Clean Air Act
Preliminary Observations on the Effectiveness and Costs of Mercury Control Technologies at Coal-Fired Power Plants Gao ID: GAO-09-860T July 9, 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 laws 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. This testimony provides preliminary data from GAO's ongoing work on (1) reductions achieved by mercury control technologies and the extent of their use at coal-fired power plants, (2) the cost of mercury control technologies in use at these plants, and (3) key issues EPA faces in regulating mercury emissions from power plants. GAO obtained data from power plants operating sorbent injection systems.
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 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, sorbent injection has not been tested on a small number of boiler configurations, some of which achieve high mercury removal with other pollution control devices. 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 $640,000. 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. For example, 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. Data from EPA's 1999 power plant survey do not reflect commercial deployments or DOE tests of sorbent injection systems and could support a standard well below what has recently been broadly achieved. Moreover, the time frame for proposing the standard may be compressed because of a pending lawsuit. On July 2, 2009, EPA announced that it planned to conduct an information collection request to update existing emission data, among other things, from power plants.
GAO-09-860T, Clean Air Act: Preliminary Observations on the Effectiveness and Costs of Mercury Control Technologies at Coal-Fired Power Plants
This is the accessible text file for GAO report number GAO-09-860T
entitled 'Clean Air Act: Preliminary Observations on the Effectiveness
and Costs of Mercury Control Technologies at Coal-Fired Power Plants'
which was released on July 9, 2009.
This text file was formatted by the U.S. Government Accountability
Office (GAO) to be accessible to users with visual impairments, as part
of a longer term project to improve GAO products' accessibility. Every
attempt has been made to maintain the structural and data integrity of
the original printed product. Accessibility features, such as text
descriptions of tables, consecutively numbered footnotes placed at the
end of the file, and the text of agency comment letters, are provided
but may not exactly duplicate the presentation or format of the printed
version. The portable document format (PDF) file is an exact electronic
replica of the printed version. We welcome your feedback. Please E-mail
your comments regarding the contents or accessibility features of this
document to Webmaster@gao.gov.
This is a work of the U.S. government and is not subject to copyright
protection in the United States. It may be reproduced and distributed
in its entirety without further permission from GAO. Because this work
may contain copyrighted images or other material, permission from the
copyright holder may be necessary if you wish to reproduce this
material separately.
Testimony:
Before the Subcommittee on Clean Air and Nuclear Safety, Committee on
Environment and Public Works, U.S. Senate:
United States Government Accountability Office:
GAO:
For Release on Delivery:
Expected at 10:00 a.m. EDT:
Thursday, July 9, 2009:
Clean Air Act:
Preliminary Observations on the Effectiveness and Costs of Mercury
Control Technologies at Coal-Fired Power Plants:
Statement of John B. Stephenson, Director:
Natural Resources and Environment:
GAO-09-860T:
GAO Highlights:
Highlights of GAO-09-860T, testimony before the 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 laws 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.
This testimony provides preliminary data from GAO‘s ongoing work on (1)
reductions achieved by mercury control technologies and the extent of
their use at coal-fired power plants, (2) the cost of mercury control
technologies in use at these plants, and (3) key issues EPA faces in
regulating mercury emissions from power plants. GAO obtained data from
power plants operating sorbent injection systems.
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 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, sorbent injection has not been tested on a small number of
boiler configurations, some of which achieve high mercury removal with
other pollution control devices.
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 $640,000. 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. For example, 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. Data from EPA‘s 1999 power plant survey do not reflect
commercial deployments or DOE tests of sorbent injection systems and
could support a standard well below what has recently been broadly
achieved. Moreover, the time frame for proposing the standard may be
compressed because of a pending lawsuit. On July 2, 2009, EPA announced
that it planned to conduct an information collection request to update
existing emission data, among other things, from power plants.
To view the full product, including the scope and methodology, click on
[hyperlink, http://www.gao.gov/products/GAO-09-860T]. For more
information, contact John Stephenson at (202) 512-3841 or
stephensonj@gao.gov.
[End of section]
Mr. Chairman and Members of the Subcommittee:
I am pleased to be here today to discuss our preliminary findings on
the effectiveness and costs of mercury control technologies, as well as
key issues the Environmental Protection Agency (EPA) faces in
developing a regulation for mercury emissions from coal-fired power
plants. 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]
EPA determined in 2000 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
establishing 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[Footnote 3]--which will require most existing coal-fired boilers
to reduce mercury emissions to at least the average level achieved by
the best performing 12 percent of boilers.[Footnote 4] While developing
MACT standards for hazardous air pollutants can take up to 3 years, EPA
may be required to promulgate these standards in a shorter period of
time to fulfill a negotiated settlement with litigants or comply with a
court decision. Specifically, EPA has until July 27, 2009, to settle or
respond to a lawsuit filed by several environmental groups requesting
an order requiring the EPA Administrator to promulgate final mercury
emissions standards for coal-fired power plants by a date certain no
later than December 2010.
The Department of Energy's (DOE) National Energy Technology Lab has
worked with EPA and the Electric Power Research Institute (EPRI), 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 on all coal types and at a variety of boiler
configurations at operating power plants.[Footnote 6] Testing at a
variety of boiler configurations using different types of coal 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.
Further, some power plants achieve mercury reductions as a "co-benefit"
of using controls designed to reduce other pollutants, such as sulfur
dioxide, nitrogen oxides, and particulate matter.
According to a 2008 DOE report describing 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. In recent years, at least 18 states have
passed laws or regulations requiring mercury emission reductions at
coal-fired power plants. The compliance time frames for the state
requirements vary, and four states--Connecticut, Delaware,
Massachusetts, and New Jersey--require reductions currently. 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.
We are currently responding to these objectives. To do this, we are
identifying 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 are obtaining data from plant managers and engineers
on the effectiveness of sorbent injection systems at reducing mercury
emissions and the costs of doing so. We are also obtaining information
on the engineering challenges plant officials have encountered in
installing and operating sorbent injection systems and actions taken to
mitigate them.[Footnote 7] In addition, we are examining DOE National
Energy Technology Lab, EPRI, and academic reports on the effectiveness
and costs of sorbent injection systems over time and reviewing
literature from recent technical conferences that addressed strategies
to overcome challenges that some plants have experienced with sorbent
injection systems. We are also reviewing 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 have met with EPA officials in the Office of Air and
Radiation regarding the agency's plans for regulating mercury at power
plants. EPA officials in the Offices of Air and Radiation and Research
and Development provided comments on the information provided in this
testimony, and we have made technical clarification where appropriate.
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. 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. In addition to mercury, coal combustion
releases other harmful air pollutants, including sulfur dioxide and
nitrogen oxides.[Footnote 8] EPA has regulated these pollutants since
1995 and 1996, respectively, through its program intended to control
acid rain. 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,
electrostatic precipitators and fabric filters 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]
The illustration depicts the following entities:
Coal supply;
Stack;
Fixed adsorption device;
Supplemental fabric filter;
Sorbent injection;
Scrubber fabric filter or electrostatic precipitator;
Selective catalytic reduction;
Boiler.
Source: Electric Power Research Institute.
[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. 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 mercury reduction costs--primarily 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 emission reductions.
Under its mercury testing program, DOE initially tested the
effectiveness of untreated carbon sorbents. On the basis of these
results, 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 9] DOE went on to
test the effectiveness of chemically treated sorbents--which can help
convert the more difficult-to-capture mercury common in lignite and
subbituminous coals to a more easily captured form--and achieved high
mercury reduction across all coal types.[Footnote 10] Finally, DOE
continued to test sorbent injection systems and to assess solutions to
impacts on plant devices, structures, or operations that may result
from operating these systems--called "balance-of-plant
impacts."[Footnote 11] In 2008, DOE reported that the high performance
observed during many of its field tests at a variety of configurations
has given coal-fired power plant operators the confidence to begin
deploying these technologies.
Bills have been introduced in the prior and current Congress addressing
mercury emissions from power plants. The bills have proposed specific
limits on mercury emissions, such as not less than 90 percent
reductions, and some have specified time frames for EPA to promulgate a
MACT regulation limiting mercury emissions from power plants. For
example, a bill introduced in this Congress would require EPA to
promulgate a MACT standard for mercury from coal-fired power plants
within a year of the bill's enactment. In addition, some bills
introduced the past few years--termed multipollutant bills--would have
regulated sulfur dioxide, nitrogen oxides, and carbon dioxide
emissions, in addition to mercury, from coal-fired power plants. Most
would have required a 90 percent reduction--or similarly stringent
limit--of mercury emissions, with the compliance deadlines varying from
2011 to 2015. One such bill currently before Congress would prohibit
existing coal-fired power plants from exceeding an emission limit of
0.6 pounds of mercury per trillion British thermal units (BTUs), a
standard measure of the mercury content in coal--equivalent to
approximately a 90 percent reduction--by January 2013.
Substantial Mercury Reductions Have Been Achieved Using Sorbent
Injection Technology at 14 Plants and in Many DOE Tests, but Some
Plants May Require Alternative Strategies to Achieve Comparable
Results:
The managers of 14 coal-fired power plants reported to us they
currently operate sorbent injection systems on 25 boilers to meet the
mercury emission reduction requirements of 4 states and several consent
decrees and construction permits.[Footnote 12] Preliminary data 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 have met or surpassed
their relevant regulatory mercury requirements, according to plant
managers. For example:
* A 164 megawatt bituminous-fired boiler, built in the 1960s and
operating a cold-side electrostatic precipitator and wet scrubber,
exceeds its 90 percent reduction requirement--achieving more than 95
percent mercury emission reductions 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,
achieves 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 achieves 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, 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 its national mercury regulation.[Footnote 14] 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 15] 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
16] 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 17]
As these examples of deployed and tested injection systems show, plants
are using chemically treated sorbents and sorbent enhancement
additives, as well as untreated sorbents. The DOE program initially
used untreated sorbents, but during the past 6 years, the focus shifted
to chemically treated sorbents and enhancement additives that were
being developed. These more recent tests 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 sorbent reduced mercury by an average of 55 percent during a
2003 DOE test at a subbituminous-fired boiler. Recent tests using
chemically treated sorbents and enhancement additives, however, have
resulted in average mercury reductions of 90 percent for boilers using
subbituminous coals.[Footnote 18] Similarly, recent tests on boilers
using lignite reduced mercury emissions by roughly 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. Specifically, regulated coal-fired power plants
typically use either electrostatic precipitators or fabric filters for
particulate matter control. The use of fabric filters--which are more
effective at mercury emission reductions than electrostatic
precipitators--at coal-fired power plants to reduce emissions of
particulate matter and other pollutants is increasing, but currently
less than 20 percent have them. Plant officials told us that they chose
to install fabric filters along with 10 of the sorbent injection
systems currently deployed to assist with mercury control--but that
some of the fabric filters were installed primarily to comply with
other air pollution control requirements. One plant manager, for
example, told us that the fabric filter installed at the plant helps
the sorbent injection system achieve higher levels of mercury emission
reductions but that the driving force behind the fabric filter
installation was to comply 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 19]
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.
Funding for the DOE testing program has been eliminated.[Footnote 20]
Regarding deployments to meet state requirements that will become
effective in the near future, the Institute of Clean Air Companies
reported that power plants had 121 sorbent injection systems on order
as of February 2009.[Footnote 21]
Importantly, mercury control technologies will not have to be installed
on a number of coal-fired boilers to meet mercury emission reduction
requirements because they already achieve high mercury reductions from
their existing pollution control devices.[Footnote 22] EPA data
indicate that about one-fourth of the industry may be currently
achieving mercury reductions of 90 percent or more as a co-benefit of
other pollution control devices.[Footnote 23] 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 24] One plant manager told us their plant
achieves 95 percent mercury reduction 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.
While sorbent injection technology has been shown to be effective with
all coal types and on boiler configurations 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. For example:
* Sulfur trioxide--which can form under certain operating conditions or
from using high sulfur bituminous coal--may limit mercury reductions
because it prevents mercury from 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, 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 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 83 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 I. 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, which EPA is currently developing, and
as some plants add air pollution control technologies required under
consent decrees. 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, such as selective catalytic
reduction devices for nitrogen oxides control and wet scrubbers for
sulfur dioxide control, which are often associated with high levels of
mercury emission reductions.
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 (see table 1).[Footnote 25] For these boilers, the
cost ranged from $1.2 to $6.2 million.[Footnote 26] 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--the estimates range from $32.6 to
$137.1 million.[Footnote 27] EPA's estimate of the average cost to
purchase and install a selective catalytic reduction device to control
nitrogen oxides is $66.1 million, ranging from $12.7 to $127.1 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, these boilers have uncommon configurations--ones that, as
discussed earlier, DOE tests showed would need additional control
devices to achieve high mercury reductions.[Footnote 28] Table 1 shows
the per-boiler capital costs of sorbent injections systems depending on
whether fabric filters are also installed primarily to reduce mercury
emissions.
Table 1: Average Cost to Purchase and Install Mercury Control
Technologies and Monitoring Equipment, per Boiler (2008 dollars):
Mercury control technology: Sorbent injection system;
Number of boilers[A]: 14;
Sorbent injection system: $2,723,277;
Mercury emissions monitoring system: $559,592;
Consulting and engineering: $381,535;
Fabric filter: [B];
Total: $3,594,023[C].
Mercury control technology: Sorbent injection system and fabric filter
to assist in mercury removal;
Number of boilers[A]: 5;
Sorbent injection system: $1,334,971;
Mercury emissions monitoring system: $119,544;
Consulting and engineering: $1,444,179;
Fabric filter: $19,009,986;
Total: $15,785,997[D].
Source: GAO analysis of data from power plants operating sorbent
injections systems.
[A] We identified 25 boilers with 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. Costs for the
remaining 5 are discussed further below because much of the cost
incurred for fabric filters in these cases is not related to mercury
removal.
[B] Not applicable.
[C] Numbers do not add to total. Total capital costs data were provided
for 14 boilers in this category, and these totals were used to provide
the average total capital cost. However, the average cost for the
individual cost categories include data on only 12 of the 14 boilers in
this category for which we were provided data.
[D] Numbers do not add to total. Total capital cost data were provided
for five boilers with fabric filters, and these totals were used to
provide the average total capital cost. However, the average cost for
the individual cost categories only include data on two of the five
boilers for which we were provided data.
[End of table]
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 both the sorbent injection system and fabric
filter was $105.9 million per boiler, ranging from $38.2 million to
$156.2 million per boiler.[Footnote 29] 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,
sulfur dioxide, and nitrogen oxides reductions, as well as EPA's
upcoming MACT regulation for coal-fired power plants that, according to
EPA officials, will regulate mercury as well as other air toxics
emitted from these plants.
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 emission reduction
required to meet regulatory requirements and to 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.[Footnote 30]
Plant engineers often adjust the injection rate of the sorbent to
capture more or less mercury--the more sorbent in the exhaust gas, for
example, 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. One state's consent decree, for example, requires plants to
operate their sorbent injection systems at an injection rate of 5
pounds per million actual cubic feet.[Footnote 31] Among the 19 boilers
for which plant managers provided operating 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--at an
average cost of $3.6 million--to meet mercury emissions requirements,
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 32]
Minnesota, for example, passed a law in 2006 allowing power companies
to seek regulatory approval for recovering the cost of anticipated
state-required reductions in mercury emissions in advance of the
regulatory schedule for rate increase requests. One utility 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 and $4.5, respectively, estimating a rate increase of 6 to 10
cents per month for customers of both plants.[Footnote 33]
For power companies operating in competitive markets where wholesale
electricity prices are not regulated, prices are largely determined by
supply and demand.[Footnote 34] 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
beneficial purposes, such 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. Specifically, some plant managers told us
that they have incurred additional costs because of lost fly ash sales
and additional costs to store fly ash that was previously either sold
or donated for beneficial 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
35]
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 of 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[Footnote 36] can decrease the amount of sorbent needed to
achieve desired levels of mercury control.
Some plant managers reported other balance-of-plant impacts associated
with sorbent injection systems, such as ductwork corrosion and small
fires in the particulate matter control devices. Plant engineers 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 the corrosion problem remains
unresolved but that it is primarily a minor engineering challenge not
impacting 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 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 mercury emissions limit. 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 could affect the
stringency of the MACT standard the agency proposes. In addition, the
format of the standard--whether it limits the mercury content of coal
being burned (an input standard) or of emissions from the stack (an
output standard)--may affect the stringency of the MACT standard the
agency proposes. Finally, the vacatur of the Clean Air Mercury Rule has
delayed for a number of years the continuous emissions monitoring that
would have started in 2009 at most coal-fired power plants.
Consequently, data on mercury emissions from coal-fired power plants
and the resolution of some technical issues with monitoring systems
have both been delayed.
Current Data from Commercial Deployments and DOE Tests Could Be Used 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 37]--is a critical
initial step in the development of a MACT standard for mercury. 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,[Footnote 38] EPA
established subcategories for the types of coal most commonly used by
power plants.[Footnote 39] 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 standard(s). 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.
Information collection requests are required when an agency collects
data from 10 or more nongovernmental parties. According to EPA
officials, this data collection process, which requires Office of
Management and Budget (OMB) review and approval, typically takes from 8
months to 1 year. EPA's schedule for issuing a proposed rule and a
final rule has not yet been established as the agency is currently in
negotiations with litigants about these time frames. In developing the
rule, EPA told us it could decide to use data from its 1999 information
collection request, data from commercial deployments and DOE tests to
augment its 1999 data, or implement a new information collection
request for mercury emissions. 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.
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 of the best performers, from which the standard is derived,
may be higher. Our analysis of EPA's 1999 data shows an average mercury
emission reduction of nearly 91 percent for the best performers.
[Footnote 40] 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 lower than the 1999 average emission
reduction of the best performers because of variability in mercury
emissions among the top performers, as discussed in more detail below.
Second, more current information that reflects mercury control
deployments and DOE tests may make the rationale EPA used to create
MACT standards for different subcategories less compelling to the
agency now. In its 2004 proposed MACT, using 1999 data, EPA proposed
separate standards for three subcategories of coal used at power
plants, largely because the co-benefit capture of mercury from
subbituminous-and lignite-fired boilers was substantially less than
from bituminous-fired boilers and resulted in higher average mercury
emissions for best performers using these coal types. Specifically, the
1999 data EPA used for its 2004 MACT proposal 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 using sorbent injection
systems with all coal types has achieved at least 90 percent mercury
emission reductions in most cases.
Finally, using more current emissions data in setting the mercury
standard, may mean that accounting for variability in emissions will
not have as significant an effect as it did in the 2004 proposed MACT-
-thereby lowering the MACT standard--because the current data 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
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. 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 41] Similarly, another manager
of a power plant operating a sorbent injection system told us the
amount of mercury in the coal they use "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 British thermal
units (BTUs) of heat input; output-based standards, on the other hand,
establish emission limits on the basis of pounds of mercury per
megawatt hour of electricity produced. These standards are referred to
as absolute limits. For the purposes of setting a standard, absolute
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).
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 42] 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, which 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.
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
43] 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 absolute limit. When used alone,
percent reduction standards can limit mercury emissions reductions. For
example, in one state, mercury reductions are measured against
"historical" coal-mercury content data, rather than current coal-
mercury content data. 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 high 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 limit actual mercury emission reductions. For example,
a plant burning coal with a mercury content of 15 pounds per trillion
BTUs that may choose between meeting an absolute 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 absolute limit. As discussed above, for the
purposes of setting a standard, a required absolute limit, which
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 equates to an emission limit of
approximately 0.7 pounds per trillion BTUs.[Footnote 44] 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, as Has Resolution of Emissions Monitoring Challenges:
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, the monitoring requirements are important to state agencies
with mercury reduction requirements. This association for state clean
air agencies 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. As a result, continuous monitoring of mercury
emissions from coal-fired power plants may continue to be delayed for
years.
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 a continuous emissions
monitoring systems (CEMS) certification process and approve protocols
for quality control and assurance. However, when the Clean Air Mercury
Rule was vacated, EPA put its CEMS certification process on hold.
Effective emissions monitoring assists facilities and regulators in
ensuring compliance with regulations and can also help facilities
identify ways to better understand the efficiency of their processes
and the efficiency of their operations. 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,
for example, is emitted at lower levels of concentration than other
pollutants and is measured in parts per billion--it is like "trying to
find a needle in a haystack," according to one plant engineer.
Consequently, mercury CEMS require more time to install and setup than
CEMS for other pollutants, and, according to plant engineers using
them, they involve a steeper learning curve in getting these relatively
complex monitoring systems up and running properly.
EPA plans to release interim quality control protocols for mercury CEMS
in July 2009. In our work, we found that these systems are installed on
16 boilers at power plants for monitoring operations or for compliance
reporting.[Footnote 45] Our preliminary data shows that for regulated
coal-fired boilers, plant managers reported that their mercury CEMS
were online from 62 percent to 99 percent of the time. When these
systems were offline, it was mainly because of failed system integrity
checks or routine parts failure. Some plant engineers told us that CEMS
are accurate at measuring mercury, but others said that these systems
are "several years away" from commercial readiness. However, according
to an EPA Clean Air Markets Division official, while some technical
monitoring issues remain, mercury CEMS are sufficiently reliable to
determine whether plants are complying with their relevant state
mercury emissions regulations.
Concluding Observations:
Data from commercially deployed sorbent injection systems show that
substantial mercury 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
substantial mercury emission 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 emit small
amounts of mercury without mercury-specific controls because their
existing controls for other air pollutants also effectively reduce
mercury emissions. In fact, while many power companies 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 will
likely find that current data on commercially deployed sorbent
injection systems and plants that achieve high mercury reductions from
their existing pollution control devices justify a more stringent
mercury emission standard than was last proposed in 2004. More
significant mercury emission 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.
Mr. Chairman, this concludes my prepared statement. We expect to
complete our ongoing work by October 2009. I would be happy to respond
to any questions that you or other Members of the Subcommittee may have
at this time.
GAO Contact and Staff Acknowledgments:
Contact points for our Offices of Congressional Relations and Public
Affairs may be found on the last page of this statement. For further
information about this testimony, please contact me at (202) 512-3841
or stephensonj@gao.gov. Key contributors to this statement were
Christine Fishkin (Assistant Director), Nathan Anderson, Mark Braza,
Antoinette Capaccio, Nancy Crothers, Philip Farah, Mick Ray, and Katy
Trenholme.
[End of section]
Appendix I: Potential Solutions to Challenges Associated with Achieving
Mercury Emissions Reductions of 90 Percent or More Using Sorbent
Injection Systems:
DOE tests show that some plants may not be able to achieve mercury
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 vendors are working to develop
alternative conditioning agents that could be used instead of sulfur
trioxide in the conditioning system to improve the performance of
electrostatic precipitators without jeopardizing mercury emission
reductions using sorbent injection.
* Selective catalytic reduction systems, a common control device 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 in the future 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 have or to install scrubbers for controlling sulfur dioxide
at plants burning high sulfur coal and are more likely to use the
scrubbers, rather than sorbent injection systems, to also reduce
mercury emissions.
Hot-side electrostatic precipitators. Installed on 6 percent of boilers
nationwide, these particulate matter control devices operate at very
high temperatures, which reduce the incidence of mercury binding to
sorbents for collection in particulate matter control devices. However,
at least two promising techniques have been identified in tests and
commercial deployments at configuration types with hot-side
electrostatic precipitators. First, 70 percent mercury emission
reductions were achieved with specialized heat-resistant sorbents
during DOE testing. 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 46] 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
currently use this system to comply with a consent decree and achieved
94 percent mercury emission reductions during the third quarter of
2008, the most recent compliance reporting period when 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. Overall, tests on boilers
using lignite reduced mercury emissions by roughly 80 percent, on
average. For example, 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 burning North Dakota
lignite and having 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 reduction 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 removal of 83 percent using
untreated carbon and a boiler additive in conjunction with the existing
electrostatic precipitator and wet scrubber.
[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.
[2] EPA's cap-and-trade program, known as the Clean Air Mercury Rule,
was established under Clean Air Act section 111 and was to establish a
cap on mercury emissions of 38 tons for 2010 and a second phase cap of
15 tons for 2018.
[3] According to EPA, its MACT will also cover the other hazardous air
pollutants listed in the Clean Air Act as well as emissions from oil-
fired power plants.
[4] 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.
[5] Mercury can be emitted in particulate, oxidized, or elemental 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] To date, we have visited seven plants using sorbent injection
systems, and we have interviewed plant managers at five other plants
that are meeting state mercury emissions requirements with existing
pollution control devices for other pollutants.
[8] Pollution controls that may be used at coal-fired power plants
include selective catalytic reduction to control nitrogen oxides, wet
or dry scrubbers to reduce sulfur dioxide, electrostatic precipitators
and fabric filters to control particulate matter, and sorbent injection
to reduce mercury emissions.
[9] 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).
[10] 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.
[11] Near the end of the research program, DOE continued field tests of
advanced mercury control technologies but aimed to achieve 90 percent
or greater mercury capture at low costs and to have them available for
commercial demonstration by 2010. According to a DOE official, federal
funding for DOE tests was eliminated before the final phase of tests
was completed.
[12] To date, we have interviewed managers at plants with 24 of the 25
sorbent injection systems. 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.
[13] This number reflects 9 boilers that were required to achieve 90
percent mercury emission reduction--which seven surpassed--and 10
boilers that were required to achieve reductions between 80 percent and
89 percent. Plant officials did not provide data on mercury reductions
achieved by sorbent injection systems for 5 boilers. Data for another
boiler are pending.
[14] 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.
[15] 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.
[16] We identified 56 field tests conducted by DOE during its mercury
control technology testing program. Of these tests, we examined mercury
reduction data of 41 tests conducted at power plants. The majority of
these tests were long-term tests (30 days or more). We did not include
mercury reduction data associated with the other 15 tests in our
analysis 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.
[17] The rate of sorbent injection varied between 1.0 lbs per million
actual cubic feet and 3.0 lbs per million actual cubic feet.
[18] 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.
[19] 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.
[20] The DOE mercury testing program has not received new funding since
fiscal year 2008.
[21] 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 beyond.
Georgia and North Carolina require installation of other pollution
control devices between 2008 and 2018 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.
[22] Nationwide, mercury reductions achieved as a co-benefit of other
pollution control devices reduces 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 capture.
[23] 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.
[24] Two of these plants 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.
[25] All reported cost data have been adjusted for inflation and are
reported in 2008 dollars.
[26] 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.
[27] EPA cost estimates reported in 2006 have been adjusted for
inflation and are reported in 2008 dollars.
[28] 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.
[29] 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.
[30] Sorbent costs ranged from $76,500 to $2.4 million.
[31] 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.
[32] 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 utility's request
and decide what costs are allowable under the relevant rules.
[33] The rate increase request will be submitted in conjunction with
requests for rate increases for the utility's other plants.
[34] If demand for electricity is elastic (that is, consumers have some
flexibility in adjusting the quantities that they purchase in response
to price changes), suppliers may not be able to raise prices in order
to fully recover the incremental cost of mercury emissions control. For
instance, if pollution controls add 5 percent to the cost of generating
electricity, the generating company may be able to raise its prices by
only 3 percent.
[35] Technologies to mitigate balance-of-plant costs associated with
fly ash are available. For example, one plant installed a polishing
fabric filter using TOXECONTM system, which preserves the plant's
ability to sell its fly ash. Another plant had previously installed as
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.
[36] 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.
[37] 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.
[38] Prior to finalizing the Clean Air Mercury Rule, EPA also proposed
a MACT standard for mercury emissions from coal-fired power plants. EPA
chose not to finalize the MACT rule.
[39] Under the Clean Air Act Amendments of 1990, EPA had 10 years from
the enactment of the amendments, or two 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 two years, or until 2002, to promulgate a
MACT standard.
[40] Our analysis of EPA's data includes the three primary coal ranks:
bituminous, subbituminous, and lignite.
[41] 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.
[42] 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.
[43] 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; and Arizona requires the more stringent option.
[44] 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.
[45] At least 14 states have enacted mercury emission standards that
include a mercury monitoring requirement. Six states require monitoring
to be conducted in accordance with the monitoring provisions of the
Clean Air Mercury Rule. Four states require sole use of CEMS. Three
states allow periodic stack tests--a method not approved under the
Clean Air Mercury Rule--until CEMS can be used at a later date. One
state requires use of CEMS or other method approved by the state
environmental protection agency.
[46] Plant officials did not provide us with mercury emission reduction
data for this boiler.
[End of section]
GAO's Mission:
The Government Accountability Office, the audit, evaluation and
investigative arm of Congress, exists to support Congress in meeting
its constitutional responsibilities and to help improve the performance
and accountability of the federal government for the American people.
GAO examines the use of public funds; evaluates federal programs and
policies; and provides analyses, recommendations, and other assistance
to help Congress make informed oversight, policy, and funding
decisions. GAO's commitment to good government is reflected in its core
values of accountability, integrity, and reliability.
Obtaining Copies of GAO Reports and Testimony:
The fastest and easiest way to obtain copies of GAO documents at no
cost is through GAO's Web site [hyperlink, http://www.gao.gov]. Each
weekday, GAO posts newly released reports, testimony, and
correspondence on its Web site. To have GAO e-mail you a list of newly
posted products every afternoon, go to [hyperlink, http://www.gao.gov]
and select "E-mail Updates."
Order by Phone:
The price of each GAO publication reflects GAO‘s actual cost of
production and distribution and depends on the number of pages in the
publication and whether the publication is printed in color or black and
white. Pricing and ordering information is posted on GAO‘s Web site,
[hyperlink, http://www.gao.gov/ordering.htm].
Place orders by calling (202) 512-6000, toll free (866) 801-7077, or
TDD (202) 512-2537.
Orders may be paid for using American Express, Discover Card,
MasterCard, Visa, check, or money order. Call for additional
information.
To Report Fraud, Waste, and Abuse in Federal Programs:
Contact:
Web site: [hyperlink, http://www.gao.gov/fraudnet/fraudnet.htm]:
E-mail: fraudnet@gao.gov:
Automated answering system: (800) 424-5454 or (202) 512-7470:
Congressional Relations:
Ralph Dawn, Managing Director, dawnr@gao.gov:
(202) 512-4400:
U.S. Government Accountability Office:
441 G Street NW, Room 7125:
Washington, D.C. 20548:
Public Affairs:
Chuck Young, Managing Director, youngc1@gao.gov:
(202) 512-4800:
U.S. Government Accountability Office:
441 G Street NW, Room 7149:
Washington, D.C. 20548:
