EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5472) noted that its commitment to environmental stewardship led it to participate as a partner with Sorbent Technologies Corporation and others in a U. S. Department of Energy ( DOE) co funded project to test an advanced halogenated activated carbon. The test objective was to determine the Hg removal performance and relative costs of sorbent injection for advanced sorbent materials in a large scale field trial. One of the sites tested was the commenter's St. Clair Power Plant Unit 1 ( STCPP U1) with a cold side electrostatic precipitator ( ESP) using subbituminous coal, or a blend of subbituminous and bituminous coal. STCPP U1 is nominally 150 MW, but a completely split duct configuration allows testing to be completed on half of the flue gas stream, without resorting to the uncertainty of slipstream configurations.

The commenter offered STCPP U1 to testing for several reasons. The majority of Hg related testing done previously was completed on units burning either bituminous, subbituminous, or lignite coals. Since most of the commenter's units burn a blend of bituminous and subbituminous coals, it was interested in improving the understanding of the effect of these blends on the ability to control Hg emissions. STCPP U1 an effectively burn 100 percent subbituminous and blends up to 70 percent subbituminous and 30 percent bituminous. This unit could provide the opportunity to test either 100 percent subbituminous or the blended fuel.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005). 9 43 Comment:

One commenter ( OAR 2002 0056 5472) was concerned about the ability of normal sized ESPs to remove the additional particulate loading resulting from injection of sorbents. STCPP U1 is equipped with a 700 SCA ( specific collection area) ESP, which is about three times larger than the average sized ESP. Not knowing how much sorbent would be injected or the ability of the ESP to remove particulate under the injection conditions, this unit's ESP could be expected to handle any possible additional loading. This means that particulate removal would not be expected to limit testing for Hg removal even at higher injection rates.

In addition, the commenter believed that this testing opportunity would provide some insight into the balance of plant impacts it might expect if using sorbent injection as an emission control technology at this or other coal fired boilers.

Baseline testing and parametric testing demonstrated that B* PACTM could be expected to provide the best results of the sorbents tested, even at a lower injection rate of 3 lbs/ Macf. The final step of this test was to inject B* PAC at 3 lbs/ Macf for a 30 day period, while the boiler operated under normal ( varying) load conditions. Over the 30 day test period, the sorbent injection equipment constructed for the test was able to adequately follow the boiler load swings and maintain a consistent injection rate. The Hg removal rate averaged 93 percent over the 30 day period. The commenter reported that these promising results encourage additional testing for longer duration under more challenging conditions.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5472) noted that longer testing periods ( minimally one year) are required to hopefully identify any unintended and unanticipated consequences resulting from the operation of this and other technologies. Cumulative effects on collection equipment or other downstream equipment not identified in a 30 day test could be identified after longer term operation, as has been experienced with other control technologies. Identification of an unanticipated consequence after a commitment to a particular technology puts the electric supply at risk. The commenter believes that this is an unacceptable result of rushing a little tested technology into operation. A technology must be tested under various fuels and operating conditions to validate commercial viability. One 30 day test cannot provide the operational assurances necessary to ensure the performance and reliability required of electric generating units.

The commenter reported that the particulate control equipment was never expected to be a challenge or represent a normal operation during this test. This unit was chosen, in part, because of an equipment configuration that would eliminate particulate collection as a concern. 9 44 The ESPs on STCPP U1, however, approach 3 times the collection capability of a normal electric generating unit ESP. Additional testing is required to demonstrate what operational impacts might be expected on smaller ESPs (< 250 SCA) and what equipment and operational modifications might be required for long term operation of sorbent injection technologies.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5472) reported that much of the industry's fly ash is currently used productively for commercial uses. The B PAC sorbent used in this test makes fly ash unusable as a concrete additive, which necessitates landfi1l disposal of a previously useful byproduct. There is a need to develop and then conduct similar tests with " concrete friendly" sorbents which will keep these productive uses for fly ash viable.

Because of the short term nature of this test, there is a still need to further investigate equipment risks, such as potential corrosion in ductwork and gas handling equipment and the possibility of contamination issues in areas of fly ash hideout.

The ultimate fate of halogens, including bromine, in the flue gas stream is a continuing area of concern. Any concerns about the possible formation of toxic byproducts in flue gas stream must be thoroughly investigated and dispelled before this technology can be widely deployed. There have only been preliminary tests conducted in coal fired electric generating boiler flue gas streams, and this issue requires significantly further research.

In addition to these specific comments offered related to the company's experience testing Brominated activated carbon injection, the commenter also supports the comments submitted by the Edison Electric Institute ( EEI), the Utility Air Regulated Group ( UARG), and the Electric Power Research Institute ( EPRI).

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5496) is an advocate of public policies that are protective of public health and is prepared to make reasonable additional reductions in power plant Hg emissions. This commenter has been a strong advocate for the Minnesota Mercury 9 45 Contamination Reduction Initiative and achieved about 17 percent reduction in Hg stack emissions in 2000 compared to 1990 levels through optimizing fuel sourcing and plant operation. The commenter's coal units are also over 70 percent wet scrubbed for particulate and sulfur dioxide removal, which combined with other voluntary Hg reduction activities has reduced base line emissions relative to 1990 and compared to other utility units. Consequently, an equitable allocation of Hg reduction requirement stringency, either through unit specific requirements or cap and trade program allowance allocation methodology is important for assuring reasonable credit for early action. The commenter supports an equitable cap and trade approach as the preferred option for regulating electric power sector Hg emissions, as that provides the most flexibility for achieving compliance using new and often unproven technology.

Response:

EPA is finalizing a cap and trade approach under section 111. See final rule preamble for rationale.

Comment:

One commenter ( OAR 2002 0056 5496) notes that the technology EPA and other modelers have presumed to be effective for achieving high percentages of Hg removal in their Integrated Planning Model involves use of activated carbon injection followed by particulate collection. However, over 70 percent of this commenter's coal generation is operated with wet scrubbers, providing for particulate removal while delivering sulfur dioxide emission reductions. The commenter has injected activated carbon into its wet scrubbers and found only small improvements in Hg removal ( zero to 30 percent) over the realm of typical activated carbon injection rates. The wet scrubbers create a near saturated flue gas with entrained water droplets, making operation with a fabric filter downstream of the scrubber impractical due to filter plugging. The flue gas temperature upstream of the wet scrubbers is too high for reliable filter operation. Consequently, units operating with existing wet scrubbers are not amenable to retrofit of activated carbon and fabric filter technology.

Response:

EPA is finalizing a cap and trade approach under section 111. See final rule preamble for rationale. Under a cap and trade approach the commenter will have flexibility in its compliance options including buying allowances. EPA also notes that ACI with a pulse jet fabric may be installed upstream of wet scrubber. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5496) notes that IPM modeling presumes uniform control costs and percent Hg reductions for coal units that are targeted to retrofit activated carbon injection and fabric filters, without sufficient consideration of unit size ( economy of scale), coal type ( concentration and species of Hg emitted) or current emission rates. Incremental 9 46 reductions in the targeted Hg emissions cap should be expected to give increasingly higher Hg reduction costs in terms of dollars per pound Hg removal when performing modeling. For example, the Table 1   Summary of CCAP Power Sector Modeling ( Federal Register Volume 69 No 230 page 69868) presents a linear incremental cost as the Hg cap is reduced from 15 tons to 7.5 tons over a regime of affected units that would be expected to exhibit higher costs due to economy of scale or lower Hg content coal. Linear consideration of unit control retrofit costs affirms the IPM does not adequately address incremental control costs.

Response:

The commenter is incorrect that IPM modeling uses uniform control costs and percent Hg reductions. Hg specific control costs ( ACI) vary by size of the unit and coal type burned. Hg removal varies by coal type and control type. In addition scrubbers and SCR also consider economies of scale. See IPM documentation in docket for further discussion of control cost and performance assumptions.

Comment:

One commenter ( OAR 2002 0056 5561) stated that the demand growth assumptions used in our sensitivity analyses, published in the NODA, appeared to be reasonable. The average growth rate of 1.8 percent per year was identical to the latest demand forecast published in Energy Information Administration's 2005 Annual Energy Outlook. Demand forecasts used by other analysts such as Cinergy ( 2.3 percent per year) may be too high. The natural gas price assumptions used in the commenter's sensitivity analyses, on the other hand, may be somewhat low. Use of higher gas price assumptions would be expected to raise system costs in both the base and policy cases. It was not clear what effect higher gas prices would have on the incremental cost of the various Hg policy scenarios that were investigated. However, the sensitivity runs the commenter evaluated with higher gas prices and load growth assumptions resulted in very modest increases in system costs ( roughly 1 percent) for the increasingly tighter second Phase Hg caps over the system cost increases under increasingly stringent scenarios using our original lower gas price and load growth assumptions. ( See Document ID No. OAR 2002 0056 xxxx submitted on June 29, 2004 for details on the Air Quality Dialogue analyses.)

Response:

As discussed in EPA's IPM documentation, EPA uses its natural gas prices and demand forecasts different from those of EIA. EPA has performed a sensitivity analysis examining the impact of uses EIA natural gas prices and electric growth projections. See chapter 7 of final rule CAMR RIA.

Comment:

One commenter ( OAR 2002 0056 5521) provided the following information:

Limestone Forced Oxidation ( LFSO) 9 47 This cost estimate was for the cost of installing, operating, and maintaining LFSO only.

Merrimack Station Cost Estimate ( 1995 Dollars) MK 1 ( 113 MWe) MK2 ( 320 MWe)

Capital $ 48/ kW ($ 54,240,000)* $ 250/ kW ($ 80,000,000)* Fixed O& M $ 16.0/ kW/ yr ($ 1,808,000/ yr) $ 10.0/ kW yr ($ 3,200,000/ yr) Variable O& M 1.1 mills/ kWh ( $ 868,733/ yr) 1.1 mills/ kWh ($ 2,527,360/ yr) Total Annual** 10.26 mills/ kWh ($ 8,100,733/ yr) 5.98 mills/ kWh ($ 13,727,360/ yr) * This capital cost estimate included the costs for a reagent feed system, a wet SO2 removal system, a flue gas handling system, a waste/ by product handling system and support equipment ( exhaust stack) but didn't include a cost estimate for replacement of primary fans if required. ** Used 2002 MWh to estimate cost in mills/ kWh.

Powdered Activated Carbon Injection This cost estimate was for the cost of installing, operating, and maintaining the Powdered Activated Carbon Injection only. Costs were calculated using U. S. EPA's and U. S. DOE's Mercury Control Performance and Cost Model ( MCPCM), September 30, 2000.

Merrimack Station Cost Estimate ( 1999 Dollars) MK 1 ( 113 MWe) MK2 ( 320 MWe)

Capital $ 8.49/ kW*** ($ 959,370) $ 5.97/ kW*** ($ 1,910,400)

Fixed O& M $ 3.64/ kW/ yr ($ 411,320/ yr) $ 1.64/ kW/ yr ($ 524,800/ yr)

Variable O& M 1.10 mills/ kWh ($ 868,733/ yr) 1.10 mills/ kWh ($ 2,527,360/ yr)

Total Annual** 1.74 mills/ kWh ($ 1,375,990/ yr) 1.41 mills/ kWh ($ 3,243,200/ yr)

** Used 2002 MWh to estimate cost in mills/ kWh. *** Total Control Capital Costs including process equipment, field materials, field labor, indirect field costs, engineering and home office overhead/ fees, process contingency, project contingency, and general facilities.

Powdered Activated Carbon Injection & Spray Cooling This cost estimate was for the cost of installing, operating, and maintaining the Powdered Activated Carbon Injection and Spray Cooling system only. Costs were calculated using U. S. EPA's and U. S. DOE's Mercury Control Performance and Cost Model ( MCPCM), September 9 48 30,2000.

Merrimack Station Cost Estimate ( 1999 Dollars) MK 1 ( 113 Mwe) MK2 ( 320 MWe)

Capital $ 24.63/ kW***($ 2,783,190) $ 17.20/ kW***($ 5,504,000)

Fixed O& M $ 5.58/ kW/ yr ($ 630,540/ yr) $ 2.99/ kW/ yr ($ 956,800/ yr)

Variable O& M 1.13 mills/ kWh ($ 900,323/ yr) 1.14 mills/ kWh ($ 2,619,264/ yr)

Total Annual** 2.29 mills/ kWh ($ 1,809,182/ yr) 1.80 mills/ kWh ($ 4,126,464/ yr)

** Used 2002 MWh to estimate cost in mills/ kWh. *** Total Control Capital Costs including process equipment, field materials, field labor, indirect field costs, engineering and home office overhead/ fees, process contingency, project contingency, and general facilities.

Powdered Activated Carbon Injection & Pulse Jet Fabric Filter This cost estimate is for the cost of installing, operating, and maintaining the Powdered Activated Carbon Injection, and Pulse Jet Fabric Filter system only. Costs were calculated using U. S. EPA's and U. S. DOE's Mercury Control Performance and Cost Model ( MCPCM), September 30, 2000.

Merrimack Station Cost Estimate ( 1999 Dollars) MK 1 ( 113 Mwe) MK2 ( 320 MWe)

Capital $ 50.38/ kW*** ($ 5,692,940) $ 40.00/ kW*** ($ 12,800,000)

Fixed O& M $ 8.68/ kW/ yr ($ 980,840/ yr) $ 5.73/ kW/ yr ($ 1,833,600/ yr)

Variable O& M 1.15 mills/ kWh ($ 908,221/ yr) 1.15 mills/ kWh ($ 2,642,240/ yr)

Total Annual** 3.11 mills/ kWh ($ 2,458,355/ yr) 2.51 mills/ kWh ($ 5,755,840/ yr)

** Used 2002 MWh to estimate cost in mills/ kWh. *** Total Control Capital Costs including process equipment, field materials, field labor, indirect field costs, engineering and home office overhead/ fees, process contingency, project contingency, and general facilities.

Powdered Activated Carbon Injection, Spray Cooling & Pulse Jet Fabric Filter 9 49 This cost estimate was for the cost of installing, operating, and maintaining the Powdered Activated Carbon Injection, Spray Cooling, and Pulse Jet Fabric Filter system only. Costs were calculated using U. S. EPA's and U. S. DOE's Mercury Control Performance and Cost Model ( MCPCM), September 30, 2000.

Merrimack Station Cost Estimate ( 1999 Dollars) MK 1 ( 113 Mwe) MK2 ( 320 MWe)

Capital $ 66.53/ kW*** ($ 7,517,850) $ 51.23/ kW*** ($ 16,393,600)

Fixed O& M $ 10.62/ kW/ yr ($ 1,200,060/ yr) $ 7.08/ kW/ yr ($ 2,265,600/ yr)

Variable O& M 1.19 mills/ kWh ($ 939,811/ yr) 1.19 mills/ kWh ($ 2,734,144/ yr)

Total Annual** 3.66 mills/ kWh ($ 2,891,660/ yr) 2.89 mills/ kWh ($ 6,639,104/ yr)

** Used 2002 MWh to estimate cost in mills/ kWh. *** Total Control Capital Costs including process equipment, field materials, field labor, indirect field costs, engineering & home office overhead/ fees, process contingency, project contingency, and general facilities.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5456) noted that the DOE National Environmental Technology Laboratory ( NETL) recently issued their next round of awards for testing of advanced Hg reduction technologies at coal fired power plants. This testing is to take place in the 2005 2007 time frame. The point of this discussion is to note that scientific testing and research on Hg monitoring and control equipment are still continuing and will continue for the next few years. If the technologies related to Hg issues were sufficiently demonstrated, there would be no need for continuation of the testing programs of this nature.

The commenter has been participating in various Hg projects that attempt to present a better understanding of various issues related to Hg emissions from the combustion of coal in electric utility steam generating units, specifically those burning PRB subbituminous coal. These projects involve studying Hg emissions control technologies and Hg emissions monitoring. 9 50 The DOE/ NETL announcement of the awards states " With an eye on future federal regulations aimed at reducing Hg emissions, the DOE has selected six additional projects as part of a DOE research program to advance the technical readiness of Hg control options for the Nation's fleet of coal fired power plants. The six projects in this next round of awards build on last year's selection of eight projects, and will verify technology performance, evaluate costs, and assess balance of plant impacts. The projects will field test advanced, post combustion technologies involving all coal types at utilities using pulverized coal or cyclone boiler configurations, and focus on technologies capable of removing Hg from flue gas containing higher concentrations of elemental Hg. The technologies include sorbent injection, wet flue gas desulfurization systems enhancement, and combustion optimization. Both rounds of selections are aimed at meeting the Energy Department's near term goal of having technologies that can capture 50 70 percent of Hg emissions ready for commercial demonstration by 2005 for power plants burning bituminous coal, and by 2007 for those that burn low rank coals and blends. The Energy Department has set a longer term goal of having technologies that can achieve 90 percent Hg reduction for all fuel types ready for commercial demonstration by 2010, and is also looking to reduce the cost of Hg control by 25 50 percent over baseline, activated carbon costs, which range from $ 50,000$ 70,000 per pound of mercury removed."

The important statement in the above is that DOE/ NETL is seeking to be ready for commercial demonstration, not commercial use, of Hg control by 2005 for bituminous coals, and 2007 for low rank coals ( lignite and subbituminous coal).

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5458) noted that in the January Federal Register proposal, EPA fails to acknowledge the ongoing work being conducted under the U. S. Department of Energy/ National Energy Technology Laboratory ( DOE/ NETL) Mercury Control Technology Research Program on coal fired power plants. Four full scale demonstration projects have tested the effectiveness of carbon injection in tandem with conventional criteria air pollution control devices currently in use at utilities. Specifically, the E. C. Gaston plant in Alabama burning low sulfur bituminous coal achieved greater than a 90 percent Hg removal rate using carbon injection, along with a hot side electrostatic precipitator ( ESP) and a compact hybrid particulate collector ( COHPAC) baghouse for particulate control. The Brayton Point plant in Massachusetts burning low sulfur bituminous coal achieved a 90 percent Hg removal rate using carbon injection in combination with a cold sided ESP. The Pleasant Prairie plant in Wisconsin burning sub bituminous coal achieved a 65 percent removal rate using carbon injection with a cold sided ESP. Significantly, the E. C. Gaston Plant achieved a high Hg removal rate and used considerably less carbon injection as a result of the addition of a COHPAC baghouse or fabric filter in comparison to the other projects. The additional pollution control equipment has the potential to significantly increase Hg removal rates from sources burning both bituminous and sub bituminous 9 51 coal.

Real reductions for both Hg and sulfur can be achieved when Utility Units install wet scrubbers or spray dryer adsorbers, in conjunction with fabric filters. According to the Information Collection Request III data, the lowest emissions of Hg and sulfur were achieved when these pollution control devices were used. The Department analyzed emissions data from Utility Units in eight states surrounding New York. This analysis showed that the Utility Units achieving the greatest Hg reduction were ones utilizing fabric filters. Several of the better controlled units have ESPs but also used a wet scrubber for sulfur control. The Department has experience with municipal waste combustors ( MWCs) in New York that use carbon injection in combination with fabric filters or ESPs. These MWCs equipped with carbon injection and ESPs achieve Hg emissions reductions of at least 85 percent. MWCs equipped with carbon injection and fabric filters achieve reductions greater than 90 percent. Mercury is predominantly emitted in the oxidized form by MWCs.

The Supplemental Notice and a letter to the Air Docket from the DOE ( Document ID No. OAR 2002 0056 0044) describe the need for six years to adequately conduct a commercial demonstration of Hg controls. The Department believes that this long time frame is not justifiable and it appears that EPA is attempting to selectively develop time lines to justify a cap and trade program. Upon closer examination, the average six year figure includes a pre award period greater than 12 months, with each full scale demonstration project taking another 12 months, and allows for inflation during the operation and reporting time line by including the time it takes to prepare a report on the project. A more realistic value for commercial demonstration is in the range of three to four years, especially in light of all of the full scale Hg demonstration projects already completed or currently being conducted.

The goal of the DOE/ NETL Mercury Control Technology Research Program is for these technologies to be available for bituminous sources by 2005 and for lignite and sub bituminous sources by 2007. The program also describes the commercial development of advanced Hg control technology that will achieve a 90 percent Hg reduction for all coal types by 2010. In fact, the field testing of this technology at a number of coal fired units was already underway in 2003. If these goals are attained, widespread commercial deployment of extremely efficient Hg air pollution control technologies could begin to occur in 2008 for bituminous sources and 2011 for lignite and sub bituminous sources.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5446) believed that the variety of input assumptions, particularly in regard to costs and Emission Modification Factors ( EMF), used in the modeling analysis highlight the uncertainty associated with the cost and performance of Hg control 9 52 technologies. Given the limited data available, this uncertainty is to be expected and simply reflects limited knowledge in the area. Therefore, any final rule must be sufficiently flexible to accommodate the high degree of uncertainty inherent in the available data. The commenter believed that a national " cap and trade" based regulation with appropriate caps and timing will provide an important component of flexibility and will help the EPA address this inherent uncertainty.

Furthermore even the range of assumptions used in the commentator's models only indicates that there is uncertainty in the cost and performance of a typical plant and typical coal. The models do not account for the wide variability of coals and process conditions that can result in significant differences in performance between two plants with nominally similar coals and identical control technology. It is important that the EPA recognize that the performance of the average plant does not represent the behavior of the fleet. In order to understand the implications of the regulation EPA must undertake some form of probability analysis that considers natural variability in coal properties and unit performance and assesses their impact on the modeled results.

Failing to account for variability in fuel type and unit operation will make it difficult if not impossible for EPA to establish limits that are technically achievable for all affected units.

Response:

EPA is finalizing a cap and trade approach under section 111. See final rule preamble for rationale. EPA's IPM modeling does take into account some extent variability of coals and control configurations. IPM provides for extensive modeling of the coal sector, where coals can be selected by mercury content and sulfur content. For further discussion see EPA's IPM documentation in rulemaking docket.

Comment:

One commenter ( OAR 2002 0056 5510) was concerned that the various input assumptions used in the commenters' modeling analysis do not account for the wide variability of coals and process conditions encompassed by the full fleet of US utility boilers. Failing to account for variability in fuel type and unit operation will make it difficult if not impossible for EPA to establish limits that are technically achievable for affected units. The commenter suggested, phased alternative to establishing a national cap and trade program, as articulated in comments dated May 14, 2004, and again in these comments in response to II. B. 4. g, would address the variability concern through ensuring a far better database than currently exists.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale.

Comment: 9 53 One commenter ( OAR 2002 0056 5488) states that activated carbon injection ( ACI) has been extensively tested in several full scale tests and pilot scale tests and in a recent long term test performed at the Gaston power plant. Full scale testing performed by ADA ES along with testing performed by EPRI showed that high levels of Hg control, at least 90 percent, could be achieved on a cost effective basis at coal fired power plants with ACI regardless of the rank of coal burned, with the utilization of modern particulate matter control equipment ( i. e., a fabric filter or a polishing baghouse downstream of an electrostatic precipitator). Long term tests of ACI outfitted with a small baghouse downstream of a hot side ESP have continued at the Gaston power plant, which burns bituminous coal. This combination effectively addresses problems with carbon contamination of fly ash that can occur when activated carbon injection is used with an ESP alone. It is also quite viable for retrofit applications, because of the compact size of the polishing baghouse. The tests conducted at Gaston show that such units can achieve greater than 90 percent Hg control on a long term average basis, with appropriately sized baghouses and activated carbon injection rates. The Gaston investigators, from ADA ES, EPRI and DOE, conclude that " activated carbon injection systems are simple, reliable and commercially available." The conclusion that activated carbon injection is commercially available today has also been affirmed by the national trade association of control technology vendors.

Beyond activated carbon injection, EPA neglected to seriously consider several other highly effective approaches that are available for reducing Hg emissions from existing coal fired power plants. These include Electro catalytic oxidationTM, advanced dry FGD, coal blending for plants burning sub bituminous coal, injection of non carbon based sorbents, and pre combustion coal scrubbing to increase combustion efficiency of lignite and sub bituminous coals while simultaneously removing Hg, N, and S before the coal is burned.

Advanced dry FGD technology is widely used in Europe and has been demonstrated at Roanoke Valley Energy's 55 MW bituminous coal fired Unit 2 with Hg removal in excess of 95 percent. Two companies actively marketing advanced dry FGD are F. L. Smidth AirTech, which is marketing their Gas Suspension Absorber ( GSA) as a retrofit with an existing ESP or Pulse Jet fabric filters; and RJM Beaumont which is marketing their Rapid Absorption Process ( RAP) as a multipollutant ( SO 2, PM and Hg) control technology.

Electro catalytic oxidationTM ( ECO) technology has been demonstrated on a 2000 scfm pilot at First Energy's Burger Plant in Akron, OH, which has been operating since March 2002. Pilot test results indicate 80 90 percent Hg removal under any inlet condition. Early results from a 50 MW commercial demonstration system at Burger indicate similar performance to the pilot tests. A 510 MW ECO system is planned for installation at AmerenUE's Sioux Plant in Missouri following successful completion of the Burger demonstration.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment: 9 54 One commenter ( OAR 2002 0056 5502) referenced technological improvement. The history of technology development, including that of environmental controls, clearly shows that technology does improve with time. Examples ( see Document ID No. OAR 2002 0056 5502) are provided to support a modest improvement rate of 2.5 percent per year, which is one of the several cases ( along with quicker and slower growth cases) modeled by Charles River Associates for the EEI and the commenter's submittals in June 2004. Because technology improvement affects the control technology choices made by power plants in the model analysis, and therefore provides a more realistic prediction of the industry's likely response to the various proposed regulatory scenarios, the commenter believed it is important, and very appropriate, to include cost reductions and/ or performance improvements in an economic model.

Control considerations for modeling. The detailed comments provide information on the topics identified in EPA's question ( under § II. B. 4. c) timeline for commercialization, cost, balance of plant impacts, and control performance. While the commenter could not comment on commercialization issues as they do not own and operate power plants, they have provided the conditions they believe are needed for Hg controls to be considered " commercially available." These include consistent, predictable results from the approximately 30 field tests sponsored by DOE and the co funded by the industry and the commenter, as well as enough truly long term tests ( e. g., 12 18 months) to ensure that the industry understands how to operate the equipment reliably and manage and plant impacts that may be caused by the technology. A technology that gets this far is then ready to be procured by the first users, with full implementation by al plants that select this technology several years later.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005). EPA has included the examination of technology improvement in its analysis of the costs of the final rulemaking. EPA has performed a sensitivity analysis assuming the introduction of second ACI option using advanced sorbents, leading to lower capital costs. See sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact Analysis.

Comment:

One commenter ( OAR 2002 0056 5505) stated that the Department of Energy ( DOE) National Environmental Technology Laboratory ( NETL) recently issued their next round of awards for testing of advanced Hg reduction technologies at coal fired power plants. This testing is to take place in the 2005 2007 time period. The point of this discussion is to note that scientific testing and research on Hg control technologies are still continuing and will continue to do so now and for the next number of years. If the technology were sufficiently demonstrated, there would be no need for continuation of the testing programs of this nature.

The DOE/ NETL announcement of the awards ( 5 November 2004) states " With an eye on future federal regulations aimed at reducing Hg emissions, the DOE has selected six additional projects as part of a DOE research program to advance the technical readiness of Hg control 9 55 options for the Nation's fleet of coal fired power plants.

The six projects in this second round of awards build on last year's selection of eight projects, and will verify technology performance, evaluate costs, and assess balance of plant impacts. The projects will field test advanced, post combustion technologies involving all coal types at utilities using pulverized coal or cyclone boiler configurations, and focus on technologies capable of removing Hg from flue gas containing higher concentrations of elemental Hg. The technologies include sorbent injection, wet flue gas desulfurization systems enhancement, and combustion optimization.

Both rounds of selections are aimed at meeting the Energy Department's near term goal of having technologies that can capture 50 70 percent of Hg emissions ready for commercial demonstration by 2005 for power plants burning bituminous coal, and by 2007 for those that burn low rank coals and blends. The Energy Department has set a longer term goal of having technologies that can achieve 90 percent Hg reduction for all fuel types ready for commercial demonstration by 2010, and is also looking to reduce the cost of Hg control by 25 50 percent over baseline, activated carbon costs, which range from $ 50,000 to $ 70,000 per pound of mercury removed."

The important statement in the above is that DOE/ NETL is seeking to be ready for commercial demonstration, not commercial use, of Hg control by 2005 for bituminous coals, and 2007 for low rank coals ( lignite and subbituminous coal).

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

The commenter ( OAR 2002 0056 5519) stated that information referred to earlier demonstrated that Hg controls were commercially viable and cost effective:

° Low NO x burners, activated carbon injection ( ACI), selective catalytic reduction ( SCR), and acid gas controls [ including Lime Stone Forced Oxidation ( LFSO)] and wet Electrostatic Precipitators ( wet ESPs) for reducing Hg emissions, were already commercially available and ready for installation on all coal fired electric steam generating units for all types of coal, and ° The maximum total control costs for achieving 90 percent Hg removal efficiency on a 100 MW coal fired electric steam generating unit was less than $ 6 per month to a homeowner who used 500 kWh per month of electricity.

( Note that this worst case total capital cost estimate for a 100 MW unit to install LSFO with a new stack and a balanced draft conversion of the boiler was $ 65.2 million dollars, 2002 dollars). 9 56 More recent control cost estimates in 2003 dollars calculated for new IPM modeling indicated that the cost to install LFSO for 500 MW unit were as follows: total capital cost=$ 236 million, fixed O& M=$ 9.16 per kW/ yr and variable O& M=$ 1.08 mills/ kWh. Recent health data indicated that if plant specific, Hg controls were not required and not installed on coal fired electric steam generating units, the same homeowner would be required to expend numerous times more in healthcare costs. Simply put, air pollution controls capable of achieving 90 percent Hg removal efficiency could be installed on all coalfired electric steam generating units 100 MW or larger at an average monthly cost to the homeowner that is much more cost effective than dealing with its environmental and health cost consequences.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5497) stated that they do not believe that EPA's modeling of the power sector has omitted any control technologies that are reasonably likely to be available or likely to be commercialized within the time frame for decision and implementation of Hg control technologies, consistent with the timelines envisioned by the Clear Skies Initiative. The preceding response discussed the problems with modifying an ESP to increase collecting plate area when ACI is employed and with the widespread retrofit of fabric filters.

While promoted vigorously by vendors with a commercial interest in such technologies, halogenated activated carbons, such as one containing bromine or iodine, are technologies that should not be considered commercially available or proven. While there has been a single test with brominated ACI that involved one half of the flue gas stream from a 150 MW unit that indicated this might eventually hold some promise, innumerable uncertainties remain with this technology. A 30 day test period is simply insufficient to understand the long term effects that might be encountered when such potentially corrosive substances are injected into a utility boiler. There would likely be effects on the ability to sell or dispose of fly ash, corrosion on ductwork and/ or collecting plates, and possibly the production of potentially harmful by products such as dioxin.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

4. CATF and Cinergy both modeled more stringent MACT type options. CATF assumed that ACI would be available in 2005 for all coal types. Cinergy assumed that ACI would be available in 2005 for all coal types in one scenario and in 2010 for 9 57 all coal types for another scenario. EPA assumed commercial application only beginning in 2010 with 70 90 percent removal levels. The year of availability for ACI makes a large difference in the projected impacts of a MACT type option. What assumptions for ACI availability are most appropriate to consider in a modeling analysis, at what quantities, for what coal types, and why?

Comment:

One commenter ( OAR 2002 0056 5464) reviewed the IPM modeling summaries highlights as an important fact: the results are only as good as the variables used in the model. That is, the inputs and assumptions used in the model are not only critical to its accuracy and success but, more importantly, assumptions about availability, control efficiency and cost ( both capital and operation and maintenance costs) predetermine its results. Unfortunately, they believed several of the assumptions and inputs described in the NODA are fundamentally flawed and account for unrealistic results. For example, the Cinergy model assumes that ACI would not be available until 2010 ( five years from now). This is erroneous, in that ACI is available now. Further, if a unit has difficulty complying with the MACT limit by 2008, using ACI and the existing control system on the unit, then the Clean Air Act, under Sections 112( i)( 3) and 112( i)( 4), contains provisions that could offer additional time. Because ACI is available now and the Clean Air Act provides for extensions for more substantial control device addition or replacement, the commenter does not agree there would be a need for power plants to shut down for as long as two years, as the Cinergy model assumes. In fact, installation of ACI requires little down time and may be sufficient on many plants to achieve substantial Hg control. With halogenated sorbents, this may be all that is required for most plants to achieve 90 percent or more control. In cases where existing particulate control at coalfired units is poor and needs to be replaced or supplemented with more effective particulate control, the compliance period for the rule should be adequate to avoid disruptions in power supply. If needed, more time can be allotted on a case by case basis, long term shutdowns can be avoided, and any shutdowns can be planned to avoid disruptions.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5332) agreed that the year of availability of ACI as a control option for Hg is a key issue in the modeling analyses. The Agency has apparently received many comments on this issue, ranging from the view that the technology is commercially available today to the opinion that it will not be commercially available until well after 2010. The commenter does not have first hand information with respect to the date on which ACI should be considered a commercially viable option for Hg control from coal fired power plants. However, the commenter offers the following evidence in support of the proposition that this technology should be considered available on the earlier end of the time frame being considered, with the 9 58 caveat that the effectiveness and cost of ACI in reducing Hg emissions will depend to some degree on the details of plant configuration and type of coal burned.

First, ICAC, which is the national trade association of companies that supply air pollution control and monitoring technology, has gone on record in written comments submitted to EPA, and in testimony presented at a Congressional hearing, that ACI systems are currently available, have already been used in full scale applications for the power sector and other industrial sectors, and can be applied to any plant configuration and coal type. It can be argued that considerations of self interest may contribute to ICAC's conclusions. On the other hand, ICAC's claims that site specific guarantees for activated carbon systems are being offered commercially in the marketplace today for many plant configurations and coal types certainly should not be ignored.

Second, a number of states, including Massachusetts, New Jersey, Wisconsin and Connecticut, have already promulgated Hg reduction requirements. In some of these states, strict Hg reduction requirements are being imposed in the 2006 to 2008 timeframe, and compliance will require use of ACI or of another approach that will achieve similar levels of reduction. In developing these regulations, the states have conducted evaluations that have lead them to conclude that activated carbon will be a commercially available option in this timeframe.

And finally, the regulations EPA promulgates will themselves play a role in driving the commercial availability of ACI and other control technologies. Relatively stringent standards will propel the commercial availability of technology, while less strict requirements will forfeit this benefit. By the same token, the more certainty the requirements offer from a legal perspective whether by virtue of legislation or rules that are likely to withstand legal challenge the more likely the requirements will be to drive the early commercial availability of controls.

Response: EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5475) noted that the utility of using ACI as a control method was discussed in the NODA. The acting principle of ACI is that by injecting carbon additional Hg is captured in the existing particulate control device in a manner similar to how the particulate form of Hg in the gas stream is already being captured. The commenter states that it is in favor of the use of this approach for significantly reducing Hg emissions. This technology has been used to successfully reduce Hg emissions at several coal fired utilities across all coal types.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s 9 59 Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5475) noted that brominated activated carbon injection, a form of ACI where the carbon is combined with bromine before injection, has demonstrated 95 percent Hg removal at Great River Energy's Stanton 10 Plant. Injecting brominated activated carbon tends to convert a higher portion of the elemental Hg to the oxidized form. This is analogous to the effect naturally occurring chlorine in coal has on Hg emissions. Achieving 95 percent removal at the Stanton 10 Plant is significant since it burns lignite coal, which is generally recognized as the most difficult to control. Lignite is difficult to control, in part, because lignite's chlorine content is typically low. This commenter states that it does not appear that EPA has considered the impacts of the recent improvements to the ACI technology in the proposed MACT rule.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005). EPA has included the examination of technology improvement in its analysis of the costs of the final rulemaking. EPA has performed a sensitivity analysis assuming the introduction of second ACI option using advanced sorbents, leading to lower capital costs. See sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact Analysis.

Comment:

One commenter ( OAR 2002 0056 5447) said that while they remain encouraged about the potential for ACI and other Hg control technologies, the basic facts have not changed since the commenter filed its April 30, 2004, comments. No technology, including ACI, has been demonstrated to achieve the emission rate proposed under the new source MACT or NSPS regulatory schemes on a commercial scale for all but the lowest Hg content coals. No vendors of control technology are willing to guarantee Hg removal at the rates needed to achieve the proposed new source emission levels. This lack of guarantees affects financing, choice of fuel, and ultimately the economic viability of the unit. If units are not economically viable, they will not be developed and the nation's energy supply will suffer.

The commenter noted that any estimate of when Hg specific control technologies will become commercially available remains uncertain. All technologies must be tested on a broad range of coals over longer periods of time. Balance of plant issues must be identified and resolved.

EPA must base its ACI availability and performance projections on realistic development estimates and not on assumptions that there will be " funding [ for and the] successful implementation of an aggressive, comprehensive [ ACI] research and development program at both EPA and the U. S. Department of Energy." 69 Fed. Reg. 69870, col. 2 3. EPA explained in 9 60 its January 2004 white paper that implementation of such a research and development program is the basis for its projection that ACI technology will be available for commercial application after 2010 and that removal levels in the 70 90 percent range could be achievable. 69 Fed. Reg. 69870, col. 2. In fact, there is no assurance that ACI will be commercially available by 2010.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005). EPA has included the examination of technology improvement in its analysis of the costs of the final rulemaking. EPA has performed a sensitivity analysis assuming the introduction of second ACI option using advanced sorbents, leading to lower capital costs. See sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact Analysis. Commenter is referred to the preamble for discussion of NSPS limits.

Comment:

One commenter ( OAR 2002 0056 5458) contended that the results of the numerous modeling summaries provided in the NODA are only as good as the input variables. The December 2000 finding clearly established an " appropriate and necessary" finding to reduce Hg emissions by properly developing a NESHAP for coal fired utility plants. The commenter believed the use of activated carbon injection and other alternative sorbents which will reduce Hg emissions from both bituminous and sub bituminous coals has advanced greatly and would be available much earlier than 2010 as speculated in some of IPM runs provided in the NODA. The commenter was also concerned that the EPA did not conduct, and provide for comment, the additional modeling with the IPM to evaluate the more stringent MACT options. This was previously requested by the state environmental agency representatives who served on the Federal Advisory Committee Act Utility Workgroup.

The IPM input data comparing MACT based approaches with alternative regulatory approaches relies solely on the projected Hg reductions achieved with using activated carbon injection ( ACI) or similar sorbents. The analysis presented by Cinergy used a stringent MACT value for all subcategories of coal but questioned the ability of ACI's availability by 2010. The DOE recently announced that six new projects would be in their second round of field testing for ACI and new sorbents. ( This is in addition to last year's selection of eight projects by DOE.) Both rounds of testing are aimed at meeting the DOE's near term goal of having technologies that can capture 50 70 percent of Hg emissions ready for commercial demonstration by 2005 for plants burning bituminous coal and by 2007 for those burning lower rank coals and blends. By 2010, the DOE expects costs to be reduced by 25 50 percent.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. EPA appreciates the commenters input to the record on the status of control 9 61 technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5446) stated that it was worth noting that even with discrepancies in assumptions models of a stringent MACT without sub categorization or with inadequate subcategorization, predict a dramatic decline in demand for sub bituminous coal. For example, Cinergy modeling of a strict MACT without sub categorization1 shows sub bituminous and lignite plants shutting down prior to the availability of dedicated control technologies. In reality it is extremely unlikely that these plants would shut down for several years and then restart when control technology became available. They would be far more likely to switch fuels or be permanently retired. In this case the very significant declines in the use of subbituminous and lignite coals predicted would have a very dramatic impact on US electricity supplies and regional economies.

In addition, modeling by the Clean Air Task Force ( CATF) of an Alternate Mercury Control Scenario with a reduced level of sub categorization showed a 27 percent decline in sub bituminous coal use relative to 2003.

These results demonstrate that the EPA must incorporate sub categorization by coal rank if it is to meet its commitment of implementing a rule that ensures a level playing field for all coal types.

Response:

EPA is finalizing a cap and trade approach under section 111. As discussed in other comment responses, the final rule takes into account the different levels of mercury control that lignite, bituminous, and subbituminous coals can achieve and uses coal adjustment factors for determining the state emission budgets and for EPA's example allocation for States to allocate at the unit level. For further discussion see final rule preamble ( section IV. C. 4) and Technical Support Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter ( OAR 2002 0056 5510) stated that DOE projects that ACI technology, capable of achieving a 50 70 percent reduction in Hg emissions from all coal types, will be commercially available by 2010. In this regard, assumptions may be used for modeling purposes, but those assumptions must have a rational basis, and must be conservative enough to take into account the uncertainty and variability associated with ACI controls on the full range of boilers and fuel types. The commenter referred to their supplemental Hg rule comments dated June 29, 2004:

" A fundamental problem in developing and predicting the performance of mercury control technology is that mercury chemistry is poorly understood, particularly in context to the 9 62 wide range of conditions encountered in coalfired power plants. Correlations of mercury speciation with flue gas composition are instructive, but have poor predictive power ( i. e., wide confidence intervals) as discussed in the commenter's May 14 comments on the rule. These numerical correlations fail to account for such important factors as flue gas and fly ash composition, including unburned carbon, and heterogeneous gas solid reactions between mercury and the fly ash1. Work on scientifically based ( i. e., a priori) chemical models is underway, but their usefulness remains to be seen."

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5491) said that a revolution has occurred over the last year in power plant Hg control technology. Coal chlorine content has now been made irrelevant. Consequently, the currently proposed Hg MACT structures, limits, and timetables need to be radically modified.

The EPA's current MACT proposals were based on a fundamental assumption that the low chlorine content of Western subbituminous coals and lignites severely limited the performance of Hg reduction technology with these fuels.

For the traditional MACT proposal, this resulted in differing Hg emission floor limits subcategorized by coal rank.

For the cap and trade proposals, this resulted in differing emission allowance allocation adjustment factors by coal rank.

Treating the different coal ranks differently because of their chlorine contents resulted in highly divergent standards which would lead to significant marketplace inequities and distortions:

Coal Type Proposed Emission Standards Allocation Adjustmen t Factors Existing Plants ( lb Hg/ TBtus) New Plants ( 10 6 lb Hg/ MWh)

Lignite 9.2 62 3 Subbituminous 5.8 20 1.25 Bituminous 2.0 6 1 Fortunately, vast improvements in the performance and cost effectiveness of activated 9 63 carbon injection technology ( ACI) for low chlorine subbituminous coal and lignites have recently been conclusively demonstrated. Multiple DOE co sponsored full scale retrofit demonstrations by different contractors of ACI with brominated carbons at plants burning low chlorine fuels this past year consistently achieved Hg emission rates of less than 1.0 lb Hg/ TBtus at very low costs. Moreover, these new brominated carbons are now commercially available for use by any plant. Consequently, the currently proposed Hg MACT structures, limits, and timetables have to be radically modified to account for these developments.

At the very least, the MACT floor levels or adjustment factors for subbituminous coals and lignites now have to be lowered to the levels currently proposed for bituminous coals. More responsibly, subcategorized standards based in plant particulate control equipment, rather than by coal rank, should be promulgated, with resulting MACT floor levels of 1.0 lb Hg/ TBtu or below. If a cap and trade system is proposed instead, its 2010 cap should be in the range of 8 to 10 tons of Hg per year, not 34.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. The final rule takes into account the different levels of mercury control that lignite, bituminous, and subbituminous coals can achieve using existing NOx and SO 2 controls and uses coal adjustment factors for determining the state emission budgets and for EPA's example allocation for States to allocate at the unit level. For further discussion see final rule preamble ( section IV. C. 4) and Technical Support Document for the Clean Air Mercury Rule Notice of Final Rulemaking, State and Indian Country Emissions Budgets, EPA, March 2005.

Comment:

One commenter ( OAR 2002 0056 5488) noted that EPA's January 30, 2004 proposed rule making erroneously and unlawfully found that ACI for Hg control at EGUs is " not available on a commercial basis." As discussed in the commenter's June 27, 2004, comments, this assertion is manifestly unreasonable and contrary to law. Moreover, EPA's assumptions about the costs of controlling Hg, which were never justified, have now been rendered virtually meaningless based on the advances achieved with low cost halogenated sorbents.

While EPA is obligated to consider all comments submitted to the administrative record, it should be extremely skeptical of cost analyses performed by the industry to be regulated, as time and time again they have proven to be skewed toward dramatically overstating compliance costs. The assumption made by Cinergy in its power sector modeling that ACI will not be commercially available until 2010 is a case in point. This assumption is laughable, given that ACI is commercially available today. The corresponding suggestion that coal plants will temporarily have to shut down is reminiscent of the hyperbolic statements of impending doom voiced by representatives of the automotive industry when they faced emissions regulations in the 1970' s. Likewise, Cinergy provides no support or justification whatsoever for the increased costs of SO 2 control, increased cost of SCR, reduced Hg co benefits and elevated discount rate that were assumed in its modeling, compared to EPA's analysis. 9 64 Response:

For final rule modeling analysis, EPA is not incorporating other commenter assumptions into its modeling analysis. The assumptions used in EPA analysis of the final rule are discussed in EPA's IPM documentation, available in the docket. EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5492) noted that ACI technology is currently being offered for sale to utilities. For example, Council Bluffs Station is required to reduce Hg emissions by 85 percent or use an injection rate of 10 lb/ mmacf. Several vendors bid on this system and offered guarantees. The commenter believes that an average 70 percent Hg reduction is achievable over a large number of boiler installations using today's technology. Based on this input, they believed that ACI technology capable of Hg reduction over a large number of installations is or will be commercially available by 2007 2008 for all coal types.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5502) referenced ACI availability and costs. Sorbent injection, either with conventional activated carbon ( ACI) or chemically treated carbon ( CTC) appears to reduce Hg in the flue gas from on all coals. However, the maximum reduction achievable and the percent reduction at any given sorbent injection ratio varies with coal type. This is especially true for ACI at plants fueled with western coals. CTCs show promise in overcoming these constraints for those fuels, especially at plants equipped with a spray dryer and baghouse, but many questions remain about this new technology   sustainable and widely applicable high removals, possible emissions of the treatment chemical and/ or corrosion caused by it, large quantity availability of consistent quality material, etc. ACI costs for 70 percent Hg reduction are predicted to range from 1.6 to 3.0 mills/ kWh for low sulfur eastern or Western fuels; presumably, most plants burning medium   to high sulfur eastern fuels would have an FGD and therefore not need sorbent injection.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired 9 65 Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5429) stated that during 1999, EPA gathered data as part of the ICR program to measure Hg capture in emission control equipment designed to capture SO 2, NO x, and particulates. These data showed that the same emission control equipment captured lower amounts of Hg at plants burning subbituminous and lignite coals. When sorbent based Hg control technology was first applied to plants burning these Western coals, it was discovered that while 50 70 percent Hg removal was achievable for units with ESPs, there appeared to be a ceiling that prevented any higher levels of Hg removal for these coals ( Durham et. al., 2002).

It was speculated that the reason for the poorer capture of Hg from Western coals was that these coals had lower concentrations of halogens such as chlorine, bromine, and fluorine. It appeared that halogens in coal resulted in gas phase species that were critical in the reaction processes that captured Hg. During 2004, research and development was conducted to determine if higher levels of Hg removal could be achieved by supplementing halogens at these plants. Full scale field tests were conducted in which various halogens were added to the coal, sprayed into the boiler and impregnated onto the sorbent.

During 2004, full scale field tests were performed on plants the burn subbituminous Powder River Basin ( PRB) coals and lignites. Two key configurations of emission control equipment were evaluation:

° Spray dryer followed by a fabric filter ° ESP only The first configuration was selected because the most likely air pollution control configurations for new units burning subbituminous PRB coal or a lignite will be a spray dryer absorber ( SDA) followed by a fabric filter ( FF). This configuration offers cost advantages to meet stringent multi pollutant control regulations. However, available data indicate that this configuration demonstrates particularly low, native Hg removal and the effectiveness of non chemically treated activated carbon is limited ( Sjostrom et. al. 2002).

The commenter, with support from DOE NETL and industry partners, conducted a Hg control demonstration using sorbent injection into the SDA FF at Sunflower Electric's 360 MW Holcomb Station. Holcomb Station is located near Garden City, Kansas. The unit is a load following sub critical 360 MW pulverized coal opposed fired Babcock and Wilcox Carolina type radiant boiler designed to burn PRB coal. The existing unit is equipped with three spray dry absorber modules followed by two very low air/ cloth ratio reverse air fabric filters. Holcomb primarily burns two different PRB coals, Jacobs Ranch and Black Thunder.

This test program was designed to provide a full scale evaluation of different technologies that can overcome the limited Hg removal achievable at these sites. Each technology was based on supplementing certain halogens that are not available in sufficient quantities in these coals. The program was very successful in that three different technologies were found that have the 9 66 potential to produce high levels (> 80 percent) of Hg removal in this difficult application ( Starns, et. al., 2004b). These technologies are:

1. Coal Blending: By blending western bituminous coal with PRB coal, the Hg removal across the system increased to almost 80 percent even without injecting another sorbent. It is highly likely that firing a blend of Black Thunder and West Elk coals with ACI could result in greater than 90 percent Hg removal. Results with other coal blends must be evaluated.

2. Chemical Addition to the Coal: KNX, a proprietary chemical developed by ALSTOM Power, was found to enhance the performance of a standard activated carbon. Mercury removal of 86 percent was measured at a carbon feed rate of just 1.0 lb/ MMacf.

3. Chemically Enhanced Sorbent: A proprietary product of NORIT Americas, FGD E3, produced Hg removal in excess of 90 percent.

It should be noted that the first two approaches were tested for very short periods of time. However, the effects were verified and demonstrated the potential of these technologies. In contrast, the test program on NORIT's E 3 involved injecting the enhanced sorbent for four weeks. The results obtained during this period showed very high levels of Hg removal, average of 93 percent, at a significantly reduced injection rate of 1.2 lb/ MMacf. During this test period Hg emissions averaged 0.8 lb/ TBtu.

In addition to the Holcomb tests, URS conducted a DOE/ NETL sponsored program at the Great River Energy's Stanton Station Unit 10 ( Machalek, et. al., 2004). This unit fires North Dakota lignite and has the identical configuration of a spray dryer/ baghouse as Holcomb. During this test program two halogenated sorbents were tested, NORIT's E 3 and Sorbent Technologies B* PAC. Mercury removal levels greater than 90 percent were achieved at an injection rate of 1.5 lb/ MMacf with both of these sorbents.

Following the success of the halogenated sorbents on spray dryer/ fabric filters, a second round of testing was conducted on plants burning subbituminous coals that only have ESPs for emission control. This configuration represents the majority of existing plants that burn subbituminous coals and was therefore very important to the industry. Two tests were conducted during the summer and fall of 2004. The commenter conducted a test program at the Ameren Meramec Station, which burns 100 percent PRB coal, as part of a DOE/ NETL sponsored program ( Starns et. al., 2004c).

During this program, the performance of NORIT standard carbon Darco FOD was compared to the halogenated version Darco FOD E 3. With the standard carbon, the " ceiling effect" is observed in that a maximum removal of about 70 percent Hg removal is achieved at a feed rate of 3 5 lb/ MMacf. No additional Hg removal is obtained even if the carbon feed rate is double and tripled. In contract, the E 3 overcomes this effect and greater than 90 percent Hg removal is achieved at a feed rate of 3 lb/ MMacf.

A similar program was conducted by Sorbent Technologies at the Detroit Edison St. Clair Station ( Nelson, et. al., 2004). This unit burns a blend of 85 percent PRB coal with 15 percent 9 67 Eastern bituminous coal. This test involved the one month evaluation of Hg removal using Sorbent Technology's brominated activated carbon B* PAC injected upstream of the cold side ESP. During the duration of the test program, B PAC removed 94 percent of the Hg emissions when injected at a rate of 3 lb/ MMacf. The Hg emission rate was reduced to 0.4 lb/ TBtu.

The Department of Energy National Technology Laboratory, Southern Company, and EPRI funded a program to evaluate sorbent injection for Hg control for a year of continuous operation ( Bustard et. al., 2004; Berry et. al., 2004). The test was conducted at Alabama Power Company's Plant Gaston Unit 3. The overall objective was to evaluate the long term effects of sorbent injection on Hg capture and COHPAC ® performance. Data from the testing will be used to determine:

1. Air to cloth ratio; 2. Advantages/ disadvantages of high permeability fabrics; and 3. Design criteria and costs for new TOXECONTM systems.

Long Term Original Bags Activated carbon was injected into the COHPAC baghouse nearly continuously from June 26 through November 25. Figure 6 presents a snapshot of data during the long term test. Inlet and outlet total vapor phase Hg, calculated Hg removal, carbon injection concentration, baghouse cleaning frequency, and inlet mass loading are presented. Mercury removal varied between 50 and 98 percent, with an overall average of 86 percent.

One thing that was clear from these tests was that the current air to cloth ratio was too high to inject sufficient carbon to achieve 90 percent Hg control. A new TOXECON baghouse would have to be designed at a lower air to cloth ratio. One way to overcome the operating limitations at this site was to operate at low load/ lower flow for an extended period. While at these conditions, carbon injection could be increased and performance data could be tracked. The primary objectives of these short tests were to 1) determine the injection concentration necessary to achieve 90 percent removal and 2) determine the impact of carbon injection on cleaning frequency at this lower air to cloth ( A/ C) ratio. An educated estimate of the ideal air to cloth ratio was about 6.0 ft/ min.

Southern Company was able to schedule an extended period of low load operation for Gaston Unit 3. Three injection rates were evaluated during the 72 hour test. The first test was conducted at the highest injection rate possible under normal operating conditions, 20 lb/ h. At this rate and the lower flow, the injection concentration was 0.9 lb/ MMacf instead of 0.6 lbs/ MMacf. The injection concentrations were then increased up to a maximum of nominally 3.3 lb/ MMacf.

The results from this test, including inlet and outlet Hg concentrations, Hg removal, and cleaning frequency are presented in Table 1. At an injection concentration of 0.9 lb/ MMacf, Hg removal was between 80 and 90 percent. When injection concentration was increased above 2 lb/ MMacf, Hg removal was well above 90 percent and there were no episodes when the removal dropped below this level. Cleaning frequency was acceptable at all injection rates. 9 68 Table 1. Results Summary from Low Load Tests, November 2003 Injection Rate ( lb/ h) Injection Concentration ( lbs/ MMacf) Inlet Hg Concentration (

g/ Nm3) Outlet Hg Concentration (

g/ Nm3) RE (%) Cleaning Frequency ( pulses/ bag/ hour)

20 0.9 20.6 3.2 84.2 0.6 45a 2.0 22.2 1.0 94.6 0.8 70 3.3 21.4 0.61 97.1 1.4 a Last 18 hours of 45 lb/ h test.

A set ( 2,300 bags) of high perm bags was purchased and installed in the B side baghouse. The differences in design were denier ( an indication of fiber diameter; 2.7 versus 7.0 denier) and permeability ( nominally 30 versus 130 cfm/ ft2 @ 0.5" H 2 O). The primary goals for this test were to:

1. Demonstrate improved pressure drop performance of the high perm bags; and 2. Increase carbon injection concentration to achieve a higher Hg removal than was possible with the original bags.

Carbon injection rate was incrementally increased from 20 to 45 lb/ h. Because baghouse cleaning frequency was acceptable, it was possible to inject at a constant rate and not reduce injection when inlet mass loading increased. Average Hg removal for five different injection conditions is shown in Table 2. The average Hg removal was higher in each of the shorter tests than the 85.6 percent removal that was measured for the four month carbon injection tests with the original bags. These tests show that there is no difference in the effectiveness of carbon injection for Hg control using either the original bags or the high perm bags.

Table 2. Average Mercury Removal, Inlet Mass Loading, and Cleaning Frequency with High Perm Bags Injection Rate ( lb/ h) Injection Concentration ( lbs/ MMacf) RE (%) Inlet Mass Loading ( gr/ acf) Cleaning Frequency ( pulses/ bag/ hour) 20 0.6 87 0.1 0.6 25 0.8 91 0.05 0.7 30 1.0 94 0.06 0.7 35 1.1 93 0.02 0.6 45a 1.3a 92a 0.05a 1.0a a Long term test these data are from only the first two weeks at this condition.

Because it is expected that cleaning frequency will increase over time, especially as the new bags season, the long term tests were conducted at an injection rate of 45 lb/ h. For a two week period with an injection rate of 45 lbs/ h ( 1.3 lb/ MMacf), Hg removal was 92 percent, with a 9 69 maximum hourly value of 98 percent and a minimum hourly value of 80 percent.

Conclusions from Long Term Test ° TOXECON units designed at lower air to cloth ratios than COHPAC units are capable of high, 90 percent, Hg removal. For TOXECON baghouses, it is recommended that the maximum design gross air to cloth ratio be 6.0 ft/ min.

° Activated carbon injection systems are simple, reliable, and commercially available. The control programs can be easily adapted to varying operating requirements.

° Continuous Hg measurements are challenging but possible. Advancements to the analyzers were made and the analyzers operated 24/ 7 for nearly 20 months.

° Activated carbon effectively reduced Hg emissions for extended periods over a wide range of operating variables with a COHPAC baghouse.

° At an average injection concentration of 0.55 lb/ MMacf, over a four month period average Hg removal was 86 percent.

° For these tests, injection concentration was limited by high, baseline COHPAC cleaning frequency.

° High inlet loading into the COHPAC baghouse contributed to variable baseline Hg removal. It is also believed that these conditions allowed for higher Hg removal at a relatively low carbon injection concentration.

° Replacing the original 2.7 denier bags with 7 denier, high perm bags, improved the COHPAC's ability to handle periods of high inlet loading.

° Short tests at higher injection rates with the high perm bags showed that is was possible to achieve greater than 90 percent average Hg removal. However, Hg removal still varied between 80 and 98 percent during these periods and higher injection rates would be required to maintain consistent, 90 percent removal.

EPRI TOXECON TECHNOLOGIES For some plants, one of the disadvantages of injecting activated carbon is its impact on the salability or reuse of ash. Tests have shown that the activated carbon interferes with chemicals used in making concrete. One straightforward, cost effective approach to achieving high Hg removal without contaminating the fly ash is the use of the EPRI COHPAC ® ( COHPAC) and TOXECON   ( TOXECON) processes that are currently commercially available. COHPAC is an EPRI patented concept that places a high air to cloth ratio baghouse downstream of an existing ESP to improve overall particulate collection efficiency. The process becomes TOXECON when a sorbent such as activated carbon is injected upstream of the baghouse located downstream of an ESP. With this configuration, the ash collected upstream of the carbon injection remains acceptable for sale ( typically > 99 percent of the ash.) The downstream baghouse provides an 9 70 effective mechanism for the activated carbon to have intimate contact with vapor phase Hg, resulting in high levels of Hg control at relatively low sorbent injection rates.

The advantages of the TOXECON configuration are:

° Sorbents are mixed with a small fraction of the ash ( nominally 1 percent), which reduces the impact on ash reuse and waste disposal.

° Full scale field tests have confirmed that fabric filters require only 10 20 percent of the sorbent required by ESPs to achieve similar removal efficiencies.

° Capital costs for COHPAC are less than other options such as replacing the ESP with a full sized baghouse or larger ESP.

° COHPAC requires much less physical space than either a larger ESP or full size baghouse system.

° Outage time can be significantly reduced with COHPAC systems in comparison to major ESP rebuilds/ upgrades.

The TOXECON   configuration offers an advantage over injecting carbon ahead of a single particulate control device because it prevents contaminating fly ash with carbon. Although it is a highly effective configuration for removing Hg from flue gas, retrofitting existing plants with a baghouse can be expensive. An attractive alternative solution is EPRI's TOXECON II   technology, in which the same effect can be achieved without a baghouse but instead uses the existing multi field ESP alone. In this configuration, carbon is injected within the ESP into downstream collecting fields. The majority of the fly ash is collected in the inlet ESP fields while carbon is injected in one or more downstream ESP fields. With this approach, most of the fly ash in the flue gas will have been collected in the first several fields ( in general, 70 90 percent of the ash in flue gas is collected in each field), and beneficial use of this ash can is preserved since it will contain no carbon. The remaining fields of the ESP will then serve to collect the injected carbon. Any ESP with multiple fields can potentially use this approach. Besides activated carbon, other sorbents that can capture Hg can be used.

The main advantages of this approach are:

° preservation of the large majority of fly ash sales, ° potential for sorbent recycle, regeneration and reuse, ° enhanced oxidation of elemental Hg to increase capture in a downstream scrubber, ° minimal capital cost, and ° minimizes amount of Hg bearing byproducts needing processing or disposal.

In August of 2004, the commenter first reported the results of the first full scale evaluation of TOXECON II   at Coal Creek Station through a program funded by Great River Energy and EPRI ( Starns, et al. 2004a). These short term tests demonstrated promise for Hg removals of > 70 percent. Results with the mid ESP injection of TOXECON II   are comparable to those obtained injecting the sorbent upstream of the ESP. 9 71 The commenter stated that this technology is based on the fact that up to 90 percent in flight capture of Hg can be achieved with a residence time of only one half second as demonstrated on their earlier programs funded by NETL. In an ESP, the gas velocity is 4 6 feet per second, so a one half second residence time requires 2 3 feet of space. This amount of space is often available between sections of an ESP.

It should also be noted that the data was obtained using the standard NORIT Carbon Darco FOD. In both cases the " ceiling effect" is clearly visible indicating the deficiency of gas phase halogens. During 2005, the commenter will conduct a full scale field test of TOXECON II   on a plant burning 100 percent PRB coal. The halogenated sorbent E 3 will be tested at this site. If these tests confirm the performance of this advanced sorbent for this application, then higher levels of Hg removal will be achieved at greatly reduced injection rates. Keeping the sorbent injection rates low minimizes the potential of any negative effects of the carbon on the electrical components in the ESP. The combination of TOXECON II and E 3 would provide a very low cost option for plants burning Western coals that want to achieve high levels of Hg control while continuing to sell the majority of their ash.

Impact of Enhanced Sorbents on Economics of Mercury Control The commenter stated that based upon the results of the first four full scale field tests, cost estimates were made for applying this technology to the US fleet of coal fired boilers. In an EPA analysis, it was concluded that 80 90 percent control of Hg for the majority of plants could be achieved for less than $ 2/ MWh ( Srivastava et. al., 2004). A DOE analysis concluded that 60 90 percent Hg removal would cost between 1.3 and 2.4 $/ MWh depending on the coal and type of emission control equipment ( Hoffmann and Ratafia Brown; 2003). In addition, DOE has established goals of reducing costs over time by 25 50 percent by funding full scale field tests of improved technology.

The test results achieved during 2004 show significant improvement in both the levels of Hg removal achievable and the cost of control technology. From four different full scale field test programs conducted on PRB, lignite, and PRB/ bituminous blends, greater than 90 percent Hg removal was achieved on the most difficult emission control equipment configurations at a cost of less than $ 0.6/ MWhr. This shows how rapidly the sorbent based Hg control technology is advancing.

It should also be pointed out that one of the additional advantages of the technology is that all of the users can benefit from the improvements in sorbents as they become available. The technology is sufficiently generic that the improved products can be feed using the same sorbent storage and feed equipment. This means that as additional progress is made in sorbents over the next 3 to 5 years resulting in even lower costs, the power industry will be able to take advantage of the improvements even if it purchase the equipment today. In other words, an early adopter is not stuck with 2004 technology if a decision is made today on equipment for 2008.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s 9 72 Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005). EPA has included the examination of technology improvement in its analysis of the costs of the final rulemaking. EPA has performed a sensitivity analysis assuming the introduction of second ACI option using advanced sorbents, leading to lower capital costs. See sensitivity analysis in Chapter 7 of final CAMR Regulatory Impact Analysis.

Comment:

One commenter ( OAR 2002 0056 5535) agreed with EPA that Cinergy's assumption concerning the date of availability of ACI drives the results of this analysis, and focused our comments on this issue. EPA has already stated that it is aware of additional Hg data, particularly the testing of various halogenated sorbents. Given the success of the halogenated sorbents in capturing Hg during initial testing, it is no surprise that over extended test periods ( 30 days), these sorbents delivered Hg reductions higher than 90 percent at these subbituminous coal fired boilers. Given the most recent test data and the numerous studies presented at the 2004 " Mega Symposium" ( EPA was a sponsor, so the agency is surely aware of the data presented), the agency must concede that a national Hg reduction well in excess of 30 percent is achievable.

At issue then is the timing of the availability of such controls. EPA has received assurances from the Institute of Clean Air Companies ( ICAC) that the equipment and manpower needed to design, manufacture and install the control equipment will be available to meet the requirements of a MACT standard. Industry counters with the assertions that neither the equipment nor the manpower will be available and further that the performance of the technology performance is not assured.

The commenter has explored the issue of new technology acceptance in the electric power sector and their analysis lends valuable insight into where Hg control technology is today in terms of commercialization and adoption. Basically, the development and acceptance of new technology has followed 6 steps. They are:

1. Laboratory testing, 2. Pilot scale testing, 3. Full scale field tests, 4. Full scale tests at multiple sites, 5. Long term demonstration at several sites, and 6. Widespread implementation.

Regarding the first two steps, laboratory and pilot scale testing of Hg control technologies took place in the early to mid 90s. Full scale field tests, including full scale tests at multiple sites were completed during 2001 2003 as Table 1 illustrates. Table 1 lists the facilities by coal type and within each coal type in roughly chronological order. Thus, it is apparent that during the later tests, as the technology has rapidly advanced, the Hg capture efficiency has increased to the 90 percent range across all coal types. In addition, it can be seen that the earlier tests required considerably more carbon to achieve the same results as the later tests with halogenated sorbents. The need for less carbon will considerably reduce control costs. 9 73 Table 1. Full Scale Tests of Sorbent Injection Completed: 2001 2003 Site Coal Equipment Injection Rate ( lb/ MMacf) Percent Hg Capture Brayton Point LS Bituminous ESP ( 2) 10 94.5%

PGE LS Bituminous ESP 10 90%

Cliffside LS Bituminous HS ESP 6.4 > 80%

Gaston LS Bituminous HSESP COHPAC 0.55 86%

Lausche HS Bituminous ESP 4 70%

St. Clair Bit./ Sub. Blend ESP 3 90%

Pleasant Prairie Subbituminous ESP 11.3 66%

St. Clair Subbituminous ESP 3 94+%

Holcomb Subbituminous SDA/ FF 1.2 93%

Meramec Subbituminous ESP 3 90%

Stanton 10 Lignite SDA/ FF 1.5 95%

Stanton 10 Lignite SDA/ FF 1.5 90% Source: Durham, M. D. Advances in mercury control technology to meet future needs. Presented at PowerGen, December 2, 2004. Orlando, Florida.

Step 5 entails long term demonstrations at multiple sites. A year long test has already been completed at the Gaston plant ( average reduction 86 percent with an average performing sorbent) and 3 other month long tests have also been completed with success at the Holcomb, St. Clair and Meramec stations. As shown in Table 2, numerous other full scale tests at a variety of plants are either ongoing or scheduled in the 2004 2005 timeframe.

The commenter also note that state Hg rules will go into effect by 2008, which will provide additional long term commercial experience with Hg controls. Compliance with some of the state rules begins in 2008, consequently these facilities will have installed, tested and operated ACI systems long before the compliance date. By 2008, 15 boilers in Massachusetts, Connecticut, and New Jersey will be controlling Hg by more than 90 percent. These bituminous fired boilers have control configurations that are similar to 60 percent of the fleet and will provide the early proving ground that industry maintains is needed prior to widespread implementation of this technology.

Given this systematic evolution of the adaptation of activated carbon technology to the power sector, the commenter was confident that this technology will not just be available prior to 2010 but widely commercially available in time to facilitate compliance with a 2008 MACT standard. The commenter also noted for the record that not all plants will need to use ACI to comply with a stringent standard. Conventional controls will achieve a stringent emissions level for many plants, and precombustion controls and other technologies not represented in the IPM ( e. g., oxidizing catalysts and multipollutant controls) will also be options. 9 74 Table 2. Full Scale Tests of Sorbent Injection Ongoing and Scheduled: 2004 2005 Site Coal Equipment Company Gaston Low S Bit FF ADA ES Holcomb PRB SDA/ FF ADA ES Arapohoe PRB FF ADA Tech Stanton 10 ND Lignite SDA/ FF Apogee Yates 1 Low S Bit ESP/ FGD URS Yates 2 Low S Bit ESP URS Leland Olds ND Lignite C ESP EERC Meramec PRB C ESP ADA ES Buck Low S Bit H ESPC ESP Sorbent Tech St. Clair PRB/ Bit C ESP Sorbent Tech Miami Fort High S Bit C ESP ADA Tech Conesville High S Bit ESP/ FGD ADA ES Nanticoke PRB/ Bit ESP ADA ES Arapahoe PRB FF ADA Tech Antelope Valley ND Lignite SDA/ FF EERC Stanton 1 ND Lignite C ESP Apogee M. R. Young ND Lignite FGD EERC Monticello TX Lignite FGD EERC Source: Durham, M. D. Advances in mercury control technology to meet future needs. Presented at PowerGen, December 2, 2004. Orlando, Florida.

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5566) submitting documentation to support its position that technology to capture Hg from power plant flue gas is readily available, effective, and affordable. Hence, the commenter urges the U. S. Environmental Protection Agency to finalize expeditiously a Maximum Achievable Control Technology standard that reflects the state of technology and the legal requirements of Section 112 of the Clean Air Act.

Recent large scale tests have been completed at several power plants nationwide that 9 75 demonstrate high Hg removal is possible using sorbent injection ( see attached).

Activated carbon injection systems are simple, reliable, and commercially available. The control programs can be easily adapted to varying operating requirements. Over a four month period average mercury removal was 86 percent. ( Berry, Irvin, Monroe, et. al., 2004)

Three different technologies [ coal blending, chemical additives, and chemically enhanced sorbents] were found that have the potential to produce high levels (> 80 percent) of mercury removal in [ power plants that burn PRB coal). ( Sjostrom, Starns, Amrhein, et. al., 2004)

Recent analysis completed by the commenter found the cost of high Hg removal to be affordable ( see attached). Using EPA's cost estimates for installing sorbent injection and advanced dry scrubbers, the commenter found that 90 percent Hg control would cost an average of 0.15 and 0.22 cents/ kWh, a one to three percent increase. These cost figures are in line with estimates previously published by the Institute of Clean Air Companies, which estimates a 1.2 to 3.7 percent increase, and by the Department of Energy which estimates that 60 90 percent control would cost 0.191 to 0.236 cents/ kWh.

[ The commenter's] analysis found that retrofitting every coal fired utility boiler with mercury control equipment... would cost the average household from about 70 cents to over $ 2.00 a month... The cost of attaining 90 percent mercury control is only slightly higher than 70 80 percent control.

Finally, to date, four states have finalized rules requiring coal fired power plants to make significant cuts in its Hg emissions by the end of the decade ( see attached). According to the Institute of Clean Air Companies, power plants already are bidding on or finalizing contracts for Hg control equipment. Over 50 plants likely will be affected by the new rules finalized by the states of Connecticut, Massachusetts, Wisconsin, and New Jersey. The pollution control market is responding to the increasing demand, making it feasible for companies to meet tight Hg limits.

The EPA has at its disposal extensive technical documentation to support a stringent MACT standard for coal fired power plants, a standard that would achieve reductions comparable to those achieved through other MACT standards. A stringent standard with flexible compliance mechanisms can be developed to ensure that the timing and level of reductions are not compromised. The commenter urges the EPA to explore all options in fashioning a MACT rule for coal fired power plants, and to adopt an appropriate MACT rule expeditiously.

Response:

EPA is finalizing a cap and trade approach under section 111. EPA is establishing a phase I cap of 38 tons in 2010 and phase II cap of 15 tons in 2018. See final rule preamble for rationale. EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005). 9 76 Comment:

The commenter ( OAR 2002 0056 5519) assumed that EPA would use the most recent definition of " commercially available" advocated by representatives of the electric power industry; that is, " technology that has gone through at least one year of long term testing," one would have concluded that sorbent based technologies ( including activated carbon injection) and other combinations of technology used in series; [ including selective catalytic reduction ( SCR), flue gas desulfurization ( FGD) and fabric filters ( FF)], were currently commercially available. If EPA wold include in its determination of commercial availability all of the technologies that had already been used for at least the past 5 years by coal fired power plants located in Europe; for example, wet electrostatic precipitators ( wet ESPs), EPA would be forced to conclude that those technologies are not only commercially available, but also proven in practice.

The commenter was pleased to provide the following additional technical information to support these comments and responded to EPA's request on the availability and cost effectiveness of these controls:

1. " Field Test Program for Long Term Operation of a COHP AC System for Removing Mercury from Coal Fire Flue Gas," Report No. 41591R09, October 25,2004, ( Attachment # 9),

2. " Evaluation of Sorbent Injection for Mercury Control," Report No. 41986R04, October 29, 2004, ( Attachment # 10),

3. " Pilot Testing of Oxidation Catalysts for Enhanced Mercury Control by Wet FGD," Paper # 36, Mega Symposium, ( Attachment # 11), and 4. Field Test Program to Develop Comprehensive Design, Operating and Cost Data for Mercury Control Systems on Non Scrubbed Coal Fired Boilers, Report No. 41005R19, October 25, 2004, ( Attachment # 12).

Response:

EPA appreciates the commenters input to the record on the status of control technologies. The Agency's position on the state of Hg technology is contained in the EPA ' s Office of Research and Development white paper ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005).

Comment:

One commenter ( OAR 2002 0056 5477) referenced the cost of Hg control technologies by stating that it is also important to note that both the capital costs and cost effectiveness of controlling Hg from coal fired boilers need to be presented in a realistic manner. For example, a common but quite misleading practice is to present cost effectiveness in terms of dollars per pound of Hg removed from the application of ACI or other technologies and compare this to the costs of controlling a ton of NO x or SO 2 from power plants. For example, typical values of cost effectiveness are as follows: $ 5,000 to $ 30,000 per pound of Hg removed for ACI; $ 100 to $ 200 9 77 per ton of SO 2 removed; and $ 1,000 to $ 1,500 per ton of NO x removed. Obviously, the control costs appear high using such a comparison because Hg is emitted in far smaller quantities than conventional pollutants ( in the U. S., power plants currently emit " only" 48 tons per year of Hg; compared to 5 million tons per year of NO x and over 10 million tons per year of SO 2). Control costs for Hg on a pound for pound or ton for ton basis are therefore necessarily higher. However, it must be emphasized that Hg presents a far greater public health and environmental hazard on an equivalent mass basis when compared to criteria pollutants such as SO 2 and NO x.

A more illuminating metric for estimating true costs of technology for a project is when the costs of controlling Hg with a technology such as ACI are expressed in terms of cost to the ratepayer ( e. g., mills per kWh of electricity). When this approach is followed, the costs are even lower than the costs currently being incurred for control of pollutants such as NO x from EGUs. Note that these values for NO x are considered cost effective by industry and regulatory agencies, and were the basis for recent ( 1997 1998) state and federal requirements for wide scale NO x reductions from EGUs in the eastern U. S. under " Section 110 Transport SIP call" as well as the EPA's newly proposed ( on January 30, 2004) Clean Air Interstate Rule ( CAIR).

Response:

EPA's modeling of the final rulemaking includes presentation of results in several metrics including marginal cost and retail electricity prices. See Chapter 7 of Final CAMR RIA for further discussion of rulemaking analysis.

Comment:

The commenter,( OAR 2002 0056 5404), in response to EPA's request for comment regarding the various assumptions used for the modeling analyses conducted by EPA, CCAP, Cinergy, CATF and EEI, submitted that its analysis is based on the most accurate assumptions and therefore results in the most accurate predictions regarding compliance costs and the timing of emissions reductions expected as a result of EPA's proposed utility Hg rule. Moreover, the generic industry wide cost projections derived from the commenter's modeling are fully supported by the more recent company specific cost estimates completed as part of the commenter's cost recovery filings with its state utility commission. The commenter noted that other commenters modeled the effects of EPA's Hg utility rule using overly optimistic assumptions, which rendered overly optimistic conclusions regarding costs and achievability. According to the commenter, because their analysis is based on the most realistic assumptions, the commenter's analysis most accurately models the impacts of cost and timing associated with EPA's Hg utility rule.

The commenter noted that EPA recently published revised assumptions documentation used for its Integrated Planning Model ( IPM) Base Case 2004 ( v. 2.1.9). The commenter further noted that the major changes incorporated into EPA Base Case 2004 include the capital costs of Selective Catalytic Reduction ( SCR) retrofits, its gas price forecast, the number of plants available to switch to PRB coal, the cost and performance of new builds, and an update to particulate controls on existing units. However, according to the commenter, EPA has left unchanged a number of improbable assumptions that several commenters raised previously, including: the load 9 78 growth rate of 1.55 percent, the cost and performance of wet Flue Gas Desulfurization ( FGD) ($ 201/ kW), the cost and performance of Activated Carbon Injection ( ACI) and ACI and Fabric Filter ( FF), the Hg co benefits of FGD+ SCR, the Hg emissions modification factors, and model plant aggregations amongst others. Furthermore, according to the commenter, as EPA did not mention any revision to the way coal units are aggregated, it appears EPA still plans to perform MACT policy modeling runs without the capability of modeling plant level emission constraints. The commenter stated that this model plant aggregation change is of particular importance when analyzing Mercury MACT regulations that are implemented on a plant averaging basis. In performing its IPM modeling analysis, the commenter took particular care to represent the model plants in IPM along physical plant lines to capture the interactions that may occur between individual units at the plant level. The commenter believed that the lack of this resolution in the EPA analysis ( as well as analysis by other parties relying on the EPA version of IPM) represents a fundamental oversight in the studies performed. The commenter referred back to its Confidential Business Information ( CBI) Comments filed in March 2004 as to why disaggregating coal units to the plant level allows for more realistic assessments of plant level emission constraints.

Demand And Peak Growth The commenter noted that the starting point for the EPA Base Case 2004 electric load growth is the projections from the reference case of AEO 2004. The commenter stated that, as in the past, EPA reduced demand growth levels in the AEO projection to account for voluntary energy efficiency programs. According to the commenter, the average annual growth rate in AEO 2004, based on the electric sales forecasts, is 1.77 percent. The commenter stated that EPA revised this growth rate down to 1.55 percent. According to the commenter, this results in a final calculated growth rate that is unchanged from the EPA Base Case 2003. The commenter stated that, as it does with air quality modeling, EPA should not include in its future energy demand modeling legislative or regulatory provisions that have not already been adopted. According to the commenter, at a minimum, EPA should use the AEO growth rates or other historically based growth rates in its reference case and, if necessary, carry out sensitivity runs with higher and lower alternative energy growth patterns that bound potential future economic growth scenarios. The commenter referred back to its CBI Comments filed in March 2004 as to why the load growth rate it uses in its analysis much more closely reflects reality.

The commenter stated that EPA's lower average demand growth rates, and the resultant energy consumption, directly impact the system and the costs of regulation. The commenter further stated that the CCAP, in a number of sensitivities based on the EPA CSA scenario, directly uses the higher average annual growth rate projected by AEO 2003. The commenter noted that other modeling results provided in the NODA utilize higher average annual growth rates. The commenter assumed a 2.3 percent annual average load growth rate and EEI assumed a 1.7 percent average annual growth rate. According to the commenter, as the annual energy growth rate is compounded over the study period, a relatively small difference in the rate has enormous implications over time.

Natural Gas Prices Have Been Revised Upwards, But Not Enough The commenter noted that the EPA Base Case 2004 incorporates a higher natural gas forecast, with the Henry Hub wellhead price increasing, in 1999 dollars, to $ 3.16 in 2020 9 79 compared to $ 2.94 in the EPA Base Case 2003. According to the commenter, this revision of natural gas prices better represents the trajectory of natural gas prices going forward as evident in comparisons with the other natural gas forecasts utilized by EIA in its Annual Energy Outlook ( AEO) 2003 and 2004, as well as in the other models submitted by the commenter and the EEI in their comments. According to the commenter, though this revision has shifted the natural gas supply curve upwards, it still falls well below the other forecasts previously mentioned. The commenter noted that AEO 2003 predicts, in 1999 dollars, a price of $ 3.53 in 2020 and the difference between AEO and EPA becomes slightly more pronounced with a price of $ 4.03 in 2020 forecasted in AEO 2004. The commenter further noted that the forecast used in their modeling is comparable to AEO with a price of $ 3.45 in 2020 while EEI reaches $ 4.13 in 2020. The commenter referred to section II of its CBI Comments for a detailed description of how both the commenter and EPA derive their natural gas prices and how they differ. The commenter stated that gas price forecasts are important in analyses such as these as less expensive gas prices artificially alleviate the pressure on coal units to generate, and exaggerate the ease of which the system can inexpensively rely on new gas fired generation to make up the shortfall. The commenter further stated that over the past 12 to 24 months, various federal agencies and committees have investigated the short and long term implications of natural gas usage and price projections. According to the commenter, EPA has not provided a comparison of its estimates to other federal findings which show significantly higher prices and decreasing domestic supply. The commenter stated that EPA's final analysis of the impact of these rules should include a range of natural gas price forecasts based on potential real world implications if EPA's overly optimistic assumptions do not come true.

The commenter has noted that historical gas prices have been volatile, but have been consistently higher then forecasts made by EPA, a trend especially evident when comparing the gas prices EPA used during the late 1990s for analyzing the impact of SIP Call regulation on the industry. The commenter noted that the table below compares recent forecasts made by EPA to historical gas prices. According to the commenter, from 2000 through 2004 these periods overlap. The commenter stated that it is worth noting that when comparing actual 2000 2004 historical data to that forecast by EPA in its 1995 and 1998 assumptions, actual prices were approximately $ 4.29/ MMBtu, while the average of EPA's forecast over that same time period results in a price of less than $ 2.00/ mmBtu   a difference of over 100 percent.

Higher SCR Capital Cost Assumption The commenter stated that in the case of unit retrofit costs, especially SCR costs, the differences between EPA's estimates and the commenter's actual experience is quite substantial. The commenter stated that in the new EPA 2004 ( v. 2.1.9) assumptions, EPA increased its capital cost assumption of SCRs from $ 62/ kW to $ 83/ kW ( for a representative 500 MW unit). While the commenter believed this move is in the right direction, it does not come close to reflecting the actual costs of retrofitting such devices on existing generating units. The commenter's estimates for SCR costs were developed through the knowledge and experience gained during nine SCR retrofit projects totaling 6,000 MW of capacity. The commenter stated that these actual costs for compliance with the NO x SIP Call have been provided to their state utility regulatory commissions for review and approval. In May 2004, the commenter's regulated utility subsidiary in Indiana, PSI Energy, received approval of these same NOx pollution control retrofit costs. The commenter stated that EPA apparently has not verified its NOx control cost information by 9 80 comparing it with the most recent state utility regulatory commission cost recovery filings in states which have recently implemented the NO x SIP Call. The commenter also stated that it should be noted that the large number of SCRs retrofitted as a result of the SIP Call represents the more cost effective ( i. e., lower capital cost) units. The commenter added that EPA apparently has not considered the increasing difficulty, and thus the higher capital cost, of retrofitting increasingly smaller units as the NO x caps get tighter. The commenter referred to costs documented and made available to EPA in their past CBI comments.

No Changes To Cost And Performance Of Wet FGD And ACI and FF The commenter stated that with the updates included in the EPA Base Case 2004, the cost and performance of a Wet FGD and ACI and FF remain the same. According to the commenter, for a representative 500 MW unit, the capital cost of a Wet FGD is $ 201/ kW and $ 55/ kW for an ACI and FF. The commenter believed these capital costs continue to be significantly understated and emphasized that the cost assumptions used in its analysis, as documented and made available to EPA in the commenter's CBI Comments, Section V, more closely represent real world retrofit cost levels that will generally be experienced by the utility industry. The commenter noted that these retrofit costs were derived from engineering estimates by the Chicago firm, Sargent & Lundy, which has extensive experience in the design and application of these technologies.

The commenter stated that while the generic industry wide cost estimates provided in their past CBI comments indicate that EPA has significantly understated compliance costs, more recent analyses undertaken by the commenter provide further support for this conclusion. The commenter has recently started construction on a number of new wet FGD projects and has provided more refined cost estimates to the Indiana Utility Regulatory Commission ( PSI Energy Cause 42622 and 42718) identifying the Company's projected costs for complying with the proposed SO 2, NO x, and Hg reduction requirements. According to the commenter, the more highly refined commenter specific cost estimates provided to the Indiana Commission show costs in excess of the generic cost projections previously provided to EPA in the commenter's CBI Comments. The commenter urged EPA, at a minimum, to use their more representative cost estimates for pollution control retrofits which have been previously provided.

The commenter stated that EPA did not choose to update the emission reduction factors associated with these pollution controls from those assumed in the EPA Base Case 2003 ( v. 2.1.6). The commenter noted that on a unit with an exiting CESP particulate control, EPA continues to assume that a Wet FGD burning bituminous coal has an emission reduction factor of 66 percent compared with 59 percent assumed by the commenter. The commenter noted that the co benefit of a wet FGD combined with a SCR on a unit burning bituminous coal is assumed, by EPA to result in a 90 percent reduction of Hg. This is higher than the 85 percent co benefit that the commenter believed is achievable and sustainable, and has particular significance regarding the stringency of an Hg policy that is feasible without significant additional cost. The commenter stated that this difference is found across different existing particulate controls and once again highlights EPA's more aggressive assumptions for cost and performance of retrofit options. The commenter stated that more detailed information of their experience of the actual costs of these pollution control technologies can be found in Section V of their CBI Comments. According to the commenter, while EPA moderated some of its very aggressive assumptions for emission reductions factors ( ERF's) when updating from the EPA Base Case 2002 ( v. 2.1) to the EPA Base 9 81 Case 2003 ( 2.1.6), the commenter believed that this issue should have been readdressed in the latest update. According to the commenter, based on recent test data, EPA acknowledges the difficulties associated with the still overly aggressive co benefit assumptions it assumed in its 2003 and 2004 Base Cases ( v. 2.1.6 and v. 2.1.9), in the text of the NODA ( pg. 69871), particularly regarding sub bituminous coals. The commenter stated that, for example, for a unit configured with a coldside ESP and with a FGD and SCR, EPA recommends changing the ERF from 66 percent to 16 percent. The commenter believed that these updates should be incorporated into any future EPA modeling as they reflect actual results at test units. The commenter also noted that these changes will have a significant impact on the Hg reduction levels that can be achieved through co benefits, and therefore the cost of attaining Hg reductions system wide.

The commenter stated that one clarifying point must be made regarding their assumption of ACI availability. The commenter further stated that in the EPA NODA, Section 4, part D, EPA states that for the commenter's other modeled scenarios, including a MACT scenario, it assumed ACI would be available in 2005. The commenter stated that this is factually incorrect. According to the commenter, they modeled the availability of ACI beginning in 2007 for its policy scenarios, but believed that widespread commercial availability of ACI is not likely before 2010.

Other Major Assumptions The commenter stated that EPA recognizes the need for regular updating of model inputs to keep up with changing energy, environmental and macroeconomic markets and understanding of future conditions. The commenter further stated that, however, EPA has not taken this process to the next logical step which is an analysis of the accuracy of the models output. The commenter noted that in the case of air quality modeling the EPA has detailed guidance, Guideline for Air Quality Models, Appendix W ( July 2003) 40 CFR Part 51 on the application of models and testing the models output against known actual air quality measurements and conditions.

The commenter pointed out that the true test of a model's capabilities is when its output compares favorably, within an acceptable confidence interval, to actual observed data. According to the commenter, neither in this most recent IPM modeling nor in any case prior to that has EPA ever provided information about how the IPM modeling output compares to representative known energy or environmental outcomes in the real world. The commenter stated that in this most recent reference case modeling EPA skips over the recent historical years and the current year and does not even provide any model output results until 2007. The commenter further stated that, thus, affected sources have no way of checking the reliability of the models input assumptions or output when compared against historical or recent actual energy prices, allowance prices or SO 2, NO x or Hg emissions. The commenter added that these uncorroborated national, state or plant level emissions are the same emissions that are then used as inputs into the air quality models that EPA, and in some cases state regulatory agencies, use to evaluate in state source impacts as well as significant contribution impacts of long range interstate transport. The commenter stated that, thus, affected sources and decision makers have no basis for quantifying the accuracy, precision and sensitivity of the model to changes in model assumptions and ultimately in making emission control policy decisions. The commenter recommended that EPA provide an evaluation of the IPM model based on a systematic performance evaluation of a wide range of temporal and spatial outputs using current real world model inputs. 9 82 Table 1 details the major assumptions across each of the modeling described in the comments submitted by the commenter, CCAP, CATF, and EEI. The following section will lay out the implications of these assumptions on the results from these different modeling comments.

Table 1 Category Commenter 5404 EPA ( v. 2.1.6) EPA ( v. 2.1.9)

Source Commenter Assumptions Document 02.03.04 EPA Assumptions Updates v. 2.1.6, July 2003 EPA Assumptions Updates v. 2.1.9, October 2003 Energy and Peak Demand ( natl avg) 2.3% Demand Growth, 2.2% Peak Growth 1.55% Demand and Peak Growth no changes from 2.1.6 SO 2 Control Cost and Performance 500MW = $ 276/ kW (+ adders for MACT & timing) 500MW = $ 201/ kW no changes from 2.1.6 Nox Control Cost and Performance ( SCR) 500MW = $ 194/ kW 500MW = $ 62.15/ kW 500MW = $ 82.27/ kW SO 2 and NOX Controls for Mercury SCR+ FGD 85% Hg co benefit ( bit with CESP) SCR+ FGD average 90% Hg co benefit ( bit) no changes from 2.1.6 Mercury Control Cost and Performance ( ACI and Fabric Filter) 500MW = $ 95/ kW 500MW  $ 55/ kW no changes from 2.1.6 Reference Gas Price Forecast ( Henry Hub) 2005$ 3.92, 2010 $ 3.66, 2015$ 3.49, 2020$ 3.54 2005$ 2.89, 2010 $ 2.97, 2015$ 2.96, 2020$ 2.94 2010$ 3.20, 2015 $ 3.25, 2020$ 3.16 PRB Fuel Switching Capital, FO& M, and VO& M PRB adders into 3 separate size categories. Additional Adders for heat rate penalty and 5 yr amortization ( amortization CSA only) $ 50/ kW adder increased # of plants available $ 50/ kW adder Capital Charge Rate ( CCR) and Discount Rates ( DR) DR = 7.1%, CCR = 13.6%( retrofits) DR = 5.34%, CCR = 12.0%( retrofits) no changes from 2.1.6 Cost and Performance of New Builds Commenter cost and performance for gas units, ICF cost and performance for coal units Updated According to AEO 2003 Updated According to AEO 2004 Category Commenter 5404 EPA ( v. 2.1.6) EPA ( v. 2.1.9)

Source Commenter Assumptions Document 02.03.04 EPA Assumptions Updates v. 2.1.6, July 2003 EPA Assumptions Updates v. 2.1.9, October 2003 9 83 Mercury EMF EMF based on ICR data for all non commenter units. Commenter specified EMFs for commenter units. Updated Attachment K. Changes made to all types, most significantly to cobenefits for SNCRs and wet FGDs. no changes from 2.1.6 Plant Aggregation Model plant along physical lines Model Plant Model Plant Model Run Years 2004, 2006, 2007, 2008, 2009, 2011, 2015, 2020 2005, 2010, 2015, 2020 2005, 2010, 2015, 2020 Table 1 ( has different headings) Category CCAP CATF EEI ( CRA) Source EPA Assumptions v. 2.1.6, July 2003 EPA Assumptions Updates v. 2.1.6, July 2003 EEI Assumptions Energy and Peak Demand ( natl avg) EPA Assumptions Updates v. 2.1.6, July 2003, AEO 2003: 1.8% Demand and Peak Growth 1.55% Demand and Peak Growth 1.8% Demand Growth, 1.95% Peak Growth SO 2 Control Cost and Performance ( Wet FGD) 500 MW = $ 201/ kW 500 MW = $ 201/ kW 500 MW = $ 201/ kW Nox Control Cost and Performance ( SCR) 500MW = $ 62.15/ kW 500MW = $ 62.15/ kW 500MW = $ 62.15/ kW SO 2 and NO X Controls for Mercury SCR+ FGD average 90% Hg co benefit ( bit) SCR+ FGD average 90% Hg co benefit ( bit) SCR+ FGD average 85% Hg co benefit ( bit) Mercury Control Cost and Performance ( ACI and Fabric Filter) 500MW ~ $ 55/ kW 500MW ~ $ 55/ kW 500MW=$ 41.29/ kW Reference Gas Price Forecast ( Henry Hub) Various Scenarios used the following assumptions: 1) EPA ( v2.1.6) 2) AEO 2003, 2005$ 2.88, 2010 $ 3.29, 2015$ 3.55, 2020$ 3.69 2005$ 2.89, 2010 $ 2.97, 2015$ 2.96, 2020$ 2.94 2004$ 4.98, 2010 $ 3.33, 2015$ 4.06, 2020$ 4.13 Category CCAP CATF EEI ( CRA) Source EPA Assumptions v. 2.1.6, July 2003 EPA Assumptions Updates v. 2.1.6, July 2003 EEI Assumptions 9 84 PRB Fuel Switching $ 50/ kW adder $ 50/ kW adder 50% annual limit for noncurrent PRB fired units CCR and Discount Rates ( DR) DR = 5.34%, CCR = 12.0%( retrofits) DR = 5.34%, CCR = 12.0%( retrofits) DR = 6.05%, CCR = 13.32%( retrofits) Cost and Performance of New Builds Updated according to AEO 2003 Updated According to AEO 2003 Updated According to AEO 2004 Mercury EMF Updated Attachment K. Changes made to all types, most significantly to co benefits for SNCRs and wet FGDs. Updated Attachment K. Changes made to all types, most significantly to co benefits for SNCRs and wet FGDs. Hg co benefits based on EPA's 1999 ICR data. ACI assumptions from EPRI Plant Aggregation Model plant Model Plant Unit Groups Model Run Years 2005, 2010, 2015, 2020 2005, 2010, 2015, 2020 2004, 2008, 2010, 2012, 2015, 2018, 2020 The commenter reviewed the modeling results provided to EPA by other parties during the comment period. The commenter noted that the majority of parties filing power sector modeling results seem to agree that demand growth and natural gas price assumptions used by EPA warrant modification, and so use assumptions from other sources in their model runs. The commenter stated that it is extremely important to emphasize that in long term planning models, such as the IPM model used by the parties to analyze the cost of new regulations, model input assumptions regarding demand growth and natural gas prices dramatically affect overall costs of regulation. The commenter stated that these assumptions should be further considered by EPA as it proceeds with its rulemaking. The commenter provided comments on some individual party modeling as indicated below.

Modeling Results Provided by CCAP The commenter stated that CCAP produced more than a dozen runs that seem to demonstrate that timing and stringency of Hg caps have little bearing on the cost of regulation. The commenter also stated that it should be noted that the runs performed by CCAP were based on the EPA modeling runs that analyzed the proposed Clear Skies Amendments and do not specifically model the CAIR rule as proposed. The commenter stated that the results are therefore not directly comparable to any of the modeling analyses performed by EPA in the course of this rulemaking. The commenter therefore focused its comments on the conclusion that timing and stringency of Hg caps, in general, are not very significant.