Comment 10: Commenter 17386 states that Table 2 in the preamble of the proposed rule identifies that oil-fired EGUs emit minor amounts of HAP, except for Ni. The minor benefit to be gained from regulating existing oil-fired EGUs does not warrant the substantial cost that would be incurred to meet the MACT rule, including the need to retrofit many additional controls that are not covered by the CAA or the EPA's own HAP study. Commenter, therefore, requests the EPA consider exempting existing oil-fired EGUs from the MACT rule or limiting compliance to a periodic tune-up based on the minor amounts of HAP produced by such EGUs.
Comment 11: Commenter 17920 urges the EPA to reconsider its decision to regulate oil-fired units. Based even on the EPA's very conservative risk assessment, the risks posed by Ni emissions from oil-fired generators are very low and do not justify a finding that the regulation of such units is appropriate and necessary. A more realistic analysis based on recent data from oil-fired units shows the risks to be even less than the EPA estimated. Thus, the EPA should rescind its finding that oil-fired units should be regulated.
Comment 12: Commenter 17648 supports commenter 17808's comment that oil-fired EGUs firing No. 2 oil should not be included in the rule because, under the EPA's Appropriate and Necessary Finding, those units are properly included in the natural gas category of EGUs that the EPA found inappropriate to regulate, rather than in the coal- and oil-fired units that the EPA found warranted regulation. No. 2 fuel oil is a lighter fraction of petroleum than No. 6 fuel oil. Because No. 6 fuel oil represents the less volatile materials with a higher boiling temperature "left behind" in the distillation process, No. 6 fuel oil contains many HAP precursors such as nickel and other heavy metals which are not present in No. 2 fuel oil or natural gas. Thus, the emissions characteristics of No. 2 fuel oil are most similar to those of natural gas and units burning No. 2 distillate should be treated in the same way. This would not be subcategorization but, rather, a recognition that units burning No. 2 fuel oil should be treated in the same manner as units burning natural gas.
Comment 13: Commenters 17803 and 17808 recommend that the EPA reevaluate its decision to include distillate oil-fired EGUs in the Utility MACT Rule. After reevaluating the risk assessment, if the EPA confirms that it is "appropriate and necessary" to regulate distillate oil-fired EGUs under CAA section 112, Commenters recommend that the EPA recalculate the Total HAP Metals standard for oil-fired generating units based on all existing oil-fired EGUs, not simply the sources for which the Administrator has information (i.e., with the MACT floor calculated as the average of 12 percent of 154 units, or 19 units). This is consistent with the approach that the EPA used in calculating the HCl and Total PM standards for coal-fired EGUs. Commenters recommend this approach based on the fact that the ICR dataset is clearly biased toward very low-emitting units, burning a distinctly different fuel type (distillate fuel oil). If the EPA concludes that this is not a viable option, Commenters recommend, at a minimum, that the EPA subcategorize between residual- and distillate-oil fired EGU.
Comment 14: Commenter 17870 states that the EPA should re-evaluate its decision to include distillate oil-fired EGUs in the Toxics Rule. The EPA's 1998 Report to Congress on HAP Emissions from Electric Utility Steam Generating Units focused exclusively on "residual" oil-fired EGUs. There is no discussion or analysis in the report supporting the inclusion of distillate oil-fired EGUs in the December 2000 Appropriate and Necessary Finding. In fact, the only reference to distillate oil in the 1998 Report to Congress is a statement suggesting that distillate oil is more similar to natural gas than residual oil. The EPA indicates that "natural gas and distillate oil" both contain relatively little fuel-bound nitrogen. For natural gas-fired EGUs, the EPA found that regulation of HAP emissions is not appropriate or necessary because the impacts due to the HAP emissions from such units are negligible based on the results documented in the Report to Congress. Commenter would also note that the Report to Congress is clear that its inhalation risk analysis - which the EPA uses to justify the regulation of oil-fired EGU - is specific to No. 6 residual oil. As indicated in Table 6-25 of the Report to Congress (the basic parameters used in the inhalation risk assessment for utilities), the EPA assumed an "average HAP concentration in test data of residual fuel oil No. 6." Also, among the 11 oil-fired EGUs listed as potentially posing inhalation risks above the threshold of concern, none rely on distillate fuel oil. The EPA lists only three power plants in the entire U.S. that rely on distillate fuel oil for the production of electricity. As a result, Commenter strongly recommends that the EPA reevaluate its decision to include distillate oil-fired EGUs in the final Toxics Rule.
Comment 15: Commenter 17928 requests that the EPA exempt distillate fuel oil-fired units from the proposed rule. Commenter believes the ICR data shows a statistically significant difference in emissions from residual and distillate fuel oil units and these differences justify exemption of distillate fuel oil-fired units.
Commenters 18025 and 17808 stated that EPA should reevaluate its decision to include distillate oil-fired EGUs in the Utility Toxics Rule. According to the commenters, both the updated risk assessment and the 1998 Report to Congress focus exclusively on residual oil-fired EGUs. The only reference to distillate oil in the 1998 Report to Congress is a statement suggesting that distillate oil is more similar to natural gas than residual oil. The EPA indicates that "natural gas and distillate oil" both contain relatively little fuel-bound nitrogen. For natural gas-fired EGUs, EPA found that regulation of HAP emissions is not appropriate or necessary because the impacts due to the HAP emissions from such units are negligible. Additionally, in Table 6-25 of the Report to Congress EPA assumed an "average HAP concentration in test data of residual fuel oil No. 6". With respect to the risk assessment, the commenters note that among the 11 oil-fired EGUs listed as potentially posing inhalation risks above the threshold of concern, none rely on distillate fuel oil.
Response to Comments 9 - 15: As noted and discussed in further detail elsewhere in the final record, the EPA disagrees with the commenters' assertion that the risks from oil-fired EGUs are "very low," and also disagrees with the assertion that this determination is based on a "very conservative risk assessment." The EPA listed oil-fired EGUs in December 2000 and we are not able to delist such units based on the refined risk assessments we conducted that show clearly that at least one oil-fired EGU poses a cancer risk greater than 1 in 1 million. See CAA section 112(c)(9)(B) (providing criteria that must be satisfied before the Administrator may delist a source category).
 The [EPA also disagrees with the commenters' assertion that distillate oil was included in the natural gas "category" in the December 2000 regulatory finding. In that notice (65 FR 79825), the EPA made no distinction between distillate and residual oils, referring only to "oil-fired" units. In the Report to Congress, the similarities between natural gas and distillate oil were in the discussion of NOX, not HAP. Distillate oil may be generally considered to be "cleaner" than residual oil but, based on data received through the 2010 ICR, emissions of some HAP are greater from distillate than from residual oil. Because the EPA listed all oil-fired EGUs and the Agency is not able to delist such sources, the final standards applicable to liquid oil-fired EGUs also apply to distillate oil-fired units.
As a result of comments received on this rulemaking, the EPA contacted all oil-fired EGUs that conducted testing under the 2010 ICR to confirm the type of oil that was used. Based on this effort, the MACT Floor spreadsheets have been revised to reflect the corrected oil use. The EPA does not believe that the data set is biased toward very low-emitting units as only 6 of the 55 total oil-fired units required to conduct testing were distillate oil-fired EGUs. Also, because the best performing sources in the floor are burning both residual and distillate oil we believe it is not appropriate to subcategorize such units. Based on our information, the EPA believes that oil-fired units may either install a PM control device or switch to burning distillate oil and be able to comply with the final standards.
Commenter is incorrect that the Agency should base the MACT floor standards using data from sources that represent 12 percent of the population of oil-fired units instead of 12 percent of the available data. The EPA used data from sources that represent 12 percent of the EGU population for coal-fired units for the acid gas and non-mercury metallic HAP proposed limits because, as was noted in the Supporting Statement for the 2010 ICR, the EPA identified the best performing 15 percent of sources and required them all to test. The EPA could not identify the best performing oil-fired units (EPA similarly could not identify the best performing coal-fired EGUs for mercury either). For this reason, the EPA used 12 percent of the available data to establish the limits.
4. Allow an opt‐out provision.
Comment 16: Commenters 17316 and 17386 state that it would be beneficial if the MACT rule clarified whether an EGU can opt-out of the MACT rule by de-rating below the 25 MW applicability threshold for classification as a "Electrical Utility Steam Generating Unit." It is the Commenters' understanding that MACT rules do in general allow a source to de-rate below applicability thresholds, so long as the de-rating is completed before the rule compliance deadline. Commenters request that the EPA provide explicit language clarifying whether this option is allowed.
Response to Comment 16: To be a non-cogeneration EGU, a unit must have a capacity of greater than 25 MW.
5. Exemption for EGUs that fire oil rather than natural gas during periods of natural gas curtailment.
All comments have been moved or combined with other comments.
6. Applicability determination at either the unit level or facility level.
a. Fossil fuel-fired.
Comment 17: Several commenters (17808, 17870, 18025) recommend allowing companies to determine whether they are "natural gas-fired" or "fossil fuel-fired" at either the individual unit level or across all electric utility steam generating units larger than 25 MW at a single plant location. For example, a power plant with multiple steam generating units may be combusting limited amounts of oil across the plant as a whole, but with an individual unit burning oil in excess of the EPA's proposed thresholds. This would avoid situations where a relatively small oil unit might be designated a fossil fuel-fired EGU despite the fact that the plant as a whole is largely reliant on natural gas and its plant-average emission rates are well below the level of the proposed standards. This would seem to be consistent with the EPA's proposal to allow emissions averaging across all affected units at a single plant location.
b. Oil-fired.
Comment 18: Commenter 17928 suggests that the EPA allow companies to determine whether they are "natural gas-fired" or "fossil fuel-fired," (i.e., "oil-fired") at either the individual unit level or across all natural gas/oil-fired electric utility steam generating units larger than 25 MW at a single plant location. As proposed, oil-based units have limited ability to take advantage of facility-wide averaging. A power plant with multiple units may be combusting limited amounts of oil across the plant as a whole with an individual unit burning oil in excess of the EPA's proposed thresholds. However, the net effect is that the plant is not "oil-fired."
Response to Comments 17 and 18: The EPA is not certain but it appears that commenter is suggesting that the EPA authorize the source to average natural gas-fired EGUs with oil-fired EGUs for purposes of determining whether the facility as a whole is fossil fuel-fired such that it would be subject to the final rule. Commenter appears to promote this approach in an effort to have certain oil-fired units become exempt from the final rule. We do not believe such a change is warranted or appropriate.
As explained in the proposed rulemaking, the EPA has generally imposed certain limits on the scope and nature of emissions averaging programs. These limits include: (1) No averaging between different types of pollutants; (2) no averaging between sources that are not part of the same affected source; (3) no averaging between individual sources within a single major source if the individual sources are not subject to the same NESHAP; and (4) no averaging between existing sources and new sources. Commenters' proposed approach violates two of these conditions because natural gas-fired EGUs and oil-fired EGUs are not part of the same affected source and the two types of units are not subject to the same NESHAP. In fact, natural gas-fired EGUs are not subject to any NESHAP.
To the extent that commenter is seeking an exemption, we think that the statute requires us to regulate oil-fired units even if located at primarily natural gas facilities. The comments themselves indicate that the oil-fired unit in the example is a relatively small unit and it implies that the unit is not run very frequently. Sources that have such units will have 3 years to either install controls, convert the unit to natural gas, limit the capacity factor to less than 8% to be included in the limited use subcategory, or find some way to replace the relatively small amount of electricity generated by the unit. Further, only the oil fired unit will be subject to the NESHAP and required to comply with the final standards. Natural gas-fired EGUs at the same facility will not be required to comply with the final rule.
7. Cogeneration efficiency standard.
Comment 19: Commenter 17733 states that the preamble to the proposed rule appears to make clear that any unit that does not meet the proposed rule's definition of a cogeneration unit will be considered an EGU if it qualifies as an EGU. Commenter strongly agrees that units that do not meet the efficiency standards required to be a cogeneration unit should still qualify as EGUs if they otherwise meet the definition of an EGU. Otherwise, owners of coal- and oil-fired units would be encouraged to avoid the EGU MACT requirements by reducing their units' efficiency. This result would clearly be contrary to the intent of the CAA, and also clearly violate the EPA's Trust Responsibility and its obligations under the Environmental Justice Doctrine. Accordingly, in the final rule, the EPA should make clear that any unit that does not meet the efficiency requirements of a cogeneration unit will still qualify as an EGU if the unit otherwise meets the CAA EGU definition.
Response to Comment 19: The EPA believes that the commenter has misunderstood the provisions of the rule. There are no "efficiency standards required to be a cogeneration unit."  There is only the requirement contained in CAA section 112(a)(8) that the cogeneration unit supply "more than one-third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale..."
8. The 3-year lookback should apply to cogeneration units.
Comment 20: Commenter 17733 states that the rule should use the same 3-year review to determine whether a unit qualifies as an EGU under the second sentence of the CAA's EGU definition. Accordingly, a cogeneration unit that over the past 3 years has at any time supplied more than one-third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale should be considered an electric utility steam generating unit. This capacity/output test should be applied on an instantaneous basis (i.e., if at any given time over the prior 3-year period the unit meets the one-third and 25 megawatt tests, the unit would be considered an EGU). This is required by the statute since the statutory EGU definition is based on a unit's capacity or megawatt output (i.e., its electrical power), not the unit's energy production over time. The EPA appears to recognize this point, since it notes that "a cogeneration facility that meets the above definition of an EGU during any portion of a month would be subject to the proposed EGU rule."
Commenter 17733 states that applying a 3-year lookback test to the second sentence, as well as the first sentence, of the EGU definition is necessary to ensure that short-term modifications to a unit do not allow it to avoid or delay the requirements of the EGU MACT Rule. This is especially important, since the very units that may be able to otherwise avoid regulation under the EGU MACT Rule by temporarily reducing their output below one-third of their capacity are also likely older, dirtier, and less efficient coal or oil plants that are operating at a lower capacity factor precisely because of their inefficiencies. Accordingly, allowing those units to avoid the requirements of the EGU MACT Rule based on temporary modifications to their historical operation would clearly fail to meet the intent of the CAA and in particular, the EPA's obligations under its Trust Responsibility and the Environmental Trust Doctrine.
Response to Comment 20: As stated in the proposed rule, a unit that meets the cogeneration definition of an EGU during any period of a month is an EGU subject to this final rule and must comply with the rule for the following 6 months. In addition, in response to comments, we included provisions to address units that may at times meet and not meet the definition of an EGU, and we allow sources that may periodically meet the EGU definition to remain subject to this final rule after that 6 month period. We believe cogeneration units in particular may take advantage of the new provisions as these units are more likely to have flexibility under the CAA section 112(a)(8) definition.
As stated above, the EPA has revised several definitions, including the definition of "fossil fuel fired," in the final rule to make clear that units must only look at the present capability and utilization of the unit to determine if it is an affected source on the compliance date. Sources will have to evaluate ongoing applicability of the standards based on their utilization of fossil fuels over annual and tri-annual periods. For example, an EGU that on the first substantive compliance date meets the definition of fossil fuel-fired will no longer be subject to the NESHAP if in subsequent years its utilization of coal or oil falls below the threshold levels to satisfy the definition of fossil fuel-fired. A source could also obtain a Title V permit requirement that prohibits the utilization of coal or oil at levels sufficient to satisfy the definition of fossil fuel-fired. Sources that violate a Title V permit limit would not only be in violation of Title V, but also in violation of the requirement to comply with this NESHAP if it exceeded the applicability thresholds.2E - Applicability: Other
Commenters: 17627, 17719, 17722, 17754, 17775, 17800, 17803, 17808, 17810, 17812, 17820, 17821, 17838, 17845, 17868, 17870, 17883, 17913, 17928, 18032, 18963, 19536/19537/19538
1. Coal Refuse Units.
Comment 1: Several commenters (17754, 17838, 18963) state that the EPA should revise the proposed provisions relating to the two subcategories of coal-fired EGUs to clarify the regulatory standards applicable to an EGU that combusts coal refuse with a heating value of greater than 6,000 Btu/lb on a dry basis. It appears from the EPA's preamble discussion to the proposed rule that the Agency intends for coal refuse fired EGUs to be covered by the proposed rule. Based on the ambiguity in the language of the relevant definitions and the apparently inconsistent language within the preamble to the proposed rule, the EPA should revise the proposed rule to expressly clarify how an EGU that combusts coal refuse with a heating value of greater than 6,000 Btu/lb on a dry basis is regulated under the proposed rule (i.e., under which of the two subcategories of coal-fired EGUs would such unit fall?).
Several commenters (17754, 17812, 17838, 18963) state that the proposed rule defines coal refuse, in relevant part, as having "a heating value less than . . . 6,000 [Btu/lb] on a dry basis." On its face, this definition would appear to indicate that a CFB unit combusting coal refuse cannot fit within the subcategory of sources comprising "unit[s] designed for coal >8,300 Btu/lb," because the heating value of coal refuse is, by definition, too low. It follows then, that, in order for a coal refuse fired EGU to be subject to the proposed rule, such unit must fall within the only other subcategory for coal-fired EGUs  -  i.e., a combustion unit designed for coal <8,300 Btu/lb. However, the "unit designed for coal <8,300 Btu/lb subcategory" is defined as including, in relevant part, "any EGU designed to burn a non-agglomerating virgin coal." This definition would appear to exclude coal refuse on the basis that coal refuse is generally considered to be distinct from virgin coal. Indeed, in the context of the EPA's Solid Waste Definition Rule, the EPA clearly takes the position that coal refuse and virgin coal are two different materials. For these reasons, it is unclear how a coal refuse fired combustion unit would be characterized for purposes of the proposed rule, because such a unit does not appear to fit within either of the two subcategories for coal-fired EGUs under the proposed rule.
Commenters 17812 and 18963 state that the proposed provisions relating to the two subcategories for coal-fired EGUs should be revised to clarify that an EGU combusting coal refuse with a heating value of less than 8,300 Btu/lb on a dry basis is regulated as a coal-fired EGU under the Utility MACT in accordance with the emission standards applicable to sources combusting coal exhibiting such lower heat content. The EPA has created only two categories for coal: >8,300 Btu Ash Free Moisture Free, and <8,300 Btu Ash Free Moisture Free virgin non-agglomerating coal. Most anthracite and bituminous waste coal (coal refuse) would have a heating value >8,300 Btu/lb.
Response to Comment 1: Partly based on comments, the EPA has revised the definitions of the two coal-fired EGU subcategories in the final rule. Under the new definitions, units burning coal refuse are included in the "[u]nit designed for coal > 8,300 Btu/lb subcategory" because such units do not meet the definition of the newly defined subcategory of "units designed to burn low rank, virgin coal."
2. The EPA should include an opt-in provision.
Comment 2: Commenter 17845 owns and operates two facilities located in the Commonwealth of Virginia, one a coal-fired cogeneration plant and the other a coal-fired electric generation plant. Each plant consists of two "three-on-one" boiler-to-generator units, in which each set of three boilers provides steam to one of two 55-MWe electric generators. Although each unit has a generator capacity of more than 25 MWe, each of the boilers has a thermal capacity of less than 250 MMBtu/hr. All boilers are equipped with dry scrubbers and bag houses. Both plants have opted into the acid rain program. The three-on-one boiler-to-generator configuration presents a novel, and perhaps unique, issue regarding applicability of proposed or final NESHAP and the proposed Cross State Air Pollution Rule (CSAPR). Specifically, it appears that the boilers at both sites could be subject to the NESHAP for Industrial, Commercial, and Institutional Boilers and Process Heaters ("Boiler MACT"), rather than the Utility MACT, although simultaneously being subject to the CSAPR, which is intended to be applicable only to EGUs, not industrial boilers.
Commenter 17845 urges the EPA to include in the Utility MACT an opt-in provision to allow units that have a generator capacity of greater than 25 MWe and that generate electricity for sale, but have a combustion rating of less than 250 MMBtu/hr, to choose the Utility MACT rather than be subject to the Boiler MACT. The EPA has previously included similar compliance options for MACT regulations in order to widen the compliance options for regulated sources (e.g., 40 CFR §63.3082(c); National Emission Standards for Hazardous Air Pollutants: Surface Coating of Automobiles and Light-Duty Trucks). By adding such a compliance option, the EPA would allow Commenter to meet the same emissions requirements as its peers, thus avoiding an economically disadvantaged scenario where only Commenter's boilers would be mandated to reduce both NOX and carbon monoxide (CO).
Commenter 17845 states that in keeping with the statutory definition in CAA section 112 (a)(8), the Boiler MACT excludes EGUs from applicability of that rule. See 40 CFR § 63.7491(a). Both the CAA and the Boiler MACT define the term "electric utility steam generating unit" to mean  -  [A] fossil fuel-fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. A fossil fuel-fired unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale is considered an electric utility steam generating unit. This definition appears to be premised on the familiar, conventional arrangement of one boiler to one generator. But it is ambiguous as applied to the unusual "three-on-one" boiler-to-generator configuration used by the Commenter's plants. Since each of its boilers contributes less than 25 MWe to Commenter's generators (each boiler contributes approximately 18 MWe), it appears from the first part of the definition that Commenter's boilers might not meet the EGU criterion for exclusion from the Boiler MACT. On the other hand, the second sentence above clarifies that such units with a potential electric output of more than 25 MWe are excluded from the Boiler MACT if they supply more than one-third of that capacity to an electric distribution system for sale. Since Commenter's units meet that criterion, they are excluded from Boiler MACT by its terms, consistent with the intent of the CAA definition. The EPA's descriptions of the intended effect of the proposed Utility MACT are consistent with the definition of excluded EGUs in the Boiler MACT. For example, the EPA stated in its Fact Sheet for the Utility MACT that the proposed rules "will affect EGUs that burn coal or oil for the purpose of generating electricity for sale and distribution." Yet the specific language of the definitions in the proposed Utility MACT would contravene both the CAA's and the EPA's apparent intent. It would have the unintended effect of excluding Commenter's units from the definition of EGU and leaving them instead to be covered by the Boiler MACT.
Commenter 17845 states that specifically, the proposed Utility MACT's definition of EGU would add a new, inconsistent threshold element to the definition. For a coal-fired unit that otherwise meets the definition to qualify as a covered EGU under the Utility MACT, it would first have to qualify as "Fossil fuel-fired." The proposed Utility MACT then defines "Fossil fuel-fired" as "an electric utility steam generating unit (EGU) that is capable of combusting more than 73 MWe (250 million Btu/hr, MMBtu/hr) heat input (equivalent to 25 MWe output) of fossil fuels." Since each of Commenter's boilers is rated at only 200 MMBtu/hr, those boilers would be omitted entirely from the Utility MACT. They would therefore be forced to comply with the Boiler MACT instead. Given the inconsistency with other requirements applicable to these units under the CSAPR, Commenter believes this effect is unintended and should be corrected. One way would be to allow Commenter and any other similarly-situated electric generators to opt in to the Utility MACT, just as Commenter has done for the Acid Rain Program.
Commenter 17845 states that in contrast to the NESHAP rules, the proposed CSAPR would base applicability on the size of the generator, rather than on the size of the combustion unit. As proposed, 40 CFR section 97.404(a)(1) would apply the CSAPR to any fossil-fuel-fired boiler serving a generator with a nameplate capacity of more than 25 MWe: The following units in a state shall be TR NOX Annual units, and a source that includes one or more such units shall be a TR NOX Annual source, subject to the requirements of this subpart: Any stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the later of November 15, 1990 or the startup of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale. Since each generator operated at both of Commenter's sites is 55 MWe, the proposed CSAPR would restrict NOX emissions from Commenter's boilers serving those generators, based on allocations to be provided by the EPA.
Commenter 17845 states that by subjecting them simultaneously to Boiler MACT and the CSAPR, the EPA would impose on the company an unnecessary and unproductive burden and disadvantage it competitively. The Boiler MACT requires reductions in emissions of CO and dioxins and furans (D/F), Although the proposed Utility MACT does not. Commenter's boilers are already able to comply with the proposed Utility MACT standards; indeed, these boilers participated in the Utility MACT ICR. The proposed CSAPR, on the other hand, requires EGUs either to reduce NOX emissions or to buy credits to meet their annual and ozone-season allocations. Emissions of CO and NOX have proven to be inversely related. Therefore, Commenter would face greater challenges to comply with both NESHAP and CSAPR than its Utility MACT peers: both Commenter and its peers would have to reduce NOX emissions but only Commenter would have to do so although simultaneously reducing CO and D/F. There is no public policy or other rationale that can support such disparate treatment. The Utility MACT does not require reductions in CO or D/F because low concentrations of chlorine in the fossil fuels and the presence of sulfur inhibit the formation of D/F. Hence there is no need to use CO as a proxy. Commenter's boilers are utility boilers that operate with sulfur to chlorine (S:Cl) ratios comparable to other utility boilers, and hence would not produce D/F. They should therefore be treated the same as other EGUs and be likewise subject the Utility MACT. Commenter urges the EPA to include a compliance option to allow it and any other EGU units subject to the CSAPR to opt in to the Utility MACT.
Response to Comment 2: The underlying statutory provisions for the electric utility NESHAP, NSPS, Acid Rain, and CSAPR programs have differing applicability definitions. For the electric utility NESHAP, the statutory definition applies to size of the boiler whereas for the Acid Rain and CSAPR programs, the statutory definition applies to the size of the electric generator. Thus, as Congress defined the EGU NESHAP source category in CAA section 112(a)(8) rather than the EPA, we do not believe that we have the flexibility to alter the applicability with regard to the size of the combustion unit through any type of "opt in" provision for the EGU NESHAP rulemaking. In addition, there is no gap between this rule and the Industrial Boiler NESHAP. An electric utility steam generating unit that does not combust solid waste is either an Industrial Boiler or an EGU. Thus, the combustion units at the two facilities are subject to the Industrial Boiler NESHAP rather than the EGU NESHAP because they do not meet the size requirement of the CAA section 112(a)(8) definition of an EGU.
Further, the EPA does not believe that the definitions in either the Industrial Boiler or EGU NESHAP contravene the intent of the CAA, and we have removed the definition of a "non-cogeneration unit" in the final rule because we determined the definition was not necessary given the clarity of the statutory definition. In the proposed rule, we improperly defined the term "non-cogeneration unit" as "a unit that has a combustion unit of more than 25 MWe and that supplies more than 25 MWe to any utility power distribution system for sale." The proposed definition is not consistent with CAA section 112(a)(8) because that provision does not require EGUs that are non-cogeneration units to sell 25 MWe to the power distribution system. We have corrected the error in the final rule. Based on the revised definitions, it is clear that any EGU greater than 25 MW is properly covered under the EGU NESHAP if the EGU is also a "coal-fired" or "oil-fired" EGU as those terms are defined in the final rule. Also, as noted elsewhere in this document, commenters have pointed out that the "73 MWe (250 million Btu/hr, MMBtu/hr) heat input" equivalency to 25 MWe output does not apply to all EGUs because of differences in efficiency; commenters indicated that the electric utility industry was familiar with the "MW" concept as being thermal MW and the EPA should remove the equivalency from the final rule. Based on these comments, the EPA has made that correction to the final rule.
Commenter also notes that the EPA has used opt-in provisions in other NESHAP actions, specifically the Automobile and Light Duty Truck Surface Coating NESHAP (40 CFR Part 63, subpart IIII). In that rule, the EPA allowed co-located facilities subject to the Surface Coating of Miscellaneous Metal Parts and Products NESHAP (40 CFR Part 63, subpart MMMM) or the Surface Coating of Plastic Parts and Products NESHAP (40 CFR Part 63, subpart PPPP) to "opt in" to the Automobile and Light Duty Truck Surface Coating NESHAP. However, there are a number of differences between the two actions that the EPA believes are pertinent. First, the operations had to be co-located (i.e., coating operations subject to 40 CFR subparts MMMM or PPPP had to be co-located with coating operations subject to 40 CFR Part 63, subpart IIII) to be able to "opt in." Such is not the situation in the cases the commenter notes; the subject EGUs are not co-located with units subject to another NESHAP. Further, the provisions of 40 CFR Part 63, subpart IIII, are more stringent in every detail than those of either 40 CFR Part 63, subparts MMMM or PPPP. As the Industrial Boiler NESHAP is currently in reconsideration, such a statement cannot be made at this time. Finally, as noted above, Congress defined the EGU source category whereas the EPA defined the coatings categories and, thus, the Agency had the flexibility to alter the applicability definitions. The EPA does not believe it has such flexibility to redefine the source category in this case where the statute is clear as it is with the 25 MW provision, and, thus, the Agency cannot allow a source to "opt in" to the EGU NESHAP.
3. The EPA should clarify that the rule does not apply to simple cycle combustion turbines.
Comment 3: Commenter 17883 owns at least one liquid-fired facility that meets the definition of a liquid-fired EGU. However, section 63.9983 excludes any "unit designated as a stationary combustion turbine, other than an integrated gasification combined cycle, covered by 40 CFR Part 63, subpart YYYY." The liquid-fired facility in question is a stationary combustion turbine; however, since it is a minor source of HAP, it is not subject to YYYY. The EPA states in the preamble that stationary combustion turbines are not considered EGUs for the purposes of this rule. However, the language in the section assumes these stationary units are otherwise covered in a separate subpart. Commenter is requesting confirmation that stationary combustion turbines are not subject to this rule regardless of whether they are subject to Subpart YYYY.
Comment 4: Commenter 17913 says that the regulation should clearly state that it does not apply to simple cycle combustion turbines (SCCTs). Since the name of the rule includes "electric utility steam generating units," it implies that it would not be applicable to SCCTs since there is no steam generation with these units. However, the definition of EGU in paragraph 63.10042 of the regulation does not specify that the term applies only to steam generating units. This is further confused by giving the acronym EGU within this definition. The definition of electric utility steam generating units should clearly state that it includes only units that produce steam and should apply the acronym EUSGU to the definition. This could also be clarified by indicating that SCCTs are not subject to the regulation in paragraph 63.9983 of the proposed regulation.
Response to Comments 3 and 4: The EPA believes that the definitions are sufficiently clear as proposed. First, paragraphs 63.9980 and 63.9981 provide that affected units must be coal- or oil-fired EGUs. Natural gas-fired EGUs are not subject to the rule. Further, the definition provided in paragraph 63.10042 is the statutory definition from CAA section 112(a)(8) and contains the word "steam" in the title, thereby indicating that a unit must generate steam in order to be an EGU. This requirement excludes simple cycle combustion turbines which generate no steam. The EPA has not changed these definitions in the final rule.
4. Support for the exclusion of natural gas-fired units.
Comment 5: Commenter 17810 supports the Agency's exclusion of natural gas-fired EGUs from the CAA section 112 regulations, and also from the PM and opacity requirements under applicable New Source Performance Standards.
Response to Comment 5: The EPA appreciates the support of the commenter.
5. Definition of new unit.
a. Commenced after May 3, 2011.
Comment 6: Commenter 17820 supports the EPA's proposal to define an EGU as a "new" unit if construction is commenced after May 3, 2011 (date this rule was published in the Federal Register) as opposed to the date MACT limits were initially proposed for EGU's (January 30, 2004), prior to the EPA's subsequent decision not to regulate under CAA section 112. In addition, the initial proposal in 2004 included limits for mercury and nickel, although this proposal seeks to impose MACT limits for several other non-mercury and metal HAP.
Comment 7: Commenter 17821 takes the position that the EPA's choice of May 3, 2011 as the new unit cutoff date is the only one permissible date that would be in keeping with the CAA and the actions of the courts. A "new source" is defined in CAA section 112(a)(4) as a stationary source the construction of which is commenced "after the Administrator first proposes regulations under this section." Some would argue that MACT limits were first proposed for EGUs on January 30, 2004 when the EPA proposed the Clean Air Mercury Rule. However, the EPA subsequently decided not to regulate EGUs under CAA section 112. That decision was vacated by the D.C. Circuit in New Jersey v. EPA. That court has previously said that "to vacate, as the parties should well know, means `to annul; to cancel or rescind; to declare, to make, or to render, void; to defeat; to deprive of force; to make of no authority or validity; to set aside.'" Therefore, the EPA is correct in treating the May 3, 2011 proposal as the first for purposes of defining whether a given EGU is a new source.
b. Commenced after January 30, 2004.
Comment 8: Commenter 19536/19537/19538 states that the rule must define as "new sources" all sources which commenced construction after January 30, 2004. The CAA defines a "new source" to include any "stationary source the construction or reconstruction of which is commenced after the Administrator first proposes regulations under this section establishing an emission standard applicable to such source." 42 U.S.C § 7412(a)(4) (emphasis added). The Agency first proposed emission standards applicable to oil- and coal-fired electric generating units on January 30, 2004. 69 Fed. Reg. 4,652 (January 30, 2004). All coal- and oil-fired power plants that commenced construction or reconstruction after that date, consequently, are "new sources" under CAA section 112, and the rule should define them as such.
Commenter 19536/19537/19538 states that the clear text of the statute requires that result. The Agency's withdrawal of the standards proposed in 2004 is irrelevant; the statute specifies proposal of standards as sufficient to bring subsequently constructed sources within the ambit of the "new source" definition. And likewise, the Agency's subsequent proposal of different emissions standards is irrelevant; the statute expressly provides the first proposal as point dividing new from existing sources. [Footnote: Indeed, EPA's effort to replace its section 112 standards with standards under CAA section 111 is a legal nullity that has no effect at all. "When a court vacates an Agency's rules, the vacatur restores the status quo before the invalid rule took effect. . . ." Envtl. Def. v. Leavitt, 329 F. Supp. 2d 55, 64 (D.D.C. 2004) (citing Indep. U.S. Tanker Owners Comm. v. Dole, 809 F.2d 847, 854 (D.C. Dir. 1987)).] That command cannot be reasonably understood to allow the Agency to move that point to the second (or third, or fourth) proposal.
Commenter 19536/19537/19538 states that the statutory definition, especially in light of the strict deadlines by which the CAA requires the EPA to establish effective standards, reflects Congress' intent to ensure maximal reductions in air toxics. It further reflects Congress' desire to prevent industry from relying on administrative lobbying and judicial challenges to delay installation of pollution controls, or to secure weaker restrictions on their hazardous air pollution. And finally, the CAA discourages manipulation of construction schedules in a similar pursuit of lesser restrictions.
Response to Comments 6 - 8: CAA section 112(a)(4) states that a new source is a stationary source if "the construction or reconstruction of which is commenced after the Administrator first proposes regulations under this section establishing an emissions standard applicable to such source." "First proposes" could refer to the date the EPA first proposes standards for the source category as a whole, or could refer to the date the Agency first proposes standards under a particular rulemaking record, or first proposes the particular standards at issue. We believe that the May 3, 2011, proposal date is the proper date under CAA section 112(a)(4) because the intent of the new source provision is to provide sources with sufficient notice so that new source control requirements can be considered in the initial design. Sources coming into existence between the January 30, 2004, proposal date and the May 3, 2011, proposal date would have no reasonable means of ascertaining the standards' for this final rule and so lacked notice of what controls and strategies to adopt. Because this is antithetical to the policy underlying new source standards, the EPA is maintaining May 3, 2011, as the date which determines if a source is existing or new. In addition, major source EGUs constructed after December 20, 2002, are subject to the case-by-case MACT requirements of CAA section 112(g). We believe it would be unreasonable to require these sources to comply with the new source limits in this final rule when such limits were not even available for consideration at the time the units were constructed.
6. The EPA should define a new source category for IGCC units.
Comment 9: Commenter 17821 recommends a different approach for regulating IGCC units under MACT. There are major differences between IGCC units and conventional coal-fired units. No individual IGCC unit by itself is a major source of HAP. As a matter of fact, the Air Quality Analysis performed for the Edwardsport Generating Station IGCC (SSM 083-23529-00003. Appendix C) IDEM states "Based on the HAP modeling results, the source will not pose a health concern."
Commenter 17821 believes that IGCC's are not included as part of the EGU category of the EPA's 2000 listing decision. This is because the IGCC process is so different from conventional coal boilers that they do not resemble the conventional electric utility steam generating unit. As a result it would be reasonable for the EPA to go beyond their subcategory determination and place IGCC units in a separate source category altogether. Although the EPA has previously created a separate source category for combustion turbines including units that generate electricity, it would not be appropriate to place IGCC units in that source category either.
Commenter 17821 states that the EPA has repeated that it intends to finalize a Utility MACT standard in November, 2011; however the proposal is particularly lacking in its discussion and treatment of IGCC units. Commenter strongly believes that the EPA needs to take the time necessary to properly review all the information provided during the comment period, make the appropriate changes, conduct an internal and an interAgency review before finalizing a standard. Commenter argues that it would be especially difficult to properly finalize final IGCC standards by November, 2011.
Response to Comment 9: The EPA disagrees with the commenters that state IGCC units should be in a separate source category from other coal- and oil-fired EGUSs. IGCC units generate steam from coal- and oil-derived fuel and, thus, fall within the CAA section 112(a)(8) definition of an EGU. The EPA listed coal- and oil-fired EGUs and such units, including IGCC units, cannot meet the statutory criteria for delisting. The EPA is establishing the final IGCC MACT limits on data from existing IGCC units or on permit limits provided for IGCC units currently under construction, thus, we maintain we have sufficient data on which to establish valid section 112(d) standards.
7. The EPA should exempt units already permitted under 112(g).
Comment 10: Commenter 18032 states that the EPA should exempt units from new source HAP requirements if they are already permitted and have complied with valid state-imposed section 112(g) HAP control requirements. Commenter is particularly concerned that the proposal (and potential finalization of) section 112 MACT limits for new sources under this rulemaking will make it impossible for them to build a new, highly-efficient, low-emission plant to replace a much less clean plant, which is critical to the Commenter and major community institutions.
Commenter 18032 is actively exploring the possibility of replacing the existing, coal-fired DeYoung Unit 3 with a much more efficient and low-emitting circulating fluidized bed boiler that will burn a blend of fuels including renewable wood and biosolids biomass, tire-derived fuel, coal and other fuels. If constructed, this 78-MW plant could also be a combined heat-and-power unit to provide multiple benefits to the community, including an expansion of the successful downtown snow melting system under the streets and sidewalks. Commenter has been through a laborious permitting process, which began 55 months ago to obtain a construction permit (known as a "Permit to Install" or "PTI" under Michigan Department of Environmental Quality regulations under its delegation of Clean Air Act authority from EPA). That permit was obtained in February 2011. During the permitting process, Michigan DEQ conducted an intense process of identifying the Maximum Achievable Control Technologies for HAP including acids, metals, and PM, pursuant to CAA section 112(g). Under that section 112(g) permitting review, MDEQ imposed requirements on the proposed new plant that went beyond the already efficient and clean combustion advantages of a circulating fluidized bed boiler, including the application of a high-performing baghouse for PM and metals, and sorbent injection for mercury.
Commenter 18032 states that it would be highly unreasonable and unnecessary for the EPA, with the proposal and potential finalization of the MACT limits for new sources, to require Holland to unwind its Michigan Permit to Install and its HAP controls. Moreover, Commenter's plant will be technically unable to meet the proposed new unit standards  -  as it is not technologically feasible for any plant. And Although Commenter could perhaps embark now on an impossible effort to revise its entire plant and permit for newly proposed MACT requirements, the community will in reality be hamstrung and stalled as it waits for the proposed requirements to be finalized  -  a process that will require Commenter to wait to commence construction until the time that its current PTI permit becomes invalid and disappears in one year, August 2012.
Commenter 18032 states that without clean generation capacity additions, Commenter may be forced to make additional purchases from a volatile wholesale market to serve its community, including the electric vehicle batteries that will be constructed in new plants that President Obama launched last year (and will revisit the week of August 8) to create thousands of jobs in struggling Michigan.
Commenter 18032's proposed and permitted plant is unique in so many ways  -  it is smaller than most new coal-fired plants, it is multi-fuel, it is a CHP unit, and it applies a medley of pollution control technologies. It really can't be categorized with other units (or "Franken-Plants") that the EPA has suggested should set the standard for the new EGU's. And as it has already undergone a major HAP review under CAA section 112(g) that will result in reduced emissions impact, it shouldn't be subjected to new, unachievable requirements.
Response to Comment 10: CAA section 112(a)(4) defines a new source as "a stationary source the construction or reconstruction of which is commenced after the Administrator first proposes regulations under this section establishing an emission standard applicable to such source." The EPA is constrained by this definition such that any source that "commenced" construction after the May 3, 2011, proposal date is considered a new source under the statute and the source must comply with the new source standards even if the source received a CAA section 112(g) permit before proposal. The EPA's regulations implementing the CAA section 112 general provisions define "commenced" to mean "with respect to construction or reconstruction of an affected source, that an owner or operator has undertaken a continuous program of construction or reconstruction or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction or reconstruction." See 40 C.F.R. 63.2. It is unclear from the comments whether the sources identified in the comments have commenced construction as defined in the regulations; however, the identified sources are existing sources, not new sources, under the final rule if construction was commenced prior to the proposal date. Existing sources have 3 years to come into compliance with the final standards if the source's CAA section 112(g) limit is not consistent with the existing source limits applicable to the source.
Under the final rule, new sources must comply with the standards on the date of promulgation or at startup, whichever is earlier, and existing sources have 3 years to come into compliance with the final standards. Pursuant to EPA's regulations at 40 C.F.R. 63.44(b)(1), however, we may provide in a final section 112(d) standard a specific compliance date for those sources that obtained a final and legally effective section 112(g) case-by-case MACT standard and submitted the information required by 40 C.F.R. 63.43 to the Agency before the close of the comment period. The EPA does not believe it has received such information during the comment period and we are not establishing a separate specific compliance period for sources that obtained final and legally effective section 112(g) standards prior to promulgation of the final rule. In the absence of EPA action on this issue, state Title V permitting authorities are required to "establish a compliance date in the [Title V] permit that assures that the owner or operator shall comply with the promulgated standard [ ] as expeditiously as practicable, but not longer than 8 years after such standard is promulgated . . . ." 40 C.F.R. 63.44(b)(2). Sources with final and legally effective section 112(g) standards should work with their permitting authorities to determine the appropriate compliance date consistent with the EPA regulations.

                         CHAPTER 3: SUBCATEGORIZATION
3A - Subcategorization: Coal (>8,300 Btu/lb) (Proposed)
Commenters: 17740, 17807, 17818, 17820, 17873, 17878, 17885, 17912, 17927, 18033, 18034, 18424, 18429, 18450, 18483, 18539, 19041, 19114
1. Clarify subcategory for units combusting coal and petroleum coke.
Comment 1: Commenter 17740 states that the EPA should clarify the appropriate category for coal-fired EGUs >8,300 Btu/lb that also combust petroleum coke ("pet coke"). According to the commenter, based on the language in the preamble, it appears that a unit combusting coal and pet coke would be regulated as a coal-fired unit in the >8,300 Btu/lb subcategory. The commenter states that however, subsequent language discussing solid oil-fired units suggests that it might be regulated in that category. According to the commenter, a fuel-flexible unit designed and permitted to burn both pet coke and coal that burned more than a de minimis amount of coal would have significant difficulties.
Response to Comment 1: The EPA has revised several definitions in the final rule to clarify when units are considered coal-fired, oil-fired, or natural gas-fired EGUs, including changes to the definition for solid oil-fired EGUs. The definitions of "Coal-fired electric utility steam generating unit," "Integrated gasification combined cycle electric utility steam generating unit," "Oil-fired electric utility steam generating unit," and "Unit designed to burn solid oil-derived fuel subcategory" have been modified as follows to clarify applicability for units co-firing coal and petroleum coke:

      Coal-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that burns coal or coal refuse for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.

      Integrated gasification combined cycle electric utility steam generating unit or IGCC means an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that burns a synthetic gas derived from coal and/or solid oil-derived fuel more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year in a combined-cycle gas turbine. No coal or solid oil-derived fuel is directly burned in the unit during operation...

      Oil-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that is not a coal-fired electric utility steam generating unit and that burns oil more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.

      Unit designed to burn solid oil-derived fuel subcategory means any oil-fired electric utility steam generating unit that burns solid oil-derived fuel.
2. Clarify how to determine "designed" to burn.
Comment 2: Commenter 17927 asks the EPA to clarify how it will determine if an EGU is "designed" to burn coal having a calorific value of greater than or less than 8,300 Btu/lb. The commenter states that it seems that most boilers would be capable of burning coal in a range of fuel heat contents greater than or less than 8,300 Btu/lb. The commenter asserts that perhaps the definition of these sub-categories should be revised so that it is clear what is meant by "designed to burn."
Commenter 17677 states that the coal-fired unit designation related to "Coal fired unit designed for coal >= 8,300 Btu/lb" is very confusing. The commenter asks where did the EPA come up with this cut-off? According to the commenter, boiler design information is most likely not available to the EPA and was not part of the 2010 ICR. The commenter asks could the cut-off be more simply defined? Such as coal type? According to the commenter, after considerable research on Commenter's equipment design and reading most of the proposed rule, Commenter emailed Bill Maxwell of EPA and he responded with this statement "the 8,300 BTU/lb definition is taken from ASTM Designation D388-05, Standard Classification of Coals by Rank." Commenter researched this with their coal lab and the lab performed an analysis and found that the commenter's subbituminous coal is significantly above the 8,300 BTU/lb threshold. The commenter states that however, finding the design information for these relatively new boilers, in the context of D388-05 specifications was not possible without considerable assumptions. According to the commenter, the EPA should consider a different approach for this critical applicability cut-off.
Response to Comment 2: The EPA has clarified the subcategory definitions in the final rule as explained in the preamble to the final rule.
3. Clarify the subcategory for units >8,300 Btu/lb and height-to-depth ratio greater than 3.82.
Comment 3: Commenters 17878 and 18483 state that the EPA defines the two coal-fired unit subcategories as based on 1) the calorific value of the coal the boiler is designed to combust and 2) the boiler dimensions in terms of height-to-depth ratio. According to the commenter, the EPA should clarify in which subcategory a unit belongs when it is designed to combust a coal with a calorific value greater than 8,300 Btu/lb and it simultaneously has a height-to-depth ratio of greater than 3.82. The commenter asserts that such a boiler would not fit neatly within either of the two subcategories as currently defined. The commenter states that the EPA should state explicitly which category a unit belongs if it is designed to burn coals having a calorific value of both >= 8,300 Btu/lb and < 8,300 Btu/lb. The commenter asks is it correct that in this case, the applicable subcategory is based solely on the boiler height-to-depth ratio?
Response to Comment 3: The EPA has clarified the subcategory definitions in the final rule as explained in the preamble to the final rule.
4. General support for the subcategory.
Comment 4: Commenter 17722 fully supports the subcategory of "coal-fired unit designed for coal greater than or equal to 8,300 Btu/lb."
Commenter 18450 supports the EPA's proposed subcategories for coal fired EGUs. According to the commenter, the EPA has proposed two basic subcategories for coal-fired EGUs: (l) EGUs designed for coal >8,300 Btu/lb, and (2) EGUs designed for coal <8,300 Btu/lb. The commenter asserts that the results of EPA's ICR clearly justify the creation of only two subcategories.
Response to Comment 4: The EPA appreciates the commenters' support. We note that we have clarified the subcategory definitions in the final rule as explained in the preamble to the final rule.
5. Further subcategorization by coal rank.
a. Support for further subcategorization by coal rank.
Several Commenters (17623, 17627, 17712, 17716, 17736, 17739, 17757, 17761, 17774, 17805, 17807, 17817, 17818, 17820,17885, 17898, 17912, 18018, 18033, 18034, 18424, 18429, 19041, 19114) support further subcategorization by coal rank.
i. Subcategorization by coal rank is consistent with past practice.
Comment 5: Commenter 17716 states that the bases for determining which subcategories and sources would be regulated under the proposed NESHAP are explained in the rule. The commenter asserts that one category that has been suggested is for "Units designed for coal < 8,300 Btu/lb," apparently to distinguish lignite sources. According to the commenter, although other subcategories had been evaluated, including subcategorization of other coal ranks, no other coal rank subcategorization was proposed. Commenter submits there should be subcategories for the coal rank: bituminous, subbituminous, and lignite. According to the commenter, such treatment would be consistent with past practice. According to the commenter, see Proposed National Emissions Standards for Hazardous Air Pollutants; and, in the Alternative, Proposed Standards of Performance for New and Existing Stationary Sources: Electric Utility Steam Generating Units; Proposed Rule. 69 FR 4652, 4692 (Jan. 30, 2004), discussing differences in the type of emissions of Hg due to the different chemical properties of coal within differing fuel ranks. The commenter states that as a result, the EPA proposed different Hg limitations: for new sources burning (1) subbituminous coal - 20 x 10-6 lb/MWh (output basis), (2) bituminous coal - 6 x 10-6 lb/MWh (output basis), and (3) coal refuse - 1.1 x 10-6 lb/MWh (output basis). According to the commenter, the marked difference for coal refuse was justified by coal refuse combustion characteristics: "Available data indicate that emissions from the combustion of coal refuse tend to result almost entirely in particulate-bound Hg (greater than 99 percent for both units tested in the 1999 EPA ICR). The commenter asserts that with few exceptions, particulate-bound Hg can be removed with PM controls, Hg++ can be removed with wet SO2 controls (flue gas desulfurization (FGD) scrubbers), but elemental Hg usually shows little to no removal with any existing conventional type of APCD used on utility boilers." According to the commenter, coal rank differentiation in mercury emission limits was proposed in the Clean Air Mercury Rule (CAMR).
Commenter 17716 states that the advent of newer control technologies, such as activated carbon injection (ACI), allows further effective control of elemental Hg. The commenter states that nonetheless, there still remains varying degrees of reduction necessary to achieve equivalent emission levels when using different coal ranks. According to the commenter, if combustion of a material such as coal refuse will inherently achieve an almost 99 percent reduction in Hg with use of minimal controls, such sources should be considered separately from sources burning other coal ranks (i.e., bituminous coal) that achieve different levels of reduction with the same amount of controls. The commenter asserts that no reason has been advanced why past precedent of making coal rank subcategorizations should not continue here. According to the commenter, the difference in effectiveness of Hg control for different coal ranks was noted in the current rulemaking as well. The commenter asserts that AC has been shown to be very effective when used in combination with low chlorine coals (such as U.S. western subbituminous coals). The commenter states that activated carbons can suffer from poor performance when used with high sulfur coals. According to the commenter, firing high sulfur coals (especially when an SCR is also used) can result in sulfur trioxide (SO3) vapor in the flue gas stream. The commenter asserts that the SO3 competes with Hg for binding sites on the surface of the AC (or unburned carbon) and limits the effectiveness of the injected AC. According to the commenter, an SO3 mitigation technology -- such as dry sorbent injection (DSI, e.g., trona or hydrated lime) -- applied upstream of the ACI can minimize this effect. The commenter asserts that particle-bound Hg can be effectively removed along with other flue gas PM (including non-Hg metal HAP) in primary or secondary PM control devices. The commenter states that electrostatic precipitators (ESP), FF and wet FGD scrubbers are all effective at removing Hg, with the degree of effectiveness depending on the specific characteristics of the EGU and fuel types.
Comment 6: Commenter 17757 states that boilers typically are designed to burn a particular class of coal and were not designed with the capability or intention of switching to another rank of coal. According to the commenter, just as Btu/lb has been deemed an appropriate criterion for sub-categorization, so too should the EPA establish different MACT limits for bituminous, sub-bituminous, eastern, western, and lignite coals, and recognize, as the EPA has done in the past, that the substantial differences in emission characteristics and heating value for the various coal ranks impact the reasonably anticipated reductions that can be achieved.
Commenter 17757 states that many coal-fired units utilize a blend of bituminous and sub-bituminous coals. According to the commenter, the MACT rule should allow for adjustment of emission limits to account for blended coal usage, rather than its current rigid scheme. The commenter states that the EPA should add subcategories for various coal ranks and provide for flexibility in addressing the blending of coals.
Comment 7: Commenter 18033 states that the EPA explicitly acknowledged the need for subcategorization based on coal ranks in CAMR. According to the commenter, the Agency stated, "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." The commenter asserts that here the Agency recognized the need to subcategorize based on coal rank by providing separate emissions standards for lignite. According to the commenter, although Commenter is supportive of the EPA's decision to subcategorize for lignite, the Agency needed to further subcategorize especially given the stringency of the proposed acid gas standard.
Commenter 18033 states that in the proposed rule, the EPA declined to further subcategorize beyond lignite because "the data did not show any difference in the level of HAP emissions." According to the commenter, based on the information the EPA provided to UJAE, however, emissions data demonstrate that the proposed acid gas standard will in fact create differences in the level of emissions. The commenter states that thus, without further subcategorization the proposed rule will fundamentally discriminate between coal types.
Commenter 18033 states that without further subcategorization the economic impacts on individual midwestern states will be particularly acute as huge segments of the U.S. coal reserve will be disenfranchised by this rule. According to the commenter, the EPA did not even attempt to legitimately analyze this issue. The commenter asserts that thus, the Agency's proffered rationale for declining to further subcategorize based on the acid gas standard is belied by the record. According to the commenter, the EPA needs to better align with its previous position in CAMR and further subcategorize based on coal type.
Comment 8: Commenter 19114 states that the design of a coal-based generating unit is driven by the characteristics of the coal supply. According to the commenter, a wide variety of combustion technologies and unit designs have been deployed and are available that contribute varying strengths with respect to unit efficiency, system performance, expected emissions profile, and commercial maturity. The commenter asserts that in general, combustion technologies for coal-based units can be classified as pulverized coal, fluidized bed, and coal gasification. According to the commenter, further, the fuel type selected, anticipated emissions profile and chosen combustion technology drives the selection of emission controls, such as wet vs. dry flue gas desulfurization or selective catalytic vs. selective non-catalytic reduction systems. The commenter asserts that all of these design differences, and subsequent operating variables and emissions performance, are a result of varying coal characteristics. The commenter asserts that these differences were recognized in prior EPA rulemakings, and have consistently been used to create different categories and subcategories of units and tailor emission standards. According to the commenter, a similar approach should have been used in the current EGU-MACT rulemaking.
Comment 9: Commenter 17807 proposes that the EPA develop permit limits based on coal basin subcategorization classifications. According to the commenter, the EPA has applied subcategorization limits based on heating values < 8,300 Btu/lb for  and > 8,300 Btu/lb for subbituminous and bituminous coals. The commenter states that the proposed categorizations do not address the wide range of chemical compositions and variability with HAP emissions for coals in the category > 8,300 Btu/lb. The commenter asserts that for example, Powder River basin (PRB) coals have generally lower SO2 and HCl emissions due to very low concentrations of chlorides and sulfur in the coal. According to the commenter, llinois basin coals can have substantially higher SO2 and HCl emissions due to higher concentrations of chlorides and sulfur in the coal. The commenter asserts that the proposed emission limits for HCl penalize utilities for using coals with higher chloride and sulfur. According to the commenter, higher chlorides in coal contribute to Hg reduction by supporting the oxidation and subsequently easier removal of mercury in existing control devices. Commenter requests that the EPA publish the coal blends in the top 12 percent of each category and develop specific non-metal HAP and HCl permit limits based on chemical composition from each major coal region. According to the commenter, the subcategorization can be similar to the proposed CAMR (70 FR 28653, May 18, 2005), standards for Hg.
Response to Comments 5 - 9: The EPA disagrees with the commenters' suggestion that the EPA must establish new subcategories. The EPA may create subcategories which distinguish among "classes, types, and sizes of sources." See CAA section 112 (d)(1). The EPA reads this provision to provide the Agency with discretion to subcategorize, and the EPA may exercise that discretion if sources are rationally distinguishable due to some difference in class, type, or size. See Lignite Energy Council v. EPA, 198 F. 3d 930, 933 (D.C. Cir. 1999) ("EPA is not required by law to subcategorize--section 111 [b] [2] merely states that `the Administrator may distinguish among classes, types, and sizes within categories of new sources'" (emphasis in original)). Moreover, as we noted at proposal, any basis for subcategorizing should be related to an effect on emissions, rather than to some difference among sources which does not affect emissions performance. 76 FR 25036. The EPA may also exercise this discretion on a pollutant-specific basis, because the difference in class, type, or size may only have practical significance for certain HAP. In this final rule, the EPA carefully considered the possibility of creating different subcategories of EGUs and concluded that it was reasonable to establish six subcategories.

The EPA also disagrees with commenters that additional subcategories are warranted and we have not established additional coal-fired EGU subcategories in the final rule. Commenters are correct in that additional subcategorization was proposed in January 2004. Without agreeing with commenters that such subcategorization was warranted or reasonable at that time, the EPA believes that the current conditions are such that, even if appropriate at that time, such further subcategorization is no longer appropriate based on the information available to the Agency, and we have reasonably exercised our discretion in declining to further subcategorize EGUs.

With the exception of Hg, the EPA does not believe that the HAP emissions to the atmosphere from coal-fired EGUs are sufficiently different to warrant further subcategorization. EGUs firing bituminous, subbituminous, and coal refuse are all among the top performing units for Hg and EGUs firing bituminous, subbituminous, lignite, and coal refuse are all among the top performers for the acid gas and non-Hg metallic HAP indicating that the MACT floor limits established based on these units would be achievable. We have identified approximately 69 EGUs that, based on the data available, comply with all the existing-source standards (i.e., Hg, PM, and HCl) and among those sources are both PC and FBC EGUs, and EGUs burning bituminous, subbituminous, lignite, and coal refuse.

The EPA disagrees with commenters that elemental Hg usually shows little to no removal with any existing conventional type of air pollution control used on utility EGUs. As noted by other commenters, ACI, not fully developed in 2004, is now able to effect mercury control levels on subbituminous coals (which emit relatively more elemental Hg) such that similar emissions to the atmosphere may be achieved as those achieved by higher-chlorine bituminous coals when FGD systems are used or by coal refuse units with fewer controls. The EPA also agrees with commenter that there are means available for addressing the adverse impact that SO3 may have on ACI performance, whether it be by using a carbon specially formulated to address the issue, or by some other method. Thus, in looking at the total system, similar emissions to the atmosphere are achieved by all of these coal ranks. The EPA has addressed elsewhere in this document its rationale for not subcategorizing by coal chlorine content but, in any event, the EPA does not believe that any fundamental discrimination between coal ranks will result as a result of the final rule. Sources have a wide array of control options available to comply with the final standards and it is likely that different units will employ different controls and other HAP emission reduction options to comply with the final standards.

The EPA agrees, in theory, that EGUs are designed around a basic set of coal characteristics. However, it was learned during the 1999 ICR that numerous EGUs have conducted trial burns and gained sufficient experience such that co-firing blends of bituminous and subbituminous, and to a lesser extent lignite and subbituminous, is now common practice. In fact, the EPA believes that such blends may be modified daily, depending on the characteristics of the coal being burned and on the level of generation needed. The extent of blending, and the ability to switch the blends on short-notice, does not lend itself (or, in fact, argue for) additional subcategorization. Furthermore, to the extent there are any differences in HAP emissions for different types of boilers or coal, with the exception of mercury for the subcategories we established, we would decline to exercise our discretion in any case because we believe based on the data that the existing source standards are achievable for all EGUs in both coal-fired EGU subcategories. For these reasons, we decline to further subcategorize coal-fired EGUs.
ii. Subcategorization by coal rank is necessary to account for the feasibility and effectiveness of controls.
Comment 10: Commenter 17716 concludes that subcategorization allows the EPA to account for feasibility and effectiveness of a control technology due to differences in fuel rank. According to the commenter, the wide range of coals found in the U.S. contain a plethora of chemical properties, including widely varying percentages of the three relevant species of Hg (elemental, particulate and gaseous ionic). The commenter states that in addition, the content of Hg, sulfur and chlorine present in any coal rank greatly affects the species of Hg created during combustion. The commenter states that similar differences in content and emissions for other HAP, such as HCl, are also found in different coal ranks. According to the commenter, these factors warrant providing different sets of controls and limits tailored to fit the characteristics of the different coal types. The commenter states that the EPA should reconsider the proposed subcategorization as currently established and allow subcategorization based on differentiation of coal rank.
Comment 11: Commenter 17805 agrees with the EPA's approach of subcategorizing oil-fired and lignite-fired facilities, however, the company recommends that the EPA further research the differences between coal types and how additional controls for mercury may already reduce other HAP as a potential additional subcategorization method. According to the commenter, for instance, Commenter's Lewis & Clark Station, an approximate 50 MW capacity lignite-fired unit, began controlling mercury emissions in late December 2009 utilizing oxidizing agent and activated carbon injection. The commenter states that a wet scrubber is also used for particulate control, as opposed to an electrostatic precipitator or a baghouse. According to the commenter, from review of preliminary stack test results from non-mercury metals testing conducted at the unit this summer, it appears that Lewis & Clark Station would be able to pass the proposed total non-mercury metals limit, but would not pass all of the proposed individual metals limits nor the proposed total PM limit.
Comment 12: Commenter 17627 states that there are significant and documented differences in halide (chloride) and Hg concentrations in sub-bituminous coal (e.g., PRB coal) versus bituminous coals (i.e., eastern bituminous coal). According to the commenter, chloride concentrations are much lower in sub-bituminous coals than in bituminous coals yet there is no distinction between the two fuels in the proposed rule. The commenter asserts that a target reduction percentage, say 80 percent, from a low starting concentration is a significantly harder and costlier endeavor than extracting the same percent reduction from bituminous coal. The commenter states that conversely although Hg concentrations tend to be lower in sub-bituminous when compared to bituminous coals it is more difficult to remove because of the lower chlorine content. According to the commenter, due to these widely varying constituent concentrations, a separate set of limits and controls should apply to each.
Commenter 17627 states that the subcategorization of coal is based on a heat input value of 8,300 Btu/lb or essentially the separation between lignite and all other coals. According to the commenter, there is a significant difference, however, between sub-bituminous (>8,300 Btu/lb but <10,000 Btu/lb) and bituminous coal (>10,000 Btu/lb) in constituent concentrations; namely chloride and Hg. The commenter states that these two constituents vary markedly between these coal classes, defining the type and extent of necessary emission controls. According to the commenter, further subcategorization between subbituminous and bituminous coal is necessary.
Comment 13: Commenter 19114 states that coal characteristics drive the design and operation of boilers, as well as the selection and performance of associated emissions control equipment. The commenter states that the proposed rule is insufficiently structured to appropriately address the range of coal types, unit designs, and equipment performance capabilities of coal-based electric generation processes. According to the commenter, further, the EPA has ignored the technical feasibility, and potentially exorbitant costs of boiler modifications and control technology retrofits by not considering the impacts of coal rank on unit design and performance. The commenter asserts that such distinctions were taken into account in determining emission rates for the acid rain program and the prior mercury proposals issued by the Agency, and should not be ignored in this rulemaking. The commenter states that to address these concerns regarding the substantial differences in emission characteristics and heating value for the various coal ranks on the emission reductions that can be achieved in practice, the EPA should establish separate subcategories and corresponding separate MACT standards for bituminous, sub-bituminous, and lignite coals. The commenter states that numerous state agencies have performed CAA section 112(g) case-by-case MACT determinations and have determined that such subcategorization is technically and legally appropriate.
Comment 14: Commenter 17885 states that the EPA should either develop a section 112(d)(4) health based standard for HCl or develop EGU subcategories based on bituminous and sub-bituminous coal use to accommodate the different emission control capabilities based on coal rank. According to the commenter, the proposed HCl limits are based on several questionable assumptions. The commenter asserts that available information does not support the contention that dry-sorbent injection (DSI) technology can achieve the levels of reduction necessary on EGUs using high chlorine eastern bituminous coals to meet the proposed MACT HCl limits.] The commenter states that the EPA takes the position that establishing a section 112(d)(4) HCl standard is inappropriate because information is not available to show acute exposures will not pose health concerns. According to the commenter, it appears, however, from the EPA's analysis and preamble discussion that it believes that health risks due to acids gas exposures including HCl is minimal. The commenter asserts that in view of these circumstances we believe it is appropriate to at the very least establish EGU subcategories for HCl controls based on coal rank such that represent levels achievable based on DSI installation and coal rank.
Comment 15: Commenter 17820 states that there are also significant and documented differences in halide (chloride) and Hg concentrations in sub-bituminous coal (e.g., PRB coal) versus bituminous coals (i.e.,eastern bituminous coal). The commenter states that chloride concentrations are much lower in sub-bituminous coals than in bituminous coals yet there is no distinction between the two fuels in the proposed rule. The commenter asserts that a target reduction percentage, say 80 percent, from a low starting concentration is a significantly harder and Hg concentrations tend to be lower in sub-bituminous when compared to bituminous coals it is more difficult to remove because of the lower chlorine content. The commenter states that these widely varying constituent concentrations imply that a separate set of limits and controls should apply to each and that these two coal classes should be a basis for sub-categorization.
Commenter 17820 states that similar issues prevail for acid gases as well. The commenter asserts that as noted earlier, the difficulty and cost associated with removing acid gases from higher chlorine coals (such as eastern bituminous) as compared to lower chlorine (PRB coal). According to the commenter, therefore, a separate set of limits and controls should apply to bituminous and sub-bituminous coals for acid gases.
Response to Comments 10 - 15: We do not agree with the commenters' assertions concerning subcategorization for the reasons set forth above in this document and in the preamble to the proposed and final rules. In addition, we note that although the commenters make recommendations for subcategories, the commenters do not provide facts, data, or analysis to support the claims that units combusting different coals ranks will be unable to meet the standards in this final rule, and the comments of different commenters are often virtually identical, including being identical in the lack of any support for their claims. We question the bases for the claims in the comments and believe the data support our subcategorization decisions in the final rule.

The EPA's response to comments related to the establishment of standards under CAA section 112(d)(4) are set forth elsewhere in the final rule and this response to comments document.
iii. The EPA has already subcategorized based on coal rank (lignite).
Comment 16: Commenter 17739 states that in the EPA's response to inter-Agency comments during OMB's review, the EPA was asked about whether it had considered subcategories based on coal rank. Commenter states that the EPA replied: "It is the Agency's policy that the rank of coal being used (or other material input) not be the basis for subcategorization." Commenter believes that this declaration is inconsistent with the EPA's stated approach to subcategorization made in the December 2000 finding, where the EPA declared: "In developing standards under CAA section 112 (d) to date, the EPA has based subcategorization on considerations such as: the size of the facility; the type of fuel used at the facility; and the plant type."
Commenter 17739 states that although they do not believe announcement of an Agency policy suffices to explain why the EPA has not exercised the discretion that statute undoubtedly confers upon the EPA to subcategorize on the basis of coal rank, to the extent the data support such a decision, Commenter also notes that the EPA has already crossed that bridge because it has issued a Hg subcategory for lignite in its proposal. The commenter asserts that this is so, even though the EPA attempts to masquerade the lignite subcategory as a boiler size/energy content subcategory. According to the commenter, we note that the EPA is proposing a Hg subcategory for lignite coals that in essence turns on the high amount of Hg in those coals. The commenter asserts that the mean Hg content of lignite coals is substantially higher than that of other coal ranks. The commenter states that the EPA decided to establish a Hg subcategory for lignite fuels, based on their heat input (< 8,300 Btu/lb) and the boiler size (height-to-depth ratio of 3.82 or greater) "because Hg emissions are different" than from other types of units. The commenter states that the EPA further opined that "any basis for subcategorizing (e.g., type of unit) must be related to an effect on emissions." According to the commenter, however, there is no evidence that the size of the boiler or the heat content of the fuel (< 8,300 Btu/lb) has anything to do with poorer performance of lignite units, and the EPA offers none. The commenter asserts that rather, the only relevant "effect on emissions" of this subcategory stems from the Hg coal rank characteristics of lignite. The commenter asserts that the fact that lignite boilers are "larger" has not been shown by the EPA or anyone else to have a relevant impact on Hg emissions. According to the commenter, consequently, although the EPA did not describe or call this subcategory one based on coal rank, it is in fact one based on coal rank, and can only be justified, from the key "effect on emissions" criterion, as one based on coal rank.
Comment 17: Commenter 17912 states that the EPA has no basis to conclude that any source burning any coal or liquid fuel can meet all of the individual emission limits that it has proposed in the EGU MACT. According to the commenter, although the EPA believes that prior court decisions may limit its ability to make distinctions based upon differences in fuel-borne HAP, unlike the Brick MACT decision, the CAA distinguished EGUs from other sources of HAP emissions. See 42 U.S.C § 7412(n). The commenter states that consequently, the EPA should consider the differences between fuel-borne HAP because the Agency has already distinguished certain solid fuels on the basis of their Btu content, which necessarily results in other regulatory distinctions.
Response to Comments 16 and 17: The EPA disagrees with the commenters. Notwithstanding the unattributed statements of an EPA employee, the EPA does not have a policy against subcategorization based on input materials, but the EPA still maintains that such a difference without a difference in emissions characteristics argues against subcategorization. Furthermore, the EPA did not establish subcategories in the 2000 Finding, instead we simply noted what the Agency could consider when establishing subcategories, and, in that notice, we do not specifically discuss coal rank and could have easily been considering a distinction between coal, oil, and natural gas. We also disagree with the commenter that suggests that the EPA has no basis to conclude that existing sources are able to meet the existing source standards. We have identified approximately 69 EGUs that, based on the data available, comply with all the existing-source standards (i.e., Hg, PM, and HCl) and among those sources are both PC and FBC EGUs, and EGUs burning bituminous, subbituminous, lignite, and coal refuse.

The EPA provides its response to comments related to lignite coal elsewhere in this document. In addition, the EPA has clarified the subcategory definitions in the final rule as explained in the preamble to the final rule
iv. Subcategorization by coal rank will improve the achievability of emission limits.
Comment 18: Commenter 17623 encourages the EPA to develop certain additional subcategories in the final Utility MACT to adequately reflect the diverse population of regulated sources. Commenter states that historical testing has shown that coal rank has a significant effect on Hg and HCl emissions. The commenter asserts that therefore, given that the EPA has wide latitude in the subcategories that can be created in a MACT standard and the impact coal rank can have on HAP emissions such as Hg and HCl, the EPA should consider developing more subcategories in the final Utility MACT if they can improve the achievability of the emission limits.
Comment 19: Commenter 17736 asserts that contributing to MACT standards that will be difficult, if not impossible, to achieve is EPA's failure to recognize the need for, and propriety of, additional subcategories. Specifically, the Commenter suggests providing subcategories based on coal rank in order to establish more realistic MACT standards and feasible compliance options. According to the commenter, the technology selection and design of a coal-based EGU is driven by the characteristics of the coal supply. The commenter asserts that although the EPA recognized the operational variances among unit designs and acknowledged that "the amount of fuel-born HAP is primarily dependent on fuel composition," the Agency rejected a coal-rank subcategory without explanation. The commenter states that coal is not a homogenous substance and the concentration of constituents, particularly Hg and HCl, can vary dramatically from region to region. The commenter states that proposing such stringent emissions limitations in the Utility MACT indicates an assumption that low sulfur coal is (or will be) burned. The commenter states that however, low sulfur coal is not compatible with wet-bottom units. The commenter asserts that as such, not one of Ohio Valley Electric Corporation's Kyger Creek units- all available emissions controls being installed- will be able to achieve the emissions limits under the proposed rule. According to the commenter, the EPA has recognized that complete structural re-construction is not a viable option. The commenter asserts that therefore, the EPA should establish an additional subcategory based on coal rank or, in the alternative, propose health based standards.
Comment 20: Commenter 17761 states that at a minimum the EPA should provide for additional subcategories to include a subcategory based on coal rank (bituminous, sub-bituminous, lignite) or general coal characteristics. The commenter states that both PRB (sub-bituminous) and lignite coals have very low chlorine content resulting in primarily elemental Hg which is inherently difficult to effectively control even with a full suite of pollution control equipment (including ACI). According to the commenter, as such, in a final rule, the EPA should provide for higher Hg emissions limits for a new subcategory of sub-bituminous and other low chlorine coals.
Comment 21: Commenter 17774 strongly recommends that the EPA develop additional subcategories in the final Utility MACT to adequately reflect the diverse population of regulated sources, including subcategories potentially based on fuel type. Specifically, Commenter recommends that the EPA further consider differences in coal rank. According to the commenter, by establishing additional subcategories and recognizing the inherent differences in types of EGU units, the EPA could provide more achievable standards for some units, reduce the number of expected plant closures, and still significantly reduce emissions from this source category. The commenter asserts that information gathered for the first proposed Utility MACT showed that coal rank can have a significant effect on Hg and HCl emissions. According to the commenter, because the EPA has wide latitude to create subcategories of sources for a given MACT standard and coal rank can have major implications on Hg and HCl emissions, the EPA should further consider whether coal rank subcategories in the final Utility MACT could result in more achievable standards. The commenter states that additional subcategories could better enable facilities to meet emission limits and avoid plant shut-downs that could greatly impact electric reliability.
Comment 22: Commenter 18424 states that the EPA can remedy these potential issues by establishing MACT limits that contain distinct categories and limits for bituminous and sub-bituminous coal-burning EGUs. The commenter states that separate categories would enable the EPA to utilize a different data set for establishing a MACT floor for units burning bituminous coals, and thus present an opportunity to establish MACT limits that may be more achievable.
Comment 23: Commenter 18429 states that the MACT should subcategorize by coal rank. In particular for Hg control, the level of achievable control is highly dependent on chlorine content which varies greatly by coal rank and source.
Comment 24: Commenter 17807 requests that the EPA develop a subcategory of emission units based on coal type to accommodate varying emission rates attributable to typical components of specific coal types impacting levels of HAP emissions. According to the commenter, recent stack testing shows compliance with the proposed HCl limit will be difficult to achieve. The commenter states that Big Bend Station is designed to operate on bituminous eastern Illinois Basin coals. The commenter asserts that these coals are generally higher in chloride concentrations and tend to have higher HCl emissions. Other coal blends such as PRB, Appalachian, and Lignite coals are lower in chloride concentration, but the Big Bend Power Station is not designed to operate with these coals. According to the commenter, for example, PRB coals have lower sulfur content but the lower ash resistivities will cause operating problems with ESPs. The commenter asserts that similarly, the lower coal fusion temperatures cause slagging and reduced boiler efficiencies. The commenter states that the lower heating value will require more coal to produce roughly the same power output. According to the commenter, ppalachian coals will not cause ESP operating problems, but the fusion temperatures do not make this coal blend a viable option. The commenter asserts that consequently, PRB and many Appalachian coal blends are not practicable for Big Bend Power Station.
Response to Comments 18 - 24: The EPA does not agree with the commenters that additional subcategories are appropriate, and we explain our reasons for that conclusion and address many of these comments in responses above. The EPA specifically disagrees with the commenter that stated that the EPA assumes low sulfur coals will be burned. Units with higher chlorine content coal may have to employ different control strategies to comply with the acid gas HAP standard, and sources with high sulfur content coal may not be able to utilize the alternative equivalent SO2 standard that the EPA has included in the final rule. Coal blending would be one means, but not the only means, of achieving the standards (and, based on the 2010 ICR data, the Kyger Creek units noted by commenter are firing a blend of bituminous and subbituminous coals). The EPA agrees that the level of chlorine in the coal is a factor in Hg control. However, there are other means of adjusting the chlorine content; the EPA has information that indicates that such means (e.g., spraying a halogen such as chlorine or bromine on the coal as it is fed to the EGU) were employed by an unknown number of EGUs during the period of time they were testing to provide data in compliance with the 2010 ICR (see docket entry EPA-HQ-OAR-2009-0234-2067). Thus, we believe that the performance of such means is reflected in the MACT floor analysis.

As noted elsewhere in this document, the EPA is not establishing a health-based emission limit for acid gas in the final rule, as we do not have sufficient data to support such a standard for HCl and we have even less information on the other acid gases (e.g., HF, HCN, and SeO2).
v. Other support for further subcategorization by coal rank.
Comment 25: Commenter 17818 is of the opinion that the EPA should consider changes to the subcategorization of coal-fired units. According to the commenter, review of data in the docket (MACT Floor Analysis-Coal HG- Revised) appears to indicate that there are noticeable differences (nearly an order of magnitude in some instances) in measured Hg emissions between the three noted coal categories (bituminous, sub-bituminous, and lignite) for EGUs of similar control figurations. It is Commenter's opinion that it would be appropriate to establish emissions limitations based upon the coal fuel rank or type (bituminous, sub-bituminous, and lignite) without regard to furnace sizing or height-to-depth ratio. The commenter asserts that review of coal analysis data in the docket that was submitted as part of the ICR also seems to indicate that it would be appropriate to also consider separate limits and considerations for bituminous, sub-bituminous and lignite coals for other HAP as well.
Comment 26: Commenter 17912 states that subcategorization of coal units is insufficient. In the current proposal, the only subcategories for coal-fired units are between those units that burn lignite and those that burn all other types of coal. Commenter urges the EPA to provide for additional subcategories within the standard. According to the commenter, for example, for non-Hg metal HAP, the U.S. Geologic Survey's COALQUAL data base provides ranges of metals found in various coal types or ranks. The commenter states that not all metals are present in all coal types or ranks in equal concentrations. The commenter asserts that moreover, when the EPA set its proposed emission limits for these pollutants from new coal-fired units, it selected the lowest reported emitting unit for each non-Hg metal. The commenter states that the problem inherent in this approach is that the test data used to identify the alleged best-performing similar source was only burning one type coal during the few hours of the tests required for by the ICR. The commenter states that that coal may or may not have had concentrations of non-Hg metals similar to the concentrations found in other coals or even for coals of the same type but mined from another seam. The commenter asserts that the metal concentrations may not even represent the same values that might be measured from the same mine the next week. According to the commenter, when setting standards for new units on the basis of a single best-performing unit as the EPA has chosen to do here, the variability of the concentrations of non-Hg metals in the fuel can and will affect the results of the test. The commenter asserts that for Hg the EPA selected the Nucla plant, which only gets its coal from a single, nearby mine.
Comment 27: Commenter 18034 states that subcategorization is only done for coal units for the purposes of the mercury emissions limit. According to the commenter, however, the EPA's proposal preamble acknowledges that coal type and unit design affect emissions performance of some of the other HAP being regulated by the proposal. The commenter asserts that subcategorization for coal-fired EGUs should be extended to other pollutants. According to the commenter, the EPA's own data indicates that further subcategorization of coal-fired EGUs is warranted. The commenter states that the speciated non-mercury metal HAP limits are derived from multiple coal-fired EGUs with different designs and fuel types. The commenter asserts that in the case of the new unit non-mercury metal HAP limits, no unit used to establish the non-mercury metal HAP emission limit profile actually meets all the limits. The commenter states that this indicates that deriving emission limits across designs and fuel types is questionable and the EPA must consider further subcategorization. According to the commenter, the EPA acknowledges that there is variability in some non-mercury HAP (e.g., selenium), yet the EPA decided not to subcategorize the non-mercury metal HAP without any clear justification for this decision (76 FR 25038). This decision is arbitrary and capricious.
Comment 28: Commenter 18034 suggests that a specific subcategory for subbituminous coal-fired EGUs should be established with different emission limits for all the targeted pollutants. According to the commenter, the EPA should have developed emission standards for the subcategory of subbituminous coal based upon the data the EPA used to establish emission standards. The commenter states that for example, of the lowest emitting 40 existing coal-fired power plants used to identify the floor for Hg in the category of greater than or equal to 8,300 Btu/lb, only three of those units burned subbituminous coal. The commenter asserts that the highest ranking of the top three subbituminous units in the top 40, was 28th overall.
Comment 29: Commenter 19041 states that the EPA should allow for more subcategorization of units for different boiler types and associated coal rank, and separate emission limitations for these additional subcategories should be promulgated. The commenter states that these subcategories should allow for coal blending and additional types of coal use beyond the two simple categories that the EPA has proposed, i.e.,coal-fired unit designed for coal greater than or equal to 8,300 Btu/lb coal, and coal-fired unit designed for coal less than 8,300 Btu/lb coal. According to the commenter, there is much more variability in the industry with respect to boiler design and coal use than the two categories proposed by the EPA.
Commenter 17761 states that there is significant variability in Hg content of coal, Cl content of coal, and measured Hg emissions, which affects the emission levels. Commenter 17761 provides example data showing from November to December 2007, the Hg content of coal ranged from 0.055 to 0.319 ppmd, and the Cl content of coal ranged from less than 1 to 461 ppm. Commenter 17761 states that the variability of Hg and Cl content of fuel directly affects the variability of Hg emissions. Commenter 17761 states that there are likely unintended consequences resulting from control devices for SO2 and NOx that adversely affect performance of Hg control devices.
Commenter 17901 stated that the Proposed Utility MACT is structured to punish coals with higher sulfur and heat contents, like the bituminous coal mined in Ohio. According to the commenter, instead of structuring both the MACT and NSPS requirements in a manner that recognizes the regional characteristics of coal and that there is no "top coal" from an emissions perspective, EPA has chosen to make bituminous coal the clear loser by skewing the limits towards fuel switching to western coals and natural gas. Commenter 17901 states his disappointment that the proposed rule is biased against the coal burning EGUs, particularly from Midwestern and eastern mining states. According to the commenter, the EPA's proposed utility MACT sets limits based on heat content, with 8,300 Btu/lb serving as the dividing line between high and low heat coals. The commenter states that the EPA is proposing more stringent regulations for high heat content coal which is mined traditionally from the eastern U.S.
Response to Comments 25 - 29: The EPA disagrees with the commenters and many of these comments are addressed above. Concerning one commenter's assertion that the new source standards for non-Hg metal HAP are flawed because of the variability of the metals in the coal, we disagree and note that commenter has provided no alternative approach for establishing the new-source MACT standards. The EPA is required by the statute to establish the standards based on the information available to the Agency. Taken to its logical conclusion, the commenter's statement would require the EPA to establish new-source MACT standards for every mine in the country and possibly even varying standards for the same mine because the commenter maintains that the same coal may have very different HAP metal content from one day to the next. The EPA thinks that approach is unreasonable and we reject it. We apply a variability factor to the MACT floor limits to account for fuel input variability in addition to other variability and we believe the final standards are achievable.

The EPA also disagrees that we acted arbitrarily by declining to further subcategorize because there is variability in the HAP content of coal. We believe it is the emissions to the air that matter and the data available indicate that, with the exception of Hg, the emissions to the atmosphere are similar for all types of EGUs burning all types of coal. It is reasonable to reject additional subcategories under these circumstances. We have identified approximately 69 EGUs that, based on the data available, comply with all the existing-source standards (i.e., Hg, PM, and HCl) and among those sources are both PC and FBC EGUs, and EGUs burning bituminous, subbituminous, lignite, and coal refuse. Further, although commenter may be correct in stating that there are few subbituminous-fired EGUs in the MACT floor pool for Hg, based on the data available, there are approximately 36 subbituminous-fired EGUs meeting the final Hg limits (which include variability considerations) and approximately 16 EGUs that report using a bituminous/subbituminous coal blend. Therefore, we conclude that no further subcategorization is necessary as all coal ranks are able to achieve the limits.
b. Opposition to further subcategorization by coal rank.
Several Commenters (17402, 17620, 17648, 17873) oppose further subcategorization by coal rank.
Comment 30: Commenter 17620 is opposed to any further subcategorization based on coal rank. According to the commenter, since many sources blend several ranks of coal on a regular basis, establishing coal rank subcategories would create numerous opportunities for sources to game the regulations and substantially increase emissions. The commenter states that there is no need for such an approach since modern pollution controls can accommodate a wide range of coals.
Comment 31: Commenter 17648 states that the EPA's decision not to subcategorize further based upon coal rank is correct. Commenter states that some have argued that the EPA should subcategorize coal-fired EGUs for purposes of setting MACT standards under CAA section 112(d) based upon coal rank, including distinguishing bituminous coal-fired EGUs from subbituminous coal-fired EGUs, and distinguishing among coal-fired EGUs firing Fort Union lignite, Gulf Coast lignite, and other coal ranks. Commenter believes that none of these proposed subcategory distinctions are appropriate. Commenter states that the EPA lacks any basis on which to set different emission limitations for sources based upon the type of solid fuel that they are firing.
Commenter 17648 states that subcategories are warranted only where differences between sources lead to differences in the nature of emissions and the technical feasibility of applying emission control techniques. According to the commenter, where a technical difference between units has no effect on emissions performance, there is no basis for subcategorizing. The commenter states that EGUs firing different ranks of coal are not fundamentally different in size, class, or type in a way that impacts emissions or that limits the availability of controls. The commenter asserts that emissions of fuel-dependent HAP can be controlled by either changing the fuel prior to combustion or by removing the HAP from the flue gas after combustion. According to the commenter, ACI systems, DSI controls, and PM controls are available for installation at units firing subbituminous coal and are equally available for units firing bituminous, anthracite, or lignite coal. As long as a control option is commercially available, that it may be costly for a particular unit is irrelevant to the EPA's development of emission standards based on MACT.
Commenter 17648 states that subcategories based on coal rank would make a meaningful consideration of fuel switching impossible, contrary to the judicial mandate to consider substitution of materials in setting the floor and the statutory mandate to consider substitution of materials in the beyond-the-floor analysis. The commenter states that if subcategories are based on coal type, the HAP levels of the fuel source would dictate the subcategories chosen and thus would preclude the EPA from considering fuel switching as control technology. According to the commenter, the practical effect of such a subcategorization scheme would be the same as if the EPA had created subcategories based on plants already equipped with a particular add-on control technology, an approach rejected by courts. The commenter states that because material substitution (i.e., coal switching) is to be considered as a control technology in the same manner as scrubbers and baghouses, coal rank cannot serve as a basis for subcategorization.
Commenter 17648 states, moreover, the best-performing coal-fired EGUs for many HAP include units firing all of these different coal ranks. The commenter asserts that sources that achieve the proposed emissions limitations for Hg, PM, or HCl do so by employing different control technologies, which often reflect differences in the type of fuel combusted. The commenter asserts that thus, even if the EPA has authority to subcategorize based upon coal rank, there is no reasonable basis for the EPA to conclude that EGUs firing different types of coal have meaningful physical differences that manifest in different emissions performance that cannot be controlled with available control technologies.
Commenter 17648 states that in the proposed Toxics Rule, the EPA appropriately identified the best-performing 12 percent of units by ranking EGUs according to each unit's emissions. According to the commenter, this approach ensures that sources that may achieve emission reductions by using fuels with low HAP content are not excluded from consideration in setting MACT floors. The commenter states that the EPA also implicitly recognized that subcategorization based upon coal rank is inappropriate when it rejected the use of percent reduction standards for fuel-dependent HAP. The commenter states that percent reduction standards would not account for practices such as fuel-switching that reduce the HAP content of fuel before firing.
Comment 32: Commenter 17402 states that although they previously supported the subcategorization of coal-fired units on the basis of coal rank, it no longer objects to grouping units that burn bituminous and subbituminous coals in a single category because the prior basis for subcategorization no longer exists. The commenter states that at the time of the prior rule, it was widely recognized that Although coal-fired units combusting bituminous coal, with its higher concentration of chlorine and therefore ionic Hg, could effectively limit Hg emissions by utilizing existing control technologies such as scrubbers, units burning subbituminous coal could not do so with the same controls because of the coal's higher levels of elemental Hg. The commenter asserts that activated carbon was only a fledgling and unproven technology at the time; today, however, activated carbon has been proven, and units burning bituminous and subbituminous coal can achieve the same levels of emissions for Hg and other HAP. According to the commenter, consequently, the prior basis for subcategorization no longer exists. Commenter therefore agrees that coal-fired units burning bituminous and subbituminous coals ought to be grouped in a single category.
Comment 33: Commenter 17873 states that further subcategorization is not necessary or appropriate. Commenter does not view further subcategorization of coals for acid gas regulatory purposes as necessary and believes that, with the exception of the lignite facilities already placed in a separate subcategory, all facilities can and should meet the same standard whether using a bituminous or subbituminous fuel. According to the commenter, the creation of a single category for both fuel types assures that EGU owners have many different options for compliance, including retrofit with controls, fuel switching or a combination thereof. The commenter states that it also assures that higher emitting EGUs (the source of the greater potential environmental impact) bear an appropriately greater burden of emission reductions under the EGU MACT.
Response to Comments 30 - 33: The EPA has not established additional subcategories for coal-fired EGUs in the final rule. We disagree with the commenter that the EPA is precluded from subcategorization based on material inputs just because material substitution is a viable control option in certain circumstances. Even if we determined that multiple subcategories were available based on material inputs, sources might still choose to comply by switching materials to comply with the standard applicable to the given subcategory. We do not agree that subcategorization by material input and material substitution as a compliance alternative are mutually exclusive as one commenter suggests.
The EPA agrees with the commenters that there is no basis to subcategorize bituminous and subbituminous coal because the emissions characteristics are similar and units burning both types of coal are currently meeting all of the existing source standards and all EGUs will be able to comply with the final standards through a combination of controls and other practices (e.g., coal washing).
6. The EPA should establish a subcategory for non-continental coal units.
Comment 34: Commenter 18539 supports the establishment a subcategory for non-continental coal-fired units. According to the commenter, due to natural gas alternative not being available in HI and Puerto Rico, these sites have less opportunity to rely on gas repowering/co-firing as the continental U.S. has. The commenter states that this geographic competitive disadvantage should be rectified with a subcategory for these units.
Response to Comment 34: The EPA does not believe that establishing a non-continental subcategory for coal-fired EGUs is warranted or appropriate because some non-continental EGUs are in the MACT floor pool for some HAP (e.g., two EGUs in HI in the Hg and PM MACT floor pool; two EGUs in Puerto Rico in the HCl MACT floor pool), indicating an ability to achieve the limits in the final rule. Thus, we do not believe that they will need to rely on any form of fuel switching to achieve the final limits. In addition to evidence that some non-continental EGUs already are capable of complying with the rule, non-continental coal units are not limited in their access to different quality fuels, and there is no showing that available control etchnology cannot assure performance at or below the emission levels specified in the final rule.3B - Subcategorization: Applicability: Coal (<8,300 Btu/lb)
Commenters: 12991, 16122, 17620, 17722, 17725, 17758, 17775, 17813, 17815, 17818, 17820, 17843, 17846, 17870, 17904, 17925, 17927, 17930, 18039, 18425, 18426, 18487, 18785, 19040, 19205, 19595, 19536/19537/19538, 18932
1. Support for the subcategory.
a. General support.
Comment 1: Several Commenters (17722, 17725, 17758, 17775, 17815, 17820, 17870, 18450) support the EPA's decision to create a separate subcategory for units burning coal with a heating content of less than 8,300 Btu/lb. According to the commenters, boilers designed to burn these coals (typically lignite) are significantly different than plants designed to burn coals with higher heat contents. The commenters states that these coals are also different in composition than other coal types.
Comment 2: Commenter 18450 supports the EPA's proposed subcategories for coal fired EGUs. According to the commenter, the EPA has proposed two basic subcategories for coal-fired EGUs: (l) EGUs designed for coal >8,300 Btu/lb, and (2) EGUs designed for coal <8,300 Btu/lb. The commenter states that the results of the EPA's ICR clearly justify the creation of only two subcategories.
b. Emissions are different.
Comment 3: Commenter 17904 strongly supports subcategorization for lignite units. According to the commenter, the EPA is correct that there is a difference in the emissions for this HAP from lignite-burning units, and Commenter commends the EPA for recognizing the propriety of creating this subcategory in order to recognize that difference and also to preserve for consumers the viability of this low-cost fuel source that provides much of the power that serves Texans. According to the commenter, section 112(c)(1) of the CAA authorizes the EPA to establish a list of all categories and subcategories of major sources, "as appropriate," and section 112(d)(1) provides that the EPA "may distinguish among classes, types, and sizes of sources within a category or subcategory in establishing" MACT standards. The commenter asserts that under this authority, the EPA has appropriately proposed a separate MACT standard for the "class" or "type" of boilers firing fuel with a heat content of less than 8,300 Btu/lb, i.e., lignite. According to the commenter, the EPA explains in the proposal that "[n]ormally, any basis for subcategorizing (e.g., type of unit) must be related to an effect on emissions, rather than some difference which does not affect emissions performance." The commenter states that the EPA concludes that "[f]or Hg emissions from coal-fired units, we have determined that different emission limits for the two subcategories are warranted," noting that "[t]here were no EGUs designed to burn a nonagglomerating virgin coal having a calorific value [of 8,300 Btu/lb] or less in an EGU with a height-to-depth ratio of 3.82 or greater among the top performing 12 percent of sources for Hg emissions, indicating a difference in the emissions for this HAP from these types of units."
Comment 4: Commenter 17930 states that it is clear that a subcategory for units designed to burn coal with a heat-input of less than 8,300 Btu/lb ("< 8,300 coal units" or "Subcategory 2 Units") is necessary; the EPA found none of the Subcategory 2 units in the overall top performing 12 percent of sources for Hg emissions.
c. Plant design and operation are different.
Comment 5: Commenter 17725 supports EPA's proposal to subcategorize low rank coal units, in part, to account for the significant impact low rank coal can have on overall plant design and the operation of pollution control equipment. According to the commenter, low rank coal, especially lignite, is substantially different from other coals and an important cost effective domestic fuel source.
Comment 6: Commenters 17930 and 18785 state that units designed to burn coal with a heat-input of less than 8,300 Btu/lb generally include the types of units that are designed to burn lignite. According to the commenters, these units are distinct from others based on the amount, type, and variability of mercury and other HAP/non-HAP content in their fuel. The commenters state that lignite burning units are substantially different in design, particularly in that they are much larger than non-lignite units, which supports the category's "designed to burn" requirement. The commenters assert that by structuring the subcategory to apply to units designed to burn <8,300 coal, it also avoids the unintended consequence of preventing the class of units that co-fire alternative fuels such as biomass, and other environmentally beneficial materials, from burning those materials in their boilers as supplements to their primarily lignite fuel.
Response to Comments 1 - 6: The EPA agrees that the proposed subcategory was reasonable. Partly based on comments received, the EPA has modified the definition for this subcategory in the final rule as explained in the preamble to the final rule.
2. Opposition to the subcategory.
Several Commenters (16122, 17620, 17818, 17843, 17846, 18039, 18421, 18425, 18426, 18487, 19205, 19595, 19536/19537/19538, 18932) oppose a separate subcategory for units burning coal with a heating content of less than 8,300 Btu/lb.
a. The record does not support the subcategory.
Comment 7: Several commenters (19536, 19537, 19538) states that the EPA's coal subcategories for existing sources are not adequately justified on the record, which shows instead that they are created to preserve poor performance and benefit and prolong the burning of low-Btu "junk" coals. According to the commenters, the EPA asserts that all of the five subcategories it creates are in fact based on the combustion technology in use at facilities burning different kinds of fuels. According to the commenters, this may justify the EPA's decision to distinguish units burning liquid fuels from units burning solid fuels, and IGCC units from those utilizing other methods of coal combustion. The commenters state that it does not, however, permit the EPA's distinction between units burning coals above and below 8300 Btu/lb. The commenters assert that although the EPA implies that its proposed Btu content-based coal subcategories are not merely set to give advantage to, or allow continued burning of low-Btu "junk coals" at new facilities, the data and the technologies for burning different coal ranks suggest otherwise. The commenters state that so does the agency's rationale: that "a distinguishable difference in [emissions] performance exists based on ... coal-fired units designed to burn coal with greater than or equal to 8,300 Btu/lb (for Hg emissions only); [and] coal-fired units designed to burn coal with less than 8,300 Btu/lb (for Hg emissions only)." 76 FR 25037.
Commenters (19536, 19537, 19538) states that the EPA's selection of the 8,300 Btu/lb heating value to subdivide the coal category is not discussed or justified in the record. According to the commenters, the EPA provides no record evidence to show that sources using fuels above and below this heating value are of a different class, type or size and, indeed, does not even claim they are. The commenters assert that in particular, the EPA has not provided a clear technical basis for its apparent conclusion that units burning coals below this heating value are of different design, or that the difference in design affects the method of pollution reduction available to such units. The commenters assert that the EPA provides no technical basis that these units have different fuel handling, burner or combustion systems. The commenters state that in fact, units burning lignite coals can burn other types of coals. The commenters assert that for example units in Texas and North Dakota (where most of these lignite burning units are located) can also burn PRB subbituminous coals as well for fuel diversity. According to the commenters, physical systems for coal handling, burners, and combustion systems are the same when either fuel is burned. According to the commenters, the controls that may be used for minimizing Hg emissions, such as ACI, baghouses, and scrubbers, can all be used on units that can burn either type of coal  -  regardless of heating value.
Commenters (19536, 19537, 19538) states that the sparse record underlying the agency's rationale for the junk coal subcategory suggests that the two coal subcategories are intended to preserve the ability to burn high-Hg coals, rather than truly distinguish sources based upon their "class, type, and size." According to the commenters, this is unlawful, as well as arbitrary, and defeats the CAA's directive to set standards that ensure that all sources will match the emission levels achieved by the best performers. The commenters assert that 2 U.S.C. § 7412(d)(3). The commenters state that the EPA therefore has not sufficiently justified its subcategory based on coals with less than 8300 Btu/lb heat input.
Commenters (19536, 19537, 19538) state that the EPA has not justified its decision to subcategorize the Hg MACT determinations for the group of coal-fired EGUs designed for coal with heat value less than 8300 Btu/lb. According to the commenters, the boundaries of the category are themselves poorly defined; the EPA provides no design characteristics to separate these plants from others merely capable (but not designed for) burning such low heat-value coals. The commenters assert that even if such a subcategory were justified, however, the EPA has not properly supported its proposed standard for such units.
Comment 8: Commenter 18932 states that the proposed rule improperly establishes a subcategory for low-Btu fuels. Commenter states that the EPA has proposed to establish two subcategories of coal-fired EGUs -- assigning drastically different Hg emission limits to each -- without providing a rational basis for doing so. According to the commenter, as proposed, the Utility Air Toxics Rule would distinguish the two subcategories based on (1) the heat value of the coal that the unit is designed to burn, and (2) the height-to-depth ratio of the unit. The commenter asserts that specifically, the EPA has proposed to establish one subcategory of EGUs that are "designed to burn a coal having a calorific value (moist, mineral matter-free basis) of greater than or equal to 19,305 kilojoules per kilogram (kJ/kg) (8,300 British thermal units per pound (Btu/lb)) in an EGU with a height-to-depth ratio of less than 3.82" (High-Btu Units).