Clean Air Act: Mercury Control Technologies at Coal-Fired Power Plants Have Achieved Substantial Emissions Reductions
Published: 2009-10-08T00:00:00

Fast Facts:

Highlights:
section_title: Why GAO Did This Study
paragraphs: 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.
section_title: What GAO Found
paragraphs: 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.

section_title: Letter
paragraphs: 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. 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, 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. 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), 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. 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. 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. 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. 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. 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.
subsections: section_title: Background
paragraphs: 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. 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  ecipitators to control particulate  matter, and sorbent injection to reduce mercury emissions.  matter, and sorbent injection to reduce mercury emissions.
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 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.
section_title: Substantial Mercury Reductions Have Been Achieved Using Sorbent Injection Technology at 14 Plants and in Many DOE Tests
paragraphs: 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.
subsections: section_title: Sorbent Injection Systems Have Achieved Substantial Mercury Emissions Reductions at Power Plants
paragraphs: 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. Of note, all 25 boilers currently operating sorbent  injection systems nationwide have met or surpassed their relevant  regulatory mercury requirements, according to plant managers.  Following are a few examples:    A 164 megawatt 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, 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. 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. 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. 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.
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. 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. 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.  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. 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. As  many states’ compliance dates for mercury emission reduction near, the  Institute of Clean Air Companies reported that power plants had 121  sorbent injection systems on order as of February 2009. (App. III  provides data on state regulations requiring mercury emission reductions.)
section_title: Some Plants May Require Alternative Strategies to Achieve Significant Mercury Reductions
paragraphs: 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, 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, 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.
section_title: A Number of Plants Already Achieve Substantial Mercury Reductions with Existing Controls for Other Pollutants
paragraphs: 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. 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. 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. 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.
section_title: Mercury Control Technologies Are Often Relatively Inexpensive, but Costs Depend Largely on How Plants Comply with Requirements for Reducing Other Pollutants
paragraphs: 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. For these boilers, the cost ranged from $1.2 million to $6.2  million. 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. 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—ones that, as discussed earlier, DOE tests  showed would need additional control devices to achieve high mercury  reductions.
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. 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. 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.  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.
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. 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.
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.
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.
section_title: 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
paragraphs: 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.
subsections: section_title: 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
paragraphs: 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—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, 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, 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.
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. 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. 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. 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.
section_title: The Type of Standard EPA Chooses May Also Affect the Stringency of the Regulation
paragraphs: 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.
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.  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. 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. 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.
section_title: Continuous Monitoring of Mercury Emissions at Most Power Plants Has Been Delayed
paragraphs: 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. 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. 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. 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.
section_title: Concluding Observations
paragraphs: 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.
section_title: Agency Comments and Our Evaluation
paragraphs: 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 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.
section_title: Appendix I: Objectives, Scope, and Methodology
paragraphs: 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. 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. 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  Indian River Generating Station, Delaware    Mercer Generating Station, New Jersey    TS Power Plant, Nevada    Vermillion Power Station, Illinois    Walter Scott Jr. Energy Center, Iowa  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:    Carney’s Point, New Jersey    Deepwater, New Jersey  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.
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. 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.
section_title: Appendix II: Emerging Technologies That May Reduce Mercury Emissions from Coal- Fired Power Plants
paragraphs: 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. 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.
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. 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.
section_title: Appendix III: Summary of State Regulations Requiring Reductions in Mercury Emissions from Coal-Fired Power Plants
paragraphs: 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.
section_title: Appendix IV: Potential Solutions for Plants Unable to Achieve High Mercury Emissions Reductions Using Sorbent Injection Systems Alone
paragraphs: 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. 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.
section_title: Appendix V: Average Costs to Purchase and Install Sorbent Injection Systems and Monitoring Equipment, with and without Fabric Filters, per Boiler
paragraphs: 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.
section_title: Appendix VI: GAO Contact and Staff Acknowledgments
subsections: section_title: GAO Contact
section_title: Staff Acknowledgments
paragraphs: 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.