Commenter 17648 states that the EPA's interpretation of the CAA is reasonable. Even assuming section 112 were ambiguous, the EPA's proposal to create MACT standards for EGUs without making any distinction between "major" and "area" sources is a reasonable interpretation consistent with the statute's purpose entitled to substantial deference under Chevron. Differentiating major source and area source EGUs for purposes of setting emissions standards is inappropriate in light of the 2000 Finding, re-affirmed in this proposed rule, regarding the threat posed by the absence of regulation of HAP emissions from EGUs. The Finding is based upon studies whose conclusions regarding the impacts from EGU emissions do not depend upon any relevant distinction between major source and area source EGUs.
Commenter 17648 continues that Congress distinguished "area sources" in section 112 in at least two ways: (1) Congress created separate prerequisite criteria for listing area source categories that are not required to list categories of major sources, and (2) Congress authorized the Agency to establish less stringent emission standards for area sources based upon GACT. Neither of these distinctions has any relevance in regulating EGUs under CAA section 112. First, according to commenter, the separate listing provision cannot apply. Commenter maintains that ssection 112(n) does not permit the EPA to avoid regulating "area source" EGUs after making the Finding. The language of section 112(n)(1)(A) is mandatory, not permissive. Moreover, it would be an odd bit of statutory construction to require the EPA to separately make a determination under CAA section 112(c)(3) that "area source" coal-fired or oil-fired EGUs "present" a threat of adverse effects to human health or the environment (by such sources individually or in the aggregate) . . . " after determining in accordance with section 112(n)(1)(A) that it was appropriate and necessary to regulate EGUs under CAA section 112. Once the EPA made the Finding, it would be inappropriate to read the statute as requiring the EPA to make an additional determination under CAA section 112(c)(3) before it could regulate "area source" EGUs.
Commenter 17648 states, second, the purpose behind providing the EPA with discretion to establish GACT standards for area sources is entirely inapposite to EGUs. When Congress amended section 112 in 1990 to create a technology-based requirement that the EPA promulgate MACT standards for regulated source categories, on a more expeditious timeframe than contemplated in the pre-1990 CAA, it did so to spur the EPA into regulating HAP emissions. However, Congress was concerned that the EPA might delay regulating relatively smaller sources of HAP emissions due to the potential costs those regulations might impose, and therefore provided the Agency with discretion to adopt GACT standards that would be less stringent than MACT. This legislative purpose behind differentiating area sources is inapplicable to EGUs, which are statutorily defined based upon their output capacity rather than their HAP emissions and which required a finding before the category could be regulated. No electric generating unit with a nameplate capacity greater than 25 MW is a "small" source of emissions, like a dry cleaner or an institutional boiler. Rather, EGUs are the largest source of HAP emissions in the United States. Any "small" EGUs already have been segregated from regulation by the statute's definition of EGUs. Moreover, some "major source" EGUs have relatively small nameplate capacity but no emissions controls and some "area source" EGUs are relatively large generators that are well controlled. Therefore, the size distinction that underlies the statutory distinctions between major and area sources is inapplicable to EGUs.
b. Separate regulation of major and area sources would produce absurd results.
Comment 2: Commenter 17648 states that treating "major source" EGUs as distinct from "area source" EGUs for purposes of setting emissions standards in the Toxics Rule would produce absurd results. Regulating "major source" and "area source" EGUs separately under CAA section 112 would undermine the very purpose of setting MACT emission standards. Segregating "major source" and "area source" EGUs would have the perverse effect of eliminating some of the best performing sources from the MACT pool of sources that constitute the "best performing" twelve percent. Many of the best performing sources have employed control technology that brings their emissions below the major source threshold, despite the fact that they are larger units. As a result, if the EPA created standards for "major source" EGUs based only upon those units, the MACT standards for "major source" EGUs would be less stringent for each of the pollutants than proposed in this rule. At the same time, the less polluting sources, the "area source" EGUs, could face limits more stringent than those proposed in the rule.
Commenter 17648 states that this absurd result is evident from analysis of the ICR database. For example, if one divides coal-fired EGUs in the ICR database into hypothetical "major" and "area" source categories using HCl emission data in the database, and recalculates separate MACT floors for each of these two source categories, then the floors and limits for HCl, mercury, and PM for "area source" EGUs would all be lower (i.e., more stringent) than the limits the EPA proposes for coal-fired EGUs, with HCl being an order of magnitude lower. By contrast, the limitations for all three pollutants for "major source" EGUs would all be higher (i.e., less stringent) than those the EPA proposes for coal-fired EGUs, with the mercury limit being an order of magnitude higher. Because the limits are based upon emissions per Btu rather than absolute size of the unit, this confirms that many of the best controlled sources would be "area sources" only because of the level of control that they are achieving.
Commenter 17648 states, thus, such a division would create an absurd result contrary to Congressional intent to compel sources to use the "maximum" control technology available. The EPA is therefore right to reject any approach that would treat EGUs differently based upon the relative mass of HAP they emit.
c. There is no significant difference between major and area source EGUs.
Comment 3: Several commenters (19536, 19537, 19538) state that there is no significant difference between major and area sources that would warrant exercise of the EPA's discretion to establish different standards for area sources. The EPA's proposed Utility Air Toxics Rule properly sets MACT emission standards for all coal- and oil-fired EGUs greater than 25 megawatts ("MW"), without further distinguishing between "major" sources and "area" sources.
Commenters state that the CAA does not require, or even promote, different emission control standards for major and area source EGUs that have an electric generation capacity of greater than 25 MW. For purposes of HAP regulation under CAA section 112, the CAA defines "electric utility steam generating unit" as "any fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale." 42 U.S.C. § 7412(a)(8). The EPA has, thus, appropriately limited the scope of the Utility Air Toxics Rule to EGUs as defined by section 112. The CAA separately defines "major source" as "any stationary source . . . that emits or has the potential to emit considering controls . . . 10 tons per year or more of any hazardous air pollutants or 25 tons per year or more of any combination of hazardous air pollutants." 42 U.S.C. § 7412(a)(1). And the CAA defines "area source" simply as "any stationary source that is not a major source." 42 U.S.C. § 7412(a)(2). Unlike the case-by-case provisions of CAA section 112(g), which apply only to major sources, CAA section 112(d)(1) imposes on the EPA a nondiscretionary duty to promulgate HAP emission standards that apply to both major sources and area sources. 42 U.S.C. § 7412(d)(1). The MACT emission standards required and defined in CAA section 112(d)(2) and (3), respectively, likewise are not limited to "major sources," and apply presumptively to new and existing major and area sources alike. 42 U.S.C. § 7412(d)(2), (3). As an alternative to this presumption, CAA section 112(d)(5) provides the EPA discretion to promulgate GACT standards in lieu of MACT standards for area sources. After reviewing the substantial record in this rulemaking, the EPA has correctly determined that major and area source EGUs greater than 25 MW have similar HAP emissions and use the same control technologies and techniques to reduce HAP emissions. Thus, the record demonstrates that there is no technical basis for distinguishing between major and area source EGUs for purposes of establishing HAP emission control standards under CAA section 112(d).
Commenters state that experience in recent permit proceedings for large new EGUs under the case-by-case MACT regime of CAA section 112(g) confirms the basis and emphasizes the importance of the EPA's decision to hold both major and area source EGUs to MACT standards pursuant to CAA section 112(d)(2) and (3). These permit proceedings further demonstrate that: (1) major and area sources are not appreciably different with respect to boiler size, HAP emissions and pollution controls; and (2) setting different standards based on such a distinction would further encourage recent attempts by large, highly polluting HAP sources to evade MACT emission standards for the HAP of greatest concern by claiming minor (or area) source status. In fact, distinguishing between major and area sources, and holding the latter to less rigorous GACT standards, would undermine the HAP program for EGUs.
Commenters state that following the D.C. Circuit Court of Appeals vacatur of the EGU Delisting Rule and Clean Air Mercury Rule in New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008), several proposed new EGUs have attempted to circumvent the case-by-case MACT requirements that apply to new and expanded major HAP sources under CAA section 112(g) by claiming that the units are minor sources of HAP and, as such, are exempt from the case-by-case MACT requirements of section 112(g). Table V-1 [in document] summarizes pertinent design details for five EGU projects that have claimed minor HAP source status in the wake of New Jersey v. EPA. As this table illustrates, each of these sources is a large EGU and, individually and as a class, they include the full array of pollution control technologies found on major source EGUs. Thus, recent experience supports the EPA's determination that "similar . . . control technologies are found on both major and area sources greater than 25 MWe."
Comment 4: Commenter 17648 concludes that even if section 112 authorizes the EPA to consider major source EGUs as distinct from area source EGUs, there is no basis for the EPA to make that distinction in the Toxics Rule. Assuming that the EPA could distinguish between major source and area source EGUs for purposes of setting section 112 emission limitations, the actual emissions data from EGUs counsel against doing so. Although section 112(d)(5) authorizes GACT standards for area sources, it does not require them. Here, GACT standards would be inappropriate. When the EPA conducts GACT determinations for categories of area sources, the Agency identifies control technologies and management practices that are generally available to area sources, and determines whether those same technologies are available to major sources, to evaluate whether the control technologies generally are transferrable and available. EGUs greater than 25 MW have similar HAP emissions and use similar control technologies, regardless of whether they qualify as "major sources" or "area sources." Thus, in the case of EGUs, control technologies are generally available and applicable regardless of the mass of HAP emissions from EGUs. There is no reasonable basis for the EPA to separately regulate "major source" and "area source" EGUs.
Comment 5: Commenter 18487 states that area sources do not differ significantly from major sources for purposes of HAP emissions and control. The EPA's proposal properly sets MACT emission standards for all coal- and oil-fired EGUs greater than 25 megawatts, without further distinguishing between "major" sources and "area" sources. The Agency correctly refuses to exercise its discretion under CAA section 112(d)(5) to set alternative GACT standards for area source EGUs. The EPA's data show that similar HAP emissions and control technologies are found on both major and area sources greater than 25 MW, and there is no essential difference between area and major source EGUs with respect to emissions of HAP. The EPA's decision to establish MACT emission limits for both major and area source EGUs is well-grounded in fact and is necessary to implement the CAA's HAP control requirements for EGUs.
d. Distinguishing major and area sources would perpetuate a loophole.
Comment 6: Several commenters (19536, 19537, 19538) state that the case-by-case permit proceedings subsequent to New Jersey v. EPA also highlight a more insidious problem that, if not resolved by the Utility Air Toxics Rule, would undermine the fundamental purpose of the HAP control provisions with respect to EGUs: any rule that establishes separate and less rigorous HAP control standards for area sources would spur dubious minor source claims by large new and modified EGU sources attempting to skirt highly protective MACT emission standards for the HAP of greatest concern to public health and the environment. Several cases following New Jersey v. EPA underscore this danger and mandate the EPA's decision to hold major and area source EGUs alike to MACT standards.
Comment 7: Several commenters (19536, 19537, 19538, 18932) state that since the D.C. Circuit handed down its decision in New Jersey v. EPA, a pattern has emerged in which large EGUs previously designated as major HAP sources have claimed minor source status to avoid MACT emission limits for all of the 60 or more HAP the sources will emit. In each of these cases, the EGUs asserted that the suite of pollution controls planned for the units would reduce HCl and HF emissions below the 10-ton per year major source threshold for individual HAP, and that the combination of all HAP emissions would fall below the 25-ton per year threshold. Commenters state that these cases reaffirm the EPA's conclusion that there is no material difference between major and area source EGUs insofar as HAP emissions and controls are concerned. The putative area sources discussed above have large capacity boilers, they emit the same HAP as major sources, and they include the full range of pollution controls available for major sources.
Comment 8: Several commenters (19536, 19537, 19538, 18932) state that additionally, these minor source case studies provide a compelling justification for the EPA's proposal to establish MACT emission limits for both major and area source EGUs. To avoid MACT emission limits that apply to major HAP sources pursuant to CAA section 112(g), large, highly polluting EGUs have sought and obtained designation as minor HAP sources based on projected control of two pollutants  -  HCl and HF  -  and blanket limits for HAP emissions. In so doing, these sources have evaded stringent MACT emission control requirements for all the HAP they will emit, including the HAP of greatest concern to people and the environment. Commenters state that distinguishing between major and area sources would perpetuate this loophole and threaten public health and welfare in the process.
Comment 9: Commenter 15678 agrees with Commenters 19536, 19537, 19538 and 18932 and says that, for consistency and to avoid potential loopholes, the EPA should propose MACT standards that apply to both major and area sources.
e. Given the large variability in HAP emissions, even small units have the potential to emit substantial quantities of HAP.
Comment 10: Commenter 17620 states that the EPA has proposed to set MACT standards, as distinct from standards based on GACT, for EGUs that have a heat capacity greater than 250 million Btu/hr, even though such sources may not have been shown in the past to emit HAP above the major source thresholds for these pollutants. Units of this size are indeed very large. Given the variability in HAP emission rates and HAP fuel content demonstrated by the record, it is clear that these units have the potential to emit substantial quantities of HAP. For this reason, Commenter supports application of MACT standards, rather than the less stringent GACT standards that would otherwise apply.
f. General opposition to separate major and area source standards.
Comment 11: Commenter 17818 agrees with the EPA that there is no reason to differentiate the control of HAP emissions between major source and area source EGUs, and that it is appropriate to set MACT standards for both major and area source EGUs.
2. Support for separate area source standards.
a. About 12 percent of coal-fired facilities are potential area sources.
Comment 12: Commenter 17621 reviewed the emissions from each EGU included in the 2010 Part II and III ICR to determine which coal-fired facilities potentially could be classified as area sources. These determinations were based on the maximum potential to emit, taking into account actual annual heat input values developed as part of a previous emission modeling project and using actual capacity factor data from the EEI. The final list of potential area source coal-fired facilities is provided in Appendix C. Of the approximately 439 coal-fired facilities listed in EPA's Part II and III ICR database, 51 (approximately 12%) are potential area sources. Note that this list includes only those facilities with emissions data reported in response to the EPA's 2010 ICR. Additional facilities that were not tested in either the Part II or III ICR could also potentially be classified as area sources; however, Commenter does not have the necessary emissions data to make this determination. Such additional sources would likely include stations with smaller total MW capacity that fire coals with low chlorine and fluorine content, such as PRB subbituminous or western bituminous coals.
Commenter 17621 states that HCl and HF are the HAP emitted in the largest quantities; these are the compounds that typically cause coal-fired EGUs to exceed the 10 and 25 tpy major source criteria. Therefore, Commenter's analysis focused on using measured emissions data for HCl and HF from units tested as part of the 2010 ICR to calculate maximum annual emissions for each ICR test unit. Since the 10 and 25 tpy criteria for major sources apply at the facility level rather than the unit level, Commenter summed emissions across all units at a facility to derive an annual facility total. If emissions were not available for all units, ICR test data for similarly configured sister units were averaged and used to estimate emissions for units not tested. The reported lb/MMBtu emission factors for HCl and HF were then used -- in conjunction with 2007 actual annual heat input data per unit (i.e., trillion Btu heat input for 2007) from a previous project and corresponding EEI capacity factor data from 2007 -- to estimate a maximum annual emission rate per unit. Facilities with total HCl and HF emissions less than 10 tpy of each species or less than 25 tpy in aggregate were classified as potential area sources.
Commenter 17621 states that emissions of HAP metals, although individually much smaller than HCl and HF emissions, can contribute a few tons per year in aggregate at the largest MW capacity facilities. Therefore, as a final check, facilities that were identified as potential area sources and were also large MW capacity stations with HCl plus HF emissions greater than or equal to 10 tpy were evaluated further. Commenter investigated whether adding total HAP metal emissions from the ICR database (where available) to the acid gas emissions would put any of the facilities over the 25 tpy limit. None of the facilities that qualified as potential area sources based on their HCl and HF emissions exceeded the 25 tpy limit when metals were included.
Comment 13: According to commenter 17621, about 12 percent of the coal-fired facilities that submitted HAP data to the EPA in response to the ICR may qualify as area sources.
b. The EPA has promulgated area source standards for other source categories.
Comment 14: Several Commenters (17756, 17775, 17821, 18023) state that section 112(d)(5) provides the EPA with the option of setting GACT limits for area sources. Commenters 17756, 17775, and 17821 state that the EPA has promulgated area source limits for many source categories of HAP emissions, including most recently industrial boilers.
Comment 15: Commenter 17868 states that GACT controls have been used successfully in many other EPA MACT rules, including the following industries: Iron & Steel Foundries, Electric Arc Steelmaking, Coatings Operations Area Source Controls Rule, Clay Ceramics Manufacturing, Glass Manufacturing, Secondary Nonferrous Metals Manufacturing, Paint Stripping & Miscellaneous [sic].
Comment 16: Commenter 17868 states that GACT has been used in the electroplating, dry cleaning and halogenated solvents industries MACT rulemakings in order to reduce costs and regulatory burdens.
Comment 17: Commenter 19114 states that the EPA should continue with the precedent it has set in past MACT rulemakings by allowing for an area source subcategory. Congress has given the EPA the ability to subcategorize area sources because of their low HAP emissions and low potential impact on human health. The EPA should move area sources away from the stringent MACT limit setting approach under CAA section 112 and set GACT limits for area sources.
c. Area source decision is not the same as subcategorization.
Comment 18: Commenters 17756, 17775, and 18023 state that in the preamble to the proposed rule, the EPA appears to have considered setting area source standards but rejected that approach because "the data show that similar HAP emissions and control technologies are found on both major and area sources. . . . Moreover, EPA believes the standards for area source EGUs should reflect MACT, rather than GACT, because there is no essential difference between area source and major source EGUs with respect to emissions of HAP." Commenters 17756 and 17775 say that the problem with the EPA's rationale is that it appears little different from the considerations the EPA uses in deciding whether to subcategorize a source category. Yet, nothing in the alternative area source provisions of section 112(d)(5) suggests that the EPA's area source decision is, or should be, the same as a subcategorization decision. Commenters 17756 and 17775 say that Congress created an area source alternative to provide the EPA a means of removing facilities with low HAP emissions, and presumably lower public health impacts, from the rigid construct of the MACT provisions of section 112(d)(2) and the residual risk provisions of section 112(f). Commenter 17775 noted that, in regard to the lower public health impacts, "where Congress was concerned about the health impacts of specific pollutants it knew how to specify that MACT limits be promulgated" and cited to CAA section 112(c)(6). Commenters 17756 and 17775 state that as the EPA has recognized in other rulemakings, "[c]onsistent with the legislative history, we can consider costs and economic impacts in determining GACT, which is particularly important when developing regulations for source categories that may have many small business."
Comment 19: Commenter 17608 states that the EPA "solicit[s] comments on whether there would be a basis for considering area sources to be significantly different from major sources with respect to issues relevant to standard setting." However, the CAA does not require that major sources and area sources be different in order to justify setting area sources standards.
d. Separate area source standards would lessen the burden on small entities.
Comment 20: Commenter 8443 agrees with Commenters 17756, 17775, and 18023 stating that the EPA should exercise its discretion, as it has done in other section 112 rulemakings and set separate area source standards for coal- and oil-fired units. Commenter says that area source rules would lessen the regulatory burden of a section 112 EGU rule on many small entities. Commenter states that many EGU's owned by small public power entities are area sources, and goes on to say that one of the most positive moments of the SER SBREFA panel meeting on December 2, 2010 was the point where the option of using area source standards was discussed. Commenter strongly encourages the EPA to use area source standards for controlling mercury from smaller coal-fired power plants.
Comment 21: Commenter 17608 states that SERs suggested that EPA establish separate emission standards for EGUs located at area sources of HAP and that the standards be based on GACT as allowed under CAA section 112(d)(5) of the CAA. Specifically, SERs recommended that the EPA establish management practice standards for area source EGUs. The EPA representative on the SBAR panel recommended considering this flexibility, the OMB representative recommended proposing this flexibility, and Advocacy supported considering the flexibility but again stated that there was insufficient information upon which to recommend a specific regulatory alternative. The EPA did not propose area source standards. Based on the record available and the limited discussion of possible area source standards in the preamble, Advocacy sees no evidence that the EPA seriously considered separate area source standards.
Comment 22: Commenters 17775 and 18023 state that EPRI estimates that about 12% of the facilities containing coal- or oil-fired EGUs would qualify as area sources. Many of these sources are municipal utilities that qualify as small businesses. Commenters state that the EPA should exercise its discretion under CAA section 112(d)(5) and promulgate GACT limits for area sources.
Comment 23: Commenter 17821 states that EPRI estimates that 50 or more coal-fired generating stations could currently qualify as area sources. Creating this category would recognize those facilities whose emissions are at the lowest end of the spectrum and provide for them a reduced compliance burden under a GAT standard.
Comment 24: Commenter 17868 states that the EPA failed to avail itself of its ability to use GACT controls and subcategorize adequately (especially for <= 100 MW units) to help either the smaller utilities or the larger utilities.
Commenter 17868 does not believe that the EPA sufficiently considered its ability within the CAA to use GACT for smaller emitters of air toxics. Section 112(d)(5) of the CAA authorizes the EPA to use less stringent emissions standards or work practices for area sources of HAP. The EPA has broad authority to set GACT standards that are less stringent than MACT standards. Alternatively, the EPA should make GACT available for smaller plants. The proposed Utility MACT blurs the distinction between pollutants and the sections where they should be regulated in the CAA. This is problematic because Commenter has many member plants that would qualify as area sources had the EPA not combined two sections of the CAA. Commenter had, along with NRECA, requested the use of GACT during the Dec. 2, 2010 SBREFA SER panel and this reasonable request was ignored.
Commenter 17868 states that it seems inexplicable that the EPA would not use GACT in this rulemaking after being advised by both electric cooperatives and Commenter member utilities that this would be an optimal way to reduce regulatory costs and achieve a reduction in toxic air pollutants. Additionally, Commenter thinks it is strange that the EPA did not include GACT in the EGU MACT proposed rule after having allowed GACT and using GACT in the ICI Boiler MACT. Commenter and NRECA filed comments and discussed GACT during the December 2, 2010 SBREFA SER meeting so the EPA had plenty of notice to accommodate this option, which is provided for small emitters in the CAA.
Comment 25: Commenter 17817 states that in further support of the options available to the EPA for alternative strategies for small businesses and small sources, it is significant that Congress itself clearly distinguished between major sources of HAP and area sources of HAP in the statute. If Congress felt it appropriate to make that distinction, it is not appropriate that the EPA failed to acknowledge the distinction and provide appropriately proportional standards for them. Area sources of HAP, such as Commenter's existing H1 and permitted H2, simply do not present as serious a threat to human health as do major sources. Congress acknowledged and allowed for that unassailable fact when it adopted the CAA, and at a minimum, area sources should be provided an additional 3 years to plan, permit, and construct the requisite control technology necessary to come into compliance.
e. Separate area source standards would afford flexibility and still achieve the desired emissions reductions.
Comment 26: Commenter 17805 states that for Lewis & Clark Station, the MACT standard is very restrictive. It would result in a very high compliance cost, and provide a very insignificant benefit since HAP emissions have been shown in the recent stack test to be already very low. This then supports further consideration be given to subcategorizing smaller, area source units and to providing a GACT standard that would allow for more flexibility in achieving HAP emission reductions, as opposed to the one-size-fits-all approach evident in the proposed MACT standards. The EPA has allowed much more flexibility in other rules, such as the recently proposed 316(b) rule, in order to achieve more cost effective environmental improvements. Commenter believes that the EPA can apply more flexibility in the proposed rule, possibly through additional subcategorization, and still achieve the desired emissions reductions.
f. GACT and MACT too similar to distinguish.
Comment 27: Commenter 17608 states that the EPA further asserts that GACT and MACT would be too similar to justify the effort to distinguish between emission standards set using GACT and standards set under MACT. Although perhaps true, Commenter would have preferred a demonstration of this fact, showing the public what factors the EPA would consider in setting a GACT standard for area source EGUs. Nonetheless, this neglects the EPA discretion to set management practices for area sources instead, an option the EPA appears not to address at all, despite a specific call by the SERs that it do so.
g. Regulating area and major sources at the same time.
Comment 28: Commenter 17608 states that the EPA states that since this rule regulated both major and area sources at the same time, it makes sense for them to meet the same requirements. Commenter does not believe this is a reasonable justification for declining to exercise its discretion. The EPA has in the past set different standards for major and area sources on the same day in parallel rulemakings.
h. General support for separate area source standards.
Comment 29: Commenter 17756 states that it has facilities with EGUs that could qualify as area sources. The EPA should exercise its discretion under promulgate GACT limits for area sources.
Comment 30: Commenter 17871 states that contrary to the plain language of section 112 and its legislative history, the EPA made no attempt in the proposed rule to distinguish between major sources and area sources for purposes of listing or setting standards.
Comment 31: Commenter 18031 states that the EPA should give consideration to developing a separate area source rule for low emitting EGU's, applying GACT standards to these sources.
Comment 32: Commenter 17846 supports the EPA's decision to regulate both area sources and major sources under MACT standards.
Comment 33: Commenter 17871 states that EPA cannot automatically impose MACT standards on all area sources without consideration of the necessity of such action. See 64 Fed. Reg. 6496, 6958 (Feb. 11. 1999) (regulating all HAP emitted by area sources "could result in applying MACT to all HAP emitted by area sources under circumstances where control would not otherwise be warranted.") According to the commenter, Congress, in allowing EPA to use a GACT standard for area sources, recognized that area sources are different from major sources in both the level of emissions and the level of scrutiny to which their emissions should be subject. 74 Fed. Reg. 69194, 19199 (Dec. 30, 2009). The risks presented by the emissions of HAP from EGU area sources are appropriately regulated under a GACT standard or "management practices." 42 U.S.C. section 112(d)(5). In most cases, area source EGUs are either very small or, like the TS Power Plant, they have already installed state-of-the art control technology that reduces HAP emissions to well below major source thresholds. The costs of applying a MACT standard to area source EGUs are simply not justified where the non-mercury emissions and associated risk to public health are negligible.
Commenter 17871 states that EPA failure to account for the important differences between major and area sources as part of this rulemaking is contrary to the plain language of section 112 of the Clean Air Act ("CAA") and results in the imposition of standards on sources whose emissions present negligible risk to public health and the environment. According to the commenter, nothing in section 112(n) gives EPA discretion to read out of the statute the provisions in section 112 requiring the EPA to distinguish between area sources and major sources when listing categories and setting standards. See Sierra Club v. EPA, 551 F.3d 1019, 1028 (D.C. Cir. 2008) (rejecting "EPA's claim of retained discretion in the face of the plain text of section 112" where Congress had "confined the Administrator's discretion...[and] was explicit when and under what circumstances it wished to allow for such discretion..."). The commenter notes that whether an area source is "large" or "small" in terms of size is not the defining characteristic under the plain language of the statute.
Commenter 18033 states that EPA should reconsider promulgating GACT standards for area sources under CAA section 112(d)(5). According to the commenter, many EGUs owned by small power utilities are area sources and pose low risk to public health. The commenter disagrees with EPA's finding that "there is no essential difference between area source and major source EGUs with respect to emissions of HAP." Instead, the commenter states that if the goal of the rule is public health then units that emit small amount of Hg present little of no risk to public health. The commenter noted that EPA found that the 390 smallest emitting coal units accounted for less than 5 percent of the total Hg emissions. In addition, many smaller units employ controls to reduce emissions to area source levels. According to the commenter, the proposed rule will ultimately result in a burden on the smallest units, many of which are owned by public power producers, impairing electric reliability and affordability for little environmental benefit.
Response to Comments 1 - 33: The CAA section 112(a)(8) defines EGUs as "any fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale." CAA section 112(a)(8) also provides that a unit "that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 megawatts electrical output to any utility power distribution system for sale shall be considered an electric steam generating unit." This definition does not distinguish between major and area sources. Rather, it specifically states that an EGU is "any" fossil fuel fired combustion unit of more than 25 megawatts that serves a generator that produces electricity. Thus, any unit that meets the definition of an EGU is part of the EGU source category. In light of this statutory definition, the EPA reasonably established standards based on the EGU source category. It did not distinguish between major and area source EGUs.

Nevertheless, the agency did examine at proposal whether it would be appropriate to regulate area source EGUs differently by issuing GACT standards for such units, as opposed to MACT standards. As the agency explained at proposal, it is appropriate to treat major and area source EGUs similarly because the data available to the EPA show that similar HAP emissions and control technologies are found on both major and area source EGUs. For example, EGUs, irrespective of size, employ the same suite of technology options for controlling air pollutant emissions (e.g., fabric filters, electrostatic precipitators, wet and dry scrubbers, etc.). Indeed, there are well-controlled EGUs of all sizes and many EGUs (both major and area) have a full suite of emission controls. There is also no essential difference between area source and major source EGUs with respect to emissions of HAP, and the commenters have not provided any data to rebut this conclusion. Instead, commenters make various qualitative statements. They assert, for example, that many EGUs owned by small entities are area sources and that an area-source GACT standard would "lessen the regulatory burden" on many small entities. Notwithstanding the lack of data and analysis conducted by the commenters, we have reevaluated the issue of whether to set GACT standards for area sources, and we decline to do so in the final rule for the reasons set forth below.  See also 76 FR 25021.

We have reviewed the "Nationwide Emission Estimates" spreadsheet prepared at proposal and updated that spreadsheet based on comments received to determine the number of area source facilities. The spreadsheet associated with the proposed rule is posted to the Agency's project website (http://www.epa.gov/ttn/atw/utility/utilitypg.html) and to the docket (EPA-HQ-OAR-2009-0234-2986). The updated spreadsheet may be found in the docket for this rulemaking. This additional review reinforces our decision to regulate all EGUs in the same manner and to set MACT standards for such sources.

The data show that there are approximately 79 potential area source EGU facilities comprised of 141 coal- and oil-fired EGUs (this number could be lower if these facilities have other HAP emitting processes that cause the facilities to exceed the major source thresholds). Of these facilities, 16 are oil-fired (29 EGUs), leaving 63 facilities that are either all coal or a mix of coal- and oil-fired EGUs. At proposal, we explained that there is essentially no difference between major and area source EGUs. That assessment is correct, as confirmed by the data in the record. For example, we have identified individual EGUs as large as 900 MW that may be synthetic area sources (i.e., units that were major sources and installed controls to emit at levels below the major source thresholds), and units as small as 40 MW that are major sources.

Based on our additional analysis, we determined that only 8 of the 63 coal - fired facilities that are potential area sources are "natural" area sources (i.e., the level of emissions is not achieved through the use of add-on controls). Thus, the reason that the vast majority of these sources are potential area sources is because they are well controlled (i.e., "synthetic" area sources). In addition, 67 of the 112 coal-fired EGUs are in the acid gas MACT floor pool; 20 are in the Hg MACT floor pool; and 21 are in the filterable PM MACT floor pool. These conditions confirm our position, presented at proposal, that there is no essential difference in the level of control or in the emissions profile between potential area sources and major sources.

Moreover, under CAA section 112, the "source" for purposes of determining major vs. area source status is determined by evaluating the facility as a whole, not the individual EGUs. Generally speaking, EGUs are not co-located with other HAP-emitting sources (i.e., are not located within a contiguous area and under common control with another HAP emitting process). All the individual EGUs (and any other HAP emitting processes, if any) at a facility must be considered when determining whether a facility as a whole is a major source or an area source. Thus, the primary determinant as to major vs. area source status is not the size of the individual EGUs, but instead whether there are multiple EGUs at a given facility. Given that the emissions characteristics of different sized EGUs are the same, we believe that establishing an area source GACT standard for facilities that have only 1 or 2 EGUs, would not be reasonable because the EGUs at the facilities with 1 or 2 units are the same as those at facilities with more EGUs, in that they have the same emissions profile and either have the same or are capable of employing the same controls. Given that we are regulating major and area sources at the same time, and the EGUs themselves are similar notwithstanding their location at a major source vs. an area source facility, we believe a common control strategy is warranted.

Based on all of the foregoing, we set MACT standards for all EGUs and declined to set GACT for those sources that may meet the definition of an area source. Some commenters suggest that the EPA is required to establish GACT standards for area sources. This is incorrect. Although EPA has the discretion to set GACT standards for area sources, it declined to do so here after fully assessing the facts and circumstances, as described above.

Some commenters note that there could be as many as 12% of the total population that could be classified as area sources. But, this fact does not render the agency's treatment of EGUs as a source category unreasonable. As noted above, major and area sources were represented in the floors for each pollutant, which confirms that major and area source EGUs are similar  -  as they have similar HAP emissions and control technologies.

Commenters also note that the agency has exercised its discretion in other NESHAP rulemakings to establish area source limits. Although true, the fact that the EPA has established area source limits in some source categories is irrelevant to similar decisions for different source categories. Commenters have not shown that the circumstances applicable to those other source categories are similar to the circumstances identified for major and area source EGUs (e.g., similar controls, similar emission characteristics, large number of synthetic minor area sources). Further, those other source categories are not statutorily defined in a manner that includes both area and major sources. EGUs are the only source category defined in CAA section 112 and, in establishing the definition of an "electric utility steam generating unit" under CAA section 112(a)(8), Congress included in the EGU source category both area and major sources. Thus, it is reasonable to regulate the EGU category in the manner Congress defined the category. Commenters have provided no legal support for the contention that the EPA must regulate area and major sources in the same category in separate rulemakings, and the EPA has in fact regulated both major and area sources in the same rulemaking even absent a statutory definition that includes both major and area sources. (See National Emission Standards for Hazardous Air Pollutants From the Portland Cement Manufacturing Industry and Standards of Performance for Portland Cement Plants; 75 FR 54970; September 9, 2010.)

The EPA considered the totality of the circumstances when determining whether to establish GACT standards for areas sources in the proposed rule and we maintain that it is reasonable to consider whether emissions characteristics of major and area sources are different when determining whether to establish GACT standards, notwithstanding commenters' implication that consideration is not correct. That we also consider emission characteristics in subcategorization decisions is of no moment. Commenter's point concerning CAA section 112(c)(6) is also odd because EGUs emit several of the CAA section 112(c)(6) HAP (i.e., lead, mercury, dioxin, furan). Although EGUs were exempted from that provision, the fact that they emit some of the HAP called out for MACT control supports our decision to not establish GACT standards for any EGUs. Commenters also state that many EGUs owned by small entities are potential area sources. However, commenters fail to note that there are also EGUs owned by small entities that are NOT potential area sources, and, thus, would not accrue any "lessened regulatory burden" benefit from such a decision by the EPA. (EPA's discussion of comments requesting a "less-than 100 MWe" subcategory are addressed elsewhere.)

Some commenters state that the EPA's mere assertion that there would be no difference between GACT and MACT to justify an area source finding does not provide sufficient documentation for the decision. But EPA did not say there would be no difference between MACT and GACT. Instead, it stated that it would be difficult to make a distinction given the similarities between the EGUs at major and area source facilities.

Specifically, as noted by other commenters, and observable by a review of the MACT Floor Analysis spreadsheets, potential area sources range in size from units near the CAA section 112(a)(8) defined lower size limit to units of hundreds of megawatts. Further, these larger area source units are, for the most part, controlled with the full suite of emission control technologies available (e.g., fabric filters, scrubbers).

As stated above, there are a number of EGUs that are quite large that are area sources and others that are small that are major sources. See "Evaluation of Area Source EGUs" TSD, Docket #EPA-HQ-OAR-2009-0234. This is the case because the acid gas HAP emissions are what drive EGUs to have HAP emissions exceeding the major source threshold. With a few exceptions, the EGUs located at area sources have FGD or other acid gas controls that reduce the acid gas HAP to area source levels. Id. Thus, the majority of sources that currently qualify as area sources were, in fact, major sources prior to installing controls. The exceptions are those units that would likely be able to achieve the MACT level of control for acid gas with minimal use of DSI at a reasonable cost. Id.

In addition, the data show that a number of area sources for which we have data are high emitters of Hg and non-Hg metal HAP. Id. For example, the area source facilities comprised of only oil-fired EGUs include the Hawaiian Electric Company Waiau facility, which was the facility exhibiting the highest modeled risk in the assessment done for the appropriate and necessary analysis discussed in the preamble and elsewhere in the record for this rulemaking. In addition, we have identified 13 facilities that use low Btu, virgin coal that are potential area sources. While these facilities are potential area sources, the sources are among the highest emitters of Hg. Specifically, the Hg emissions of these units range up to 0.667 tons per year (tpy) for one facility (Limestone Unit 1  -  0.32 tpy; Limestone Unit 2  -  0.34 tpy) with at least 4 facilities using the same coal with Hg emissions greater than 0.20 tpy and 2 additional facilities that use other coals with Hg emissions greater than 0.10 tpy. Pursuant to our appropriate and necessary finding, Hg and non-Hg metal HAP pose a significant threat to human health. Thus, even were we to distinguish between major and area sources, which we do not believe is appropriate given the similarities between such sources, we would still decline to set GACT standards for these HAP, and as such we maintain that MACT standards are appropriate. Moreover, for acid gas HAP, as discussed above, the data indicate that the level of control would likely be the same even if we did establish GACT standards under CAA section 112(d)(5).  See "Evaluation of Area Source EGUs" TSD, Docket #EPA-HQ-OAR-2009-0234.
We fully evaluated the nature of EGUs, and we do not see a basis on which to distinguish these sources for purposes of setting standards. Thus, we maintain that we reasonably exercised the discretion afforded the agency under the statute and declined to set separate standards for area source EGUs.
3. The Rule should apply only to major sources.
Comment 34: Commenter 17772 states that the proposed regulations should clarify that subpart UUUUU is only applicable to major sources of HAP emissions as defined by section 112(a)(l) of the CAA. The proposed rule does not recognize explicitly that sources that already have federally enforceable requirements such as mercury limitations in their state SIP or consent decrees may no longer be major sources for HAP. An ESP or fabric filter in conjunction with an FGD or other control systems may be able to maintain the unit below the major threshold of 10 tpy individual HAP emissions or 25 tpy of any combination of HAP emissions.
Commenter 17772 states that sections 63.9981 and 63.9982 should clearly state that: (1) if an EGU is subject to a federally-enforceable requirement to operate certain pollution control equipment; and (2) the operation of that equipment would result in emissions below the major source threshold of HAP as defined in section 112(a)(l) of the CAA; then (3) that EGU is exempt from subpart UUUUU. This result is consistent with CAA section 112(d), which excludes non-major sources of HAP.
Response to Comment 34: As noted above, the CAA section 112(a)(8) definition of EGU does not distinguish between major and area sources and we maintain that EGUs are a single source category that contains both major and area sources. The EPA listed coal- and oil-fired EGUs as that term is defined in the statute and, therefore, we must issue standards for both major and area sources pursuant to CAA section 112(d). See CAA section 112(c)(2). Nothing in CAA section 112(d) excludes area source EGUs as the commenter suggests. We believe this position to be correct even in the presence of "federally enforceable requirements such as mercury limitations in their state SIP or consent decrees" or "a federally-enforceable requirement to operate certain pollution control equipment." The EPA cannot rely on such standards even if they exist because those standards are not established consistent with CAA section 112(d). In addition, these requirements do not address all HAP emitted from EGUs as required by CAA section 112(d). To the extent sources complying with such standards are meeting the standards in this final rule, the sources will be in compliance with the limits in this rule.
4. Other.
Comment 35: Commenter 17871 states that EPA failed to comply with the notice-and-comment provisions of the APA by failing to include in the docket any indication of which sources within the EGU category emit HAP at levels below the major source thresholds. Additionally, the commenter notes that the emission data in the docket are based on emission rates, rather than mass emissions of HAP and, therefore, it is extremely difficult to calculate annual mass emissions from these units. According to the commenter, where the Agency has failed to make this distinction and the record does not provide an adequate basis on which to make this distinction, the onus cannot be on the public to comment on how area sources should be treated as part of this process. See Portland Cement Ass `n v. Ruckelshaus, 486 F.2d 375, 393 (D.C. Cir. 1973), cert denied, 417 U.S. 921(1974). See also Connecticut Light & Power Co. v. N.R.C., 673 F.2d 525,531 (D.C. Cir. 1982).
Response to Comment 35: The materials noted by the commenter were posted in the docket on May 3, 2011 (EPA-HQ-OAR-2009-0234-2986). In addition, the underlying nationwide emissions estimate spreadsheets were also posted in the docket on May 3, 2011 (EPA-HQ-OAR-2009-0234-2943 and -3035); a similar spreadsheet was also made public on the Agency's website within days of signature of the proposed rule (http://www.epa.gov/ttn/atw/utility/utilitypg.html; March 21, 2011). These spreadsheets were in a tons/year format.
Comment 36: Commenter 17767 states that EPRI evaluated the HAP emissions of plants representing the MACT pool, specifically those that were among the lowest emitters. EPRI identified two sources on that list operated by We Energies, Elm Road Generating Station and Pleasant Prairie Power Plant. Commenter agrees with EPRI's comments that all sources identified by EPRI, including commenter's, are area sources and should be removed from the EGU MACT pool and the emissions from the remaining sources be used to calculate MACT limits for existing major sources. Further, commenter fully agrees with UARG's comments that GACT limits be established for area sources.
Commenter 17772 states that the Elm Road Generating Station and Pleasant Prairie Power Plant are area sources and should be removed from the MACT pool.
Response to Comment 36: We disagree with the commenters. The EGU source category is defined in CAA section 112(a)(8) in a manner that includes both major and area sources, and EPA is regulating EGUs as a single source category consistent with the statutory definition at CAA section 112(a)(8).

2B - Applicability: Section 112 rules, Industrial Boiler MACT (DDDDD and JJJJJJ)
Commenters: 17174, 17691, 17796, 17818, 19040, 18023
1. Units should not transition between Boiler MACT and Utility MACT.
Comment 1: Commenter 17691 is concerned with the proposed structure of regulatory applicability for cogeneration units. Commenter does not concur with the concept of applying certain applicable requirements when facilities meet the definition of a cogeneration facility (i.e., producing and selling one-third of their generated power that is greater than 25 MWe) and other applicable requirements when the facility is operated as an industrial boiler. Using the proposed approach, Commenter predicts that the process of permitting cogeneration facilities will become complicated, overly burdensome, and result in confusion during compliance determinations.
Comment 2: Commenter 18023 states that a unit should not be forced to switch between compliance with the Industrial Boiler MACT and the Utility MACT. There are some indications in the preamble that a unit could switch immediately from being an industrial boiler to an electric utility steam generating unit if it increases its electricity production beyond a given threshold. The unit would remain an EGU for at least six months but after that period, if the electricity output dropped, the unit would revert back to being an IB. This would be extremely problematic and confusing from an emissions control and monitoring perspective. The emission standards in both rules are different, which would likely require different emission control designs. In addition, the monitoring and reporting requirements are different for these classes of units. In order to be in compliance, a source would have to install the monitoring equipment under both rules. This is nonsensical and could not have been intended.
2. Once-in, always-in.
Comment 3: Commenter 17174 notes that the EPA should address how the "once-in-always-in" policy applies to sources subject to the Boiler MACT that become subject to the Utility MACT when the source meets the EGU cogeneration criteria.
Comment 4: Commenter 17818 is of the opinion that this provision has the potential to have affected units periodically bounce in and out of the necessity of meeting certain compliance requirements. This has the potential of causing regulatory compliance and permitting issues for the source and the permitting organizations. It is Commenter's opinion that once a unit becomes classified as an EGU, that unit remains an EGU until such time that permit restrictions for the affected units are finalized that prohibit the unit from again attaining the output necessary for the unit to potentially reach the EGU output criteria at any time in the future.
3. Units should be subject to the more stringent of the two regulations.
Comment 5: Commenter 17796 suggests that the facility [with combustion units that are at times IB units or solid waste incineration units subject to other standards under CAA section 112 or to standards under CAA section 129] be subject to the more stringent of the two regulations should this situation occur for the same unit at the same facility. Thus, no matter what operating scenario the unit is in, it will be in compliance with either NESHAP. In addition this would eliminate any possible confusion about the applicable regulatory requirements for both the regulator and source owner.
4. The EPA should clarify the details of transition.
Comment 6: Commenter 17174 states that there are several cogeneration units in South Carolina that could potentially follow this scenario. Commenter says that the EPA did not address the regulatory logistics on how this would be implemented. Commenter requests that the EPA provide in the final rule a clear process to demonstrate initial and continuous compliance for cogeneration units changing section 112 applicability. This process needs to provide the specific period or deadline when the cogeneration unit stops compliance with the Boiler MACT and starts complying with the Utility MACT and vice versa, include notification requirements when changing rules, and specify testing and NOCS deadlines.
Comment 7: Commenter 17818 states that it is not clear what period of time is related to the portion of the statement "potential electric output capacity." In the statement, the EPA indicates that if any unit exceeds the one-third potential (and also meets the 25 MWe criteria) during any portion of a month, the unit is subject to the proposed rule. Commenter questions what averaging period is proposed for the determination criteria of "any portion of a month" (hourly, 24-hr avg., etc). Commenter also questions the appropriateness of an averaging period of less than monthly if such a provision is to be retained in the final rule.
5. The EPA should base the threshold on becoming an EGU on a 12-month rolling average.
Comment 8: Commenter 19040 states that at numerous locations throughout the preamble and in the proposed regulation the difference between a cogeneration and an EGU is discussed. It is consistently mentioned that a cogeneration facility can become classified as an EGU if the facility in question puts more than 25 MW on the grid and the 25 MW is more than one-third of the rated capacity of the generator.
When a coal-fired cogeneration unit stops being a cogeneration unit and becomes an EGU, the emission requirements for the unit switches from the EGU emission requirements to the IB emission requirements. Aside from the differences in emission levels that have to be met, the pollutants that need to be controlled are different.
It appears, from the manner the proposed regulation is written, that if a non-EGU crossed the threshold to becoming an EGU for even an hour, it would have to meet the emission requirements for an EGU for the next six months. It might be more equitable and allow a non-EGU to plan better if the threshold to becoming an EGU were based on a 12-month rolling average. That way, if the facility crossed over the threshold for one or two hours, they would not be penalized for six months of operation as an EGU.
Commenter 17880 states that in addition to any cogeneration facility that sells electricity to any power distribution system equal to or more than 1/3 of their potential electric output capacity is considered an EGU if it meets the proposed definition of fossil-fuel-fired, the definition would also apply to any cogeneration facility capable of combusting enough coal or oil to generate 25 MWe from fossil fuels alone. The commenter also states that any units subject to Boiler NESHAP that increase their electricity output supply to meet peak energy demand to the extent that they meet the EGU cogeneration criteria should be subject to the proposed EGU NESHAP for a six month period from the initial increase of production.
Response to Comments 1 - 8: Congress in CAA section 112(a)(8) defined the EGU source category; for all other source categories, the EPA defined the source category in the listing decision. Thus, sources that meet the CAA section 112(a)(8) definition are EGUs and, therefore, must comply with this final rule; however the EPA believes that it has some flexibility with regard to restricting the "movement" between source categories under CAA section 112. We maintain that units with the potential to periodically meet the definition of an EGU should generally be subject to the EGU NESHAP. This is particularly pertinent to EGUs that cogenerate steam and electricity where the production of electricity for sale may vacillate above and below the "one-third of its potential electric output capacity" and "more than 25 megawatts electric output" thresholds mandated in CAA section 112(a)(8).
As explained in the preamble to this final rule, we are finalizing that you are subject to the requirements of the final rule at least 6 months following the last date you met the definition of an EGU subject to the final rule (e.g., 6 months after a cogeneration unit provided more than one third of its potential electrical output capacity and more than 25 megawatts electrical output to any power distributions system for sale). In addition, we requested comment on the need for provisions to account for sources that move between different standards and several commenters indicated a need for such provisions. For this reason, we are finalizing a provision whereby you may opt to remain subject to the provisions of the final rule beyond the 6 months if you continue to have the potential to meet the statutory definition of an EGU in the future, unless you combust solid waste in which case you are a solid waste incineration unit subject to standards under CAA section 129 (e.g., 40 CFR Part 60, subpart CCCC (New Source Performance Standards (NSPS) for Commercial and Industrial Solid Waste Incineration Units), or subpart DDDD (Emissions Guidelines (EG) for Existing Commercial and Industrial Solid Waste Incineration Units)). We believe the provision to opt to remain subject to this final rule will ameliorate conditions where EGUs may potentially move between NESHAP on a relatively frequent basis. Notwithstanding the provisions of this final rule, an EGU that starts combusting solid waste is immediately subject to standards under CAA section 129 and the unit remains subject to those standards until the unit no longer meets the definition of a solid waste incineration unit consistent with the provisions of the applicable CAA section 129 standards.
We believe this situation is different from that of an EGU that may periodically combust materials defined to be "solid waste" under the rule entitled "Identification of Non-Hazardous Secondary Materials That Are Solid Waste" (Solid Waste Definition Rule; 76 FR 15456; March 21, 2011). CAA section 129 defines "solid waste incineration unit" as "a distinct operating unit of any facility which combusts any solid waste material from commercial or industrial establishments or the general public." See CAA section 129(g)(1). The plain reading of CAA section 129(g)(1), and the emphasis placed on the word "any" by the Court in its decision on the September 22, 2005, CAA section 129 "Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and Industrial Solid Waste Incineration Units" (CISWI; 76 FR 15704; March 21, 2011) rule, precludes the Agency from exempting EGUs that combust materials determined to be "solid waste" from complying with the applicable CAA section 129 standards (e.g., the CISWI rules). However, we do believe that procedures need to be provided whereby an EGU may transition in and out of CAA section 129 standards. For example, the CISWI rule contains provisions similar to the ones included in this final rule to address the requirements for sources that stop being solid waste incineration units.
In addition, the once-in-always-in policy does not apply to sources that move between NESHAP applicability to separate source categories (e.g., boilers and EGUs). Sources that must comply with multiple NESHAP at different times should work with their permitting authorities to include alternative operating scenarios in their Title V permits to ease the transitions between different standards. Finally, we are not adopting provisions that authorize sources to comply with the more stringent of alternatively applicable standards. We believe the approach we have adopted in this final rule and in the CISWI rules provide sufficient flexibility for sources that may at times be subject to different standards. 2C - Applicability: Section 129 rule, CISWI
Commenters: 17174, 17402, 17754, 17796, 17838, 18963
1. Transition between CAA section 112 and CAA section 129 rules.
Comment 1: Commenter 17174 addresses transitioning from CAA section 112 to section 129 and vice versa. Commenter notes that the EPA solicits comment on whether they should include provisions similar to those included in the final CISWI rule to address units that combust different fuels at different times. Commenter states that several utility boilers in South Carolina have the potential to combust materials that could be considered solid waste under the proposed RCRA definition. Commenter states that these are utility boilers that do not meet the exemption under CAA section 129 (g)(1)(B) for qualifying small power production facilities or qualifying cogeneration facilities. Commenter recommends that the EPA include provisions similar to those included in the final CISWI rule to address units that combust different fuels at different times.
Comment 2: Commenter 17402 states that the EPA should clarify the interactions between the Utility MACT and the Solid Waste Incinerator and Definition Rules. Commenter supports the EPA's general goal of reducing risks to human health and the environment from emissions from combustion facilities; however it believes that regulation of the combustion of secondary materials under CAA section 129 of the CAA should be carefully applied so as to encourage the safe reuse of materials that were previously used for different purposes, and in a flexible manner that does not impose unnecessary regulatory burdens in exchange for insignificant benefits. Commenter believes the EPA should provide flexibility to EGUs that attempt to use nontraditional fuels, and encourage those with beneficial emissions profiles.
Commenter 17402 states that under CAA section 129, 42 U.S.C. section 7429, facilities combusting materials that are determined to be non-hazardous solid waste under the RCRA are regulated as incinerators and required to meet the emissions standards under CAA section 129 of the CAA, rather than under other sections of the CAA, including section 112 on which this Utility MACT rule is based. The EPA had originally attempted to exempt energy recovery facilities from this requirement (no matter what they combust), but that approach was found to be invalid in NRDC v. EPA, leading to a revised rule covering incinerators. In response to the NRDC decision, the EPA promulgated the new Non-Hazardous Secondary Materials Rule ("Solid Waste Rule"), defining non-hazardous solid waste under RCRA. The EPA released the Solid Waste Rule along with standards for CISWI and major source boiler standards ("Boiler MACT"), among other rules. All of these rules were published in the Federal Register on March 21, 2011. The EPA delayed the effective dates of both the CISWI and Boiler MACT rules as part of its ongoing reconsideration of those rules on May 18, 2011, but did not reconsider or stay the Solid Waste Rule.
Commenter 17402 offered comments in response to the proposed Solid Waste Rule on August 2, 2010. Those comments are hereby incorporated by reference. Although the final Solid Waste Rule represents an improvement over the proposed rule, two specific areas for concern remained, on which Commenter requested reconsideration. Commenter also requested reconsideration of related issues under the CISWI rule. Both petitions were filed on May 20, 2011, and are also incorporated by reference here. Commenter requested that the EPA treat existing coal rejects identically to currently generated coal rejects, as they are chemically largely identical. In fact, legacy coal rejects may be of higher fuel value, as coal processing technology has improved to reduce the amount of energy-bearing coal that must be rejected. Commenter also requested a de minimis exemption from both the definition of solid waste under RCRA, and treatment as an incinerator under CISWI, for combusting de minimis quantities of boiler cleaning wastes and demineralizer resins.
Commenter 17402 appreciates that the EPA requested comments on the relationship between section 129 and the comparable EGU standards in the proposed Utility MACT rule. However, the EPA's initial approach does not adequately account for the challenging interaction between uncertainty in the Solid Waste Rule with a lack of flexibility in the proposed rule. In part, because the impacts of the Solid Waste Rule can only be measured by comparing the impacts different rules, i.e.,the CISWI, Boiler MACT, and Utility MACT rule operating under different scenarios, the EPA has not attempted to address the true costs of the Solid Waste Rule. In response to concerns Commenter raised in the Solid Waste Rule context, the EPA responded that the comments were beyond the scope, but then did not address those concerns in the CISWI rule or in the current proposal. As a result, the EPA has created an uncertain, and potentially onerous and burdensome, process for using materials which may or may not be solid wastes. The EPA should review the interactions of the Solid Waste Rule, the CISWI Rule, Boiler MACT, and this proposed rule and apply the principles of E.O. 13653 to the whole integrated system. By dividing its treatment and analysis of the different aspects of the rule, it is impossible for the Agency, or the public, to have a clear picture of the true impacts of the rule.
Commenter 17402 states that the risks of error are extremely high in that, under the proposal, if an EGU combusts any solid waste, it automatically becomes an incinerator for regulatory purposes. However, it is a virtual certainty that no EGU has permits that allow it to operate as an incinerator, nor are they sited as an incinerator, nor do they have in place the additional monitoring and testing required under CAA section 129. Without those items, an accidental combustion of a styrofoam peanut at a coal-fired EGU could require the unit to cease operations for six months, the period it takes for a CISWI to revert to an EGU.
Commenter 17402 states that as a result, the operator of an EGU is faced with a choice: preemptively become a solid waste incinerator before any planned burning of materials that may trigger the rule, or avoid any materials whose provenance under the Solid Waste Rule is not entirely clear. This outcome is exactly crosswise with the statutory intent behind both RCRA and section 129 of the CAA. RCRA was developed and passed to assist the nation with responding to mounting volumes of solid wastes. RCRA's specific purpose was to encourage the removal of usable materials from the waste stream, create a cradle-to-grave regulatory scheme for hazardous wastes, and to encourage the generation of energy from solid waste. Section 129 of the CAA was created to regulate municipal and other waste incinerators. Perhaps because the EPA has only previously enacted federal regulations with respect to the hazardous waste aspects of RCRA, which occupy the central role at the federal level, it has adopted the "cradle-to-grave" mentality associated with it for all secondary materials. This can be seen in the proposed rule by the monitoring and tracking requirements imposed on those plants which combust secondary materials that are determined not to be a solid waste through a variety of mechanisms.
Commenter 17402 states that instead, the EPA should be encouraging EGUs that seek to develop alternative clean sources of energy. When a material is present in large quantities in the environment with high heating value, similar contaminants and emissions to traditional fuels, and that is currently creating an environmental problem, the EPA should encourage its removal and use for fuel. Similarly recycled wood products and other materials that can generate electricity should be made easier for operators to consume, not harder. The EPA should focus on the intent of the statutes in question  -  improving emissions and encouraging resource recovery. Instead, the Agency has gotten sidetracked by a quest to regulate all potentially "discarded" material. This proposed rule, along with the reconsideration of related rules affecting combustion units, provides an opportunity for the EPA to correct that focus. Commenter urges the EPA to do so.
Commenter 17402 states that to that end, it proposes two principles for the EPA to consider as it goes about clarifying the relationship between the various categories of EGUs: (1) EPA should provide certainty to EGUs that combust secondary materials regarding their permit status; and (2) EPA should provide flexibility to EGUs that attempt to use nontraditional fuels, and encourage those with beneficial emissions profiles.
Commenter 17402 states that applying those principles to its own operations, two issues of concern remain as potential obstacles to its continued economic operations. The first is the treatment of legacy coal rejects. Commenter's Grant Town plant was built to use, and currently operates in large part using, coal rejects from abandoned coal piles within a relatively short distance of the plant. However, the final solid waste rule, combined with the proposal at issue in these comments, raises questions about Grant Town's continued permit status as an EGU. Without a viable, and continuing permit and adequate cost-effective fuel supply, Grant Town cannot continue operations.
Commenter 17402 states that the second issue is the treatment of materials generated in the normal course of boiler operations. Under longstanding utility practice in North America, boilers typically combust their boiler cleaning wash. Commenter also combusts other materials generated in the normal course of boiler operations, such as demineralizer resins. Although the resins may have sufficient fuel value to qualify as processed materials, and thus not solid wastes, under the EPA's legitimacy tests, boiler wash would not. The combustion of these materials is an economic disposal option; one that prevents the land-based disposal of numerous gallons of water and solvents.
Response to Comments 1 and 2: Consistent with NRDC v. EPA, any source combusting any solid waste is a solid waste incineration subject to standards issued pursuant to section 129. 489 F.3d 1250, 157-58 (D.C. Cir. 2007). The EPA may not subject sources subject to standards under CAA section 129 to standards issued pursuant to section 112. See CAA section 129(h)(2). For these reasons, EPA may not exempt from section 129 standards EGUs that combust solid waste as that term is defined in the recently issued Solid Waste Definitions rule. This includes units that are burning what commenters describe as di minimis levels of solid waste or solid waste that has significant fuel value. As to the commenter that expressed concern about its unit burning coal refuse, we concluded in the proposed rule that all EGUs burning coal refuse were either burning newly mines coal refuse such that it is not solid waste or sufficiently processing previously discarded coal refuse such that the coal refuse is not a solid waste. The commenter expressed concern that their unit might be subject to section 129 because it was combusting coal refuse but it did not indicate that it was not in fact sufficiently processing the coal refuse it uses. We continue to believe that all coal refuse units, including the unit identified by the commenter, are EGUs because it is our understanding that all coal refuse, newly mined and previously discarded, is processed in the same manner.
In response to comments, the EPA is including provisions in the final rule similar to those included in the final "Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and Industrial Solid Waste Incineration Units" (CISWI; 76 FR 15704; March 21, 2011) rule to address units that combust different fuels at different times. The requirements contained in the final CISWI rule generally govern how units must comply when they begin and cease combusting solid waste, but, as described above, the new provisions in this final rule will address how units move between different NESHAP.
2. The EPA should exempt boilers combusting small amounts of secondary materials.
Comment 3: Commenter 17402 respectfully requests that the EPA use its inherent de minimis authority to exempt boilers combusting small amounts of materials generated in the normal course of boiler operation from treatment as an incinerator when the materials are generated and combusted onsite. Combustion of these materials does not appreciably impact contaminant emissions, but the economic and environmental costs of alternative disposal are significant. Commenter's facilities are more properly regulated as EGUs under the Utility MACT rule, and standard operating procedures should not cause those units to be considered as incinerators.
Commenter 17402 states that the EPA should allow a de minimis exemption from treatment as an incinerator for units burning materials generated in the normal course of boiler operation. Commenter states that the EPA has a long history of de minimis authority, with the seminal case being Alabama Power Co. v. Costle. In Alabama Power, the court held that the EPA has inherent de minimis authority to exempt small sources from all but the most rigidly prescribed statutes as long as the legislative intent of the statute is not frustrated. The D.C. Circuit expressively stated that, "It is commonplace . . . that the law does not concern itself with trifling matters, and this principle has often found application in the administrative context. Courts should be reluctant to apply the literal terms of a statute to mandate pointless expenditure of effort . . . . The ability, which we describe here, to exempt de minimis situations from a statutory command is not an ability to depart from the statute, but rather a tool to be used in implementing the legislative design."
Commenter 17402 states that this authority has been applied by the EPA and upheld by the courts in a variety of different circumstances. Similar to the examples described below, the EPA has the inherent authority under RCRA to limit the application of the incinerator standards in situations where the intent of the statute would not be frustrated, and imposing the regulation would produce no or trivial benefits. It should do so here with respect to boiler cleaning wastes, spent demineralizer resins, and the other minor constituents generated in the normal course of boiler operations.
Commenter 17402 requested in its comments on the proposed Solid Waste Rule, and again in its reconsideration, that the EPA clarify that burning de minimis amounts of non-hazardous boiler cleaning wastes and other traditional byproducts of boiler operation does not transform a boiler into an incinerator, even if the byproducts have a low heat value. The same principle applies to an EGU. As discussed below, and in more detail in EME's CISWI and Solid Waste Rule petitions, the EPA has sufficient de minimis authority to prevent applications of the law which would have trifling benefits at extremely high cost.
Commenter 17402 states additionally, reconsidering the interaction between the CISWI, Solid Waste, and Utility MACT Rules in the manner we seek will promote the principles of the recent regulatory Executive Order 13563, which was issued after the rules were signed. The EPA should use the reconsideration of the Solid Waste Rule as an opportunity to apply the principles of the Executive Order. Specifically, the EPA should incorporate a cost-benefit analysis into its application of the solid waste definition, and avoid illogical results that treat identical materials differently and create a greater potential for harm to the environment. The EPA should also allow regulatory flexibility in continuing existing utility practices by allowing de minimis exemptions from the solid waste definition under RCRA. The EPA failed to address EME's request for an exemption in the final rule, and should correct that oversight here. Both of EME's requests are in line with the principles of the Executive Order and will reduce unnecessary regulatory burdens.
Commenter 17402 states that an exemption for materials generated in the course of normal boiler operations would fit squarely within the scope of the EPA's de minimis authority. Commenter states that on the whole, Courts have found broad authority for the EPA to exempt minor sources of contaminants when a strict legal application would provide little or no benefit. Given the limited emissions impacts and low contaminant levels inherent in materials generated in the regular operation of the boiler, the EPA's de minimis authority allows it to exempt those materials from treatment as solid wastes, and to exempt EGU's combusting small amounts of those materials from incinerator standards.
Commenter 17402 states that the EPA allows similar de minimis exemptions under the solid waste rule and other rules under RCRA. The EPA already uses its de minimis authority under RCRA and, indeed, has applied it in the Solid Waste Rule. The EPA allows a de minimis exemption for contaminants, including paper, insulation, and other items which may be included in construction wastes demolition derived wood ("C&D wood"): "C&D-derived wood can contain de minimis amounts of contaminants and other materials provided it meets the legitimacy criterion for contaminant levels."
Commenter 17402 states that the EPA has also applied its de minimis authority under RCRA in the hazardous waste context, allowing listed wastes to be discharged to a wastewater treatment facility as long as the total concentration of the chemicals does not exceed a certain threshold. The EPA allows similar exemptions from characterization as solid wastes for condensates derived from overhead gases from Kraft mill steam strippers that are used to comply with 40 CFR § 63.446(e) where the exemption applies only to combustion at the mill generating the condensates, 40 CFR § 262.4(a)(16), or pulping liquors that are reclaimed in a pulping liquor recovery furnace and then reused in the pulping process, 40 CFR § 261.4(a)(6). One of the requirements under 40 CFR § 63.446(e) is for the condensate to be treated so it is either managed in specified equipment or in a manner that ensures the HAP are destroyed to specified levels. Similar requirements could be used in a de minimis exemption under CAA section 1004, limiting any exemption to onsite materials that do not significantly increase the level of contaminants.
Commenter 17402 states that the emissions impacts of an exemption would be trivial. Combusting and evaporating boiler cleaning wastes and other materials generated in the course of normal boiler operations is standard practice, and currently part of most electrical generating units' air permits in North America. Allowing this practice to continue would not increase emissions. Further, without a de minimis exemption to maintain their status as generators, not incinerators, generating unit operators would be required to transport cleaning wastes and other materials to an offsite disposal site, incurring additional expenses, generating more emissions in the process, creating potential safety issues associated with transportation of materials, and disposing of the wastes without necessarily destroying them.
Commenter 17402 states that there is little to no environmental benefit to requiring alternate disposal of materials in control of the generator that have only a de minimis impact on emissions. The emissions impact from evaporating boiler cleaning materials, for example, is comparatively small and the resulting total variation in emission of pollutants from their combustion would likely be similar to that from normal variation resulting from differences in coal composition. Emissions tests of the ESP outlet flue gas conducted by EPRI during evaporation of boiler cleaning wastes showed no statistically significant increases in metal concentrations over baseline data. In addition, the concentrations of NOx, HCl, and HF present in the flue gas were also not statistically affected. In monitoring studies conducted by EPRI on evaporation of boiler cleaning wastes in utility boilers, chromium levels in the stack gas were 0.076 lb/hr at baseline vs. 0.080 lb/hr during evaporation. Chromium is the metal typically of the highest concentration in boiler cleaning wastes and the boiler cleaning wastes are tested prior to combustion to ensure the concentrations are below the hazardous level. Results for other metals, PM, and trace organics were similarly low.
Commenter 17402 states that water treatment resins are used to demineralize boiler feed water. Like home water softeners, utility-scale water treatment resins are used to remove minerals and other compounds that would lead to corrosion and premature failure of boiler pressure parts. Although resins can be reused multiple times, they eventually become spent and can no longer effectively cycle to capture minerals and release them, at which point they must be replaced. Resins typically have significant fuel value, and are relatively low in contaminants, as they are repeatedly flushed to remove mineral contents. Further, any contaminants they contain would be from the water supply, not the fuel supply, and thus with limited potential for hazardous materials to be included.
Commenter 17402 states that boiler cleaning wastes and other non-hazardous materials have routinely been allowed to be evaporated in onsite utility boilers because they do not appreciably increase emissions and thus pose minimal risk to the environment. As an example, Commenter provides the following permit condition, included in its Illinois facility air operating permits: "The permittee is allowed to burn boiler cleaning wastes only when the boiler is in a normal mode of operation and generating no less than 105 megawatts (gross). Burning of boiler cleaning wastes is not allowed during startup, shutdown, malfunction or breakdown."
Commenter 17402 states that operating information submitted by the generating station to obtain the permit indicates that to ensure steady boiler operations the maximum boiler cleaning waste feed rate to the boilers of up to 200 gpm depending on the size of the unit.
Commenter 17402 states that with respect to the volumes of onsite generated materials such as boiler cleaning wastes that would be evaporated in the boilers, Commenter's experience is that the waste volumes range from approximately 250 to 1835 tons per boiler per boiler cleaning event, but would only be fed to the boiler at a rate of up to 0.8 tons per minute. This contrasts with a total amount of coal burned on average in each boiler of between 1,420 and 8,220 tons per day. The boiler cleaning frequency can vary from every two to ten years, depending on the type of boiler and amount of contaminants introduced into the boiler water cycle. Other materials generated include resins from water treatment; however, those materials are even more limited in amounts than the boiler cleaning wastes. Regardless, the annual amount of boiler cleaning wastes generated for each individual boiler is relatively small.
Commenter 17402 states that the application of de minimis authority where emissions impacts are trivial is consistent with how courts have addressed the authority in the context of similar situations. As in EDF, here a de minimis exemption for materials generated in the normal course of boiler operation would have minimal or no impact on the level of emissions. Since this does not affect the purpose of the CAA, i.e., reducing emissions, allowing such an exemption would be a proper exercise of the EPA's de minimis authority.
Commenter 17402 states that requiring application of section 129 to de minimis amounts of secondary materials would be a mandate of pointless expenditure. Although the volumes of solvents are relatively small compared to the overall volume of fuel burned, the costs of the disposal for a boiler cleaning event can exceed $1 million per event in Commenter's experience and, as a result, the costs to the industry may exceed $50 million per year. The volumes generated per year that would require offsite disposal are estimated at 125,100 tpy. This compares to annual coal burned of over 1 trillion tpy. Commenter questions whether there is sufficient treatment capacity for this volume of material, which the EPA may not have considered because the volumes and frequency of occurrence per facility are relatively low. As in Alabama Power, the flexibility to prevent these kinds of needless expenditures and unnecessary burdens are exactly the reasons that the courts originally applied de minimis exemptions. Given the trivial impact on emissions, the environmental and economic costs generated by treating generators as incinerators because of common utility practice is simply not justified. Commenter requests that the EPA apply its de minimis authority to prevent this unnecessary regulatory burden.
Commenter 17402 states that the text of section 1004 Of RCRA and section 129 of the CAA is not "uncompromisingly rigid." In section 1004, "solid waste" is defined as: "any garbage, refuse, sludge from [treatment facilities] and other discarded material, including solid, liquid, semisolid, or contained gaseous material resulting from industrial, commercial, mining, and agricultural operations, and from community activities . . . "
Commenter 17402 states that a similarly expansive definition is the basis for treatment as an incinerator under CAA section 129 of the CAA, where "solid waste incineration unit" is defined as: "a distinct operating unit of any facility which combusts any solid waste material from commercial or industrial establishments or the general public (including single and multiple residences, hotels, and motels)."
Commenter 17402 states that although clearly broad, these definitions are not so restrictive as to prevent a de minimis exemption, and are similar to the provisions for which courts have allowed exemptions under the CAA and CERCLA. Specifically, in New York v. EPA, the court recognized the EPA's inherent de minimis authority notwithstanding the language "any modification." The D.C. Circuit in EDF also allowed an exemption from the broad "any activity which does not conform to an implementation plan after it has been approved or promulgated" when increases in emissions were trivial. Finally, in Ohio v. EPA, the court upheld the EPA's de minimis authority to only monitor sites with minimal contamination despite the language of CERCLA that required monitoring of any sites with "any hazardous substances."
Commenter 17402 states these definitions also include several more general exemptions, such as materials in domestic sewage, irrigation return flows, certain industrial discharges, or radioactive materials, further supporting a conclusion that Congress did not intend an "uncompromisingly rigid" application of the provision. Applying the EPA's de minimis authority will not frustrate, and has the potential to further, the goals of the statute. EME respectfully requests that the EPA do so here.
Commenter 17402 states that with appropriate limitations to ensure that the intents of both RCRA and the CAA are not harmed, a de minimis exemption for boiler cleaning materials would allow compliance at a level that would increase emissions less than the natural variation in a power plant's regular coal supply. As a fairly irregular procedure, with a relatively small impact on emissions, boiler cleaning materials are exactly the kind of "trifling matter" considered in Alabama Power that are not worth the undue expense or complication of additional regulation. Commenter respectfully requests that the EPA reconsider its request for a de minimis exemption for boiler cleaning materials generated under the course of regular operations and that remain in possession of the generator.
Response to Comment 3: Although we are mindful of commenter's concerns, particularly as they relate to the boiler cleaning waste, we believe that the statute and case law limit our ability to exempt units that combust solid waste. CAA section 129 defines "solid waste incineration unit" as "a distinct operating unit of any facility which combusts any solid waste material from commercial or industrial establishments or the general public" See CAA section 129(g)(1). In Natural Resources Defense Council v. EPA, the Court held that the term "solid waste incineration unit" in CAA section 129(g)(1) "unambiguously include[s] among the incineration units subject to its standards any facility that combusts any commercial or industrial solid waste material at all  -  subject to the four statutory exceptions identified [in CAA section 129(g)(1)]." 489 F.3d 1250, 1257 - 58 (D.C. Cir. 2007) (emphasis added). Combustion units located at commercial or industrial facilities that combust solid waste as that term is defined in the rule entitled "Identification of Non-Hazardous Secondary Materials That Are Solid Waste" (Solid Waste Definition Rule; 76 FR 15456; March 21, 2011) are subject to standards under CAA section 129, unless the unit is expressly exempt pursuant to CAA section 129(g)(1). Facilities that include EGUs would generally be considered commercial or industrial facilities and the EPA established standards for "energy recovery units" in the CISWI rules. Because the Agency defines solid waste under RCRA, comments requesting we include a de minimis level exemption into the RCRA Solid Waste Definitions Rule are outside the scope of this rulemaking. For these reasons, we are not including a de minimis exemption in the final rule. We need not respond to the remainder of the de minimis comments as they also pertain to the RCRA Non-Hazardous Solid Waste rulemaking and are, thus, outside the scope of this rulemaking.
3. The EPA should treat legacy coal rejects as fuels.
Comment 4: Commenter 17402 states that the EPA should treat legacy coal rejects as fuels, since they are chemically identical, if not superior fuels, to those coal rejects which are currently generated that the EPA recognizes as a fuel under the rule. The EPA mistakenly concludes that it is required to do so under the statute because of the length of time the materials have been unused, but the actual language of the statute and the applicable case law demonstrate that Resource Conservation and Recovery Act ("RCRA") is not so rigid as EPA has presumed.
Commenter 17402 appreciates the fact that in the Solid Waste Definition Rule the EPA improved its treatment of coal rejects from the proposal by allowing currently generated coal mining rejects to be treated as fuel. Unfortunately, when the EPA defined existing or "legacy" coal mining reject piles as solid waste, it potentially subjected facilities that burn legacy coal rejects and their suppliers to citizen suits and other enforcement under RCRA. By increasing that risk, the EPA greatly reduces an electricity generating facility's ability to utilize legacy coal fuel resources in a cost-effective manner, also reducing the simultaneous removal of the blight of such coal piles from the landscape. CFB electrical generating facilities were constructed, once the technology was developed, specifically to burn coal rejects as a primary source of fuel or as a secondary fuel to coal. As such, this interpretation will impose economic and environmental costs on electricity generators using coal rejects for fuel and return to the public little to no benefit, in terms of either emissions reductions or resource recovery. As discussed in more detail in Commenter's petition for reconsideration of the Solid Waste Rule, this result is not compelled by the law, and the EPA should have reconsidered this aspect of the Solid Waste Rule and its impacts on the CISWI, Boiler MACT, and ultimately the Utility MACT rule that is the subject of this comment. By not treating legacy coal as solid waste, the EPA could remove a requirement that is excessively burdensome, hampers the use of innovative technology and less costly methods for remediation, represents poorly coordinated rulemakings, and has a high cost-to-benefits ratio.
Commenter 17402 states that using coal from legacy piles in electricity generating units provides numerous environmental benefits. If not economical for use as a fuel in electricity generation, legacy coal piles are expensive to remove and treat, and would likely remain a dangerous feature of coal country landscape. Legacy coal piles can leach contaminants, similar to acid mine drainage. Replacing the legacy coal in the nation's electricity supply requires mining fresh coal, which requires resources and economic expense and poses its own environmental concerns. Some of the fuel replacing legacy coal may also be burned in plants with less effective emissions controls than the fluidized bed reactors used for legacy coal. If legacy coal piles are required to upgrade their environmental performance in order to be accessed by generators, then that fuel asset will become more expensive as compared to newly mined coal, with the net result that the piles are likely to remain untreated, and continue damaging the environment. The economic costs associated with mitigating the impacts of legacy coal piles can be quite significant, and coal rejects combustors play an important role in addressing those areas. Legacy coal operators will either face increasing competition for currently generated mining rejects, or will be forced to use more expensive grades of coal, thus affecting the economics of operating the CFB units. As a result of the potential negative impacts to this environmentally beneficial use of a troubled resource, Commenter encourages the EPA to reconsider the treatment of legacy coal piles in the Solid Waste Rule.
Commenter 17402 states that, as issued, the final Solid Waste Rule treats coal mining rejects from prior mining operations as solid waste unless they are sufficiently "processed" into a fuel product. Yet, this treatment is distinct from that of coal mining rejects that are currently generated by mining operations, which are not required to be processed to be considered fuel. The materials are identical, and should be treated so. Fortunately, the law does not mandate the result the EPA reached in the final rule that the EPA treat these legacy materials as solid waste under RCRA.
Commenter 17402 states that section 129 (g) (6) of the CAA indicates that the term "solid waste" shall have the same meaning as established by the Administrator under the Solid Waste Disposal Act, 42 U.S.C. §6901 et. seq., also known as RCRA. In RCRA Section 1004, solid waste is defined as, "any garbage, refuse, sludge from [treatment facilities] and other discarded material, including solid, liquid, semisolid, or contained gaseous material resulting from industrial, commercial, mining, and agricultural operations, and from community activities . . . "
Commenter 17402 states that the EPA's authority over solid waste is focused almost entirely on hazardous wastes, with the states retaining authority over non-hazardous solid wastes subject to certain exceptions. As a result, although the EPA has published extensive regulations with regard to hazardous solid waste, those regulations explicitly exclude non-hazardous wastes. The EPA has not previously promulgated detailed regulations regarding the definition of non-hazardous solid-waste.
Commenter 17402 states importantly, the EPA (correctly) does not attempt to apply all of the principles of those hazardous waste regulations in the proposed rule; the EPA, however, does attempt to incorporate case law based on the EPA's central RCRA role of regulating hazardous wastes to the definition of non-hazardous solid waste, with mixed results. Although the hazardous waste case law may add guidance as to how courts might interpret a non-hazardous waste definition, because "cradle-to- grave" hazardous waste authority is central to the EPA's purpose under RCRA, those interpretations may not be applicable to the non-hazardous solid waste definition, where the EPA plays a far less central statutory role.
Commenter 17402 notes that the 2007 decision in NRDC v. EPA, which invalidated the EPA's prior interpretation of the solid waste incinerator definitions in the CAA, did not address the RCRA definition of "solid waste." As a result, the EPA retains significant discretion and little on-point case law in its creation of a "solid waste" definition. This discretion is applied inconsistently in the final rule, resulting  -  in the case of legacy coal piles in particular  -  in a needlessly burdensome rule that produces some illogical results. The EPA should add the Solid Waste Rule to the list of the related rules issued simultaneously that the EPA wisely moved to immediately reconsider (and subsequently stayed.) When it does so, the EPA should exercise the discretion afforded it under the statute and apply the principles of Executive Order 13563 to produce a more thorough, reasoned, cost-effective, and ultimately beneficial rule.
Commenter 17402 states that the EPA treats legacy coal piles as solid waste based on a presumption that everything discarded is necessarily solid waste. The EPA should reconsider this presumption for three core reasons: (1) EPA recognizes in the rule that certain materials which are discarded are not solid waste; (2) EPA did not consider in its analysis support in both the statutory language and case law that suggests that although a material must be "discarded" to be considered solid waste, not every material that is discarded is necessarily solid waste; and (3) the case law that suggests a more expansive approach is explicitly premised on the "cradle-to-grave" nature of the RCRA hazardous waste regime  -  a regime which is utterly inapplicable to the non-hazardous materials at issue in this rule. Each of these points is discussed in more detail in Commenter's reconsideration petition.
Comment 5: Commenters (17754, 17838, 18963) state that within the preamble to the proposed rule, the Agency reiterates its position, as originally stated in the EPA's recently promulgated final rule, "Identification of Non-Hazardous Secondary Materials That are Solid Waste," that currently mined coal refuse should not be considered a solid waste under the RCRA, as long as it is not discarded. By contrast, the EPA appears to indicate within the Solid Waste Definition Rule that legacy coal refuse qualifies as a solid waste in the first instance, because it has been discarded. The EPA makes clear, however, that if legacy coal refuse is processed in the same manner as currently mined coal refuse, the legacy coal refuse would not be a solid waste at the point of combustion, and therefore the combustion of such material would not be subject to regulation under CAA section 129. Instead, the relevant combustion unit would be subject to the Utility MACT regulation, if the unit meets the definition of EGU.
Commenters (17754, 17838, 18963) state that the information available to them is consistent with the EPA's assumption that all units that combust coal refuse and otherwise meet the definition of a coal refuse fired EGU combust either newly mined coal refuse or legacy coal refuse that has been processed such that it is not a solid waste. In fact, Commenters are not aware of any unit combusting coal refuse that qualifies as solid waste, such that the unit would be a solid waste incineration unit instead of an EGU.
Commenters (17754, 17838, 18963) state that in May 2011, they submitted to the EPA a Petition for Regulation regarding the Solid Waste Definition Rule. Among other comments raised in its Petition, Commenters argued that, even prior to any processing activity, legacy coal refuse should be classified as a traditional fuel under the Solid Waste Definition Rule, rather than as a solid waste. Commenters offered several justifications in support of this argument. First, legacy coal refuse is indistinguishable from currently mined coal refuse, based on the definition of "traditional fuels" in the Solid Waste Definition Rule. Second, the segregation of legacy coal refuse from other usable coal fuel during the initial mining operations did not reflect any contemporaneous determination that such legacy coal refuse did not have value as a fuel. Third, operations processing legacy coal refuse to produce fuels are separately regulated as mining activities by the Office of Surface Mining Reclamation and Enforcement ("OSM"), pursuant to the Surface Mining Control and Reclamation Act, 30 U.S.C. § 1201 et seq. ("SMCRA"), and the EPA has consistently determined to exclude from regulation under the solid waste regime those material processing activities subject to regulation by OSM as mining activities. For these reasons, Commenters requested that the EPA revise the definition of "traditional fuels" in the Solid Waste Definition Rule to expressly identify legacy coal refuse as an alternative traditional fuel.
Commenters (17754, 17838, 18963) also argued in their Petition that, to the extent that the EPA does not agree to regulate legacy coal refuse as a traditional fuel under the Solid Waste Definition Rule, the Agency should revise the Solid Waste Definition Rule to expressly provide that legacy coal refuse is a legitimate non-waste fuel at the point of combustion, because it is processed in the same manner as coal is today. Consistent with the EPA's assumption stated in the preamble to the proposed rule that any legacy coal refuse being combusted in EGUs has been processed such that it is not a solid waste, the EPA unequivocally acknowledges within the preamble to the Solid Waste Definition Rule that legacy coal refuse is processed in the same manner in which virgin coal is processed, thereby meeting the EPA's standard for "sufficient processing." The EPA also clarifies under the Solid Waste Definition Rule that legacy coal refuse satisfies the applicable legitimacy criteria at the point of combustion.
Commenters (17754, 17838, 18963) believe that the EPA's intent to characterize legacy coal refuse as a non-waste fuel at the point of combustion is clearly stated within the preamble to the Solid Waste Definition Rule. The EPA's discussion of the combustion of legacy coal refuse in EGUs in the preamble to the proposed rule provides even further evidence of the EPA's intent to regulate such material as a non-waste fuel product at the point of combustion, rather than as a solid waste pursuant CAA section 129. Commenters expressly endorse this assumption, and request that the EPA achieve consistent promulgation and implementation of regulatory language in each of the relevant rulemakings to ensure that this regulatory conclusion is reflected in the Agency's standards.
Response to Comments 4 and 5: Comments on the status of "coal refuse" in the Solid Waste Definition Rule and reconsideration of that rule are not within the scope of this rulemaking and, thus, are not considered here. As noted elsewhere, combustion of any materials determined to be "solid waste" under the Solid Waste Definition Rule (76 FR 15456; March 21, 2011) would subject the unit to applicability under the CAA section 129 standards (e.g., for units at commercial or industrial facilities the "Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and Industrial Solid Waste Incineration Units" (CISWI; 76 FR 15704; March 21, 2011)). However, as one commenter noted, the EPA indicated in the proposed rule that, pursuant to the Solid Waste Definition Rule, coal refuse in legacy piles is not a solid waste if it is processed in the same manner as currently mined coal refuse. The commenter also agreed with the EPA's statement that all EGUs combusting coal refuse from legacy piles processed the coal refuse in the same manner as currently mined coal refuse such that it would not be a solid waste. We received no comments that stated that our assumption in the proposed rule was incorrect. The commenter that requested a determination in the Solid Waste Definition Rule that all coal refuse in legacy piles be considered to be a traditional fuel in all cases did not indicate that that commenter used unprocessed coal refuse and, for this reason, we believe the commenter's concern may be unfounded.
4. Units should be subject to the more stringent of the two.
Comment 6: Commenter 17796 suggests that the facility [with combustion units that are at times EGUs or solid waste incineration units subject to other standards under CAA section 112 or to standards under CAA section 129] be subject to the more stringent of the two regulations should this situation occur for the same unit at the same facility. Thus, no matter what operating scenario the unit is in, it will be in compliance with either the NESHAP or the CAA section 129 standard. In addition this would eliminate any possible confusion about the applicable regulatory requirements for both the regulator and source owner.
Response to Comment 6: Assuming EPA has this authority, we decline to finalize such a provision because CAA section 129 regulates both criteria (including NOX) and HAP which is inconsistent with the requirements of CAA section 112. Further, CAA section 129 standards do not address all HAP listed under CAA section 112(b) which, again is inconsistent with the requirements of CAA section 112. With regard to units that may be, at times, subject to different CAA section 112 rules, including the EGU NESHAP, we believe that because the term EGU is defined in section 112(a)(8), we do not have the discretion to allow sources to comply with other standards if the unit meets the statutory definition of an EGU. Similarly, EPA may not subject a unit to section 112 standards if the unit is a solid waste incineration unit subject to standards issued pursuant to section 129. See CAA section 129(h)(2). Further, we believe it would be more difficult than commenter suggests to require sources to comply with the more stringent of the potentially applicable standards because one standard could be more stringent for one pollutant and less stringent for another pollutant. Sources are authorized to comply with more stringent provisions and could petition the Administrator to approve alternative monitoring procedures if the monitoring requirements of the different rules varied. See 40 CFR 63.8(f). Sources can also work with their permitting authorities to include alternative operating scenarios in their Title V permits to account for the different standards that may at times apply to the source. As explained above, we have included in the final rule provisions that address units that move into and out of applicability to this final rule. For these reasons, we are declining to include provisions similar to those suggested by the commenter.

2D - Applicability: Exemptions or de minimis size threshold
Commenters: 17316, 17386, 17681, 17689, 17696, 17718, 17725, 17733, 17740, 17760, 17775, 17796, 17803, 17805, 17808, 17820, 17881, 17902, 17911, 17913, 17920, 17928, 18020, 18024, 18450, 18498
Commenters have made several comments regarding applicability and exemptions.
1. Exemption for units that fire 10% or less oil or coal.
a. The EPA should clarify whether this exemption can be applied dynamically.
Comment 1: Commenters 17316 and 17386 strongly support the allowed exemption from the MACT rule for units whose annual average heat input on coal or oil is less than 10 percent of their total annual heat input, as a 3‐year average. Commenters add, however, that the rule should clarify whether this exemption can be applied dynamically. In particular, if a unit should initially qualify for this exemption, but subsequently have a utilization that exceeds the qualification threshold (i.e., has a 3‐year average utilization >10% or a 1 year utilization >15%), thereby losing its exemption status, can the unit re‐gain exemption status if its utilization should later drop below the qualification thresholds? Commenters support the idea that this exemption should be determined dynamically, allowing a source to re‐qualify for exemption status if its operating usage should drop below this exemption threshold after exceeding it. Commenters note that this would be consistent with peaking unit status determination under 40 CFR 75.
Comment 2: Commenter 17881 asks is qualification for the provisions of 63.9983(c) a onetime determination which is made just prior to the compliance date, or can units qualify for 63.9983(c) at any time after the applicable compliance date (as well as lose the exemption at any time)? For example, if the final rule is issued 01/01/2012 (such that existing units must comply starting on 01/01/2015), could an existing unit qualify for the provisions of 63.9983(c) based upon the three calendar year period 2013, 2014 and 2015?
Commenter 17881 states that it is assumed that qualification for 63.9983(c) would consist of both an initial demonstration and an ongoing demonstration to be completed following the end of each calendar year. If this assumption is correct, the proposed rule should have provisions which address the loss of the exemption. If the exemption is lost after the applicable compliance date, how long would such a unit have to demonstrate compliance with the proposed rule? In the absence of such provisions, it is assumed that 63.9982 would require compliance immediately upon loss of the exemption, and this is not realistic in cases where additional controls must be installed and/or significant changes must be made to the fuel blend.
Commenter 17881 asks whether the provisions of 63.9983(c) allow EGUs to re-qualify for the exemption if the exemption is lost following the initial compliance date. For example, if an EGU qualifies for the exemption in years 1 and 2 following the compliance date, loses the exemption in year 3, and then once again meets the criteria in year 6, would such a unit once again be exempt from the rule in year 6? Many standards under 40 CFR Part 63 utilize a "once in, always in" approach, and the proposed rule is not clear in this regard.
Commenter 17881 believes that 63.9984 should contain one or more paragraphs devoted to the applicable compliance date for those units that lose the exemption provided at 63.9983 following the applicable initial compliance date. In those cases where additional control technology will be installed to ensure compliance, it seems reasonable to allow at least 3 years for completing such installations.
b. Units that stop combustion of coal and/or oil prior to the compliance date should not be subject to the rule.
Comment 3: Commenters (17696, 17740, 17775, 17820) state that the EPA should clarify that an EGU can qualify as a natural gas-fired unit (or biomass unit) and not be subject to the rule if, as of the compliance deadline, the unit has a federally enforceable permit limit that requires use of natural gas fuel (or biomass) for at least 90 percent or more of the average annual heat input during any three calendar year period and 85 percent or more of the annual heat input during any calendar year. That is, the EPA should not require an owner/operator to switch an EGU to burning natural gas (or biomass) in the requisite amounts 3 years prior to the compliance deadline in order to avoid applicability of the rule as of the compliance deadline. Rather, the rule should clearly allow an owner/operator to switch to burning natural gas (or biomass) as of the compliance deadline and thereby avoid applicability of the rule so long as a federally enforceable permit condition requiring natural gas (or biomass) use is in effect as of the deadline.
Comment 4: Commenter 17820 states that for units that cease burning oil or coal (conversions to natural gas or to biomass), the proposed rule needs to be modified to allow a more flexible transition process that assures that units converting to biomass or natural gas are not penalized for having burned oil or coal in the period before compliance and are assured exemption from the rule as long as they stop combusting oil or coal prior to the compliance date.
Commenter 17820 states that the EPA should revise the definition to change the "look-back" period to begin 3 years after the unit's final compliance date. This change would not penalize a unit that switches to natural gas and retains the ability to combust coal or oil (a desirable outcome to provide system reliability) for having burned coal or oil in the period before compliance. The EPA should also clarify that a unit that switches to natural gas or biomass and later switches back to highly controlled coal use would not be in violation of the 3-year average for the years it was burning natural gas or biomass.
Comment 5: Commenter 17902 requests that section 63.9983(b) and (c) be amended to also exclude units that will burn more than 10 percent natural gas as of the required compliance date for subpart UUUUU. This exclusion should apply even if the prior year combustion of coal or oil was greater than the percent thresholds given in section 63.9983. If an EGU is primarily natural gas-fired then it should not be subject to the MACT emissions limits or associated compliance MRR that are intended for coal- or oil-fired units.
Response to Comments 1 - 5: In the proposed rule, the EPA stated through the definition of "fossil fuel-fired" that an electric steam generating unit would not be considered fossil fuel-fired such that it would be an EGU subject to this final rule unless it burned more than 10% fossil fuel over the previous 3 years or more than 15% fossil fuel in any one of those years. We included this definition because the statute does not define the level of fossil fuel combustion necessary to make a unit subject to the CAA section 112(a)(8) definition. We do not consider the definition an exemption from the rule, instead it was included to assist sources in determining applicability. Sources that do not meet the definition of an EGU as established in the final rule are not subject to the rule. Thus, a unit may cease to be an EGU subject to this rule if over a 3-year period it combusts less than 10 percent fossil fuel. Such a unit would then be subject to an otherwise applicable standard. As stated above, we are adding provisions to the final rule that address the situation where sources become subject to this rule after the compliance date. In addition, we added a provision to 40 CFR 63.9984 as suggested by the commenter.
Partly based on comments, the EPA has revised several definitions, including the definition of "fossil fuel-fired," in the final rule to make clear that units must only look at the present capability and utilization of the unit to determine if it is an affected source on the compliance date. Sources will have to evaluate ongoing applicability of the standards based on their utilization of fossil fuels over annual and tri-annual periods. For example, an EGU that on the first substantive compliance date meets the definition of fossil fuel-fired will no longer be subject to the NESHAP if in subsequent years its utilization of coal or oil falls below the threshold levels to satisfy the definition of fossil fuel-fired. A source could also obtain a Title V permit requirement that prohibits the utilization of coal or oil at levels sufficient to satisfy the definition of fossil fuel-fired. Sources that violate a Title V permit limit would not only be in violation of Title V, but also in violation of the requirement to comply with this NESHAP if it exceeded the applicability thresholds and was not complying with the standards during the relevant periods. A unit that spends the 3 year (or 4 years if necessary for the installation of controls) compliance period converting the unit to natural gas or biomass will not be subject to this rule based on our revised definition of fossil fuel-fired.
The EPA believes that the current definitions adequately indicate that natural gas-fired units are not subject to the final rule, and we are adding a definition for natural gas-fired EGU in the final rule.
c. Permit limits with specific fuel caps.
Comment 6: Commenter 17796 does not believe it is appropriate to allow facilities that fire less than a certain percentage of coal or oil or only natural gas to be exempted from this regulation unless the facility has permit limitations with specific fuel usage caps that do not allow operation above these fuel use percentages.
Response to Comment 6: In the final rule, the EPA provides as an alternative compliance assurance measure that sources may include in their Title V operating permit a practically enforceable limit on the authorized fossil fuel utilization to demonstrate that the source is not an affected source under the final rule; however, we do not believe it is necessary to require sources to include such limits in their Title V permits.
d. The EPA should clarify that predominantly gas-fired units are not subject to the rule.
Comment 7: Commenter 17913 states that the regulation should clearly indicate that it is not applicable to predominately gas-fired units. From information given in the proposed rule preamble, the intent was that a facility that predominately burns natural gas would not be subject to the regulation based on the percentage of natural gas used at the facility (natural gas more than 90 percent of heat input average over previous 3 years or more than 85 percent in anyone of three previous years). However, these applicability criteria don't appear in the proposed rule itself. The applicability section (paragraph 63.9982) or the definitions section (paragraph 63.10042) should be revised to clearly state that predominately gas-fired units are not subject to the regulation.
Response to Comment 7: The EPA believes that sections 63.9981 and 63.9982 of the proposed rule clearly indicate that only coal- and oil-fired units are subject to the rule. In addition, section 63.9983(b) states that "any EGU that is not a coal- or oil-fired EGU and combusts natural gas more than 10.0 percent of the average annual heat input during the previous 3 calendar years or for more than 15.0 percent of the annual heat input during any one of those calendar year" is not subject to this final rule.
e. The EPA should allow units firing less than 50% fossil fuels to be exempted.
Comment 8: Commenter 17911 states that the EPA in the proposed rule requested input about the level of biomass that must be used before a plant would be considered other than coal-fired or oil-fired. Commenter understands the Agency's reasoning for wanting to establish a significant upper limit on the use of biomass fuel sources before exempting the unit from the emission requirements of this rule. Commenter agrees that allowing a marginal heat input from sustainable biomass, e.g., 5 percent to 10 percent of total heat input per year, would encourage some generators to make a marginal switch to a reformulated fuel stream without making any significant difference in their general operation.
Commenter 17911 states, however, requiring an 85 percent or greater heat input from biomass in any given year, or 90 percent over 3 years may significantly reduce the potential for a significant transition from coal to biomass. As an example, before this rule was announced the City of Columbia, MO was already in the process of retrofitting their +/- 40MW coal-fired power plant to burn a mixture of coal and biomass in an effort to effectively reduce the amount of CO2 being released into the atmosphere. As written, the draft rule may discourage the city from moving ahead with its efforts. The cost of conversion to a coal/biomass mix and compliance with the EGU MACT may not be financially sustainable. In this case, the rule may actually make total emissions higher.
Commenter 17911 states that the Agency should consider language allowing power plants with less than 50.0 percent heat input from fossil-fuel to be exempted, if the remaining heat input comes from biomass. In this manner, the rule will encourage a transition to biomass-fueled generation, and will further encourage development of a robust biomass fuel generation sector. Over time the amount to qualify for the exemption could be modified as the sector capacity increases.
Response to Comment 8: The EPA believes that the criteria currently in the definitions in the final rule adequately protect biomass-fired EGUs that limit coal or oil use for start-up or flame stabilization to the 10 and 15 percent usage limits. We believe fossil fuel combustion above these levels makes the unit"fossil fuel-fired" and we are maintaining these thresholds in the final rule. The EPA believes that exempting coal or oil use at levels greater than those in the final rule would be inconsistent with the decision to list coal- and oil-fired EGUs, particularly given the fact that the HAP of greatest concern from EGUs are fuel borne HAP.
2. Exemption for limited-use oil fired units.
All comments have been moved or combined with other comments.
3. Exemption for all oil-fired units.
Comment 9: Commenter 17316 suggests that the EPA should consider exempting existing oil-fired EGUs from the Electric Utility MACT, or at least limiting compliance to a periodic tune‐up. Commenter notes that Table 2 in the preamble shows that oil-fired boilers emit minor to insignificant amounts of HAP, except for Ni. Commenter states that because of the manner in which the CAA section 112 law is formulated, once a category is listed the MACT, emission limits are very stringent, and cannot be relieved. Commenter states that the small environmental reduction in HAP, particularly key HAP such as mercury, to be gained from regulating existing oil-fired EGUs does not justify the substantial cost that would be incurred, including the likelihood that uncontrolled oil fired boilers will have to be shutdown entirely.