While Hg reductions will take place through the expanded use of co benefit technology as required by CAIR, and promising Hg specific technology is under development, it is premature to set a MACT, NSPS standard, cap, or emission allowance allocations because of the lack of reliable data on Hg emissions and the performance of control technology. It would be arbitrary and unreasonable to base an emissions standard on the hypothetical performance of unproven technology.

To the extent that EPA relies on EMFs for modeling purposes, those factors should be conservative enough to allow for the various sources of variability and uncertainty associated with co benefit removal rates on different coal types. Where co benefit reductions are the product of speculation within a range the commenter recommended a conservative estimation of the EMF at the low end of the range; where evidence exists that co benefit reductions are not being achieved, the commenter recommended an EMF of 1 ( i. e., no co benefit reductions). The commenter noted the results of a recent study conducted by the Energy and Environmental Research Center using a slipstream SCR unit at one lignite fired power plant to determine the ability of new and aged catalyst to oxidize Hg. The results indicate " limited oxidation of Hg across the SCR catalyst 9 125 when firing lignite coals" and that the sulfation of calcium and sodium ash deposits foul the catalyst rendering the SCIR   technology ineffective for NO x control. An article describing the findings has been accepted for publication in Fuel Processing Technology. A copy of the " article in press" entitled, " SCR catalyst performance in flue gases derived from subbituminous and lignite coals" is attached ( see e docket text, Attachment 1).

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 first phase cap is based on EPA modeling of the Hg co benefits of SO 2 and NOx controls installed for compliance with the CAIR rulemaking. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for discussion of emissions projections. As discussed in the NODA, for the final rulemaking analysis, EPA has made changes to some of its co benefit assumptions for subbituminous units with SCR and FGD controls. EPA is also using a newer version of EPA's IPM for the final rulemaking. Changes to the modeling assumptions can found in the IPM documentation in the rulemaking docket ( see Documentation Summary for EPA Base Case 2004 ( v. 2.1.9) Using the Integrated Planning Model, EPA, October 2004).

EPA projections of Hg co benefits are based on 1999 Hg ICR emission test data and other more recent testing conducted by EPA, DOE, and industry participants. Overall the 1999 Hg ICR data revealed higher levels of Hg capture for bituminous coal fired plants as compared to subbituminous and lignite coal fired plants and a significant capture of ionic Hg in wet FGD scrubbers. Additional Hg testing indicates that for bituminous coals SCR has the ability to convert elemental Hg to ionic Hg and thus allow easier capture in a wet FGD scrubber. This understanding of Hg capture was incorporated into EPA modeling assumptions and is the basis for our projections of Hg co benefits from installation of scrubbers and SCR under CAIR. ( For further discussion see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005, in the docket).

Comment:

One commenter ( OAR 2002 0056 5502) state that estimated emissions in 2010 after co benefits of CAIR alone are realized remain in the range of 39 40 tons. Variations of the assumptions in EPMM that affect its estimate of co benefits, accounting for new information from the commenter and other researchers, did not produce any significant change from the level of 39.9 tons that was reported in the earlier submittal.

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. 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. The first phase cap is based on EPA modeling of the Hg co benefits of SO 2 and NOx controls installed for compliance with the CAIR 9 126 rulemaking. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for discussion of modeling analysis.

Comment:

One commenter ( OAR 2002 0056 5460) stated that EPA should not be concerned with the co benefits of Hg reductions associated with implementation of the proposed CAIR. The commenter further stated that EPA is required to regulate power plant Hg emissions pursuant to Section 112 regardless of what CAIR may accomplish. The commenter added that, indeed, it is required to do so promptly, both under the plain language of the Clean Air Act and under a consent decree between EPA and the Natural Resources Defense Council ( NRDC). See 42 U. S. C. § 112( c); OAR 2002 0056 3459 ( NRDC comments) ( describing consent decree). The commenter stated that given these requirements, and given EPA's own admission that CAIR may never become law, EPA should not continue to focus on the hypothetical consequences of CAIR.

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. 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. The first phase cap is based on EPA modeling of the Hg co benefits of SO 2 and NOx controls installed for compliance with the CAIR rulemaking. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for discussion of modeling analysis.

Comment:

One commenter ( OAR 2002 0056 5548) stated that CRA's 2004 EMF data ( EEI data) better reflect current knowledge than EPA's, but should be modified as discussed below based on our more recent data. The commenter believed that EPA must augment and modify these EMFs using all available data that meet appropriate experimental quality criteria. In that context, the commenter reiterated their comment made on the initial proposal that much of the ICR Part III emissions data on which EPA has relied heavily does not meet reasonable tests of data quality and should be discounted, if only to meet EPA's stated objectives and obligations under the Data Quality Act.

CONSOL Energy Inc., in cooperation with the U. S. Department of Energy's National Energy Technology lab ( DOE NETL), the Ohio Coal Development Office ( OCDO), the Illinois Clean Coal Institute ( ICCI), and the Electric Power Research Institute ( EPRI), has conducted an extensive test program to measure Hg speciation and emissions on coal fired boilers with wet and dry Flue Gas Desulfurization ( FGD) with and without Selective Catalytic Reduction ( SCR) equipment. All of the units burned bituminous coal, and all but one of the wet FGD units had an ESP for particulate control. Speciated measurements of Hg in the flue gas were made across the particulate control device as well as the FGD, and in the case of SCR equipped units, ahead of the SCR. Appendix A provides detail on each unit, including the type of FGD, SCR and particulate 9 127 collection device, and citations to more complete reports of the various tests. The Ontario Hydro Method ( OHM) was used for all of these tests with the exception of the Hg removal across the ESP which was based on the Hg content of the ESP fly ash.

One important criterion for assessing the accuracy of Hg emission measurements is a material balance ( notably lacking in the ICR Part III data), wherein the Hg content of the coal is measured and compared against the sum of the stack Hg emissions and the Hg contents of all process streams that contain Hg including such streams as the bottom ash, ESP ash, FGD solids, and mill reject pyrites. All of the data contained in Appendix A and summarized below have a material balance closure of ± 120 percent thus assuring a high degree of data quality.

Table 1 below lists each unit's emission control devices, the Hg removal across the ESP, the total ( coal to stack) Hg removal and the average Hg removal for various emissions control configurations. 9 128 Table 1. Mercury Removal, Various Pollution Control Configurations Bit Coal Plants SCR Part. Control Device FGD % Hg Removal across ESP % Hg Removal Coal to Stack 1 Yes FF Lime Spray Dryer 87.3 ± 3.4 2 Yes FF Lime Spray Dryer 94.6 ± 0.3 Average percent Hg Removal for SCR/ FF/ FGD 91.06 ± 5.2 5 Yes ESP Limestone, in situ Oxidation 17 85.8 ± 2.8 6 Yes ESP Limestone, in situ Oxidation 24 88.2 ± 4.2 7 Yes ESP Limestone, in situ Oxidation 6 83.6 ± 2.7 8 Yes ESP Mg Lime, ex situ Oxidation* 71.6 ± 5.2 9 Yes ESP Mg Lime, Inhibited Oxidation 86.7 ± 2.8 10 Yes ESP Mg Lime, Inhibited Oxidation 89.2 ± 3.6 11 Yes Vent. Scrub Mg Lime Vent., Scrub. Inhib. Oxidation 85.1 ± 1.7 Average percent Hg Removal for SCR/ CS ESP/ FGD 15.7 ± 9.1 86.1 ± 2.1 13 No ESP Limestone, in situ Oxidation 48.7 ± 4.5 14 No ESP Limestone, in situ Oxidation 23 74.6 ± 1.4 17 No ESP Mg Lime, Nat. Oxidation 24.0 ± 11 66 ± 3 18 No ESP Limestone, in situ Oxidation 7.0 ± 2.0 56.0 ± 6 19 No ESP Limestone, Nat. Oxidation 13.0 ± 2.0 72 ± 9 21 No ESP Limestone, Nat. Oxidation 9.0 ± 1.0 67 ± 3 22 No ESP Mg Lime, Nat. Oxidation 11.0 ± 6.0 63 ± 4 Average % Hg Removal for CS ESP/ FGD 14.5 ± 7.3 63.9 ± 9.0 12 Yes ESP 13 19.6 ± 20.7 * 15 percent of flue gas is bypassed around FGD. Calculated percent Hg removal would be 84 percent.

This commenter and others stated that EPA must consider coal and process variability in any MACT, cap or allowance allocation determination. In each of the tests shown in Table 1, 9 129 four OHM tests were performed over a two to three day period. The variability evident from the test results over this short period of time is significant and must be considered by EPA. The standard deviation for SCR/ FGD equipped units is 2.1 percent, indicating a relatively small variability among these measurements. The Hg removals from the FGD only units have a standard deviation of 9.0 percent, indicating a greater variability among these units. Based on the test variability shown at each unit and the variability between units, the commenter believed that EPA must use a conservative EMF number to allow for the margin of variability inherent in both the Hg measurements and the performance of coal fired units due to coal Hg content and process control. Therefore, the commenter recommended that EPA use EMF values reflecting the performance at the lower bound of a confidence interval calculated as one standard deviation about the average. Table 2 below compares the EMF's calculated in this manner from the data in Table 1 above to the EMF's provided by EPA in Table 5 of the NODA.

Table 2. EMF Comparisons Name of Control EPA 2003 EMFs CRA 2004 EMFs EIA AE02004 EMFs CONSOL Energy EMFs Bit EMF Bit EMF Bit EMF Bit EMF PC/ CS ESP 0.64 0.65 0.64 0.93 PC/ CS ESP/ FGD 0.34 0.40 0.34 0.45 PC/ CSESP SCR/ FGD 0.10 0.15 0.10 0.16 PC/ FF/ SCR/ FGDDry N/ A N/ A N/ A 0.14 PC/ SCR/ ESP N/ A N/ A N/ A 0.80 The commenter believed that the EMFs for the wet FGD units are similar, though somewhat greater than those proposed by CRA. One notable difference is the EMF for CS ESPonly units. Because of the interest in Hg reduction as a co benefit of NO x and SO x controls, there has been relatively little done to characterize emissions from this, the most common class of unit in use now. As the commenter noted in their June, 2004 comments on the initial proposal, these units were highly under represented in the ICR Part III database. The commenter believed that EPA should revise the estimated EMF for these units to 0.93, based on the results presented here.

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. 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 first phase cap is based on EPA modeling of the Hg co benefits of SO 2 and NOx controls installed for compliance with the CAIR rulemaking. See final rule preamble for rationale and Chapter 7 of final CAMR RIA for discussion of emissions projections. As discussed in the NODA, for the final rulemaking analysis, EPA has made changes to some of its co benefit assumptions for subbituminous units with SCR and FGD 9 130 controls. EPA is also using a newer version of EPA's IPM for the final rulemaking. Changes to the modeling assumptions can found in the IPM documentation in the rulemaking docket ( see Documentation Summary for EPA Base Case 2004 ( v. 2.1.9) Using the Integrated Planning Model, EPA, October 2004).

EPA projections of Hg co benefits are based on 1999 Hg ICR emission test data and other more recent testing conducted by EPA, DOE, and industry participants. Overall the 1999 Hg ICR data revealed higher levels of Hg capture for bituminous coal fired plants as compared to subbituminous and lignite coal fired plants and a significant capture of ionic Hg in wet FGD scrubbers. Additional Hg testing indicates that for bituminous coals SCR has the ability to convert elemental Hg to ionic Hg and thus allow easier capture in a wet FGD scrubber. This understanding of Hg capture was incorporated into EPA modeling assumptions and is the basis for our projections of Hg co benefits from installation of scrubbers and SCR under CAIR. ( For further discussion see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005, in the docket)

Comment:

One commenter ( OAR 2002 0056 5548) stated that by definition, co benefit reductions occur anyway as a result of control technologies installed to meet the CAIR. Hence, it is unnecessary to establish a cap to achieve Hg reductions through co benefits.

As the commenter noted in their initial comments, because co benefit Hg reductions will occur anyway, EPA's better course is to measure precisely what these co benefits are, and use that information to set an interim cap in 2012, that would be effective in 2015. Setting the initial cap in 2012 allows EPA to quantify the precise amount of co benefits reductions, and also allows EPA to dispense with its grossly unfair coal rank allowance allocation " adjustment" factors, since no such adjustments would be needed in the absence of an initial 2010 cap. As well, by 2012, EPA will be able to properly assess the performance of new Hg specific control reduction technologies such as ACI to reduce Hg emissions across all coal ranks. The commenter was confident that the technology will show that roughly equal removal levels can be achieved across all coal ranks. Hence, EPA would not be justified in establishing allowance allocation adjustment factors for any subsequent cap.

The commenter noted that the EEI's modeled " Alternative Hg Trading" scenario outlined in the NODA generally follows this approach by establishing no first phase co benefits cap, and setting an initial firm cap ( 24 TPY) in 2015. Because the EEI proposal would allow banking of early reduction credits above co benefits, the eligibility of actions that qualify for early reduction credit would need to be defined. However, this early reduction and banking system is wholly discretionary, and consequently there is no need to adjust allocation of allowances by coal rank to implement it since there is no specific obligation by any individual source to reduce Hg emissions to a pre determined level.

Response: 9 131 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 cap and trade program will include a provision for banking. See final rule preamble and Chapter 5 comment responses for further discussion of banking. EPA is not including a provision for early reduction credits in the final rulemaking. See Chapter 5 response to comments for further discussion of ERCs.

8. More recent test data on subbituminous coal fired units equipped with SCR indicate that SCR does not enhance the oxidation of Hg0 on such coals and, thus, does not provide for additional capture in a wet scrubber ( OAR 2002 0056 1268,  1270). Based on these data, EPA is considering revising the emission modification factor ( EMF) for subbituminous coal fired units equipped with SCR and wet FGD in the IPM model. EPA recommends use of the EMF control combination before an SCR is added ( i. e., ascribe no additional control due to the addition of the SCF). EPA requests comments on these proposed changes: for CS ESP/ SCR/ FGD, use CS ESP/ FGD ( 0.84); for FF/ SCR/ FGD, use FF/ FGD ( 0.27); and for HSESP SCR/ FGD, use HS ESP/ FGD ( 0.80). EPA also requests comment on the appropriateness of using other test data ( DOE and EPRI tests) for EMF development and asks commenters to submit any relevant data.

Comment:

One commenter ( OAR 2002 0056 5475) mentioned that EPA may rely on information gleaned from reports that were not available for public review prior to the end of the comment period. The commenter recommends that any reports, or studies, relied upon in making determinations relevant to the Hg rule be made available for public review.

Response: EPA projections of Hg co benefits are based on 1999 Hg ICR emission test data and other more recent testing conducted by EPA, DOE, and industry participants. This testing is summarized in reports by EPA, DOE and others and are available on EPA's website. In addition a comprehensive summary of this test was prepared by EPA's Office of Research and Development ( ORD) assessment and made available in the docket at time of the proposal. available in For the final rule ORD has prepared an updated assessment ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005, in the docket).

Comment:

One commenter ( OAR 2002 0056 5482) stated that in August 2003, a pilot scale SCR reactor was installed at a Fort Union mine mouth lignite fired EGU located in North Dakota. The study was conducted by the Energy and Environmental Research Center ( EERC) to determine the ability of new and aged catalyst to oxidize Hg at full scale EGUs. The results indicate that SCR technology was not effective in oxidizing Hg and that the sulfation of calcium and sodium ash 9 132 deposits foul the catalyst rendering the SCR technology ineffective for NO x control.

An article describing the findings has been accepted for publication in Fuel Processing Technology. A copy of the " article in press" entitled, " SCR Catalyst Performance in Flue Gases Derived from Subbituminous and Lignite Coals" can be downloaded from the EERC ftp site: ftp:// ftp. undeerc. orglbenson/ .

The article is also available online via Science Direct in the " Articles in Press" section for the following title: http:// authors. elsevier. com/ sd/ article/ S0378382004001870 .

Response:

EPA has examined the commenter's analysis in context of the final rulemaking. EPA's modeling Hg co benefit assumptions already assume that SCR does not enhance Hg control for lignite plants.

Comment:

One commenter ( OAR 2002 0056 5482) noted that Table 5 of the NODA, " Hg Removal Assumptions for Pollution Control Equipment," identifies lignite EMF factors for various EGU pollution control configurations. As noted in the above EERC study and EPA's acknowledgment of a lack of SCR elemental Hg reduction co benefits for subbituminous coal ( similar to Fort Union lignite), the this commenter recommends an EMF factor designation of 1.0 or " NA" ( not applicable) for all Fort Union EGU pollution control configurations employing SCR.

As previously noted, elemental Hg is the predominant form of Fort Union Hg emissions and conventional air pollution control equipment provides little or no incidental removal. An important factor impacting EMF values is the high variability of Hg and important species such as chloride and alkali. The interplay of the chemical factors coupled with EGU operation variations would not justify an EMF factor of less than 1.0. The EMF factor of 0.56 for configuration PC/ CS ESP/ FGD is not representative of Fort Union lignite EGU emissions.

The commenter recommends an EMF factor of 1.0 be employed for PC/ CS ESP/ FGD, similar to the PC/ CS ESP, FF/ FGD Dry and PC/ FF configurations.

No Fort Union configurations of PC/ CS ESP/ FGD Dry are known. The commenter recommends an EMF factor designation of " NA."

The commenter also recommends an EMF factor of " NA" for all PC/ HS ESP pollution control configurations since the technology is not applicable or utilized by Fort Union EGUs.

Response:

EPA projections of Hg co benefits are based on 1999 Hg ICR emission test data and 9 133 other more recent testing conducted by EPA, DOE, and industry participants. EPA believes the lignite factors used for final rulemaking analysis are supported by ICR test data. ( For further discussion see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005, in the docket.)

Comment:

One commenter ( OAR 2002 0056 5446) stated that in order to provide a level playing field any " cap and trade" type regulatory approach must include appropriate allocation factors. The factors currently proposed by the EPA, 1.0 for bituminous, 1.25 for subbituminous and 3.0 for lignite do not adequately address this issue. Even the EPA states that these factors are only " directionally correct," this is a completely inadequate basis for setting a regulatory standard.

Furthermore, assessment of the EMFs used in the different models indicates that these allocation factors are likely to be inadequate. For the most common generating configuration ( PC/ CS ESP representing approximately 59 percent of generating capacity) the EPA and EIA assume a 36 percent Hg reduction for bituminous coal and a 3 percent reduction for subbituminous coal, CRA assumes a 35 percent reduction for bituminous coal and a 20 percent reduction for sub bituminous coal. For the second most common configuration ( PC/ CS ESP/ FGD representing approx 16 percent of capacity) the EPA and EIA assume a 66 percent Hg reduction for bituminous coal, and a 16 percent and 27 percent reduction respectively for subbituminous coal. Even when adjusted for average Hg content of bituminous and subbituminous coals these reduction factors imply that the allocation factor for subbituminous coal should be higher that the 1.25 proposed by the EPA.

However given the wide range of uncertainty in the reduction factors ( e. g., a reduction factor of between 3 percent and 20 percent for PC/ CS ESP with sub bituminous coal) basing allocation factors on the relative proportions of elemental Hg produced by the different coal ranks is likely to be a more robust approach.

Because the amount of elemental Hg produced effectively reflects the difficulty of control, factors based on elemental Hg content are more likely to result in an even distribution of the compliance burden between coal ranks in the long term. However, because plant configuration also affects Hg capture and as subbituminous coal is typically burned in plant configurations that produce little co benefit capture ( e. g., plants with dry scrubbers) a subbituminous factor based purely on elemental Hg content will be inadequate to avoid fuel switching in the short term. As per our original comments, factors of 1.0 for bituminous, 1.9 for subbituminous and 2.95 for lignite, as proposed by the industry majority during the CAAAC process, appear to be the most appropriate. These factors have been calculated from the floors developed by industry majority position, which included representatives from the unions, the major coal producing regions and a large proportion of the electric utility industry.

Testing to date indicates that the presence of an SCR does not enhance Hg removal from sub bituminous coals. Therefore, the commenter strongly supports the EPA's recommendation 9 134 that the EMF assume that the presence of an SCR provides no additional Hg control for sub bituminous coals.

Response:

As discussed in the Chapter 5, section 5.6.1, EPA is finalizing coal adjustment factors for the purpose of establishing state emission budgets of 1.0 for bituminous coals, 1.25 for subbituminous coals, and 3.0 for lignite coals. 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 EPA should draw upon whatever data is available, provided appropriate data quality controls have been applied. In this regard, however, the commenter again drew attention to the problems with EPA's use of the ICR Part III data set, as outlined in their May 14, 2004 comments. In particular, the commenter noted their concerns associated with EPA's use of short term test data. Great care should be taken to account for the uncertainty and variability in coal quality, unit operation, and to the variable performance of pollution control devices. The commenter does not believe that the large degree of uncertainty incorporated by these variables can be adequately attenuated through short term tests performed on a limited number of units, coal types, plant configurations and operating conditions. To resolve these problems, EPA should institute a comprehensive test program, as elsewhere described in these comments.

Response:

EPA has used the best data were possible in developing its analysis for the final rulemaking. 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's ( OAR 2002 0056 5492) question: EPA is considering making three changes to the subbituminous coal EMF used in the IPM: for CS ESP/ SCR/ FGD use CS ESP/ FGD (. 84); for FF/ CR/ FGD use FF/ FGD (. 27); and for HS ESP/ SCR/ FGD use HS ESP/ FGD (. 8). EPA is seeking comments on these proposed changes.

In the NODA, EPA cites two literature references: OAR 2002 0056 1268 and OAR 2002 0056 1270. These two references cite the same source data, based on a single test. The two reports are using information developed and reported in an EPRI report. In the report, EPRI and their contractor point out several exceptions to standard flue gas sampling procedures. First, the samples are single point and are not a full or even a partial traverse of the duct. Flue gas 9 135 stratification could mean that the observations are not representative of the entire flue gas stream. Second, only duplicate flue gas Hg samples were obtained. In all EPA methods, samples are obtained in triplicate. The authors state that ". . . the data set presented here is small, so the reader should exercise caution in extrapolating the results. . . ."

In addition, the authors state that " an increase in oxidized Hg from 8 percent to 18 percent ( occurred) across the SCR." They go on further to state " Consequently, Hg capture across the ESP increased from 60 percent to 78 percent as a result of SCR operation." The authors statements in the cited reports do not support EPA's conclusion that " SCR does not enhance the oxidation of Hg." The commenter respectfully suggested that the proposed changes are unwarranted based on the data submitted by EPA.

Question: EPA is seeking comment on the appropriateness of using other test data for EPM development and requests commenters submit any test data that may be relevant.

The Department of Energy has operated a COHPAC system for Hg removal at the Southern Company Gaston Station which fired a low sulfur bituminous coal for about one year. At an injection concentration of 0.55 lb/ mmacf and using 2.7 denier bags, over a four month period the average Hg removal was 86 percent. During shorter term tests using higher denier bags, 7 denier, it was possible to achieve greater than 90 percent Hg removal. The weekly average Hg removals observed at the Gaston site are presented in e docket text.

In addition to the COHPAC tests, additional tests were conducted using activated carbon injection on CS ESP and SCR/ dry FGD units firing subbituminous coals. For example, at the subbituminous coal fired Sunflower Electrics Holcomb Station which is equipped with a SCR/ dry FGD system, over 90 percent Hg reduction was achieved for the entire 4 week test period.

In addition, there have been tests at Pleasant Prairie Station that fires a subbituminous coal and is equipped with a CS ESP. At an injection rate of 11 lb/ mmacf, 73 percent Hg removal was reported.

Additional tests were completed on both bituminous and subbituminous coals. There are a number of publications listed at the following web address: www. adaes. com under " Publications" on the tool bar. There have been at least four full scale evaluations of ACI on PRB coal fired units ( Holcomb Arapahoe ( two tests), Meramec) and four tests on lignite fired boilers( Antelope Valley, Stanton 1, M. R. Young, and Monticello).

Response:

EPA appreciates the commenter's 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). 9 136 Comment:

One commenter ( OAR 2002 0056 5502) referenced co benefits and agreed with EPA's proposal to assign no co benefit to the addition of an SCR at a site with an SO 2 control that is burning a western fuel. This is generally supported by the small, but growing, body of data available to date. These data are provided in the detailed comments, as are suggested EMFs for a number of fuel/ air pollution control configurations.

Power plants firing a bituminous coal can expect to experience oxidized Hg fractions in the flue gas entering the FGD that range from 75 90 percent   i. e., high but not necessarily always in the 90 percent range. There does not appear to be a significant increase in Hg oxidation for PRB coals, and potential low chloride bituminous coals.

Response:

EPA projections of Hg co benefits are based on 1999 Hg ICR emission test data and other more recent testing conducted by EPA, DOE, and industry participants. EPA believes the factors used for final rulemaking analysis are supported by test data. EPA's Hg co benefit assumptions can found in the IPM documentation in the rulemaking docket ( see Documentation Summary for EPA Base Case 2004 ( v. 2.1.9) Using the Integrated Planning Model, EPA, October 2004). 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 5535) said that in conducting the various modeling exercises, different stakeholders used different emission modification factors ( EMF) to calculate the Hg co control benefits of different NO x and SO 2 controls. The EPA requests comments on what EMF are appropriate. As shown in Table 5 of the NODA, there are differences in EMF the agency has developed and those used by Charles River Associates ( CRA) for industry stakeholder modeling. The commenter noted that the EMF used by CRA are consistently lower than the EMF developed by EPA, that is, they result in less co control of Hg emissions than assumed by EPA. The result, not surprisingly, is that industry stakeholders estimate that Hg emissions will be higher after implementation of CAIR requirements than EPA has stated. Because EPA has proposed to establish the first phase of its pollution trading scheme to reflect reductions achieved as a co benefit of CAIR, the effect of industry's suggested EMF changes would be to inflate the initial Hg cap, making it easier to meet without significant control, or making it easier for companies to bank allowances for future use.

With the exception of new data on the effects of SCR on Hg oxidation when subbituminous coals are fired, the commenter saw no new information in the other commenter's remarks that should lead EPA to change the EMF in the IPM. EPA developed the existing EMF after analyzing the extensive ICR data set. In contrast, there are no new analyses of Hg 9 137 co control presented by other commenters. Thus, EPA need not revise its EMF, despite the desire of industry stakeholders to raise the first phase Hg cap. With respect to EPA's intention to revise the EMF associated with the use of SCR with subbituminous coals, the agency does not provide sufficient information for us to comment on whether this is a legitimate action. The agency merely refers to " more recent test data." EPA must submit to the docket all of the test data along with the agency's analysis of such test data in support of any such changes to the EMF. Revising the EMF associated with the use of SCR with subbituminous coals without making such data and analysis publicly available would be arbitrary.

Fourth, EPA also mentions Hg speciation in the context of conducting economic modeling with the IPM. With respect to the use of different speciation profiles in the IPM, EPA notes that the national estimate of emissions of the three forms of Hg is Hg0   54 percent, Hg+ 2   43 percent, and Hgp   3 percent. The agency states that plant specific estimates based on these data were used in the IPM modeling activities. The IPM should not be revised with respect to Hg speciation. To the extent that different speciation profiles have been estimated for different coal types and control device configurations, these data have already been incorporated into the IPM through the use of EMF. The EMF are average control levels that are calculated from average Hg and chlorine levels in coal and averages of test data, so the use of average speciation profiles in the IPM model is appropriate. The commenter noted however, that EPA could and should improve the speciation profiles used in deposition modeling, as discussed above.

Response:

EPA projections of Hg co benefits are based on 1999 Hg ICR emission test data and other more recent testing conducted by EPA, DOE, and industry participants. This testing is summarized in reports by EPA, DOE and others and are available on EPA's website. In addition a comprehensive summary of this test was prepared by EPA's Office of Research and Development ( ORD) assessment and made available in the docket at time of the proposal. For the final rule ORD has prepared an updated assessment ( see Control of Emissions from Coal Fired Electric Utility Boilers: An Update, EPA/ Office of Research and Development, March 2005, in the docket). With regard to speciated profiles, IPM modeling includes only total Hg emissions projections as output. EPA than post processes IPM unit level results to determine the speciated form of Hg at the unit level. This information is than used in deposition modeling. The determination on speciated emissions is based on 1999 ICR data.

Comment:

One commenter ( OAR 2002 0056 5548) noted that EPA was considering revising the EMFs for subbituminous coal fired units equipped with SCR and wet FGD. After reviewing the literature cited by EPA to support this change and discussing the supporting data with EPA R& D and EPRI, the commenter did not believe that the available data support the proposed changes. First, there are not two independent literature sources as cited by EPA in the NODA. These two papers simply report the same information from a single set of measurements on a PRB coal fired unit, equipped with an SCR, a CS ESP, originally reported in EPRI Report 1005400 dated 9 138 December 2002. Notably, although EPA proposes to use these data to modify the EMFs for FGD equipped units, the one test cited in these two reports was done on a unit with no FGD. It also is noteworthy that the report states, " Caution is urged in drawing conclusions from this limited set of data. The results are based on short term tests that might be misleading due to the potential for substantial variation in total and speciated mercury concentration." Moreover, the results do show a significant increase in oxidized Hg across the SCR ( from 8 percent to 18 percent), and a total Hg removal ( 78 percent) for a SCR CESP unit. The commenter believed that the proper manner to evaluate the effect of SCR operations is the impact on total Hg removal. These results, the only ones that EPA cites, indicate that a boiler equipped with an SCR CS ESP combination firing a subbituminous coal can achieve a 78 percent Hg reduction. One of the cited references states " Consequently, mercury capture across the ESP increased from 60 percent to 78 percent as a result of SCR operation." The EPA, DOE, and EPRI authors ascribe a significant increase in Hg removal to the SCR operation. The cited literature does not support EPA's contention that they should "... ascribe no additional control due to the addition of the SCR..." Rather the cited papers state that the operation of the SCR improved total Hg capture.

The commenter added that in addition to the papers cited by EPA in the NODA, there was a joint study conducted by EPA R& D and EPRI at the Texas Genco WA Parish Station. ( The final report is in draft.) The Parish Station burns subbituminous coal and is equipped with an SCR/ FF/ wet FGD air pollution control system. This system achieved 64 percent Hg control with the FF/ wet FGD in operation. With the SCR/ FF/ wet FF/ wet FGD in operation, the Hg removal increased to 79 percent. Again the operation of the SCR significantly increased the co benefit Hg removal of the air pollution control system.

In the commenter's opinion the literature provided no supporting information for the proposed changes to the EMFs. Instead, it indicates that the EMF for subbituminous coal fired units equipped with CS ESP/ SCR/ FGD should be 0.2, and for units equipped with SCR/ FF/ FGD should be between 0.2 and 0.3.

Response:

EPA projections of Hg co benefits are based on 1999 Hg ICR emission test data and other more recent testing conducted by EPA, DOE, and industry participants. EPA has assumed for the final rulemaking analysis that for subbituninous fired units that SCR has the no ability to convert elemental Hg to ionic Hg and thus allow easier capture in a wet FGD scrubber. EPA is thus using the emission modification factors for CS ESP/ SCR/ FGD, use CS ESP/ FGD ( 0.84); for FF/ SCR/ FGD, use FF/ FGD ( 0.27); and for HS ESP/ SCR/ FGD, use HS ESP/ FGD ( 0.80). EPA EPA's Hg co benefit assumptions can found in the IPM documentation in the rulemaking docket ( see Documentation Summary for EPA Base Case 2004 ( v. 2.1.9) Using the Integrated Planning Model, EPA, October 2004). 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). 9 139 Comment:

One commenter ( OAR 2002 0056 5497) stated that the different levels of Hg co benefits predicted from implementation of the CAIR rule are hardly surprising. The 1999 Information Collection Request ( ICR) stack testing results, which serve as the basis for most emission modification factors, showed highly variable Hg removals in plants equipped with the same control equipment. In addition, predicting the level of Hg co benefits resulting from the CAIR rule requires one to estimate the effects of SCRs on Hg removal. Mercury testing of SCRs is limited and questions remain about a number of factors that may affect the amount of elemental Hg that is converted to ionic Hg in an SCR. As a result of these uncertainties, it is impossible to predict the true co benefits that will be achieved from implementation of the CAIR rule. As was described in the preceding response, the commenter believed that instead of trying to set a " hard" cap based on co benefits in 2010. EPA would be better served by imposing a " soft" cap and commencing trading in 2015.

The commenter agreed with the Electric Power Research Institute ( EPRI) that many of the EMFs should be revised, in most cases very slightly, to reflect additional information that has been received since EPA last ran its IPM model. For example, for bituminous coals, the commenter recommended these changes:

° CS ESP/ wet FGD: Revise EPA's EMF from 0.34 to 0.40 because six additional test results have doubled the database.

° SCR/ CS ESP/ wet FGD: Revise EPA's EMF from 0.10 to 0.15 based upon ICR measurements and recent SCR/ FGD co benefits tests.

For other configurations ( e. g., SCR/ FF/ wet FGD and SCR/ FF/ dry FGD) the commenter believed that no change is justified. A complete list of our recommendations is attached.

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 projections of Hg co benefits are based on 1999 Hg ICR emission test data and other more recent testing conducted by EPA, DOE, and industry participants. EPA EPA's Hg co benefit assumptions can found in the IPM documentation in the rulemaking docket ( see Documentation Summary for EPA Base Case 2004 ( v. 2.1.9) Using the Integrated Planning Model, EPA, October 2004). 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: 9 140 One commenter ( OAR 2002 0056 5497) stated that they believed that there were inadequate data to assign any measurable or reproducible level of SCR co benefits for either wet or dry scrubbers. Two independent sources of data support this conclusion.

First, EPRI has synthesized the increase in oxidized Hg across SCR equipment at 18 sites. Of the 18 sites, three fire Powder River Basin (" PRB") coal and exhibit an increase in oxidized Hg between effectively zero ( Site S9) to 19 percent ( Site 1). These data suggest there is effectively no Hg oxidation across the SCR catalyst. The commenter did not think that the anomalous Site 1 unit   a cyclone boiler   is representative of the boiler design and characteristics of the boiler population in this nation. That boiler has relatively low particulate matter loading, elevated NO x level entering the SCR reactor, and the lowest space velocity ( e. g., most generous catalyst volume) of any of the tested units. Cyclone boilers comprise less than 5 percent of the boiler population. The other units are representative of boiler design and catalyst space velocity. While they suggest a 3 4 percent increase in Hg oxidation with PRB coal, this is within the " noise" of the measurement systems.

The second set of data that supports this conclusion is the measurement of increased Hg removal across a wet scrubber due to SCR. Of the sites reported, only Site 11 is equipped with wet scrubber. The use of SCR induces an 11 percent increase in the removal of Hg by a wet scrubber. Site 11 is equipped with a fabric filter that precedes the wet scrubber, and EPRI reports that much of the Hg oxidation occurs across the fabric filter, unrelated to the SCR. Consequently, it appears that much of the 11 percent increase in Hg removal is due to the fabric filter, and not the SCR.

For these reasons, and because the data are sparse and preliminary, the commenter suggested that zero co benefits be assigned to the role of SCR on PRB and other subbituminous coals.

Response:

EPA has assumed for the final rulemaking analysis that for subbituninous fired units that SCR has the no ability to convert elemental Hg to ionic Hg and thus allow easier capture in a wet FGD scrubber. EPA EPA's Hg co benefit assumptions can found in the IPM documentation in the rulemaking docket ( see Documentation Summary for EPA Base Case 2004 ( v. 2.1.9) Using the Integrated Planning Model, EPA, October 2004).

Comment:

One commenter ( OAR 2002 0056 5411) stated that their results indicated that the EMFs are not related to coal rank, but do vary with coal age. The consistent relationship between the EMFs and the geologic age of coal, coupled with simple criteria that definitively establish the age of coal, provide a scientifically justified and practical basis to subcategorize coal for regulation of Hg emissions.

The commenter stated that commercial U. S. coal was formed during two, substantially 9 141 different geologic ages, and can be broadly grouped as older Paleozoic coal, and younger Mesozoic/ Cenozoic coal. The mutually exclusive geographic occurrence of Paleozoic coal and Mesozoic/ Cenozoic coal is significant. Unlike coal rank, which varies locally, with ASTM standard vintage, and with assay precision, geologic age can be unambiguously determined based on coal origin location. Moreover, the origin location of coal shipments to units  50 MW is publicly reported; if regulation of units as small as 25 MW is required, determining the coal origin location is clearly less burdensome than representative sampling for coal rank assays. Finally, a precise coal origin location is not required to establish geologic age. Indeed, the " state of origin" reported on FERC form 423 is sufficient to establish geologic age for current coal production.

The commenter also stated that in the unlikely event that the age of a coal shipment is disputed, the 200 million year interval between Paleozoic coal and Mesozoic/ Cenozoic coal is significant. Ubiquitous pollen from angiosperms ( flowering plants), as well as certain terpene resins, are found in Cretaceous and Paleogene coal, but absent from Paleozoic coal. Consequently, if shipment receipts or transportation records prove insufficient, palynological or geochemical assays can definitively settle such disputes.

The commenter calculated Emission Modification Factors ( EMFs) for five of the 12 emission control technologies listed in Table 5 of the December 1, 2005 Federal Register Notice ( 69 FR p. 69871). Their calculation method is described in their docket comment ( Appendix B) together with the tabulated data used for this calculation. The results are illustrated in the figure below, which shows greater Hg capture for units burning Paleozoic coal than for units burning Mesozoic/ Cenozoic coal. Note that all U. S. Paleozoic age coal is bituminous or anthracite rank, whereas the rank of U. S. Mesozoic/ Cenozoic age coal varies. Importantly, the figure below also shows that the EMF does not vary with coal rank, but does vary with coal age.

The commenter added that the EMFs that they calculated are not directly comparable to those shown in Table 5 of the NODA. Nonetheless, with two minor exceptions, our EMFs are generally closest to the CRA 2004 values listed in the table. The first exception is for the relatively small HS ESP/ FGD technology class, where our EMF values are more similar to the EPA and EIA values. Secondly, our EMFs for the important CS ESP/ FGD technology class suggest slightly less Hg capture for this class than any of corresponding EMFs in the table.

U. S. Cenozoic/ Mesozoic age coal has greater fractional mercury emissions ( EMF values) than U. S. Paleozoic age coal, when burned in units equipped with conventional emission control technologies; this difference is not related to coal rank. 9 142 Notes, PC: pulverized coal; HS ESP: hot side electrostatic precipitator; CS ESP: cold side electrostatic precipitator; HS ESP FGD: hot side electrostatic precipitator with wet Flue Gas Desulphurization; FF FGD Dry: Fabric Filter and spray dry adsorption Flue Gas Desulphurization.

More than 25,800 ICR records were used to calculate the EMF values presented in the figure above; ~ 5,500 ICR coal assay data records where the location origin was not reported were ignored, as were ~ 3,300 records corresponding to blended coals. The tonnage weighted EMFs calculated for this comment ( Table 3) indicate the fractional emissions expected if all U. S. coal were burned in each technology class, rather than the coals that are currently burned. Although this approach is neutral with respect to fuel switching, it may overestimate Hg emissions for some units that burn blended coal. The omission of blended coals is likely to have slightly decreased our EMF's for CESP/ FGD units and PC/ FF FGD Dry units. This effect can be demonstrated for these technologies using the equations listed in Table Bl ( see OAR 2002 0056 5411), which predict net improved Hg capture for blends containing both high and low chlorine coal. The equations show predicted Hg capture substantially increases as chlorine content approaches 500 ppm, but only modestly rises above 1000 ppm chlorine. Thus, blending to optimum chlorine content between 500 and 1000 ppm, should result in a net reduction of Hg emissions.

A potentially more significant limitation of the EMFs presented in this comment is equally applicable to those listed in Table 5 of the NODA. Current FF/ FGD Dry technology is limited to low sulfur coal. Fortunately, excluding the ~ 30 percent of U. S. coal production that contains more than 1 lb sulfur/ 106 Btu, does not significantly change the our calculated EMFs for 9 143 FF FGD Dry technology; respective EMFs for Paleozoic and Mesozoic/ Cenozoic coal are 0.13 and 0.64, for low sulfur coal burned in units with FF/ FGD Dry technology. However, assuming a 1 lb sulfur / 106 Btu limit, FF/ FGD Dry technology is only applicable to ~ 25 percent of northern lignite, and hardly any Texas lignite, or coal from Ohio and Northern Pennsylvania  all of these areas produce relatively high Hg coal. Consequently, one of the best existing Hg reduction technologies is not appropriate for many coals with the highest Hg contents.

Due to time constraints, the commenter noted without comment the remarkably improved Hg capture suggested by the EMFs listed in Table 5 for units with SCR technology compared to those without SCR. For the same reason, the commenter had not considered Indonesian, Venezuelan, Columbian, Polish, or Alaskan coal, although these calculations are comparatively straightforward. Evaluation of potential coal supplies from countries not included in the ICR is more problematic; assay data from the USGS international coal data base might be useful for this purpose.

Response:

For the final rulemaking, EPA is using Hg emission modification factors based on coal rank. We believe this approach is consistent with our understanding of Hg control. 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 EPA's Hg co benefit assumptions can found in the IPM documentation in the rulemaking docket ( see Documentation Summary for EPA Base Case 2004 ( v. 2.1.9) Using the Integrated Planning Model, EPA, October 2004).

B. Issues of Hg Speciation General Comments Concerning Issues of Mercury Speciation Comment:

One commenter ( OAR 2002 0056 5460) stated that the NODA reveals an undue concern for alleged uncertainties concerning Hg speciation and the relative contribution of domestic power plants to global Hg emissions. The commenter further stated that EPA need not and should not delay regulation of domestic power plant Hg emissions until those alleged uncertainties are resolved. According to the commenter, rather, to the extent uncertainties exist concerning such topics as Hg speciation, transport, deposition and exposure, those uncertainties provide a basis for imposing stricter protections so as to ensure an adequate margin of safety. The commenter stated that no other approach is consistent with the preventive and precautionary purposes of the CAA.

The commenter ( OAR 2002 0056 5460) also stated that developing a Hg speciation profile is not relevant to setting a proper MACT floor pursuant to CAA section 112. The commenter added that, rather, by statute that floor is to be based on the average of actual 9 144 emissions achieved by the top 12 percent of the coal fired power plants for which EPA has data. The commenter added that, equally important, developing a speciation profile will not cure the legal defects in EPA's proposed section 111 approach.

The commenter stated that a speciation profile might be relevant to certain aspects of the beyond the floor analysis required by section 112, but EPA cannot and should not use either the fact of speciation, or uncertainty about the nature of such speciation, as a basis for concluding that section 112 no longer applies. The commenter further stated that, indeed, EPA's December 2000 determination that it was necessary and appropriate to regulate Hg emissions from power plants was not limited to particular species of Hg, and no basis exists for EPA to revisit or revise that determination now.

Response:

EPA is not delaying regulation of U. S. utility units until all uncertainties are resolved. However, we believe that these uncertainties do factor into the approach that should be taken in such regulation. We believe that the cap and trade approach being finalized adequately accounts for the uncertainties.

Comment:

One commenter ( OAR 2002 0056 5535) stated that the Agency's interest in speciation profiles and how they relate to Hg control, fate and transport, and ultimately human exposure raises the question of whether the Agency is contemplating basing emission rates or trading schemes on the level of different Hg species emitted. The overall impression left by this line of inquiry is that the Agency is suggesting that only oxidized Hg emissions from power plant need to be controlled. This is clearly inappropriate and arbitrary   elemental Hg is no less important than oxidized Hg in terms of the environmental and public health impacts in the U. S. To imply that elemental Hg does not contribute to Hg exposure in the U. S. is incorrect, because elemental Hg is eventually oxidized and deposited. This deposition can occur on the east coast of the U. S. as a result of emissions from a boiler located in the western U. S., or it may occur in the western U. S. from elemental Hg emissions circling the globe. Comments submitted to the EPA by a consortium of scientists convened by the Hubbard Brook Research Foundation ( HBRF) emphasize that elemental Hg can be rapidly converted to oxidized Hg and deposited locally or regionally. This process is known to occur after polar sunrises in the Arctic and Antarctic atmosphere and in the marine boundary layer in the presence of marine aerosols. Furthermore, emissions of oxidants from utilities and other high temperature sources provide ample reactants for oxidizing elemental Hg. New research shows that dry deposition of elemental Hg, uptake of elemental Hg by the forest canopy and subsequent litter fall can provide more than twice as much Hg to a watershed than wet deposition. Moreover elemental Hg can be converted to reactive gaseous Hg ( RGM or oxidized Hg) at a tree's leaf surface, thereby enhancing the deposition of elemental Hg at the local and regional scale and reducing long range transport. Consequently, there is ample evidence that emissions of elemental Hg must be reduced in conjunction with oxidized Hg emissions. 9 145 In addition, EPA cannot even entertain the notion that elemental Hg emissions need not be controlled from U. S. power plants and maintain an ounce of credibility in global Hg protocol discussions. One of Administrator Leavitt's " guiding principles" recognizes that Hg is a global issue and asks what opportunities there are to reduce Hg emissions worldwide. The opportunities to reduce global emissions ( and their subsequent impacts in the U. S.) will only arise if the U. S. is serious about reducing total Hg emissions from coal fired power plants.

Comment:

One commenter ( OAR 2002 0056 5464) noted that the NODA includes a discussion about speciation. It is unclear to them what EPA means by this discussion. If EPA's intention is to regulate by species, it is important to note that the workgroup discussed that idea briefly and rejected it as an unworkable solution. Further, although some companies have indicated that Hg emitted as oxidized all becomes elemental Hg in the plume as it exits the stack, this is counter to the vast research on Hg's behavior in the atmosphere. The key point here is that this industry finding is too preliminary, is within the error of measurements, and has had inconsistent results in different power plant plumes. Even if this one reaction among many is confirmed in later studies, this work needs to be interpreted in the context of many other atmospheric reactions of Hg whose net effect and direction tendency is just the opposite: conversion of elemental Hg into oxidized Hg. Oxidized Hg deposits locally and regionally, and a MACT that requires ALL power plants to substantially reduce emissions significantly ( 80 90 percent) would protect against hot spots.

The discussion about speciation relates to the atmospheric fate and transport of Hg emissions. Regardless of where emissions originate, in a world where international transport is becoming an increasing public health concern, there is no justification for this country turning its back on our contributions to transboundary pollution. This commenter believed the U. S. should show leadership by controlling Hg emitted here, regardless of where and how emissions travel.

Response:

EPA is showing leadership through issuance of this first ever regulation limiting Hg emissions from coal fired power plants. We agree that, at this time, it is inappropriate to regulate Hg emissions by species and, therefore, have structured the final rule on a total Hg basis.

Comment:

One commenter ( OAR 2002 0056 5559) stated that the 1999 ICR data is the most comprehensive body of Hg speciation data available that was developed through consistent and standard measurement methods. The commenter stated that EPA should rely on the ICR data as the primary basis for evaluating existing Hg control measures. The additional body of Hg emission testing conducted since 1999 by researchers and industry can be used to augment the ICR data but in doing so EPA needs to account for differences in testing methods and conditions. 9 146 Response:

EPA concurs with the commenter.

Comment:

One commenter ( OAR 2002 0056 5474) stated that it fully supports using different multipliers for the different coal ranks for the reasons stated above, but is concerned that the multiplier will be determined by using the coal or coals that a unit burned in 1999 rather than the coal a unit is actually burning at the time the rules are finalized. That approach is inequitable and grossly unfair to any unit that has switched from a higher to lower rank coal since 1999. This commenter has two units that made the decision in 2001 to switch from bituminous to subbituminous coal, to reduce NOx emissions to comply with new anticipated regulatory requirements. The engineering and design work needed to make the equipment and operational changes necessary for such a switch was started in late 2001. Construction commenced in early 2002 and was completed in 2003. After several test burns in 2003, subbituminous coal became the sole fuel source at the beginning of 2004. The commenter has no plans to switch back to bituminous coal in the future at such units. In fact, such an occurrence would be extremely unlikely, since the move was made to meet more stringent permanent NOx requirements for these units. Using EPA's methodology, the baseline heat input for these units will be multiplied by 1.0 when computing the number of allowances to be allocated to such units either for the State trading program budget or for a Federal trading program administered by EPA. However, as these units will be combusting subbituminous coal when the Hg reduction requirements become effective, such units will be unfairly penalized, since they will not be allocated allowances based on the coal actually being burned, which will result in approximately 25 percent fewer allowances for each unit. EPA should not punish units that switched fuels to comply with earlier environmental requirements not related to the CAMR, by allocating allowances based on the fuel type burned in an arbitrary baseline year, 1999, rather than the fuel being burned at the time when the rules are actually finalized.

Moreover, there may be Utility Units that have done the opposite of this commenter ( i. e., that have instead switched to a higher rank coal since 1999). If EPA were to use 1999 as the determining year for these units, their owners would receive a windfall of allowances, because the proposed methodology would base the allowance allocation on a coal type that is in fact no longer being burned.

To remedy this, this commenter suggests the following approach. EPA should use as the determinate for which coal rank multiplier to apply, the rank of coal that was combusted by such unit in the year the CAMR rule is finalized. Ideally, the goal should be to award allowances based on the rank of coal that a unit is actually burning. Alternatively, EPA should specifically allow for units like the commenter's that switched fuels to a lower coal rank to petition EPA and, if States are actually allocating allowances to Hg budget units, the relevant State, to receive an adjustment to the coal rank factor in recognition of any situation like the one described above that would allocate Hg allowances in an inequitable manner to units that switched fuels. 9 147 Response:

EPA is using 1999 coal type as the basis for the adjustment of the baseline for establishing plant mercury allocations to be used in developing the state and tribal emission budgets for the final rulemaking. However, in the example allocation methodology for states to allocate at the unit level EPA is finalizing a different approach. EPA's example allows states to use baseline heat input for the years 2000 through 2004 and coal type for those years. Under the model trading rule, EPA notes that States and Tribes have the authority to allocate at the unit level as they choose. See Chapter 5 and final rule preamble for further discussion of emission budgets and allocation methodology.

Comment:

One commenter ( OAR 2002 0056 5548) stated that EPA should adjust the Hg allowance allocations, by coal rank, to reflect the disparity of Hg removal efficiencies that NOx and SO2 controls have among coal ranks in any emissions trading program established under sections 111 or 112. This commenter, and others, agreed with EPA's proposal that coal rank emission control disparities justify using differing allowance allocation adjustments for each coal rank. However, the commenter argued that the allowance allocation adjustment factor for subbituminous coals should be increased from the proposaled factor of 1.25 to a higher factor of 1.5.

Response:

EPA is finalizing coal adjustment factors for the purpose of establishing state emission budgets of 1.0 for bituminous coals, 1.25 for subbituminous coals, and 3.0 for lignite coals. These adjustment factors are considered to be appropriate numbers based on the test data currently available. 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 5548) suggested that it should be obvious that EPA's allowance allocation approach, and the similar approaches advocated by Southern, UARG, and others, based on speciation and control issues, are fundamentally flawed. The primary question has been articulated by WEST Associates' comment that " for facilities that would have to purchase allowances, WEST Associates recommends that an additional allocation adjustment factor be applied that promotes equitable allowance distribution, particularly in Phase I of the cap" program reasoning that " it is critical that the allocations of mercury allowances reflect the relative level of mercury control for bituminous, subbituminous and lignite coal ranks that will be achieved, within each coal rank, by the SO2 and NOx controls required under the CAIR by 2010." That this comment, and similar comments by Southern, UARG, and the SEC that EPA has cited in the NODA, is a misconception seems clear. There is absolutely no reason to adjust allowance allocations for purchasers of allowances based on relative levels of Hg reduction capability among 9 148 coal ranks because purchasers of allowances are not reducing anything; they are simply buying allowances representing reductions made by others. That is the very point of the entire cobenefits cap and trade approach, where allowance purchases, and not controls, are the means to compliance for many sources. It is equally obvious that allowance purchasers do not pay different prices depending upon the rank of coal they burn. A purchaser of Hg allowances has the same equitable status regardless of the rank of coal burned. The only relevant consideration at issue is the price at which these three classes of allowance purchasers ( bituminous, subbituminous, and lignite) must buy allowances. And that price is exactly the same between all of the coal ranks.

Response:

EPA is finalizing coal adjustment factors for the purpose of establishing state emission budgets of 1.0 for bituminous coals, 1.25 for subbituminous coals, and 3.0 for lignite coals. These adjustment factors are considered to be appropriate numbers based on the test data currently available. 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 5332) stated that the modeling results reported in the NODA do not fill the gap. Because the modeling was done by numerous stakeholders with different objectives, crucial assumptions ( e. g., demand growth; natural gas prices; availability, performance, and cost of control technologies) vary, with no attempt at systematic inquiry. Moreover, the results are not presented in uniform metrics and, therefore, in many cases are not comparable. The commenter urged the Agency to undertake a systematic, transparent modeling effort, along the lines that the Clean Energy Group and other stakeholders have recommended.

Response:

EPA is finalizing a cap and trade approach under section 111. Analyses in support of the process will be presented in the final CAMR Regulatory Impact Analysis document.

1. EPA received numerous comments on subcategorization by coal type and the speciation profiles resulting from the combustion of various types of coal. EPA sought additional specific data and information on the speciation profiles of various types and blends of coal.

Comment:

One commenter ( OAR 2002 0056 5484) provided detailed information and a technical report with its comments ( OAR 2002 0056 2948) of June 29,2004, on the speciation of Hg in coal fired power plant plumes. In the NODA, EPA has asked for more information on Hg 9 149 speciation and has also indicated that it is performing a benefits analysis that attempts to estimate the reduction in adverse human health effects that will occur as a result of reducing Hg emissions from coal fired power plants. To this end, this commenter wishes to provide more information to supplement the information provided in June and to re state the implications of this information. OAR 2002 0056 5484 is the latest summary of the research which has shown that the fraction of Hg emitted as oxidized Hg from coal fired power plants is rapidly converted to elemental Hg. Current models do not account for this conversion. Research is underway by EPRI and others to better understand the chemical mechanisms that explain this observation and to incorporate the mechanisms into air quality models. The most important implication of this research finding is that, because the observed transformations are not taken into account in current assessments, current estimates of the benefits from reducing power plant Hg are overestimated. This overstatement applies to the results of the most comprehensive assessment conducted to date   that conducted by EPRI   which already shows that very small Hg deposition and exposure reductions will result from either the cap and trade or MACT approaches. EPA should include these transformations in whatever benefits estimation it conducts.

Comment:

One commenter ( OAR 2002 0056 5556) referred to the speciation of Hg and noted that new information challenged the estimated lifetime of elemental Hg before it is deposited. Also, new data are demonstrating the oxidation of elemental Hg to reactive gaseous Hg during periods of enhanced photochemical activity with high ozone and warm temperatures ( OAR 2002 0056 5557).

Response:

EPA has addressed the commenter's issue through the application of the Community Multiscale Air Quality ( CMAQ) modeling system in estimating current and future levels of total mercury deposition for the purposes of this rule. This sophisticated photochemical air quality model is able to differentiate across Hg emissions species and account for the complex atmospheric reactions as referenced by this commenter. The model and these specific reactions are detailed in the Air Quality Modeling TSD ( docket # OAR 2002 0056 6130).

Comment:

One commenter ( OAR 2002 0056 5564) noted that the principal business of San Miguel Electric Cooperative, Inc., is the production of electric energy in South Central Texas. Production includes one coal fired power plant and one lignite mine. The lignite mine supplies fuel only for the San Miguel Generating Station and produces, on average, 3.3 million tons of lignite/ year. The one generating unit fires only lignite provided by this mine and comprises 100 percent of San Miguel's generating capacity; average yearly output is 3.2 million MWh.

The commenter provided comments on the issues of Hg speciation. The commenter's unit has an ESP and a wet FGD system for controlling PM and SO2 and has performed two stack tests 9 150 for Hg. These tests were conducted in 2002 and 2004 using appropriate methods and the test results were provided in the comments.

Response:

EPA appreciates the submission of the data.

Comment:

The commenter ( OAR 2002 0056 5490) stated that their comments are all related to the second section, " Electric Utility Sector Modeling and Hg Speciation," especially as it relates to Gulf Coast lignite. The commenter continued its research into the Hg content of the coals it combusts, the speciation of the Hg in the flue gases prior to existing control devices, the removal efficiencies of the existing control devices and the Hg emissions ( and speciation) from its stacks. Unfortunately, the reports for the testing had not been finalized at this time. The commenter also participated in four DOE Hg control technology projects. The results of Hg analysis on samples of coal taken through October 31, 2004, from pulverizer feeders at the commenter's nine coalfired units were provided in the comments. All of these units, except Sandow Unit 4, burned blends of Gulf Coast lignite and western subbituminous coal. The minimum Hg in coal values are from high percentage subbituminous samples and the maximum values are from high percentage lignite samples. Sandow Unit 4 burned Gulf Coast lignite only.

The Cl in the Gulf Coast lignite ranged from less than 1 part per million ( ppm) to 170 ppm, which is less than the 1999 ICR Part II analysis indicated. Chlorine content affected the speciation of Hg generated from firing coal.

Response:

EPA appreciates the submission of the data.

Comment:

Two commenters ( OAR 2002 0056 5456,  5505) mentioned that EPA is seeking input on issues of Hg speciation. The NODA states, " During this data collection effort, incoming coal shipments for all coal fired power plants in the U. S. were tested for Hg content ( for calendar year 1999)." Perhaps the more fundamental issue than the speciation of the Hg is one of if the Hg content of the coal is accurate in the EPA ICR database. There has been much controversy expressed that the proposed MACT Hg emission standards for subbituminous coal are too high creating a " compliance coal" for Hg, particularly for PRB coal. This conclusion was based upon an analysis of the EPA coal Hg content database.

Since that time, there has been some testing of advanced Hg control technologies with various types of coals and control configurations. Also included in these analyses were a quantification of the coal Hg content, and inlet total vapor ( Hg). 9 151 The commenter was a participant in the testing done at Sunflower Electric's Holcomb Station, located near Garden City, Kansas. The plant burns Wyoming PRB coal, and has a SDA/ FF control configuration, which is widely considered to be a " typical" configuration for future coal fired plants; particularly those that consume PRB coal. Mercury reduction testing took place at this plant, funded by the DOE and others. The results of the test are presented figures 1 and 2 of OAR 2002 0056 5456 , and show that in this test PRB coal significantly exceeds EPA's proposed MACT Hg emission limit of 5.8 lb Hg/ TBtu for subbituminous coal.

Comment:

Commenter OAR 2002 0056 5505 provided information from Arapahoe Unit 3, a 44 MWe PRB coal fired unit in the Denver metro area. The unit is equipped with a reverse air fabric filter and a dry sodium injection system for SO2 removal. Testing at this plant occurred over a two week period in May 2004 to evaluate the use of Amended Silicates for Hg removal. The interesting part of the work from the perspective of the commenter is that it included two separate PRB coals. These coals were burned separately, and were not mixed during the test. One of the coals had significantly higher Hg content that the other coal.

The commenter provided results for the higher Hg content coal tests. In both tests, PRB Coal A yielded significantly higher results than EPA's proposed MACT emission limit of 5.8 lb Hg/ TBtu. From the final report, PRB Coal A " had nearly twice the Hg of [ PRB Coal B] with a Hg content of 0.071 ppm ( as received basis). [ PRB Coal A] yielded flue gas vapor phase Hg concentrations in the range of 12 to 16

g/ Nm3. For Xcel's samples from [ PRB Coal A] shipments to Arapahoe, their average Hg content has been measured as 0.06 ppm, somewhat lower than the value for the [ PRB Coal A] sample obtained during the May trial."

Response:

EPA appreciates the commenter's 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 Hg speciation. Test results obtained by the commenter in the last year have not markedly changed the speciation correlations developed from the ICR. While coal Cl content appears to drive the degree of flue gas Hg oxidation, other factors may also have a noticeable effect on this process; tests and chemical modeling studies are seeking to quantify the role and significance of these other factors. Speciation continues to be viewed as important for determining the most applicable and cost effective controls, the achievable emission levels, and, to a certain extent, the potential impact of emissions from a given plant on Hg deposition onto downwind water bodies.

Response: 9 152 EPA appreciates the commenter's 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 subsequent to the ICR stack sampling in 1999, Hg speciation measurements have been taken as part of research studies sponsored by DOE, EPRI and others. These studies have explored, among other things, the effect of SCR on Hg oxidation and Hg removal using ACI. In addition, a number of coal fired power plants have conducted their own sampling of Hg emissions to determine the levels and species of Hg that are emitted.

In general, this additional testing has produced results that continue to show Hg emission variability like that seen during the ICR stack testing. As EPRI's NODA comments indicate ( see OAR 2002 0056 5469), these recent Hg results do not substantially change the Hg speciation correlations that EPRI produced using the ICR data.

Response:

EPA appreciates the commenter's 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 5494) noted that the NODA solicits input on, among other matters, issues related to " Hg speciation" and the results of four approaches of modeling Hg emissions under various emission control equipment deployment scenarios. All those model calculations start with certain assumptions about the relative proportions of the chemical composition of Hg emissions exiting the stacks ( three species   elemental, ionized, and particle bound) from coals classified as bituminous, subbituminous, and lignite.

This commenter addresses two issues relating to coal ranks/ Hg speciation: ( 1) uncertainty associated with compliance with the proposed regulations for coal used at several Southwestern power plants, and ( 2) questions associated with the appropriateness of developing the proposed Hg rule utilizing the ICR III database's Hg emissions data segregated under the three coal rank classifications. Specifically, these comments address unique problems in applying the ASTM methodology referenced in the proposed rule to determine coal ranks and compliance obligations.

EPA's proposed rule refers to the ASTM coal ranking methodology and sets different Hg emission limitations for different coal ranks. However, the ASTM coal ranking methodology may not be appropriate for regulating Hg emissions from certain coal fired power plants. The 9 153 ASTM methodology is based on analyses on a " moist" basis, or the moisture content of the coal in the mine. ASTM D388 99 clearly requires that coal rank should be determined while the coal is in the mine. Coal ranking classification made any other way, such as under " as received" is designated by ASTM D388 99 as " apparent rank."

The EPA's ICR data collection efforts discuss reporting coal properties on an " as received" basis at each respective coal fired power plant. In some cases, as discussed below, coal determined to be subbituminous in the mine according to the ASTM methodology could very well transform to bituminous when it is " received" at the plants, stored on site, or while combusted in a boiler, because its " inherent moisture" value could change.

Moreover, in the case of coals whose heating value falls in the overlapping region between 10,500 to 11,500 Btu/ lb, only an agglomeration test can definitively determine its actual coal rank ( D388 99). The proposed rule does not contemplate situations like those identified here and raises considerable ambiguity as to the applicable regulatory requirements. This situation is very different from the " coal blending" scenario addressed in the proposed rule to establish the appropriate emission limit. This commenter believes that the rule should be made very clear as to what the operator's regulatory obligations are. Specifically, the commenter requests that EPA expressly state in the rule where the coal rank should be determined: at the mine, " as received" at the plant, or when the coal is combusted in the boiler.

EPA developed the rule, as noted above, by segregating Hg emissions test data ( ICR III) from 81 units by the rank of the coal used during the emission tests. In this process, coal data were taken from the ICR III test reports, and constituted coal characteristics on an " as received" basis. Data for one of the four units used in calculating the MACT level for subbituminous coal came from the commenter's Cholla Power Plant ( Cholla Unit 3), and in 1999 Cholla reported the coal used during the ICR III tests to be " Bituminous/ Subbituminous." Recently, Cholla has reviewed coal data submitted to the EPA under ICR III and ICR II throughout 1999, and concluded that Cholla burned bituminous coal most of the time. In fact, that review has also concluded that Cholla Unit 3 burned bibuminous coal during the ICR III testing. Based on these conclusions, the commenter believes that EPA segregated ICR III data from Cholla Unit 3 in the incorrect subbituminous category.

The commenter's review of the ICR III data for the other three top performing units ( used to calculate the subbituminous MACT level) suggests that at least two of those units' coal ranks may have been incorrectly classified . Thus, if the coal ranks have indeed been misclassified before calculating the MACT levels for the subbituminous coal category, the coal rank based determination of Hg emission limitations may be in error.

The commenter understands that similar concerns were included in the comments submitted to the EPA in the proposed rulemaking by the Subbituminous Energy Coalition ( SEC). Therefore, the commenter respectfully requests that EPA reassess the classification of ICR III Hg emissions test data by coal rank and the subsequent statistical analyses done in developing the proposed MACT levels/ national Hg emissions cap and trade program ( and its allowance allocations). 9 154 Commenter OAR 2002 0056 5494 agreed that EPA has found that the Cl content of coal determines the relative proportions of various chemical species of Hg emitted. For example, combusting Eastern bituminous coal ( with its high Cl content) creates higher proportions of ionized and particle bound Hg, while Western subbituminous, Western bituminous, and lignite coals ( all with much lower Cl content) create a higher proportion of elemental Hg. EPA has also found that ionized and particle bound Hg emissions are more efficiently controlled in existing pollution control devices ( such as SO2 scrubbers and PM control devices). Therefore, modeling results of Hg emissions from stacks depend on the assumed relative proportions of the three Hg species.

The commenter believed that regulating Hg emissions on the ASTM methodology of coal ranking ( based primarily on heating value) may not be appropriate, at least where the Btu value for bituminous and subbituminous coal overlaps ( as noted by ASTM D388 99). EPA's proposed rule sets MACT levels based on coal ranks: for example, the proposed emissions limits are 2.0 lb/ TBtu for bituminous and 5.81 lb/ Btu for subbituminous coals. There are several plants in the Western and Southwestern U. S. that utilize coal whose rank can vary between bituminous and subbituminous from time to time, even for coal coming from the same seam. Given below are two different types of examples where the commenter believes such changes can occur.

First, the commenter considered the case of coal whose heating value falls in the " overlapping region" between bituminous and subbituminous coals. Several Western power plants are " mine mouth" plants, and hence, restricted to utilize coal burned in the adjacent mine. One such plant, the commenter's Four Corners Power Plant, uses coal from the Navajo Mine on the Navajo Reservation in Northwestern New Mexico. Navajo Mine's coal has fairly low heating value ( typically under 9,000 Btu, on an " as received basis") and very high ash content ( typically 20 25 percent). Over the past decades, the mine operator assured the commenter that its coal was subbituminous coal.

If the ASTM methodology is utilized, the Navajo Mine's coal's " mineral free" heating value often falls in the 10,500 to 11,500 Btu range, the overlap region between bituminous and subbituminous coal classification. Under such conditions, ASTM methodology requires an " agglomeration test" to determine the coal rank. Very limited agglomeration tests conducted by the commenter indicate that the Navajo Mine's coal could be bituminous, contrary to long held belief and assurances from the coal supplier. EPA's proposed rule ( 69 FR 4665) emphasizes the significance of coal rank in the engineering design of power plants and their operation. Therefore, Four Corners, and several other plants in the Southwest designed to burn subbituminous coal, may be forced to comply with the Hg emission limitation applicable to bituminous coal.

The commenter reported that its experience with coal from the McKinley Mine in New Mexico used at the Cholla Plant provides a situation completely different from the above example. There, the " apparent rank" on occasion falls in the range of 11,300 to 11,800 Btu/ lb range. If the " Free Swelling Index" is applied to that coal, that coal is non agglomerating, and thus, will be classified as subbituminous. Under those circumstances, coal from the McKinley Mine could vary from bituminous to subbituminous on a daily basis. 9 155 The commenter reported that EPA staff said that they never envisioned that plants would undertake " agglomeration tests" on a routine basis, as it is time consuming and expensive. This situation leads to two potential problems. First, the commenter notes that there is considerable uncertainty concerning the plant's compliance obligations under both MACT and cap and trade regulatory approaches ( i. e., via calculation of the national cap as well as the Hg allowance allocations). Second, the commenter notes that in situations like the one described above, it may be possible to " blend coals" in such way to bring its heating value to just below the threshold level to classify it as subbituminous. Such a situation can create opportunities for " gaming" the regulatory system. These potential scenarios are untenable and should be clearly addressed in the final rule.

The commenter related the second issue to variability in moisture content, which can change during the mining process, transportation to the power plant, and combustion in a boiler. For example, the Cholla Power Plant ( as well as certain other power plants in the Southwest) utilizes coal from several mines, including the McKinley Mine in New Mexico. Typically, McKinley Mine adds about 3 to 4 percent moisture in dust suppression activities. Adding moisture reduces its heating value, and according to the ASTM methodology coal rank is determined on a moist, mineral free basis for subbituminous coals. At the plant, storage of coal in the open ( prior to combustion) and pulverization can result in loss of some moisture.

The commenter reported that when EPA assembled the ICR II and III database, no guidance was given to plant operators about any adherence to ASTM methodology in developing the data and reporting it to EPA. Accordingly, plant operators relied on the information on coal ranks provided by the coal suppliers, and reported the same data to the ICR database. It appears that EPA developed the coal rank based Hg rule, and the ASTM methodology was brought in later as an afterthought. Upon careful review of the ASTM methodology, the commenter believes that potential problems like the ones discussed above exist. If EPA retains the coal rank based Hg regulatory scheme, then the commenter recommends that the rule should clarify that the coal rank reported by the coal supplier ( mine) will be the basis of determining the appropriate Hg emission limitation. This commenter believes that forcing the plants to conduct agglomeration tests on a routine basis is unreasonable and will create uncertainty in plants' compliance obligations.

Because Cholla Unit 3 was one the four " top performing" units used to calculate the MACT level for the subbituminous coal category, the commenter recently reviewed the coal data reported in 1999. The commenter found that the coal rank data was reported as " Bituminous/ Subbituminous" during the ICR III tests. After the proposed rule was published with its reference to ASTM methodology, the commenter recently calculated the Btu value of the coal on a moist, mineral free basis, utilizing the coal analysis data reported in Cholla's ICR III test report. These calculations, as per ASTM methodology, lead us to conclude that Cholla Unit 3 indeed burned bituminous coal during the ICR III testing. Accordingly, the commenter believed that ICR III test data from Cholla Unit 3 were inappropriately classified under the subbituminous coal category, and consequently, use of data from that unit to calculate the subbituminous MACT level may be in error. 9 156 The commenter had also evaluated the coal ranks reported for some of the units that were tested under ICR III, and the commenter believed that EPA's grouping of units under bituminous/ subbituminous categories may be erroneous in certain cases. The commenter provided a table of the coal Btu values from the ICR III test reports for the four units used in setting the MACT level for subbituminous coal. If the ASTM guidelines on Btu content were to be used, three of those four ( i. e., AES Hawaii, Clay Boswell Unit 2, Cholla Unit 3) units clearly fall under the bituminous category, rather than subbituminous category. This raises questions about the validity of the proposed MACT levels for subbituminous coal, and raises a similar problem for the cap and trade proposal.

The commenter is aware of the uncertainty with the type of coal used ( and associated potential misclassification) during the ICR III tests at the Valmont Plant in Colorado reported by Xcel Energy. Data from that plant was used to calculate the MACT level for the bituminous coal category. However, had the coal indeed been subbituminous ( rather than the assumed bituminous), the proposed MACT levels for both bituminous and subbituminous would be significantly different.

The commenter stated that, based on the new information on the possible misclassification of coal ranks in the ICR III Database presented here, they believed that EPA should reassess the MACT levels and cap and trade allowance allocations included in the proposed Hg rulemaking. This commenter believed that EPA should address the unique compliance uncertainty created for several Western/ Southwestern plants using certain coals whose heating value ( Btu) falls in the overlap area for bituminous and subbituminous coal ranks. Therefore, should EPA retain the coal rank based approach to regulate Hg emissions, the commenter recommends that EPA use the same Hg emissions limitation for low Cl content Western bituminous coal and subbituminous coal.

The commenter also believed that the Cl content of the coal is a better basis for regulating Hg emissions than the proposed coal rank based approach, which relies on the ASTM methodology that was never intended and is not appropriate for characterizing Hg emissions. Finally, in the event that EPA retains the coal rank based approach of regulating Hg emissions, this commenter recommends that plants using Western bituminous coal be subjected to MACT levels and allowance allocations identical to those plants using subbituminous coals.

Response:

EPA appreciates the commenter's 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:

Commenter OAR 2002 0056 5548 noted that commenter OAR 2002 0056 2535/ 5505 had urged EPA to reevaluate the MACT determination for Wyoming subbituminous coals to 9 157 account for large differences in Wyoming PRB and other western subbituminous coals. Commenter OAR 2002 0056 2535/ 5505 is, in effect, asking EPA to further subcategorize subbituminous coals based on differences, such as a distinction between ASTM sub classifications within the subbituminous rank, as they discuss in their comments. Commenter OAR 2002 0056 5548 believed that the commenter OAR 2002 0056 2535/ 5505' s argument points out one of the fundamental flaws with the attempt to subcategorize by coal rank, because rank is not predicative of coal properties of relevance to Hg emissions and control. Furthermore, if EPA were to do so for subbituminous coal, it also must further subcategorize bituminous coals based on the even greater differences in bituminous coals from different regions of the country. Commenter OAR 2002 0056 5548 believes that, at a minimum, EPA should subcategorize bituminous coals by rank ( High volatile A, B, and C, medium volatile, and low volatile), and further by geographic region ( western, mid continent, northern, central, and southern Appalachia). Within these regions, bituminous coals are produced from individual seams which themselves exhibit large differences in coal properties. A decision by EPA to further subcategorize one rank coal without doing so for all ranks of coal would clearly be arbitrary and would fail to ensure an equitable treatment for coals of all ranks, which EPA states as one of its objectives.

In its original comments on the rule and in these NODA comments, commenter OAR 2002 0056 5548 demonstrated, using the IRC Part II coal analysis data, that 62 percent of all subbituminous coals sampled would meet the proposed 5.8 lb/ TBtu MACT limit with no Hg reduction, largely eliminating the speciation or any other control issue. The average subbituminous coal has a Hg content of 5.7 lb/ TBtu, thus making subbituminous coal, in aggregate, a compliance coal, given the proposed 12 month averaging period of the rule.

In its comments, commenter OAR 2002 0056 2535/ 5505 attempts to refute this compliance coal demonstration by presenting ICR Part III emissions data from 10 plants burning Wyoming PRB coal, purporting to show that Hg emissions from the majority of these plants are in excess of the 5.8 lb/ TBtu limit. EPA should discount this for two reasons. First, commenter OAR 2002 0056 2535/ 5505 acknowledges in its comments that the ICR Part III data, which consists of only short term sampling at 80 power plants, is highly suspect. Commenter OAR 2002 0056 5548 strongly concurred with that observation and point out that none of the units that meet the data quality criteria burns a Wyoming PRB coal. Therefore, the attempts of commenter OAR 2002 0056 2535/ 5505 to use the ICR Part III data to support a conclusion concerning plant emissions contradicts their clear understanding of the limitations of the ICR Part III data.

Second, the IRC Part II data set, on which commenter OAR 2002 0056 2535/ 5505 relied, is much more substantial and robust, because it contains the Hg contents of thousands of coal samples from most mines, sampled as delivered to most power plants in the country for a full year. Commenter OAR 2002 0056 5548 provided a table reporting the mean and median Hg contents from the ICR Part II data base for the 509 coal shipments sampled as delivered to the nine plants for which commenter OAR 2002 0056 2535/ 5505 presented emissions data. Contrary to the SEC's assertion, six of the nine plants ( 67 percent) received coals in compliance with the proposed 5.8 lb/ TBtu limit in 1999, and the three that did not would require an average reduction of only 10 percent to come into compliance. That reduction is well within the range of 9 158 EEI/ CRA's subbituminous EMF for a CS ESP. Thus, assuming only a modest reduction across existing emission control equipment, these plants would require no further reduction to come into compliance. The average Hg content of coals delivered to the same nine plants in commenter OAR 2002 0056 2535/ 5505' s comments was 5.2 lb/ TBtu, further supporting the commenter OAR 2002 0056 5548' s conclusion that the 5.8 lb/ TBtu MACT limit effectively would denominate subbituminous coals as compliance coals.

Commenter OAR 2002 0056 2535/ 5505 stated that " elemental mercury comprises 70 80 percent for the total mercury emitted from the furnace" for subbituminous coal fire units. They do not provide a source for this statement, but it appears to overstate the percentage of elemental Hg in the flue gas of such units. An analysis of the ICR Part III data for Hg speciation at the inlet to the last control device at each subbituminous coal fired station reveals an average elemental Hg concentration of 59 ± 23 percent. Some particulate or oxidized Hg may have been removed ahead of the flue gas measurement point, so this should be considered an upper bound on the average percentage of elemental Hg in the flue gas for subbituminous coal fired units. Note that this average excludes those plants identified by commenter OAR 2002 0056 2535/ 5505 as misidentified by the EPA as burning only subbituminous coal.

Commenter OAR 2002 0056 2535/ 5505 contended that the imputed emission factors calculated from EPA's proposed allowance adjustment factors under section 111 results in " relatively little" subcategorization. Commenter OAR 2002 0056 5548 opposes the imposition of any allowance adjustment factors. The commenter believed that too little is known at present about Hg emissions and control technology to ensure that they are equitable and result in achievable emission limits ( a position with which commenter OAR 2002 0056 2535/ 5505 concurs). The commenter also contended the development of Hg specific control technology will obviate the rationale for allowance adjustments in the future. Nevertheless, commenter OAR 2002 0056 2535/ 5505 would support the use of EPA's section 112 MACT limits as the basis for allowance adjustment factors. This would simply create under the guise of a cap and trade program the same inequity as in the MACT proposal, under which subbituminous coal fired units would receive sufficient allowances as to require no Hg reductions, and most likely receive excess allowances from which they would profit by selling them to bituminous coal fired units which face a stringent, and in some cases unachievable, compliance burden.

Response:

EPA believes that the comments provided by commenters OAR 2002 0056 5494 and  5548 relate, variously, to the issues of subcategorization ( either more or fewer subcategories) and the use of the ASTM ranking scheme to delineate the subcategories, rather to the issue of Hg speciation. EPA has addressed, earlier in this document, other comments related to the issue of subcategorization and has presented its rationale for the use of subcategories.

We are, however, somewhat perplexed regarding the comments related to a utility " not knowing" the rank of coal being fired and on the use of the ASTM classification methodology as the basis for determining the rank of coal burned, and, thus, " membership" in the appropriate subcategory. EPA based its subcategorization on the coal rank information provided by the 9 159 utility, not on the coal analysis data provided by the utility. That is, if a utility reported that their coal was ( e. g.) " subbituminous," EPA did not question the statement. During the period of the ICR, EPA requested that the responding utilities provide to EPA only the Hg and Clcontents of their coals as new information. The remaining coal information requested ( e. g., coal rank; heating value; moisture, ash, and sulfur content) was that information already being provided to the DOE. Each U. S. utility company ( including combined heat and power companies) is required by law to submit to the DOE/ EIA for each Utility Unit the rank of coal burned, on a monthly or annual basis, on at least one of the following forms:

EIA Form 423: Monthly Cost and Quality of Fuels for Electric Plants Report (" Column ` c'Fuel) EIA Form 767: Steam Electric Plant Operation and Design Report (" Fuel Code") EIA Form 860: Annual Electric Generator Report (" Energy Source Code") EIA Form 860m: Monthly Update to the Annual Electric Generator Report (" Energy Source Code") EIA Form 906: Power Plant Report (" Energy Source") EIA Form 920: Combined Heat and Power Plant Report (" Energy Source")

Thus, utility companies are currently obtaining the coal rank information being reported to DOE from someone, somehow to comply with this legal requirement. EPA is not asking for any additional information or analyses upon which to establish a given Utility Unit in a subcategory for purposes of either the final NSPS or cap and trade provisions. Rather than being able to " game" the system, units that blend two or more ranks of coal are required to use specified procedures for determining their applicable NSPS emission limit.

EPA continues to believe that the ASTM ranking methodology is the one most widely recognized within the industry and, therefore, is appropriate for this rulemaking. Given the existing legal requirement to provide DOE with the coal rank being utilized, EPA believes that the industry knows what coal rank it is consuming in its units.

2. EPA sought comment on if/ when a standard ( or average) speciation profile should be used for either the CAA section 111 or CAA section 112 regulatory approach.

Comment:

One commenter ( OAR 2002 0056 5475) stated that under Part II, Sub Part C of the NODA, EPA indicates that it received comments related to the speciation of Hg. The commenter stated that speciation is fundamentally important since the ability of control devices to remove Hg is directly related to the form of Hg in the flue gas. The three species of Hg that exist in plant emissions are elemental, ionic/ oxidized, and particulate. Oxidized and particulate are known to be the more easily captured forms of Hg. Average Hg speciation data from the 81 power plants that were the basis of the MACT floor calculations, is set forth in the NODA ( 69 FR 69871). The calculated averages of the speciated Hg forms across all coal types were: 54 percent elemental, 9 160 43 percent oxidized, and 3 percent particulate.

Response:

EPA appreciates the commenter's 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) objected to the notion of using an average speciation profile to predict the characteristics of Hg emissions from coal fired utilities. The percentages of the three forms of Hg emissions can vary widely from facility to facility, even in the same coal category. For example, it has been determined that within a given coal category the proportion of oxidized Hg emitted is proportional to the Cl content of the coal. Commenter OAR 2002 0056 2038 noted that average speciation for electric utilities range between 10 percent and 90 percent for the oxidized form. The Brookhaven National Laboratory's May 2003 study utilized data from the Bruce Mansfield Plant in Shippingport, PA, and the Monticello Power Plant in Monticello, TX. The fraction of the oxidized form of Hg between these two plants varied between 19.7 percent and 60.4 percent, respectively. Given the disparate speciation data that exists for Hg emissions, this commenter recommends that a sensitivity analysis be performed to evaluate the effect that the range of values for the oxidized form of Hg has on the proposed rule.

Response:

EPA appreciates the commenters concerns. Please see 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) for a discussion of the importance of speciation for mercury capture. Also, please see Chapter 7 of the Regulatory Impact Analysis for a discussion of how we took speciation into account in our power sector modeling and see Chapter 8 for a discussion of how we took speciation into account in our air quality and deposition modeling.

Comment:

Two commenters ( OAR 2002 0056 5510,  5548) said that an average speciation profile cannot capture the large degree of variability and uncertainty associated emissions from different coal types, and should not be used for either section 111 or 112 regulation.

In the case of MACT regulation, if the standard is set based upon an average speciation profile, coals with greater Hg concentrations will not be able to comply   even if the unit is meeting a targeted percentage reduction. For example, the average Hg content of bituminous coal reported in the ICR Part II data is 8.4 lb/ TBtu. Assuming the availability of a Hg control 9 161 technology able to achieve 50 to 70 percent reduction ( DOE's goal for 2010), the " average" bituminous coal could achieve an emission rate of 2.5 to 4.2 lb/ TBtu. However, coals from the State of Ohio, which have an average Hg concentration of 15.7 lb/ TBtu, would need to achieve 75 to 85 percent removal to meet a standard in this range, beyond the range of the hypothetical then available technology. As a result, these coals could not be used in compliance with the MACT.

Although this risk may be somewhat lessened under a cap and trade rule, because operators have the potential ability to purchase allowances, there is no assurance that allowances will be available in sufficient quantity to meet compliance needs. To the degree that allowances are not available, the explicit compliance problem under the MACT described above becomes effectively the same liability under the cap and trade program.

Response:

EPA is finalizing a cap and trade rule. Please see the CAMR preamble for a complete discussion. EPA appreciates the commenters concerns. Please see 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) for a discussion of the importance of speciation for mercury capture. Also, please see Chapter 7 of the Regulatory Impact Analysis for a discussion of how we took speciation into account in our power sector modeling and see Chapter 8 for a discussion of how we took speciation into account in our air quality and deposition modeling.

Comment:

One commenter ( OAR 2002 0056 5502) referenced using average vs. individual power plant speciation in modeling and used individual speciation in the model runs conducted for it to gain insights into the potential changes in deposition patterns as a result of different Hg emission reduction scenarios. The commenter recommends that EPA do the same to develop similar insights, as these are important to inform decisions on cap and trade vs. MACT.

Response:

EPA is finalizing a cap and trade rule. Please see the CAMR preamble for a complete discussion. EPA appreciates the commenters concerns. Please see 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) for a discussion of the importance of speciation for mercury capture. Also, please see Chapter 7 of the Regulatory Impact Analysis for a discussion of how we took speciation into account in our power sector modeling and see Chapter 8 for a discussion of how we took speciation into account in our air quality and deposition modeling.

Comment: 9 162 One commenter ( OAR 2002 0056 5497) stated that given the repeated concerns voiced about Hg " hot spots," it makes sense to use the best estimates of Hg speciation in any dispersion modeling. EPA's 1999 ICR request produced a year of detailed coal data for all coal fired power plants in the U. S. These coal data can be used along with Hg speciation correlations that EPRI developed from the 1999 ICR Hg stack sampling to produce Hg speciation estimates for every coal fired unit in the country. This is exactly how EPRI modeled Hg deposition in the U. S. EPRI's modeling results were provided in EPRI CAMR comments dated June 16, 2004 and in the comments EPRI is submitting in response to this NODA. The commenter believes that EPA should follow a similar approach in any Hg deposition modeling it may perform. EPA should not use an average speciation value for each coal rank.

Response:

EPA appreciates the commenters concerns. Please see 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) for a discussion of the importance of speciation for mercury capture. Also, please see Chapter 7 of the Regulatory Impact Analysis for a discussion of how we took speciation into account in our power sector modeling and see Chapter 8 for a discussion of how we took speciation into account in our air quality and deposition modeling. EPA has addressed the hot spots issue in the revision Federal Register notice and in the Technical Support Document: Methodology Used to Generate Deposition, Fish Tissue Methylmercury Concentrations, and Exposure for Determining Effectiveness of Utility Emission Controls in the docket.

3. Is it currently feasible, or will it be feasible within the compliance timeframes of the proposed rule, to accurate monitor a source's Hg emissions by species?

Comment:

As part of the commenter's ( OAR 2002 0056 5490) Mercury Research Program, they had purchased two Hg CEMS. The analyzers, manufactured by Nippon, are " dry" monitors and appeared to be fairly reliable. Most of the problems that the commenter saw had been in the sample conditioning system. A great deal of effort had gone into increasing the reliability of the sample conditioning system. High temperatures had to be maintained throughout or fouling of the glassware would occur. The commenter has installed a completely glass lined probe to help maintain closer tolerances with sampling temperatures. Even with all the effort put into making the system run reliably, they are only getting about 5 days of continuous operation without significant maintenance. Until these problems are resolved, it will not matter if the monitor can measure speciated Hg. The commenter's Hg CEMS are capable of measuring speciated ( elemental and oxidized) Hg.

Response:

EPA believes that field tests have demonstrated Hg CEMS to be accurate and reliable. The Hg CEMS have performed adequately for several months and meet the Ontario Hydro 9 163 Reference Method specifications. Furthermore, several dry chemistry Hg CEMS are currently being tested at sites that represent the most challenging conditions and the Agency plans to share with industry the results of such experiences to facilitate the selection of appropriate monitoring methodology. EPA also agrees with the commenter that the sample conditioning system provides one of the most challenging aspects of operating a successful Hg CEMS, but feels confident that substantial advancement of the sample conditioning system will occur before the implementation of the rule and as other monitoring techniques may become available, is allowing the use of systems that can meet performance based specifications.

The final rule requires the measurement of total vapor phase Hg, but does not require separate monitoring of speciated Hg emissions ( i. e., elemental and ionized Hg). Because of the potential impact of Hg speciation on local versus broader geographical deposition, the Agency considers separate monitoring of these emissions as a need to be addressed. However, at least two current monitoring technologies can accurately monitor speciated Hg emissions. The Agency will continue to test speciated Hg monitoring technologies. If these technologies are adequately demonstrated, the Agency may consider a proposed rulemaking within four to five years after program implementation, which should provide enough lead time for development and installation of these monitoring systems.

Comment:

One commenter ( OAR 2002 0056 5510) noted that speciated Hg emissions can currently be measured via the Ontario Hydro Method. However, when the tests are being conducted specific attention must be provided to the experimental method to ensure data reliability. As pointed out in the commenter's May 14, 2004, comments, EPA's IGR Part III data contain many instances of incomplete or invalid testing.

CEMS, or semi continuous methods like proposed EPA Method 324, for the measurement of total Hg emissions are projected to be available in the 2008 time frame and would be sufficient to demonstrate compliance with the proposed standards. The commenter believed adequate information can be gathered using CEMS or semi continuous methods for total Hg emissions, combined with periodic Ontario Hydro sampling for speciated emissions profiles, if adequate methods for monitoring speciated Hg are not developed by that time.

As noted in the commenter's May 14, 2004, comments, adequate technical data do not exist at this time to provide a reasoned basis for the allocation of allowances among coal types for purposes of an initial reduction in 2010. For this reason, the commenter recommended that Hg monitoring begin on affected units in the 2008 time frame in order to determine prospective emissions allocations by coal type for an interim 2015 emissions cap. The analysis required for setting appropriate allocations will necessarily require speciated emissions information over the full range of operational conditions including emissions during partial load, transient operations and during maintenance events.

Response: 9 164 The final rule requires the measurement of total vapor phase Hg, but does not require separate monitoring of speciated Hg emissions ( i. e., elemental and ionized Hg). Because of the potential impact of Hg speciation on local versus broader geographical deposition, the Agency considers separate monitoring of these emissions as a need to be addressed. However, at least two current monitoring technologies can accurately monitor speciated Hg emissions. The Agency will continue to test speciated Hg monitoring technologies. If these technologies are adequately demonstrated, the Agency may consider a proposed rulemaking within four to five years after program implementation, which should provide enough lead time for development and installation of these monitoring systems.

Comment:

One commenter ( OAR 2002 0056 5502) referenced future availability of speciating continuous Hg monitors. Assuming the developers ( and future suppliers) of continuous Hg monitors are successful in developing accurate, reliable and robust instruments for near continuous measurements of total Hg, they should be able to enhance these to also provide near continuous speciated measurements with 1 to 2 years after commercialization of the total Hg monitors.

Response:

At least two current monitoring technologies can accurately monitor speciated Hg emissions. EPA agrees with the commenter and the Agency will continue to test speciated Hg monitoring technologies. If these technologies are adequately demonstrated, the Agency may consider a proposed rulemaking within four to five years after program implementation, which should provide enough lead time for development and installation of these monitoring systems.

Comment:

One commenter ( OAR 2002 0056 5535) stated that EPA's specific question about whether it is currently feasible, or will be feasible within the compliance time frames of the proposed rule, to accurately monitor a source's Hg emissions by species is irrelevant. EPA has already stated that continuous Hg monitors that measure total Hg have been validated and will be required for compliance with the final rule. Total Hg emissions must be reduced from these sources.

Response:

The final rule requires the measurement of total vapor phase Hg, but does not require separate monitoring of speciated Hg emissions ( i. e., elemental and ionized Hg). Because of the potential impact of Hg speciation on local versus broader geographical deposition, the Agency considers separate monitoring of these emissions as a need to be addressed. However, at least two current monitoring technologies can accurately monitor speciated Hg emissions. The Agency will continue to test speciated Hg monitoring technologies. If these technologies are adequately demonstrated, the Agency may consider a proposed rulemaking within four to five years after 9 165 program implementation, which should provide enough lead time for development and installation of these monitoring systems.

Comment:

One commenter ( OAR 2002 0056 5497) stated that although the Ontario Hydro Method ( ASTM Method D6784 02) provides only short term emissions data, it is currently capable of providing accurate and repeatable data on Hg emissions at the stack by species. The commenter believed that speciated data collected by EPA pursuant to its Hg ICR using the Ontario Hydro Method clearly documents the need for subcategorization of the utility industry based on coal type in any final MACT rule.

As for continuous monitoring of Hg emissions by species, there is no commercially available monitor capable of providing Hg emissions data by species, and there is almost no possibility that a such a monitor will become available within the compliance timeframe of the proposed rules. A number of tasks remain to be completed before the existing Hg CEMS ( all of which measure total Hg) can be deemed sufficiently accurate and reliable for use in the proposed regulatory programs.

Response:

At least two current monitoring technologies can accurately monitor speciated Hg emissions. The Agency will continue to test speciated Hg monitoring technologies. If these technologies are adequately demonstrated, the Agency may consider a proposed rulemaking within four to five years after program implementation, which should provide enough lead time for development and installation of these monitoring systems. The final rule requires the measurement of total vapor phase Hg, but does not require separate monitoring of speciated Hg emissions ( i. e., elemental and ionized Hg). Because of the potential impact of Hg speciation on local versus broader geographical deposition, the Agency considers separate monitoring of these emissions as a need to be addressed.

C. EPA's Proposed Revised Benefits Assessment General Comments concerning EPA's Proposed Revised Benefits Assessment Comment:

The commenter ( OAR 2002 0056 5460) agreed that EPA should improve its estimate of human exposure to Hg that arises from power plant emissions. The commenter stated that two notes of caution must be sounded, however.

The commenter stated that first, the proposed revised benefits assessments methodology described in the NODA will not cure the fundamental defects in the proposed CAMR. The commenter pointed out that, for example, the revised methodology does not address, let alone 9 166 remedy, EPA's failure to calculate a proper Section 112 MACT floor. And, the commenter added, as long as EPA continues to underestimate the benefits associated with a proper Section 112 approach, it will continue to overestimate the comparative benefits of its proposed Section 111 approach. The commenter, therefore, reiterated that EPA should focus its energies on remedying the problems with its Section 112 proposal.

The commenter further stated that second, EPA cannot and should not delay regulation until all alleged scientific uncertainties concerning power plant Hg emissions have been resolved. The commenter stated that, to the contrary, to the extent uncertainties exist concerning Hg speciation, deposition, transport and exposure, EPA should err on the side of caution so as to fulfill the preventive and precautionary purposes of the Clean Air Act. See American Lung Ass'n, 134 F. 3d at 389; Lead Industries Ass'n, 647 F. 2d at 1155; see also 42 U. S. C. § 7412( d)( 2) ( requiring EPA to impose emissions standards that " require the maximum degree of reduction in emissions. . ."). The commenter added that, furthermore, as previously noted, EPA is required to regulate power plant emissions promptly.

Response:

EPA appreciates the commenters concerns. EPA is finalizing a cap and trade approach under section 111. Please see the Revision of December 2000 Regulatory Finding on the Emissions of Hazardous Air Pollutants from Electric Utility Steam Generating Units and the Removal of Coal and Oil fired Electric Utility Steam Generating Units from the Section 112( c) List for a discussion of the Agency's rationale for not proceeding under Section 112. For a discussion of our exposure modeling, please see the Technical Support Document: Methodology Used to Generate Deposition, Fish Tissue Methylmercury Concentrations, and Exposure for Determining Effectiveness of Utility Emission Controls and the Regulatory Impact Analysis in the docket.

Comment:

With regard to the first three steps of the proposed revised benefits assessment methodology, the commenter ( OAR 2002 0056 5460) reiterated that EPA should not allow any alleged uncertainties in the scientific evidence to prevent it from regulating power plant Hg emissions in a manner adequate to protect human health and the environment. The commenter stated that existing science confirms the need to regulate power plant emissions and any scientific uncertainties should be resolved in favor of more protective requirements.

Response:

EPA is finalizing a cap and trade approach under section 111. Please see Chapters 10 and 11 of the CAMR Regulatory Impact Analysis for a discussion of the exposure modeling and benefit methodologies used to analyze the benefits associated with this rulemaking.

Comment: 9 167 Two commenters ( OAR 2002 0056 5365,  5404) supported EPA's proposed general methodology for revising its assessment of the benefits associated with Hg emissions reductions from power plants. The commenters believed that the revised benefits assessment methodology generally is an appropriate, reasonably accurate quantification of benefits associated with the implementation of EPA's proposed regulation of Hg emissions ( See 69 Fed. Reg. 69864, 69872.). In particular, the commenters supported EPA's revised methodology insofar as it focuses on quantification of benefits from Hg reductions ( See 69 Fed. Reg. at 69873.). According to the commenters, that is, the Agency's requests for further comment in the NODA indicate that EPA's benefits analysis appropriately has shifted toward issues that are central to the purpose of the Hg regulation, in particular, changes in human exposure to Hg as a result of the emissions reductions that will be required by the rule, and potential consequent changes in public health ( See 69 Fed. Reg. at 69876.).

The commenters stated that by contrast, EPA's benefits assessment in the NPR dated Jan. 30,2004, as well as EPA's conclusion that the benefits of the proposed rule far outweigh the costs, was essentially faulty and misleading in that the assessment and its consequent conclusions were premised on tangential and/ or irrelevant information. According to the commenters, for example, in the NPR dated January 30,2004, EPA predicted that the implementation of Hg MACT would result in benefits equal to $ 15 billion which would be offset by costs equal to less than $ 2 billion   a net benefit valued at greater than $ 13 billion. The commenters stated that EPA's figures are misleading, however, because none of the quantified benefit is attributable to EPA's proposed Hg regulation. According to the commenters, rather, the benefit reflects ancillary NO x and SO 2 reductions expected to be achieved as co benefits resulting from the operation of MACT imposed Hg controls. The commenters stated that in any event, according to EPA, " most or all of the ancillary benefits of control would be achieved anyway, regardless of whether a section 112 MACT is promulgated." See 69 Fed. Reg. at 4711 ("[ E] ven if no [ mercury] controls were imposed [ pursuant to the rule making], most major coal fired units would have to reduce their SO 2 and NO x emissions as part of the effort to bring the nation into attainment with new air quality standards."). According to the commenters, considering the foregoing, EPA's benefits assessment in the NPR is of limited value, because it quantifies only benefits that are ancillary to the core purpose of the proposed rule and are likely to be realized in any case. The commenters believed that it is fundamentally inappropriate to justify a rule   as EPA did in the NPR   based on emissions reductions that are not related to the central purpose of the rule and that are likely to occur whether or not the rule is promulgated. Thus, in response to EPA's requests for comment regarding the revised benefits assessment, the commenters strongly believed that the Agency must focus on quantifying benefits that are central to the purpose of the regulation.