Clean Air Act
Mercury Control Technologies at Coal-Fired Power Plants Have Achieved Substantial Emissions Reductions Gao ID: GAO-10-47 October 8, 2009The 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.
GAO-10-47, Clean Air Act: Mercury Control Technologies at Coal-Fired Power Plants Have Achieved Substantial Emissions Reductions
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Report to the Chairman, Subcommittee on Clean Air and Nuclear Safety,
Committee on Environment and Public Works, U.S. Senate:
United States Government Accountability Office:
GAO:
October 2009:
Clean Air Act:
Mercury Control Technologies at Coal-Fired Power Plants Have Achieved
Substantial Emissions Reductions:
GAO-10-47:
GAO Highlights:
Highlights of GAO-10-47, a report to the Chairman, Subcommittee on
Clean Air and Nuclear Safety, Committee on Environment and Public
Works, U.S. Senate.
Why GAO Did This Study:
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.
What GAO Found:
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 [hyperlink, http://www.gao.gov/products/GAO-10-47] or key
components. For more information, contact John B. Stephenson at (202)
512-3841 or stephensonj@gao.gov.
[End of section]
Contents:
Letter:
Background:
Substantial Mercury Reductions Have Been Achieved Using Sorbent
Injection Technology at 14 Plants and in Many DOE Tests:
Mercury Control Technologies Are Often Relatively Inexpensive, but
Costs Depend Largely on How Plants Comply with Requirements for
Reducing Other Pollutants:
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:
Concluding Observations:
Agency Comments and Our Evaluation:
Appendix I: Objectives, Scope, and Methodology:
Appendix II: Emerging Technologies That May Reduce Mercury Emissions
from Coal-Fired Power Plants:
Appendix III: Summary of State Regulations Requiring Reductions in
Mercury Emissions from Coal-Fired Power Plants:
Appendix IV: Potential Solutions for Plants Unable to Achieve High
Mercury Emissions Reductions Using Sorbent Injection Systems Alone:
Appendix V: Average Costs to Purchase and Install Sorbent Injection
Systems and Monitoring Equipment, with and without Fabric Filters, per
Boiler:
Appendix VI: GAO Contact and Staff Acknowledgments:
Tables:
Table 1: Summary of Key Provisions of State Regulations Requiring
Mercury Emission Reductions Applicable to Existing or All Coal-Fired
Power Plants:
Table 2: Detailed Average Costs to Purchase and Install Sorbent
Injection Systems and Monitoring Equipment, with and without Fabric
Filters, per Boiler:
Figure:
Figure 1: Sample Layout of Air Pollution Controls, Including Sorbent
Injection to Control Mercury, at a Coal-Fired Power Plant:
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:
[End of section]
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.[Footnote 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,
[Footnote 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
12 percent of coal-fired boilers.[Footnote 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),
[Footnote 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.[Footnote 5] The DOE program has focused largely
on testing sorbent injection systems[Footnote 6] on all coal types and
at a variety of boiler configurations at operating power plants.
[Footnote 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 "co-benefit" 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
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.[Footnote 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.
[Footnote 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.
[Footnote 10] In addition, we examined DOE National 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.
Background:
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.
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, including the geographic location where it was mined and the
chemical variation within and among coal types.[Footnote 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:
[Refer to PDF for image: illustration]
This following items are labeled on the illustration:
Coal supply;
Stack;
Fixed adsorption device;
Supplemental fabric filter;
Scrubber;
Fabric filter or electrostatic precipitator;
Sorbent injection;
Selective catalytic reduction;
Boiler.
Source: GAO analysis of Electric Power Research Institute data.
[End of figure]
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.[Footnote 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.
Substantial Mercury Reductions Have Been Achieved Using Sorbent
Injection Technology at 14 Plants and in Many DOE Tests:
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.
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.[Footnote 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.[Footnote 14] Following are a few examples:
* A 164 megawatt[Footnote 15] 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.
* 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,[Footnote 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.[Footnote
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.[Footnote 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 development
programs are factored in, mercury reductions of at least 90 percent
have been achieved at boiler configurations used at nearly three-
fourths of coal-fired power boilers nationally.[Footnote 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.[Footnote 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.[Footnote 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 coals.[Footnote 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.
[Footnote 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.[Footnote 24] Fabric filters, which are more effective
at mercury emission reduction than electrostatic precipitators, are
increasingly being installed to reduce emissions of particulate matter
and other pollutants, but currently less than 20 percent of boilers
have them.
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.
[Footnote 25] As many states' compliance dates for mercury emission
reduction near,[Footnote 26] the Institute of Clean Air Companies
reported that power plants had 121 sorbent injection systems on order
as of February 2009.[Footnote 27] (Appendix 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,[Footnote
28] has relatively high levels of elemental mercury--the most difficult
form to capture. 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,[Footnote
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.
A Number of Plants Already Achieve Substantial Mercury Reductions with
Existing Controls for Other Pollutants:
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.[Footnote 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.[Footnote 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.[Footnote 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.
Mercury Control Technologies Are Often Relatively Inexpensive, but
Costs Depend Largely on How Plants Comply with Requirements for
Reducing Other Pollutants:
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 coal-
fired boilers that use sorbent injection systems alone to reduce
mercury emissions.[Footnote 33] For these boilers, the cost ranged from
$1.2 million to $6.2 million.[Footnote 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.
[Footnote 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.
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 configurations
[Footnote 36]--ones that, as discussed earlier, DOE tests showed would
need additional control devices to achieve high mercury reductions.
[Footnote 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.
[Footnote 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, 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.[Footnote 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.[Footnote 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 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.[Footnote 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.[Footnote 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.[Footnote 43]
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.[Footnote 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.
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:
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.
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 emissions[Footnote 45]--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,
[Footnote 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.
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,[Footnote 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.[Footnote 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.[Footnote 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 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 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.[Footnote 50] Along these lines, at least 15 states with
mercury emission limits require long-term 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.
[Footnote 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 coal-
fired 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 on the basis of pounds of mercury per megawatt hour of
electricity produced. These standards are referred to as emission
limits.[Footnote 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.[Footnote 53] However, input-based limits may allow
some power plants to emit more mercury per megawatt hour than output-
based limits. Under an output-based 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 reduction or emission limit--are greater.[Footnote
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.[Footnote 55] For bituminous coal, a 90 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.[Footnote 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.[Footnote 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
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.[Footnote 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. 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.
Concluding Observations:
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.
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.
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.
Agency Comments and Our Evaluation:
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.
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
[hyperlink, 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,
Signed by:
John B. Stephenson:
Director, Natural Resources and Environment:
[End of section]
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.[Footnote 59] 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.[Footnote
60] 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 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:
* 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.[Footnote 61]
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.
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.
[Footnote 62] 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.
[End of section]
Appendix II: Emerging Technologies That May Reduce Mercury Emissions
from Coal-Fired 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 MerCAP™ 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.[Footnote 63] 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.
* 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.
MerCAP™: 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. MerCAP™ 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, pre-
combustion technology has other benefits: (1) removing the moisture
from 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 pre-combustion 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.[Footnote 64]
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.[Footnote 65] Finally, DOE researchers have invented a new
sorbent that works at elevated temperatures. The new sorbent, which is
palladium-based, removes mercury at temperatures above 500° Fahrenheit
and, according to DOE, may improve the overall energy efficiency of the
combustion process.[Footnote 66]
[End of section]
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: Arizona[A];
Compliance date: December 31, 2013;
Percent reduction: 90;
Emission limit: 0.0087 pounds/gigawatt-hour;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Colorado[A];
Compliance date: July 1, 2014[B];
Percent reduction: 80; Emission limit: 0.0174 pounds/gigawatt-hour;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Colorado[A];
Compliance date: January 1, 2018;
Percent reduction: 90;
Emission limit: 0.0087 pounds/gigawatt-hour;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Connecticut[A];
Compliance date: July 1, 2008;
Percent reduction: 90;
Emission limit: 0.60 pounds/trillion BTUs;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Empty].
State: Delaware[C];
Compliance date: January 1, 2009;
Percent reduction: 80;
Emission limit: 1.0 pounds/trillion BTUs;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Delaware[C];
Compliance date: January 1, 2013;
Percent reduction: 90;
Emission limit: 0.60 pounds/trillion BTUs;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Georgia;
Compliance date: Each plant shall install certain types of air
pollution control devices, at varying times, according to a
legislatively prescribed schedule;
Percent reduction: [Empty];
Emission limit: [Empty];
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Empty].
State: Illinois[A, D];
Compliance date: July 1, 2009;
Percent reduction: 90;
Emission limit: 0.0080 pounds/gigawatt-hour;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Maryland;
Compliance date: January 1, 2010;
Percent reduction: 80;
Emission limit: No emission limit required;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Maryland;
Compliance date: January 1, 2013;
Percent reduction: 90;
Emission limit: No emission limit required;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Massachusetts;
Compliance date: January 1, 2008;
Percent reduction: 85;
Emission limit: 0.0075 pounds/gigawatt-hour;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Massachusetts;
Compliance date: October 1, 2012;
Percent reduction: 95;
Emission limit: 0.0025 pounds/gigawatt-hour;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Minnesota[A];
Compliance date: December 31, 2010[E];
Percent reduction: 90;
Emission limit: No emission limit required;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Minnesota[A];
Compliance date: December 31, 2014[F];
Percent reduction: 90;
Emission limit: No emission limit required;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Montana[A];
Compliance date: January 1, 2010;
Percent reduction: No percent reduction required;
Emission limit: 0.90 pounds/trillion BTUs[G];
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: New Hampshire[A];
Compliance date: July 1, 2013;
Percent reduction: 80;
Emission limit: No emission limit required;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: New Mexico;
Compliance date: January 1, 2010/January 1, 2018;
Percent reduction: No percent reduction required;
Emission limit: Each plant has its own emission limit (in two phases);
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: New Jersey;
Compliance date: December 15, 2007;
Percent reduction: 90;
Emission limit: 3 milligrams/megawatt-hour;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Empty].
State: New York;
Compliance date: January 1, 2010[H];
Percent reduction: No percent reduction required;
Emission limit: 0.60 pounds/trillion BTUs;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: North Carolina[I];
Compliance date: December 31, 2013;
Percent reduction: No percent reduction required;
Emission limit: No emission limit required;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Oregon[A];
Compliance date: July 1, 2012;
Percent reduction: 90;
Emission limit: 0.60 pounds/trillion BTUs;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Utah[A];
Compliance date: December 31, 2012;
Percent reduction: 90;
Emission limit: 0.65 pounds/trillion BTUs;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Wisconsin;
Compliance date: January 1, 2010[J];
Percent reduction: 40;
Emission limit: No emission limit required;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
State: Wisconsin;
Compliance date: January 1, 2015[K];
Percent reduction: 90;
Emission limit: 0.0080 pounds/gigawatt-hour;
Continuous emission or other long-term monitoring requirement (some
state requirements may rely on vacated portions of federal rule):
[Check].
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 control.
[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.
[End of table]
[End of section]
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 high-sulfur 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 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 co-benefit, 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 heat-resistant 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.[Footnote 67] 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, 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.
[End of section]
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.[Footnote 68]
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: Sorbent injection system alone;
Number of boilers using technology type[A]: 14;
Cost of sorbent injection system: $2,723,000[B];
Cost of mercury emissions monitoring system: $560,000[B];
Cost of consulting and engineering: $382,000[B];
Cost of fabric filter: [C];
Total: $3,594,000[D].
Mercury control technology type: Sorbent injection system with fabric
filter to assist in mercury removal;
Number of boilers using technology type[A]: 5;
Cost of sorbent injection system: $1,335,000[E];
Cost of mercury emissions monitoring system: $120,000[F];
Cost of consulting and engineering: $1,444,000[G];
Cost of fabric filter: $19,010,000[H];
Total: $15,786,000[I].
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.
[End of table]
[End of section]
Appendix VI: GAO Contact and Staff Acknowledgments:
GAO Contact:
John B. Stephenson, (202) 512-3841 or stephensonj@gao.gov:
Staff Acknowledgments:
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.
[End of section]
Footnotes:
[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.
[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.
[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.
[10] We 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.
[11] Coal 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.
[12] DOE'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.
[13] This 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.
[14] Data 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.
[15] A 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.
[16] As 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.
[17] For 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.
[18] We 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.
[19] We 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.
[20] The rate of sorbent injection varied between 1.0 pounds per
million actual cubic feet and 3.0 pounds per million actual cubic feet.
[21] DOE injected sorbents that were treated with halogens such as
chlorine or bromine, which help convert mercury from an elemental form
into an oxidized form.
[22] GAO, Clean Air Act: Emerging Mercury Control Technologies Have
Shown Promising Results, but Data on Long-Term Performance Are Limited,
[hyperlink, http://www.gao.gov/products/GAO-05-612] (Washington, D.C.:
May 31, 2005).
[23] On 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.
[24] Properties 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.
[25] The DOE mercury testing program has not received new funding since
fiscal year 2008.
[26] Illinois, 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.
[27] The Institute of Clean Air Companies is the trade association of
companies that supply air pollution control and monitoring technology.
[28] As noted earlier, the lignite burned by all coal-fired power
plants represents 8 percent of all coal burned in the United States.
[29] The 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.
[30] Nationwide, 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.
[31] This 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.
[32] Two 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.
[33] Cost data are reported in 2008 dollars.
[34] The 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.
[35] EPA's 2006 cost estimates are reported in 2008 dollars.
[36] Three 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.
[37] The 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.
[38] The 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.
[39] Pounds per million actual cubic feet is the standard metric for
measuring the rate at which sorbent is injected into a boiler's exhaust
gas.
[40] Under 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.
[41] The rate increase request will be submitted in conjunction with
requests for rate increases for the utility's other plants.
[42] Technologies to mitigate balance-of-plant costs associated with
fly ash are available. For example, one plant installed a polishing
fabric filter using TOXECON™ 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.
[43] DOE'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.
[44] An 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.
[45] This is how section 112 of the Clean Air Act, as amended, defines
best performers for the largest categories of sources when establishing
MACT standards.
[46] Prior 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.
[47] EPA 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.
[48] Under 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.
[49] Our analysis of EPA's data includes the three primary coal types:
bituminous, subbituminous, and lignite.
[50] According 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.
[51] The requirement for this plant, which the plant manager reported
it has met, is for a 90 percent reduction averaged over a 3-month
period.
[52] For 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).
[53] The 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.
[54] Colorado, 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.
[55] Presentation 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.
[56] The 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.
[57] Portland 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.
[58] At least 15 states have enacted mercury emission standards that
include a continuous emission or other long-term monitoring requirement
[59] 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.
[60] 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.
[61] 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.
[62] 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).
[63] The Western Research Institute is a not-for-profit research
organization involved in advanced energy systems, environmental
technologies, and highway materials research.
[64] 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.
[65] 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.
[66] Researchers at DOE's National Energy Technology Laboratory
received the 2008 Award for Excellence in Technology Transfer for
developing the palladium-based sorbent.
[67] Plant officials did not provide us with mercury emission reduction
data for this boiler.
[68] 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.
[69] 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.
[End of section]
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