GAO 

United States Government Accountability Office

Report to the Chairman, Subcommittee 

on Clean Air and Nuclear Safety, 

Committee on Environment and Public 

Works, U.S. Senate 

CLEAN AIR ACT 

Mercury Control 

Technologies at 

Coal-Fired Power 

Plants Have Achieved 

Substantial Emissions 

Reductions 

October 2009 

GAO-10-47 
What GAO Found

United States Government Accountability Office

Why GAO Did This Study

Highlights

Accountability Integrity Reliability

October 2009

CLEAN AIR ACT

Mercury Control Technologies at Coal-Fired Power 

Plants Have Achieved Substantial Emissions

Highlights of GAO-10-47, a report to the Reductions

Chairman, Subcommittee on Clean Air 

and Nuclear Safety, Committee on 

Environment and Public Works, U.S. 

Senate 

The 491 U.S. coal-fired power plants 

are the largest unregulated 

industrial source of mercury 

emissions nationwide, annually 

emitting about 48 tons of mercury—

a toxic element that poses health 

threats, including neurological 

disorders in children. In 2000, the 

Environmental Protection Agency 

(EPA) determined that mercury 

emissions from these sources 

should be regulated, but the agency 

has not set a maximum achievable 

control technology (MACT) 

standard, as the Clean Air Act 

requires. Some power plants, 

however, must reduce mercury 

emissions to comply with state 

regulations or consent decrees. 

After managing a long-term mercury 

control research and development 

program, the Department of Energy 

(DOE) reported in 2008 that systems 

that inject sorbents—powdery 

substances to which mercury 

binds—into the exhaust from 

boilers of coal-fired power plants 

were ready for commercial 

deployment. Tests of sorbent 

injection systems, the most mature 

mercury control technology, were 

conducted on a variety of coal types 

and boiler configurations—that is, 

on boilers using different air 

pollution control devices. In this 

context, GAO was asked to examine 

(1) reductions achieved by mercury 

control technologies and the extent 

of their use at power plants, (2) the 

cost of mercury control 

technologies, and (3) key issues 

EPA faces in regulating mercury 

emissions from power plants. GAO 

obtained data from power plants 

operating sorbent injection systems. 

EPA and DOE provided technical 

comments, which we incorporated 

as appropriate. 

Commercial deployments and 50 DOE and industry tests of sorbent injection 

systems have achieved, on average, 90 percent reductions in mercury 

emissions. These systems are being used on 25 boilers at 14 coal-fired plants, 

enabling them to meet state or other mercury emission requirements—

generally 80 percent to 90 percent reductions. The effectiveness of sorbent 

injection is largely affected by coal type and boiler configuration. Importantly, 

the substantial mercury reductions using these systems commercially and in 

tests were achieved with all three main types of coal and on boiler 

configurations that exist at nearly three-fourths of U.S. coal-fired power 

plants. While sorbent injection has been shown to be widely effective, DOE 

tests suggest that other strategies, such as blending coals or using other 

technologies, may be needed to achieve substantial reductions at some plants. 

Finally, some plants already achieve substantial mercury reductions with 

existing controls designed for other pollutants. 

The cost of the mercury control technologies in use at power plants has 

varied, depending in large part on decisions regarding compliance with other 

pollution reduction requirements. The costs of purchasing and installing 

sorbent injection systems and monitoring equipment have averaged about $3.6 

million for the 14 coal-fired boilers operating sorbent systems alone to meet 

state requirements. This cost is a fraction of the cost of other pollution control 

devices. When plants also installed a fabric filter device primarily to assist the 

sorbent injection system in mercury reduction, the average cost of $16 million 

is still relatively low compared with that of other air pollution control devices. 

Annual operating costs of sorbent injection systems, which often consist 

almost entirely of the cost of the sorbent itself, have been, on average, about 

$675,000. In addition, some plants have incurred other costs, primarily due to 

lost sales of a coal combustion byproduct—fly ash—that plants have sold for 

commercial use. The carbon in sorbents can render fly ash unusable for 

certain purposes. Advances in sorbent technologies that have reduced sorbent 

costs at some plants offer the potential to preserve the market value of fly ash.

 

EPA’s decisions on key regulatory issues will have implications for the 

effectiveness of its mercury emissions standard. In particular, the data EPA 

decides to use will impact (1) the emissions reductions it starts with in 

developing its regulation, (2) whether it will establish varying standards for 

the three main coal types, and (3) how the standard will take into account a 

full range of operating conditions at the plants. These issues can affect the 

stringency of the MACT standard EPA proposes. For example, if EPA uses 

data from its 1999 power plant survey as the basis for its mercury standard, 

the standard could be less stringent than what has been broadly demonstrated 

in recent commercial deployments and DOE tests of sorbent injection systems 

at power plants. On July 2, 2009, EPA announced that it would seek approval 

from the Office of Management and Budget to conduct an information 

collection request to update existing emissions data, among other things, from 

power plants. 

View GAO-10-47 or key components.

For more information, contact John B. 

Stephenson at (202) 512-3841 or 

stephensonj@gao.gov. 
Page i GAO-10-47 

Contents 

Letter 1

Background 4 

Substantial Mercury Reductions Have Been Achieved Using 

Sorbent Injection Technology at 14 Plants and in Many DOE 

Tests 7 

Mercury Control Technologies Are Often Relatively Inexpensive, 

but Costs Depend Largely on How Plants Comply with 

Requirements for Reducing Other Pollutants 14 

Decisions EPA Faces on Key Regulatory Issues Will Have 

Implications for the Effectiveness of Its Mercury Emission 

Standard for Coal-Fired Power Plants and the Availability of 

Monitoring Data 19 

Concluding Observations 27 

Agency Comments and Our Evaluation 28 

Appendix I Objectives, Scope, and Methodology 29 

Appendix II Emerging Technologies That May Reduce Mercury 

Emissions from Coal-Fired Power Plants 33 

Appendix III Summary of State Regulations Requiring 

Reductions in Mercury Emissions from 

Coal-Fired Power Plants 36 

Appendix IV Potential Solutions for Plants Unable to Achieve 

High Mercury Emissions Reductions Using Sorbent 

Injection Systems Alone 38 

Appendix V Average Costs to Purchase and Install Sorbent 

Injection Systems and Monitoring Equipment, 

with and without Fabric Filters, per Boiler 41 

 Clean Air Act 
Appendix VI GAO Contact and Staff Acknowledgments 42 

Tables 

Table 1: Summary of Key Provisions of State Regulations Requiring 

Mercury Emission Reductions Applicable to Existing or All 

Coal-Fired Power Plants 36 

Table 2: Detailed Average Costs to Purchase and Install Sorbent 

Injection Systems and Monitoring Equipment, with and 

without Fabric Filters, per Boiler 41 

Figure 

Figure 1: Sample Layout of Air Pollution Controls, Including 

Sorbent Injection to Control Mercury, at a Coal-Fired 

Power Plant 5 

Abbreviations 

BTU British thermal units 

CEMS continuous emissions monitoring systems 

DOE Department of Energy 

EPA Environmental Protection Agency 

EPRI Electric Power Research Institute 

MACT maximum achievable control technology 

OMB Office of Management and Budget 

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Page ii GAO-10-47 Clean Air Act
Page 1 GAO-10-47 

 

United States Government Accountability Office

Washington, DC 20548 

 

October 8, 2009 

The Honorable Thomas R. Carper 

Chairman 

Subcommittee on Clean Air 

 and Nuclear Safety 

Committee on Environment 

 and Public Works 

United States Senate 

Dear Mr. Chairman: 

Mercury is a toxic element that poses human health threats—including 

neurological disorders in children that impair their cognitive abilities. 

Coal-fired power plants, the nation’s largest electricity producers, 

represent the largest unregulated industrial source of mercury emissions 

in the United States.1

 In 2000, the Environmental Protection Agency (EPA) 

determined that it was “appropriate and necessary” to regulate mercury 

emissions from coal-fired power plants under section 112 of the Clean Air 

Act. Subsequently, in 2005, EPA chose to promulgate a cap-and-trade 

program,2

 rather than establish a maximum achievable control technology 

(MACT) standard to control mercury emissions as required under section 

112. However, the cap-and-trade program was vacated by the D.C. Circuit 

Court of Appeals in February 2008 before EPA could implement it. 

EPA must now develop a MACT standard to regulate mercury emissions 

from coal-fired power plants. As prescribed by the Clean Air Act, the 

MACT standard shall require that mercury emissions from all coal-fired 

boilers be reduced to the average amount emitted by the best performing 

1

EPA’s 1999 data, the agency’s most recent available data on mercury emissions, show that 

the 491 U.S. coal-fired power plants annually emit 48 tons of mercury into the air. These 

emissions are unregulated at the federal level and largely unregulated at the state level. 

2

EPA’s cap-and-trade program, known as the Clean Air Mercury Rule, was established 

under Clean Air Act section 111 and set a cap on mercury emissions of 38 tons for 2010 and 

a second phase cap of 15 tons for 2018. The rule included a model cap-and-trade program 

that states could adopt to achieve and maintain their mercury emissions budgets. States 

could join the trading program by adopting the model trading rule in state regulations, or 

by adopting regulations that mirrored the necessary components of the model trading rule. 

States could also opt out of the trading program entirely as long as they imposed controls 

on plants sufficient to meet the mercury budget set for the state by the federal rule. 

 Clean Air Act 
 

12 percent of coal-fired boilers.3 While developing MACT standards for 

hazardous air pollutants can take up to 3 years, EPA may be required to 

promulgate its standard sooner depending on the outcome of a pending 

lawsuit. Specifically, EPA has been sued by several environmental groups 

requesting that the EPA Administrator promulgate a MACT standard to 

regulate mercury emissions for coal-fired power plants by a date no later 

than December 2010. 

The Department of Energy’s (DOE) National Energy Technology 

Laboratory has worked with EPA and the Electric Power Research 

Institute (EPRI),4

 among others, during the past 10 years on a 

comprehensive mercury control technology test program. Mercury is 

emitted in such low concentrations that its removal and measurement are 

particularly difficult, and it is emitted in several forms, some of which are 

harder to capture than others.5

 The DOE program has focused largely on 

testing sorbent injection systems6

 on all coal types and at a variety of 

boiler configurations at operating power plants.7

 This regimen of testing 

was important because the type of coal burned and the variety of air 

pollution control devices for other pollutants already installed at power 

plants can impact the effectiveness of sorbent injection systems. For 

example, some power plants already achieve mercury reductions as a “cobenefit” of using devices designed to reduce other pollutants, such as 

sulfur dioxide, nitrogen oxides, and particulate matter. 

According to a 2008 report in which DOE described its mercury 

technology testing program, “DOE successfully brought mercury control 

technologies to the point of commercial-deployment readiness.” 

Nonetheless, the report stated that while the results achieved during 

 

3

According to EPA, its MACT is to also cover the other hazardous air pollutants listed in the 

Clean Air Act as well as emissions from oil-fired power plants. For categories with fewer 

than 30 sources, the MACT standard must be set, at least, at the average level achieved by 

the top five performing units. 

4

EPRI is an independent non-profit company funded by electricity producers that conducts 

research and development in the electricity sector. 

5

Mercury can be emitted in oxidized, elemental, or particulate-bound form. 

6

Sorbent injection systems inject sorbents—powdery substances, typically activated 

carbon, to which mercury binds—into the exhaust from boilers before it is emitted from 

the stack. 

7

In this report, the term “boiler configuration” refers to a coal-fired boiler’s suite of air 

pollution control devices. 

Page 2 GAO-10-47 Clean Air Act
 

DOE’s field tests met or exceeded program goals, the only way to truly 

know the effectiveness—and associated costs—of mercury control 

technologies is through their continuous operation in commercial 

applications at a variety of configurations. At least 18 states have laws or 

regulations requiring mercury emissions reductions at coal-fired power 

plants.8

 The compliance time frames for the state requirements vary. As of 

August 2009, five states—Connecticut, Delaware, Illinois, Massachusetts, 

and New Jersey—require compliance with mercury emission limits. In this 

context, you asked us to examine (1) what mercury reductions have been 

achieved by existing mercury control technologies and the extent to which 

they are being used at coal-fired power plants; (2) the costs associated 

with mercury control technologies currently in use; and (3) key issues 

EPA faces in developing a new regulation for mercury emissions from 

coal-fired power plants. 

To respond to these objectives, we identified power plants with coal-fired 

boilers that are currently operating sorbent injection systems—the most 

mature, mercury-specific control technology—to reduce mercury 

emissions. Using a structured interview tool, we interviewed plant 

managers and engineers at the 14 coal-fired power plants operating 

sorbent injection systems to reduce mercury emissions. These individuals 

provided data on the effectiveness of sorbent injection systems at reducing 

mercury emissions and the costs of doing so.9

 We also obtained 

information on the engineering challenges plant officials have encountered 

in installing and operating sorbent injection systems and actions taken to 

mitigate those challenges.10 In addition, we examined DOE National 

 

8

Two of the states expect mercury emissions reductions from required installations of 

multipollutant control technologies; the other sixteen have specific mercury emissions 

reduction targets. These 18 states are those that had mercury emissions reduction 

requirements in place before the Clean Air Mercury Rule was promulgated or which 

promulgated state-specific provisions in addition to the provisions required by the rule and 

have not specifically repealed those provisions as of August 2009. GAO did not confirm 

whether each state is actively enforcing or planning to enforce these rules. Provisions of 

some state rules may rely on provisions of the Clean Air Mercury Rule, which have been 

vacated. 

9

We interviewed managers at plants with 24 of the 25 boilers using sorbent injection 

systems. As of August 2009, data for one boiler were not provided. Mercury emissions data 

for one boiler were being reviewed by the state clean air agency and were not provided in 

time for inclusion in this report. 

10We visited six plants using sorbent injection systems, and we interviewed plant managers 

at six other plants that reported meeting state mercury emissions requirements with 

existing pollution control devices for other pollutants. 

Page 3 GAO-10-47 Clean Air Act
 

Energy Technology Lab, EPRI, and academic reports on the effectiveness 

and costs of sorbent injection systems over time and reviewed literature 

from recent technical conferences that addressed strategies to overcome 

challenges that some plants have experienced with sorbent injection 

systems. We also reviewed EPA’s requirements for establishing MACT 

standards under the Clean Air Act and recent court cases with 

implications for how EPA establishes such standards. Finally, we met with 

EPA officials in the Office of Air and Radiation regarding the agency’s 

plans for regulating mercury at power plants. Appendix I provides a more 

detailed description of our scope and methodology. We conducted this 

performance audit from November 2008 through September 2009 in 

accordance with generally accepted government auditing standards. Those 

standards require that we plan and perform the audit to obtain sufficient, 

appropriate evidence to provide a reasonable basis for our findings and 

conclusions based on our audit objectives. We believe that the evidence 

obtained provides a reasonable basis for our findings and conclusions 

based on our audit objectives. 

Mercury enters the environment in various ways, such as through volcanic 

activity, coal combustion, and chemical manufacturing. As a toxic 

element, mercury poses ecological threats when it enters water bodies, 

where small aquatic organisms convert it into its highly toxic form—

methylmercury. This form of mercury may then migrate up the food chain 

as predator species consume the smaller organisms. Fish contaminated 

with methylmercury may pose health threats to people who rely on fish as 

part of their diet. Mercury can harm fetuses and cause neurological 

disorders in children, resulting in, among other things, impaired cognitive 

abilities. The Food and Drug Administration and EPA recommend that 

expectant or nursing mothers and young children avoid eating swordfish, 

king mackerel, shark, and tilefish and limit consumption of other 

potentially contaminated fish. These agencies also recommend checking 

local advisories about recreationally caught freshwater and saltwater fish. 

In recent years, most states have issued advisories informing the public 

that concentrations of mercury have been found in local fish at levels of 

public health concern. 

Background 

Coal-fired power plants burn at least one of three primary coal types—

bituminous, subbituminous, and lignite—and some plants burn a blend of 

these coals. Of all coal burned by power plants in the United States in 

2004, DOE estimates that about 46 percent was bituminous, 46 percent 

was subbituminous, and 8 percent was lignite. The amount of mercury in 

coal and the relative ease of its removal depend on a number of factors, 

Page 4 GAO-10-47 Clean Air Act
 

including the geographic location where it was mined and the chemical 

variation within and among coal types.11 In addition to mercury, coal 

combustion releases other harmful air pollutants, including sulfur dioxide 

and nitrogen oxides. EPA regulates these pollutants under its program 

intended to control acid rain and its new source performance standards 

program. Figure 1 shows various pollution controls that may be used at 

coal-fired power plants: selective catalytic reduction to control nitrogen 

oxides, wet or dry scrubbers to reduce sulfur dioxide, fabric filters and 

hot-side or cold-side electrostatic precipitators to control particulate 

matter, and sorbent injection to reduce mercury emissions. 

Figure 1: Sample Layout of Air Pollution Controls, Including Sorbent Injection to Control Mercury, at a Coal-Fired Power Plant 

Coal supply

Stack

Source: GAO analysis of Electric Power Research Institute data.

Sorbent injection

Boiler

Selective catalytic

Fixed adsorption device reduction

Fabric filter or

electrostatic

precipitator

Scrubber

Supplemental

fabric filter

 

11Coal combustion releases mercury in oxidized, elemental, or particulate-bound form. 

Oxidized mercury is more prevalent in the flue gas from bituminous coal combustion, and 

it is relatively easy to capture using some sulfur dioxide controls, such as wet scrubbers. 

Elemental mercury, more prevalent in the flue gas from combustion of lignite and 

subbituminous coal, is more difficult to capture with existing pollution controls. 

Particulate-bound mercury is relatively easy to capture in particulate matter control 

devices. 

Page 5 GAO-10-47 Clean Air Act
 

From 2000 to 2009, DOE’s National Energy Technology Lab conducted 

field tests at operating power plants with different boiler configurations to 

develop mercury-specific control technologies capable of achieving high 

mercury emission reductions at the diverse fleet of U.S. coal-fired power 

plants.12 As a result, DOE now has comprehensive information on the 

effectiveness of sorbent injection systems using all coal types at a wide 

variety of boiler configurations. Most of these tests were designed to 

achieve mercury reductions of 50 to 70 percent while decreasing costs—

which consist primarily of the cost of the sorbent. Thus, the results from 

the DOE test program may understate the mercury reductions that can be 

achieved by sorbent injection systems to some extent. For example, while 

a number of short-term tests achieved mercury reductions in excess of 90 

percent, the amount of sorbent injection that achieved the reductions was 

often decreased during long-term tests to determine the minimum cost of 

achieving, on average, 70 percent mercury emissions reductions. 

Beginning in 2007—near the end of the research program—DOE field tests 

aimed to achieve reductions of 90 percent or greater mercury at low costs. 

However, DOE reported that federal funding for the DOE tests was 

eliminated before the final phase of planned tests was completed. Under 

its mercury testing program, DOE initially tested the effectiveness of 

untreated carbon sorbents, and then DOE tested the effectiveness of 

chemically treated sorbents. In addition, DOE assessed solutions to 

impacts on plant devices, structures, or operations that may result from 

operating these systems—called “balance-of-plant impacts.” We note that 

DOE, EPRI, and others have also helped develop and test other 

technologies, including oxidation catalysts and precombustion mercury 

removal, to reduce mercury emissions that may become commercially 

available in the future. We provide information on some of these emerging 

technologies in appendix II. 

 

12DOE’s research program also tested different types of boilers (such as T-fired, wall-fired 

and cyclone); DOE officials said the pollution control devices were the more important 

parameter in mercury emissions reductions. 

Page 6 GAO-10-47 Clean Air Act
 

Power plants using sorbent injection systems—either commercially 

deployed or tested by DOE and industry—have achieved substantial 

mercury reductions with the three main types of coal and on boiler 

configurations that exist at nearly three-fourths of U.S. coal-fired power 

plants. Some plants, however, may require alternative strategies to achieve 

significant mercury emissions reductions. Nonetheless, some plants 

already achieve substantial mercury emissions reductions with existing 

control devices for other pollutants. 

Substantial Mercury 

Reductions Have 

Been Achieved Using 

Sorbent Injection 

Technology at 14 

Plants and in Many 

DOE Tests 

Sorbent Injection Systems 

Have Achieved Substantial 

Mercury Emissions 

Reductions at Power 

Plants 

The managers of 14 coal-fired power plants reported to us they currently 

operate sorbent injection systems on 25 boilers to meet the mercury 

emissions reduction requirements of five states and several consent 

decrees and construction permits. Data from power plants show that these 

boilers have achieved, on average, reductions in mercury emissions of 

about 90 percent.13 Of note, all 25 boilers currently operating sorbent 

injection systems nationwide have met or surpassed their relevant 

regulatory mercury requirements, according to plant managers.14

Following are a few examples: 

• A 164 megawatt15 bituminous-fired boiler, built in the 1960s and operating 

a cold-side electrostatic precipitator and wet scrubber, was reported as 

exceeding its 90 percent reduction requirement—achieving more than a 95 

percent mercury emission reduction using chemically treated carbon 

sorbent. 

 

13This number reflects data reported by officials with 9 boilers that were required to 

achieve 90 percent mercury emission reduction—which 7 surpassed—and 10 boilers that 

were required to achieve reductions between 80 percent and 89 percent. We do not have 

mercury emissions reduction data for 5 of the 24 sorbent injection systems because the 

power company running these systems is not required to measure emissions under its 

regulatory framework. Data for another boiler are being reviewed by the state clean air 

agency. 

14Data from commercial applications of sorbent injection systems show that mercury 

reductions have been achieved over periods ranging from 3 months to more than a year. 

Most data we examined reflected mercury emissions as of the fourth quarter of 2008. Since 

that time, the power plants have continued to use sorbent injection systems—in some 

cases, these systems have been in continuous use for nearly 2 years. 

15A megawatt is a unit for measuring the electric generation capacity of a power plant. One 

megawatt of capacity operating for one full day produces 24 megawatt-hours—or 24,000 

kilowatt-hours—of electricity. 

Page 7 GAO-10-47 Clean Air Act
 

• A 400 megawatt subbituminous-fired boiler, built in the 1960s and 

operating a cold-side electrostatic precipitator and a fabric filter, was 

reported as achieving a 99 percent mercury reduction using untreated 

carbon sorbent, exceeding its 90 percent reduction regulatory 

requirement. 

• A recently constructed 600 megawatt subbituminous-fired boiler operating 

a fabric filter, dry scrubber, and selective catalytic reduction system was 

reported as achieving an 85 percent mercury emission reduction using 

chemically treated carbon sorbent, exceeding its 83 percent reduction 

regulatory requirement. 

While mercury emissions reductions achieved with sorbent injection on a 

particular boiler configuration do not guarantee similar results at other 

boilers with the same configuration,16 the reductions achieved in 

deployments and tests provide important information for plant managers 

who must make decisions about pollution controls to reduce mercury 

emissions as more states’ mercury regulations become effective and as 

EPA develops a national mercury regulation.17 Further, in 2008, DOE 

reported that the high performance observed during many of its field tests 

at power plants with a variety of boiler configurations has given coal-fired 

power plant operators the confidence to begin deploying these 

technologies. The sorbent injection systems currently used at power plants 

to reduce mercury emissions are operating on boiler configurations that 

are used at 57 percent of U.S. coal-fired power boilers.18 Further, when the 

results of 50 tests of sorbent injection systems at power plants conducted 

primarily as part of DOE’s or EPRI’s mercury control research and 

 

16As we reported in 2005, the results achieved at a particular power plant may not 

necessarily serve as a reliable indicator of the performance of the same control devices at 

all plants. For example, some data show that the extent of mercury reduction achieved by 

sorbent injection at facilities using electrostatic precipitators depends largely on the 

location of these devices at the plant. The location of an electrostatic precipitator affects 

the temperatures of the flue gas entering the device, allowing more mercury to be captured 

at cooler temperatures. 

17For example, see EPRI’s 2006 Mercury Control Technology Selection Guide, which 

summarized tests by DOE and other organizations to provide the coal-fired power industry 

with a process to select the most promising mercury control technologies. EPRI assessed 

the applicability of technologies to various coal types and power plant configurations and 

developed decision trees to facilitate decision making. 

18We used EPA’s 2006 National Electric Energy Data System database for calculating the 

percentage of coal-fired boilers with particular configuration types. We excluded coal-fired 

boilers under 25 megawatts from our analysis because the Clean Air Act does not apply to 

smaller units such as these. 

Page 8 GAO-10-47 Clean Air Act
 

development programs are factored in, mercury reductions of at least 90 

percent have been achieved at boiler configurations used at nearly threefourths of coal-fired power boilers nationally.19 Some boiler configurations 

tested in the DOE program that are not yet included in commercial 

deployments follow: 

• A 360 megawatt subbituminous-fired boiler with a fabric filter and a dry 

scrubber using a chemically treated carbon sorbent achieved a 93 percent 

mercury reduction. 

• A 220 megawatt boiler burning lignite, equipped with a cold-side 

electrostatic precipitator, increased mercury reduction from 58 percent to 

90 percent by changing from a combination of untreated carbon sorbent 

and a boiler additive to a chemically treated carbon sorbent. 

• A 565 megawatt subbituminous-fired boiler with a fabric filter achieved 

mercury reductions ranging from 95 percent to 98 percent by varying the 

amount of chemically treated carbon sorbent injected into the system.20

As these examples of commercially deployed and tested injection systems 

show, power plants are using chemically treated sorbents and sorbent 

enhancement additives, as well as untreated sorbents. Chemically treated 

sorbents and additives can help convert the more difficult-to-capture 

mercury common in lignite and subbituminous coals to a more easily 

captured form, which helped DOE and industry achieve high mercury 

reduction across all coal types.21 The DOE test program initially used 

untreated sorbents. On the basis of these initial tests, we reported in 2005 

that sorbent injection systems showed promising results but that they 

were not effective when used at boilers burning lignite and subbituminous 

 

19We identified 56 field tests conducted by DOE during its mercury control technology 

testing program. Of these tests, we analyzed mercury reduction data of 41 tests conducted 

at power plants. The majority of these tests were long-term tests (30 days or more). Our 

analysis does not include mercury reduction data associated with the other 15 tests either 

because they reflected mercury reduction associated with mercury oxidation catalysts—an 

emerging mercury control technology—or because test result data were not reported. We 

also analyzed results of 9 tests conducted by industry, primarily by EPRI. 

20The rate of sorbent injection varied between 1.0 pounds per million actual cubic feet and 

3.0 pounds per million actual cubic feet. 

21DOE injected sorbents that were treated with halogens such as chlorine or bromine, 

which help convert mercury from an elemental form into an oxidized form. 

Page 9 GAO-10-47 Clean Air Act
 

coals.22 Since then, DOE’s shift to testing chemically treated sorbents and 

enhancement additives showed that using chemically treated sorbents and 

enhancement additives could achieve substantial mercury reductions for 

coal types that had not achieved these results in earlier tests with 

untreated sorbents. For example, injecting untreated sorbents reduced 

mercury emissions by an average of 55 percent during a 2003 DOE test at a 

subbituminous-fired boiler. Recent DOE tests using chemically treated 

sorbents and enhancement additives, however, have resulted in average 

mercury reductions of 90 percent for boilers using subbituminous coals.23

Similarly, recent tests on boilers using lignite reduced mercury emissions 

by about 80 percent, on average. 

The examples of substantial mercury reductions highlighted above also 

show that sorbent injection can be successful with both types of air 

pollution control devices that power plants use to reduce emissions of 

particulate matter—electrostatic precipitators and fabric filters. In some 

commercial deployments, fabric filters were installed to assist with 

mercury control. Plant officials told us, for example, that they chose to 

install fabric filters to assist with mercury control for 10 of the sorbent 

injection systems currently deployed—but that some of the devices were 

installed primarily to comply with other air pollution control requirements. 

One plant manager, for example, said that the fabric filter installed at his 

plant has helped the sorbent injection system achieve higher levels of 

mercury emission reductions but that the driving force behind the fabric 

filter installation was compliance with particulate matter emission limits. 

Further, as another plant manager noted, fabric filters may provide 

additional benefits by limiting emissions of acid gases and trace metals, as 

well as by preserving fly ash—fine powder resulting from coal 

combustion—for sale for reuse.24 Fabric filters, which are more effective 

at mercury emission reduction than electrostatic precipitators, ar

increasingly being installed to reduce emissions of particulate matter and 

other pollutants, but currently less than 20 percent of boilers have them. 

e 

 

22GAO, Clean Air Act: Emerging Mercury Control Technologies Have Shown Promising 

Results, but Data on Long-Term Performance Are Limited, GAO-05-612 (Washington, 

D.C.: May 31, 2005). 

23On subbituminous coal units, eight long-term tests were conducted using chemically 

treated sorbents. The average mercury emission reduction was 90 percent, with mercury 

reductions ranging from 81 percent to 93 percent. 

24Properties of fly ash vary significantly with coal composition and plant-operating 

conditions. Some power plants sell fly ash for use in Portland cement and to meet other 

construction needs. 

Page 10 GAO-10-47 Clean Air Act
 

The successful deployments of sorbent injection technologies at power 

plants occurred around the time DOE concluded, on the basis of its tests, 

that these technologies were ready for commercial deployment. As a 

result, funding for the DOE testing program has been eliminated.25 As 

many states’ compliance dates for mercury emission reduction near,26 the 

Institute of Clean Air Companies reported that power plants had 121 

sorbent injection systems on order as of February 2009.27 (App. III 

provides data on state regulations requiring mercury emission reductions.) 

 

Some Plants May Require 

Alternative Strategies to 

Achieve Significant 

Mercury Reductions 

While sorbent injection technology has been shown to be effective with all 

coal types and on boiler configurations that currently exist at more than 

three-fourths of U.S. coal-fired power plants, DOE tests show that some 

plants may not be able to achieve mercury reductions of 90 percent or 

more with sorbent injection systems alone. Following are a few reasons 

why: 

• Sulfur trioxide—which can form under certain operating conditions or 

from using high sulfur bituminous coal—may limit mercury reduction 

because it interferes with the process of mercury binding to carbon 

sorbents. 

• Hot-side electrostatic precipitators reduce the effectiveness of sorbent 

injection systems. Installed on 6 percent of boilers nationwide, these 

particulate matter control devices operate at very high temperatures, 

which reduces the ability of mercury to bind to sorbents and be collected 

in the devices. 

• Lignite, used by roughly 3 percent of boilers nationwide,28 has relatively 

high levels of elemental mercury—the most difficult form to capture. 

25The DOE mercury testing program has not received new funding since fiscal year 2008. 

26Illinois, Maryland, Minnesota, Montana, New Mexico, New York, and Wisconsin require 

compliance by the end of 2010. Arizona, Colorado, New Hampshire, Oregon, and Utah 

require compliance in 2012 or later. Georgia and North Carolina require installation 

between 2008 and 2018 of other pollution control devices that capture sulfur dioxide, 

nitrogen oxides, and mercury as a side benefit. North Carolina requires the submission of 

specific mercury reduction plans for certain plants by 2013. 

27The Institute of Clean Air Companies is the trade association of companies that supply air 

pollution control and monitoring technology. 

28As noted earlier, the lignite burned by all coal-fired power plants represents 8 percent of 

all coal burned in the United States. 

Page 11 GAO-10-47 Clean Air Act
 

Lignite is found primarily in North Dakota and the Gulf Coast (the latter is 

called Texas lignite). Mercury reduction using chemically treated sorbents 

and sorbent enhancement additives on North Dakota lignite has averaged 

about 75 percent—less than reductions using bituminous and 

subbituminous coals. Less is known about Texas lignite because few tests 

have been performed using it. However, a recent test at a plant burning 

Texas lignite achieved an 82 percent mercury reduction. 

Boilers that may not be able to achieve 90 percent emissions reductions 

with sorbent injection alone, and some promising solutions to the 

challenges they pose, are discussed in appendix IV. Further, EPRI is 

continuing research on mercury controls at power plants that should help 

to address these challenges. In some cases, however, plants may need to 

pursue a strategy other than sorbent injection to achieve high mercury 

reductions. For example, officials at one plant decided to install a sulfur 

dioxide scrubber—designed to reduce both mercury and sulfur dioxide—

after sorbent injection was found to be ineffective. This approach may 

become more typical as power plants comply with the Clean Air Interstate 

Rule and court-ordered revisions to it,29 which EPA is currently 

developing, and as some plants add air pollution control technologies 

required under consent decrees. 

Along these lines, EPA air strategies group officials told us that many 

power plants will be installing devices—fabric filters, scrubbers, and 

selective catalytic reduction systems—that are typically associated with 

high levels of mercury reduction, which will likely reduce the number of 

plants requiring alternative strategies for mercury control. Finally, 

mercury controls have been tested on about 90 percent of the boiler 

configurations at coal-fired power plants. The remaining 10 percent 

include several with devices that are often associated with high levels of 

mercury emission reductions, such as selective catalytic reduction devices 

for nitrogen oxides control and wet scrubbers for sulfur dioxide control. 

 

29The Clean Air Interstate Rule is a regional air pollution reduction program covering 28 

eastern states and the District of Columbia. Developed by EPA and promulgated in May 

2005, the rule controls emissions from power plants through caps on sulfur dioxide and 

nitrogen oxides pollution. A D.C. Circuit Court of Appeals December 23, 2008, ruling leaves 

this rule and its trading programs in place until EPA issues a new rule to replace it. EPA 

informed the Court that development and finalization of a replacement rule could take 

about 2 years. 

Page 12 GAO-10-47 Clean Air Act
 

Importantly, mercury control technologies will not have to be installed on 

a number of coal-fired boilers to meet mercury emission reduction 

requirements because these boilers already achieve high mercury 

reductions from their existing pollution control devices.30 EPA 1999 data, 

the most recent available, indicated that about one-fourth of the industry 

achieved mercury reductions of 90 percent or more as a co-benefit of 

other pollution control devices.31 We found that of the 36 boilers currently 

subject to mercury regulation, 11 are relying on existing pollution controls 

to meet their mercury reduction requirements.32 One plant manager told us 

his plant achieves 95 percent mercury reduction as a result of existing 

devices, specifically with a fabric filter for particulate matter control, a 

scrubber for sulfur dioxide control, and a selective catalytic reduction 

system for nitrogen oxides control. Other plants may also be able to 

achieve high mercury reduction with their existing pollution control 

devices. For example, according to EPA data, a bituminous-fired boiler 

with a fabric filter may reduce mercury emissions by more than 90 

percent. As discussed above, it is likely that many power plants will be 

installing devices that are typically associated with high levels of mercury 

reduction; thus the number of plants that may not require sorbent 

injection systems to meet regulatory requirements is likely to increase. 

A Number of Plants 

Already Achieve 

Substantial Mercury 

Reductions with Existing 

Controls for Other 

Pollutants 

 

30Nationwide, mercury reductions achieved as a co-benefit of other pollution control 

devices reduced mercury emissions from about 75 tons (inlet coal) to approximately 48 

tons. Mercury reductions achieved as a co-benefit range from zero to nearly 100 percent, 

depending on control device configuration and coal type. For example, a boiler using 

bituminous coal and having a fabric filter can achieve mercury reductions in excess of 90 

percent. In contrast, a boiler using subbituminous coal and having only a cold-side 

electrostatic precipitator might achieve little, if any, co-benefit mercury reduction. 

31This estimate is based on data from EPA’s 1999 information collection request, which 

EPA air toxics program officials believe to be representative of the current coal-fired 

power industry. 

32Two plants with four boilers will face increasingly stringent limits in the next 3 to 4 years. 

One plant manager, facing a mercury reduction requirement that will increase from 80 

percent to 90 percent, told us that the plant is currently installing a sorbent injection 

system in anticipation of the more stringent standard. The other plant manager, facing a 

mercury reduction requirement that will increase from 85 percent to 95 percent, told us 

that his plant will likely need to install a sorbent injection system in the future to 

supplement the co-benefit mercury capture the plant currently achieves with existing 

pollution controls. 

Page 13 GAO-10-47 Clean Air Act
 

The cost to meet current regulatory requirements for mercury reductions 

has varied depending in large part on decisions regarding compliance with 

other pollution reduction requirements. For example, while sorbent 

injection systems alone have been installed on most boilers that must meet 

mercury reduction requirements—at a fraction of the cost of other 

pollution control devices—fabric filters have also been installed on some 

boilers to assist in mercury capture or to comply with particulate matter 

requirements, according to plant officials we interviewed. 

The costs of purchasing and installing sorbent injection systems and 

monitoring equipment have averaged about $3.6 million for the 14 coalfired boilers that use sorbent injection systems alone to reduce mercury 

emissions.33 For these boilers, the cost ranged from $1.2 million to $6.2 

million.34 By comparison, on the basis of EPA estimates, the average cost 

to purchase and install a wet scrubber for sulfur dioxide control, absent 

monitoring system costs, is $86.4 million per boiler, ranging from $32.6 

million to $137.1 million.35 EPA’s estimate of the cost to purchase and 

install a selective catalytic reduction device to control nitrogen oxides 

ranges from $12.7 million to $127.1 million, or an average of $66.1 million. 

Mercury Control 

Technologies Are 

Often Relatively 

Inexpensive, but 

Costs Depend Largely 

on How Plants 

Comply with 

Requirements for 

Reducing Other 

Pollutants 

Capital costs can increase significantly if fabric filters are also purchased 

to assist in mercury emission reductions or as part of broader emission 

reduction requirements. For example, plants installed fabric filters at 

another 10 boilers for these purposes. On the five boilers where plant 

officials reported also installing a fabric filter specifically designed to 

assist the sorbent injection system in mercury emission reductions, the 

average reported capital cost for both the sorbent injection system and 

fabric filter was $15.8 million per boiler—the costs ranged from $12.7 

million to $24.5 million. Importantly, some of these boilers have 

uncommon configurations36—ones that, as discussed earlier, DOE tests 

 

33Cost data are reported in 2008 dollars. 

34The total cost to purchase and install a sorbent injection system reflects the costs of (1) 

sorbent injection equipment, (2) an associated mercury emissions monitoring system, and 

(3) associated engineering and consulting services. 

35EPA’s 2006 cost estimates are reported in 2008 dollars. 

36Three of the five boilers with fabric filters designed specifically to assist in mercury 

reduction, for instance, have hot-side electrostatic precipitators—a relatively rare 

particulate matter control device that inhibits high mercury removal when sorbent 

injection systems are used without fabric filters. 

Page 14 GAO-10-47 Clean Air Act
 

showed would need additional control devices to achieve high mercury 

reductions.37

For the five boilers where plant officials reported installing fabric filters 

along with sorbent injection systems largely to comply with requirements 

to control other forms of air pollution, the average reported capital cost 

for the two technologies was $105.9 million per boiler, ranging from $38.2 

million to $156.2 million per boiler.38 For these boilers, the capital costs 

result from requirements to control other pollutants, and we did not 

determine what portion of these costs would appropriately be allocated to 

the cost of reducing mercury emissions. Decisions to purchase such fabric 

filters will likely be driven by the broader regulatory landscape affecting 

plants in the near future, such as requirements for particulate matter and 

sulfur dioxide reductions, as well as EPA’s upcoming MACT standard to 

regulate mercury emissions from coal-fired power plants. Information on 

detailed average costs to purchase and install sorbent injection systems 

and monitoring equipment, with and without fabric filters, is provided in 

appendix V. 

Regarding operating costs, plant managers said that annual operating costs 

associated with sorbent injection systems consist almost entirely of the 

cost of the sorbent itself. In operating sorbent injection systems, sorbent is 

injected continuously into the boiler exhaust gas to bind to mercury 

passing through the gas. The rate of injection is related to, among other 

things, the level of mercury emissions reduction required to meet 

regulatory requirements and the amount of mercury in the coal used. For 

the 18 boilers with sorbent injection systems for which power plants 

provided sorbent cost data, the average annualized cost of sorbent was 

$674,000—ranging from $76,500 to $2.4 million. 

Plant engineers often adjust the injection rate of the sorbent to capture 

more or less mercury—the more sorbent in the exhaust gas, the higher the 

likelihood that more mercury will bind to it. Some plant managers told us 

that they have recently been able to decrease their sorbent injection rates, 

 

37The costs reported by officials of coal-fired power plants that installed sorbent injection 

systems and, in some cases, fabric filters may not necessarily serve as reliable indicators of 

the costs of the same control devices at all plants. 

38The average cost of the sorbent injection system for these boilers was $2.9 million and for 

the monitoring systems, $500,000. The average cost for the fabric filters was $84 million 

and for the engineering studies, $11 million. 

Page 15 GAO-10-47 Clean Air Act
 

thereby reducing costs, while still complying with relevant requirements. 

Specifically, a recently constructed plant burning subbituminous coal 

successfully used sorbent enhancement additives to considerably reduce 

its rate of sorbent injection—resulting in significant savings in operating 

costs when compared with its original expectations. Plant managers at 

other plants reported that they have injected sorbent at relatively higher 

rates because of regulatory requirements that mandate a specific injection 

rate. In one state, for example, plants are required to operate their sorbent 

injection systems at an injection rate of 5 pounds per million actual cubic 

feet.39 Among the 19 boilers for which plant managers provided operating 

cost data, the average injection rate was 4 pounds per million actual cubic 

feet; rates ranged from 0.5 to 11.0 pounds per million actual cubic feet. 

For those plants that installed a sorbent injection system alone to meet 

mercury emissions requirements—at an average cost of $3.6 million—the 

cost to purchase, install, and operate sorbent injection and monitoring 

systems represents 0.12 cents per kilowatt hour, or a potential 97 cent 

increase in the average residential consumer’s monthly electricity bill. 

How, when, and to what extent consumers’ electric bills will reflect the 

capital and operating costs power companies incur for mercury controls 

depends in large measure on market conditions and the regulatory 

framework in which the plants operate. Power companies in the United 

States are generally divided into two broad categories: (1) those that 

operate in traditionally regulated jurisdictions where cost-based rate 

setting still applies (rate-regulated) and (2) those that operate in 

jurisdictions where companies compete to sell electricity at prices that are 

largely determined by supply and demand (deregulated). Rate-regulated 

power companies are generally allowed by regulators to set rates that will 

recover allowable costs, including a return on invested capital.40

Minnesota, for example, passed a law in 2006 allowing power companies 

to seek regulatory approval for recovering the costs of state-required 

reductions in mercury emissions in advance of the regulatory schedule for 

rate increase requests. One power company in the state submitted a plan 

for the installation of sorbent injection systems to reduce mercury 

 

39Pounds per million actual cubic feet is the standard metric for measuring the rate at 

which sorbent is injected into a boiler’s exhaust gas. 

40Under traditional cost-based rate regulations, utility companies submit to regulators the 

costs they seek to cover through the rates they charge their customers. Regulators examine 

the power companies’ requests and decide what costs are allowable under the relevant 

rules. 

Page 16 GAO-10-47 Clean Air Act
 

emissions at two of its plants at a cost of $4.4 million and $4.5 million, 

respectively, estimating a rate increase of 6 to 10 cents per month for 

customers of both plants.41

For power companies operating in competitive markets where wholesale 

electricity prices are not regulated, prices are largely determined by supply 

and demand. Generally speaking, market pricing does not guarantee full 

cost recovery to suppliers, especially in the short run. Of the 25 boilers 

using sorbent injection systems to comply with a requirement to control 

mercury emissions, 21 are in jurisdictions where full cost recovery is not 

guaranteed through regulated rates. 

In addition to the costs discussed above, some plant managers told us they 

have incurred costs associated with balance-of-plant impacts. The issue of 

particular concern relates to fly ash—fine particulate ash resulting from 

coal combustion that some power plants sell for commercial uses, 

including concrete production, or donate for such uses as backfill. 

According to DOE, about 30 percent of the fly ash generated by coal-fired 

power plants was sold in 2005; 216 plants sold some portion of their fly 

ash. Most sorbents increase the carbon content of fly ash, which may 

render it unsuitable for some commercial uses.42 Specifically, some plant 

managers told us that they have lost income because of lost fly ash sales 

due to its carbon content and incurred additional costs to store fly ash that 

was previously either sold or donated for re-use. For the eight boilers with 

installed sorbent injection systems to meet mercury emissions 

requirements for which plants reported actual or estimated fly-ash-related 

costs, the average net cost reported by plants was $1.1 million per year.43

 

41The rate increase request will be submitted in conjunction with requests for rate increases 

for the utility’s other plants. 

42Technologies to mitigate balance-of-plant costs associated with fly ash are available. For 

example, one plant installed a polishing fabric filter using TOXECONTM system, which 

preserves the plant’s ability to sell its fly ash. Another plant had previously installed an ash 

reduction device that removes excess carbon in fly ash and enables the plant to sell the 

vast majority of its fly ash when operating its sorbent injection system. 

43DOE’s research program also examined the potential costs plants may incur to dispose of 

fly ash if the carbon and mercury content renders it unsuitable for commercial uses. See 

Andrew P. Jones et al., DOE/NETL’s Phase II Mercury Control Technology Field Testing 

Program: Updated Economic Analysis of Activated Carbon Injection, prepared at the 

request of DOE, May 2007. 

Page 17 GAO-10-47 Clean Air Act
 

Advances in sorbent technologies that have reduced costs at some plants 

also offer the potential to preserve the market value of fly ash. For 

example, at least one manufacturer offers a concrete-friendly sorbent to 

help preserve fly ash sales—thus reducing potential fly ash storage and 

disposal costs. Additionally, a recently constructed plant burning 

subbituminous coal reported that it had successfully used sorbent 

enhancement additives to reduce its rate of sorbent injection from 2 

pounds to less than one-half pound per million actual cubic feet—resulting 

in significant savings in operating costs and enabling it to preserve the 

quality of its fly ash for reuse. Other potential advances include refining 

sorbents through milling and changing the sorbent injection sites. 

Specifically, in testing, milling sorbents has, for some configurations, 

improved their efficiency in reducing mercury emissions—that is, reduced 

the amount of sorbent needed—and also helped minimize negative impact 

on fly ash re-use. Also, in testing, some vendors have found that injecting 

sorbents on the hot side of air preheaters can decrease the amount of 

sorbent needed to achieve desired levels of mercury control.44

In addition, some plant managers reported balance-of-plant impacts 

associated with sorbent injection systems, such as ductwork corrosion 

and small fires in the particulate matter control devices. The managers 

told us these issues were generally minor and have been resolved. For 

example, two plants experienced corrosion in the ductwork following the 

installation of their sorbent injection systems. One plant manager resolved 

the problem by purchasing replacement parts at a cost of $4,500. The other 

plant manager told us that the corrosion problem remains unresolved but 

that it is primarily a minor engineering challenge that does not impact 

plant operations. Four plant managers reported fires in the particulate 

matter control devices; plant engineers have generally solved this problem 

by emptying the ash from the collection devices more frequently. Overall, 

despite minor balance-of-plant impacts, most plant managers said that the 

sorbent injection systems at their plants are more effective than they had 

originally expected. 

 

44An air preheater is a device designed to preheat the combustion air used in a fuel-burning 

furnace for the purpose of increasing the thermal efficiency of the furnace. 

Page 18 GAO-10-47 Clean Air Act
 

EPA’s decisions on key regulatory issues will impact the overall stringency 

of its MACT standard regulating mercury emissions. Specifically, the data 

EPA decides to use will affect (1) the mercury emission reductions 

calculated for “best performers,” from which a proposed emission limit is 

derived; (2) whether EPA will establish varying standards for the three 

coal types; and (3) how EPA’s standard will take into account varying 

operating conditions. Each of these issues will affect the stringency of the 

MACT standard the agency proposes. In addition, the format of the 

standard—whether it limits the mercury emissions as a function of the 

amount of mercury per trillion British thermal units (BTU) of heat input 

(an input standard) or on the basis of the amount of mercury per 

megawatt hour of electricity produced (an output standard)—may affect 

the stringency of the MACT standard the agency proposes. Finally, the 

court’s decision to vacate the Clean Air Mercury Rule, which required 

most coal-fired power plants to conduct continuous emissions monitoring 

for mercury beginning in 2009, has delayed for a number of years the 

continuous emissions monitoring that would have started in 2009 at most 

coal-fired power plants. 

Decisions EPA Faces 

on Key Regulatory 

Issues Will Have 

Implications for the 

Effectiveness of Its 

Mercury Emission 

Standard for CoalFired Power Plants 

and the Availability of 

Monitoring Data 

Current Data from 

Commercial Deployments 

and DOE Tests Could Be 

Used in Determining 

Whether to Support a More 

Stringent Standard for 

Mercury Emissions from 

Power Plants Than Was 

Last Proposed by EPA 

Obtaining data on mercury emissions and identifying the “best 

performers”—defined as the 12 percent of coal-fired power plant boilers 

with the lowest mercury emissions45—is a critical initial step in the 

development of a MACT standard regulating mercury emissions. EPA may 

set one standard for all power plants, or it may establish subcategories to 

distinguish among classes, types, and sizes of plants. For example, in its 

2004 proposed mercury MACT standard,46 EPA established subcategories 

for the types of coal most commonly used by power plants. Once the 

average mercury emissions of the best performers are established for 

power plants—or for subcategories of power plants—EPA accounts for 

variability in the emissions of the best performers in its MACT standards. 

EPA’s method for accounting for variability has generally resulted in 

MACT standards that are less stringent than the average emission 

reductions achieved by the best performers. 

 

45This is how section 112 of the Clean Air Act, as amended, defines best performers for the 

largest categories of sources when establishing MACT standards. 

46Prior to finalizing the Clean Air Mercury Rule, EPA also proposed a MACT standard 

regulating mercury emissions from coal-fired power plants. EPA chose not to finalize the 

MACT rule. 

Page 19 GAO-10-47 Clean Air Act
 

To identify the best performers, EPA typically collects emissions data 

from a sample of plants representative of the U.S. coal-fired power 

industry through a process known as an information collection request. 

Before a federal agency can collect data from 10 or more nongovernmental 

parties, such as power plants, it must obtain approval from the Office of 

Management and Budget (OMB) for the information collection request. 

According to EPA officials, this data collection process typically takes 

from 8 months to 1 year. Although EPA has discretion in choosing the data 

it will use to identify best performers,47 on July 2, 2009, EPA published a 

draft information collection request in the Federal Register providing a 60-

day public comment period on the draft questionnaire to industry prior to 

submitting this information collection request to OMB for review and 

approval. EPA’s schedule for issuing a proposed rule and a final rule has 

not yet been established; the agency is currently defending a lawsuit that 

may establish such a schedule.48

Our analysis of EPA’s 1999 data, as well as more current data from 

deployments and DOE tests, shows that newer data may have several 

implications for the stringency of the standard. First, the average 

emissions reductions of the best performers, from which the standard is 

derived, may be greater using more current data than the reductions 

derived from EPA’s 1999 data. Our analysis of EPA’s 1999 data shows an 

average mercury emission reduction of nearly 91 percent for the best 

performers.49 In contrast, using more current commercial deployment and 

DOE test data, as well as data on co-benefit mercury reductions collected 

in 1999, an average mercury emission reduction of nearly 96 percent for 

best performers is demonstrated. The 1999 data do not reflect the 

significant and widespread mercury reductions achieved by sorbent 

injection systems. Further, EPA’s 2004 proposed MACT standards for 

mercury were substantially less stringent than the 1999 average emission 

 

47EPA officials told us, for instance, that the agency could decide to use data from its 1999 

information collection request or data from commercial deployments and DOE tests. 

48Under the Clean Air Act Amendments of 1990, EPA had 10 years from the enactment of 

the amendments, or 2 years from the listing of electric steam-generating units as sources of 

hazardous air pollutants subject to regulation, whichever was later, to promulgate a MACT 

standard. Because EPA did not list electric steam-generating units until 2000, it originally 

had 2 years, or until 2002, to promulgate a MACT standard. Because EPA missed this 

promulgation date, a mandatory duty lawsuit was filed against the agency that will result in 

a court-approved schedule. 

49Our analysis of EPA’s data includes the three primary coal types: bituminous, 

subbituminous, and lignite. 

Page 20 GAO-10-47 Clean Air Act
 

reduction of the best performers because of variability in mercury 

emissions among the top performers, as discussed later in more detail. 

Second, more current information that reflects mercury control 

deployments and DOE tests may make the rationale EPA used in the past 

to create MACT standards for different subcategories less compelling to 

the agency now. In 2004, using 1999 data, EPA proposed separate MACT 

standards for each type of coal used at power plants. The agency 

explained that mercury emissions reductions from boilers using lignite and 

subbituminous coal was substantially less than from those using 

bituminous coal. Specifically, the 1999 data EPA used for its 2004 

proposed MACT standards showed that best performers achieved average 

emission reductions of 97 percent for bituminous, 71 percent for 

subbituminous, and 45 percent for lignite. In contrast, more current data 

show that sorbent injection systems have achieved average mercury 

emissions reductions of more than 90 percent with bituminous and 

subbituminous coal types and nearly this amount with lignite. 

Finally, using more current emissions data in setting the MACT standard 

for regulating mercury may mean that accounting for variability in 

emissions will not have as significant an effect as it did in the 2004 

proposed MACT—when it led to a less stringent MACT standard—because 

more current data may already reflect variability. In its 2004 proposed 

MACT, EPA explained that its 1999 data, obtained from the average of 

short-term tests (three samples taken over a 1- to 2-day period), did not 

necessarily reveal the range of emissions that would be found over 

extended periods of time or under a full range of operating conditions they 

could reasonably anticipate. EPA thus extrapolated longer-term variability 

data from the short-term data, and on the basis of these calculations, 

proposed MACT standards equivalent to a 76 percent reduction in mercury 

emissions for bituminous coal, a 25 percent reduction for lignite, and a 5 

percent reduction for subbituminous coal—20 to 66 percentage points 

lower than the average of what the best performers achieved for each coal 

type. 

However, current data may eliminate the need for such extrapolation. Data 

from commercial applications of sorbent injection systems, DOE field 

tests, and co-benefit mercury reductions show that mercury emissions 

reductions well in excess of 90 percent have been achieved over periods 

ranging from more than 30 days in field tests to more than a year in 

Page 21 GAO-10-47 Clean Air Act
 

commercial applications. Mercury emissions measured over these periods 

may more accurately reflect the variability in mercury emissions that 

plants would encounter over the range of operating conditions.50 Along 

these lines, at least 15 states with mercury emission limits require longterm averaging—ranging from 1 month to 1 year—to account for 

variability. According to the manager of a power plant operating a sorbent 

injection system, long-term averaging of mercury emissions takes into 

account the “dramatic swings” in mercury emissions from coal that may 

occur. He told us that while mercury emissions can vary on a day-to-day 

basis, this plant has achieved 94 percent mercury reduction, on average, 

over the last year.51 Similarly, another manager of a power plant operating 

a sorbent injection system told us the amount of mercury in the coal used 

at the plant “varies widely, even from the same mine.” Nonetheless, the 

plant manager reported that this plant achieves its required 85 percent 

mercury reduction because the state allows averaging mercury emissions 

on a monthly basis to take into account the natural variability of mercury 

in the coal. 

The Type of Standard EPA 

Chooses May Also Affect 

the Stringency of the 

Regulation 

In 2004, EPA’s proposed mercury MACT included two types of standards 

to limit mercury emissions: (1) an output-based standard for new coalfired power plants and (2) a choice between an input- or output-based 

standard for existing plants. Input-based standards establish emission 

limits on the basis of pounds of mercury per trillion BTUs of heat input; 

output-based standards, on the other hand, often establish emission limits 

 

50According to officials with one industry group, many coal-fired power plants use coal 

from numerous mines, and the mercury content in coal from these different sources can 

vary dramatically. These officials said that variability in mercury emissions resulting from 

the use of coal from different sources should be considered when setting a MACT standard. 

Officials with several coal-fired power plants told us that requiring compliance over long 

time periods—such as monthly, quarterly, or annually—is one way to ensure that such 

variability is accounted for. 

51The requirement for this plant, which the plant manager reported it has met, is for a 90 

percent reduction averaged over a 3-month period. 

Page 22 GAO-10-47 Clean Air Act
 

on the basis of pounds of mercury per megawatt hour of electricity 

produced. These standards are referred to as emission limits.52

Input-based limits can have some advantages for coal-fired power plants. 

For example, input-based limits can provide more flexibility to older, less 

efficient plants because they allow boilers to burn as much coal as needed 

to produce a given amount of electricity, as long as the amount of mercury 

per trillion BTUs does not exceed the level specified by the standard.53

However, input-based limits may allow some power plants to emit more 

mercury per megawatt hour than output-based limits. Under an outputbased standard, mercury emissions cannot exceed a specific level per 

megawatt-hour of electricity produced—efficient boilers that use less coal 

will be able to produce more electricity than inefficient boilers under an 

output-based standard. Moreover, under an output-based limit, less 

efficient boilers may have to, for example, increase boiler efficiency or 

switch to a lower mercury coal. Thus, output-based limits provide a 

regulatory incentive to enhance both operating efficiency and mercury 

emission reductions. If all else was held equal, less mercury would be 

emitted nationwide under an output-based standard. 

We found that at least 16 states have established a format for regulating 

mercury emissions from coal-fired power plants. Eight states allow plants 

to meet either an emission limit or a percent reduction, three require an 

emission limit, four require percent reductions, and one state requires 

plants to achieve whatever mercury emissions reductions—percent 

 

52For the purposes of setting a standard, emissions limits can be correlated to percent 

reductions. For example, EPA’s 2004 proposed standards for bituminous, lignite, and 

subbituminous coal (2, 9.2, and 5.8 pounds per trillion BTUs, respectively) are equivalent 

with mercury emissions reductions of 76, 25, and 5 percent, respectively, based on 

nationwide averages of the mercury content in coal. During EPA’s 2004 MACT development 

process, state and local agency stakeholders, as well as environmental stakeholders, 

generally supported output-based emission limits; industry stakeholders generally 

supported having a choice between an emission limit and a percent reduction. EPA must 

now decide in what format it will set its mercury MACT standard(s). 

53The main types of coal burned, in decreasing order of rank, are bituminous, 

subbituminous, and lignite. Rank is the coal classification system based on factors such as 

the heating value of the coal. High-rank coal generally has relatively high heating values 

(i.e., heat per unit of mass when burned) compared with low-rank coal, which has 

relatively low heating values. 

Page 23 GAO-10-47 Clean Air Act
 

reduction or emission limit—are greater.54 On the basis of our review of 

these varying regulatory formats, we conclude that to be meaningful, a 

standard specifying a percent reduction should be correlated to an 

emission limit. When used alone, percent reduction standards may reduce 

the actual mercury emissions reductions achieved. For example, in one 

state, mercury reductions are measured against the “historical” amount of 

mercury in coal, rather than the amount of mercury in coal being currently 

used by power plants in the state. If plants are required to reduce mercury 

by, for example, 90 percent compared to historical coal data, but coal used 

in the past had higher levels of mercury than the plants have been using 

more recently, then actual mercury emission reductions would be less 

than 90 percent. In addition, percent reduction requirements do not 

provide an incentive for plants burning high mercury coal to switch coals 

or pursue more effective mercury control strategies because it is easier to 

achieve a percent reduction requirement with higher mercury coal than 

with lower mercury coals. 

Similarly, a combination standard that gives regulated entities the option 

to choose either a specified emission limit or a percent reduction might 

reduce the actual mercury emission reductions achieved. For example, a 

plant burning coal with a mercury content of 15 pounds per trillion BTUs 

that may choose between meeting an emission limit of 0.7 pounds of 

mercury per trillion BTUs or a 90 percent reduction could achieve the 

percent reduction while emitting twice the mercury that would be allowed 

under the specified emission limit. As discussed earlier, for the purposes 

of setting a standard, a required emission limit that provides a consistent 

benchmark for plants to meet can be correlated to a percent reduction. 

For example, according to EPA’s Utility Air Toxic MACT working group, a 

90 percent mercury reduction based on national averages of mercury in 

coal generally equates to a national average emission limit of 

approximately 0.7 pounds per trillion BTUs.55 For bituminous coal, a 90 

 

54Colorado, Connecticut, Delaware, Illinois, Massachusetts, New Jersey, Oregon, and Utah 

allow either an emission limit or a percent reduction; Montana, New Mexico, and New York 

require an emission limit; Maryland, Minnesota, New Hampshire, and Wisconsin require 

percent reductions (Wisconsin mercury emission standard changes to require meeting 

either a limit or a percent reduction in 2015); and Arizona requires the more stringent 

option—whichever is more stringent, a percent reduction or emission limit. 

55Presentation on “Recommendations on the Utility Air Toxics MACT, Final Working Group 

Report, October 2002.” The Working Group on the Utility MACT was formed under the 

Clean Air Act Advisory Committee, Subcommittee for Permits/New Source 

Reviews/Toxics. 

Page 24 GAO-10-47 Clean Air Act
 

percent reduction equates to a limit of 0.8 pounds per trillion BTUs; for 

subbituminous coal, a 90 percent reduction equates to a limit of 0.6 

pounds per trillion BTUs; and for lignite, a 90 percent reduction equates to 

a limit of 1.2 pounds per trillion BTUs. 

Continuous Monitoring of 

Mercury Emissions at Most 

Power Plants Has Been 

Delayed 

EPA’s now-vacated Clean Air Mercury Rule required most coal-fired power 

plants to conduct continuous emissions monitoring for mercury—and a 

small percentage of plants with low mercury emissions to conduct 

periodic testing—beginning in 2009. State and federal government and 

nongovernmental organization stakeholders told us they support 

reinstating the monitoring requirements of the Clean Air Mercury Rule. In 

fact, in a June 2, 2008, letter to EPA, the National Association of Clean Air 

Agencies requested that EPA reinstate the mercury monitoring provisions 

that were vacated in February 2008 because, among other things, they are 

important to state agencies with mercury reduction requirements and 

power plants complying with them.56 This association also said the need 

for federal continuous emissions monitoring requirements is especially 

important in states that cannot adopt air quality regulations more stringent 

than those of the federal government. However, EPA officials told us the 

agency has not determined how to reinstate continuous emissions 

monitoring requirements for mercury at coal-fired power plants outside of 

the MACT rulemaking process. 

Under the Clean Air Mercury Rule, the selected monitoring methodology 

for each power plant was to be approved by EPA through a certification 

process. For its part, EPA was to develop performance specifications—

protocols for quality control and assurance—for continuous emissions 

monitoring systems (CEMS). However, when the Clean Air Mercury Rule 

was vacated in February 2008, EPA delayed development of these 

performance specifications. EPA has taken steps recently to develop 

performance specifications for mercury CEMS under a May 6, 2009, 

proposed rule limiting mercury emissions from facilities that produce 

Portland cement.57 As part of this proposed rule, EPA also proposed 

performance specifications that describe performance evaluations that 

must be conducted to ensure the continued accuracy of the CEMS 

 

56The National Association of Clean Air Agencies represents air pollution control agencies 

in 53 states and territories and over 165 major metropolitan areas across the United States. 

57Portland cement is the most common type of cement in general use around the world. It is 

a basic ingredient of concrete, mortar, stucco and most non-specialty grout. 

Page 25 GAO-10-47 Clean Air Act
 

emissions data. In the proposed rule, EPA stated that the performance 

specifications for mercury CEMS used to monitor emissions from Portland 

cement facilities could also apply to other sources. Further, an EPA Sector 

Policies and Programs Division official told us that if EPA chooses—as it 

did in its 2004 proposed MACT—to require continuous monitoring for 

mercury emissions in its final rule regulating hazardous air pollutants from 

coal-fired power plants, the performance specifications will already be in 

place for continuous emissions monitoring systems’ use when the Portland 

cement MACT is finalized. 

Effective continuous emissions monitoring can assist facilities and 

regulators ensure compliance with regulations and can also help facilities 

identify ways to better understand the efficiency of their processes and 

operations. For example, using CEMS, plant managers told us they can 

routinely make adjustments in the amount of sorbent needed to meet 

regulatory requirements, potentially reducing costs. Nevertheless, 

monitoring mercury emissions is more complex than monitoring other 

pollutants, such as nitrogen oxides and sulfur dioxide, which are 

measured in parts per million—mercury is emitted at lower levels of 

concentration than other pollutants and is measured in parts per billion. 

Consequently, mercury CEMS may require more time to install than CEMS 

for other pollutants, and according to plant engineers using them, getting 

these relatively complex monitoring systems up and running properly 

involves a steeper learning curve. 

In our work, we found that mercury CEMS were installed on 16 boilers at 

power plants and used for monitoring operations and compliance 

reporting.58 Plant managers reported that their mercury CEMS were online 

from 62 percent to 99 percent of the time. The system that was online 62 

percent of the time was not used for compliance purposes but rather to 

monitor the effectiveness of different sorbent injection rates on mercury 

emissions. Excluding this case, CEMS were online about 90 percent of the 

time, on average. When these systems were offline, it was mainly because 

of failed system integrity checks or for routine parts replacement. Some 

plant engineers told us that they believed CEMS were several years away 

from commercial readiness to accurately measure mercury emissions but 

that they had purchased and installed the CEMS in anticipation of the 

requirement that was part of the now-vacated Clean Air Mercury Rule. 

 

58At least 15 states have enacted mercury emission standards that include a continuous 

emission or other long-term monitoring requirement 

Page 26 GAO-10-47 Clean Air Act
 

Others using CEMS said that these systems are accurate at measuring 

mercury emissions and can be used to determine compliance with a 

stringent regulation. 

EPA, EPRI, the National Institute of Standards and Technology, and others 

are working collaboratively to approve protocols for quality assurance and 

control for mercury CEMS that will ensure the continued accuracy of the 

emissions data at the precise levels of many state rules. These 

organizations are in the final phase of their collaborative effort, and in July 

2009 they provided interim procedures to states that require use of 

mercury CEMS and other groups that use these systems. 

Data from commercially deployed sorbent injection systems show that 

substantial mercury emissions reductions have been achieved at a 

relatively low cost. Importantly, these results, along with test results from 

DOE’s comprehensive research and development program, suggest that 

similar reductions can likely be achieved at most coal-fired power plants 

in the United States. Other strategies, including blending coal and using 

other technologies, exist for the small number of plants with configuration 

types that were not able to achieve significant mercury emissions 

reductions with sorbent injection alone. 

Concluding 

Observations 

Whether power plants will install sorbent injection systems or pursue 

multipollutant control strategies will likely be driven by the broader 

regulatory context in which they operate, such as requirements for sulfur 

dioxide and nitrogen oxides reductions in addition to mercury, and the 

associated costs to comply with all pollution reduction requirements. 

Nonetheless, for many plants, sorbent injection systems appear to be a 

cost-effective technology for reducing mercury emissions. For other 

plants, sorbent injection may represent a relatively inexpensive bridging 

technology—that is, one that is available for immediate use to reduce only 

mercury emissions but that may be phased out—over time—with the 

addition of multipollutant controls, which are more costly. Moreover, 

some plants achieve substantial mercury emissions reductions without 

mercury-specific controls because their existing controls for other air 

pollutants also effectively reduce mercury emissions. In fact, while many 

power plants currently subject to mercury regulation have installed 

sorbent injection systems to achieve required reductions, about one-third 

of them are relying on existing pollution control devices to meet the 

requirements. 

Page 27 GAO-10-47 Clean Air Act
 

As EPA proceeds with its rulemaking process to regulate hazardous air 

pollutants from coal-fired power plants, including mercury, it may find 

that current data from commercially deployed sorbent injection systems 

and plants that achieve high co-benefit mercury reductions would support 

a more stringent mercury emission standard than was last proposed in 

2004. More significant mercury emissions reductions are actually being 

achieved by the current best performers than was the case in 1999 when 

such information was last collected—and similar results can likely be 

achieved by most plants across the country at relatively low cost. 

We provided a draft of this report to the Administrator, EPA, and the 

Secretary, DOE, for review and comment. EPA and DOE provided 

technical comments, which we incorporated as appropriate. 

Agency Comments 

and Our Evaluation 

We are sending copies of this report to interested congressional 

committees; the Administrator, the Environmental Protection Agency; the 

Secretary, Department of Energy; and other interested parties. The report 

is also available at no charge on the GAO Web site at http://www.gao.gov. 

If you or your staff have any questions about this report, please contact me 

at (202) 512-3841 or stephensonj@gao.gov. Contact points for our Offices 

of Congressional Relations and Public Affairs may be found on the last 

page of this report. GAO staff who made major contributions to this report 

are listed in appendix VI. 

Sincerely yours, 

John B. Stephenson 

Director, Natural Resources 

 and Environment 

Page 28 GAO-10-47 Clean Air Act
Appendix I: Objectives, Scope, and 

Methodology 

Page 29 GAO-10-47 

Appendix I: Objectives, Scope, and 

Methodology 

This appendix details the methods we used to examine (1) the mercury 

reductions that have been achieved by existing mercury control 

technologies and the extent to which they are being used at coal-fired 

power plants, (2) the costs associated with mercury control technologies 

currently in use, and (3) key issues the Environmental Protection Agency 

(EPA) faces in developing a new regulation for mercury emissions from 

coal-fired power plants. 

For the first two objectives, we identified coal-fired power plants subject 

to regulatory requirements to reduce mercury emissions by contacting 

clean air agencies in all 50 states. In so doing, we identified those states 

that had established laws or regulations—or had coal-fired power plants 

subject to consent decrees or construction permits—requiring reductions 

in mercury emissions. In states where laws or regulations are in effect, we 

asked clean air agency officials to identify which coal-fired power plants 

are meeting the requirements—either through “co-benefit” mercury 

removal achieved by plants’ existing air pollution control equipment or by 

operating sorbent injection systems. State clean air agency officials 

identified 14 coal-fired power plants that are currently operating sorbent 

injection systems to meet regulatory requirements to reduce mercury 

emissions.1

 For these plants, we developed a structured interview 

instrument to obtain information on the effectiveness of sorbent injection 

systems in reducing mercury emissions and the associated costs of the 

systems and the monitoring equipment.2

 We designed the instrument to 

also obtain information on the engineering challenges, if any, that plant 

officials experienced when operating the systems and the steps taken to 

mitigate such challenges. Staff involved in the evaluation and development 

of mercury control technologies within EPA’s Office of Research and 

 

1

Representatives of one plant that is operating a sorbent injection system to meet its state’s 

mercury reduction requirements did not participate in the structured interview, stating they 

could not participate until a compliance report had been completed and submitted to the 

state clean air agency. 

2

We obtained data on the capital and operating costs incurred to purchase, install, and 

operate sorbent injection systems and determined their potential impact on utility rates. To 

account for differences in timing, we adjusted these costs for inflation to represent 2008 

dollars. We then used, by boiler, the reported operating costs, total electrical output, and 

capital costs to determine a levelized cost per kilowatt hour. The levelized cost is an 

assessment of the anticipated costs of a sorbent injection system over its lifetime, including 

capital costs and operations and maintenance costs. We assumed a 20-year lifetime and a 

return on capital of 10 percent. We then compared these costs with DOE data on 2008 

average utility rates by state to determine the potential impact on utility rates, should the 

plants we interviewed pass on 100 percent of the costs to consumers. 

 Clean Air Act 
Appendix I: Objectives, Scope, and 

Methodology 

Development and DOE’s Office of Fossil Energy reviewed and commented 

on the instrument. We conducted the structured interview with 

representatives of 13 of the 14 coal-fired power plants and conducted site 

visits at 6 of them. We conducted structured interviews with officials at 

the following plants: 

• B.L. England, New Jersey 

• Brayton Point, Massachusetts 

• Bridgeport Harbor, Connecticut 

• Crawford, Illinois 

• Fisk, Illinois 

• Indian River Generating Station, Delaware 

• Mercer Generating Station, New Jersey 

• Presque Isle, Michigan 

• TS Power Plant, Nevada 

• Vermillion Power Station, Illinois 

• Walter Scott Jr. Energy Center, Iowa 

• Waukegan, Illinois 

• Weston, Wisconsin 

Furthermore, state clean air agency officials identified six coal-fired power 

plants that are aiming to meet mercury emission reduction requirements 

through operation of existing air pollution control equipment. From 

officials with these six plants, we obtained information on the 

effectiveness of the existing controls in reducing mercury emissions, as 

well as the reliability and costs of mercury emissions monitoring 

equipment. We spoke with officials at the following plants: 

• AES Thames, Connecticut 

• Carney’s Point, New Jersey 

• Deepwater, New Jersey 

Page 30 GAO-10-47 Clean Air Act
Appendix I: Objectives, Scope, and 

Methodology 

• EdgeMoor, Delaware 

• Logan, New Jersey 

• Salem Harbor, Massachusetts 

In addition to examining the effectiveness of commercially deployed 

sorbent injection systems, we examined field test results of sorbent 

injection systems—installed at operating power plants—conducted by 

DOE and the Electric Power Research Institute (EPRI) over the past 10 

years as part of DOE’s comprehensive mercury control technology test 

program. We relied primarily on data from the second and third phases of 

the DOE field testing program. The second phase of the DOE program 

focused heavily on chemically treated sorbents, which helped many boiler 

configurations achieve much higher mercury emission reductions than the 

same boiler configurations achieved under phase one tests, when 

untreated sorbents were used. The third phase of the DOE program 

focused on finding solutions to “balance-of-plant” impacts. To determine 

the percentage of coal-fired boilers nationwide that have air pollution 

control device configurations that are the same as those at power plants 

with commercially deployed sorbent injection systems or where field tests 

occurred, we used a draft version of EPA’s National Electricity and Energy 

Data System database that contains boiler level data, as of 2006, on coal 

type used, pollution control devices installed, and generating capacity.3

We conducted a reliability review of the data we received from coal-fired 

power plants, EPA, and DOE. Through our review, we determined that the 

data were sufficiently reliable for our purposes. Our assessment consisted 

of interviews with officials about the data systems and elements of data. 

We also corroborated the data with other sources, where possible. For 

example, we verified the information in structured interviews by obtaining 

compliance reports from state clean air agencies, where possible. Finally, 

we reviewed literature presented at the 2008 MEGA Symposium and the 

2009 Energy and Environment Conference on (1) strategies to overcome 

challenges that some plants have experienced with sorbent injection 

systems, such as sulfur trioxide interference, and (2) on emerging mercury 

control technologies, such as oxidation catalysts. 

 

3

We excluded boilers with generating capacity of less than 25 megawatts from our analysis 

because they would not be subject to a MACT regulation under the Clean Air Act. 

Page 31 GAO-10-47 Clean Air Act
Appendix I: Objectives, Scope, and 

Methodology 

For the third objective, we examined EPA’s requirements for establishing 

MACT standards under the Clean Air Act and recent court cases with 

implications for how EPA establishes such standards.4

 We interviewed 

EPA officials in the Clean Air Markets Division and Sector Policies and 

Programs Division regarding the agency’s plans for regulating mercury at 

power plants. To examine EPA’s process for identifying best performers, 

we obtained and analyzed EPA data on mercury emissions reductions 

from the agency’s 1999 information collection request. Using these data, 

we followed the steps EPA described in its proposed 2004 MACT 

rulemaking to calculate the average mercury emissions reductions 

achieved by the best performing 12 percent of boilers—the threshold for 

calculating a minimum MACT emissions standard under the Clean Air Act. 

We then used newer data—the data we obtained from commercially 

deployed sorbent injection systems and DOE and industry tests—and 

followed the same steps to calculate the average mercury emissions 

reductions achieved by the best performing 12 percent of these boilers. 

In addition, we examined EPA’s steps to resolve technical monitoring 

challenges, including how the agency develops quality control and 

assurance procedures for continuous emissions monitoring systems. We 

also obtained data from coal-fired power plants—operating 16 continuous 

emissions monitoring systems—on the reliability of the systems, including 

data on the number of times the systems were offline, the outcome of 

periodic system integrity checks, and the extent to which plant engineers 

believed the systems to accurately measure mercury emissions. We 

interviewed EPA’s technical experts in the Clean Air Markets Division. 

We conducted this performance audit from November 2008 through 

September 2009 in accordance with generally accepted government 

auditing standards. Those standards require that we plan and perform the 

audit to obtain sufficient, appropriate evidence to provide a reasonable 

basis for our findings and conclusions based on our audit objectives. We 

believe that the evidence obtained provides a reasonable basis for our 

findings and conclusions based on our audit objectives. 

 

4

We examined the following cases: National Lime Association v. EPA, 233 F.3d 625 (D.C. 

Cir. 2000); Cement Kiln Recycling Coal. v. EPA, 255 F.3d 855 (D.C. Cir. 2001); Sierra Club 

v. EPA, 479 F.3d 875 (D.C. Cir. 2007); Natural Resources Defense Council v. EPA, 489 F.3d 

1250 (D.C. Cir. 2007); Natural Resources Defense Council v. EPA, 489 F.3d 1364 (D.C. Cir. 

2007). 

Page 32 GAO-10-47 Clean Air Act
Appendix II: Emerging Technologies That May 

Reduce Mercury Emissions from Coal-Fired Appendix II: Emerging Technologies That Power Plants 

May Reduce Mercury Emissions from CoalFired Power Plants 

In addition to sorbent injection systems, DOE, EPRI, and others have 

developed and tested other technologies to reduce mercury emissions that 

show promise and may become commercially available in the future. 

These technologies are being developed to potentially lower the cost of 

mercury removal for some plants and enable others—those for which 

sorbent injection may be ineffective—to achieve significant mercury 

emission reductions. Such technologies include oxidation catalysts, which 

help convert elemental mercury into oxidized mercury that can be 

captured in particulate control devices; the MerCAPTM process, which 

involves installing metal plates with sorbents on them in the exhaust gas 

(instead of injecting sorbents); and low-temperature mercury capture, 

which involves lowering the temperature of the exhaust gas to enable 

mercury to bind more effectively to the unburned carbon in fly ash. 

Finally, novel technologies are being developed by entities such as the 

Western Research Institute.1

 The technologies the Western Research 

Institute is working on include those designed to remove mercury directly 

from coal before it is burned. Innovative techniques for mercury control 

could eventually replace or augment the more mature technologies 

discussed in this report, according to DOE. 

Oxidation catalysts. Oxidation catalysts are powdered chemicals injected 

into either the boiler or the boiler’s exhaust gas to help change elemental 

mercury into oxidized mercury—a form that is easier to capture in 

pollution control devices for sulfur dioxide and particulate matter. 

According to recent research, oxidation of elemental mercury, which is 

then collected in particulate matter control devices or absorbed across a 

wet scrubber system, has the potential to be a reliable and cost-effective 

mercury control strategy for some coal-fired power plants, especially 

those that must comply with sulfur dioxide emission requirements. 

According to DOE, examples of oxidation catalysts tested at operating 

power plants include the following: 

• URS Corporation tested oxidation catalysts at a plant that fires a blend of 

Texas lignite and subbituminous coals. Tests completed in April 2005 

showed that oxidation catalysts enabled the wet scrubber to achieve 

mercury reductions ranging from 76 percent to 87 percent, compared with 

only 36 percent reduction under baseline conditions. 

 

1

The Western Research Institute is a not-for-profit research organization involved in 

advanced energy systems, environmental technologies, and highway materials research. 

Page 33 GAO-10-47 Clean Air Act 
Appendix II: Emerging Technologies That May 

Reduce Mercury Emissions from Coal-Fired 

Power Plants 

• URS has also begun testing oxidation catalysts at a boiler firing low-sulfur 

eastern bituminous coal that is equipped with a cold-side electrostatic 

precipitator. According to DOE, the project represents the next logical 

advancement of the catalytic oxidation technology, and it will answer 

technical questions such how much catalyst is required to achieve high 

mercury oxidation percentages, what is the catalyst life, and what is the 

efficiency of mercury capture in wet scrubber systems using oxidation 

catalysts. 

MerCAPTM: Developed by EPRI, MerCAP is a process in which metal 

plates laced with carbon sorbents are positioned in a boiler’s exhaust gas 

stream to adsorb mercury. During two 6-month tests, MerCAP was used at 

a boiler equipped with a dry scrubber and a fabric filter and at another 

boiler equipped with a wet scrubber. After more than 250 days of 

continuous operation at one plant, mercury reduction averaged 30 percent 

to 35 percent across acid-treated MerCAP plates and 10 to 30 percent 

across the untreated plates. At the other plant, MerCAP achieved 15 

percent mercury reduction when a water wash system for the plates was 

installed, which helped prevent limestone slurry from the wet scrubber 

system from inhibiting mercury reduction. MerCAPTM is still in the 

research and development phase, and although these mercury reduction 

amounts appear relatively low, when engineers altered the spacing 

between the metal plates, mercury emission reductions increased to about 

60 percent in some cases. 

Low-temperature mercury capture process: The low temperature mercury 

capture process helps reduce mercury emissions by cooling the exhaust 

gas temperature to about 220° Fahrenheit, which promotes mercury 

adsorption to the unburned carbon inherent in fly ash. This process may 

have the ability to reduce mercury emissions by over 90 percent, as was 

recently shown by one company performing a limited scale test. 

Pilot testing of novel mercury control technology: The Western Research 

Institute is developing and evaluating the removal of mercury from coal 

prior to combustion. The institute developed a two-step process that 

involves first evaporating moisture in the coal and then heating the coal 

with inert gas. Pre-combustion mercury removal technology has been 

successful in removing 75 percent of mercury from subbituminous coal 

and 60 percent of mercury from lignite coal, but the technology has 

encountered difficulty when used with bituminous coal. By removing up to 

75 percent of mercury before combustion, less mercury remains in the 

exhaust gas for removal by pollution control devices. In addition, precombustion technology has other benefits: (1) removing the moisture from 

Page 34 GAO-10-47 Clean Air Act
Appendix II: Emerging Technologies That May 

Reduce Mercury Emissions from Coal-Fired 

Power Plants 

the coal increases the heat content of the coal for combustion purposes, 

which may reduce the amount of coal burned by the plant and increase 

efficiency by about 3 percent; (2) this process also helps to remove other 

trace metals; (3) the water that is removed from the coal during precombustion treatment can be recovered and re-used in plant operations. 

According to DOE, Western Research Institute testing has also shown that, 

for some coals, the amount of time the coal is exposed to heat affects the 

amount of mercury removed. For example, an increase of 8 minutes of 

“residence time” resulted in the removal of nearly 80 percent of mercury 

before combustion.2

DOE in-house development of novel control technologies: DOE recently 

patented three techniques that are now licensed and in commercial 

demonstration. First, the thief carbon process—which involves extracting 

carbon from the boiler and using it as sorbent to inject into the exhaust 

gas for mercury capture—may be a cost-effective alternative to sorbent 

injection systems for mercury removal from boilers’ exhaust gas. Thief 

carbon sorbents, for instance, range from $90 to $200 per ton according to 

DOE—less than 10 percent of the typical cost of sorbents used in sorbent 

injection systems. According to the Western Research Institute, which 

tested the thief carbon process at an operating power plant, mercury 

emission reductions were comparable to those achieved by commercially 

available sorbents. Second, DOE patented the photochemical oxidation 

process. This process introduces an ultraviolet light into the exhaust gas to 

help convert mercury to an oxidized form for collection in other pollution 

control devices.3

 Finally, DOE researchers have invented a new sorbent 

that works at elevated temperatures. The new sorbent, which is palladiumbased, removes mercury at temperatures above 500° Fahrenheit and, 

according to DOE, may improve the overall energy efficiency of the 

combustion process.4

 

2

During testing, the percentage of mercury removed from coal varied from 50 percent to 

almost 90 percent, depending on the amount of time the coal was exposed to heat and inert 

gas, according to DOE. 

3

Researchers at DOE’s National Energy Technology Laboratory received the 2005 Award 

for Excellence in Technology Transfer from the Federal Laboratory Consortium for the 

photochemical oxidation method. 

4

Researchers at DOE’s National Energy Technology Laboratory received the 2008 Award 

for Excellence in Technology Transfer for developing the palladium-based sorbent. 

Page 35 GAO-10-47 Clean Air Act
Appendix III: Summary of State Regulations 

Requiring Reductions in Mercury Emissions 

from Coal-Fired Power Plants 

Table 1 summarizes data about state regulations that require reductions in 

mercury emissions from coal-fired power plants, including compliance 

date, percent reduction required, and emission limit. This table represents 

the best available data on state regulations, which appear to be 

independent of rules that were adopted in accordance with the vacated 

Clean Air Mercury Rule as of August 2009. For states with percent 

reduction and emission limit provisions, plants generally may choose the 

format with which they will comply. 

Table 1: Summary of Key Provisions of State Regulations Requiring Mercury Emission Reductions Applicable to Existing or 

All Coal-Fired Power Plants 

State Compliance date Percent reduction Emission limit 

Continuous emission or 

other long-term 

monitoring requirement 

(some state requirements 

may rely on vacated 

portions of federal rule) 

ArizonaaDecember 31, 2013 90 0.0087 pounds/gigawatt-hour X 

Coloradoa July 1, 2014b 80 0.0174 pounds/gigawatt-hour 

January 1, 2018 90 0.0087 pounds/gigawatt-hour 

X 

ConnecticutaJuly 1, 2008 90 0.60 pounds/trillion BTUs 

DelawarecJanuary 1, 2009 80 1.0 pounds/trillion BTUs 

January 1, 2013 90 0.60 pounds/trillion BTUs 

X 

Georgia Each plant shall install 

certain types of air 

pollution control devices, 

at varying times, 

according to a 

legislatively prescribed 

schedule. 

Illinoisa, d July 1, 2009 90 0.0080 pounds/gigawatt-hour X 

Maryland January 1, 2010 80 No emission limit required 

January 1, 2013 90 No emission limit required 

X 

Massachusetts January 1, 2008 85 0.0075 pounds/gigawatt-hour 

October 1, 2012 95 0.0025 pounds/gigawatt-hour 

X 

MinnesotaaDecember 31, 2010e90 No emission limit required 

December 31, 2014f90 No emission limit required 

X 

MontanaaJanuary 1, 2010 No percent reduction 

required 

0.90 pounds/trillion BTUsgX 

New Hampshirea July 1, 2013 80 No emission limit required X 

New Mexico January 1, 2010/ 

January 1, 2018 

No percent reduction 

required 

Each plant has its own emission 

limit (in two phases) 

X 

New Jersey December 15, 2007 90 3 milligrams/megawatt-hour 

Appendix III: Summary of State Regulations 

Requiring Reductions in Mercury Emissions 

from Coal-Fired Power Plants 

Page 36 GAO-10-47 Clean Air Act 
Appendix III: Summary of State Regulations 

Requiring Reductions in Mercury Emissions 

from Coal-Fired Power Plants 

State Compliance date Percent reduction Emission limit 

Continuous emission or 

other long-term 

monitoring requirement 

(some state requirements 

may rely on vacated 

portions of federal rule) 

New York January 1, 2010h

No percent reduction 

required 

0.60 pounds/trillion BTUs X 

North CarolinaiDecember 31, 2013 No percent reduction 

required 

No emission limit required X 

OregonaJuly 1, 2012 90 0.60 pounds/trillion BTUs X 

UtahaDecember 31, 2012 90 0.65 pounds/trillion BTUs X 

Wisconsin January 1, 2010j40 No emission limit required 

January 1, 2015k90 0.0080 pounds/gigawatt-hour 

X 

Source: GAO analysis of state clean air agency data. 

a

Alternate standards may be applied under certain circumstances. 

b

Two plants in Colorado must comply with an 80 percent mercury emission reduction requirement 

beginning on January 1, 2012. 

c

Requirement applies to large plants. Plants are also subject to mass emission caps beginning in 

2009 and becoming more stringent in 2013. 

d

Through 2013, requirement applies to systems of plants and additional minimum requirements apply 

on a plant-by-plant basis; after 2013, requirement applies to all plants on a plant-by-plant basis. 

e

This compliance date applies to coal-fired boilers equipped with dry scrubbers for air emissions 

control. 

f

This compliance date applies to coal-fired boilers equipped with wet scrubbers for air emissions 

conrol. 

g

The Montana regulation established a separate standard for coal-fired boilers using lignite of 1.5 

pounds per gigawatt-hour. 

h

Between 2010 and 2015, 13 coal-fired power plants must reach a specific mercury emission limit 

prescribed by law. If a plant is not on that list, it must achieve an emission limit of 0.60 pounds per 

trillion BTUs. Beginning in 2015, all plants must achieve an emission limit of 0.60 pounds per trillion 

BTUs. 

i

North Carolina requires installation of technology that captures sulfur dioxide, nitrogen oxides, and 

mercury. 

j

Applies to four major utilities. 

k

Applies to large coal-fired power plants. Plants can take an additional six years to achieve 90% 

reduction if they choose additional nitrogen oxide and sulfur dioxide controls. Small coal-fired power 

plants must reduce their mercury emissions to that achieved by the Best Available Control 

Technology by January 1, 2015. 

Page 37 GAO-10-47 Clean Air Act
A

Unable

Reduc

Al

ppendix IV: Potential Solutions for Plants 

 to Achieve High Mercury Emissions 

tions Using Sorbent Injection Systems 

one 

Page 38 GAO-10-47 

Appendix IV: Potential Solutions for Plants 

Unable to Achieve High Mercury Emissions 

Reductions Using Sorbent Injection Systems 

Alone 

DOE tests show that some plants may not be able to achieve mercury 

emissions reductions of 90 percent or more with sorbent injections alone. 

Specifically, the tests identified three factors that can impact the 

effectiveness of sorbent injection systems: sulfur trioxide interference, 

using hot-side precipitators, and using lignite. These factors are discussed 

below, along with some promising solutions to the challenges they pose. 

Sulfur trioxide interference. High levels of sulfur trioxide gas may limit 

mercury emission reductions by preventing some mercury from binding to 

carbon sorbents. Using an alkali injection system in conjunction with 

sorbent injection can effectively lessen sulfur trioxide interference. 

Depending on the cause of the sulfur trioxide interference—which can 

stem from using a flue gas conditioning system, a selective catalytic 

reduction system, or high-sulfur bituminous coal—additional strategies 

may be available to ensure high mercury reductions: 

• Flue gas conditioning systems, used on 13 percent of boilers nationwide, 

improve the performance of electrostatic precipitators by injecting a 

conditioning agent, typically sulfur trioxide, into the flue gas to make the 

gas more conducive to capture in electrostatic precipitators. Mercury 

control technology vendors are working to develop alternative 

conditioning agents to improve the performance of electrostatic 

precipitators without jeopardizing mercury emission reductions using 

sorbent injection. 

• Selective catalytic reduction systems, common control devices for 

nitrogen oxides, are used by about 20 percent of boilers nationwide. 

Although selective catalytic reduction systems often improve mercury 

capture, in some instances these devices may lead to sulfur trioxide 

interference when sulfur in the coal is converted to sulfur trioxide gas. 

Newer selective catalytic reduction systems often have improved catalytic 

controls, which can minimize the conversion of sulfur to sulfur trioxide 

gas. 

• High-sulfur bituminous coal—defined as having a sulfur content of at least 

1.7 percent sulfur by weight—may also lead to sulfur trioxide interference 

in some cases. As many as 20 percent of boilers nationwide may use highsulfur coal, according to 2005 DOE data; however, the number of coal 

boilers using high-sulfur bituminous coal is likely to decline as more 

stringent sulfur dioxide regulations take effect. Plants can consider using 

alkali-based sorbents, such as Trona, which adsorb sulfur trioxide gas 

before it can interfere with the performance of sorbent injection systems. 

Plants that burn high-sulfur coal can also consider blending their fuel to 

 Clean Air Act 
Appendix IV: Potential Solutions for Plants 

Unable to Achieve High Mercury Emissions 

Reductions Using Sorbent Injection Systems 

Alone 

include some portion of low-sulfur coal. In addition, according to EPA, 

power companies are likely to install scrubbers for controlling sulfur 

dioxide at plants burning high-sulfur coal (for those boilers that do not 

already have them). Scrubbers also reduce mercury emissions as a cobenefit, so many such plants may use them instead of sorbent injection 

systems to achieve mercury emissions reductions. 

Hot-side electrostatic precipitators. Installed on 6 percent of boilers 

nationwide, these particulate matter control devices operate at very high 

temperatures, which reduces the amount of mercury binding to sorbents 

for collection in particulate matter control devices. However, at least two 

promising techniques for increasing mercury capture have been identified 

in tests and commercial deployments at configuration types with hot-side 

electrostatic precipitators. First, during DOE testing 70 percent mercury 

emission reductions were achieved with specialized heat-resistant 

sorbents. Moreover, one of the 25 boilers currently using a sorbent 

injection system has a hot-side electrostatic precipitator and uses a heatresistant sorbent. Although plant officials are not currently measuring 

mercury emissions for this boiler, the plant will soon be required to 

achieve mercury emission reductions equivalent to 90 percent.1

 Second, in 

another DOE test, three 90 megawatt boilers—each with a hot-side 

electrostatic precipitator—achieved more than 90 percent mercury 

emission reductions by installing a shared fabric filter in addition to a 

sorbent injection system, a system called TOXECONTM. According to plant 

officials, these three units, which are using this system to comply with a 

consent decree, achieved 94 percent mercury emission reductions during 

the third quarter of 2008, the most recent compliance reporting period 

during which the boiler was operating under normal conditions. 

Lignite. North Dakota and Texas lignite, the fuel source for roughly 3 

percent of boilers nationwide, have relatively high levels of elemental 

mercury—the most difficult form to capture. Four long-term DOE tests 

were conducted at coal units burning North Dakota lignite using 

chemically treated sorbents. Mercury emission reductions averaged 75 

percent across the tests. The best result was achieved at a 450 megawatt 

boiler with a fabric filter and a dry scrubber—mercury reductions of 92 

percent were achieved when chemically treated sorbents were used. In 

addition, two long-term tests were conducted at plants burning Texas 

lignite with a 30 percent blend of subbituminous coal. With coal blending, 

 

1

Plant officials did not provide us with mercury emission reduction data for this boiler. 

Page 39 GAO-10-47 Clean Air Act
Appendix IV: Potential Solutions for Plants 

Unable to Achieve High Mercury Emissions 

Reductions Using Sorbent Injection Systems 

Alone 

these boilers achieved average mercury emission reductions of 82 percent. 

Specifically, one boiler, with an electrostatic precipitator and a wet 

scrubber, achieved mercury reductions in excess of 90 percent when 

burning the blended fuel. The second boiler achieved 74 percent 

reductions in long-term testing. However, 90 percent was achieved in 

short-term tests using a higher sorbent injection rate. Although DOE 

conducted no tests on plants burning purely Texas lignite, one power 

company is currently conducting sorbent injection tests at a plant burning 

100 percent Texas lignite and is achieving promising results. In the most 

recent round of testing, this boiler achieved mercury emission reduction of 

82 percent using untreated carbon and a boiler additive in conjunction 

with the existing electrostatic precipitator and wet scrubber. 

Page 40 GAO-10-47 Clean Air Act
Appendix V: A

Install Sorbe

Monitoring

Fabr

verage Costs to Purchase and 

nt Injection Systems and 

 Equipment, with and without 

ic Filters, per Boiler 

Page 41 GAO-10-47 

Appendix V: Average Costs to Purchase and 

Install Sorbent Injection Systems and 

Monitoring Equipment, with and without 

Fabric Filters, per Boiler 

Table 2 summarizes information on average costs to purchase and install 

sorbent injection systems and monitoring equipment, with and without 

fabric filters. This table includes cost data for boilers with sorbent 

injection systems and fabric filters installed specifically for mercury 

emissions control. This table does not include cost data for the 5 boilers 

with sorbent injection systems and fabric filters that were installed largely 

to comply with requirements to control other forms of air pollution.1

Table 2: Detailed Average Costs to Purchase and Install Sorbent Injection Systems and Monitoring Equipment, with and 

without Fabric Filters, per Boiler 

2008 dollars 

Mercury control 

technology type 

Number of 

boilers using 

technology typea

Cost of sorbent 

injection system 

Cost of mercury 

emissions 

monitoring system 

Cost of 

consulting and 

engineering 

Cost of 

fabric filter Total 

Sorbent injection 

system alone 

14 $2,723,000b $560,000b $382,000b c $3,594,000d

Sorbent injection 

system with 

fabric filter to 

assist in mercury 

removal 

5 $1,335,000e$120,000f$1,444,000g$19,010,000h$15,786,000i

Source: GAO analysis of data from power plants operating sorbent injection systems. 

a

We identified 25 boilers using sorbent injection systems to reduce mercury emissions, for which 

power companies provided cost data on 24. Cost data for 19 of the 24 are provided in the table. We 

did not report costs in this table for the remaining 5 because much of the cost incurred for fabric filters 

in these cases is not related to mercury removal. See footnote. 

b

Of the 14 boilers that installed a sorbent injection system alone, cost data for only 12 boilers were 

provided in this category. 

c

Not applicable. 

d

Numbers do not add to total. Total capital cost data were provided for 14 boilers, but for only 12 in 

the other cost categories. 

e

Cost data were provided for two boilers in this category. The costs of the sorbent injection systems 

for the two boilers were $1,071,000 and $1,599,000. 

f

Cost data were provided for two boilers in this category. The costs of the monitoring systems for the 

two boilers were $107,000 and $160,000. 

g

Cost data were provided for three boilers in this category and were the same for all three boilers. h

Cost data were provided for two boilers in this category. The costs of the fabric filters were 

$15,255,000 and $22,765,000. 

i

Numbers do not add to total. Total capital cost data were provided for five boilers with fabric filters. 

 

1

For the five boilers where plant officials reported installing fabric filters along with sorbent 

injection systems largely to comply with requirements to control other forms of air pollution, 

the average reported capital cost for the two technologies was $105.9 million per boiler, 

ranging from $38.2 million to $156.2 million per boiler.1

 For these boilers, the capital costs 

result from requirements to control other pollutants, and we did not determine what portion 

of these costs would appropriately be allocated to the cost of reducing mercury emissions. 

 Clean Air Act 
Appendix VI: GAO Contact and Staff Appendix VI: GAO Contact and Staff Acknowledgments 

Acknowledgments 

John B. Stephenson, (202) 512-3841 or stephensonj@gao.gov 

In addition to the contact named above, Christine Fishkin, Assistant 

Director; Nathan Anderson; Mark Braza; Antoinette Capaccio; Nancy 

Crothers; Michael Derr; Philip Farah; Mick Ray; and Katy Trenholme made 

key contributions to this report. 

Page 42 GAO-10-47 Clean Air Act

GAO Contact 

Staff 

Acknowledgments 

(361014) 
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