RESPONSE TO SIGNIFICANT PUBLIC COMMENTS ON THE PROPOSED CLEAN AIR MERCURY RULE Received in response to:

Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units ( 69 FR 4652; January 30, 2004)

Supplemental Notice for the Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units ( 69 FR 12398; March 16, 2004)

Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources, Electric Utility Steam Generating Units: Notice of Data Availability ( 69 FR 69864; December 1, 2004)

Docket Number OAR 2002 0056 1.0 INTRODUCTION AND BACKGROUND 2.0 APPLICABILITY AND SUBCATEGORIZATION US Environmental Protection Agency Emissions Standards Division Office of Air Quality Planning and Standards Research Triangle Park, North Carolina 27711 15 March 2005 i General Outline 1.0 INTRODUCTION AND BACKGROUND 2.0 APPLICABILITY AND SUBCATEGORIZATION 3.0 PERFORMANCE STANDARDS FOR COAL FIRED ELECTRIC UTILITY STEAM GENERATING UNITS 4.0 PERFORMANCE STANDARDS FOR OIL FIRED ELECTRIC UTILITY STEAM GENERATING UNITS 5.0 MERCURY CAP AND TRADE PROGRAM 6.0 MERCURY EMISSIONS MONITORING 7.0 IMPACT ESTIMATES 8.0 COMPLIANCE WITH EXECUTIVE ORDERS AND STATUTES 9.0 NODA 10.0 OTHER Appendix A LIST OF COMMENTERS 1 1 1.0 INTRODUCTION AND BACKGROUND The purpose of this document is to provide EPA's responses to public comments received on the notice of proposed rulemaking ( NPR), " Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units" ( Clean Air Mercury Rule; CAMR) ( 69 FR 4652; January 30, 2004); on the supplemental notice of proposed rulemaking ( SNPR), " Supplemental Notice for the Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units" ( 69 FR 12398; March 16, 2004); and on the notice of data availability ( NODA), " Proposed National Emission Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources, Electric Utility Steam Generating Units: Notice of Data Availability" ( 69 FR 69864; December 1, 2004).

The opportunity for written and oral public comment on the proposed rulemaking was announced with the NPR, the SNPR, and the NODA. Concurrent public hearings on the NPR were held on February 25 and 26, 2004, in Chicago, IL, Philadelphia, PA, and Research Triangle Park, NC. A public hearing on the SNPR was held on March 31, 2004, in Denver, CO. No public hearing was held on the NODA. The period for public comment on the NPR closed on March 30, 2004, but was extended to April 30, 2004, upon publication of the SNPR. Following numerous requests for an extension, the public comment period was reopened on May 1, 2004, and extended to June 29, 2004. The public comment period on the NODA closed on January 3, 2005. In addition, a telephone hotline was established for use by the public in providing comments.

EPA received approximately 500,000 comments on this proposed rulemaking, including numerous mass mailings and approximately 5,000 " unique" comments. A listing of the commenters is provided in Appendix A to this document. A complete set of the public comments received ( including the transcripts of the public hearings and telephone hotline calls) is available as part of eDocket OAR 2002 0056. This docket can be accessed at www. epa. gov/ edocket or through the U. S. EPA Docket Center, 1301 Constitution Avenue, NW, Washington, D. C., 20004 in the Public Reading Room, Room B102, EPA West Building, 8: 30 a. m. through 4: 30 p. m., Monday through Friday.

A summary of the public comments received and EPA's responses is contained in the subsequent chapters of this document. In this document, EPA has followed the following three criteria:

! Detailed responses are provided only for those comments deemed to be significant. Other comments may be summarized and general responses provided.

! Comments determined to be " late public comments" on the NODA ( i. e., received after the close of the public comment period for the NODA) are neither summarized in this document nor are responses provided. Comments received between June 30, 2004 1 2 ( following the June 29, 2004, end of the public comment period on the NPR and SNPR) and November 30, 2004 ( prior to the December 1, 2004, opening of the public comment period on the NODA) were considered in the decisions on the final rule because the comment period was reopened on December 1, 2004, if only on a limited number of issues. Responses are not provided to comments received after the close of the public comment period on the NODA on January 3, 2005, because there was insufficient time for adequate analyses of these comments.

! Comments received on the proposed Clean Air Act ( CAA) section 112( d) maximum achievable control technology ( MACT) approach and on the proposed approach to institute a cap and trade rulemaking under the authority of CAA section 112( n)( 1)( A) have neither been summarized nor responded to in this document. We have taken this approach because these two proposed regulatory approaches, which were two of the three regulatory approaches proposed, were not selected for promulgation. Some commenters on CAA section 112( d) discussed alternative measures of what the proper emissions standards would be under a MACT, or criticized EPA's methodology for estimating those standards. To the extent these commenters have stated, or believe, that EPA should have performed additional MACT calculations, and compared these revised calculations with the emissions reductions achieved under CAA sections 110( a)( 2)( D) and 111 before revising its 2000 CAA section 112( n) determination or promulgating CAMR, EPA disagrees. In assessing the effects of Hg emissions from U. S. utilities, EPA identified, to the extent possible given limits in data and modeling capability, all utility attributable Hg emissions that deposit in the U. S. or otherwise affect U. S. public health. EPA used this information   what would happen if Hg emissions form U. S. utilities were eliminated completely   to identify the effects, and any remaining risks, of today's regulatory actions. Because EPA has concluded the effects and benefits of emissions reductions beyond those achieved through the Clean Air Interstate Rule ( CAIR) and CAMR are small, and would not justify different decisions than those reached today, EPA has, therefore, not relied upon comparison between the emissions standards under a MACT and emissions after the actions adopted today. 2 1 2.0 APPLICABILITY AND SUBCATEGORIZATION 2.1 APPLICABILITY 2.1.1 Definitions Comment:

One commenter ( OAR 2002 0056 2922) stated that EPA uses the terms " coal fired electric utility steam generating unit," " integrated gasification combined cycle electric utility steam generating unit," and " oil fired electric utility steam generating unit" to define applicability in the proposed rules. However those terms are not defined anywhere in the proposed revisions ( or the existing 40 CFR 60). EPA should add definitions for those units that are consistent with the definitions in proposed 40 CFR 60 Subpart UUUUU and with the public comments on those definitions.

Response:

EPA has provided the additional definitions, as appropriate, as suggested by the commenter.

Comment:

One commenter ( OAR 2002 0056 2922) stated that EPA proposes to incorporate Hg and Ni standards into 40 CFR 60 subpart Da through section 60.45a( a) and ( b) and section 60.46a, respectively. As revisions to the NSPS, applicability of those limits to new units is limited to units that commenced construction after the proposal date of January 30, 2004. EPA proposes to reflect that limited applicability only by means of parenthetical statements in the compliance provisions in 40 CFR 60 Subpart Da 60.48a( m) and ( n). The commenters do not believe that EPA's approach is sufficient to make applicability clear. Instead, EPA should follow the approach it took with promulgation of a new output based NOx standard and also include a clear statement of applicability in the provisions setting out the new standards.

Response:

EPA has clarified the applicability language as suggested by the commenter.

Comment:

Several commenters ( OAR 2002 0056 2922,  2634,  2718) identified a number of instances where the definitions do not reflect the proposed regulatory provisions. For example, the provisions for regulation of " oil fired" units apply to any unit combusting oil. Because some coal fired units combust oil for start up, the definitions of " coal fired" and " oil fired" should be revised to make clear that units that combust both coal and oil are not " oil fired," and that any unit regulated as a coal fired unit is not subject to the " oil fired" unit limits. Those revisions 2 2 would be consistent with EPA's statements in the preamble regarding applicability.

Several commenters ( OAR 2002 0056 2634,  2718,  2922) stated that under the proposed rule, units combusting " natural gas at greater than or equal to 98 percent" of the unit's annual fuel consumption are not affected units under this proposal. Because other provisions in the rule state that they apply to " coal fired" units, the definition of " coal fired" should be revised to reflect the 98 percent or more exclusion for combustion of natural gas.

Response:

EPA has clarified the definitions. It was EPA's intention that the definition of a " coalfired boiler would be the governing definition. That is, if a unit burned coal, in any amount, then it would be classified as a " coal fired" boiler and subject to the Hg regulation. A unit that is designed to burn oil is more likely to be able physically and actually to combust natural gas interchangeably than is a unit designed to burn coal. Units continue to be exempt from the emission limits during periods of startup, shutdown, and malfunction. Therefore, coal fired units that combust natural gas during such periods would, during these periods, be exempt from the regulations.

Comment:

Several commenters ( OAR 2002 0056 2634,  2718,  2922) noted that the rule would include several exclusions related to combustion of " natural gas," which is not defined. Section 63.10042 should be revised to include a definition of natural gas. EPA should also consider whether combustion of synthetic gaseous fuels that are not derived from coal ( e. g., digester gas and landfill gas) also should be eligible for the 98 percent exclusion. The commenters believe that they should be.

Response:

EPA will add the definition of natural gas as suggested by the commenters. However, the other synthetic gases noted by the commenters are not " fossil fuels" under the definitions in 40 CFR 60.41a and, therefore, units firing these fuels would not be subject to this regulation unless such firing was in combination with the firing of coal.

Comment:

One commenter ( OAR 2002 0056 3449) stated that a definition of startup should be added to the rule.

Response:

" Startup" is already defined in the General Provisions at 40 CFR 60.2.

2.1.2 Industrial Boilers 2 3 Comment:

One commenter ( OAR 2002 0056 2331) agreed with EPA's position that the rule should apply to only electric utility steam generating facilities ( EGU). The commenter added that non EGU should not be included under the proposed rule. The commenter also stated that Hg emissions from industrial boilers are insignificant in comparison with those from EGU.

Response:

EPA concurs that industrial boilers should not be included in the same source category as electric utility steam generating units.

2.1.3 Cogeneration Units Comment:

One commenter ( OAR 2002 0056 2277) believed that consistent with Acid Rain regulations, the proposed definition of " electric utility steam generating unit" seems intended to exclude units that are primarily designed to provide power to industrial facilities. The commenter believed the definition seems intended to create two categories that are regulated, typical electricity generating utilities, and co generation units that supply more than one third of its potential electric output capacity and more than 25 megawatts electric ( MWe) output to any utility power distribution system for sale. The commenter noted that, however, as written, the first category seems overly broad and could be read to include the industrial units that are intentionally excluded from the second category ( those that supply less than one third of the units potential electric output capacity or less than 25 MWe output to any utility power distribution system for sale). The commenter further noted that, as written, the second category does not create an exemption from the first category, although it seems intended to create this exemption. To clarify that the regulation applies only to units that produce more than one third of their power for sale, the commenter suggested the definition be changed as follows:

Electric utility steam generating unit means any fossil fuel fired combustion unit of more than 25 MWe that serves a generator that produces more than one third of its potential electric output capacity and more than 25 MWe of its electricity for sale. A unit that co generates steam and electricity and supplies more than one third of its potential electric output capacity and more than 25 MWe output to any utility power distribution system for sale is also considered an electric utility steam generating unit.

The commenter noted that, alternately the regulation could be changed as follows to show that the second category exempts units from the first category:

Electric utility steam generating unit means any fossil fuel fired combustion unit of more than 25 MWe that serves a. generator that produces electricity far sale. A unit that co generates steam and electricity and supplies less than one third of its potential electric 2 4 output capacity or less than 25 MWe output to any utility power distribution systems for sale is not an electric utility steam generating unit.

Response:

EPA believes that the definition provided in revised subpart Da clearly defines two categories of new sources   utility units and non utility units ( which could include industrial boilers, combustion turbines, etc.). That is, a joint condition must be met in order to be classified as a Utility Unit   the unit must provide more than one third of its potential electric output capacity and more than 25 MWe electrical output to any utility power distribution system for sale. Further, the boiler itself must be capable of combusting more than 73 MW ( 250 million Btu/ hr) heat input ( which equates to 25 MWe on an output basis). The Agency's historical interpretation of the subpart Da definition has been that a boiler meeting the capacity definition ( i. e., greater than 250 million Btu/ hr) but connected to an electrical generator with a generation capacity of 25 MWe or less would still be classified as an " electric utility steam generating unit" under subpart Da. However, one or more new boilers with heat input capacities less than 250 million Btu/ hr connected to an electrical generator with a generation capacity of greater than 25 MWe would not be considered Utility Units because they individually do not meet the definition ( they would be considered industrial boilers). EPA acknowledges that there are differences in definitions between the NSPS program and the Acid Rain and other trading programs ( e. g., CAIR) that result from the underlying statutory mandates.

With regard to the amount of power sold to the grid and the " trigger" beyond which a unit is considered a Utility Unit for the purposes of this rulemaking, again there are definitional differences that have developed from the statutory mandates. EPA believes that new sources have the foreknowledge of the rules in effect and, thus, should be expected to be able to determine up front whether they want to be considered a Utility Unit or an industrial boiler ( i. e., do they plan on selling, or is it likely that they will sell, more than one third of their power in the future). Therefore, EPA considers a new cogeneration unit to be subject to the subpart Da Hg emission limit if it ever exceeds the definitional threshold. Existing units, discussed further elsewhere in this document, are brought into the program at its inception rather than at their start up. Therefore, EPA is using an annual average threshold for existing units, noting that if the threshold is ever met for a given year, then the unit will be considered a Utility Unit from there on out.

Comment:

Several commenters ( OAR 2002 0056 2085,  2206,  2906,  2922,  3525) recommended that the final rule allow cogeneration ( or combined heat and power; CHP) units above 25 MWe to supply up to 25 MWe electrical output or up to one third of their potential electrical output capacity to a utility power distribution system for sale on a net annual basis as is done in the Acid Rain program. This would likely minimize the possibility of non utility units being classified as utility units based upon unique situations of relatively short duration or of unrepresentative operating history ( e. g., if power was generally used exclusively at the plant at which it was generated, but was sold to the grid when the production facility was down for maintenance). In 2 5 the event that a unit were classified as a Utility Unit and had to meet a more stringent standard, the EPA should provide a reasonable period of time for the unit to come into compliance. Two commenters ( OAR 2002 0056 2206,  2906) stated that this requirement stands in contrast to EPA's proposed CAIR, where the definition for a Utility Unit is based on a historical annual average ( 69 FR 4610). The commenter stated that to prevent these undesirable consequences, and to prevent conflicts and confusion with the definition of a Utility Unit in the CAIR, EPA should base the Utility Unit definition on a net annualized average and not " during any portion of the year."

One commenter ( OAR 2002 0056 2085) stated that EPA created a new opportunity for misunderstanding by proposing in the rule that a cogeneration unit that meets the definition of a Utility Unit during any portion of a year would be subject to the proposed rule ( 69 Fed. Reg. 4657). The commenter believed that EPA should not adopt its proposed approach to cogeneration units that may operate as " electric utility steam generation units" on a short term or temporary basis. According to the commenter, the proposed approach will create complicated and unnecessary issues in implementation. The commenter asked is a " year" a calendar year or a 12 month rolling average? The commenter also asked how long does a cogeneration unit need to meet the " electric utility steam generation unit" definition to qualify  one day, one hour, or one minute? The commenter believed that EPA will not gain a material improvement in environmental conditions by creating these implementation problems ( caused by a unit being classified as an " electric utility steam generation unit" on a short term or temporary basis). According to the commenter, the Industrial Boiler MACT rule has Hg limits for boilers of the size involved here ( 40 CFR Part 63 Subpart DDDDD, Table 1). The commenter noted that for coal fired electric utility units, the principal environmental benefit is the Hg limit. The commenter believed these cogeneration units should be subject only to the Industrial Boiler MACT ( 40 CFR Part 63 Subpart DDDDD).

Three commenters ( OAR 2002 0056 2206,  2906,  3525) stated that in the preamble, EPA, absent rationale, states that any CHP unit that meets the definition of a Utility Unit during any portion of the year would become subject to the rule. The commenters stated that requiring a CHP unit to stay below the Utility Unit definition on an instantaneous basis provides a disincentive for facilities to invest in new CHP capacity or to maximize the output and efficiency of their current CHP and energy producing network of units. The commenters encouraged EPA to confirm that for purposes of its proposed definitions of " electric utility steam generating unit" and " cogeneration unit," all sales of electricity will be measured on a " net" annual basis, as is done in the Acid Rain program. The commenters stated that in determining that " net" basis, EPA's accounting should take account of the specific situation of major facilities with a number of cogeneration units. The commenters stated that at such plants, some units may be over the size threshold, while others may be below it. Yet, according to the commenters, the electricity from all those units will be pooled before it is either used in the plant or sold to the grid. In that case, the commenters believed EPA's accounting rules should provide for determining when the threshold conditions have been met by looking at all the electricity generated by all the cogeneration units, whether they were subject to the SIP call or not. The commenters asserted that no other approach would be administratively feasible. In addition, the commenters pointed out that, in some cases, contractual arrangements may exist between the cogeneration facility and 2 6 the local electric utility wherein all generated power is considered sold to the utility and all electricity used on the site is purchased from the utility. According to the commenters, in reality, only a small portion of the generated power really enters the grid from the cogeneration facility, and only that " net" sales of power should be considered when determining applicability with the EGU definition. Subject to these qualifications, the commenters supported the cogeneration unit threshold being used for consideration as an EGU, specifically, a unit serving a generator with a nameplate capacity of greater than 25 MW and supplying more than one third of its potential electric output capacity and more than 25 MW to any utility power distribution system for sale. The commenters stated however, it would provide additional clarity and prevent confusion if it was specifically stated that units associated with generators of 25 MWe capacity or less were not affected sources under this subpart; and any cogeneration units not supplying both more than one third of their potential electric output capacity and more than 25 MWe to any utility power distribution system for sale were not affected sources under this subpart. The commenters recommended that EPA include this additional clarifying language in the final rule.

Two commenters ( OAR 2002 0056 2206,  2906) stated that requiring a cogeneration unit to stay below the Utility Unit definition on an instantaneous basis would create a large disincentive for facilities to invest in new CHP capacity, or to maximize the output and efficiency of their current cogeneration and energy producing network of units. According to the commenters, cogeneration units are inherently more efficient than traditional Utility Units ( in many cases twice as efficient), and often provide distributed key power to the grid during transient or short term periods of peak power demand. The commenters stated that in order to prevent being included within the Utility Unit definition, many cogeneration units will likely establish tight restrictions on exporting excess power to the grid, or eliminate export all together. According to the commenters, this would have the perverse effect of reduced cogeneration unit power output, reduced overall grid efficiency and reduced industrial steam and electricity generation efficiency.

Response:

EPA believes that its historic interpretation of the subpart Da definition of an " electric utility steam generating unit" has been that meeting the criteria ( i. e., more than one third of its potential electric output capacity and more than 25 MW net electrical output to any utility power distribution system for sale) at any time subjects the source to subsequent compliance with the appropriate standard. Subpart Da is applicable to each new electric utility steam generating unit otherwise meeting the definition. Thus, there is no more basis for considering a group of cogeneration units for the purpose of determining applicability with the rule than there is currently for considering a group of non cogeneration boilers.

Comment:

One commenter ( OAR 2002 0056 3525) stated that in both the proposed rule and preamble ( 69 FR 4696 and 69 FR 4762), EPA applies the 18 CFR 292.205 efficiency methodology to cogeneration facilities ( implied to be limited to solid fuel fired facilities because gas fired units are not included in the rule applicability). The commenter submitted that this 2 7 proposed emission rate calculation for cogeneration units appears to unfairly penalize them for sales of any electric power less than the full generation capacity. According to the commenter, such a penalty is contrary to the Bush Administration's stated intent to advance the application of cogeneration facilities and thereby improve the nation's energy efficiency and achieve greenhouse gas emission intensity reductions. The commenter strongly encouraged EPA to reconsider this approach. The commenter believed a much more equitable and workable approach would be to provide cogeneration facilities with the ability to use input based emission limits and calculations. The commenter stated that in that way, the boiler, fuels, and emissions controls will determine compliance without the apparent emission rate being unfairly skewed by the portion of electricity sold to the grid. According to the commenter, this method also follows from past EPA practice in establishing emissions standards. The commenter submitted that EPA should establish emissions standards that encourage installation and operation of highly efficient cogeneration facilities, and recognize their inherent variability in design and operating profiles versus typical single use electric utility units.

Response:

The approach EPA has taken with regard to crediting the steam generated beyond that necessary to generate electric power in a cogeneration system is consistent with that taken during the earlier revision of the subpart Da NOx emission limits. We believe that consistency is appropriate for this application.

Comment:

Two commenters ( OAR 2002 0056 2906,  3525) supported EPA's decision not to set emission limits for utility units that burn 98 percent or more of natural gas. The commenters noted that historically, EPA has not drawn a distinction among natural gas and other refinery or process gases, but rather has determined to define and regulate them as simply " gaseous fuels." The commenters noted that although most commercial gas fired utility units burn natural gas, many CHP units located at petroleum refineries or petrochemical facilities also burn some amount of refinery fuel gas or other process gas that is being produced and consumed onsite for energy production. Commenter OAR 2002 0056 2906 noted that in the Industrial Boiler MACT, EPA included not only natural gas but also process gas and refinery gas in the same subcategory. In other words, in that rule EPA did not draw a distinction among natural gas and other refinery or process gases, but rather defined and regulated them as simply " gaseous fuel." The commenter stated that this same issue exists for Utility Units under the proposed rule, and in particular cogeneration units that meet EPA's definition of a Utility Unit. The commenter believed that most readers would conclude that this rule and its emission limits do not apply to CHP type or other utility units that burn 98 percent or more of natural gas, including other gaseous fuels. The commenters stated that, however, it would help clarify matters if the rule specifically stated that this exemption applies not just to natural gas, but also to other gaseous fuels such as process and refinery gases, as well as other non residual fuel oil fuels, in keeping with EPA's approach in the Industrial Boiler MACT.

Response: 2 8 EPA believes that a reasonable interpretation of its exclusion provision for natural gasfired units would include other gaseous fossil fuels. However, EPA has clarified in the final rule to indicate that only units that combust coal, in any amount, or any coal derived fuel are subject to the rule.

2.1.4 Combined Heat and Power Units Comment:

Several commenters ( OAR 2002 0056 2066,  2206,  2833,  3530) stated that the final NSPS utility rule should not extend its mandates to either current or future CHP systems. The commenters stated that in virtually all cases, CHP units are a source of highly efficient power with correspondingly low emissions. According to the commenters, because cogeneration units are generally twice as efficient ( i. e.; more output per unit of input) as non CHP Utility Units, they consume less coal and oil, and have significantly less emissions than fossil fuel burning non CHP Utility Units. The commenters asserted that, for this reason, encouraging CHP units should be part of EPA's strategy toward reducing harmful emissions from the electricity generating sector. The commenters stated that the Agency should not, therefore, seek to impose additional regulation on these units. The commenters added that hundreds of industrial facilities depend on the economic efficiencies of CHP. The commenters stated that in fact, the President's National Energy Policy recommends the increased use of CHP systems to improve energy efficiency and decrease air emissions ( See National Energy Policy, Report of the National Energy Policy Development Group, May 2001, pp. 4 11 and 6 18). The commenters also stated that however, industrial units should be given the opportunity to voluntarily opt in to the benefits of the cap and trade program. The commenters stated that any opt in provision should be drafted to encourage participation and recognize cost effective emission reductions tailored to the unique attributes of manufacturing facilities.

Two commenters ( OAR 2002 0056 2066,  2206) stated that CHP units currently represent only about 3 percent of the electric generating capacity covered by Agency's proposal. According to the commenters, CHP units are generally twice as efficient when compared to their utility counterparts, and about two thirds of all CHP units burn natural gas and have extremely low NOx emission rates. The commenter stated that although individual CHP emission rates will vary, the average gas fired CHP emission rates are only 15 to 25 percent of that emitted by a typical utility. The commenter added that even CHP units using coal or oil as a fuel source are still much more efficient than a utility using the same fuels. The commenter further stated that CHP units are usually only a small part of a much larger industrial facility or complex. According to commenter OAR 2002 0056 2206, including CHP units in this rule may require them to install flue gas desulfurization ( FGD) or selective catalytic reduction ( SCR) control technology by 2010 or purchase credits. The commenter stated that these costs will be a significant disincentive to building these environmentally superior forms of electricity generation and could significantly impair continued reliance on this type of environmentally wise technology. The commenter asserted that including these units into this rulemaking would layer another set of regulations on the entire facility, thus further complicating on going compliance efforts, and, because there are relatively little emissions coming from such units, not significantly reduce the amount of Hg. The 2 9 commenter added that EPA is proposing that compliance with its new standards will be based on emissions attributable to combustion for electricity generation, and not from steam production ( See e. g., 69 FR at 4,668 and 4,696). For these reasons, the commenters believed that CHP units should be exempted from inclusion in this rulemaking. According to the commenters, inclusion of traditional CHP facilities would provide negligible environment benefit while discouraging application of these ultra efficient power and steam generators both now and in the future.

Response:

EPA sees no reason to exclude cogeneration or CHP units that otherwise meet the definition of " electric utility steam generating unit" from the final rule, as units meeting the definition would, like other similarly sized but non cogeneration units, be emitters of Hg.

2.1.3 Other Comment:

One commenter ( OAR 2002 0056 2835) stated that for any regulatory program for Hg and Ni emissions, EPA should clarify that compliance with the regulatory requirements qualifies as a pollution control project. The commenter stated that regardless of whether EPA implements a regulatory program under CAA section 112( d), section 112( n)( 1)( A), or section 111, the regulation should provide that projects and/ or activities undertaken by electric utilities to comply with the obligations of a Hg regulatory program do not trigger the requirements of New Source Review ( NSR) or Prevention of Significant Deterioration ( PSD). The commenter further stated that as a matter of policy, an affected source should not trigger additional regulatory requirements when undertaking efforts to comply with a set of new regulations, particularly where the new rules lead to reductions in HAP.

The commenter noted that the proposed emission guidelines for oil fired units already include a provision in Section 60.4010( b) which states that "[ p] hysical or operational changes made to an existing electric utility steam generating unit solely to comply with an emission guideline are not considered a modification or reconstruction and would not subject an existing electric utility steam generating unit to the requirements of subpart Da ( see Section 60.40a of subpart Da)." The commenter recommended that this provision be expanded to include the requirements imposed by the NSR and PSD programs. Furthermore, the commenter urged EPA to include this expanded provision in any regulatory program for all electric utilities ( i. e., the MACT standard or a cap and trade program). The commenter stated that by making the rule explicit that such projects would not trigger the NSR and PSD programs, EPA avoids the situation where State permitting agencies have to second guess whether implementation projects and activities are indeed pollution control projects.

Response:

NSR and PSD are only triggered through emission increases. Compliance with the promulgated rule would not result in emission increases and, thus, would not trigger NSR or 2 10 PSD.

2.2 SUBCATEGORIZATION The proposed NSPS includes Hg emission limits for new coal fired units subcategorized by coal rank ( bituminous, subbituminous, lignite, waste coal, integrated gasification combined cycle [ IGCC]). The rationale for subcategorization under section 111 is the same as was described in the January 30, 2004, proposed section 112 standards. Therefore, many commenters only addressed subcategorization in the context of section 112; it is presumed that their comments, when not otherwise explicitly stated, also pertain to the proposed section 111 standards.

2.2.1 Support for Subcategorization Comment:

One commenter ( OAR 2002 0056 2915) pointed out that under CAA section 111, EPA has previously subcategorized coal fired utility units based on the sulfur levels in the coals they burn. The commenter noted that this subcategorization approach was approved by the U. S. Court of Appeals for the District of Columbia Circuit in Sierra Club v. Costle, 657 F. 2d 298 ( D. C. Cir. 1981). The commenter stated that in approving EPA's NSPS regulations, the Court recognized that CAA section 111 allowed EPA " to distinguish among classes, types and sizes within categories." The commenter noted that the Court explained that "[ o] n the basis of this language alone, it would seem presumptively reasonable for EPA to set different... standards for utility plants that burn coal of varying sulfur content." Thus, the Court found that EPA could create subcategories based on the type of fuel an EGU burns.

One commenter ( OAR 2002 0056 2862) stated that in establishing a new source NSPS for Hg, EPA should subcategorize coal fired power plants based on the rank of coal fired. The commenter stated that pursuant to CAA section 111( b)( 2), EPA has the authority to distinguish among classes, types, and sizes within categories of new sources for the purpose of establishing NSPS standards. ( 42 U. S. C. section 7411( 2)) The commenter stated that it supports EPA's proposed subcategorization of coal fired power plants based on coal rank and also referred to the Circuit Court case ( Sierra Club v. Costle, 657 F. 2d 298 ( D. C. Cir. 1981)).

Several commenters ( OAR 2002 0056 2067,  2161,  2247,  2264,  2332,  2365,  2375,  2634,  2721,  2725,  2835,  2891,  2897,  2898,  2900,  2907,  2911,  2915,  2918,  2948,  3198,  3200,  3398,  3440,  3469,  3514,  3537,  3539,  4139,  4191) supported EPA's use of subcategories. Two commenters ( OAR 2002 0056 2375,  2918) supported EPA's decision to subcategorize bituminous, subbituminous, and lignite burning affected units and stated that EPA's subcategorization based on coal rank is proper under section 111, which gives EPA broad authority to subcategorize as it deems appropriate. The commenter also stated that the CAA, as interpreted by the D. C. circuit and the legislative history, make clear that EPA has broad authority to distinguish among classes, types, and sizes of sources to account for differences in the effectiveness of control technology. One commenter ( OAR 2002 0056 2375) stated that EPA's 2 11 approach to the subcategorization of electric utility steam generating units is generally appropriate and consistent with the CAA and believes that subcategorization of coal fired and oil fired units into two subcategories is warranted based on their distinct emissions profiles and their typical uses as base load and peaking units, respectively. The commenter also supported EPA's proposal to subcategorize coal fired units by coal rank, in part, to account for the significant impact coal rank can have on overall plant design, the design process and the operation of pollution controls.

According to several commenters ( OAR 2002 0056 2067,  2365,  2375,  2725,  2898,  3198,  3514), subcategorization by coal rank is amply supported by the differences in Hg speciation that in turn impact the effectiveness of control technology. One commenter ( OAR 2002 0056 2891) notes that cooperatives are users of all three general coal ranks and, in relation to the rest of the industry, are heavy users of subbituminous and lignite coals. The commenter stated that because it is much more difficult and expensive to reduce Hg emissions from these when compared to eastern bituminous coal, a single standard for Hg emission limits for all coal fired power plants would be impossible, as a practical matter, for some lignite and subbituminous coal burning plants to meet. The commenter believed that it is imperative that in the final rule, the use of any specific coal type or rank must not be advantaged or disadvantaged.

One commenter ( OAR 2002 0056 2897) stated that concerns that subcategorization causes an increase in allowable Hg emissions are unjustified in that under a cap and trade system, the emissions cannot exceed the cap, and under a MACT system the average floor effectively sets the emission level. The commenter believed that subcategorization does not necessarily raise emissions but merely ensures that the compliance burden is evenly distributed. The commenter also stated that concerns that subcategorization may result in more complex permitting are overstated and can be resolved. The commenter indicated that permitting is a relatively minor issue compared with the disruption to the nation's energy system and fuel switching, including switching to gas, that will occur if bituminous and subbituminous coals are not subcategorized separately.

One commenter ( OAR 2002 0056 2375) supported EPA's subcategorization of IGCC units based on the distinct processes that such units employ ( i. e., they are the only units that do not combust coal in the unit during operation).

One commenter ( OAR 2002 0056 2948) supported EPA's decision to subcategorize electric utility steam generating units and stated that EPA should place oil fired units in a different category than coal fired units because emissions from those plants differ markedly.

One commenter ( OAR 2002 0056 2721) agreed with EPA's proposed five subcategories  four based on coal ranks and one for process type  and disagreed with the option to combine subbituminous with bituminous coals for the purposes of Hg regulations. The commenter did not agree that a five category program places a burden on the Utility Unit for tracking burn rates from various coal sources on a monthly or annual basis. The commenter asserted the practical implications of this co categorization would be significant. The commenter stated that the differences in the Hg emission levels on subbituminous and bituminous coals are great and have been well documented and published in the ICR data. The commenter noted that these coals are 2 12 currently blended for sulfur compliance. The commenter stated that because of the significant higher sulfur content in the bituminous coal, the reverse scenario of blending bituminous coal with subbituminous coal for Hg compliance would be detrimental to the SO2 compliance of the facility.

Several commenters ( OAR 2002 0056 2260,  2560,  2725,  3440) supported EPA's proposal to use subcategories in setting emissions limits and providing allocations to adequately address differences in abilities to control Hg based on coal chemistry that varies with coal rank. One commenter ( OAR 2002 0056 2560) stated that their coal fired facilities have different boiler configurations and fuel firing abilities, and that this is typical for the industry. The commenter further stated that a key consideration in Hg removal from coal is the presence or lack of halogens. The commenter supported subcategorization in that it recognizes the technological challenges presented by the lack of halogens in Powder River Basin ( PRB) subbituminous coals.

One commenter ( OAR 2002 0056 2725) believes that subcategorization should include at least three categories: lignite, subbituminous, and bituminous coals. The commenter stated all these coal ranks behave differently when burned, releasing significantly different levels of Hg that may require different controls. The commenter adds that Hg control costs for lignite and subbituminous coals may be higher at plants that already have particulate matter ( PM) and sulfur dioxide ( SO2) controls than the control costs for plants burning bituminous coal. The commenter stated that any regulation of Hg that includes a one size fits all standard would unfair. The commenter stated that lignite and subbituminous coals are fundamentally different from bituminous coal.

Several commenters ( OAR 2002 0056 2830,  3543,  3406) supported the separate treatment of lignite through the subcategorization process.

One commenter ( OAR 2002 0056 3208) believed it is important for EPA to recognize the relative disadvantage at which it now places PRB subbituminous coal due to the preponderance of elemental Hg in its content. The commenter submits that PRB coal now will be placed at risk in contravention of previous environmental policies that encouraged its use. According to the commenter, these factors should motivate EPA to recognize the need for subcategorization of coals in determining MACT for Hg removal.

In supporting EPA's decision to create separate subcategories for bituminous and subbituminous coals, one commenter ( OAR 2002 0056 2897) stated that bituminous coals are more likely to be used in a plant equipped with wet flue gas desulfurization ( wet FGD) for SO2 control and selective catalytic reduction ( SCR) for nitrogen oxides ( NOx) control and are, therefore, more likely to benefit from " co benefit" capture in these systems, whereas a subbituminous coal is more likely to be burned in a plant with a dry scrubber, which has shown no quantifiable Hg capture in testing to date. The commenter also stated that supra fuel switching is not a viable solution and failing to subcategorize between bituminous and subbituminous would create regional disparities.

Several commenters ( OAR 2002 0056 1969,  2161,  2535,  2661,  2843,  2867,  2891,  2897,  3539) supported separate subcategories stating that there are significant differences 2 13 between the two coals, subsequent speciation of the Hg in the flue gases, and differences in achievable emission reductions. One commenter ( OAR 2002 0056 2661) stated that if coal ranks were combined into a single category, rural electric consumers would be negatively impacted. The commenter stated that if a single standard for Hg emission limits were set for all coal fired power plants, based on bituminous rank coals, it would be impossible, as a practical matter, for some lignite and subbituminous coal burning plants to meet that standard. One commenter ( OAR 2002 0056 2891) stated that cooperatives are users of all three general coal ranks and, in relation to the rest of the industry, are heavy users of subbituminous and lignite coals and would be disadvantaged under a single emission limit.

One commenter ( OAR 2002 0056 2948) stated that EPA should subcategorize units based on differences between coal ranks. The commenter did not believe, however, that EPA should place units burning coals of more than one rank in a separate subcategory because large differences exist in the way plants burn coals of more than one rank.

One commenter ( OAR 2002 0056 2067) agreed with EPA that there is no demonstrated justification to create a separate category for circulating fluidized bed ( CFB) units.

Response:

EPA concurs with the commenters.

2.2.2 No Subcategorization Comment:

Many commenters ( OAR 2002 0056 2575,  2823,  2878,  2920,  3459) doubt the legality of EPA's use of subcategorization by coal rank. One commenter ( OAR 2002 0056 2920) stated that EPA's proposal to subcategorize by coal rank is unlawful, arbitrary, and capricious for the following reasons:

( 1) EPA provides no reason to believe that just because some plants are located near mine mouths ( e. g., lignite plants), they are of a different class, type, or size than other units;

( 2) EPA argues that the characteristics of the coal rank to be burned was the driving factor in how a unit was designed, but does not say what those design differences are and does not claim that any such differences are so great that plants designed to burn different ranks of coal are different classes, types, or sizes of a unit;

( 3) EPA admits that many plants burn two or more different ranks of coal;

( 4) EPA admits that its basis for subcategorization was to ensure that standards are achievable for all sources through the use of certain technologies. According to the commenter, this argument has been found unlawful ( Cement Kiln Recycling Coalition v. 2 14 EPA);

( 5) EPA appears not to have seriously considered alternative subcategorization approaches or no subcategorization.

One commenter ( OAR 2002 0056 2878) stated that EPA fails to provide any technical rationale to justify why coal rank should define the allowable emissions a unit can emit when technology is available that enables all plants to meet high levels of Hg control regardless of coal rank. According to the commenter, EPA's rationale is based on a misguided claim that boilers are specifically designed for a specific rank of fuel. Yet, according to the commenter, units burn more than one rank of coal in the same boiler. In support, the commenter cited the Stanton study which showed that high levels of Hg reduction can be achieved with currently available technology, regardless of coal rank. According to the commenter, the Stanton study was used as the basis for Iowa's recent permit for a new unit burning subbituminous coal from the PRB that requires 83 percent reduction using activated carbon injection ( ACI) or other sorbent injection.

According to one commenter ( OAR 2002 0056 2823), 11 State Attorneys General contend that EPA's proposed subcategorization by coal rank is unlawful because:

( 1) EPA applied the scheme inconsistently ( i. e., EPA cannot insist that emission standards be set for specific subcategories and then reject standards that are so tailored because they are not appropriate for every unit in the category as a whole);

( 2) EPA's scheme does not accurately reflect industry practices as it applies to the subcategorization scheme because there are units that burn more than one rank of coal; and ( 3) The proposed scheme does not serve to protect health and the environment in that EPA admits that it elected to subcategorize by coal rank so as to produce a standards achievable by all units, ensuring that units continue to operate rather than on protecting human health and the environment.

One commenter ( OAR 2002 0056 2575) argued that subcategorization can only be done on three criteria: class, type, and size of sources and the factor that coal rank is one of the characteristics of a coal fired boiler does not mean it can be used for subcategorization. The commenter stated that EPA's reliance on coal rank is misplaced because many coal fired units blend or fire two or more ranks of coal in the same boiler and EPA itself states that coal blending is possible and not uncommon. The commenter stated that EPA also claims ( with no support) that fuel switching would require significant modification or retooling of a unit. The commenter cited case law to support its contention that EPA's subcategorization is not permitted. The commenter stated that EPA's justification for rejecting a no subcategorization option is factually and legally indefensible. That is, EPA based its subcategorization on two principles:

( 1) plants were largely designed based on coal rank to be burned and fuel switching would be problematic, and 2 15 ( 2) the type of coal rank to be burned is based on economic issues, including availability withing the area.

The commenter stated that, as stated above, reliance on coal rank is factually wrong and fuel switching is a common practice.

According to one commenter ( OAR 2002 0056 3459), EPA's proposed subcategories are contrary to law, without rational basis, arbitrary and capricious, and an abuse of discretion. The commenter stated that EPA proposes subcategorization by coal rank, based on the arguments that combustion technologies are coal rank specific and that many utilities are dependent on particular mines and, therefore, particular ranks of coal. According to the commenter, these arguments are not supported by the facts:

( 1) Utilities regularly burn more than one rank of coal together and there is no significant technical difference in the boilers receiving various ranks of coal.

( 2) EPA's reliance on American Society for Testing and Materials ( ASTM) methods to determine coal rank is so technically problematic that it erodes EPA's rationale for subcategorization by coal rank. Coal rank is not an easily discernible and always clear characteristic of coal and EPA itself acknowledges some overlap.

( 3) Individual mines can produce different ranks of coal. EPA's justification that many utilities are dependent on particular mines and therefore particular ranks of coal is not supported.

( 4) EPA acknowledges that coals of varying ranks have similar combustion and handling properties, and operators have learned to handle these blends but then ignores it.

( 5) EPA's assumptions also differ from real world experience where many units switched to low sulfur coal to satisfy the acid rain program requirements, demonstrating that units are capable of burning a mix of coal ranks.

( 6) Even if different ranks do have different properties, coal treatment technology may allow one coal rank to act in ways that make it more like a coal of a different rank. EPA acknowledges that a key consideration in subcategorization decisions is whether different units have differences in the feasibility in the application of control technology. However, available evidence shows that units burning different ranks of coal are equally amenable to Hg pollution controls. Both high and low rank coals ( such as bituminous and subbituminous) coal can be controlled by the same control technology ( 7) Although EPA has only spurious rationale for subcategorization of existing units; there is no rationale for new units. These can be designed to provide optimum performance when firing all coal ranks.

Response: 2 16 EPA continues to believe that it has the statutory authority to subcategorize based on coal rank and process type, as appropriate for a given standard. As initially structured, subpart Da subcategorized based on the sulfur content of the coal ( essentially based on coal rank) for SO2 emission limits and based on coal rank for NOx emission limits. This approach was selected because of the differences in the relative ability of the respective control technologies to effect emission reductions on the various coal ranks. Although EPA has subsequently changed the format of the NOx emission limits and has recently proposed to establish common SO2 emission limits regardless of coal rank ( 70 FR 9706), we believe that the conditions existing at proposal of the previous standards ( e. g., the inability of the technologies to control SO2 and NOx equally from all coal ranks) equally apply now for Hg and justify the use of subcategorization by coal rank for the Hg emission limits. This does not indicate, however, that at some point in the future, the performance of control technologies on Hg emissions will not advance to the point that the rank of coal being fired is irrelevant to the level of Hg control achieved ( similar to the point reached by controls for SO2 and NOx emissions). At that time, EPA may adjust the approach to Hg controls appropriately.

Comment:

Many commenters ( OAR 2002 0056 1471,  1611,  1682,  1686,  1687,  1773,  1861,  2108,  2160,  2243,  2334,  2415,  2441,  2819,  2833,  2878,  2887,  2889,  2924,  3199,  3435,  3437,  3440,  3449) opposed the use of subcategories based on fuel types. One commenter ( OAR 2002 0056 3199) recommended that EPA establish fuel neutral limits that account for the high variability in coal, combustion processes, and control system performance under different types of firing conditions. Several commenters ( OAR 2002 0056 1471,  1611,  1773,  1861,  2108) believe that subcategorization by coal rank is not warranted or is otherwise questionable because a unit can burn bituminous or subbituminous coal with no change to the boiler. They argued that a fuel neutral rule would provide an incentive for plants to blend the two ranks of coal and point to the industrial boiler MACT which was fuel neutral. These commenters stated that subcategorization by coal rank simply guarantees the continuing use of Hg heavy fuel. In opposing subcategorization, two commenters ( OAR 2002 0056 2243,  2878) stated that the percent removal requirement should be the same for all fuel ranks and unit configurations. One commenter ( OAR 2002 0056 2878) recommended a single performance standard to reduce emissions by 90 percent in 2007 and stated that this can be achieved by ACI with an electrostatic precipitator ( ESP) and a retrofit fabric filter or a fabric filter alone.

Several commenters ( OAR 2002 0056 1682,  1686,  1687,  2108) oppose subcategorization by coal rank because plants burning western, subbituminous, or lignite coal remain uncontrolled while plants burning eastern bituminous coal must have one or more controls. The commenters stated that this is inconsistent with the CAA's fuel neutrality and harms the economies of States with eastern coal. According to the commenters, Illinois has seen a 25 percent increase in Hg emissions due to a switch to subbituminous coals. They stated that this impact has not been reflected in the EPA analyses. One commenter ( OAR 2002 0056 2160) stated that Illinois, Indiana, Ohio, and West Virginia oppose subcategorization by coal rank and prefer limits that are fuel neutral. The commenter stated that the more stringent limits for bituminous coal will result in fuel switching with severe economic impacts on States that produce 2 17 bituminous coal and negligible emission reductions due to switching to subbituminous coal as the low cost compliance strategy for Hg. One commenter ( OAR 2002 0056 2819) supported a single fuel neutral limit that would not be any less stringent than the rules proposed by New Jersey and promulgated by Massachusetts. According to the commenter, compliance can be achieved through currently available technologies: for a cyclone boiler, SCR can be used in conjunction with FGD or ACI and a particulate control device, and, for a tangential boiler, compliance can be achieved through an appropriate PM control device that collects fly ash if needed or by ACI with a particulate control device when fly ash re injection systems are used. Two commenters ( OAR 2002 0056 2924,  3449) oppose subcategorization on the grounds that the higher limit for subbituminous coal could encourage operators to switch and blend fuels resulting in an increase in Hg emissions. One commenter ( OAR 2002 0056 2924) stated that as a result, they would continue to be impacted by Hg emissions from other areas and that differentiation should be based on the type of unit ( which would not discriminate against fuel type), not the rank of coal.

One commenter ( OAR 2002 0056 3449) stated that subbituminous coals or blends of subbituminous and bituminous coals can frequently be burned in units previously burning only bituminous coal without extensive retrofit. According to this commenter, combustion of waste coal or anthracite coals also results in similar emissions; thus, separate limits for bituminous, subbituminous, and waste coal is questionable. One commenter ( OAR 2002 0056 2889) stated that if EPA had used a sufficiently long averaging time ( which it did not attempt to address), it would obviate the need to consider variability of coal Hg content, allowing a coal neutral rule. The commenter stated that another difficulty with the subcategorization scheme is the inaccuracy typically encountered in determining the amount of different ranks of coal in a blend, which is typically done in a bulldozer. One commenter ( OAR 2002 0056 2887) stated that practical reasons for limiting the number of subcategories is the reduced regulatory burden and increased plant flexibility in fuel procurement and management strategies. One commenter ( OAR 2002 0056 2819) stated that EPA's analyses supporting subcategorization are severely flawed because of the limited amount of stack test data collected and analyzed to date. The commenter stated that as more data is collected ( primarily at the State level), it is evident that factors other than coal rank are more important in determining Hg speciation and the ability of commercially available control technologies to reduce emissions from coal fired boilers. According to the commenter, important factors that affect Hg speciation and control effectiveness include: the combustion efficiency of the utility boiler, and the combination of control. One commenter ( OAR 2002 0056 3437) stated that subcategorization creates a competitive advantage for western coal that is not justified and is inconsistent with other Federal programs such as the NOx SIP Call and the proposed Clean Air Interstate Rule ( CAIR; originally titled at proposal the Interstate Air Quality Rule, IAQR), which are fuel neutral. One commenter ( OAR 2002 0056 3435) stated that the variability of the Hg and chlorine ( Cl) content of coal within a rank, the ability of a unit to burn more than one rank of coal, and the magnitude of the difference in emission limits diminishes the merit of subcategorization by coal rank, particularly for bituminous and subbituminous units.

One commenter ( OAR 2002 0056 2944) disagreed with the proposal to subcategorize based on coal ranks. The commenter stated that coal rank is a continuous variable, a function of 2 18 degree, not one of kind, stretching from before peat on the one end to past anthracite on the other. The commenter noted that these classifications grade into each other and in many cases can be subject to dispute and added that, as noted in the proposed rules, the ASTM classification of coal rank has overlapping attributes.

One commenter ( OAR 2002 0056 2944) noted that U. S. boilers commonly fire mixes of coals of different ranks, citing information from the ICR that although around 215 utility boilers burned only subbituminous coals, nearly as many burned both combinations of subbituminous and bituminous. The commenter added that about 25 percent of the boilers that burned lignite burned other coal ranks as well. The commenter further stated that over the last two decades a very significant number of U. S. plants converted their boilers from burning high sulfur bituminous coals to low sulfur subbituminous coals to reduce their SO2 emissions. According to the commenter, obviously, there is nothing particularly unique about coal rank that should lead to subcategorization and dramatically different Hg emission limits. The commenter observed that U. S. coal fired boilers burn combinations of many carbonaceous fuels: in addition to lignite, subbituminous, and bituminous coals they burn anthracite, petroleum coke, waste subbituminous, waste bituminous, waste anthracite, biomass, and waste tires. The commenter asked is it logical, or practical to have separate emission standard determinations for each. The commenter further asked how can compliance be fairly determined at the over 20 percent of plants that burn multiple fuels simultaneously.

The commenter continued that the three primary coal fired boiler fuel types contain Hg relative to their heating value at about the same degree. The commenter stated that each coal rank has about 70 percent of its deliveries with Hg contents measured between 4 and 14 pounds of Hg per trillion British thermal units ( lb/ TBtu). The commenter added that median Hg contents of each coal rank are also similar at 7, 5 and 8 lb Hg/ T Btu for bituminous, subbituminous, and lignite respectively. ( The commenter further noted that although subbituminous coals contain less Hg than bituminous coals, they ended up being allowed to emit nearly three times as much in the currently proposed regulations.) The commenter stated that there is nothing obvious about the Hg content of coals of different ranks that justifies subcategorization.

Response:

EPA believes that there are sufficient differences in the design and operation of utility boilers utilizing the different coal ranks to justify subcategorization by major coal rank. As documented in the record, utility boilers vary in size depending on the rank of coal burned ( i. e., boilers designed to fire lignite coal are larger than those designed to fire subbituminous coal which, in turn, are larger than those designed to fire bituminous coal). Boilers designed to burn one fuel ( e. g., lignite) can not randomly or arbitrarily change fuels without extensive testing and tuning of both the boiler and the control device. Further, if a different rank of coal is burned in a boiler designed for another rank, either in total or through blending, the practice is only done with ranks that have similar characteristics to those for which the boiler was originally designed. That is, the ASTM classification system is structured on a continuum based on a number of characteristics ( e. g., heat content or Btu value, fixed carbon, volatile matter, agglomerating vs. non agglomerating) and provides basic information regarding combustion characteristics. 2 19 Because more than one characteristic is used, the possibility exists for numerous situations where a coal could be " classified" in one rank based on one characteristic but in another rank based on another characteristic. Ranking is based on an evaluation of all characteristics. Therefore, it is possible that ( for example) a non agglomerating subbituminous coal with a heating value of 8,300 Btu/ lb ( ASTM classification III. 3   " Subbituminous C coal") could be co fired with, or substituted for, a non agglomerating lignite coal with heating value of 8,300 Btu/ lb ( ASTM classification IV. 1" Lignite A coal"). This does not, however, mean that it is possible for a boiler designed to burn the Lignite A coal to burn an agglomerating coal with a heating value of 13,000 Btu/ lb ( e. g., ASTM classification II. 5   " High volatile C bituminous coal"). Further, it does not mean that the substituted coal would exhibit the same " controllability" with respect to emissions reductions as the original coal, regardless of its compatibility with the boiler. The fact that a number of Utility Units co fire different ranks of coal does not negate the overall differences in the ranks that preclude universal coal rank switching, particularly when the design coal ranks are not adjacent on the ASTM classification continuum.

Although other classification approaches have been suggested ( e. g., based on the geologic age of the coal; see OAR 2002 0056 5411), the ASTM classification system remains the one most recognized and utilized by the industry and the one which the EPA believes is most suitable for use as a basis for subcategorization. EPA further believes that, at this time, coal rank is an appropriate and justifiable basis on which to subcategorize for the purposes of this rule. We address elsewhere in this document comments related to the appropriate emission level for each subcategory.

2.2.3 Single Subcategory for Bituminous and Subbituminous Comment:

Many commenters ( OAR 2002 0056 1675,  1677,  1762,  1848,  1852,  1853,  2160,  2269,  2660,  2826,  2860,  2871,  2878,  2875,  2889,  2904,  2905,  2908,  2937,  2944,  3205,  3324,  3366,  3394,  3406,  3435,  3449,  3560) opposed subcategorization and setting different limits for bituminous and subbituminous coal ranks. Some commenters ( OAR 2002 0056 1675,  2160,  2871,  2889,  3324,  3394) stated that such subcategorization discriminates against bituminous coal and could result in increased emissions as plants switch to subbituminous coal to take advantage of the lax limit, rather than install Hg controls. Two commenters ( OAR 2002 0056 2871,  2889) stated that the final rule should address the lax requirement for subbituminous coal by requiring a stricter limit for subbituminous coal ( i. e., 80 percent). One commenter ( OAR 2002 0056 3406) stated that the rationale for subcategorization presumably is that Hg emissions from subbituminous coal are more difficult to control. The commenter believed, however, this is almost certainly a short term problem in light of the progress that has been and is being made with respect to the development of Hg controls for this coal rank and that development of these needed controls for subbituminous coal actually will be stalled if strict control standards are not promulgated. Another commenter ( OAR 2002 0056 2160) stated that when Hg specific control technologies are commercialized, there will be no differentiation in their performance for different ranks of coal, which they say, is 2 20 supported by preliminary data which indicates that there are no removal differences between bituminous and subbituminous coals using the compact hybrid particulate collector ( COHPAC) technology.

Two commenters ( OAR 2002 0056 2878,  3205) cited the paper, " Mercury Air Pollution: The Case for Rigorous MACT Standards for Subbituminous Coal," to support their contention that there is no technical justification for the separate subcategories. The commenters stated that the technology is available that can achieve 90 percent reduction at the same costs for both ranks of coal using ACI and an ESP and COHPAC baghouse for particulate collection and nearly all the western plants are already equipped with either an ESP or baghouse. According to the commenters, subcategorizing these two ranks of coal also may result in plants switching or locking into using the dirtier western subbituminous coal because of the more lenient limits. The commenters also stated that separate limits would be difficult to implement and enforce because many plants burn both ranks of coal, some coals cannot be classified as either rank under the ASTM standard, and the amounts vary from month to month and year to year. One commenter ( OAR 2002 0056 3205) stated that the proposed Roundup power plant provides a perfect example of the implementation issues that arise with EPA's proposed subcategorization. A review of 300 samples from various points across the nearby basin from which the plant's coal would come could not be classified as bituminous or subbituminous by ASTM standards.

One commenter ( OAR 2002 0056 3205) stated that EPA fails to provide an adequate rationale to justify weaker standards for units burning subbituminous coal. In opposing separate subcategories for units burning bituminous and subbituminous coal, one commenter ( OAR 2002 0056 3406) explained that companies are increasingly attempting to capture subtle changes in fuel price and viewing fuel supply as a compliance option, with the result that many companies use various blends of coal to optimize their emission performance. The commenter believed that the use of subcategories may significantly limit the flexibility to manage a facility's operational conditions and fuel choice; in the context of a competitive market for supplying electric generation, operational flexibility and fuel choice are of paramount importance. One commenter ( OAR 2002 0056 3435) stated that the variability of the Hg and Cl content of coal within a rank, the ability of a unit to burn more than one rank of coal, and the magnitude of the difference in emission limits diminishes the merit of subcategorization by coal rank, particularly for bituminous and subbituminous units.

One commenter ( OAR 2002 0056 3449) opposed subcategorization by coal rank stating that subcategorization results in more blending of subbituminous coal at existing bituminous units. The commenter stated that coal blending is becoming more common and can result in Hg emission reductions ( 30 to 40 percent subbituminous coal with about 60 to 70 percent bituminous coal reduced Hg emissions by about 35 percent at one plant). According to the commenter, this is because subbituminous coal has less Hg and the combination of blend characteristics and existing controls for bituminous coal maintains the efficiency of Hg control for the blend. The commenter stated that this contradicts EPA's assumption that it is harder to control Hg from subbituminous coal. According to the commenter, it may be that the lack of control systems, especially for NOx, will cause lower Hg removal at some subbituminous plants. 2 21 One commenter ( OAR 2002 0056 2860) favored a single category for bituminous and subbituminous coal stating that a fuel neutral standard would facilitate compliance by simplifying recordkeeping and reporting for the type of fuel burned. The commenter also stated that it was not clear in the ICR database how EPA determined which sources are considered in each subcategory because a number of sources identified one fuel as primary yet tested another fuel.

Two commenters ( OAR 2002 0056 1848,  1853) opposed subcategorization for subbituminous coal as unnecessary and potentially illegal, stating that the decision is at odds with the FACA workgroup as evidenced in October 30, 2002, memorandum.

Some commenters ( OAR 2002 0056 2826,  3560) stated that because of the CAA and rules relevant to SO2, several Midwest utilities switched to low sulfur western subbituminous coal, thereby increasing the amount of Hg that was emitted. Yet, under the proposed Hg rules, power plants burning low sulfur western coal will be subject to less strict Hg emissions limits than plants that burn bituminous and coal refuse. Those power plants that switched to lower sulfur coal will benefit from the less stringent Hg standard, even though these plants are emitting more Hg. The commenter stated that they should not be penalized for making the choice to continue to burn coal refuse and bituminous coal, rather than switching to low sulfur western coal, especially when it has in place on both units all the technology considered sufficient for compliance.

According to one commenter ( OAR 2002 0056 2905), Wisconsin recently completed a Hg rule that is reasonable, achievable, and cost effective and urges EPA to promulgate a more stringent rule, particularly for subbituminous coal. According to the commenter, Wisconsin, where many utilities rely heavily on western subbituminous coal, requires a 40 percent reduction by 2010, 75 percent by 2015, and 80 percent by 2018.

One commenter ( OAR 2002 0056 3435) recommended a single subcategory for existing units burning bituminous and subbituminous coal with separate subcategories for lignite, coal refuse fired, and IGCC units. The commenter stated that according to EPA, an estimated 23 percent of the coal fired utilities burn two or more ranks of coal in the same boiler. Because the proposed rule does not prohibit a utility from fuel switching, the commenter stated that a unit could switch to a lower rank coal and increase emissions by as much as 190 percent. The commenter argued that combining bituminous and subbituminous units in one category would preserve flexibility for fuel blending and switching without affecting the applicable emission standard. Although fuel switching is not an option due to design limitations, the commenter stated that there are plants that are capable of burning both ranks of coal. According to the commenter, if other coal ranks such as lignite are given a separate limit, the use of lower rank coal should be subject to approval, considering either the operation of the facility or other environmental impacts, such as NOx or SO2 reductions. Another commenter ( OAR 2002 0056 3406) recommended a single standard for existing pulverized coal units burning bituminous and subbituminous coal.

Response:

As noted above, EPA believes that subcategorization by coal rank, including for 2 22 bituminous and subbituminous ranks, is appropriate in this case. The ability of some units to burn more than one rank of coal does not override the overall appropriateness of the approach. We will address later in this document the respective emission limits for the various coal ranks. Further, we believe that the regulatory approach being taken ( e. g., cap and trade) will address the monitoring and recordkeeping concerns raised.

Comment:

One commenter ( OAR 2002 0056 1852) sought clarification on how EPA will calculate a Hg emission standard, based upon the proposed subcategories, for coals that have undergone pre combustion. According to the commenter, pre combustion technology alters a fuel's chemical and physical properties so that the end resulting fuel does not resemble the initial feedstock.

Response:

Under the approach being taken for the final rule ( i. e., cap and trade), units will be assigned Hg allocations. Compliance with the allocated Hg emissions " cap" may then be accomplished by any means the owner/ operator chooses.

Comment:

One commenter ( OAR 2002 0056 2269) recommended combining subbituminous coal and western bituminous coal into a single subcategory because:

( 1) The similar low sulfur, low Hg, low Cl, and high calcium content of western bituminous and subbituminous coal is consistent with similar Hg flue gas speciation ( and consequently, similar emission control performance);

( 2) Combining them into a single class simplifies equitable development and enforcement of rules; and ( 3) The amount of Hg in western bituminous coal is only 5 percent of the total Hg in coal burned in the U. S., so this change would have a negligible effect on emission reductions.

They recommended that the same limits as proposed for subbituminous coal also apply to western bituminous coals at new and existing plants. The commenter believed that the proximity of subbituminous and bituminous coals in the west will cause market impacts and complicated oversight if limits are specified by rank. The commenter stated, for example, both kinds of coal may be produced from a single mine or a single county or region. And, where the ASTM rank parameter is near the subbituminous/ bituminous threshold, the commenter stated that regulators will need to consider complicated scientific factors as well as the impact of the sampling method on moisture content to know which rank is which. The commenter also recommended that State Hg budgets should be revised to reflect coal origin, where the algorithm used for plants burning subbituminous coal is also used for plants burning western bituminous coal and adjusted in 2 23 proportion to their fractional share of western bituminous coal as needed.

Response:

As noted above, although EPA recognizes that the ASTM classification system may not be perfect and, in fact, has occurrences of overlap, it remains the most widely accepted system and, therefore, is appropriate for use in subcategorizing for the purpose of this rule.

2.2.4 Lignite Comment:

To recognize the differences in lignite coals, several commenters ( OAR 2002 0056 1803,  2054,  2422,  2844,  2867,  2915,  3327,  3440,  3463,  3469,  3510,  3543,  4191,  4891) stated their support for creation of a subcategory for units burning Gulf Coast lignite separate from units burning Fort Union lignite. One commenter ( OAR 2002 0056 3543) supported a separate subcategory for Gulf Coast lignite because the current rule structure could force generators to switch coal ranks, primarily from lignite and subbituminous to bituminous coal. According to the commenter, Gulf Coast lignite is substantially different from other lignite coals and, because it is an important fuel source, should remain viable. The commenter stated that under a cap and trade approach, the subcategorization should be used to determine allocations for State Hg budgets. According to some commenters ( OAR 2002 0056 2054,  2422,  3510,  4191), the higher Hg content of Gulf Coast lignite and higher Hg emissions from units burning Gulf Coast lignite versus Fort Union lignite for similarly controlled boilers justifies separate subcategories and higher emission limits for units burning Gulf Coast lignite. Several commenters ( OAR 2002 0056 2915,  3463,  3478,  4191) stated that inaccurate analytical methods ( method ASTM D 3684 for coals with high ash and moisture content) used during EPA's Hg ICR coal sampling gave erroneously low Hg content readings for Gulf Coast lignite in comparison to more accurate analytical methods. Using a new analyzer and ASTM D 6414 method, the commenter stated that Hg in fuel averaged a six fold increase over the other method. A commenter ( 3478) stated that they believe that all high ash coals may have a higher Hg content in the coal than the ICR data reveals and if this is the case, and the stack emissions are also higher, then EPA has proposed a much more stringent standard than a 70 percent reduction. The commenter further discusses the problems with the test methods used to analyze for Hg and Cl in these samples and stated that the allowance allocations must be based on a baseline adjustment factor of at least 3 for lignite plants to meet the targets.

Several commenters ( OAR 2002 0056 2915,  3463,  4191) stated that if EPA does not establish a separate subcategory for Gulf Coast lignite with a higher emission standard, they should offer an alternative percent reduction option.

Response:

EPA continues to believe that there is insufficient evidence available to justify separate subcategories for Gulf Coast and Fort Union lignites. The reanalysis of the data in support of 2 24 the revised new source NSPS Hg emission limits, discussed later in this document, incorporated data from units firing both types of lignite, further lessening the necessity of additional subcategorization. EPA will continue to evaluate the Hg emission data that becomes available, including that generated through the studies on emerging Hg control technologies by the U. S. Department of Energy ( DOE), and reassess the issue of further subcategorizing lignites during the normal NSPS review cycle.

Comment:

Although one commenter ( OAR 2002 0056 3406) supported the separate treatment of lignite through the subcategorization process, the commenter adds that a great deal of research and development is focused on controlling Hg emissions from lignite coal, and strict control standards will certainly further fuel these development efforts.

Response:

EPA concurs with this comment and believes that the regulatory approach being taken will further serve to advance the development of improved Hg control technologies.

2.2.5 Integrated Gasification Combined Cycle ( IGCC)

Comment:

One commenter ( OAR 2002 0056 2948) opposed including IGCC units in this rulemaking because those units differ fundamentally from electric steam generating units.

Response:

EPA agrees that IGCC units differ fundamentally from other types of coal fired electric utility steam generating units in their mode of combustion and operation. However, they remain " fossil fired electric utility steam generating units" under the subpart Da definitions of " fossil fuel" and " electric utility steam generating unit" ( see 40 CFR 60.41a) currently included in subpart Da and, therefore, are included within this rule.

2.2.6 Coal Refuse Comment:

According to one commenter ( OAR 2002 0056 2160), waste coals are insignificant in the overall fuel mix; there is no value in regulating them separately, which creates unnecessary complexity.

One commenter ( OAR 2002 0056 2162) stated that waste coal fired plants should not be subject to the proposed Hg rules. 2 25 Response:

Although insignificant in the overall mix of fuels used in Utility Units, coal refuse fired units are typically utilized in fluidized bed combustors ( FBC), a type of boiler not in general use for other coal ranks. For this reason, coupled with the fact that their emission characteristics are dissimilar from other coal ranks, EPA is considering coal refuse as a separate subcategory for purposes of this rule.

Comment:

According to one commenter ( OAR 2002 0056 2920), EPA must regulate plants burning waste coal refuse, including culm, gob, and subbituminous coal refuse, as incineration units under CAA section 129. According to the commenter, it is not relevant whether a unit recovers energy from the combustion of waste ( coal refuse burning plants do not fall into the exception for specific energy recovery units under section 129( g)( 1)). The commenter stated that EPA's failure to regulate coal refuse burning power plants as incinerators under section 129 contravenes the CAA.

Response:

Coal refuse is a recognized subcategory under subpart Da ( see 40 CFR 60.41b); this revision of the rule merely continues to consider " coal refuse" as a subcategory of " fossil fuelfired electric utility steam generating units."

Comment:

One commenter ( OAR 2002 0056 2842) noted that EPA proposed to include all waste coal units in a single subcategory, regardless of the rank of waste coal burned and stated that EPA must establish separate waste coal subcategories based on coal rank or otherwise adjust the waste coal emission limits to reflect the control and other issues that would be expected to be associated with subbituminous or lignite waste coals. The commenter also stated that EPA must modify the limits to account for the possibility that the units used to develop the limits might burn any rank of waste coal from any source, which, depending upon the Hg content and control issues of the Hg in the coal, would require adjustments to the limits. According to the commenter, waste coal units have the same issues EPA identified for conventional units regarding coal rank. The commenter also stated that EPA has based the limits on data from only two units, both of which fired waste bituminous coals, and ignored the fact that waste subbituminous and lignite coals can be expected to have the same issues concerning emissions controllability as the coal ranks from which the waste coal is derived. The commenter also stated that EPA must take the same considerations into account to the extent that it considers a rule under CAA section 111.

Response:

As the commenter noted, EPA used the only coal refuse data available in establishing the proposed NSPS emission limits. No additional coal refuse emission data were provided during 2 26 the public comment period; therefore, EPA has no additional data upon which to base any further subcategorization of the " coal refuse" subcategory. As discussed later in this document, EPA is, however, reassessing the approach taken to develop the new source NSPS limits.

Comment:

One commenter ( OAR 2002 0056 3525) stated that waste fuel combustion is a variable process, because the waste varies from mine site to mine site. According to the commenter, existing CFB plants are among the newest of the boiler fleet in this country, most having been built to meet best available control technology ( BACT) requirements within the last 15 years. According to the commenter, all of the units with which he is aware have current Hg removal rates of 96 to 99 percent. The commenter stated that using more restrictive input limits on these units appears to be punishing facilities that made early investment in technology. The commenter stated that the variability of Hg content in the fuel is greater than that of regular coal and that carbon injection and other Hg removal methods currently under study are not directly adaptable to CFB design operations. The commenter stated that if variability of fuel quality justifies the proposed limit for bituminous coal, then at least a similar limit seems reasonable for a unit combusting waste products from bituminous coal mining processes. The commenter asserted that assignment of less than 20 percent of that value to units that currently meet BACT is overly restrictive and discriminatory, as well as arbitrary and capricious. The commenter submits that similarly, emission limits for firing of other rank coal wastes should be at least the level of limits applied to those other respective coal ranks.

Response:

EPA disagrees that the limits proposed for coal refuse fired units is arbitrary and capricious given that the limits are based on data from such units and were not extrapolated from non coal refuse fired units. As discussed later in this document, EPA is, however, reassessing the approach taken to develop the new source NSPS limits.

Comment:

According to one commenter ( OAR 2002 0056 2162), EPA may only regulate waste coal fired sources as part of the broader category of electric utility steam generating units, rather than as a distinct subcategory subject to a unique emission limitation. The commenter pointed out that EPA has developed a unique, and unduly stringent, Hg emission control level applicable only to waste coal fired units without making a finding that emissions from waste coal fired sources would pose a hazard to public health, or that the regulation of such units is " appropriate and necessary." According to the commenter, EPA's finding that it is " appropriate and necessary" to regulate Hg emissions for electric utility steam generating units applied generally to all coal fired sources in that source category and that it is inconsistent, therefore, for EPA to distinguish waste coal fired sources under the proposed rule as a separate and distinct source category subject to unduly stringent emission limitations. The commenter stated that any determination to regulate Hg emissions from waste coal plants   as sources that are " reasonably anticipated to cause adverse health effects"   only can be justified under EPA's statutory mandate, if at all, if waste coal sources 2 27 are members of the broader source category of electric utility steam generating units. Accordingly, in order for the Agency to appropriately regulate waste coal plants, it must not distinguish between waste coal plants and other coal fired electric utility steam generating units in establishing proposed emission limits. For these reasons, if the Agency regulates waste coal fired sources under the Proposed Mercury Rules, the commenter argued that the Hg emission levels applied to waste coal fired sources must be consistent with those applied to conventional coal fired sources, such as sources firing bituminous coal.

Response:

As noted earlier, EPA believes that it has the statutory authority to subcategorize " fossil fuel fired electric utility steam generating units" for purposes of regulation under CAA section 111. Further, based on the subcategorization, EPA proposed a unique Hg emissions limit for each of the subcategories and does not believe that any are " unduly stringent" as the commenter asserts, given that each was based on the data available. As discussed later in this document, EPA is, however, reassessing the approach taken to develop the new source NSPS limits.

2.2.7 Fluidized Bed Combustors Comment:

Several commenters ( OAR 2002 0056 2375,  2911,  2918,  2948,  3537) supported a subcategory for FBC units. Three commenters ( OAR 2002 0056 2375,  2918,  3537) stated that EPA should create a subcategory for FBC units to subsume the proposed subcategory for units that combust waste coal because FBC units use a fundamentally distinct process for fuel combustion that implicates differences in design, construction, and equipment. According to the commenters, such differences are sufficient to establish that FBC units constitute a different " class" or " type" of utility steam generating unit. Both commenters stated that subcategorization is further warranted because the FBC unit process and design differences have significant implications for Hg removal efficiency. One commenter ( OAR 2002 0056 2918) provided a list of the main differences between FBC units and conventional boilers and stated that these differences are important for the higher Hg removal efficiencies of FBC units and such differences should make FBC units a distinct subcategory. The commenter offered examples of when EPA has created subcategories among sources due to the performance of control technology ( i. e., steel pickling and phosphoric acid manufacturing MACT).

Two commenters ( OAR 2002 0056 3445,  3556) supported EPA's proposed subcategories based on coal rank but feel additional subcategorization, specifically a separate category for FBC units, is appropriate because FBC units use a fundamentally different combustion process than pulverized coal units, making them a different type of source.

Response:

EPA agrees that FBC units operate and are designed differently than conventional 2 28 pulverized coal ( PC) boilers. However, with the exception of FBC units firing coal refuse, there was no clear indication from the available data that such units impacted on the ultimate Hg control effected. That is, in some cases, FBC units had higher removal rates than most with respect to their Hg emissions; in other cases, FBC units had lower removal rates than most. Therefore, EPA concluded that it was the coal rank, rather than the process type ( e. g., FBC, PC) that should govern in any determination relating to subcategorization.

2.2.8 Fuel Switching and Impacts on U. S. Coal Supply Comment:

Many comments were received regarding fuel switching and the impacts of the proposed rule on fuel switching. Several commenters ( OAR 2002 0056 1969,  2067,  2260,  2834,  2897,  3198) agreed with EPA that fuel switching is not practicable to meet the proposed Hg emission limits. One commenter ( OAR 2002 0056 2260) stated that furthermore, there exists no one fuel in sufficient quantities and availability that can be used by all utilities. The commenter's boilers were designed to burn western subbituminous/ bituminous coals and cannot switch to burn eastern bituminous coals. Eastern coals also have higher levels of sulfur and would overload their scrubber control units. The commenter's remote location in southeastern Arizona also makes it impossible to transport coals from regions other than the west. Additionally, the commenter's units are limited in the amount of natural gas that can be burned because of severe constraints on the natural gas supply in the region.

One commenter ( OAR 2002 0056 1969) stated that EPA has appropriately concluded that fuel switching is not a compliance option which is consistent with the CAA and favors the development of consistent standards that do not create regional inequities or favor one fuel type over another.

One commenter ( OAR 2002 0056 2945) stated that any fuel switching or shift in coal utilization away from bituminous coal due to the proposed rules would have a drastic adverse impact on mining employment and on electric power generation.

One commenter ( OAR 2002 0056 2891) stated that cooperatives believe that fuel switching is not a reasonable or practical alternative for many units to meet the new emission limits and that in many cases, plants may have no option but to shut down.

Response:

Modeling done in support of EPA's proposed rules does not indicate that a significant amount of fuel switching will be undertaken by the utility sector to comply with the proposed rules. Some companies may chose to change fuels to effect compliance with either the CAIR or CAMR, or both. Further, EPA believes that some sources have extremely limited options ( in some cases, no options) with regard to other coals or fuels that could be fired at a given Utility Unit. Therefore, EPA proposed emission limits that would be achievable for such units that would not require fuel switching. 2 29 Comment:

Some commenters were concerned over the impacts of the rule on bituminous coal. One commenter ( OAR 2002 0056 3445) stated that in addition to coal fired power plants which burn bituminous coal, they also own and operate bituminous coal mining and terminal operations. The commenter stated that any Hg regulation must treat all coals fairly. The commenter added that providing an advantage to coal from one region over coal from other regions encourages fuel switching as a compliance strategy and could limit the diversity of fuels available for electrical generation. The commenter stated that it is critical to the nation's security that all forms of coal continue to be available for electrical generation.

One commenter ( OAR 2002 0056 2845) stated that any rule must not favor one rank of coal over another and that, although fuel switching appears to be an acceptable control option, it will severely reduce employment in the bituminous coal sector.

One commenter ( OAR 2002 0056 2692) stated that the proposed rules threaten the future of the Appalachian coal industry. The commenter stated that industry and elected representatives from western States have for some time pushed EPA for a rule that would advantage western coal. According to the commenter, EPA responded to these concerns by publishing rules on January 30, 2004, that provide a major disadvantage to eastern coal. The commenter stated that specifically, the rules as proposed require sharp cuts in Hg emissions from eastern bituminous coals, but require far smaller cuts from the subbituminous and lignite coals of the west. According to the commenter, this difference in treatment is so great that it will certainly produce an illogical result: utilities will be encouraged to burn more western coal, despite the fact that it has higher levels of Hg. The commenter stated that the result will be more pollution and less eastern coal jobs.

One commenter ( OAR 2002 0056 3469) stated that the Hg rule and the CAIR will further concentrate U. S. coal supply among Wyoming Southern PRB subbituminous coal producers and delay emission control technology retrofits and further erode production from the Illinois Basin as well as niche coal and lignite production regions, including certain Indian reservations.

One commenter ( OAR 2002 0056 2661) stated that EPA's generalities of Hg emissions in coal, as a one size fits all, implies a greater burden for subbituminous coal users. The commenter noted that substantial reductions in SO2 and NOx were achieved by the conversion to low sulfur coal  subbituminous coals. The commenter stated that units that have borne the economic burden for fuel switching should not bear a disproportionate burden of Hg emission reduction strategy now. Further, the commenter did not believe it is in the best interest of the U. S. energy policy to favor limited coal choices based on any emission threshold currently established by EPA. According to the commenter, EPA's policy would continue to hamper U. S. energy needs and reliance on foreign and other inappropriate sources of fuel for U. S. consumer energy needs.

One commenter ( OAR 2002 0056 3531) expressed concern with the discriminating impact the proposed rule will have on Ohio and other eastern bituminous coals. The commenter stated the current rule proposals may allow sources burning western coal to continue to do so 2 30 without installing any control technologies. The commenter stated that essentially, the cost of all Hg reductions under the current proposal would be borne entirely by sources burning eastern coals, such as in Ohio. According to the commenter, there is no valid technical or economic justification for such discrimination. The commenter stated that Hg reductions must be based on an examination of the best controlled sources in each fuel subcategory and a valid determination of the level of control that can be achieved within each subcategory. The commenter concluded that EPA must revise the rules to not favor regional fuel usage and, instead, require reductions for all sources based on available technical data. One commenter ( OAR 2002 0056 2870) encouraged EPA to adopt approaches to control Hg emissions from power plants that will ensure a level playing field among all coal ranks and will promote an equitable strategy to address interstate pollutant transport. The commenter claimed the rule creates an uneven playing field that would harm the bituminous coal industry and its coal miners. One commenter ( OAR 2002 0056 2937) recognized that although difficult regulatory decisions must be made, the commenter felt that good science, coupled with a sense of fairness can produce a rule that yields Hg reduction in a way that does not compromise the viability of bituminous coal producing regions.

Response:

EPA's modeling has shown little significant coal switching as a result of the proposed CAMR and CAIR actions. We believe that this rebuts the commenter's suggestions that one or another coal rank is " advantaged" or " disadvantaged" with respect to other coal ranks. EPA's responses to comments on the allocation adjustment factors are found elsewhere in this document.

Comment:

Many commenters ( OAR 2002 0056 1625,  1673,  1768,  1802,  2020,  2066,  3478,  3513,  3517,  3530) expressed concern over the impacts of the proposed rule on the nation's energy supply. Several commenters ( OAR 2002 0056 1673,  1768,  3478) believed that the Hg levels set by this rulemaking should not result in the loss of viability of any fuel type, such as lignite, considering the severe impact this would have on local communities, jobs and the nation's energy security from the loss of this significant domestic fuel supply for electric generation.

One commenter ( OAR 2002 0056 3513) stated that the nation's largest energy supply will be unduly impacted if EPA fails to adequately consider the vital role that coal based electricity plays in America's current and future economic prosperity; the demand for electricity is growing and other fuels   such as natural gas   cannot meet this growing demand.

One commenter ( OAR 2002 0056 3517) stated that coal represents our single largest domestic reserve of fossil fuel, representing 95 percent of the reserves ( as compared to crude oil at 2 percent and natural gas at 3 percent). The commenter asserted that coal is electricity, accounting for 87 percent of the use of coal in the nation, and is responsible for 50 percent of total electricity generated in the U. S. The commenter believed it is incumbent upon EPA to promulgate responsible and achievable standards so as to not impact the reliability and cost of 2 31 electric service.

Several commenters ( OAR 2002 0056 1768,  3530) stated that the final rule must be consistent with the need for reliable and affordable electric power, including affordable use of all coal ranks and options for efficient on site power generation such as CHP. The commenter stated that the final rule must facilitate   not discourage   the availability of an adequate and diverse fuel supply for the future, including coal, natural gas, nuclear energy, hydroelectric, and renewable sources. According to several commenters ( OAR 2002 0056 1768,  2066), the final rule must not aggravate the already precarious natural gas supply which is currently inadequate. One commenter ( OAR 2002 0056 2066) stated that these actions will inhibit, if not totally eliminate, plans for any new coal fired base load electric generation, and this forgone option will undoubtedly be replaced by additional natural gas fired generation.

Should EPA proceed with the rulemaking, one commenter ( OAR 2002 0056 2847) urged the agency to adopt sufficient subcategories of expected reductions so as to limit the potential for economic disruption in the coal, transportation, and utility industry sectors.

Although supporting full use of categories and subcategories to adequately address differences in abilities to reduce Hg based on such things as coal chemistry that varies with coal rank, one commenter ( OAR 2002 0056 3200) stated that it is imperative that no fuel type be afforded an unfair market advantage and that overly aggressive mandatory reductions in Hg emissions be avoided that would lead to loss of fuel diversity, higher energy prices and a strain on electric reliability, all of which are inconsistent with sound energy policies.

Several commenters ( OAR 2002 0056 1675,  2160,  2660,  2875,  2904,  2908,  2937,  3324,  3366,  3560) stated that limits that favor one coal over another may have considerable economic impacts due to the higher control costs affecting coal producers, utilities, and customers. According to two commenters ( OAR 2002 0056 2875,  2937), a significant loss of employment would occur in the Appalachian areas of their State and would be devastating to an area already suffering from excessively high unemployment rates.

Several commenters ( OAR 2002 0056 1675,  1677,  1762,  2944) stated that subbituminous coal, which is primarily produced in the West, will receive favorable treatment at the expense of eastern bituminous coal that will make bituminous coal virtually non competitive with western subbituminous coal. One commenter ( OAR 2002 0056 2944) stated that subcategorization will result in regional disparities and inconsistences in the industry which EPA stated that it intended to avoid.

One commenter ( OAR 2002 0056 1852) opposed EPA's proposal to subcategorize stating that the widely varying proposed emission rates for coal subcategories could cause disruption to coal supplies and fuel blends in order for utilities to comply with the Hg standard.

Response:

As noted above, EPA's modeling has shown little significant coal switching as a result of 2 32 the proposed CAMR and CAIR actions. We believe that this rebuts the commenter's suggestions that one or another coal rank is " advantaged" or " disadvantaged" with respect to other coal ranks. Further, we do not believe that the final rules will have a negative impact on the nation's energy security, employment rates, or energy reliability. Responses to comments on the allocation adjustment factors are found elsewhere in this document.

Comment:

One commenter ( OAR 2002 0056 3198) stated that these regulations will have a tremendous impact on the mining industry in Wyoming and on the state as a whole and it is critical that EPA adequately address the unique chemistry of Wyoming coal.

Response:

EPA believes that it has adequately addressed the commenter's concerns in the rule through the finalizing of two emission limits for subbituminous coals, depending on the type of FGD unit used and the allocation factors used in the trading program.

Comment:

According to one commenter ( OAR 2002 0056 3254), Illinois Hg emissions have risen about 28 percent while burning western coal. The commenter stated that Illinois coal Hg content is 1/ 3 that of western coal and that EPA should not allow western coal to be burned.

Response:

EPA does not feel that it is in the best interest of the country to prohibit the use of some ranks of coal when those coals can be adequately controlled to limit Hg emissions.

Comment:

One commenter ( OAR 2002 0056 3525) encouraged EPA to reduce Hg emissions without undermining fuel diversity. The commenter believed that flexibility will more likely be achieved through EPA's market based, cap and trade, approach to controlling Hg emissions than through the MACT approach. The commenter stated that the tight time frame for reductions in the Hg MACT approach could leave utilities with no real choice but to install a significant quantity of additional gas fired generation facilities and thereby switch fuels as a primary means of compliance. The commenter stated that market based mechanisms, like the successful cap and trade program under the acid rain program, will dramatically increase the cost effectiveness of any program. The commenter supported an approach of imposing Hg emissions reductions to a level commensurate with co benefits achieved through the SO2 and NOx emissions reductions of the proposed CAIR. The commenter stated this will help mitigate the costs of compliance, which will be borne by all electricity consumers. According to the commenter, when establishing emission limits, the inherent fuel quality differences and the varying capability of emission control devices to capture Hg between coal ranks needs to be considered 2 33 and properly accommodated. The commenter urged EPA to establish a rule that does not preferentially disadvantage a particular fuel or fuel type so that fuel diversity of the electrical generation sector is not artificially restricted.

Response:

EPA concurs with the commenter's belief that a cap and trade approach will better serve to protect the environment while at the same time allowing the industry to maintain fuel diversity.

2.2.9 Other Subcategorization Approaches Comment:

One commenter ( OAR 2002 0056 2422) suggested the following subcategorization approach: hot stack, wet stack, and saturated stack configurations. According to the commenter, this approach recognizes that many hot stack eastern units fired with bituminous coals are not cost effective candidates for capital intensive control technology retrofits. The commenter believed that EPA should provide emission based exemptions for relatively small Hg emitting units to mitigate the substantial risks of plant closures among older and smaller units.

One commenter ( OAR 2002 0056 2634) stated in addition to subcategorization by coal rank, further subcategorization could be warranted, based on pollution control process configuration and coal chemistry, due to its impact on Hg speciation and its ability to be controlled by present technology.

Response:

EPA believes that cost effective emission reduction approaches are available for " hot stack" units, particularly when the CAMR is taken in concert with the CAIR. EPA analyzed the commenter's suggested subcategorization approach but believes subcategorization based on coal rank is more easily implemented and more adequately addresses the coal chemistry issue.

Comment:

One commenter ( OAR 2002 0056 2267) believed that EPA should create a subcategory for small municipal generators under the MACT approach.

Response:

EPA sees no justification for creating such a subcategory. Such units are constructed and operated in a manner similar to other " electric utility steam generating units" and, as such, are sources of Hg emissions. Coal fired municipal units otherwise meeting the definition would be subject to the final rule. 2 34 2.2.10 New Units Comment:

Several commenters ( OAR 2002 0056 1969,  2067,  2634,  2721,  2843,  3403,  3514,  3537) supported the proposal to use the same coal subcategories for new plants as for existing plants. However, one commenter ( OAR 2002 0056 2067) stated that the EPA ICR reference data should be supplemented with more recent and representative power plants and coal sources. The commenter stated that Hg removal data used to set the standards for the best performing utility units must be accurate and represent the variations of coal within each coal rank. The commenter stated that standards for new power plants should be adopted to encourage the construction of cleaner coal plants and maintain a diverse mix of fuel.

One commenter ( OAR 2002 0056 1969) stated that the historical fuel mix is indicative of regional and economic conditions and fuel needs and according to the commenter, selection of other subcategorization methodologies for new units could affect their future market conditions and an ongoing need for a diversified electrical generation fuel mix.

One commenter ( OAR 2002 0056 2721) believed that without subcategorization, the location of new units will be biased geographically near the fuel types that provide for the ease of compliance. According to the commenter, this unfair siting advantage will place strenuous hardships on the electrical supply chain of the country and place economic hardship in areas of the western U. S. where typically the low Cl content of coal resides.

One commenter ( OAR 2002 0056 3435) recommended a single subcategory for new units burning bituminous and subbituminous coal. The commenter stated that the difference in the limits for new bituminous and subbituminous coal would allow a 233 percent increase in emissions.

Response:

EPA continues to believe that new sources should be subcategorized in the same manner as existing units.

Comment:

One commenter ( OAR 2002 0056 3459) stated that, although EPA has only spurious rationale for subcategorization of existing units, there is no rationale for new units. The commenter stated that these can be designed to provide optimum performance when firing all coal ranks and that EPA must reject subcategorization and establish a single limit for new units. According to the commenter, the effect of EPA's proposal is to make the standards less stringent by subcategorizing according to the rank of coal. The commenter stated that the words of a statute must be read in their context and with a view to their place in the overall statutory scheme and that Congressional intent was to use subcategorization sparingly; the same reasons the NOx NSPS was fuel neutral ( improvements in control technologies were available on all utility boilers) 2 35 applies here.

Response:

EPA believes that the proposed requirement for new units to comply with an output based emission limit will ensure that they are designed to achieve optimum performance. However, units designed to burn bituminous coals will still not be able to burn lignite coals ( for example) and, thus, the need for subcategorization remains. As noted earlier, EPA concurs that advancements in Hg control technologies may lead to more " fuel neutral" formats; however, that time has not come.

Comment:

One commenter ( OAR 2002 0056 3537) contends that IGCC units use fundamentally different processes than conventional boilers and should be placed in their own new unit subcategory.

Response:

EPA concurs that new IGCC units should continue to be subcategorized separately from other coal fired units.

Comment:

One commenter ( OAR 2002 0056 2862) stated that in establishing a new source NSPS for Hg, EPA should also subcategorize coal fired power plants based on the process type. The commenter believed that it is vital that EPA further consider the performance of representative boiler types and variations in Hg content.

Response:

EPA does not believe that there is any additional justification for subcategorizing new units by process type than there is for existing units.

2.2.11 Coal Blends Comment:

Two commenters ( OAR 2002 0056 2535,  3435) favored a subcategory for units burning a blend of subbituminous and bituminous coals. One commenter ( OAR 2002 0056 2535) believed that blends of subbituminous and bituminous coals should not be categorized under subbituminous coal. The commenter stated that EPA incorrectly set the limit for subbituminous coal by mis classifying blended fuel units as subbituminous units, resulting in a erroneously higher number of plants classified as subbituminous plants. The commenter cited certain plants named by EPA as being subbituminous plants ( e. g., Craig, La Cygne, Lawrence, Newton, and Presque Isle) 2 36 as potentially burning blends of subbituminous and bituminous coal. For each of the plants identified as burning subbituminous coal, the Energy Information Administration ( EIA) database was reviewed by the commenter to determine which mine the coal was shipped from in 1999. According to the commenter, EPA's Table 2 summary of the coal supply data as reported to the EIA for these plants, shows these plants categorized as subbituminous plants, but may instead be plants that burn a blend of bituminous and subbituminous coals. The commenter further stated that neither the EIA data nor the ICR data differentiates as to what coals were delivered to which unit within a facility, so the shipments listed above are for the plant as a whole for 1999. The commenter was unable to find any clear documentation as to what rank of coal was being burned during the EPA ICR tests. The commenter stated that unless EPA is able to accurately determine what coals were burned during the test, the assumption must be made that it was a subbituminous/ bituminous blend and the plant must be placed in the " blend" category. The commenter further stated as unsound the suggestion that any plant that burned over 90 percent subbituminous coal should still be classified as a subbituminous unit and that the remaining blend be considered a deminimus amount. The commenter stated that there needs to be a better evaluation of blended coals, and how these different ranks of coals interact relative to the species of Hg that is emitted.

Response:

As noted above, EPA does not believe that a subcategory based on blended use of bituminous and subbituminous coals is warranted. EPA relied on the facilities to provide accurate information regarding the rank of fuel burned and, in some cases, errors were corrected. It is true that some units noted by the commenter received shipments of multiple ranks of coal during the reporting period, they reported burning only one rank of coal during their emission test program and, therefore, have been classified as being in that subcategory. However, as noted later in this document, EPA has reevaluated the basis for the new source NSPS limits for the final rule.

Comment:

Commenter OAR 2002 0056 3459 states that EPA's proposed case by case alternative for units burning a blend of coals is unlawful. EPA must establish emission standards for each subcategory of sources that emit HAP and those standards are to be based on the best performing units within the subcategory. However, EPA does not propose a uniform standard for units burning a blend of coals and does not base the standard, such as it is, on the best performing units. Even though EPA effectively creates a subcategory for units burning a blend of coals, it makes no effort to establish standards for that subcategory.

Response:

The approach being taken for blended coals is consistent with the procedures already inplace in 40 CFR 60, subpart Da.

2.2.12 Other 2 37 Comment:

One commenter ( OAR 2002 0056 2897) agreed with EPA's decision to subcategorize by coal rank and to differentiate between bituminous and subbituminous coals. The commenter also stated that the ICR data used to support the claim that PRB coal is compliant must be questioned. The commenter agreed with EPA's determination that the overlap in coal classification properties does not compromise its ability to subcategorize by coal rank and overlap only occurs in a very limited number of cases and it remains true that coal rank is a significant factor that distinguishes the design and operational characteristics of different boilers.

Response:

EPA has reanalyzed the data used to support the Hg emission limit for subbituminous coals. Discussion of this reanalysis is contained elsewhere in this document.

Comment:

Not all commenters ( OAR 2002 0056 2661,  2692,  2870,  2937,  2944,  3208,  3469,  3531,  4139) agreed with EPA's use of subcategories. One commenter ( OAR 2002 0056 2944) stated that the combustion processes involved in IGCC systems, FBC, and PC boilers are themselves fundamentally different in their mechanical operation and the resulting processes offer distinctly different possibilities for limiting Hg emissions. The commenter added that in actual practice each of these combustion types produces significantly different relative Hg emissions. According to the commenter, because the differences between these classes of coal combustors is a matter of kind, rather than one of degree, it is logical to determine separate emission limits for them. The commenter believed that because the combustion process, opportunities for limiting emissions, and typical emission results of cyclone boilers and stoker boilers are very similar to those of PC boilers, it makes regulatory sense to combine them into the class of pulverized boilers.

Response:

As noted above, EPA concurs that IGCC units should be subcategorized separately but disagrees with the commenters with regard to FBC units.

Comment:

One commenter ( OAR 2002 0056 4139) suggested that the logic used in establishing the subcategories needs to be reassessed.

Response:

EPA has reviewed its analysis leading to the proposed subcategories and continues to believe that the subcategories proposed continue to be appropriate. 2 38 Comment:

In addition to demonstrating the efficacy of ACI, one commenter ( OAR 2002 0056 3208) and other participants in research funded in part by the U. S. Department of Energy's National Energy Technology Laboratory stated that they are exploring the potential use of oxidizing agents, enhanced sorbents, and coal blending as potential pathways to achieving significant reductions in Hg emissions from use of PRB coals. On this basis, the commenter urges EPA to adopt a separate subcategory for PRB coals within a subbituminous coal category.

One commenter ( OAR 2002 0056 4139) agreed that the importance of coal ranks may diminish and that EPA should review its limits by coal rank periodically and make them more stringent if appropriate due to improving Hg control technology.

Response:

EPA stands by its decision with regard to subcategorization. Further, EPA believes that the research noted by commenter  3208 supports more limited, rather than broader, subcategorization scenarios ( i. e., fewer, perhaps none, rather than more subcategories) when the rule is reviewed in the future as suggested by commenter  4139.

Comment:

According to some commenters ( OAR 2002 0056 2364,  2430), EPA's straw proposals of August 2001 and December 2001 contained subcategorization possibilities calling for 90 percent control, have defensible MACT floors, are cost effective, have timely implementation, and are preferable to EPA's proposals.

Response:

The " straw proposals" noted by the commenters were extremely preliminary in nature and were never the basis for any proposal options. The data upon which the straw proposals were based were subsequently determined to be in error with regard to levels of Hg control achieved by existing controls. Further analysis of the available data also indicated that the subcategories used at proposal were appropriate.

2.3 GENERAL COMMENTS Comment:

One commenter ( OAR 2002 0056 2485), also noted that many sources of natural gas contain high levels of Hg and should be included in this subpart.

Response:

EPA received no data or information during the public comment period to indicate that 2 39 its determination that regulation of natural gas fired Utility Units was neither necessary nor appropriate was in error. Therefore, EPA stands by that decision.