that is

ancillary to the regulated industrial process and may contribute significant amounts of pollutants

to U.S. waters. In the ELG proposal, EPA said that it was considering using this authority to

establish BMP requirements to address impoundment construction, operation, and maintenance.

EPA explained that the BMPs under consideration were similar to structural integrity and

corrective action requirements that EPA had proposed in the then-pending RCRA rulemaking to

address CCR.27 In the CWA proposal, EPA said that the BMP provisions being considered in both

the ELG and CCR rulemakings, such as requiring that impoundment inspections be conducted

weekly by a qualified person, are critical to ensure that owners and operators of impoundments

become aware of structural stability problems before they occur. If included in the ELG rule,

these BMPs would become conditions to be included in CWA permits, along with numeric limits

and other requirements in that rule, thus utilizing the CWA to accomplish a portion of the

agency’s objectives in the CCR regulatory proposal.

The 2013 CWA proposal included BMP provisions for CCR surface impoundments similar to

those for coal slurry impoundments at coal mines promulgated by the Mine Safety and Health

Administration (MSHA).28 These provisions in the proposed ELG would require facilities using

CCR impoundments to submit to the CWA permitting authority (EPA or an authorized state) plans

for design, construction, and maintenance of existing impoundments, as well as closure plans.

Ibid., p. 21428.

The BMP provisions in the ELG proposal did not include closure requirements that were proposed as part of the

CCR rulemaking under RCRA.

30 C.F.R. 77.216.

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They also would require periodic inspection and annual certification of the construction,

operation, and maintenance of the impoundment.

In the 2015 final CWA rule, EPA declined to include BMPs, saying that many commenters had

argued that BMPs are better suited for the CCR rule.29

Timing of New Requirements

EPA believes that providing a window of time for facilities to raise capital, plan and design

systems, and construct and test equipment will enable installation of technology during planned

shutdown or maintenance periods. Further, EPA anticipates that for many plants, changes to FGD

wastewater treatment systems, fly ash and bottom ash transport systems, and leachate treatment

systems would constitute major system modifications requiring several years to accomplish. In

the 2015 final rule, EPA provides that BAT limitations for existing sources (those that would

establish requirements more stringent than existing BPT requirements) will apply beginning three

years after the effective date of the rule. Thus, the rule will apply to discharges generated on or

after the date established by the permitting authority that is as soon as possible within the next

permitting cycle after November 1, 2018. Under the rule, all steam electric facilities will have the

BAT limitations applied to their permits no later than December 31, 2023, approximately eight

years from the anticipated date of promulgation of a final regulation. Permitting authorities will

have flexibility to determine the “as soon as possible” date (but no later than December 31, 2023),

based on considerations of a facility’s need for new treatment technology. Plants are assumed to

implement the control technologies beginning in 2019.

For those parts of the rule where EPA promulgated BAT limits equivalent to current BPT limits

(e.g., combustion residual leachate), the rule does not build in an implementation period for

meeting its limitations, since existing facilities presumably are already meeting these limits.

These requirements are applicable on the date that a permit is issued to a discharger, after the

rule’s effective date. Also, new NSPS and PSNS requirements (for new sources) would be

applicable on the effective date of the rule.

Because pretreatment standards are self-implementing (they do not require permits), existing

sources that are indirect dischargers must comply with the final rule by November 1, 2018.

“Legacy” Wastewater

EPA defines “legacy” wastewater as discharges of wastewater and associated pollutants from

existing sources from the six wastestreams regulated by the ELG that are generated prior to the

date established by the permitting authority for the effective date of the 2015 rule (see above).

Wastewater generated after the date established by the permitting authority is referred to as

“newly generated” wastewater. Under the final rule (and as proposed by EPA in 2013), legacy

wastewater discharges will continue to be subject to existing BPT effluent limits, not to more

stringent BAT or PSES requirements that apply to newly generated wastewater. In other words,

discharges from the regulated wastestreams that occur before the date set by the permitting

authority for meeting the rule’s new standards will not be required to retrofit to meet more

stringent standards.

In developing the 2013 proposal, EPA found that these legacy wastewaters are typically

transferred to surface impoundments that often commingle legacy wastewaters and other plant

80 Federal Register 67863.

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wastewaters, such as cooling water or coal pile runoff. Except in limited circumstances, plants do

not treat the legacy wastewater that they send to an impoundment using anything beyond the

surface impoundment itself. Under the 2015 final rule, the technology basis to meet the rule’s

BAT requirements will eliminate wastewater in the future (e.g., the zero discharge requirement

for fly ash transport water will necessitate conversion to dry ash handling) but does not eliminate

wastewater that has already been generated and transferred to an existing impoundment. EPA

evaluated whether technologies would be available that might represent BAT for these legacy

wastewaters, but determined that these alternatives are either impracticable or insufficient data are

available for establishing BAT effluent limitations. In the final rule, the agency did not establish

zero discharge BAT limitations for legacy wastewater because technologies that can achieve zero

discharge were not shown to be available. EPA believes that the rule’s zero discharge

requirements for newly generated discharges of fly ash transport water, bottom ash transport

water, and FGMC wastewater will provide strong incentives for power plants to greatly reduce, if

not completely eliminate, disposal of their major sources of ash-containing wastewater in surface

impoundments.30

Costs and Benefits of the ELG

Compliance Costs

EPA estimates that the final rule will result in annualized pre-tax compliance costs for industry of

$496.2 million and after-tax costs of $339.6 million.31 Pre-tax costs provide insight on the total

expenditures as incurred by the plants, while after-tax annualized costs are a more meaningful

measure of impact on privately owned for-profit plants, because they incorporate approximate

capital depreciation and other relevant tax treatments in the analysis.32 EPA’s estimates of

compliance costs reflect anticipated unit retirements or fuel conversion, ash handling conversions

(from wet to a dry or closed-loop ash handling system), and repowerings33 announced as of

August 2015. The agency projects that 133 steam electric power plants (130 direct discharging

facilities and three indirect discharging plants), or 12% of plants to which the final rule applies,

will incur costs associated with the rule.34

EPA also analyzed the social costs of the final ELG, which are the costs from the viewpoint of

society as a whole, rather than regulated facilities only. Social costs include costs incurred by

both private entities and government in implementing the regulation. In this case, EPA estimates

that the final rule will not lead to additional costs to permitting authorities, so, in calculating

social costs, the agency only estimated social costs for owners of steam electric power plants. The

analysis projects total annualized social costs of $479.5 million at a 3% discount rate and $471.2

million at a 7% discount rate. The value for the 7% discount rate is slightly lower than the

comparable pre-tax industry costs described above ($471.2 million versus $496.2 million) due to

the consideration of the timing of expenditures in the annualized social calculations.35

Ibid., pp. 67854-67855.

2013 dollars at a 7% discount rate.

80 Federal Register 67864.

Repowering is the process of replacing older power stations with newer ones that either have a greater nameplate

capacity or more efficiency which results in a net increase of power generated.

80 Federal Register 67881.

Ibid., pp. 67864-67865. The social cost analysis covers a 24-year period during which plants install control

(continued...)

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Overall, EPA concludes that the limitations and standards in the final rule are economically

achievable for the industry as a whole. EPA projects that 88% of the plants subject to the rule will

incur zero compliance costs, because they already have implemented processes or technologies

that are the basis for the rule. An estimated 8% of plants will incur compliance costs of less than

1% of revenue and in EPA’s view are unlikely to face economic impacts (88 plants) as a result of

the ELG rule. The agency estimates that 4% of plants will have compliance costs between 1%

and 3% of revenue (38 plants), and less than 1% of plants have costs above 3% of revenue (eight

plants).

The number of plants projected to incur non-zero compliance costs is about 50% less than that

estimated at the time of the 2013 proposal, due to such factors as announced unit retirements,

relevant operational changes, and changes that plants are likely to make in response to the CCR

and other EPA rules.36 Regionally, plants in the Reliability First Corporation (covering the eastern

United States and lower Great Lakes region) and the Southeast are generally expected to have the

highest compliance costs.

EPA estimates that variable production costs at steam electric power plants will increase by

approximately 0.3%, or 10 cents per megawatt-hour, at the national level as a result of the rule.

Major compliance costs are associated with controls on FGD and bottom ash transport

wastewater. An important factor that reduced total compliance costs of the final rule, compared

with stringent alternatives in the 2013 proposal, is the standard for one of the wastestreams,

combustion residual leachate. By retaining the technology basis of the 1982 BPT ELG—i.e.,

surface impoundments—EPA concluded that facilities will incur no compliance costs for

managing this wastestream. In developing the final rule, the agency considered a regulatory

option that would establish limitations for arsenic and mercury in combustion residual leachate

based on treatment using a chemical precipitation system, but concluded that the amount of

pollutants discharged in combustion residual leachate is a small portion of the pollutants

discharged collectively by all steam electric power plants. That fact, combined with the final

rule’s standards for larger contributors of pollutant discharges (e.g., FGD wastewater), led EPA to

conclude that retaining the BPT standard for this wastestream still represents reasonable further

progress toward the CWA’s goal of eliminating the discharge of all pollutants.37

EPA does not expect the final rule to increase costs to permitting authorities, because it does not

change permit application requirements or increase the number of permits issued to steam electric

power plants. Overall, EPA expects that the rule will reduce the burden to permitting authorities,

because, by establishing national BAT standards, it will require permitting authorities to make

fewer site-specific permitting decisions than under the 1982 ELG.38

Electricity Market and Other Impacts

EPA also examined impacts of the final rule on electricity markets, including changes in capacity

to plant or unit closures (i.e., capacity closures and avoided closures) and changes in the price of

electricity (due to increased generation costs). Overall, EPA concluded that the final rule will not

significantly affect total costs of electricity production either in the short run (2020) or the long

(...continued)

technologies and the useful life of the longest-lived technology at any facility (20 years).

Ibid., p. 67864.

Ibid., p. 67854.

Ibid., p. 67888.

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run (2030). Under the final rule, the electricity market would generate 843 million kWh less coalfired electricity in 2030, or 0.2% of the 359,982 MW baseline (2009) capacity. The change is

based on a combination of incremental capacity closures (corresponding to eight generating units

nationwide) and avoided capacity closures nationally (six generating units).

EPA projects that the final rule will have small effects on the electricity market in 2030, both

nationally and regionally, despite the higher compliance costs. At the national level, total annual

costs are estimated to increase by 0.4%, compared with the 2009 baseline. The agency’s model

projects a small increase on electricity prices nationally, with increases of no more than 0.5% in

any region and a 0.2% reduction in the West.

EPA examined impacts of the ELG on residential, commercial, industrial, and transportation

consumers and concluded that industrial consumers would experience the highest price increases

relative to their baseline electricity price (0.21% nationally), while residential consumers would

experience the lowest price increases (0.11% nationally). The higher relative price increase for

industrial consumers is due to the lower baseline electricity rates paid by this sector and EPA’s

assumption of uniform price increase across all consumer groups. EPA’s analysis shows the

average annual cost per residential household increasing as a result of the ELG, depending on the

region, by $0.03 (in the Northeast Power Coordinating Council region) to $2.67 (in the Reliability

First Corporation region) with a national average of $1.42.39

EPA’s model projects that total coal-fired generating capacity will decrease by approximately

0.6% due to the ELG final rule. Coal-fired plants may generate less electricity than would

otherwise occur in the absence of the rule, due to increased production costs. In addition, some

plants may retire earlier than would otherwise occur. These effects may lead to lower employment

at coal-fired power plants and in coal mining. Generation using other fuels, including natural gas,

nuclear power, and renewable fuels such as biomass, would increase modestly and would have

positive labor impacts (e.g., natural gas extraction, constructing and operating natural gas power

plants). EPA estimated that approximately 60% of the annualized compliance costs for the final

rule are annualized capital costs. These capital costs are not expected to significantly affect

employment at steam electric power plants themselves, but could increase employment in

industries that manufacture and install equipment, according to EPA.40

Many stakeholders and other observers have criticized EPA for not analyzing the impacts of its

regulatory proposals on jobs, the labor market, and the economy broadly, arguing that the agency

fails to consider the economy-wide effects of its rules. EPA does not have a robust methodology

to fully assess impact of all possible changes in employment, so it is difficult for the agency to

project how the ELG would affect employment levels in the entire U.S. economy. Thus, EPA did

not quantify long-run economy-wide regulatory changes in employment resulting from the ELG,

which would depend on how the electric power sector adjusts to regulatory requirements, as well

as indirect upstream and downstream effects in the rest of the economy, and the overall state of

the economy and the labor market.41

EPA acknowledges some uncertainties in these analyses. For example, it assumes that electricity

demand at the national level would not change between the baseline and post-compliance options,

and the model does not capture changes in demand that may result from electricity price increases

associated with proposed ELG. Also, fuel prices—differences in actual fuel prices vs. modeled

RIA, pp. 7-4–7-9.

Ibid., pp. 6-5–6-12.

Ibid.

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prices, such as lower natural gas prices—would be expected to affect the cost of electricity

generation and the amount of electricity generated, but effects of fuel prices are not reflected in

the analysis. Estimates of price increases to households and other consumer groups assume 100%

pass-through of compliance costs, which EPA characterizes as a worse-case scenario that may

overstate potential impact, depending on whether power plants are able to pass their costs on to

electricity customers. Further, how states choose to comply with the Clean Power Plan may lead

to fewer or more coal-fired steam power plant retirements than EPA’s model is able to project.

Such differences could affect power plant existing and new capacity, production costs, prices, and

other factors.

Environmental Benefits/Pollutant Reductions

Compared with Costs

EPA estimated the reduction of conventional, non-conventional, and priority (toxic) pollutants

that would result from the final rule is 385 million pounds per year. The largest amount of

pollutant reduction (96%) is nonconventional pollutants, such as ammonia, phosphorus, and TDS.

Additionally, the final rule will eliminate or reduce water withdrawals associated with wet fly ash

and bottom ash transport and wet FGD scrubbers by 57 billion gallons per year. Reduced water

usage is significant, because total water withdrawals by the steam electric power industry

(primarily for cooling purposes) are larger than those of any other public or private sector.42

EPA expects a number of environmental and ecological improvements and reduced impacts to

wildlife and human health to result from reductions in effluent loadings for the different proposed

options. The agency conducted an environmental assessment that examined several beneficial

outcomes, including improvements in water quality, reduction in impacts to wildlife, and

reduction in number of receiving waters impacted by potential human health cancer and noncancer risks.

In that analysis, EPA estimated that reduced pollutant loadings to surface waters would improve

water quality by reducing metal concentrations to receiving waters. Metals in combustion

wastewater discharges such as arsenic, cadmium, copper, and chromium can drastically alter

aquatic populations and communities and the surrounding ecosystems that rely on them.

Selenium is the metal most frequently associated with environmental impacts following exposure

to combustion wastewaters. On average, total selenium receiving water concentrations would be

reduced by two-thirds under the final rule, leading to a reduction in the number of receiving

waters exceeding the freshwater chronic criteria for selenium.43

EPA acknowledges that there are varying degrees of completeness and rigor in its ability to assess

benefits. Where possible, EPA quantified expected effects and associated human health and

ecological benefits—such as reduced incidence of cancer from arsenic exposure via fish

consumption—but EPA was able to monetize only a small subset of health benefits associated

with reduced steam electric discharges. Other benefits can be quantified, but not monetized, such

as reduced non-cancer adverse health effects. Quantifying and monetizing the benefits of

regulations is challenging because of a large number of uncertainties in approaches used to value

benefits. Finally, due to data limitations and gaps in understanding how society values certain

Water withdrawals for thermoelectric power were 161 billion gallons in 2010, or 45% of total withdrawals for all

uses. U.S. Geological Survey, U.S. Department of the Interior, Estimated Use of Water in the United States in 2010,

Circular 1405, 2014.

80 Federal Register 67874.

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water quality changes, some effects can be neither quantified nor monetized, such as reduced

sediment contamination and increased property values from water quality improvements.

EPA also recognizes a number of other limitations and uncertainties in analyzing benefits. Some

may lead to potential overestimation of benefits. For example, the analysis is based on

information on loadings of toxic metals that that was subsequently revised downward by EPA,

and the change indicates that water quality improvements due to the ELG may be lower than the

agency estimated. Others may lead to underestimation of benefits: EPA estimated the benefits of

reducing mercury exposure in children, but not in adults, although the scientific literature

suggests that exposure to mercury also may have adverse health effects in adults.44

Despite the data limitations, EPA projects annualized monetized benefits of the final rule (human

health, recreational uses, improved ecological conditions, groundwater quality, avoided

impoundment failures, air-related [i.e., human health and avoided climate change impacts], and

reduced water withdrawals) to range from $451 million to $566 million, with a mid-point of $463

million (at a 3% discount rate), and from $387 million to $478 million, with a mid-point of $397

million, at a 7% discount rate.45

Finally, EPA evaluated the net benefits (i.e., benefits minus costs) and estimates that the annual

monetized social costs exceed the mid-range annual monetized benefits for the final ELG by

$16.5 million using a 3% discount rate and by $74.2 million using a 7% discount rate.46 It should

be noted that the CWA does not require that the benefits of regulation exceed or even equal the

costs. It does require that effluent limitations “result in reasonable further progress toward the

national goal of eliminating the discharge of all pollutants.”47

Issues

Steam electric power plants are highly technical and complex industrial operations. So, too, the

revised ELG is very technical and complex. Industry’s major concern with the 2013 proposed rule

was that EPA would set overly stringent standards that will be an economic burden on generators

and may not be achievable. Following release of the final rule, an industry spokesman noted that

the rule will force technological and operational changes at existing facilities that have the

potential to create compliance challenges and increase customer costs.48 The technology bases of

the rule are available, companies generally agree, but there is concern that the standards may

require extensive retrofitting that is costly and could reduce generating plant effectiveness, and

some may be infeasible (e.g., may not be physically possible within the plant’s footprint). Many

in industry are concerned that the CWA rule imposes new requirements and compliance timelines

at the same time that power plants are implementing other costly and burdensome EPA rules. The

Benefit-Cost, pp. 3-21–3-23, 4-22–4-23.

EPA estimated the annualized value of future benefits using two discount rates: 3% and 7%. The 3% discount rate

reflects society’s valuation of differences in the timing of consumption; the 7% discount rate reflects the opportunity

cost of capital to society. In Circular A-4, the Office of Management and Budget recommends that 3% be used when a

regulation affects private consumption, and 7% be used in evaluating a regulation that will mainly displace or alter the

use of capital in the private sector. All future costs and benefits in EPA’s analyses are discounted to 2015, the

promulgation year of the rule, and are expressed in 2013 dollars.

Benefit-Cost, pp. 13-2–13-3.

CWA §301(b)((2)(A); 33 U.S.C 1311(b)(2)(a).

Lara Beaven, “Advocates Mull Challenge to ‘Suspect’ Utility ELG Legacy Waste Provisions,” InsideEPA, October

15, 2015. Hereinafter, Beaven, InsideEPA.

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agency attempted to address the issue of timing and coordination with other rules both through

the timing of the final ELG and deadlines in the RCRA coal ash rule, discussed above.

One issue concerns impacts of the rule on small entities, including small businesses and small

governmental jurisdictions. The Regulatory Flexibility Act (RFA) requires agencies to prepare a

regulatory flexibility analysis of most rules. The RFA, as amended by the Small Business

Regulatory Enforcement Fairness Act (SBREFA), requires EPA to convene a Small Business

Advocacy Review Panel for most rules, unless the agency can certify that a rule will not have a

significant economic impact on a substantial number of small entities.49

EPA did analyze impacts of the proposed ELG on small entities. EPA projects that 22 small

entities (small businesses, small organizations, and small governmental jurisdictions) will incur

compliance costs as a result of the final rule. It estimates that six small entities owning steam

electric power plants (one cooperative, one nonutility, and four municipalities) will incur

compliance costs exceeding 1% of revenue as a result of the final rule, and one additional

municipality will incur costs exceeding 3% of revenue. Further, potential impacts of the rule on

small entities and municipalities are reduced by establishing requirements for small power plants

(50 MW or less) equal to the previous BPT limits. The agency believes that these impacts are

small and support a finding of no significant economic impact on a substantial number of small

entities.50

Nevertheless, a number of stakeholders are concerned that EPA underestimated costs of portions

of the rule (for example, by overestimating the bottom ash removal efficiencies of power plants).

Some were critical that EPA did not convene a SBREFA panel, with small business

representatives participating, to evaluate the impact prior to the proposed rulemaking. 51

Spokesmen for the National Rural Electric Cooperative Association (NRECA) argue that EPA has

underestimated compliance costs of the final rule. NRECA believes that the ELG, together with

other recent EPA rules, will disproportionately affect the small- and medium-sized power plants

that its members operate.52

Environmental advocates view the ELG differently from industry and reportedly are generally

satisfied with the final rule, but expressed concerns that parts of the rule were not stringent

enough. Many had urged that EPA promulgate standards requiring the most environmentally

protective technologies (i.e., dry handling of fly ash and bottom ash by all plants, and chemical

precipitation plus biological treatment or evaporation of FGD scrubber waste by all plants). They

opposed regulatory options in the proposed rule would have set BAT equal to current BPT

standards for some wastestreams and thus allow continued use of surface impoundments for

bottom ash and combustion residual leachate, because impoundments can be a significant source

of contamination of surface and ground water. Thus, they endorsed provisions of the final rule

that will require dry handling of fly ash and bottom ash from power plants.

Environmental advocates indicated concern with some provisions of the final rule, however, such

as allowing compliance deadlines as late as December 31, 2023, under the rule’s incentive

program (rather than in three years) and the lack of strict limits on legacy wastestreams, discussed

previously. Some advocates dispute EPA’s view that it is not possible to establish BAT limits for

5 U.S.C. §§601 et seq.

80 Federal Register 67888-67889.

In June 2011, EPA issued a notice inviting small businesses to nominate representatives to participate in a SBREFA

panel in connection with the rule. However, no panel was convened.

Amena H. Saiyid, “New Power Plant Effluent Limits Too Costly, Critics Say,” Bloomberg BNA Daily Environment

Report, November 3, 2015, pp. B-1.

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

power plant wastestreams that are generated before standards under the new rule are required and

believe that the rule should have addressed waste that leaks from old, inactive coal ash ponds.53

Conclusion

As noted in the introduction to this report, EPA rules affecting steam electric power plants have

been scrutinized and challenged based on their stringency, feasibility, and projected compliance

costs. Some argue that these rules may change the economics of power production, the fuel

profile of the electricity market, and electricity rates. Congressional interest has been evident in

legislation that has been introduced to alter the direction and substance of some of EPA’s

regulatory actions and initiatives. To this point, discussion of the power plant ELG has centered

on the administrative proceedings at EPA and has not drawn significant attention of lawmakers.

Following promulgation of the ELG, attention has shifted to the federal courts. Petitions for

review of the ELG were filed in several federal courts of appeals and have been consolidated in

the U.S. Court of Appeals for the Fifth Circuit (Southwestern Elec. Power Co. v. EPA, 5th Cir., 1560821, filed November 20, 2015). The consolidated cases include challenges filed by individual

electric utility companies and a group of such companies, as well as environmental advocacy

groups. The deadline for new challenges to the ELG is March 16, 2016, under a 120-day time

limit that started two weeks after the rule’s publication in the Federal Register.

Beaven, InsideEPA.

Congressional Research Service

Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

Appendix. Steam Electric Power Plant Wastestreams

Regulated under the 2015 Revised ELG

This Appendix provides additional detail on the six wastestreams from steam electric power

plants that are regulated in the revised ELG.54 Also see the summary information in Table 1.

FGD Wastewater

FGD systems remove sulfur dioxide from the flue gas so that it is not emitted into the air. There

are approximately 401 FGD systems either currently operating or planned in the United States.

Approximately 17% are dry systems that do not generate wastewater and are not subject to the

FGD wastewater requirements of the ELG, while the remaining 83% are wet FGD systems that

generate a slurry and are subject to FGD requirements of the rule. Dry FGD systems typically

remove 80% to 90% of the sulfur dioxide, which is less than a wet FGD system which in some

cases can remove up to 99%. In wet FGD systems, the flue gas stream comes in contact with a

liquid stream containing a sorbent, which is used to effect the transfer of pollutants from the flue

gas to the liquid stream. Of the 150 plants with wet FGD systems, 100 discharge FGD wastewater

after treatment using one or more of several technologies alone or in combination, including

surface impoundments, chemical precipitation systems, biological treatment, vapor-compression

evaporation systems, and constructed wetlands. EPA estimates that the steam electric industry

discharges 16.1 billion gallons of FGD wastewater per year, with an average total industry daily

discharge of 0.45 million gallons per day (MGD) per plant. Wastewaters generated by wet FGD

systems generally contain significant levels of metals and other pollutants of concern. EPA found

that treatment technologies are available to treat these pollutants in FGD wastewater; however,

most plants use only surface impoundments that are designed primarily to remove suspended

solids from FGD wastewater via settling.

Historically, power plants relied on surface impoundments to treat FGD wastewater because

NPDES permits generally focused on controlling suspended solids for this wastestream. Metals in

FGD wastewater are present both in particulate form, which can be substantially removed by

settling (e.g., arsenic), and in soluble (i.e., dissolved) form (metals such as selenium, boron, and

magnesium) that is not effectively and reliably removed by surface impoundments. More

advanced technologies are available that are effective at removing both soluble and dissolved

forms of metals, as well as nitrogen and total dissolved solids (TDS). The technology basis for the

final rule is chemical precipitation/coprecipitation used in combination with anoxic/anaerobic

biological treatment to optimize removal of selenium. EPA determined that 45% of all steam

electric power plants with wet scrubbers have equipment or processes in place able to meet the

final BAT/PSES effluent limitations and standards in the 2015 rule. Many of these plants use

FGD wastewater management approaches that eliminate the discharge of FGD wastewater. EPA

rejected technology based on chemical precipitation alone for FGD wastewater because, while

chemical treatment systems are capable of achieving removals of various metals, the technology

is not effective at removing selenium, nitrogen compounds, and certain metals that contribute to

high concentrations of TDS in FGD wastewater.

Sources: U.S. Environmental Protection Agency, “Effluent Limitations Guidelines and Standards for the Steam

Electric Power Generating Point Source Category, Final Rule,” 80 Federal Register 67838-67903, November 3, 2015;

and U.S. Environmental Protection Agency, Technical Development Document for the Effluent Limitations Guidelines

and Standards for the Steam Electric Power Generating Point Source Category, Document No. 821-R-15-007,

September 2015.

Congressional Research Service

Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

Fly Ash Transport Water

Fly ash is the combustion residual of fine ash particles entrained in flue gases. Depending on the

boiler design, as much as 70% to 80% of the ash from a pulverized coal furnace consists of fly

ash. Many plants transport fly ash from the boiler using water as the motive force, known as

sluicing, and fly ash transport water is one of the largest wastewater sources generated at coalfired power plants. The steam electric power industry generates 209 billion gallons of fly ash

transport water annually, with the average plant generating 4.27 MGD. It is typically treated in

large surface impoundment systems. Untreated fly ash transport waters contain significant

concentrations of metals and total suspended solids (TSS).

Because current NSPS regulations prohibit the discharge of pollutants in fly ash transport water,

all plants built since 1982, as well as many existing generating units that have converted, already

have dry fly ash handling systems that use air to transport fly ash to storage silos. Because dry fly

ash handling practices do not generate fly ash transport water, converting to a dry system

eliminates the discharge of fly ash transport water and the pollutants contained therein. EPA

estimates that over 80% of existing coal- and petroleum coke-fired generating units use dry ash

fly handling systems that utilize mechanical, pressure, or other technologies.

Fly ash transport water is one of the largest volume flows from coal-fired power plants. Studies

have found that fly ash transport waters generated from wet systems at coal-fired power plants

contain significant concentrations of metals, including arsenic, selenium, and mercury. EPA

identified generating units at 145 plants that transport (i.e., sluice) fly ash with water to a surface

impoundment to remove particulates from the wastewater by means of gravity. Thus, steam

electric units generating wet fly ash transport water tend to be older units (e.g., more than 30

years old). Most of these plants are located east of the Mississippi River.

The 2015 revised rule establishes zero discharge effluent limitations and standards for discharges

of pollutants in fly ash transport water, based on the use of dry fly ash handling technologies.

Specifically, the technology basis for BAT is a dry vacuum system that employs a mechanical

exhauster to pneumatically convey the fly ash from hoppers directly to a silo. As with FGD

wastewater, surface impoundments are not effective at removing soluble forms of metals and

nutrients.

Bottom Ash Transport Water

Bottom ash, sometimes referred to as “boiler slag,” is the combustion residual of heavier ash

particles collected at the bottom of a boiler. Since 70%-80% of the ash from a pulverized coal

furnace consists of fly ash, the remaining 20%-30% is bottom ash. Like fly ash, bottom ash can

be transported from the boiler using water and when it is, it is typically directed to an on-site ash

impoundment for treatment. EPA found that bottom ash transport waters generated from wet

systems at coal-fired power plants contain significant concentrations of the same metals found in

fly ash transport water. Bottom ash transport water is an intermittent stream from steam electric

units, with flow rates that typically are not as large as fly ash transport water flow rates, but it is

still one of the larger volume flows. Moreover, significantly more plants generate bottom ash

transport water than generate fly ash transport water. EPA identified 875 EGUs (348 plants)—

67% of plants—that wet sluice (transport) at least a portion of their bottom ash to a surface

impoundment or a dewatering bin for solids removal. EPA estimates that the steam electric

industry generates a total of 297 billion gallons of bottom ash transport water annually, with the

average plant generating 2.5 MGD. Amounts released to surface waters from impoundment

overflow or discharge totaled 157 billion gallons in 2009.

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Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

According to EPA, many coal and oil-fired power plants design their bottom ash handling

systems either to not use water to transport bottom ash away from the boiler or manage the

transport water in a manner that eliminates or reduces the need to discharge bottom ash transport

water to surface waters.

The 2015 revised rule requires zero discharge, using dry handling or closed-loop systems as the

BAT technology basis for control of pollutants. About 20% of coal- and petroleum coke-fired

units that generate bottom ash currently operate systems that eliminate the use of transport water;

more than 80% of coal-fired generating units built in the last 20 years have installed dry bottom

ash handling systems. Technologies to achieve zero discharge include mechanical drag systems,

remote mechanical drag systems, and impoundment-based systems that are managed to eliminate

all discharge of bottom ash transport water and associated pollutants. EPA found that more than

half of the entities that would be subject to BAT requirements for bottom ash transport water are

already employing zero discharge technologies or are planning to do so in the near future.

Combustion Residual Leachate from Surface Impoundments and Landfills

Combustion residuals include fly ash, bottom ash, and FGD solids, which are generally collected

by or generated from air pollution control technologies. These residuals may be stored at the plant

in on-site landfills or surface impoundments (ponds). Few steam electric power plants currently

employ technologies other than surface impoundments for this waste. Combustion residual

leachate is leachate from landfills or surface impoundments that contains combustion residuals.

Water that comes in contact with the combustion residuals stored in a landfill or impoundment

will be contaminated by metals and other contaminants present in the combustion residuals. The

two sources of landfill combustion residual leachate are precipitation that percolates through the

waste deposited in the landfill or impoundment and the liquids produced from the combustion

residual placed in the landfill or impoundment. When a landfill or impoundment has reached its

capacity, it will typically be closed to protect against environmental release of pollutants in the

waste. However, these landfills or impoundments may continue to generate leachate, which is the

liquid that drains or leaches from a landfill or surface impoundment. EPA estimated in 2009 that

150 to 200 coal-fired and petroleum coke-fired steam electric plants generated on average 0.57

MGD per plant of combustion residual leachate and that 100 to 110 plants discharged 80,000 to

90,000 gallons per day of combustion leachate residual.

In addition to leachate, stormwater that enters the impoundment or contacts and flows over the

landfilled combustion residual would be contaminated with pollutants, such as heavy metals.

Power plants manage these wastewaters in various ways. Stormwater collection systems typically

consist of one or more small impoundments.

According to EPA, approximately 160 to 190 coal- and petroleum-fired steam electric power

plants collect combustion residual leachate from either an impoundment and/or landfill. The

majority (52%) of landfills and some impoundments (13%) have leachate collection systems,

which may be combined with stormwater or sent to a separate impoundment. According to EPA,

63% of combustion residual landfills and 51% of combustion residual impoundments are lined.

Unlined impoundments and landfills do not collect leachate that migrates away from the

impoundment or landfill, which can potentially cause groundwater and/or drinking water

contamination. Recently installed landfills and impoundments are more likely to be lined and to

collect leachate.

Once collected, the landfill or impoundment leachate can be recycled back to the landfill or

impoundment or within the plant, or it is discharged. Some plants discharge the effluent from

leachate impoundments, while others send the leachate impoundment effluent to another

Congressional Research Service

Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

impoundment that handles ash transport water or other systems.55 Surface impoundments are the

most common type of system used to treat combustion residual leachate from landfills and

impoundments. Constructed wetlands are the next most commonly used treatment system.

Physical/chemical and chemical precipitation technologies also have been demonstrated capable

of treating pollutants in combustion residual leachate.

In the 2015 revised rule, EPA established effluent limitations and standards for existing sources

equal to current BPT effluent limitations, based on technology of gravity settling in surface

impoundments to remove suspended solids. For new sources, the technology basis of the 2015

rule is chemical precipitation/coprecipitation. Such systems are capable of achieving low effluent

concentrations of various metals and are effective at removing many of the pollutants of concern

present in leachate discharges to surface waters, and, like FGD wastewater, combustion residual

leachate is similarly amenable to chemical precipitation treatment. However, as is the case with

FGD wastewater, this technology is not effective at removing selenium, boron, and other

parameters that contribute to TDS (e.g., magnesium, sodium).

Flue Gas Mercury Control (FGMC) System Wastewater

In response to recent Clean Air Act rules and other state regulations requiring limits on air

emissions of mercury and other air toxics, power plants have been installing systems to improve

removal of mercury from flue gas emissions. Thus, these systems are relatively new to the steam

electric industry. FGMC systems remove mercury from the flue gas, so that it is not emitted into

the air. In 2009, there were approximately 120 operating FGMC systems, with an additional 40

planned for installation by 2020. Approximately 90% of the currently operating FGMC systems

are dry systems that add oxidizers to the coal prior to combustion and move the oxidized mercury

in the wet FGD system. Using oxidizers does not generate a new wastestream, but the mercury

concentration in FGD wastewater may be increased as a result, because oxidized mercury is more

easily removed by the FGD system. About 6% of the currently operating systems involve

injection of activated carbon into the flue gas to adsorb the mercury, which can generate a new

wastestream at a plant that is likely sent to a surface impoundment.56 According to EPA, coalfired power plants can minimize or eliminate the discharge of FGMC particulate handling

transport water using the same technologies that are available for fly ash, such as wet or dry

vacuum pneumatic systems, pressure systems, or combined vacuum/pressure systems. EPA

identified 6 plants that manage their FGMC waste with systems that use water to transport the

waste to surface impoundments.

Under the final rule, the technology basis for existing and new sources would be zero discharge

using dry handling technologies to store and dispose of fly ash without utilizing transport water.

EPA found that this technology is available and well-demonstrated in the industry, since nearly all

plants with FGMC systems use dry handling systems. Effluent limits based on dry handling

would completely eliminate the discharge of pollutants in FGMC wastewater. EPA did not select

BAT limitations for FGMC wastewater based on surface impoundments, because impoundments,

which can remove particulate forms of metals and other pollutants, are not capable of removing

dissolved metals and nitrates.

At some plants, leachate from impoundments and landfills is not collected and can potentially migrate to nearby

groundwaters or surface waters.

The type of handling system (wet or dry) for the remaining 4% is unknown because they were planned FGMC

systems as of 2009.

Congressional Research Service

Regulation of Power Plant Wastewater Discharges: Summary of the EPA Final Rule

Gasification Wastewater

Integrated gasification combined cycle (IGCC) plants use coal or petroleum coke and subject it to

high temperature and pressure to produce a synthetic gas, which is used as the fuel for combined

cycle generating plants. After the synthetic gas is produced and prior to combustion, it undergoes

cleaning to remove chlorides and other contaminants. This step can generate wastewater and

condensate that require treatment prior to reuse or discharge. Two technologies in use to treat

gasification wastewaters are vapor-compression evaporation systems and cyanide destruction

systems.

The technology basis for the effluent limitations in the final rule is vapor-compression

evaporation, which is currently used by the three operating IGCC plants in the United States.

Surface impoundments were not selected as the basis for BAT limitations, because impoundments

are not effective at removing the pollutants of concern in gasification wastewater, particularly

dissolved solids.

Author Contact Information

(name redacted)

Specialist in Resources and Environmental Policy

[redacted]@crs.loc.gov , 7-....

Congressional Research Service

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