Clean Air Act: Preliminary Observations on the Effectiveness and Costs of Mercury Control Technologies at Coal-Fired Power Plants
Published: 2009-07-09T00:00:00

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 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.
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 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.

section_title: Letter
paragraphs: 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.
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, 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—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. 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. 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. 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. 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.
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. 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. 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.
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. 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.  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.”  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 pla nt  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.
section_title: 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
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  emission reduction requirements of 4 states and several consent decrees  and construction permits. Preliminary data 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 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. 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 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. 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.
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. 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.
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. 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. 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 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.
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 (see table 1). For these boilers, the cost ranged from $1.2 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—the estimates  range from $32.6 to $137.1 million. 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.  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.
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. 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.
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. 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.  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.
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 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.
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 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.
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 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.
subsections: section_title: 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
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 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, 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 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. 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.  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.
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 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.  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. 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. 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, as Has Resolution of Emissions Monitoring Challenges
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, 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. 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.
section_title: Concluding Observations
paragraphs: 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.
section_title: GAO Contact and Staff Acknowledgments
paragraphs: 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.
section_title: Appendix I: Potential Solutions to Challenges Associated with Achieving Mercury Emissions Reductions of 90 Percent or More Using Sorbent Injection Systems
paragraphs: 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. 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.
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