Commenter 18932 states that based solely on these distinguishing characteristics, the Agency has assigned to the low-Btu units Hg emission limits that are several orders of magnitude less stringent than the emission limits assigned to the high-Btu units. According to the commenter, the EPA has not provided a rational basis or reason for this distinction. The commenter asserts that he proposed approach lacks a sound technical basis and, due to the profound difference in the stringency of the Hg emission limits assigned to the two subcategories, it provides a strong incentive for sources to design, or merely attempt to characterize, their EGUs as low-Btu units in order to skirt the more highly protective standards that apply to high-Btu units.
Commenter 18932 states though the EPA may distinguish between sizes of sources within a category or subcategory, the record does not support the Agency's proposal to establish dramatically different Hg emission limits based on whether EGUs are designed to burn coal that has a heat value of less than or greater than 8,300 Btu/lb. Commenter states that there is no indication in the record that these units have inherently different combustion systems; there is no evidence that these units cannot use the same types of post-combustion mercury pollution controls, or that those controls differ in Hg control effectiveness. Commenter states that in fact, it appears that the EPA is attempting to establish a subcategory based on coal rank for lignite coal, which is improper. Commenter adds that based on the Hg emissions data compiled as part of this rulemaking, the record shows that the best-performing low-Btu units have achieved levels of Hg emission control that fall within the range of the best-performing high-Btu units. Commenter asserts, thus, based on the data in the record, there is no basis for establishing different Hg emission limits for units based on coal heating value.
Comment 9: Commenters 16122 and 17846 assert that the EPA's subcategorization for coal-fired EGUs lacks support and creates improper incentives for EGUs to burn dirtier, less-efficient coals. Commenters state that CAA section 112(d)(l) allows the EPA to "distinguish among classes, types, and sizes of sources within a category or subcategory in establishing [MACT] standards" (referred to as subcategorization). According to the commenters, based on the statutory language, the EPA clearly has a choice as to whether to subcategorize sources when developing MACT standards. The commenters assert that however, where the EPA chooses to subcategorize, its decision must be supported with a reasoned justification. The commenter states that the EPA has found that subcategorization is justified when "different types of units within a category have different emission characteristics which affect the technical feasibility and effectiveness of applying emission control."
Commenters 16122 and 17846 state that the EPA's subcategorization scheme lacks support. Commenters state that the EPA's preamble and supporting memoranda provide little justification for the EPA's decision to set a separate standard for units designed to burn lignite coal. Commenters state that the EPA's only support for its subcategorization scheme is that "[t]here were no EGUs designed to burn [lignite coal] among the top performing 12 percent of sources for Hg emissions [and] . . . [t]he boiler of a coal-fired EGU designed to burn [lignite] is bigger than a boiler designed to burn [subbituminous and bituminous coal]." Commenters note, however, the EPA provides no evidence that EGUs designed to burn lignite coal have different emission characteristics that affect the technical feasibility and effectiveness of emission control. Commenters assert that the EPA should remove from the EGU MACT Rule any subcategorization between lignite and non-lignite units.
Comment 10: Commenter 18421 states that the EPA erred in its decision basis that no lignite-burning facilities included in top 12 percent warrants a separate subcategory.
Comment 11: Commenter 18426 states that in Michigan, many existing units have switched from bituminous coal to subbituminous coal combustion or a blend of both types of coals. According to the commenter, with the right combination of emission controls, the proposed Hg emission limit of 1.0 lb/TBtu or 0.0081b/GWh is achievable by existing Michigan units. The commenter asserts that due to the Clean Air Interstate Rule (CAIR) and the Cross-State Air Pollution Rule (CSAPR) which replaces CAIR, the addition of fabric filter bag houses (which would support ACI), SCRs, and wet and/or dry FGD systems is under way on many Michigan units and can be used to meet the proposed Hg emission limit. According to the commenter, however, the proposed Hg emission limit of 0.040 lb/GWh for coal-fired units designed to burn coal with a heat content of less than 8,300 Btu/lb and with a height-to-depth ratio of 3.82 or greater is too high when the 0.008 lb/GWh is achievable by existing units with additional and Hg specific controls. The commenter states that to demonstrate the impact of keeping the 0.040 lb/GWh Hg emission limit, the following example is presented. The commenter asserts that an 800 MW unit subject to the proposed Hg emission limit of 0.040 lb/GWh would be allowed to emit up to 280 pounds per year of Hg. According to the commenter, a similar sized unit operating under the proposed Hg emission limit of 0.008 lb/GWh, would have potential Hg emissions of 56 pounds per year of Hg. The commenter states that therefore, the subcategory for coal-fired units designed to burn coal with less than 8,300 Btu/lb and with a height-to-depth ratio of 3.82 or greater needs to be eliminated as it creates an unequal bias for low rank coals, is not protective of public health, and technology exists and is in use on existing units which does not justify the subcategorization. Commenter recommends just one general subcategory of coal-fired units.
Comment 12: Commenter 17818 does not support the EPA's definition [of coal-fired EGUs of more and less than 8,300 BTU/lb] as proposed. According to the commenter, in the proposal, the EPA appears to be drawing a distinction between steam generators combusting bituminous and/or subbituminous coals with those steam generators combusting lignite coals.
Comment 13: Commenter 19205 strongly urges the EPA to strengthen standards to protect public health and our environment by requiring lignite burning facilities to control Hg emissions.
Comment 14: Commenter 19595 states that although the EPA has taken an important step toward protecting public health by drafting these rules, the rules have some major deficiencies in how they protect public health. According to the commenter, the current draft rules virtually exempt lignite coal facilities from controlling Hg emissions. The commenter states that these dirty facilities are some of the country's biggest Hg polluters, and should have to comply with strong emission standards that protect our environment and public health. The commenter states that the proposed standards are an excellent start, but don't go far enough to protect public health and our environment. According to the commenter, lignite burning facilities should receive equal treatment, and be required to control their Hg emission levels to protect public health.
Response to Comments 7 - 14: We disagree with commenters that subcategorization by fuel type is not authorized under CAA section 112. Under CAA section 112(d)(1), the Administrator has the discretion to "...distinguish among classes, types, and sizes of sources within a category or subcategory in establishing..." standards. The EPA maintains that any basis for subcategorization (i.e., class, type, or size) must be related to an effect on HAP emissions that is due to the difference in class, type or size of the units. See 76 FR 25036-25037. The EPA believes it is not reasonable to exercise our discretion without such a difference because if sources can achieve the same level of emissions reductions notwithstanding a difference in class, type, or size the purposes of CAA section 112 are better served by requiring a similar level of control for all such units in the category or subcategory. 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 original)); see also CAA section 112(d)(1) (containing almost identical language to CAA section 111, CAA section 112(d)(1) provides that "the Administrator may distinguish among classes, types, and sizes of sources within a category or subcategory in establishing [] standards..."). Nothing in the statute prohibits EPA from subcategorizing based on material input and the case law supports it to the extent it has considered subcategorization based on such factors. See Sierra Club v. Costle, 657 F. 2d 298, 318-19 (D.C. Cir. 1981) (differing pollutant content of input material can justify a different standard based on subcategorization authority to "distinguish among classes, types and sizes within categories of new sources"). Furthermore, we believe had Congress intended to prohibit EPA from subcategorizing based on material input it would have clearly stated such intent in the CAA.
We also disagree with commenters' suggestion that because units are able to blend fuels we are limited in our ability to subcategorize units that are different in class, type, or size at the time we establish the standards. If commenters are correct that different fuels will lead to less pollution, the conversion to the "cleaner" fuel will have the desired benefit of reducing HAP emissions. In addition, EPA is required to conduct technology analysis at least every 8 years so the Agency will have opportunities in the future to determine whether subcategorization remains warranted and whether more stringent standards are appropriate. We also disagree that the fact that the availability of similar control options negates the legitimacy of a subcategorization approach. In fact, the controls available to reduce HAP are generally available for all types of sources, but that does not mean that all classes, types and sizes of sources must be included in the same subcategory under a given regulation. In addition, we disagree that the final rule effectively exempts a subcategory from controlling mercury and we note that we established the MACT standard consistent with the statute and it is based on beyond-the-floor levels of control. Finally, we disagree that EGUs in the low rank, virgin coal subcategory have demonstrated that the new-source limit for the non-low rank, virgin coal subcategory is achievable as commenter alleges or that an unequal bias is established for such units. We estimate that the final rule will reduce Hg emissions from the subcategory by approximately 20 tons.
b. There is insufficient test data to support the subcategory.
Comment 15: Commenter 17620 states that the EPA has emission test data for 330 of the 1,061 units in Subcategory 1, but only for two of the 30 units in the smaller subcategory. According to the commenter, however, if the performance of the two subcategories is the same, one would expect the two tests for the small subcategory to be randomly distributed throughout the 340 results of Subcategory 1. The commenter states that thus, the fact that those two results were not in the top 40 results of the larger group does not, by itself, demonstrate that there are engineering reasons to set a separate subcategory. Commenter submits that two test results are insufficient to characterize the emission performance of a group and point out that the two sources for which the EPA has data may be among the worst performers in the lignite group. The commenter states that thus, even if it were permissible to establish subcategories based on emission test results (absent an engineering basis for doing so), the EPA test data argument does not appear to support a separate subcategory. The commenter asserts that the real basis for the EPA's proposal for a separate subcategory include the facts that (1) lignite generally has higher Hg content than other forms of coal, and (2) several lignite-burning facilities in the EPA's data base were equipped with ACI and FF and tested higher than 1.2 lb/TBtu. Commenter is also aware of the EPA's earlier assertion that all known lignite-burning units are "mine mouth" units or nearly so. According to the commenter, the EPA should simply acknowledge these facts and argue that it is entitled to treat lignite as a separate subcategory of fuel for purposes of Hg control, just as it does oil and petroleum coke.
Commenter 17620 states, as would be expected with small sample sizes, the EPA does not have sufficient data to establish a credible MACT floor for the proposed lignite group and has no way to ascertain the performance of the best performing 12 percent of the subcategory. According to the commenter, the EPA can only determine which of the few units in the subcategory for which it had data performed better. The commenter states that further, as would be expected with such small categories, small sample statistics generate excessively high variability factors and inappropriate MACT floors. The commenter asserts that here, the variability factors employed by the EPA are so large that all of the "lignite subcategory" units apparently currently meet the proposed MACT floor.
Comment 16: Commenter 17843 agrees with Commenter17620 that there is weak support for this subcategory. Commenter states that the rationale put forward in the proposal for establishing the proposed Hg subcategory is that no unit meeting this definition was within the top 12 percent of performing sources in the larger category. According to the commenter, even if it were permissible to establish subcategories based on emission test results, absent an engineering basis for doing so, the EPA test data does not appear to support a separate subcategory in this instance.
Comment 17: Commenter 18039 agrees with Commenter 17620 on the flaws in the EPA's creation of a subcategory for "coal-fired units designed to combust coal with heat content less than 8,300 Btu per pound" (the "lignite category").
Comment 18: Several commenters (19536, 19537, 19538) state that the data do not support the proposed subcategorization of coal-fired units. The commenters assert that the chart in his comment shows the Hg data (in lb/MMBtu) that were used in the EPA's analysis. According to the commenters, the bars in red are units in the "less than 8,300 Btu/lb" subcategory, although all of the other data are for the greater than 8,300 Btu/lb subcategory. The commenters state that as shown below, there is no distinction between the two groups of data. The commenters state that in other words, the Hg data for the two subcategories do not fall into two different or distinct populations. The commenters assert that in fact, although the Hg emissions for the best performing lignite units were generally higher, the EPA's floor analysis for the greater than 8,300 Btu/lb subcategory includes suggests that some best-performing units in that subcategory have Hg emissions greater than those used in the lignite subcategory  -  these are the blue bars in the chart below that are to the right of the red bars.
Several commenters (19536, 19537, 19538) state that the EPA asserts that in its ICR data set there were "no EGUs designed to burn a nonagglomerating virgin coal having a calorific value (moist, mineral matter-free basis) of 19,305 kJ/kg (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." According to the commenters, the next sentences in the preamble demonstrate clearly that this is not a combustion technology driven subcategory, but rather one designed to accommodate the EPA's conclusion that "emissions of Hg are different between these two subcategories." The commenters assert that subcategorizing an industry in order to preserve poor performance  -  essentially the EPA's asserted rationale  -  is an effort to sidestep the requirements of the statute, of the kind that the Court invalidated in NRDC v. EPA, 489 F.3d at 1372-73. According to the commenters, units lacking pollution controls may have poor performance; the Agency cannot, however, create a subcategory for such units so as to prevent them from installing the necessary controls.
Response to Comments 15 - 18: The EPA believes it has sufficient data to support the subcategory. The EPA has Hg and non-mercury metallic HAP data from 11 low rank, virgin coal-fired EGUs and acid gas HAP data from 7 low rank, virgin coal-fired EGUs, not just from 2 as noted by commenter. The units that were included in the MACT Hg floor for this subcategory are well controlled and have ACI, wet/dry FGD, and fabric filters, and these and other units were included in floor calculation for PM and HCl. Thus, commenters assumption that the units in the low rank, virgin coal subcategory for which we have data are not good performers is not accurate. Based on these facts, the EPA disagrees with commenter's statement that there is no distinction between the Hg emissions data from low rank, virgin coal EGUs. Even after revising the data set partly based on comments received, there are no low rank, virgin coal-fired EGUs whose data are in the top performing 12 percent of the Hg data set.
c. The definition of the subcategory is imprecise.
i. The EPA should specify how to measure height-to-depth ratio.
Comment 19: Commenter 18932 states additionally, the proposed definitions for each subcategory are imprecise and subject to manipulation. According to the commenter, for instance, the definitions do not indicate how to measure the height-to-depth ratio of a unit; whether the ratio is based on the dimensions of the inside volume of the unit or its outside surface area. The commenter states that nor does the definition make it clear whether the height-to-depth dimensions include the structural components of the unit or merely its functional elements.
ii. The EPA should define "nonagglomerating fuel."
Comment 20: Commenter 18932 states that the Southeast Environmental Organizations have not found an established technical definition for "nonagglomerating fuel." The commenter states that the definition does not indicate how a unit that is designed to burn a mixture of agglomerating along with nonagglomerating fuels should be characterized. According to the commenter, rather, it merely states that a low-Btu unit is designed to burn a nonagglomerating fuel, not that it is exclusively designed to do so. Commenter states that the lack of precision or established standards in these definitions will allow EGU operators to misconstrue these terms to circumvent more stringent mercury emission limits that the units can and should meet.
iii. The EPA should specify whether the 8,300 Btu/lb is gross or net.
Comment 21: Commenter 18425 states that if the EPA uses the >8,300 Btu/lb coal units subcategory, it is important for the EPA to clarify the definition of such units. The commenter states that first, as the NESHAP is written currently, there is no indication whether the <8,300 Btu/lb indicates the gross calorific value or net calorific value of the coal (whether or not the heat contained in the water vapor from combustion is recovered). The commenter asserts that it is important to specify which measurement is being used so units can meet the proper emissions standards.
iv. The EPA should specify the method to determine gross or net heat.
Comment 22: Commenter 18425 states that the method to determine the gross or net heat output needs to be specified to ensure all owners/operators of EGUs properly measure and categorize their EGUs.
v. The EPA should state what types of coal are included in the subcategory.
Comment 23: Commenter 18425 states that the EPA needs to state which types of coal, aside from lignite, are included in these coal-burning units. The commenter states that the current definition of such units is units that burn "coal or coal refuse either exclusively, in any combination together, or in any combination with other fuels in any amount." According to the commenter, this definition does not sufficiently explain what constitutes "coal" for purposes of this NESHAP. The commenter states that the EPA should consider these suggestions and properly specify this subcategory if it insists upon using it at all.
Response to Comments 19 - 23: The EPA has clarified the definitions in the final rule. The height-to-depth ratio has been removed from the definition making these comments moot. The term "nonagglomerating" is contained within the American Society for Testing and Materials (ASTM) definitions which are well-known to industry. We have clarified that we are using "gross" MW in the final rule.
d. The subcategory creates an incentive to characterize as "low-Btu units" to avoid more stringent emission limits.
Comment 24: Commenter 18425 states that because these units have higher Hg emissions than other types of fuel, they should be regulated closely, not lumped into a subcategory with less stringent emissions limits. The commenter states that the proposed emissions limits for coal-burning EGUs with coal >8,300 Btu/lb is 0.000010 lb/GWh, and the emissions limit for coal-fired EGUs with coal <8,300 Btu/lb is only 0.040 lb/GWh. According to the commenter, this regulatory scheme essentially gives EGUs burning coal <8,300 Btu/lb less stringent emissions standards because they emit more Hg than units burning higher efficiency coal. The commenter asserts that in other words, they pollute more so they should get less stringent standards.
Comment 25: Commenter 18487 states that the EPA's MACT proposal includes an inadequately supported MACT subcategory for "junk fuels" which can and must be corrected in the final Rule. The commenter states that the EPA is permitted to distinguish among classes, types, and sizes of sources within a category or subcategory in establishing MACT standards, but is not required to subcategorize an industry when in standard setting. According to the commenter, where the EPA does set MACT standards based on industrial subcategories, the Agency's action must be reasonable, and well-supported. The commenter asserts that the EPA cannot use subcategories in such a way as to avoid the requirements of the statute, or as part of an effort to allow existing sources to avoid controls or standards.
Commenter 18487 states that the EPA's proposal appears at first glance not to devolve this standard setting process into one based on multiple fuel-based subcategories, as it proposed to do in 2004 with its unjustified "coal-rank" based scheme. According to the commenter, unfortunately however, a deeper look shows that the proposal does include an inadequately justified subcategory, which seems clearly designed to allow lignite burning plants to avoid more stringent MACT standards applicable to other coal-fired EGUs. The commenter states that this defect in the rule can easily be  -  and must be  -  corrected in the final rule, based on data the EPA has in the record.
Comment 26: Several commenters (19536, 19537, 19538) state that the EPA's authority to set MACT standards for subcategories of an industrial category is not unlimited. According to the commenters, the CAA provides only that the agency "may distinguish among classes, types, and sizes of sources within a category or subcategory in establishing [MACT] standards." 42 U.S.C. § 7412(d)(1). The commenters assert that it does not permit the EPA to distinguish between sources on other grounds, and does not require any subcategorization in MACT standard setting for a listed industry. The commenters state that the EPA's "subcategorization authority . . . does not authorize EPA to sidestep what Congress has plainly prohibited," or otherwise contradict section 112's basic command to require the maximum achievable reductions in hazardous air pollution. The commenters cites Natural Resources Defense Council v. Environmental Protection Agency, 489 F.3d 1364, 1372 (D.C. Cir. 2007) ("NRDC v. EPA"). According to the commenters, the plain text of the CAA demonstrates that Congress intended the EPA to create categories and subcategories in a regulated industry "as a step toward establishing emission standards," not as part of a scheme to provide incentives for existing sources to avoid controls or standards. The commenters state that where the EPA sets MACT standards based on subcategories of an industry, the EPA must offer a reasoned justification for the subcategories it has chosen. 42 U.S.C. §§ 7607 (d)(3), (d)(6), (d)(9). See, e.g., Northeast Maryland Waste Disposal Authority v. EPA, 358 F.3d 936, 947-950 (D.C. Cir. 2004) (remanding a decision to subcategorize in setting MACT standards because the Agency had not properly justified its subcategorization scheme).
Commenters (19536, 19537, 19538) states that sub-dividing the category according to the specified heating value is likely to cause confusion during implementation. The commenters state that for example, it is entirely possible that heating values for a number of subbituminous coals may fall above or below this break-point based on variability of heating values, mineral matter content, moisture content and the like. According to the commenters, the EPA has provided no clear standard by which to distinguish units "designed" to burn low-calorie coals, and those doing so by choice. The commenters assert that given the difference in the proposed Hg MACT limits (1.2 lb/TBtu for the greater than 8,300 Btu/lb category, and 4 lb/TBtu for the less than 8,300 lb/TBtu category), there will be a significant incentive for many sources that burn subbituminous coals to classify themselves into the less than 8,300 Btu/lb sub-category, and thereby bypass available means of reducing their pollution.
Comment 27: Commenter 18932 states that the proposed subcategorization scheme, which sets significantly more stringent Hg emission limits for high-Btu units, creates a powerful incentive for operators to characterize their EGUs as low-Btu units in order to evade more rigorous regulation. Commenter suggests that such an approach is antithetical to the fundamental goal of the CAA's hazardous air pollution provisions to "require the maximum degree of reduction in emissions of the hazardous air pollutants subject to [section 112 that] . . . is achievable for new and existing sources." Commenter provided details of a recent case (Plant Washington, Sandersville, Georgia) to demonstrate how the Agency's proposed subcategories based on coal heating value would create an opportunity for EGU operators to game the system.
Commenter 18932 concludes that establishing subcategories with markedly different MACT limits for Hg based on such imprecisely framed and manipulable characteristics as a unit's height-to-depth ratio, coal heat values, and other coal characteristics would encourage the same type of maneuvering to avoid more stringent emission limits. The commenter asserts that indeed, codifying such an approach in a NESHAP would greatly expand and magnify the risk of companies gaming the system to evade the highly protective MACT emission standards mandated by the CAA. Commenter states that the goals and requirements of CAA section 112, the evidence in the rulemaking record, and actual experience from recent cases all preclude setting separate Hg emission limits for EGU subcategories based on coal heating values, other coal characteristics, and EGU height-to-depth ratios.
Response to Comments 24 - 27: The EPA believes the revised subcategory definitions in the final rule clearly delineate the subcategory populations. We also believe the definitions in the final rule will prevent sources from potentially gaming the system. Responses to the remainder of the comments are set forth above and in the preamble to the final rule.
e. The subcategory creates an incentive for existing units to switch to dirtier coal.
Comment 28: Commenter 16122 states that the EPA's subcategorization scheme provides incentives for existing EGUs to switch to dirtier lignite coal. Commenter states that the proposed rule creates incentives for existing coal-fired EGUs to switch to a less efficient fuel (i.e., lignite) to fit into a subcategory with a higher emissions standard. Commenter says that this is very concerning since it could effectively result in a substantial weakening of the EGU MACT Rule. According to the commenter, the EPA defines EGUs designed to burn lignite coal as "any EGU designed to burn [lignite coal] in an EGU with a height-to-depth ratio of 3.82 or greater." The commenter states that this definition provides too much flexibility for EGUs to switch categories by simply changing their fuel source.
Comment 29: Commenter 18425 states that the <8,300 Btu/lb coal subcategory also fails to incentivize future emissions reductions. The commenter asserts that the EPA is correct to emphasize point-of-use reductions in this NESHAP in the form of numeric emissions limits. The commenter states that such emissions limits will reduce the amount of HAP released into the atmosphere. According to the commenter, regulating point sources through the use of numeric emissions limits will result in an overall reduction in HAP, especially for Hg because there has never been a federal standard limiting Hg emissions. The commenter states that however, in implementing this NESHAP, the EPA's goal should be to promote future emissions reductions from using cleaner fuel types in addition to creating point-of-use reductions. The commenter asserts that the EPA attempts to equalize the energy sector through this NESHAP by subjecting all covered EGUs of the same type to the same emissions limitations. According to the commenter, however, the subcategory designation for EGU units designed to burn coal <8,300 Btu/lb incentivizes the use of lower-quality fuels by permitting lower standards for those units. The commenter states that the EPA instead should incentivize the use of cleaner fuels.
Commenter 18425 states that the EPA should not use a special subcategory for coal-fired EGUs that burn coal <8,300 Btu/lb. Commenter believes that grouping these units with coal-fired EGUs that burn coal >8,300 Btu/lb will encourage units using low-efficiency coal to upgrade to cleaner fuel types. According to the commenter, such incentivizing will result in future emissions reductions, which will provide benefits to public health as well as wildlife and the environment.
Response to Comments 28 and 29: The EPA does not agree with commenters that establishment of this subcategory will incentivize the use of low-rank, virgin coals because of the definition in the final rule.
f. The subcategory creates an incentive to build new units that burn dirtier coal.
Comment 30: Commenter 16122 states that the EPA's subcategorization scheme also provides incentives for power generators to construct new sources that burn dirtier lignite coal. Commenter states that the EPA's subcategorization scheme for new coal-fired sources is even more disturbing since it strongly encourages EGU developers to construct new EGUs that are designed to burn inefficient, dirty coal. According to the commenter, this is because the EPA's proposed rule creates a MACT standard that is 4,000 times higher for EGUs designed to burn lignite than the MACT standard for EGUs designed to burn other ranks of coal. The commenter asserts that again, the CAA does not require the EPA to set MACT standards for different subcategories, and the EPA provides no justification in the preamble for creating two vastly different standards based solely on the rank of coal.
Commenter 16122 states that the perverse incentives created by the EPA's subcategorization scheme for new coal-fired EGUs frustrate the purpose of the CAA - to achieve the greatest reduction of HAP that is achievable. According to the commenter, when Congress enacted section 112 it purposely created two standards - one for existing sources and another for new sources. The commenter states that Congress realized that new sources could achieve significantly lower emissions of Hg because it is more cost effective to implement Hg control strategies at the design stage. The commenter asserts that however, in this proposed rule, the EPA frustrates Congressional intent by allowing new lignite EGUs to emit 4,000 times more Hg than other new coal-fired sources burning bituminous and subbituminous coal.
Commenter 16122 adds that the EPA's subcategorization scheme is also in contradiction to its intention to establish MACT standards that support a coordinated air pollution compliance strategy for EGUs. Commenter states that in contrast to this stated approach, the EPA strongly incentivizes EGU developers to invest in new EGUs designed to burn lignite, which would not only result in tremendously higher Hg emissions but significantly higher emissions of greenhouse gases and criteria pollutants. According to the commenter, on average, burning lignite coal is less efficient than other ranks and results in higher emissions of CO2, SO2, and NOX. The commenter states that hence, in order to encourage EGUs to make smart investment choices that will pay off long term internally and for public health, the EPA should create a single MACT standard for all new coal-fired EGUs. According to the commenter, by doing this, EGUs will be motivated to make practical investments which will lead to long-term reductions in multiple air pollutants and lower the EGU's overall compliance costs.
Commenter 16122 states that there is no reason why the EPA should further subcategorize coal-fired EGUs. Commenter states that, as the EPA has noted in the preamble to the proposed rule, there is no rationale for the EPA to further subcategorize coal-fired EGUs. Commenter states that although the Agency has the discretion to subcategorize sources by size, class or type under CAA section 112, such subcategorization is simply not required. Commenter adds that considering the range of control technologies available to EGUs to control Hg emissions, there is no reason why well-controlled units within the subcategories the EPA has already established should differ significantly in levels of Hg emissions.
In summary, Commenter 16122 states there is no reason to create a lignite subcategory for new EGUs. Commenter states, in fact, creating a lignite subcategory would encourage the construction of significantly dirtier units. Commenter states, however, if the EPA insists on creating a lignite subcategory for new EGUs despite the adverse effects this would cause, the EPA must consider the numerous available studies regarding the effectiveness of alternative Hg control technologies, and regulate beyond the MACT floor for new lignite facilities.
Response to Comment 30: The EPA disagrees with commenter that creating such a subcategory will encourage the proliferation of new lignite-fired EGUs. Lignite is not of sufficient quality (e.g., high moisture content, low energy density) to warrant transportation over long distances and, thus, EGUs burning lignite are built at or near the mines that generate the coal. The availability of such mines is not infinite and the economics of construction of a new lignite-fired EGU would not be enhanced by the final rule. There have been less than a half-dozen such units built in the last 10  -  15 years.
g. Technology exists and is in use on existing units which does not justify the subcategorization.
All comments have been moved or combined with other comments.
h. There is no substantial design difference.
Comment 31: Commenter 18425 states that there are no substantial design differences between coal-fired EGUs that burn coal <8,300 Btu/lb and those that burn coal >8,300 Btu/lb. According to the commenter, as the EPA noted, units that burn coal <8,300 Btu/lb have larger boilers to accommodate the larger volume of coal that must be combusted. The commenter states that however, the EPA even notes that for the rest of the regulated HAP, there is no discernable difference in emissions between units burning coal <8,300 Btu/lb and those burning coal >8,300 Btu/lb. According to the commenter, because all HAP emissions between these two types of coal-fired EGUs are the same except Hg, it makes more sense to regulate them according to the same numeric emissions limits, rather than creating two separate subcategories. The commenter asserts that the adverse environmental and public health effects of Hg demand the EPA closely regulate large sources of Hg, such as EGUs burning coal <8,300 Btu/lb. According to the commenter, the totality of these facts indicate that the EPA should regulate EGUs burning coal <8,300 Btu/lb with the same Hg emissions standards used for units burning coal >8,300 Btu/lb.
Comment 32: Several commenters (19536, 19537, 19538) states that there is no technical justification for two subcategories defined by the 8300 Btu/lb characteristic; there is no difference between the combustion technologies and pollution-control options available to facilities burning the different grades of coal. Indeed, the industry experience is one in which the same or very similar pollution-control methods are employed for a variety of coal ranks, as environmental groups pointed out previously to the Agency in comments on the 2004 MACT standards proposal. According to the commenters, the data demonstrates that EGUs commonly burn a blend of coals, above and below the 8300 Btu/lb threshold. The commenters state that moreover, Babcock and Wilcox, the manufacturer of various coal-fired power plant components, states that the majority of bituminous, subbituminous and lignite fired conventional units are adaptable to most types of coal.
Commenters (19536, 19537, 19538) states that the EPA has presented no reason why the units in its less-than-8300 Btu/lb subcategory could not alter their choice of fuels, or otherwise reduce their emissions to match the performance of units burning higher-calorie coals. See 42 U.S.C. section 7412(d)(2) (requiring the EPA to set standards which include pollution reductions achievable, inter alia, through "process changes, [or] substitution of materials."). According to the commenters, most coal plants (including their various sub-systems) are designed to accommodate coals of different properties. The commenters state that even for conventional pulverized coal fired units, the fuel storage areas, flue handling systems, pulverizers, burners and the combustion air circuit, the firebox, as well as the later heat transfer surfaces such as the superhaters, reheaters, economizer, air preheaters are all designed to accommodate coals of different properties. The commenter asserts that fluidized bed units are even more accommodating of a range of fuel properties. According to the commenters, similarly, the add-on pollution controls affecting hazardous air pollution depend mainly on the nature of exhaust gases from the unit; they can, accordingly, can be uniformly installed at coal-fired units of various designs. The commenters state that there are no significant design differences between coal-fired units to justify the proposed (or any other) subcategories.
Response to Comments 31 and 32: We respond to these comments above. In addition, the EPA has revised the definition for this subcategory.
i. The EPA should establish a single MACT limit for emissions from all new coal units.
Comment 33: Several commenters (19536, 19537, 19538) state that the EPA does not simply propose its 8300 Btu/lb distinction as defining existing source subcategories; it also extends this for use in standard setting for new sources. According to the commenters, the EPA has absolutely no rationale for selecting this subcategory for new units. New EGUs can very easily be designed to provide optimum performance  -  and control  -  when firing all kinds of coal. The commenters state that even in its extraordinarily weak 2003 proposal, the EPA agreed that "the industry has some ability during the designing of new units to choose coal or oil that would minimize emissions of Hg and Ni and recognizes that the MACT standard for new units should, to the extent possible, encourage the industry in that direction." The commenters assert that the EPA now seems to believe that a unit combusting coal with heat values below 8300 Btu/lb and coal above 8300 Btu/lb are not "similar units," for the purpose of deriving MACT floors for new sources. According to the commenters, these units are not just similar, they frequently are units of exactly the same design, with the only difference being that their owners/operators choose different fuel suppliers as they strive to minimize the cost of coal. The commenters assert that put differently, the same units can and do burn more than one type of coal. According to the commenters, the EPA has not justified the less than 8300 Btu/lb subcategory for new units. The commenters state that the EPA should establish a single MACT limit for emissions from all new coal units.
Response to Comment 33: The EPA believes that at this time, for the reasons provided above and in the preamble, it remains appropriate to maintain two coal-fired EGU subcategories for new EGUs in the final rule.
3. Support for expanding the Btu/lb threshold for the subcategory.
Comment 34: Commenter 12991 supports the expansion of the EPA's proposed lignite-fired subcategory (coal <8,300 Btu/lb). The commenter compared the heating value of coal delivered to the 40 best-performing low-Hg units with the coal delivered to U.S. electric power plants in 2009, noting that the distribution for all plants is bimodal, with the lower peak near 8,500 Btu/lb attributed to coal from the PRB. Commenter stated that the distribution for the 40 best-performing units is also bimodal, but the PRB peak is missing and the lower peak near 6,500 Btu/lb is attributed to waste coal. Commenter states that the absence of units designed to burn virgin coal with less than 9,500 Btu/lb within the group of 40 best-performing units is noteworthy, because the EPA justified subcategorization of lignite-fired units for substantially the same reason. According to the commenter, the expanded subcategory would include "units that are designed to burn pulverized virgin coal having a calorific value (moist, as-shipped basis) of 22,100 kJ/kg (9,500 Btu/lb) or less, where the furnace has a height-to-depth ratio of 3.53 or more." The commenter asserts that the EPA's proposed lignite-fired subcategory would include up to 7 percent of the coal burned at U.S. power plants, although the expanded subcategory would include up to 50 percent. The commenter states that the suggested 3.53 furnace height-to-depth ratio is consistent with the slagging behavior of subbituminous rank PRB coal. According to the commenter, a list of measured furnace dimensions for the 1,061 affected units is needed to identify units that have height-to-depth ratios greater than 3.82 or 3.53 and would be included in either the proposed or expanded subcategories.
Alternatively, Commenter 12991 states that if the EPA decides that more than 40 units are required to characterize the Hg emissions from the best-performing 12 percent, justification for the more limited lignite-fired subcategory might be maintained. Commenter says that 19 units that burn PRB coal are within the top 127 units ranked by Hg stack emission rate, but the best lignite-fired unit (Sandow 5B) is ranked 138.
Response to Comment 34: The EPA disagrees with commenter and has not expanded the threshold for the subcategory or the basis for establishing the MACT floor standards for mercury. We have revised the definition of the subcategory in the final rule as explained in the preamble to the final rule.
4. Suggested revisions to the definition of the source category.
a. Only lignite.
Comment 35: Commenter 16122 states that if EPA keeps the subcategorization for existing EGUs, it should revise the rule's definition to limit the subcategory to "any EGU designed to burn only [lignite coal] in an EGU with a height-to-depth ratio of 3.82 or greater." According to the commenter, , the definition in the proposed rule, unlike the preamble to the rule, does not make clear that the 3.82 height-to-depth ratio applies to the EGU furnace and not the EGU as a whole. Accordingly The commenter states that the definition in the final rule should be revised further to state "any EGU designed to burn only [lignite coal] in an EGU furnace with a height -to-depth ratio of 3.82 or greater."
b. No less than 75 percent lignite.
Comment 36: Commenter 17620 states that the definition of this subcategory gives rise to some concerns that many sources, other than those contemplated by the EPA, may qualify for these relaxed limits. According to the commenter, the definition of the subcategory applies to any EGU with a height-to-depth ratio of 3.82 or greater that burns any amount of low-rank coal. The commenter states that most, if not all, coal-fired EGUs have the capability of burning some amount of low-rank coal, especially if the low-rank coal is pre-blended with higher quality coal. The commenter asserts that we have not found any information in the record that systematically identifies the number of conventional boilers that may in the past have burned small amounts of lignite, or may choose to do so in the future, to take advantage of the more lenient Hg limits proposed for lignite-fired conventional boilers. According to the commenter, to prevent such gaming, any definition of lignite-fired units should include a requirement that any such unit must have used lignite for no less than 75 percent of its heat input over each of the last 3 years. The commenter states that one Commenter member with experience in permitting lignite-fired facilities has confirmed that there are a number of facilities that do not combust lignite on a regular basis, but are in a position to take advantage of the more lenient Hg limits for lignite-fired units if the rule is adopted as proposed.
c. Remove the height-to-depth ratio.
Comment 37: Multiple Commenters (17815, 17818, 17904, 17925, 17930, 18785, 19040) request that the EPA remove the height-to-depth ratio from the definition of the subcategory.
Comment 38: Commenter 17815 states that the height-to-depth ratio criteria for subcategorization of low rank coal units should be removed. According to the commenter, the EPA has proposed a subcategory for Hg limits for low-rank coal units and a prescribed height to depth ratio of >3.82 (often referred to as "boiler aspect ratio"). Although Commenter strongly supports the EPA's use of its discretion to propose new standards that are subcategorized, Commenter recommends that the EPA remove the height-to-depth ratio criteria from the low-rank fuel boiler criteria. Commenter is not aware of any predefined height-to-depth ratio specified in regulatory or other standards to define a low-rank coal unit, and the EPA has not explained the purpose or foundation for the 3.82 height to depth ratio. Further, Commenter member companies have reviewed the aspect ratio of their low rank coal units and have identified that the EPA's proposed height-to-depth ratio does not include designs of all low-rank coal unit manufactures or types of boilers for burning such fuels. The commenter states that if the prescribed 3.82 height-to-depth ratio were to be used, at least four units (Oak Grove Unit 2, Monticello Unit 3, Twin Oaks Units 1 & 2) from Commenter member companies' fleets that are designed to burn <8,300 Btu/lb would be erroneously excluded.
Comment 39: Commenter 17818 states that the EPA appears to be introducing a requirement for furnace sizing for determination of what emissions limitations would be applicable to the unit. It is Commenter's opinion that this is inappropriate, as furnace design and sizing is a function of the characteristics of the fuel(s) intended to be combusted in the unit. According to the commenter, even among specific coal ranks or classifications, (such as bituminous, subbituminous, or lignite), the furnace sizing (and width-to-height ratio) may differ greatly depending upon the characteristics of the particular fuel(s) the steam generator is being designed to combust. The commenter asserts that other factors that could affect the width-to-height ratio include the steam generator's design operating pressure, total output, firing configuration, etc. Further, Commenter was unable to locate any data in the docket that permitted an analysis of furnace sizing and fuel type/category. It is Commenter's opinion that the EPA should consider definitions that draw distinction only between fuel types based on ASTM or other similar coal ranking or standard, without regard to furnace sizing.
Comment 40: Commenter 17904 states that a technical clarification is needed. According to the commenter, the height-to-depth ratio specified in the proposed rule excludes some lignite burning units that have the same "difference in emissions" identified by the EPA. The commenter states that as proposed, a "unit designed for coal <8,300 Btu/lb" is defined as "any EGU designed to burn a nonagglomerating virgin coal having a calorific value. . . of less than [8,300 Btu/lb] in an EGU with a height-to-depth-ratio of 3.82 or greater." According to the commenter, a "unit designed for coal > 8,300 Btu/lb subcategory includes any EGU designed to burn a coal having a calorific value . . . of greater than or equal to [8,300 Btu/lb] in an EGU with a height-to-depth ratio of less than 3.82." The commenter states that these definitions have the unintended effect of excluding certain boilers from both definitions. Commenter has reviewed the aspect ratio of its boilers and has identified that the EPA's proposed aspect ratio does not include boiler designs of all boiler manufacturers for burning lignite.
Commenter 17904 is not aware of any predefined aspect ratio specified in regulatory or other standards to define a low rank fuel boiler. According to the commenter, the EPA has concluded from the data it gathered in the ICR that there are no EGUs burning lignite with a height-to-depth ratio of 3.82 or greater. The commenter asserts that as the EPA notes, a lignite boiler "is bigger than a boiler designed to burn coals with higher heat values to account for the larger volume of coal that must be combusted to generate the desired level of electricity." The commenter states that however, these types of boilers are taller and deeper than boilers for other fuels, all else being equal, the specific height-to-depth ratio is determined by each boiler manufacturer based on their particular design criteria.
Commenter 17904 presents Figure 19 (see docket entry), excerpted from Steam: Its Generation and Use, 40th Edition (a reference published by Babcock and Wilcox ("B&W")) that compares relative sizes and dimensions of boilers for various categories of fuel based on factors such as slagging potential of low rank fuels. Commenter believes this comparison is likely the original source of the EPA's proposed height-to-depth ratio of 3.82. The commenter states that however, as explained more fully in comments submitted by B&W, the relative height-to-depth ratio shown in this excerpt is illustrative only. The commenter asserts that B&W has designed lignite boilers with lower height-to-depth ratios, and it is the properties of lignite fuel that impact Hg emissions rather than the specific height-to-depth ratio of the boiler. B&W has specifically explained that the 3.82 ratio is not a firm design criterion.
Commenter 17904 states that although it has many tangential design, low-rank fuel boilers originally manufactured by Combustion Engineering that meet the EPA's proposed aspect ratio, Commenter also currently operates boilers originally manufactured by B&W that have a height-to-depth ratio less than 3.82. According to the commenter, these units are opposed-burner, wall-fired design, and are very tall but also have a deeper furnace to handle opposed-burner flame patterns. The commenter asserts that these units have a slightly lower aspect ratio of approximately 3.5. Even though these boilers have an aspect ratio that is not "3.82 or greater," these boilers (1) are "lignite boilers" and (2) have a boiler designed "to account for the larger volume of coal that must be combusted." According to the commenter, for instance, Commenter's Monticello Unit 3 and Oak Grove Unit 2 are designed to burn coal with a heating value of less than 8,300 Btu/lb, but have a height-to-depth ratio of slightly less than 3.82. The commenter asserts that in addition to lower heating value, variations in physical boiler design for units firing fuels less than 8,300 Btu/lb are also driven by fuel characteristics including sodium content and slagging potential. According to the commenter, therefore, in order to implement the EPA's appropriate policy choice and accurately reflect actual, existing boiler designs, and to bridge the gap between the proposed definitions for the two solid fuel subcategories, Commenter urges the EPA to remove the height-to-depth ratio from the definition of "unit designed for coal < 8,300 Btu/lb." According to the commenter, the EPA's basis for the lignite subcategory would remain undisturbed  -  no "lignite boilers" were "among the top performing 12 percent of sources for Hg emissions." The commenter asserts that significantly, the EPA's discretion to establish a standard for a class or type of boiler is not limited to this circumstance. The commenter states that in other words, regardless of whether some few units registered a given value on an individual "snapshot" stack test, the EPA can determine that a separate standard is appropriate for a class or type of boiler in light of what level of control is "actually achieved" under all operating conditions by that class or type of unit.
Commenter 17904 states that if the EPA determines however, that an aspect ratio must be part of the definition of the low-rank subcategory, then the ratio should be lowered from "greater than 3.82" to "greater than 3.5" to at least cover the ratios for existing lignite units currently operated by Commenter.
Comment 41: Commenter 17925 states that the definitions of subcategories of units designed for coal >8,300 Btu/lb and units designed for coal <8,300 Btu/lb should be changed to remove combustion unit geometry from the definitions. According to the commenter, the EPA has defined five categories for existing units depending on design fuel and fuel type. The commenter states that the proposed rule places a unit within one of these five categories. The commenter asserts that some boilers, such as Cleco's Madison 3 Circulating Fluidized Bed (CFB) Boiler, are designed and permitted to burn multiple fuels such as pet coke, subbituminous/bituminous coal, lignite, biomass and other fuel types. According to the commenter, the unit's fuel mix is generally not set long term since it is dependent on multiple factors such as availability and cost. The commenter states that under the proposed rule, the definition of a "coal unit" is one that burns any amount of coal. According to the commenter, the coal unit is subcategorized into units that are designed to burn fuels >8,300 Btu/lb and units designed to burn fuels <8,300 Btu/lb. The definition of a "solid-oil" unit is one that burns petroleum coke. The commenter states that outside of the lignite subcategory's furnace height to depth ratio of 3.82, Madison 3 meets all three fuel categories.
Commenter 17925 states but since Madison 3 can burn lignite, that is, a fuel in the subcategory of fuels <8,300 Btu/lb, it would be unfair to penalize the unit because it does not meet a furnace height-to-depth ratio that was apparently taken from an example lignite boiler dimension in a Babcock & Wilcox book, Steam and It's Uses. According to the commenter, the book's discussion in Chapter 20 at Figure 19 clearly shows that the primary purpose of the height to depth ratio for this type of coal is to reduce the potential for slagging and not for emission control. In fact, Commenter understands that B&W built lignite boilers that don't meet this ratio. The commenter states that if a unit can burn lignite without modifications, it should be eligible for the lignite category. Therefore, Commenter proposes that the EPA remove the combustion unit geometry description from the definitions of the two subcategories of coal.
Comment 42: Commenter 17930 supports the creation of this subcategory but believes the proposed unit characteristics within this category should be modified. Commenter strongly supports the EPA's decision to design a subcategory for these units, but objects to the use of the height-to-depth ratio of 3.82 or greater. The commenter states that this ratio should be removed from the definition. According to the commenter, the new definition should state: Unit designed for coal < 8,300 Btu/lb includes any EGU designed to burn a nonagglomerating virgin coal having a calorific value (moist, mineral matter free basis) of less than 19,305 kJ/kg (8,300 Btu/lb).
Commenter 17930 states that the EPA has provided no basis in the rulemaking regarding the purpose or foundation for the 3.82 ratio. None of Commenter's members have seen 3.82 as a common measure within the lignite-fired EGU industry. The commenter states that further, boiler height-to-depth ratio has no effect on Hg and non-Hg HAP removal.
Commenter 17930 states that the apparent source of the 3.82 ratio is the Standard Handbook of Powerplant Engineering, which contains a graphic displaying side-by-side height/depth/width dimensions of bituminous, subbituminous, and lignite furnaces. The commenter states that the graphic is entitled "Influence of coal ash slagging potential on furnace size." According to the commenter, the purpose of this graphic is not to demonstrate a standard height-to- depth ratio. The commenter states that its purpose is only to demonstrate that typically, units burning lignite require larger furnaces than those burning bituminous or subbituminous coals. The commenter asserts that the graphic is clearly not applicable to CF) boilers which may have a lower height-to-depth ratio. The commenter asserts that further, even though the graphic may generally be depicting a wall-fired boiler, at least two Commenter member wall-fired boilers (Oak Grove Unit 2 and Monticello Unit 3), designed to burn <8,300 Btu/lb coal, would be excluded if the ratio was set at 3.82.
Commenter 17930 states that it is apparently based on this 3.82 ratio that the EPA in its Beyond-the-Floor Memorandum excludes, at a minimum, four of Commenter's units from Subcategory 2 that were designed to burn <8,300 Btu/lb coal. According to the commenter, these units were originally designed to burn lignite with a heat value of <8,300 Btu/lb, are mine-mouth lignite-fired power plants, and are classified in the EPA and U.S. Energy Information Administration (EIA) databases as lignite units. The commenter states that they are: Big Brown (EPA ID 3497) Units 1 and 2, and Monticello (EPA ID 6147) Units 1 and 3. Monticello Unit 2, a similarly designed lignite-burning unit to the other lignite units, is included in the EPA's Beyond-the-Floor Memorandum Subcategory 2 listing.
Commenter 17930 states that Although removing the 3.82 ratio would likely include all units originally designed to burn <8,300 coal, any finalized rule proposal should include within Subcategory 2, at a minimum, all of the units identified in Attachment A: Texas, Mississippi, and Louisiana Existing EGUs Designed to Burn <8,300 Btu/lb Coal. Attachment A is a non-exhaustive list and does not include the EPA recognized, or potentially recognized, Subcategory 2 units in North Dakota, Montana, and other states where <8,300 Btu/lb coal is burned.
Comment 43: Commenter 19040 states that to the author's knowledge, the EPA has never specified a technology for complying with a regulation. The EPA has always allowed the EGU to select the technology that will satisfy the regulatory requirement and allows the EGU to address unique situations the EGU may have. The commenter states that by specifying the height-to-depth ratio for EGUs that are firing a coal with< 8,300 Btu/lb, the EPA is essentially specifying a control technology, which the EPA has never done before. According to the commenter, if an EGU is designed to fire coal with< 8,300 Btu/lb and has a height-to-depth ratio of 3.82 or greater, the EPA has essentially limited the control options for the EGU. The commenter states that by specifying the height-to-depth ratio and the calorific value of the fuel in a single definition, the EPA has created a subcategory of EGUs that is not covered by this regulation. The commenter asserts that f an EGU is firing a coal that is > 8,300 Btu/lb and the EGU has a height-to-depth ratio that is 3.82 or greater, the EGU is not covered by this regulation. According to the commenter, this is also true if an EGU is firing a coal with< 8,300 Btu/lb and the height-to-depth ratio is less than 3.82. The commenter states that this last scenario is not addressed in this proposed regulation. The commenter asserts that it is suggested that the EPA eliminate the height-to-depth ratio in the regulation. According to the commenter, this ratio is going to be dictated by the fuel the EGU is going to fire and should not be regulatory requirement for determining the emission limitation. The commenter states that the fuel higher heating value on a moisture and ash free basis should determine the regulatory requirement, not the fuel's higher heating value and some arbitrary height-to-depth ratio.
Comment 44: Commenter 18785 generally supports the EPA's effort to create a subcategorized Hg category for units designed to burn coal with heat-inputs of less than 8,300 Btu/lb, but the subcategory's 3.82 height-to-depth ratio criterion must be removed. Commenter owns and operates two Paint Leg CFB boilers designed by Alstom and the EPA has recognized that the units are in the Hg subcategory for units designed to burn coal with heat-inputs of less than 8,300 Btu/lb. According to the commenter, this is evident in the technical document describing the beyond-the-floor requirements for the subcategory. Twin Oaks is included in Table 5: Subcategory 2 EGUs BTF Option Impact Estimates of this technical document. The commenter states that however, we outline the following points regarding the subcategory for clarification and to ensure that CFB boilers are not inadvertently excluded from the subcategory due to the 3.82 height-to-depth ratio criterion. The commenter asserts that we also fully support the "designed to" element of the definition, as it will allow Twin Oaks to continue to co-fire environmentally beneficial alternative fuels, allowing emissions reductions and compliance with future EPA regulations and standards.
Commenter 18785 states that the dimensions of a CFB combustor are not determined based on a ratio of height-to-depth, and are not a control feature for managing Hg emissions. According to the commenter, dimensions of a CFB are the result of process parameters that must be met in order to fluidize and circulate the fuel and sorbent particles in the combustor.
Commenter 18785 states that the depth of a combustor is determined by its plan area. The commenter states that the plan area of a CFB combustor is proportional to unit capacity since design fluidizing velocity is fixed. According to the commenter, the relationship between combustor plan area and fluidizing air velocity is: Plan Area of the Combustor = Volumetric Fluidizing Air Flow/Fluidizing Air Velocity. The commenter asserts that for a CFB the velocity of fluidizing air is 15-30ft/sec with an average bed particle size of 100-300 um [footnote 1], According to the commenter, although the volumetric fluidizing air flow is determined by air flow required for the fuel to be burned. The commenter states that with the fluidizing air flow and velocity being known the combustors plan area can be calculated.
Commenter 18785 states that the height of a CFB combustor varies with its steam generating capacity, and the height of a CFB increases as its steam generating capacity increases in order to absorb the required heat in its walls.' According to the commenter, CFB combustor heights greater than 100-110 ft offer diminishing returns because the heat-transfer rates are low in the upper combustor and additional fan power is required to achieve a desired solids loading at the combustor outlet. The commenter states that the dimensions of the cyclone collector and fluid bed heat exchanger have a large influence on establishing a CFB combustor's height. The commenter asserts that since the combustion temperatures of CFBs are below the ash fusion temperature slagging is not an issue, and therefore is not a factor in determining the combustor's height.
d. Subcategorization should be based on original boiler design.
Comment 45: Commenter 17725 recommends that the applicable subcategory is based on the boiler's original design to combust a low-rank coal (e.g., lignite) with a calorific value less than 8,300 Btu/lb and the boiler remains in this subcategory, provided low-rank coal continues to be burned in the boiler, even if blended with higher-rank coal.
e. Expand the subcategory to other pollutants.
Comment 46: Commenter 17725 requests that the EPA give additional thought to expanding the low rank coal (<8300 Btu/lb) subcategory for other trace metals subject to regulation under the proposed rule. According to the commenter, the relevant fuel and unit design properties that support a separate low-rank coal subcategory for Hg emissions also support including the other trace metal emissions subject to regulation in this subcategory.
Comment 47: Commenter 17813 states that to the extent that the EPA finalizes a rule to reduce non-Hg HAP, subcategorization should be extended to emissions limits for non-Hg metal HAP and averaging time should be expanded to recognize the variability. The commenter states that it appears clear that the EPA will promulgate emissions limits for non-Hg HAP, despite no measured benefits of reducing non-Hg HAP. To the extent that the EPA promulgates these emissions limits, Subcategory 2 should be expanded beyond Hg and apply to all HAP. According to the commenter, the emissions limit for non-Hg metal HAP, with total PM as a surrogate, is believed to be unattainable for lignite-fired EGUs.
Comment 48: Commenter 17813 states that continuing with the currently proposed PM limits poses a dual problem for lignite units, as compared to other types of coal units. The commenter states that first, lignite has a higher ash content than other types of coals. According to the commenter, for every pound of lignite burned, there will simply be more PM generated. The commenter asserts that second, due to the lower heating value of lignite, more must be burned in order to generate the same level of energy produced as other types of coals. According to the commenter, in a comparison of our Texas lignite mine to PRB subbituminous coal, Texas lignite could have in the range of 9 times more ash than PRB coal. (Our mine has coal with a heat content of 5,250 Btu/lb, containing 27.8 percent ash or 52.9 lb of ash/millionBtu. The commenter states that this is compared to typical PRB coal, which has a heat input of 8,400 Btu/lb, containing 5 percent ash or 5.9 lb of ash/millionBtu.) According to the commenter, these numbers also demonstrate that due to the lower heating value of lignite, more must be burned in order to generate the same level of energy produced as other types of coals. The commenter asserts that he EPA has already acknowledged this difference in supporting Subcategory 2 for Hg. A non-Hg metal HAP subcategory would have the same legal and technical basis and be the same in practice as the modified Subcategory 2 for Hg.
Commenter 17904 asks the EPA to reconsider its calculations. The commenter states that moreover, the commenter urges the EPA to establish a separate standard for non-Hg metallic HAP emissions from lignite units if the EPA retains total PM as the surrogate. The commenter asserts that although they fully support the EPA's proposal of separate Hg limits for lignite boilers, the commenter believes the EPA has not provided a sufficient basis for the proposed beyond-the-floor standard. Finally, the commenter believes the 3-year compliance schedule is inadequate and unworkable. Commenter 17904 states that on review of ICR database for lignite boilers for total PM and for each of the non-Hg metals it has determined there is a substantial difference in the measured emissions from lignite boilers than from other types of boilers, justifying the establishment of alternate MACT limits for total PM.
Commenter 17930 states that Subcategory 2 should be expanded beyond Hg and apply to all non-Hg metal HAP as PM. According to the commenter, the emissions limit for non-Hg metal HAP, with total PM as a surrogate, is unattainable for lignite-fired EGUs.
Commenter 17904 requests that the EPA establish a separate PM standard for lignite units.
Response to Comments 35 - 48: Partly based on comments received, the EPA recognizes that the proposed definition was inadequate to fully characterize the subcategory. Therefore, the EPA has revised the definitions in the final rule and the revised definition does not include a boiler height-to-depth ratio. However, the EPA does not believe that there is sufficient justification to expand the subcategory to additional HAP given that low rank, virgin coal-fired EGUs are among the top performing 12 percent in each of the acid gas and non-Hg metallic HAP groups. In addition, the EPA has included alternative equivalent total metal and individual metal standards so that units have compliance options for the final PM standard. Comments related to beyond-the-floor and compliance time issues are addressed elsewhere in this document.
5. Specific questions/clarifications regarding the subcategory.
Comment 49: Commenter 17927 says that the EGU Revised MACT Floor Memo developed by RTI International and dated May 18, 2011, states that Subcategory 2 contains fewer than 30 sources. Commenter asks the EPA to please provide the list of the sources included in this subcategory and the reason(s) why they are included in Subcategory 2.
Commenter 17927 asks the EPA to clarify how the height-to-depth ratios used in the definitions for these subcategories were determined. According to the commenter, it does not appear that any information related to specific boiler design was submitted to the EPA as part of the CAA section 114 ICR used to establish the emission limits in the proposed rule.
Commenter 17927 asks the EPA to clarify the definition of height-to-depth ratio as it applies to affected EGUs in the proposed rule. According to the commenter, this definition is not commonly used by boiler manufacturers or operators.
Comment 50: Commenter 17761 requests clarification about unit applicability and the current subcategorization approach. The commenter states that specifically, several units were designed to burn less than 8,300 Btu/lb coal, but do not appear to meet the boiler height-to-depth ratio requirement. However, Commenter cannot absolutely establish the boilers' height to depth ratios as the EPA has not provided information on how to calculate this ratio. According to the commenter, if it is the EPA's intent that this provision only apply to lignite-fueled units, then the section should be redrafted to clearly state this objective, versus including a convoluted, undefined boiler size calculation methodology. The commenter states that again, the most straightforward approach would be to provide specific emission limits for each fuel subcategory (bituminous, subbituminous, lignite, etc.).
Comment 51: Commenter 19040 states that the definition of this subcategory creates some unintended consequences that may need to be addressed by the EPA. Commenter asks, what if an EGU is designed to fire a nonagglomerating coal having a calorific value <8,300 Btu/lb and has a height-to-depth ratio of 3.82 or greater and the EGU is not firing the fuel the EGU was designed to burn? Commenter asks, what if the fuel being fired has a calorific value >8,300 Btu/lb? Commenter asks if the EGU is designed to fire a lignitic fuel and is currently firing a subbituminous fuel, does the EGU meet the emission requirements for the lignitic fuel or the subbituminous coal? According to the commenter, this will encourage EGUs that are designed to fire a lignitic fuel to possibly switch to a subbituminous coal because the EGU can fire a higher caloric fuel and have a less strict requirement for Hg emissions. The commenter states that instead of basing the regulation on the way the EGU was designed it is suggested the definition be changed to what the EGU is firing.
Response to Comments 49 - 51: The EPA erred in stating that there were only 30 EGUs in the subcategory; there are 36. The EPA believes it is following the mandate of CAA section 112 by using 12 percent of the data available to the Administrator in calculating the MACT floor (i.e., 2 sources) rather than 5 sources as explained elsewhere in response to comments and in the preamble to the final rule. As noted elsewhere in this document, the EPA has revised the definitions applicable to this source category in a manner that we believe addresses commenters' concerns.
3C - Subcategorization: IGCC (Proposed)
Commenters: 17191, 17775, 17801, 17821
1. Support for IGCC subcategory.
Comment 1: Commenters 17775 and 17821 agree with the EPA's proposal to create a separate subcategory for IGCC units. Commenters state that it is well understood that IGCC units use a process that is fundamentally different from that used by conventional pulverized coal-fired boilers and that, therefore, IGCC units should be placed in their own subcategory. According to the commenters, IGCC units consist of two distinct parts: a gasifier and a combined cycle unit. IGCCs do not burn coal in its solid form, rather the coal is converted to a combustible gas that is then burned in a turbine. The commenters state that the synthetic gas is cleaned and conditioned before being burned in a gas turbine. Commenters agree that if IGCC units are to be regulated under the EGU MACT, then IGCC units belong in a separate IGCC-only subcategory.
Comment 2: Commenter 17402 agrees that subcategorization of IGCC units is warranted because of the unique process employed by such units. According to the commenter, IGCC units are specialized units in which no coal is directly combusted during operation. The commenter assert that instead, coal is first converted to synthetic coal gas (i.e., syngas) comprised of hydrogen (H2) gas and carbon monoxide (CO), which is then burned in a combustion turbine. The commenter states that the combustion turbine drives an electric generator that produces steam, which is then fed into a steam turbine connected to a second electric generator. According to the commenter, because of the fundamentally different design and operation of IGCC units, it is well within the EPA's authority to treat IGCCs as a separate subcategory.
Comment 3: Commenter 17801 states that the EPA has properly proposed a separate subcategory for IGCC units. The commenter states that the EPA proposes to subcategorize IGCC units as a distinct type of EGU for this proposed rule. According to the commenter, the EPA bases this approach due to the differences in process and emission characteristics as compared with conventional coal plants. Commenter agrees with this approach of establishing IGCC as separate subcategory and notes also that it allows for (1) provisions that are necessary to deal with IGCC's unique pre-combustion contaminant treatment and (2) the need for a single standard with unambiguous regulatory provisions as they apply to combustion turbines that are specifically designed for IGCC's coal-derived fuel versus other applications such as natural gas units.
Response to Comments 1 - 3: The EPA has maintained the IGCC subcategory in the final rule.
2. Coal and petroleum coke IGCC are similar.
Comment 4: Commenter 17191 says that in the preamble of the proposed rule, the EPA reports "Based on information available to the Agency, although the fuel characteristics of coal and petcoke are quite different, the synthetic gas products are very similar from both feedstocks." Commenter adds that the Agency cites a DOE 2002 study of the WVPA-owned facility as the source basis for the statement. Commenter supports the determination that the syngas products are similar whether coal or petcoke is used as feedstock. Commenter urges that the MACT rule makes no regulatory emissions distinction (aka "subcategories") for IGCC facilities whether the fuel source is coal, petcoke, or combinations of the two. Commenter emphasizes that blending of coal and petcoke should also be free of subcategorization under the final MACT rule. According to the commenter, if the use of either feedstock represents a similar result, surely a combination of the two will as well.
Response to Comment 4: The EPA proposed standards for one IGCC subcategory. The EPA proposed to define IGCC unit, in part, as an EGU "that burns a synthetic gas derived from coal or solid oil-derived fuel in a combined-cycle gas turbine." We intended this definition to apply to units that burn gas derived from coal or solid-oil derived fuel both alone and in combination and we have revised the definition slightly to make clear our intention by stating that the gas burned is derived from "coal and/or solid oil-derived fuel..." (emphasis added).
3. The EPA should establish a subcategory for IGCC units designed for coals <8,300 Btu/lb.
Comment 5: Commenter 17801 states that a concern with respect to the Hg standard is the absence of a new source subcategory specific to IGCC designed and used for coals with <8,300Btu/lb (characteristic of certain U.S. subbituminous coals and lignite). The commenter asserts that no data or relevant references are contained in the proposed rule that explain the EPA's justification for this exclusion. According to the commenter, the only mention on the effect of feedstock effect is (page 25027) "Based on information available to the Agency, although the fuel characteristics of coal and petcoke are quite different, the syngas products are very similar from both feedstocks" derived from the DOE final report on the Wabash IGCC repowering. The two fuels (coal and petcoke) used had heating values (>10,000Btu/lb) and although major syngas constituents (CO, CO2, H2) are similar, the Wabash data does not include Hg speciation data nor is there relevance of the Wabash data for low rank coal. The commenter states that the EPA determined the floor of 0.04lb/GWh for boilers based on the assumed application of ACI and a criteria of a height to depth ratio (H/D) >3.82  -  a characteristic design parameter for lignite boilers. According to the commenter, IGCC must also be purpose-built to use subbituminous coals or lignite of <8,300Btu/lb to accommodate their specific characteristics of moisture, sulfur and ash content. The commenter states that although such a purpose-built IGCC will similarly use activated carbon for Hg capture, the effectiveness of activated carbon will be dependent on the speciation of Hg following gasification which can be fundamentally different than obtained with bituminous coal or petroleum coke. According to the commenter, the verifiable IGCC design features specific for sub-bituminous and/or lignite are (1) dry feed, (2) ash handling capacity for 10 percent ash or higher, (3) capacity of the acid gas removal system and (4) sizing of the sulfur recovery system. The commenter asserts that these features will exclude operation to any coal other than subbituminous or lignite. The commenter states that we therefore recommend that a subcategory be provided for IGCC for coals with <8,300Btu/lb with a floor of 0.04lb/GW/h and consistent with that allowed for combustion coal units.
Response to Comment 5: The EPA has no information to suggest that an IGCC unit being built to burn synthetic gas derived from a nonagglomerating virgin coal having a calorific value (moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) could not meet the same emission limits as an IGCC designed to burn synthetic gas derived from any other coal or solid oil.
3D - Subcategorization: Oil - Liquid (Proposed)
Commenters: 17316, 17623, 17775, 17870, 17912, 18024, 18025, 18428, 18477, 18502
1. The EPA should establish separate subcategories for distillate and residual fuel oil.
a. Support for further subcategorization by oil type.
Comment 1: Numerous Commenters (17316, 17386, 17621, 17623, 17690, 17725, 17760, 17775, 17803, 17808, 17870, 17912, 18025, 18428, 18477) support the development of separate subcategories for distillate and residual fuel oil.
i. Fuels are different, boiler design is different, boiler operation is different, emissions are different.
Comment 2: Commenters 17316 and 17386 state that distillate oil, and in particular ultra-low sulfur diesel (ULSD) oil, has fuel characteristics closer to that of pipeline gas than to residual oils. The commenter states that the metals, as well as the ash and nitrogen content, of distillate oils are very low, and the sulfur content of ULSD is approximately the same as that of pipeline natural gas (0.5 grains Sulfur/100 scf gas; 15 ppm sulfur on a wt/wt basis). According to the commenter, separating liquid oil-fired EGUs in Tables 1 and 2 into two subcategories (distillate and residual oil) would be consistent with the discussion of subcategory differentiation in the rule's preamble. According to the commenter, Page 25037 of the preamble indicates that the division of a category into subcategories is justified if the two subcategories have very different emissions, which is true for distillate vs. residual oils. Distillate and residual oils are also differentiated by their operating requirements. The commenter asserts that residual oil must be heated to ~120 deg F for operational use, Although no heating of distillate oil is required. The commenter states that residual oil systems normally employ steam atomization, rather than air atomization, for proper combustion. According to the commenter, conversion of a burner system designed for residual oil firing to allow combustion of distillate oil can require significant hardware and control changes.
Comment 3: Commenter 17621 reviewed the ICR data and concludes that emissions of trace metals, including nickel, differ between distillate (No. 2) and residual (No. 6) oil. The commenter states that distillate and residual oil are different grades of fuel oil produced by refining crude oil. According to the commenter, they contain different levels of ash, sulfur and trace metals, and thus would be expected to have different emission characteristics. The commenter asserts that in the proposed rule, the EPA used emissions data from all liquid oil-fired units (excluding sites that co-fired natural gas) to develop the MACT standard for new and existing units. According to the commenter, ICR data from distillate and residual oil were combined to develop proposed regulations for total metals (including Hg), as well as for HCl and HF.
Commenter 17621 states that in developing the MACT standards for the liquid oil category, the EPA grouped emission results from distillate and residual oil together: the seven EGUs used to calculate the MACT floor included five that burned distillate and only one that burned residual oil. According to the commenter, two units from Mitchell Power Station [Office of Regulatory Information Systems (ORIS) Code 3181] were incorrectly reported as firing residual oil when they in fact burned distillate oil. The commenter asserts that figure 2-10 shows the cumulative frequency distribution of total metal emissions from the six test sites firing distillate oil versus the 40+ units firing residual oil. According to the commenter, the "best-performing" 12 percent of the residual oil-fired EGUs have emissions that are nearly ten times higher than those of the five distillate oil-fired units. The commenter states that this trend is directly related to fuel metals content, as none of the distillate oil EGUs employs particulate emission controls. The commenter asserts that in contrast, about one-third of the residual oil sites have some form of PM control. Figure 2-11 shows that emissions of nickel, the major metallic element present in fuel oils, are also far lower from distillate oil-fired EGUs than from residual oil-fired EGUs. (See EPA-HQ-OAR-2009-0234-17621 for Figures 2-10 and 2-11.).
Comment 4: Commenter 17623 states that the EPA should create separate subcategories for distillate and residual oil. Commenter states that distillate oil is a more refined product than residual oil and thus burns cleaner. Commenter notes that due to the high cost of distillate oil, however, six of the distillate oil ICR test sites report capacity factors of less than 1 percent. According to the commenter, se of residual oil, on the other hand, is significantly higher than use of distillate oil, with more than 40 units in the ICR using residual oil. Commenter notes that despite this discrepancy, the EPA grouped emission results from both distillate and residual oil to determine the floor level. Commenter adds that, residual oil-fired units produce more PM emissions, for example, than distillate oil-fired units even though some residual oil-fired units have controls and no distillate oil-fired units in the ICR pool have controls. Commenter states that based on these differences, the EPA should have created subcategories within the oil category for residual and distillate oil.
Comment 5: Several Commenters (17690, 17760, 17803, 17808, 17870, 18025) recommend that the EPA consider subcategorizing residual and distillate oil-fired EGUs. According to the commenters, residual and distillate oils are distinctly different fuels with different physical characteristics, heat content, and emissions profiles. The commenters state that most of the fuel oil used in the electric power sector is residual fuel oil, a general classification for the heavier oils, including Grades No. 5 and No. 6, that remain after the distillate fuel oils and lighter hydrocarbons are distilled away in the refining process. The commenters assert that the lighter distillate fuel oils (No. 1 and No. 2) are characterized by lower viscosities and lower pour points. According to the commenters, these grades of oil are used in most domestic burners and in many medium capacity commercial-industrial burners where ease of handling and ready availability justifies the higher fuel costs.
Several Commenters (17690, 17760, 17803, 17808, 17870, 18025) state that the formal classification of fuel oil grades is specified in ASTM Standard D396-10 (Standard Specification for Fuel Oils), providing a clear basis for subcategorizing the two fuel types. The commenters assert that according to the standard, Grades No. 4 to No. 6 are generally residual fuels of increasing viscosity (resistance to flow) and boiling range. ASTM Standard D396-10 lists the viscosity of residual No. 5 and No. 6 fuel oils in the range of 5.0 to 50.0 square millimeters per second (mm2/s) at 100°C. According to the commenters, in contrast, ASTM Standard D396-10 lists the viscosity of distillate No. 1 and No. 2 fuel oils in the range of 1.3 to 4.1 mm2/s at 40°C. The commenters state that we would also emphasize that the handling and use of residual and distillate fuel oils requires a different set of equipment and technologies. The commenters assert that residual fuel oils must be stored, shipped, and transferred in heated tanks, vessels, and heat traced piping. According to the commenters, further, in order to burn residual fuel oil, it is necessary to break the fuel into small droplets using steam atomization (200 pounds per square inch [psi] steam) or high pressure mechanical atomization (1,000 psi).
Commenter 17870 states that switching from a steam-electric boiler currently designed and operated to burn residual fuel oil to a unit capable of burning distillate oil may also require tile following modifications:
Oil Secondary Containment:
      -According to the commenter, double-wall tank bottoms
      -According to the commenter, double pipe fuel transfer/supply lines outside containment areas
Fuel Pumping System:
      -According to the commenter, new oil transfer/supply pumps. The commenter states that screw pumps are typically used for transferring and supplying Fuel Oil #6 to the boiler. The commenter asserts that due to the low viscosity of light oil, new pumps (e.g., centrifugal or gear pumps) would be required at the tank farm and power block.
Oil Atomization:
      -According to the commenter, new oil atomizer assemblies. The commenter states that heavy oil atomizers are too big for firing light oil with much lower viscosity.
Tanks & Storage:
      -According to the commenter, review of tank venting & lightning protection systems to handle lighter hydrocarbon products present in light oil.
Boiler Performance:
      -According to the commenter, shift heat absorption profile by pushing more heat toward the upper furnace and backend due to changes in flame emissivity of light oil, resulting in higher attemperation (spray) demand. Shifting of the boiler heat distribution may also require boiler surface area upgrades (e.g., superheat and reheat tube metals and possible larger economizer tube banks) in order to maintain current unit generation output.
      -According to the commenter, change flame detection system (e.g., new flame scanner) with greater infrared range to safety pick up brighter flames expected with light oil firing. Current flame scanners have wider ultraviolet range to accommodate darker heavy oil flames and purely UV natural gas flames.
      -According to the commenter, increase in thermal NOX (due to hotter flames), which may upset the expected reduction in fuel NOX (due to lower fuel Nitrogen when firing light oil), resulting in an increase of flue gas recirculation demand and/or higher total NOX emission.
      -According to the commenter, retune boiler controls to account for new fuel, air, FW, drum level, spray and emission characterizations expected with light oil firing.
Several Commenters (17690, 17760, 17803, 17808,17870) state that as a consequence of the mechanical differences between boilers designed for residual oil vs. distillate oils, and between the fuel handling requirements for the different fuels, it is not possible to interchange oil types without significant modifications to the oil storage tanks, transfer pumps, piping and valves, flow control systems, burners and burner control systems. According to the commenters, given the differences between residual and distillate fuel oils, Commenters recommend that the EPA consider subcategorizing between residual- and distillate-oil fired EGUs based on the ASTM specifications or the relative viscosities of the fuels.
Comment 6: Several commenters (17808, 17870, 18025) state that the EPA lists 147 EGU boilers in the ICR database (Part I) that rely on residual fuel oil. According to the commenters, the EPA lists only seven EGU boilers that rely on distillate fuel oil: Harding Street (9 and 10), Eagle Valley (1 and 2), and Mitchell Generating Station (1, 2, and 3). The commenters states that three of these units (Mitchell Generating Station Units 1-3) are listed for retirement in 2013. Eagle Valley Units 1 and 2 are listed for retirement in 2017. The commenter asserts that other EGU boilers will burn limited quantities of distillate fuel oil for boiler light-off or other purposes, with fuel handling equipment separate from the residual oil equipment, although using another fuel, like natural gas, for the production of electricity. According to the commenter, under this option, given that the total universe of distillate oil-fired EGUs would include fewer than 30 units, the CAA directs the EPA to calculate the MACT floor based on a minimum of five units.
Comment 7: Commenter 17725 requests that the EPA establish a total metals emission based on the subcategorization of DFO and RFO units or if the limit is based on a dataset equal to the 12 percent top performers of the universe of the 154 oil-fired EGUs rather than 12 percent of the tested oil-fired EGUs.
Comment 8: Commenters 17775 and 18428 note that the EPA has not proposed to subcategorize oil-fired units, and that EPRI's review of the ICR data shows statistically significant differences in metal HAP emissions depending on whether an oil-fired unit burns distillate fuel oil (No. 2) or residual oil (No. 6). Commenters state that these differences justify subcategorization by fuel oil type for metal HAP emissions.
Comment 9: Commenter 18024 states that No. 6 oil-fired boilers and distillate oil-fired boilers are fundamentally different emission sources, with different physical and operating characteristics as well as different emission controls, and thus should be regulated differently. According to the commenter, distillate oil-fired EGUs are not physically capable, nor are they permitted, to fire No. 6 oil and vice versa. The commenter asserts that fuel oil receiving, storage, heated recirculation (in the case of No. 6 oil), fuel forwarding systems, burners, control systems and emissions monitoring and reporting systems for these two fuels are not compatible and are not interchangeable. The commenter states that they are therefore different and distinct source categories that should not be considered "similar sources" for purposes of setting MACT Floors.
The commenter states that in addition, best available control technology (BACT) for PM from distillate oil-fired boilers is the use of ultra-low sulfur distillate oil (ULSD), Although BACT for PM for a new No. 6 oil-fired unit would require electrostatic precipitators (ESPs). The commenter asserts that these two source types differ significantly in the type and degree of control technology needed to achieve state-of-the-art emission levels.
Comment 10: Commenter 17912 states that the combustion and emissions profiles of No. 2 and No. 6 fuel oil differ significantly, including heating value, impurities and other constituents. According to the commenter, the EPA should therefore account for those differences by subcategorizing oil-fired EGUs, acknowledging that there are significant design and operational differences that warrant additional subcategorization under CAA section 112(d) (1).18. The commenter states that these differences impact the feasibility, cost and effectiveness of control technology. The commenter asserts that the EPA has provided no explanation for treating these fuels the same. The commenter states that indeed, none of the discussion in the preamble to the proposed rule concerns the merits of additional subcategorization of oil-fired units.
ii. Combined limits are unachievable for residual oil-fired units.
Comment 11: Commenters 17316 and 17386 state that by combining distillate and residual oil into a single MACT category effectively results in MACT standards that cannot be satisfied by a boiler firing residual oil without substantial add-on controls. As a result, Commenters request that the EPA separate liquid oil-fired EGUs into 2 subcategories, consistent with that done for coal-fired EGUs.
Comment 12: Commenter 17623 suggests that the EPA create separate subcategories for oil-fired units that distinguish between residual and distilled oil. The commenter states that in so doing, the EPA would render the standards more achievable for distinct subcategories of units and reduce the number of potential plant closures, although still advancing the goal of reducing overall emissions.
Comment 13: Commenter 17760 states that the proposed Liquid Oil subcategory is not sufficient for all liquid oil-fired units because it does not account for the significant differences between distillate- and residual-fired units. According to the commenter, the 2010 ICR data upon which the proposed limit is based includes six units burning distillate oil, all but one of which set the MACT floor. The commenter states that despite the disproportionate reliance on residual oil among the sector as a whole, five distillate oil-fired EGUs were included in the calculation of the MACT floor for Total HAP Metals. The commenter asserts that therefore, despite the EPA's intention of selecting a random sample of units, in fact the 2010 ICR database is biased toward very low-emitting units that burn distillate fuel oil. The commenter states that residual oil-fired EGUs represent more than 70 percent of the units in the MACT floor for the Liquid Oil subcategory. The commenter asserts that in contrast, nationwide, distillate oil-fired EGUs represent less than five percent of oil-fired EGUs. According to the commenter, the CAA requires the Administrator to establish standards that she "determines [are] achievable for new or existing sources in the category or subcategory to which such emission standard applies." The commenter states that CAA section 112(d)(1). According to the commenter, the EPA's proposal to establish a single liquid oil subcategory is inconsistent with this requirement. The commenter states that the overwhelming majority of the sources in the source category cannot achieve the resulting emissions standards, due to the insurmountable differences between distillate- and residual-fired units.
Comment 14: Commenter 18024 states that No. 6 and distillate oil-fired units are, and should be treated as, two separate and distinct subcategories. According to the commenter, the proposed MACT floor emission limits applicable to all liquid oil-fired boilers cannot all be achieved by any identified No. 6 oil-fired boiler (based on the ICR data set) because, for several of the regulated pollutants, the MACT Floor calculation was dominated by results from distillate oil-fired units.
Commenter states that combining boilers firing these two fuel types into a single subcategory effectively eliminates any potential for existing No.6 oil-fired boilers (controlled or uncontrolled) to comply with MACT floors without having to be substantially reconstructed for distillate oil-fired operations. The commenter states that we do not believe that the MACT requirements of the CAA were intended to establish MACT floors that require reconstructing existing boilers to a physically different boiler type in order to achieve MACT floor emission levels. According to the commenter, the EPA's proposed EGU MACT Rule cites the "extensive changes" to a liquid oil-fired EGU that would be required to allow it to burn solid oil-derived fuel as the basis for establishing two subcategories of oil-fired EGUs. See 76 Fed. Reg. 24976, 25036 (May 3, 2011). The commenter asserts that likewise, the extensive changes to a No.6 oil-fired EGU that would be required to allow it to burn distillate oil justify splitting the liquid oil-fired EGU subcategory into "Existing No. 6 oil-fired EGUs" and "Existing distillate oil-fired EGUs."
According to the commenter, by combining these two subcategories into a single calculation that no existing No. 6 oil-fired EGU can meet, and offering no emission control technology that has been demonstrated in practice to continuously achieve the proposed EGU MACT limits, the EPA is essentially barring continued operation of existing No. 6 oil-fired EGUs in the U.S., including the best controlled existing No.6 oil-fired boilers. The commenter states that MACT Floors should not be used to eliminate whole classes of existing EGUs through mathematical floor calculations based on data from uncontrolled units and combining boiler subcategories that are not capable of accommodating a different fuel.
Comment 15: Commenter 18428 states that emission limits that are based on a mixture of distillate and residual oil-fired units will be difficult - if not impossible - for residual oil-fired units to meet even with pollution controls.
Response to Comments 1 - 15: The EPA has reviewed the data and determined that its proposed position of no distillate vs. residual oil subcategory is correct. Commenters had noted that the EPA's MACT Floor Analysis spreadsheet had erroneously assigned the oil type used during testing for some boilers. The EPA reviewed the data and determined that the submitting companies had miss-entered the data, or had indicated that two types of oil were fired in different parts of the 2010 ICR responses. The EPA contacted all of the companies with oil-fired EGUS in the 2010 ICR to confirm the oil used during testing. Upon review of these data, it became apparent that units using residual oil with ESPs or distillate oil were the best-performing units for PM and the HAP metals. Further, although emissions of HAP from distillate oil-fired EGUs are generally lower than those from residual oil-fired EGUS, EGUs burning distillate oil appeared to have higher emissions of some HAP but lower emissions of others. In addition, as explained elsewhere in this document, the EPA does not believe it appropriate to exclude distillate oil from regulation under the final rule because the Agency did not make a distinction when listing the oil-fired EGUs.

The EPA disagrees with commenters that by providing the distillate vs. residual oil subcategories as requested, the resultant standards would be more achievable. Were the EPA to subcategorize distillate oil from residual oil, the users of distillate oil would have no means of compliance other than obtaining "compliance" oil from their distributor (which was not indicated as an option by any commenter) or converting to natural gas and being removed from the subcategory. With no further subcategorization, oil-fired EGUs are likely able to comply with the standards by installing an ESP or burning distillate oil. Therefore, the EPA is not establishing separate subcategories for distillate and residual oil-fired units in the final rule.

In addition, as described in the Supporting Statement for the 2010 ICR, the EPA was unable to identify the pool of potential best-performing oil-fired EGUs when selecting units for testing. The EPA does not believe it has identified all the best performing EGUs for any of the HAP emitted from oil-fired EGUs so we developed the MACT floors for oil-fired EGUs based on the top 12 percent of the available data rather than on 12 percent of the universe of oil-fired EGUs.
b. Opposition to further subcategorization by oil type.
Comment 16: Commenter 17648 states that the EPA should not subcategorize liquid oil-fired EGUs based upon different grades of liquid oil. The commenter states that although different grades of liquid oil may vary in their heat contents or viscosities, there is no indication in the rulemaking record that any physical distinction among units burning different grades of liquid oil (such as No. 2 versus No. 6 oil) affects the nature or characteristics of emissions in a way that impacts the availability of controls. The commenter states that both No. 2 and No. 6 oil-fired units can apply similar control technologies to reduce HAP emissions, and units firing these fuels do not have physical distinctions that prevent controls from operating effectively. The commenter asserts that moreover, distinctions between different varieties of liquid oil are distinctions grounded in fuel type, not in class, size, or type of source. According to the commenter, fuel switching is an appropriate control technology and is available for liquid oil-fired sources. No. 6 fuel oil contains higher levels of contaminants, including HAP, than No. 2 fuel oil, and since a regulated entity can readily burn cleaner No. 2 fuel oil in lieu of No. 6, it is inappropriate to subcategorize based on the distillation fraction of the liquid oil. The commenter states that , grade of liquid-oil fuel does not provide a reasonable basis for subcategorizing various groups of liquid oil-fired EGUs.
Response to Comment 16: The EPA agrees with commenter and, as noted above, has not subcategorized distillate vs. residual oil in the final rule.
2. The EPA should establish a non-continental liquid oil subcategory.
Comment 17: Commenters 17760 and 18477 state that if the EPA continues to believe that oil-fired units should be regulated under CAA section 112, the EPA should include a "non-continental liquid oil" subcategory in the final rule. According to the commenter, establishing a subcategory for non-continental units is consistent with the approach the EPA has taken in past rulemakings, including the final rule establishing MACT standards for Industrial, Commercial, and Institutional Boilers and Process Heaters. See 76 FR 15608, 15635 (March 21, 2011) ("Boiler MACT"). The commenter states that non-continental liquid oil-fired EGUs face the same unique challenges and limitations as non-continental boilers. The commenter asserts that non-continental EGUs have little or, in the case of group member Hawaiian Electric Company, no access to natural gas, minimal control over the quality of available fuel, and disproportionately high operational and maintenance costs.
Comment 18: Commenter 18502 states that a separate subcategory should be established for EGUs located in non-continental areas (such as the islands of Hawaii, Puerto Rico, and Guam). The commenter asserts that being a non-continental state places Puerto Rico at a time disadvantage over the continental states. According to the commenter, there are no "local" materials or equipment vendors and the purchase of emission control equipment is not as straight forward as for continental facilities. The commenter states that moreover, the prevailing atmospheric conditions make the island's environmental conditions to be extremely different than those in the continental U.S. According to the commenter, the EPA should establish a subcategory for non-continental oil-fired EGU subcategory based on the unique operating and environmental issues in these areas.
Comment 19: Commenter 17868 states that oil-fired units in Alaska, Puerto Rico, American Samoa, and Guam require special considerations. Commenter supports a waiver for oil-fired units in Guam, Puerto Rico, Hawaii, and Alaska. Commenter has member utilities in locations that are uniquely isolated including islands, or areas of the country that are not connected to the national utility or industrial infrastructure. According to the commenter, these locations have special needs for delivery of pollution control devices, installation, working around seasonal loads, scheduled outages and extreme economic impacts due to extended outages for installation.
Commenter 17868 supports the petitions presented by Guam, Puerto Rico, Hawaii, and Alaska to exempt their oil-fired power plants from the new nickel limits. Commenter defers to that petition as to the specific treatment. Commenter notes that because of the relationship between investor, electric coop and public power (municipal or state owned utilities), we believe the language offered by the petitioners should cover all utilities on those "islands" (including Alaska, which functions as an island due to its isolation).
Comment 20: Commenter 18477 expresses concern that the proposed rule mistakenly assumes that switching to natural gas or co-firing with natural gas is a valid and cost-effective compliance option for liquid oil-fired units; however, there is no natural gas or liquid natural gas resource in Hawaii. According to the commenter, as a remote island utility, Hawaiian Electric does not even have access to the small amount of refinery gas available to the refiners addressed by the Boiler MACT.
Commenter 18477 states that all oil-fired EGUs operating in Hawaii, Guam, and Puerto Rico exclusively combust residual fuel oil to generate electricity, and all are limited by the crude slates of their fuel suppliers. According to the commenter, Hawaiian Electric's contracts with on-island refineries contain fuel specifications for factors such as sulfur content, pour point, flash point, API gravity and viscosity, which the refiners are able to meet primarily by blending and some sulfur removal. The commenter asserts that however, they do not and cannot economically control for metal content. According to the commenter, as the Agency noted in the preamble to the Boiler MACT, the quality of the fuel produced by non-continental refineries is limited by the quality of the crude slate used in the refining process (76 FR 15,635).
Commenter 18477 states that it is not feasible for non-continental liquid oil-fired EGUs to comply with the proposed numeric emission standards based on their survey of equipment control vendors. According to the commenter, the vendors surveyed uniformly responded that they cannot guarantee their equipment can meet the proposed HAP limits for liquid oil-fired EGUs. The commenter states that the ability to achieve HAP control with residual fuel oil applications and ESPs or multi-cyclones in utility type boilers is currently being researched and is not a commercially demonstrated technology. The commenter asserts that bag-houses are not a suitable technology for particulate matter control for residual fuel oil applications. The commenter asserts that reputable dry and wet ESP suppliers, such as Alstom, Babcock & Wilcox, PECO, Siemens, Southern Environmental Inc., Clyde Bergemann, Hamon Research-Cottrell, and Allied Environmental Solutions, Inc. were contacted to determine their current position on providing ESP guarantees to meet the proposed emission limits for liquid oil-fired units. According to the commenter, the companies that have provided feedback thus far will not guarantee that currently available technology can achieve the proposed emissions limits for residual fuel oil applications.
Comment 21: Commenter 18502 states that because they are a non-continental facility, the availability of alternate fuels is limited. According to the commenter, there are no fossil fuel resources on the island (Puerto Rico). The commenter states that the fuels presently used are delivered by ocean tankers, which is a possible source chloride contamination of the fuel as indicated by the erratic HCI measurements made during the ICR testing (HCI emissions varied by a factor of 20).
Commenter 18502 states that they have a long term plan for converting their steam generators, CCs, and CTs to co-fire natural gas (NG), but the infrastructure needed to deliver natural gas does not currently exist. The commenter states that the long term plan involves participation in expansion of a local LNG facility operated by EcoEiectrica and actively pursuing installation of a NG pipeline. According to the commenter, engineering evaluations and permitting for the pipeline is underway, but completion has not been established yet.
a. The EPA has sufficient data to establish a Non-Continental Liquid Oil-Fired subcategory.
Comment 22: Commenters 17760 and 18477 state that when the EPA developed the proposed rule, it had only received ICR data from a single non-continental utility  -  Hawaiian Electric. The commenter states that although the EPA may have determined that such limited information was an insufficient basis on which to establish a non-continental subcategory, since issuance of the proposed rule, the Agency has received 2010 ICR data from the two other island utilities with liquid oil EGUs  -  the Puerto Rico Electric Power Authority ("PREPA") and the Guam Power Authority ("GPA"). According to the commenter, the EPA now has 2010 ICR test data from 15 of the 31 liquid oil-fired EGUs operated by non-continental utilities, including GPA's Cabras Unit 1 and PREPA's San Juan Units 7, 8, 9 and 10, Costa Sur Units 3 and 6, and Aguirre Units 1 and 2. The commenter asserts that the additional data provided by PREPA and GPA is more than sufficient for the EPA to establish a non-continental liquid oil subcategory. The commenter states that the proposed subcategory would consist of a total of 31 units: 14 from Hawaiian Electric; 14 from PREPA; and three located on the island of Guam (two units owned/operated by GPA and a third GPA-owned unit operated by Pruvient Energy).
b. Island utilities have minimal control over fuel quality.
Comment 23: Commenter 17760 states that many island utilities have little or, like Hawaiian Electric no, access to natural gas or liquid natural gas supply. The commenter states that as a result, the combustion of liquid fuel oil is unavoidable. According to the commenter, all oil-fired EGUs operating in Hawaii, Guam and Puerto Rico combust residual fuel oil exclusively and all are limited by the crude slates of their fuel suppliers. Island utilities can contract with suppliers for certain fuel specifications, such as sulfur content, pour point, flash point, API gravity and viscosity, which the refiners are able to meet primarily by blending and some sulfur removal during the refining process. The commenter asserts that however, the suppliers do not and cannot economically control for metal content. The commenter states that as the Agency noted in the preamble to the Boiler MACT, the quality of the fuel produced by non-continental refineries is limited by the quality of the nearby crude slate used in the refining process. 76 FR 15,635. According to the commenter, the crude slate feeding the refinery determines the HAP metal content of the residual oil produced. The commenter states that because island utilities are dependent on local sources of fuel, they are equally limited by these factors.
Comment 24: Commenter 18502 states that the EPA should re-examine the logic of establishing a MACT floor for a source subcategory for which emissions variability is the result of un-measureable differences in fuel quality, and then setting MACT.
c. Establishing a Non-Continental Liquid Oil Subcategory is consistent with previous EPA rulemakings.
Comment 25: Commenters 17760 and 18477 state that establishing a subcategory for non-continental units is consistent with previous Agency rulemakings. The commenters assert that in those rulemakings, the EPA recognized that facilities operating on remote island locations or other non-continental areas face a unique set of challenges that do not apply to their mainland (continental) counterparts. The commenters state that most recently, the Boiler MACT established a separate non-continental subcategory. See 76 FR 15635 ("EPA agrees that the unique considerations faced by non-continental refineries warrant a separate subcategory for these units."). The commenters state that similarly, several NSPS contain separate standards for non-continental units: 40 CFR Part 60, Subparts Da (Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978); Db (Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units); Dc (Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units); and KKKK (Standards of Performance for Stationary Combustion Turbines).
d. Non-continental units have limited compliance options.
Comment 26: Commenters 17868 and 18502 believe that a separate subcategory should be established for EGUs located in non-continental areas (such as the islands of Hawaii, Puerto Rico, and Guam), and potentially for continental areas that are not interconnected with other utilities and have limited compliance options due to remote locations. Commenter 17868 believes such a subcategory should apply to Alaska also.
Comment 27: Commenter 18477 states that Hawaii's RPS has two significant ramifications for commenter's ability to comply with the proposed rule. The commenter asserts that first, modification of a large percentage of commenter's generation fleet to use renewable fuel sources has the potential to substantially reduce HAP emissions. The commenter states that these modifications, however, will not be completed prior to the EGU MACT compliance date. The commenter asserts that second, compliance with both the Hawaii RPS and the EGU MACT will require massive capital investments. According to the commenter, it would be unfair to require commenter and its customers to invest in both, particularly when current resource plans indicate the retirement of at least four EGUs with relatively low capacity factors within 8 to 10 years. The commenter states that installation of costly control technology on these units to comply with the EGU MACT for the relatively short time frame before retirement would also represent significant economic inefficiency. The commenter asserts that it estimates that installation of emission control equipment for Hg, HCl, HF, and PM would cost at least $696 million, based on preliminary quotes provided by engineering consultants and equipment vendors. According to the commenter, to date, no control equipment vendor will provide performance guarantees, so this cost estimate does not address the risk associated with failure to comply with the proposed HAP emission limits. The commenter states that it is extremely difficult for companies to develop a cost-effective compliance plan without control equipment vendor guarantees. The commenter asserts that vendor guarantees allow companies to plan for prudent capital investments in control technology. The commenter asserts that without these guarantees, it is facing the untenable possibility that it will not be able to comply with the proposed standards despite the Company's best efforts and significant capital investments. The commenter states that accordingly, it urges the EPA to exercise its discretion and establish work practice standards for non-continental liquid oil-fired units.
Commenters 18433 and 19213 disagree with the assumption that all coal and fuel-oil units can be used with available control technologies. The commenters state that such fuel switching from one fuel type to another or fuel blending can be expensive and facilities in small municipalities or Guam are restricted in their fuel choices and must rely on oil currently.
Response to Comments 17 - 27: At proposal, the EPA did not have all of the data from liquid oil-fired units in non-continental areas (e.g., Guam, Puerto Rico) and solicited comment on whether a subcategory should be established, based on the data to be received, for non-continental oil-fired EGUs. The EPA agrees that the unique considerations faced by non-continental EGUs (e.g., limited access to alternative refinery supplies) warrant a separate subcategory for these units. The EPA is finalizing a non-continental subcategory for oil-fired EGUs for units in Guam, Hawaii, Puerto Rico, and the U.S. Virgin Islands. The EPA is not aware of any liquid oil-fired EGUs in any of the other U.S. territories that meet the CAA section 112(a)(8) definition but, if there are such units, they would also be part of the non-continental subcategory. The EPA has now received the late data and confirmed that no non-continental liquid oil-fired EGUs are in the MACT floor pool for PM. Therefore, based on those data, the EPA has established emission limits for the non-continental liquid oil-fired EGU subcategory in the final rule. The EPA believes that units in this subcategory will comply through the use of cleaner oils or, for PM, through the installation of an ESP (non-continental liquid oil-fired EGUs may also use the 1 percent moisture-in-oil compliance option). The EPA finds no merit in the comment that Alaska should be included in this non-continental subcategory.
3E - Subcategorization: Oil - Solid (Proposed)
Commenters: 17925, 19536, 19537, 19538
1. Opposition to a separate subcategory for petroleum coke.
Comment 1: Several commenters (19536, 19537, 19538) state that it appears that the EPA has proposed to include EGUs that burn other fuels with coal to be considered coal-fired EGUs. The commenters state that this is consistent with the definition of "coal-fired electric utility steam generating units" in the NSPS, Subpart Da (40 C.F.R. §60.41Da). Commenters support such a determination by the EPA. Coal-fired units that blend with pet coke do so in varying amounts throughout a year of operations. According to the commenters, it would be administratively impracticable to set separate MACT limits for units that intermittently burn pet coke with coal.

Commenters (19536, 19537, 19538) state moreover, that even for units that burn 100% pet coke, there is no justification for putting such units in a separate subcategory from those that burn coal or coal and pet coke. According to the commenters, all of these units are "similar sources" to coal-fired EGUs. See 40 C.F.R. section 63.41. The commenters state that specifically, such coal-fired and coal/pet coke-fired EGUs have comparable HAP emissions, are structurally similar in design and capacity, and the HAP emissions can be controlled with the same control technology [Commenters provided examples].

Commenters (19536, 19537, 19538) state that the EPA has not put forth any rationale for identifying a separate subcategory for pet coke-fired EGUs (i.e., EPA's "solid oil-derived fuel-fired EGU" category). According to the commenters, because the HAP emissions from pet coke-fired EGUs can be controlled with the same control technology and methods as can be applied at those EGUs that burn coal, there is no justification for a separate category for pet coke burning EGUs. Commenters state that the EPA should not, therefore, create separate standards for pet coke units.
Comment 2: Commenter 17925 states that petroleum coke should be placed in the coal subcategory. Commenter's Madison 3 unit is designed to burn coal from two subcategories and petroleum coke. Commenter is unclear what subcategory Madison 3 as a unit fits into under the proposed rule since the unit can burn any of the above fuels alone or in a mix. Commenter is also unclear what would trigger a subcategory change, if indeed a unit can change subcategories. According to the commenter, any subcategory changes could cause confusion and the pollution controls, injection rates and operating procedures could require change if the unit changes subcategories. The commenter asserts that it would not make sense or be practical to pro-rate limits based on the percentage fuel a unit burns, i.e., rule is unclear as to what emission limit applies when combusting combinations of fuels. Commenter strongly suggests that the limits in the coal subcategory should apply once "any¨ coal is burned. Commenter would like to maintain the fuel flexibility so that they can provide their customers with low cost and reliable power, however, the proposed rule threatens fuel flexibility and low cost power.
Several commenters (19536, 19537, 19538) state that the EPA has included EGUs that burn blends of coal and pet coke in the HCl MACT floor determination for existing pet coke burning EGUs. The commenters state that specifically, the Northside Generating Station units and the Manitowoc units burn coal in addition to pet coke. According to the commenters, such units should be considered coal-fired EGUs under the EPA's proposed definition of coal-fired electric utility steam generating unit in section 63.10042. 76 Fed.Reg. at 25122. The commenters state that it is not clear why these units were included in the pet coke MACT floor analysis. The commenters assert that further, it is not known whether the units were burning any coal at the time of the tests but, regardless, it does not make sense to include these units that should be covered under the coal-fired EGU MACT requirements rather than under the pet coke (solid oil-derived fuel) EGU MACT requirements.
Response to Comments 1 - 2: Coal- and oil-fired EGUs were separately listed in 2000 and it is reasonable to maintain such units in different subcategories. In addition, commenters' assertions that the emissions characteristics between coal and solid oil-derived fuel are the same are incorrect. Coal and oil, including solid-oil derived fuel, contain different amounts and different pollutants and combustion of those fuels leads to different emissions of HAP for that reason. For example, Ni is found at much higher levels in oil and Hg is found at much higher levels in coal; thus, oil combustion will cause more emissions of nickel and coal combustion will cause more emissions of Hg. For these reasons, the EPA believes it reasonable to maintain coal and solid-oil derived fuel (e.g., petroleum coke) in separate subcategories.
We also maintain that it is reasonable to establish different subcategories in this rule than those contained in the Industrial Boiler NESHAP, because the industrial boilers rule regulates a more diverse universe of units burning fossil and other fuels and this rule regulates only fossil fuel-fired EGUs.
We have clarified the definitions in the final rule such that we believe commenter's concerns are addressed with regard to potential subcategory switching.

3F - Subcategorization: New suggested categories
Commenters: 16513, 16849, 17316, 17386, 17608, 17621, 17623, 17627, 17648, 17689, 17690, 17712, 17716, 17718, 17724, 17725, 17730, 17731, 17732, 17735, 17736, 17739, 17754, 17756, 17757, 17758, 17760, 17761, 17767, 17774, 17775, 17801, 17803, 17805, 17808, 17816, 17817, 17818, 17820, 17821, 17826, 17843, 17867, 17868, 17870, 17876, 17885, 17898, 17912, 17920, 18014, 18018, 18025, 18031, 18032, 18033, 18034, 18428, 18429, 18447, 18450, 18539, 18644, 19114, 19120, 18023
Commenters offered a number of alternative subcategorization approaches. These suggested subcategorization alternatives fit generally into the groups noted below.
1. The EPA should develop subcategories for high sulfur or high chlorine coal.
Comment 1: Commenter 17739 states that the EPA should establish an existing source acid gas subcategory for high sulfur or high chlorine coals since the same factors that the EPA relied on to support a lignite subcategory for Hg are also present in the high sulfur or high chlorine coal context. Commenter states that the data indicate that even well-controlled units burning high sulfur coals would not be in the top performers for acid gases even at removal rates of 95 or 96%. Commenter adds that, in addition, absent such a subcategory, about 12% of coal deliveries (2005 data), and the vast majority of coal shipped from that states of Indiana, Ohio, and Illinois (2008 data), would become unusable.