Several commenters questioned the validity of the chronic inhalation study by EPA because of (1) the use of surrogate speciated Cr emissions data instead of actual emissions data, (2) the assumption that units were run 100 percent of the time which is impossible, (3) dispersion modeling was used that is biased towards over predicting downwind impacts, and (4) estimated ambient concentrations were utilized as substitutes for real exposure concentrations for all people within a census block.
Response: The EPA disagrees with the commenters' assertion that all Cr was considered to be hexavalent. As discussed in "Methods to Develop Inhalation Cancer Risk Estimates for Chromium and Nickel Compounds," existing test data for utility and industrial boilers indicate that Cr(VI) is, on average, 12 percent of total Cr from coal-fired boilers. This document underwent peer review by three external reviewers, and all three reviewers considered EPA's use of the values to be reasonable given the limited data available for Cr speciation profiling. The EPRI inhalation study for coal-fired boilers also used the 12 percent value.
      Two EPA also disagrees that units were assumed to operate 100 percent of the time. The dispersion modeling performed for the case study facilities used hourly heat input as a temporalization factor for estimating hourly emissions, and in some cases hourly heat inputs (and emissions) were zero or very low. The commenter provided no data or information to support their claim that the dispersion modeling EPA used is biased towards overestimating downwind impacts.
      The EPA disagrees with the commenters' assertion that "real exposure concentrations for all people within a census block" must be considered because it runs counter to the long-standing approach that EPA has taken to estimate the maximum individual risk, or MIR. The MIR is defined by EPA's Benzene NESHAP regulation of 1989 and codified by CAA section 112(f) as the lifetime risk for a person located at the site of maximum exposure 24 hours a day, 365 days a year for 70 years (e.g., census block centroids). The MIR is the metric associated with the determination of whether or not a source category may be delisted from regulatory consideration under CAA section 112(c)(9). The MIR is the risk metric used to characterize the inhalation cancer risks associated with the case study facilities. The EPA used the annual average ambient air concentration of each HAP at each census block centroid as a surrogate for the lifetime inhalation exposure concentration of all the people who reside in the census block. The EPA has used this approach to estimate MIR values in all of its risk assessments to support risk-based rulemakings under CAA section 112 to date.
5. Acid Gas Risk
Comment: One commenter stated that acid gas emissions from oil-fired EGUs are not of the magnitude that triggered EPA's decision to regulate EGUs in general, raising the question of whether reduction (or even total elimination) of acid gas emissions from oil-fired EGUs could have any significant effect on EPA's goals of reducing non-cancer health risk or acidification of sensitive ecosystems in the U.S.
 	Several commenters stated that acid gas concentrations estimated in the case study facility assessment and the Utility Study do not exceed human health thresholds of concern. Two commenters stated that HCl emissions are negligible compared to other primary emissions (such as SO2) that can lead to potential acidification of ecosystems.
Response: As explained in the preamble to the proposed rule, EPA is not adopting an emissions standard based on its authority under CAA section 112(d)(4) in the final rule. The EPA first notes that the Agency's authority under CAA section 112(d)(4) is discretionary. That provision states that EPA "may" consider established health thresholds when setting emissions standards under CAA section 112(d). By the use of the term "may," Congress clearly intended to allow EPA to decide not to consider a health threshold even for pollutants that have an established threshold. As explained in the preamble to the proposed rule, it is appropriate for EPA to consider relevant factors when deciding whether to exercise its discretion under CAA section 112(d)(4), and the language of that provision does not prevent the Agency from considering factors not specifically enumerated. To interpret the statute as commenters suggest would effectively require the Agency to establish CAA section 112(d)(4) standards whenever there is an established health threshold for a HAP. The EPA has considered the public comments received and is not adopting an emissions standard under CAA section 112(d)(4) for the reasons explained below and in the preamble to the proposed rule.
      First, as explained in the preamble to the proposed rule, EPA maintains that the potential cumulative public health and environmental effects of acid gas emissions from EGUs and other acid gas sources located near EGUs supports the Agency's decision not to exercise its discretion under CAA section 112(d)(4). The EPA did not receive information regarding facility-specific emissions of all the acid gases from EGUs as well as sources that may be co-located with EGUs or nearby such sources. Additional data were also not provided during the comment period, and the data already in hand regarding these emissions are not sufficient to support the development of emissions standards for any of the EGU subcategories under CAA section 112(d) that take into account the health threshold for acid gases, particularly given that the Act requires EPA's consideration of health thresholds under CAA section 112(d)(4) to protect public health with an ample margin of safety. The commenters' assertions that EPA has sufficient data, even for HCl, are incorrect, and it appears that they believe that EPA can establish a CAA section 112(d) standard for HCl and ignore the other acid gas HAP, a belief that is also incorrect. Second, the concerns expressed by EPA in the preamble to the proposed rule regarding the potential environmental impacts and the cumulative impacts of acid gases on public health were not assuaged by the comments received.
      As explained in the preamble to the proposed rule, EPA also considered the co-benefits of setting a conventional MACT standard for HCl. The EPA considered the comments received on this issue and maintains that the co-benefits are significant and provide an additional basis for the Administrator to conclude that it is not appropriate to exercise her discretion under CAA section 112(d)(4). The EPA disagrees with the commenters who stated that it is not appropriate to consider non-HAP benefits in deciding whether to invoke CAA section 112(d)(4). Although MACT standards may directly regulate only HAP and not criteria pollutants, Congress did recognize, in the legislative history to CAA section 112(d)(4), that MACT standards would have the collateral benefit of controlling criteria pollutants as well and viewed this as an important benefit of the air toxics program. The EPA consequently does not accept the argument that it cannot consider reductions of criteria pollutants, for example in determining whether to take or not take certain discretionary actions, such as whether to adopt a risk-based standard under CAA section 112(d)(4). There appears to be no valid reason that, where EPA has discretion in what type of standard to adopt, EPA must ignore controls which further the health and environmental outcomes at which CAA section 112(d) is fundamentally aimed because such controls not only reduce HAP emissions but emissions of other air pollutants as well.
      Thus, the issue being addressed is not whether to regulate non-HAP under CAA section 112(d) or whether to consider other air quality benefits in setting CAA section 112(d)(2) standards  --  neither of which EPA is doing  --  but rather whether to make the discretionary choice to regulate certain HAP based on the MACT approach and whether EPA must put blinders on and ignore collateral environmental benefits when choosing whether or not to exercise that discretion. The EPA knows of no principle in law or common sense that precludes it from doing so.
6. EPRI Risk Analysis
Comment: Two commenters stated that a comprehensive tiered inhalation risk assessment (the EPRI study) using EPA-prescribed methods with improved emission factors, fuel data, and confirmed stack parameters did not identify significant health risks (cancer or non-cancer) among U.S. coal-fired power plants (as they existed in 2007). The commenters noted that these results contrast with those presented by EPA for its non-mercury case studies on 16 (15 coal-fired) power plants. The commenters stated that several issues appear to underlie these differences, indicating the need for EPA to reevaluate its assessment and to undertake more refined (Tier 3) risk assessment for any facility of concern. Several commenters stated that for non-mercury HAP EPA produced one study on chronic inhalation risk assessment that identified three sites with cancer risks greater that one in one million for Cr(VI), which was authored by EPA staff and not peer reviewed. One commenter stated that EPA study is based on misinformation and overestimates assumptions, and that EPA has no data demonstrating health impacts from EGU emissions of non-mercury HAP, or the benefit from reducing such emissions. Two commenters stated that no benefits will be derived from the non-mercury HAP emission reductions associated with the proposed rule because no non-mercury HAP health risks were proven, and that no showing was made that EGU non-mercury HAP emission levels reach levels associated with adverse health effects. Another commenter stated that EPA must complete a comparable and separate national-scale risk assessment for non-mercury metals in order to determine appropriateness of proposing emissions standards for non-mercury metals.
Response: The commenters are incorrect in the assertion that EPA's case studies were performed with less rigor than the EPRI analysis. The EPRI analysis used a tiered approach to risk assessment, beginning with Tier 1 using EPA's SCREEN3 dispersion model on all 470 coal-fired power plants in the U.S., and following with Tier 2 with EPA's Human Exposure Model (which uses the AERMOD dispersion model) for plants with higher risks from the Tier 1 modeling. Although tiered risk assessment is an appropriate approach, the Tier 2 modeling could have been more refined. For example, more meteorological data could have been used and building downwash could have been considered. The EPRI analysis ostensibly concluded that the Tier 2 modeling with HEM was conservative, and that because the modeled risks did not exceed certain thresholds, no further refinement was necessary. However, such refinements could result in higher modeled risks than those from the commenter's Tier 2 modeling.
      The EPA's dispersion modeling of the case study facilities was actually performed with a greater degree of refinement than the EPRI analysis, and was consistent with EPA's Guideline on Air Quality Models.
      In contrast to the approach used in the EPRI analysis, EPA used:
   1) 5 years of recent meteorological data from the weather station nearest to each facility, rather than one year of meteorological data. This is more representative of long-term (i.e., lifetime) exposures and risks.
   2) Temporally-varying emissions based on continuous emissions monitoring data, rather than assuming a constant emission rate for each facility throughout the entire simulation.
   3) Building downwash, where appropriate.
   4) The latest version of AERMOD [version 11103]
      The EPA's assessment of the case study facilities for the proposed rule concluded that three coal-fired facilities and one oil-fired facility had estimated lifetime cancer risks greater than one in a million. For the final rule, revisions were made to the case studies based on comments received, and the results indicate that five coal-fired facilities and one oil-fired facility had estimated lifetime cancer risks greater than one in a million.
      Regarding peer review, the risk assessment methodology used by EPA for the case studies was consistent with the method that EPA uses for assessments performed for Risk and Technology Review rulemakings, which underwent peer review by the Science Advisory Board in 2009. The SAB issued its peer review report in May 2010. The report generally endorsed the risk assessment methodologies used in the program. In addition, in July 2011, EPA completed a letter peer review of the methods used to develop inhalation cancer risk estimates for Cr and Ni compounds.
f. Ecosystem Impacts from HAP
Comment: Two commenters assert that EPA is not justified in regulating acid gases based on concern about the potential that acid gases contribute to ecosystem acidification rather than concerns about hazards to public health. The commenters further claim that HCl's contribution to ecosystem acidification is de minimis. The commenters point out that EPA acknowledges uncertainty in quantification of acidification and EPA relies on recently published research that is irrelevant to the question since it is based on research conducted in the peat bog ecosystem in the United Kingdom. Another commenter calls attention to several new studies published in a special issue of the journal Ecotoxicology devoted to the effects of MeHg on wildlife.
Response: Although EPA agrees that quantification of acidification effects has remaining uncertainty, the science and methodology has progressed in recent years. Based on recent peer reviewed research including Evans et al., acid gases can significantly contribute to acidification. The EPA published a comprehensive risk assessment of acidification effects of nitrogen and sulfur deposition and a policy assessment. Given the extent and importance of the sensitive ecosystems evaluated in the review of nitrogen and sulfur deposition any substance that contributes to further acidification must be considered to be affecting the public welfare. The EPA disagrees that the peer reviewed study mentioned by commenter by Evans et al. (2011) is not relevant to U.S. ecosystems. The paper presents experimental results that show 1) that HCl is highly mobile in the environment, transferring acidity easily through soils and water, 2) that HCl can transport longer distances than previously thought (given its presence in remote ecosystems, and 3) that it can be a larger driver of acidification than previously thought. The fact that this study took place in the U.K. is itself irrelevant. The chemical interactions of HCl in water are the same the world over and sensitive ecosystems exist in the U.S. as well as in Europe as illustrated in the risk assessment for NOX and SOX (U.S. EPA, 2009). Furthermore, the commenter is factually incorrect that EPA is justifying that it is appropriate and necessary to regulate HAP emissions from EGUs based on this one study. The EPA agrees with the commenter that Hg exposure in wildlife is responsible for various adverse health effects in many species across the U.S. and recognizes that research is ongoing in this area. As discussed in the preamble to the proposed rule, EPA agrees that there are potential environmental risks from exposures of ecosystems through Hg and non-mercury HAP deposition. The EPA cited relevant articles from the special edition of Ecotoxicology mentioned by the commenter in the ecosystem effects section on Chapter 5 of the RIA for this rule, which is available in the docket.
G. EPA Affirms the Finding that it is Appropriate and Necessary to Regulate EGUs to Address Public Health and Environmental Hazards Associated with Emissions of Hg and Non-mercury HAP from EGUs
      In response to peer reviews of both the Hg and non-mercury HAP risk analyses, and taking into account public comments, we conducted revised analyses of the risks associated with U.S. EGU emissions of Hg and non-mercury HAP. These revised analyses demonstrated that the risk results reported in the preamble to the proposed rule are robust to the revisions made to the risk analyses.
      Specifically, the revised Hg Risk TSD shows that up to 29 percent of modeled watersheds have populations potentially at-risk from exposure to Hg from U.S. EGUs. In the revised Hg Risk TSD, up to 24 percent of modeled watersheds have potential total Hg exposure greater than the RfD and U.S. EGU-attributable Hg deposition accounts for 5 percent or more of total deposition to those watersheds. In the revised Hg Risk TSD, U.S. EGUs contribute to potential exposure greater than the RfD in 10 percent of modeled watersheds, even excluding consideration of other U.S. and non-U.S. sources of Hg deposition. Given that 1) the percent of modeled watersheds with populations potentially at-risk increased from 28 to 29 percent in the revised risk assessment, and 2) the revised analysis includes 36 percent more watersheds, which significantly expands the coverage in several states, we conclude that the finding that emissions of Hg from U.S. EGUs are a hazard to public health is confirmed by the revised Hg Risk TSD.
      With regards to the revised non-mercury inhalation case studies, the highest estimated individual lifetime cancer risk for the one case study facility (out of 16) with oil-fired EGUs is estimated to be 20 in a million, driven by Ni emissions. For the facilities with coal-fired EGUs, there were five (out of 16) with maximum individual cancer risks greater than one in a million (the highest was five in a million), four of which were driven by emissions of Cr(VI), and one of which was driven by emissions of Ni. There were also two facilities with coal-fired EGUs with maximum individual cancer risks at one in a million, for a total of six facilities that meet or exceed the criterion for EGUs to be regulated under CAA section 112. In the preamble to the proposed rule, we reported that the maximum individual lifetime cancer risk for the one facility with oil-fired EGUs was estimated to be 10 in a million, and that there were 3 coal-fired EGU facilities with maximum individual cancer risks greater than 1 in a million (the highest was 8 in a million), and 1 coal-fired EGU facility with maximum individual cancer risks equal to 1 in a million. Given that 1) the lifetime cancer risk for the oil-fired EGU facility has increased from 10 to 20 in a million, 2) the number of coal-fired EGU facilities with cancer risks greater than 1 in a million has increased from 3 to 5, and 3) the highest risk coal-fired facility still has cancer risks of 5 in a million, which is above the 1 in a million benchmark, we conclude that the finding that emissions of non-mercury HAP from U.S. EGUs are a hazard to public health is confirmed by the revised non-mercury risk inhalation case studies.
	While we did not do new analyses on these topics, we also reiterate that 1) Hg emissions from U.S. EGUs are a hazard to the environment, contributing to adverse impacts on fish-eating birds and mammals, 2) Hg is a persistent bioaccumulative environmental contaminant, and as a result, failing to control Hg emissions from U.S. EGU sources will result in long-term environmental loadings of Hg, above and beyond those loadings caused by immediate deposition of Hg within the U.S.; controlling Hg emissions from U.S. EGUs helps to reduce the potential for environmental hazard from Hg now and in the future, and 3) it is appropriate to regulate those HAP which are not known to cause cancer but are known to contribute to chronic non-cancer toxicity and environmental degradation, such as the acid gases. These findings independently support a determination that it is appropriate to regulate Hg and non-mercury HAP emissions from EGUs. In addition, we have identified effective controls available to reduce Hg and Non-mercury HAP emissions.
      Our revised analyses still show that in 2016 the hazards posed to human health and the environment by HAP emissions from EGUs will not be addressed by other sections of the CAA; therefore, it is necessary to regulate EGUs under section 112. In addition, based on evaluation of the regulations required by the CAA, including the recent CSAPR, it is necessary to regulate EGUs under section 112 because the only way to ensure permanent reductions in U.S. EGU emissions of HAP and the associated risks to public health and the environment is through standards set under section 112. While CSAPR is projected to achieve some Hg reductions due to co-control of Hg provided by controls put in place to achieve required reductions in SO2 emissions, the Hg Risk TSD shows that a substantial percent of modeled watersheds with populations potentially at-risk from U.S. EGU-attributable Hg deposition would remain after implementation of CSAPR. While we modeled slightly higher Hg emissions from U.S. EGUs of 29 tons in our risk analysis compared to the most recent estimate of 27 tons, we do not expect that this small change would affect our finding that Hg emissions from U.S. EGUs are a hazard to public health. In addition, the actual reductions in Hg that will occur due to application of controls to meet the SO2 emissions requirements of CSAPR may differ from those projected to occur, due to differences in the technologies that individual EGU sources choose to install. The only way to ensure reductions in Hg, including those modeled as resulting from the CSAPR, is to directly regulate Hg emissions under section 112.
      We reiterate that it is necessary to regulate HAP emissions from EGUs because 1) even though the hazards from Hg will not be resolved through regulation under section 112, incremental reductions in Hg are important because as exposure above the RfD increases the likelihood and severity of adverse effects increases, 2) we cannot be certain that the identified cancer risks attributable to EGUs will be addressed through imposition of the requirements of the CAA, 3) the environmental hazards posed by acidification will not be fully addressed through imposition of the CAA, 4) regulation under section 112 is the only way to ensure that HAP emissions reductions that have been achieved since 2005 remain permanent, and 5) direct control of Hg emissions affecting U.S. deposition is only possible through regulation of U.S. emissions as we are unable to control global emissions directly.
      All of these findings independently support a finding that it is necessary to regulate EGUs under section 112. Therefore, the agency affirms its finding that it remains appropriate and necessary to regulate coal- and oil-fired EGUs under CAA section 112, and the inclusion of coal- and oil-fired EGUs on the CAA section 112(c) list of source categories regulated under CAA section 112.
IV. Denial of Delisting Petition

      During the comment period, the Utility Air Regulatory Group (UARG) submitted a petition pursuant to CAA section 112(c)(9), asking the Agency  to delete the EGU source category from the list of source categories to be regulated under CAA section 112. A copy of that petition has been placed in the docket for today's rulemaking. In support of its petition, UARG presents an analysis of the cancer and noncancer risks associated with all coal-fired EGUs in the U.S. The UARG asserts that its analysis: 1) demonstrates that emissions of HAP from EGUs do not cause any cancer risks greater than 1 in a million; 2) demonstrates that emissions of HAP from EGUs do not exceed a level which is adequate to protect public health with an ample margin of safety with respect to health effects other than cancer and which will result in no adverse environmental effect, and; 3) is consistent with documents it characterizes as EPA guidance. We disagree with UARG's assertions and for the reasons set forth below, are denying UARG's petition to delist EGUs from the CAA section 112(c) source category list.
A. Requirements of CAA Section 112(c)(9)
      Section 112(c)(9)(B) of the CAA provides that "[t]he Administrator may delete any source category" from the CAA section 112(c) source category list if the Agency determines that: (i) for HAP that may cause cancer in humans, no source in the category emits such HAP in quantities that "may cause a lifetime risk of cancer greater than one in one million" to the most exposed individual; and (ii) for HAP that may result in human health effects other than cancer or adverse environmental effects, "emissions from no source in the category or subcategory concerned...exceed a level which is adequate to protect public health with an ample margin of safety and no adverse environmental effect will result from emissions from any source."
      The EPA has the discretion to delete a source category under CAA section 112(c)(9)(B), but only if EPA concludes that both clause (i) and clause (ii) have been met. The HAP emissions from EGUs present both cancer risks and non-cancer human health effects or adverse environmental effects and, thus, the requirements of both CAA section 112(c)(9)(B)(i) and (ii) must be met. We evaluated the cancer and non-cancer risks association with HAP emissions from EGUs.
B. Rationale for Denying UARG's Delisting Petition
      The EPA is denying UARG's petition to delist EGUs from the CAA section 112(c) source category list.
      As explained in section V of this final rule, the Agency analyzed non-Hg inhalation risks from 16 EGU facility case studies. That analysis demonstrates that there are 6 EGU facilities (of the 16 that we analyzed) that have cancer risks that exceed 1 in a million. Because these cancer risk levels exceed the delisting criteria set forth in CAA section 112(c)(9)(B)(i), EPA must deny UARG's delisting petition. Although this fact alone is enough to determine that EGUs cannot be delisted under CAA section 112(c)(9), EPA also conducted a national-scale mercury assessment in connection with the development of its appropriate and necessary determination for this final rule. The results of this assessment are described fully in the preamble above and in the Technical Support Document accompanying this rule. The results of that assessment show that there are a significant percentage of watersheds that have populations potentially at risk from exposure to Hg emissions from U.S. EGUs. Specifically, up to 29 percent of the modeled watersheds have populations that are potentially at-risk from exposure to Hg from U.S. EGUs. Additionally, in up to 24 percent of the modeled watersheds, populations are potentially exposed to Hg at levels greater than the RfD and U.S. EGU-attributable Hg deposition accounts for 5 percent or more of total deposition to those watersheds. U.S. EGUs were also found to contribute to potential exposures greater than the RfD in 10 percent of modeled watersheds, even excluding consideration of other U.S. and non-U.S. sources of Hg deposition. Since these mercury impacts from U.S. EGUs "exceed a level which is adequate to protect public health with an ample margin of safety," the delisting criterion set forth in CAA section 112(c)(9)(B)(ii), EPA believes the delisting petition should be denied under that prong of section 112(c)(9) as well.
      In considering the impacts of HAP that may cause cancer in humans, our analyses show that HAP emissions from a subset of U.S. EGUs result in cancer risks above 1 in one million, thereby requiring EPA to deny UARG's delisting petition. As explained above, some commenters assert that EPA's analysis of non-Hg inhalation risks from EGUs conducted in support of the proposal for this rulemaking overstated emissions from, and risks associated with, EGUs, pointing to the analysis supporting UARG's petition as being the more correct analysis. The EPA disagrees with these comments, as noted below and in the more detailed responses to those comments provided above.
      First, EPA's analysis of the UARG petition shows that UARG based its own inhalation risk analyses on inappropriately underestimated HAP emissions, particularly non-Hg metal HAP emissions (refer to Appropriate and Necessary section on non-Hg HAP emissions for further discussion). In reviewing UARG's underlying HAP emission estimates, we identified significant errors and low bias in the non-Hg HAP metals emissions used by the petitioner. In particular, the petitioner's analysis was based on Cr(VI) emission estimates that ignored a majority of the highest Cr(VI) measurement data obtained through the EPA's ICR process, claiming that these data should be eliminated based on a statistical outlier test. The EPA re-analyzed the Cr(VI) data using an appropriate statistical outlier test (different from the outlier test used by the petitioners), and ultimately determined that the high Cr(VI) emission measurements must be considered. Although UARG did use EPA models to conduct its analysis, the emission values used in their non-Hg HAP inhalation analyses were not appropriately derived. Thus, UARG's assertion that their "analysis is consistent with EPA guidance and therefore has to be accepted as valid" is incorrect.
      Second, we re-analyzed the 16 case studies that we conducted for the proposal and revised those analyses consistent with new non-Hg HAP emissions data and corrected stack parameters provided by commenters (including UARG) during the comment period on the proposed rule. We received and incorporated revised information on stack heights and stack diameters for some of the case study EGU facilities, and further revised emissions based on the re-analysis described in the above paragraph. When completed, we determined that the corrections incorporated into the reanalysis had little effect on the overall results. In the final rule, we conclude that the maximum individual inhalation cancer risks for 6 out of the 16 case study EGU facilities are greater than 1 in a million.
      In addition to its analysis of inhalation risks due to HAP from U.S. EGUs, UARG conducted a refined multi-pathway risk assessment for emissions of Hg and several other HAP from a single model EGU facility to support its petition. In interpreting the results of this case study, UARG calculates a maximum individual cancer risk estimate of 4 in a million driven by the ingestion of arsenic emissions from the model EGU facility that have deposited out of the atmosphere. Since this maximum risk level is too high to satisfy the delisting criterion that cancer risks cannot be greater than 1 in a million, UARG dismisses the result, stating that its modeling approach is "overly conservative," even after acknowledging that its fictional model plant scenario was not designed to capture the highest potential multi-pathway risks from any EGU, and that the methods used to develop the risk estimates were based on refined models and data. The EPA believes that the results of UARG's refined modeling support our analyses showing that some U.S. EGUs in fact are responsible for cancer risks above 1 in a millions. Thus, we disagree with UARG's dismissal of the results of its own refined analysis, and believe that these analyses are further support for our denial of the UARG petition.
      The UARG also claimed that EPA's national-scale Hg analysis is not relevant to the delisting question, arguing that the statute only requires a facility-by-facility assessment of risks. As noted above, EPA appropriately assessed the risks of Hg emissions associated with the EGU source category and concluded that even assessing EGU Hg emissions alone, UARG does not meet the requirements of 112(c)(9)(B)(ii).
      For these reasons, EPA believes that the national-scale Hg analysis demonstrates non-cancer risks from U.S. EGUs that support our denial of this petition.
For all the reasons described above, EPA is denying UARG's petition to delist EGUs under CAA section 112(c)(9).
 V. Summary of this Final NESHAP
       This section summarizes the requirements of the final EGU NESHAP. Section VI below summarizes the significant changes to this final rule following proposal.
 A. What is the source category regulated by this final rule?
      This final rule affects coal- and oil-fired EGUs.
 B. What is the affected source?
       An existing affected source for this final rule is the collection of coal- and oil-fired EGUs within a single contiguous area and under common control. A new affected source is a coal- or oil-fired EGU for which construction or reconstruction began after May 3, 2011.
       CAA section 112(a)(8) defines an EGU as:
       a fossil fuel-fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale. 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 utility steam generating unit.
       If an EGU burns coal (either as a primary fuel or as a supplementary fuel) or any combination of coal with another fuel (except for solid waste as noted below) where the coal accounts for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year, the unit is considered to be coal fired under this final rule. If a unit is not a coal-fired unit and burns only oil or burns oil in combination with a fuel other than coal (except solid waste as noted below) where the oil accounts for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year, the unit is considered to be oil fired under this final rule. As noted below, the EPA is finalizing a definition to determine whether the combustion unit is "fossil fuel fired" such that it is considered an EGU as defined in CAA section 112(a)(8) and, thus, potentially subject to this final rule. In addition, using the construct of the definition of "oil-fired" from the ARP, we are finalizing a requirement that the unit fire coal or oil (or natural gas) for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year to be considered a "fossil fuel-fired" EGU as defined in CAA section 112(a)(8). If a new or existing EGU is not coal- or oil-fired, and the unit burns natural gas exclusively or burns natural gas in combination with another fuel where the natural gas constitutes 10 percent or more of the average annual heat input during any 3 calendar years or 15 percent or more of the annual heat input during any 1 calendar year, the unit is considered to be natural gas-fired EGU and not subject to this final rule. As discussed later, we believe that this definition will address those situations where either an EGU fires co-fires limited amounts of coal or oil with natural gas or other non-fossil fuels (e.g., biomass).
       If an EGU combusts solid waste, standards issued pursuant to CAA section 129 apply to that EGU, rather than this final rule.
 C. What are the pollutants regulated by this final rule?
       This final rule regulates HCl (for oil-fired EGUs and as a surrogate for acid gas HAP for coal-fired EGUs) and HF (for oil-fired EGUs), with an alternate of SO2 (as a surrogate for acid gas HAP for coal-fired EGUs with FGD systems installed and operational), filterable PM (as a surrogate for non-mercury HAP metals for coal-fired EGUs or as a surrogate for total HAP metals for oil-fired EGUs), with total non-mercury HAP metals and individual non-mercury HAP metals as alternative equivalent standards, Hg, and organic HAP, from coal- and oil-fired EGUs.
 D. What emission limits and work practice standards must I meet?
       We are finalizing the emission limitations presented in Tables 3 and 4 of this preamble. Within the two major subcategories of "coal" and "oil," emission limitations were developed for new and existing sources for six subcategories, two for coal-fired EGUs, one for coal- and solid oil-derived IGCC EGUs, and three for oil-fired EGUs, which we developed based on unit type and geographical location.
 TABLE 3. EMISSION LIMITATIONS FOR COAL-FIRED AND SOLID OIL-DERIVED FUEL-FIRED EGUS

                                  Subcategory
                         Filterable particulate matter
                               Hydrogen chloride
                                    Mercury

 Existing Unit designed for coal >8,300 Btu/lb
                        3.0E-2 lb/MMBtu (3.0E-1 lb/MWh)
                                2.0E-3 lb/MMBtu
                                (2.0E-2 lb/MWh)
                                 1.2E0 lb/TBtu
                                (2.0E-2 lb/GWh)
 Existing Unit designed low rank, virgin coal
                        3.0E-2 lb/MMBtu (3.0E-1 lb/MWh)
                                0.0020 lb/MMBtu
                                 (0.020 lb/MWh)
                                 1.1E1 lb/TBtu
                                (2.0E-1 lb/GWh)
                                 4.0E0 lb/TBtua
                               (4.0E-20 lb/GWha)
 Existing - IGCC
                         4.0E-2 lb/MMBtu (0.30 lb/MWh)
                        5.0E-4 lb/MMBtu (3.0E-3 lb/MWh)
                                 2.2E0 lb/TBtu
                                (2.0E-2 lb/GWh)
 Existing  -  Solid oil-derived
                                8.0E-3 lb/MMBtu
                                (9.0E-2 lb/MWh)
                        5.0E-3 lb/MMBtu (8.0E-2 lb/MWh)
                         2.0E-1 lb/TBtu (2.0E-4 lb/GWh)
 New unit designed for coal > 8,300 Btu/lb
                                 7.0E-3 lb/MWh
                                 4.0E-1 lb/GWh
                                 2.0E-4 lb/GWh
 New unit designed for low rank virgin coal
                                 7.0E-3 lb/MWh
                                 4.0E-1 lb/GWh
                                 4.0E-2 lb/GWh

 New  -  IGCC
                                 7.0E-2 lb/MWhb
                                 9.0E-2 lb/MWhc
                                3.0E-3 lb/MWh[d]
                                3.0E-3 lb/GWh[e]
 New  -  Solid oil-derived
                                 2.0E-2 lb/MWh
                                 3.0E-4 lb/MWh
                                  2.0E3 lb/GWh
 Note: lb/MMBtu = pounds pollutant per million British thermal units fuel input
 lb/TBtu = pounds pollutant per trillion British thermal units fuel input
 lb/MWh = pounds pollutant per megawatt-hour electric output (gross)
 lb/GWh = pounds pollutant per gigawatt-hour electric output (gross)
 [a] Beyond-the-floor limit as discussed elsewhere
 b Duct burners on syngas; based on permit levels in comments received
 [c] Duct burners on natural gas; based on permit levels in comments received
 [d] Based on best-performing similar source
 [e] Based on permit levels in comments received

 TABLE 4. EMISSION LIMITATIONS FOR LIQUID OIL-FIRED EGUS

                                  Subcategory
                                 Filterable PM
                               Hydrogen chloride
                               Hydrogen fluoride
 Existing  -  Liquid oil-continental
                                3.0E-2 lb/MMBtu
                                (2.0E-1 lb/MWh)
                                3.0E-4 lb/MMBtu
                                (4.0E-3 lb/MWh)
                                2.0E-4 lb/MMBtu
                                (2.0E-3 lb/MWh)
 Existing  -  Liquid oil-non-continental
                                3.0E-2 lb/MMBtu
                                (3.0E-1 lb/MWh)
                                2.0E-4 lb/MMBtu
                                (3.0E-3 lb/MWh)
                                6.0E-5 lb/MMBtu
                                (5.0E-4 lb/MWh)
 New  -  Liquid oil - continental
                                 7.0E-2 lb/MWh
                                 5.0E-4 lb/MWh
                                 5.0E-4 lb/MWh
 New  -  Liquid oil - non-continental
                                 2.0E-1 lb/MWh
                                 3.0E-3 lb/MWh
                                 5.0E-4 lb/MWh

      We are also finalizing alternate equivalent emission standards (for certain subcategories) to the proposed surrogate standards in three areas: SO2 (in addition to HCl), individual non-mercury metals (for PM), and total non-mercury metals (for PM). The proposed alternate emission limitations are provided in Tables 5 and 6 of this preamble.
 TABLE 5. ALTERNATE EMISSION LIMITATIONS FOR EXISTING COAL- AND OIL-FIRED EGUS

                                  Subcategory
                                Coal-fired EGUs
                                      IGCC

                            Liquid oil, continental
                          Liquid oil, non-continental
                               Solid oil-derived
 SO2
                           0.20 lb/MMBtu (1.5 lb/MWh)
                                       NA
                                       NA
                                       NA
                           0.30 lb/MMBtu (2.0 lb/MWh)
 Total non-mercury metals
                               0.000050 lb/MMBtu
                                (0.00050 lb/MWh)
                               0.000050 lb/MMBtu
                                (0.00030 lb/MWh)
                                      [a]
                                      [a]
                         0.000040 lb/MMBtu (0.6 lb/GWh)
 Antimony, Sb
                                 0.60 lb/TBtu
                                (0.0060 lb/GWh)
                                  0.40 lb/TBtu
                                (0.0040 lb/GWh)
                                  0.30 lb/TBtu
                                (0.0030 lb/GWh)
                                  2.2 lb/TBtu
                                 (0.020 lb/GWh)
                                 0.090 lb/TBtu
                                (0.00080 lb/GWh)
 Arsenic, As
                                  1.1 lb/TBtu
                                (0.020 lb/GWh)
                                  1.2 lb/TBtu
                                 (0.020 lb/GWh)
                                  0.50 lb/TBtu
                                 (0.007 lb/GWh)
                                  4.3 lb/TBtu
                                 (0.080 lb/GWh)
                                  0.30 lb/TBtu
                                (0.0050 lb/GWh)
 Beryllium, Be
                                 0.20 lb/TBtu
                                (0.0020 lb/GWh)
                                 0.030 lb/TBtu
                                (0.00030 lb/GWh)
                                 0.060 lb/TBtu
                                (0.00070 lb/GWh)
                                  0.60 lb/TBtu
                                (0.0030 lb/GWh)
                                 0.050 lb/TBtu
                                (0.00050 lb/GWh)
 Cadmium, Cd
                                 0.30 lb/TBtu
                                (0.0030 lb/GWh)
                                  0.20 lb/TBtu
                                (0.0020 lb/GWh)
                                  0.20 lb/TBtu
                                 0.0020 lb/GWh)
                                  0.30 lb/TBtu
                                (0.0030 lb/GWh)
                                  0.30 lb/TBtu
                                (0.0040 lb/GWh)
 Chromium, Cr
                                  2.8 lb/TBtu
                                 (0.030 lb/GWh)
                                  2.9 lb/TBtu
                                 (0.020 lb/GWh)
                                  1.8 lb/TBtu
                                 0.030 lb/GWh)
                                   31 lb/TBtu
                                 (0.30 lb/GWh)
                                  0.8 lb/TBtu
                                 (0.020 lb/GWh)
 Cobalt, Co
                                  0.80 lb/TBtu
                                (0.0080 lb/GWh)
                                  1.2 lb/TBtu
                                (0.0040 lb/GWh)
                                  1.0 lb/TBtu
                                 0.020 lb/GWh)
                                  113 lb/TBtu
                                 (1.40 lb/GWh)
                                  1.1 lb/TBtu
                                 (0.020 lb/GWh)
 Lead, Pb
                                  1.2 lb/TBtu
                                 (0.020 lb/GWh)
                                0.00020 lb/MMBtu
                                (0.0030 lb/MWh)
                                  2.3 lb/TBtu
                                 0.030 lb/GWh)
                                  4.9 lb/TBtu
                                 (0.080 lb/GWh)
                                  0.80 lb/TBtu
                                 (0.020 lb/GWh)
 Manganese, Mn
                                  4.0 lb/TBtu
                                 (0.050 lb/GWh
                                  2.5 lb/TBtu
                                 (0.020 lb/GWh)
                                  2.9 lb/TBtu
                                 0.040 lb/GWh)
                                   20 lb/TBtu
                                 (0.30 lb/GWh)
                                  2.3 lb/TBtu
                                 (0.040 lb/GWh)
 Mercury, Hg
                                       NA
                                       NA
                                 0.060 lb/TBtu
                                (0.00080 lb/GWh)
                         0.040 lb/TBtu (0.00040 lb/GWh)
                                       NA
 Nickel, Ni
                                  3.1 lb/TBtu
                                 (0.040 lb/GWh)
                                  4.2 lb/TBtu
                                 (0.050 lb/GWh)
                                  5.6 lb/TBtu
                                 (0.070 lb/GWh)
                                  465 lb/TBtu
                                  (4.1 lb/GWh)
                                  9.0 lb/TBtu
                                  (0.2 lb/GWh)
 Selenium, Se
                                  5.0 lb/TBtu
                                 (0.060 lb/GWh)
                                  22.0 lb/TBtu
                                 (0.20 lb/GWh)
                                  1.2 lb/TBtu
                                 (0.020 lb/GWh)
                                  9.8 lb/TBtu
                                 (0.20 lb/GWh)
                                  1.2 lb/TBtu
                                 (0.020 lb/GWh)
NA = Not applicable
[a] Includes Hg.

 TABLE 6. ALTERNATE EMISSION LIMITATIONS FOR NEW COAL- AND OIL-FIRED EGUS

                                  Subcategory
                                Coal-fired EGUs
                                    IGCC[a]
                        Liquid oil, continental, lb/GWh
                      Liquid oil, non-continental, lb/GWh
                               Solid oil-derived
 SO2
                                  0.40 lb/MWh
                                       NA
                                       NA
                                       NA
                                  0.40 lb/MWh
 Total non-mercury metals
                                0.000020 lb/MWh
                                 0.00030 lb/MWh
                                      [b]
                                      [b]
                                 0.00060 lb/MWh
 Antimony, Sb
                                 0.00020 lb/GWh
                                  0.010 lb/GWh
                                     0.0020
                                     0.0080
                                 0.00090 lb/GWh
 Arsenic, As
                                 0.00080 lb/GWh
                                 0.0080 lb/GWh
                                     0.0020
                                     0.060
                                 0.0020 lb/GWh
 Beryllium, Be
                                0.000060 lb/GWh
                                0.000090 lb/GWh
                                    0.00070
                                     0.0030
                                0.000080 lb/GWh
 Cadmium, Cd
                                 0.00040 lb/GWh
                                 0.0010 lb/GWh
                                    0.00040
                                     0.0020
                                 0.0070 lb/GWh
 Chromium, Cr
                                 0.0070 lb/GWh
                                  0.030 lb/GWh
                                     0.020
                                     0.0020
                                 0.0060 lb/GWh
 Cobalt, Co
                                 0.00080 lb/GWh
                                 0.0030 lb/GWh
                                     0.0060
                                     0.020
                                 0.0020 lb/GWh
 Lead, Pb
                                 0.0030 lb/GWh
                                 0.0060 lb/GWh
                                     0.0060
                                      0.30
                                  0.020 lb/GWh
 Mercury, Hg
                                       NA
                                       NA
                                    0.00010
                                    0.00040
                                       NA
 Manganese, Mn
                                 0.0040 lb/GWh
                                  0.020 lb/GWh
                                     0.030
                                     0.020
                                 0.0070 lb/GWh
 Nickel, Ni
                                 0.0040 lb/GWh
                                  0.020 lb/GWh
                                     0.040
                                      4.1
                                 0.0070 lb/GWh
 Selenium, Se
                                 0.00030 lb/GWh
                                  0.30 lb/GWh
                                     0.0040
                                     0.020
                                 0.00090 lb/GWh
NA = Not applicable
[a] Based on best-performing similar source
[b] Includes Hg.

       As noted elsewhere in this preamble, we are also finalizing a compliance assurance option that would allow you to develop and submit for approval a site-specific liquid oil fuel moisture limit and sampling plan for those EGUs that combust liquid oil transported in contact with seawater as an alternate to the HCl and HF emission limits for both liquid oil subcategories (i.e., continental and non-continental).
       We are finalizing that new or existing EGUs are "coal-fired" if they combust coal and meet the final definition of "fossil fuel-fired." We are finalizing that an EGU is considered to be a "coal-fired unit designed for coal greater than or equal to 8,300 Btu/lb" if the EGU: 1) combusts coal; 2) meets the final definitions of "fossil fuel-fired" and "coal-fired electric utility steam generating unit;" and 3) is not a coal-fired EGU in the "unit designed for low rank, virgin coal" subcategory. We are finalizing that the EGU is considered to be a "unit designed for low rank, virgin coal" if the EGU: 1) combusts coal; 2) meets the final definitions of "fossil fuel-fired" and "coal-fired electric utility steam generating unit;" and 3) is designed to burn and is burning nonagglomerating virgin coal having a calorific value (moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) and that is constructed and operates at or near the mine that produces such coal.
       We are finalizing that the EGU is considered to be an IGCC unit if the EGU: 1) combusts a synthetic gas derived from gasified coal or solid oil-derived fuel (e.g., petroleum coke), 2) meets the final definition of "fossil fuel-fired," and 3) is classified as an IGCC unit. We are not subcategorizing IGCC EGUs based on the source of the syngas used (e.g., coal, petroleum coke). Based on information available to the Agency, although the fuel characteristics of coal and petcoke are quite different, the syngas products from both feedstocks are very similar.
      We are finalizing that the EGU is considered to be "liquid oil - continental" if the EGU is not a coal-fired EGU and burns liquid oil, meets the final definitions of "oil-fired electric utility steam generating unit" and "fossil fuel-fired," and is located in the continental United States (U.S.). We are finalizing that the EGU is considered to be "liquid oil  -  non-continental" if the EGU is not a coal-fired EGU and burns liquid oil, meets the final definitions of "oil-fired electric utility steam generating unit" and "fossil fuel-fired," and is located outside continental North America. We are finalizing that the EGU is considered to be "solid oil-derived fuel-fired" if the EGU is not a coal-fired EGU and burns solid oil-derived fuel (e.g., petroleum coke), and meets the final definitions of "oil-fired electric utility steam generating unit" and "fossil fuel-fired."
      Pursuant to CAA section 112(h), we are finalizing a work practice standard for organic HAP, including emissions of dioxins and furans, from all subcategories of EGUs. The work practice standard being finalized requires the implementation of periodic burner tune-up procedures described elsewhere in this preamble. We are finalizing work practice standards because the significant majority of data for measured organic HAP emissions from EGUs are below the detection levels of the EPA test methods, even when long duration (around 8 hour) test runs are considered. As such, we consider it impracticable to measure emissions from these units. As discussed at proposal, we believe the inaccuracy of a majority of measurements, coupled with the extended sampling times used, allow a work practice standard under CAA section 112(h) to apply to these HAP.
      We are finalizing a beyond-the-floor standard for Hg only for all existing coal-fired units designed for low rank, virgin coal based on the use of activated carbon injection (ACI) for Hg control, as described elsewhere in this preamble. The EPA has determined that this beyond-the-floor level was achievable after considering the relevant CAA section 112(d)(2) considerations.
      As noted elsewhere in this preamble, we are finalizing a requirement to use filterable PM as a surrogate for the non-mercury metallic HAP and HCl as a surrogate for the acid gas HAP for all subcategories of coal-fired EGUs and for the solid oil derived fuel-fired EGUs. For all liquid oil-fired EGUs, we are finalizing measurement of filterable PM as a surrogate for the total metallic HAP and of HCl and HF.
      In addition, we are finalizing alternative standards for certain subcategories: 1) SO2 (as an alternative equivalent to HCl for all subcategories with add-on FGD systems); 2) individual non-mercury metallic HAP (as an alternate to filterable PM for all subcategories except liquid oil-fired); 3) total non-mercury metallic HAP (as an alternate to PM for all subcategories); 4) individual metallic HAP (as an alternate to total metal HAP) for the liquid oil-fired subcategory; and 5) fuel moisture less than 1 percent coupled with tune ups (as an alternate to HCl and HF) for the liquid oil-fired subcategory. These alternative proposed standards are discussed elsewhere in this preamble.
E. What are the requirements during periods of startup, shutdown, and malfunction?
      We proposed numerical emission standards that would apply at all times, including during periods of startup, shutdown, and malfunction. Although at proposal we stated that we were not setting a different standard for startup and shutdown, we, in fact, did propose different standards for startup and shutdown by our inclusion of the default values described below, which applied only during startup and shutdown. Specifically, we stated:
      To appropriately determine emissions during startup and shutdown and account for those emissions in assessing compliance with the proposed emission standards, we propose use of a default diluent value of 10.0 percent O2 or the corresponding fuel specific CO2 concentration for calculating emissions in units of lb/MMBtu or lb/TBtu during startup or shutdown periods. For calculating emissions in units of lb/ MWh or lb/GWh, we propose source owners use an electrical production rate of 5 percent of rated capacity during periods of startup or shutdown. We recognize that there are other approaches for determining emissions during periods of startup and shutdown, and we request comment on those approaches. We further solicit comment on the proposed approach described above and whether the values we are proposing are appropriate.
      Thus, we proposed application of the respective emission limits during periods of startup and shutdown and use of default values to calculate the emission limits. The standards that apply at all times other than startup and shutdown are production-based limits, which is why we proposed the default values. Specifically, the default values account for the fact that during startup and shutdown events production (in this case the generation of electricity) is by definition nonexistent. Thus, in effect, we proposed a separate standard to apply during startup and shutdown.
      We received a variety of comments on the proposed standards that would apply during startup and shutdown. Many commenters pointed to the lack of data in the record concerning emissions that occur during periods of startup and shutdown. They further asserted that emissions during these periods can be highly variable in light of the sequence of events that occurs during the startup and shutdown of an EGU. Although a number of commenters supported the use of the diluent factor approach, including the default 5 percent of rated capacity, during startup/shutdown periods, other commenters questioned the feasibility of collecting additional data during such periods and had concerns regarding the reliability of measurements obtained from EGUs during such periods.
      In response to the Agency's ICR to the utility industry, we received CEMS data from seven EGUs that represent measurements made during startup and shutdown operations. These data were submitted in response to the requirement in the ICR to provide all available data from the five years prior to the date the ICR was issued. None of the data for startup and shutdown submitted by these seven EGUs meet our data quality requirements. Thus, we have no data on emissions that occur during startup and shutdown on which to set emission standards. We are therefore establishing work practices for periods of startup and shutdown in the final rule. Before we describe those work practices, we first address what constitutes startup and shutdown.
      Several commenters had an expansive view of what constitutes startup and shutdown. We disagree with these commenters that asserted that periods of "load swings" should be considered "startup" or "shutdown," as they are routine, normal operations. We maintain that the standards as promulgated account for any variability in emissions that may occur during these periods, particularly over a 30 day averaging period, and commenters have provided no data that causes us to doubt that determination. For these reasons, we have included definitions of startup and shutdown in the final rule that are consistent with the definitions in the proposed rule. At proposal, we included the following definitions of startup and shutdown:
      Startup means the setting in operation of an affected source or portion of an affected source for any purpose.
      Shutdown means the cessation of operation of an affected source or portion of an affected source for any purpose.
      Commenters sought more clarity regarding the meaning of these terms as applied to EGUs, so we provide the following clarification. For purposes of this rule, "startup" refers only to a cold startup (i.e., starting from the point of no fuel being fired in the boiler and the boiler at ambient temperature). "Shutdown" refers only to an event that ends at the point of no fuel being fired in the boiler. These interpretations are wholly consistent with the definitions of "startup" and "shutdown" contained in the part 63 General Provisions. In addition, the definition in the final rule states that startup ends when the turbine-generator is synchronized to the grid, and shutdown begins when the turbine-generator is disconnected from the grid. We believe these additional interpretations address the comments and are rational based on the fact that EGUs function to provide electricity to the grid and, for that reason, they should be considered to be operating normally at all times electricity is flowing to the grid.
      As for the work practices, in this final rule, the EPA is requiring sources to operate using either natural gas or distillate oil for ignition during startup. The EPA also is requiring sources to operate all control devices necessary to meet the normal operating standards under this final rule (with the exception of SCRs) when coal or residual oil is fired in the boiler during startup or shutdown. It is the responsibility of the operators of EGUs to start their SCR systems appropriately to comply with relevant standards applicable during normal operation.
      This final rule requires work practice standards for emissions during startup and shutdown, and the rule requires sources to measure and report their emissions at all times, including periods of startup and shutdown. Data collected under this final rule will provide the EPA with information to more fully analyze this issue and address it during the 8-year review established under CAA section 112.
      As mentioned earlier, periods of startup, normal operations, and shutdown are all predictable and routine aspects of a source's operations. However, by contrast, malfunction is defined as a "sudden, infrequent, and not reasonably preventable failure of air pollution control and monitoring equipment, process equipment or a process to operate in a normal or usual manner * * *"(40 CFR 63.2). The EPA has determined that CAA section 112 does not require that emissions that occur during periods of malfunction be factored into development of CAA section 112 standards. Under CAA section 112, emissions standards for new sources must be no less stringent than the level "achieved" by the best controlled similar source and for existing sources generally must be no less stringent than the average emission limitation "achieved" by the best performing 12 percent of sources in the category. There is nothing in CAA section 112 that directs the Agency to consider malfunctions in determining the level "achieved" by the best performing or best controlled sources when setting emission standards. Moreover, while the EPA accounts for variability in setting emissions standards consistent with the CAA section 112 case law, nothing in that case law requires the Agency to consider malfunctions as part of that analysis. Clean Air Act section 112 uses the concept of "best controlled" and "best performing" unit in defining the level of stringency that CAA section 112 performance standards must meet. Applying the concept of "best controlled" or "best performing" to a unit that is malfunctioning presents significant difficulties, as malfunctions are sudden and unexpected events.
      Further, accounting for malfunctions would be difficult, if not impossible, given the myriad different types of malfunctions that can occur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. As such, the performance of units that are malfunctioning is not "reasonably" foreseeable. See, e.g., Sierra Club v EPA, 167 F. 3d 658, 662 (D.C. Cir. 1999) (The EPA typically has wide latitude in determining the extent of data-gathering necessary to solve a problem. We generally defer to an agency's decision to proceed on the basis of imperfect scientific information, rather than to "invest the resources to conduct the perfect study."). See also,  Weyerhaeuser v Costle, 590 F.2d 1011, 1058 (D.C. Cir. 1978) ("In the nature of things, no general limit, individual permit, or even any upset provision can anticipate all upset situations. After a certain point, the transgression of regulatory limits caused by `uncontrollable acts of third parties,' such as strikes, sabotage, operator intoxication or insanity, and a variety of other eventualities, must be a matter for the administrative exercise of case-by-case enforcement discretion, not for specification in advance by regulation."). In addition, the goal of a best controlled or best performing source is to operate in such a way as to avoid malfunctions of the source and accounting for malfunctions could lead to standards that are significantly less stringent than levels that are achieved by a well-performing non-malfunctioning source. The EPA's approach to malfunctions is consistent with CAA section 112 and is a reasonable interpretation of the statute.
      In the event that a source fails to comply with the applicable CAA section 112(d) standards as a result of a malfunction event, the EPA would determine an appropriate response based on, among other things, the good faith efforts of the source to minimize emissions during malfunction periods, including preventative and corrective actions, as well as root cause analyses to ascertain and rectify excess emissions. The EPA would also consider whether the source's failure to comply with the CAA section 112(d) standard was, in fact, "sudden, infrequent, not reasonably preventable" and was not instead "caused in part by poor maintenance or careless operation." 40 CFR section 63.2 (definition of malfunction).
      Finally, the EPA recognizes that even equipment that is properly designed and maintained can sometimes fail and that such failure can sometimes cause an exceedance of the relevant emission standard. (See, e.g., State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and Shutdown (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and Malfunctions (Feb. 15, 1983)). The EPA is therefore adding to the final rule an affirmative defense to civil penalties for exceedances of emission limits that are caused by malfunctions. See 40 CFR 63.10042 (defining "affirmative defense" to  mean, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding). We also have added other regulatory provisions to specify the elements that are necessary to establish this affirmative defense; the source must prove by a preponderance of the evidence that it has met all of the elements set forth in 63.10001. (See 40 C.F.R. 22.24). The criteria ensure that the affirmative defense is available only where the event that causes an exceedance of the emission limit meets the narrow definition of malfunction in 40 C.F.R. 63.2 (sudden, infrequent, not reasonable preventable and not caused by poor maintenance and or careless operation). For example, to successfully assert the affirmative defense, the source must prove by a preponderance of the evidence that excess emissions "[w]ere caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner..." The criteria also are designed to ensure that steps are taken to correct the malfunction, to minimize emissions in accordance with section 63.10001 and to prevent future malfunctions. For example, the source must prove by a preponderance of the evidence that "[r]epairs were made as expeditiously as possible when the applicable emission limitations were being exceeded..." and that "[a]ll possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment and human health..." In any judicial or administrative proceeding, the Administrator may challenge the assertion of the affirmative defense and, if the respondent has not met its burden of proving all of the requirements in the affirmative defense, appropriate penalties may be assessed in accordance with CAA section 113 (see also 40 CFR Part 22.27).
      The EPA included an affirmative defense in the final rule in an attempt to balance a tension, inherent in many types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission limits may be exceeded under circumstances beyond the control of the source. The EPA must establish emission standards that "limit the quantity, rate, or concentration of emissions of air pollutants on a continuous basis." 42 U.S.C. §7602(k)(defining "emission limitation and emission standard"). See generally Sierra Club v. EPA, 551 F.3d 1019, 1021 (D.C. Cir. 2008) Thus, the EPA is required to ensure that section 112 emissions limitations are continuous. The affirmative defense for malfunction events meets this requirement by ensuring that even where there is a malfunction, the emission limitation is still enforceable through injunctive relief. While "continuous" limitations, on the one hand, are required, there is also case law indicating that in many situations it is appropriate for the EPA to account for the practical realities of technology. For example, in Essex Chemical v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit acknowledged that in setting standards under CAA section 111 "variant provisions" such as provisions allowing for upsets during startup, shutdown and equipment malfunction "appear necessary to preserve the reasonableness of the standards as a whole and that the record does not support the `never to be exceeded' standard currently in force." See also, Portland Cement Association v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973). Though intervening case law such as Sierra Club v. EPA and the CAA 1977 amendments undermine the relevance of these cases today, they support the EPA's view that a system that incorporates some level of flexibility is reasonable. The affirmative defense simply provides for a defense to civil penalties for excess emissions that are proven to be beyond the control of the source. By incorporating an affirmative defense, the EPA has formalized its approach to upset events. In a Clean Water Act setting, the Ninth Circuit required this type of formalized approach when regulating "upsets beyond the control of the permit holder." Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73 (9[th] Cir. 1977). But see, Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an informal approach is adequate). The affirmative defense provisions give the EPA the flexibility to both ensure that its emission limitations are "continuous" as required by 42 U.S.C. §7602(k), and account for unplanned upsets and thus support the reasonableness of the standard as a whole.
 F. What are the testing and initial compliance requirements?
      We are requiring that you, as an owner or operator of a new or existing coal- or oil-fired EGU must conduct performance tests to demonstrate compliance with all applicable emission limits. For units using certified continuous emissions monitoring systems (CEMS) that directly measure the concentration of a regulated pollutant under final 40 CFR Part 63, subpart UUUUU (e.g., Hg CEMS (for simplicity of reference, in other places this preamble often refers to both an Hg CEMS and a sorbent trap monitoring system as an Hg CEMS)), HCl CEMS, HF CEMS, SO2 CEMS (where an SO2 limit applies as the alternative equivalent surrogate for the acid-gas HAP, including HCl), or sorbent trap monitoring systems, the initial performance test consists of all valid data recorded with the certified monitoring system in the first 30 boiler operating days after the compliance date. For other units, the owner or operator of an affected unit must perform the initial performance testing in accordance with established EPA reference test methods or the Ontario Hydro method for Hg (ASTM D6784-02). You, as the owner or operator of an affected unit, must conduct the following compliance tests where applicable:
      (1) For coal-fired units, IGCC units, and solid oil-derived fuel-fired units, if you elect to comply with the filterable PM emission limit, you must conduct Method 5 PM emissions testing to determine initial compliance. If you elect to comply with the total non-mercury HAP metals emission limit or the individual non-mercury HAP metals emissions limits, you must conduct HAP metals testing using EPA Method 29. Note for this rule that the filter temperature for each Method 29 or 5 emissions test must be maintained at 160º +- 14ºC (320º +- 25ºF), and the material in Method 29 impingers must be analyzed for metals content. Whenever metals testing is performed with Method 29, you must report the front half and back half analytical fractions separately.
      (2) For coal-fired, IGCC, and solid oil-derived fuel-fired units, you must use a Hg CEMS or sorbent trap monitoring system for both initial compliance and continuous compliance using the continuous Hg monitoring provisions of Appendix A to 40 CFR Part 63, subpart UUUUU, except where the low emitting EGU (LEE) requirements apply (see below). The initial performance test consists of all valid data recorded with the certified Hg monitoring system in the first 30 boiler operating days after the compliance date.
      (3) For coal-fired and solid oil-derived fuel-fired units and new or reconstructed IGCC units that employ FGD technology and elect to meet the alternative SO2 limit in place of the HCl limit, you need not conduct an initial stack test for HCl or SO2. Instead, the first 30 boiler operating days of certified SO2 CEMS data after the compliance date are used to determine initial compliance, and the SO2 CEMS is used thereafter to demonstrate continuous compliance. If you instead opt to meet the HCl limit and use an HCl CEMS for compliance, you need not conduct an initial stack test for HCl. Instead, the first 30 boiler operating days of certified HCl CEMS data are used to determine initial compliance. For units not using the SO2 or HCl CEMS options, you must conduct an initial stack test using Method 26, 26A, or 320 testing for hydrochloric acid. You may use EPA Method 26 or 320 if no entrained water droplets exist in the exhaust gas but you must use Method 26A if entrained water droplets exist in the exhaust gas.
      (4) For liquid oil-fired units, you must conduct initial performance testing as follows. For non-mercury HAP metals, use EPA Method 29. If you elect to meet the filterable PM limit instead of the non-mercury metals limit (total or individual), then use Method 5 maintained at 160º +- 14ºC (320º +- 25ºF). For Hg, conduct emissions testing using EPA Method 29 or 30B or ASTM Method D6784-02. For acid gases, conduct HCl and HF testing using EPA Method 26A, 320, or 26; or you may elect to use an HCl CEMS and/or an HF CEMS; or you may choose to measure fuel moisture daily if fuel is delivered continuously or per shipment if fuel is delivered on a batch basis or via fuel supplier certification. If you use a CEMS, then use the first 30 boiler operating days of certified CEMS data to determine initial compliance.
      (5) For all required performance stack tests, you must conduct concurrent oxygen (O2) or carbon dioxide (CO2) emission testing using EPA Method 3A and then use an appropriate equation, selected from among Equations 19 - 1 through 19 - 9 in EPA Method 19, to convert measured pollutant concentrations to lb/MMBtu values. Multiply the lb/MMBtu value by one million to get the lb/TBtu value (where applicable). If you are required or choose to meet an electrical output-based emissions limit, you must also collect concurrent stack gas flow rate and electrical production data.
      (6) For an existing unit that you believe will qualify as LEE, you must conduct an initial Method 30B test over 30 days and follow the calculation procedures in the final rule to document a potential to emit less than 10 percent of the Hg emissions limit or less than 22 pounds of Hg per year. If your unit qualifies as an LEE, you must conduct subsequent performance tests on an annual basis to demonstrate that the unit continues to qualify.
      (7) You may use results from tests conducted no earlier than 12 months before the compliance date of this rule as the initial performance test for an applicable pollutant, provided that:
      a. You certify no significant changes have occurred,
      b. Tests were conducted using methods allowed in this rule,
      c. Test sample volume or duration was consistent with that required in this rule, and
      d. You have and maintain a complete set of documentation needed to electronically file results.
      Under the final rule, you may elect to comply with an optional operating limit for PM that will be established during the initial compliance performance test. You may elect to use a PM continuous parameter monitoring system (PM CPMS) to demonstrate compliance with an operating limit. The PM CPMS operating principle must be based on in-stack or extractive light scatter, light scintillation, beta attenuation, or mass accumulation detection of the exhaust gas or representative exhaust gas sample. The reportable measurement output from the PM CPMS may be expressed as milliamps, stack concentration, or other raw data signal. Meeting the operating limit is required as part of demonstrating continuous compliance with a filterable PM, total non-mercury HAP metals, or individual non-mercury HAP metals limit. If you use this method to demonstrate continuous compliance, you must install a PM CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-mercury HAP metals, or individual non-mercury HAP metals. As noted below, when you use this operating limit, you can reduce stack testing frequency to demonstrate ongoing compliance.
      For dioxins and furans and non-dioxin/furan organic HAP, you must submit documentation that you have conducted a combustion process tune-up, a thorough equipment inspection, and an optimization service, all meeting the requirements of this final rule. The work practice involves maintaining and inspecting the burners and associated combustion controls, tuning the specific burner type to optimize combustion, obtaining and recording CO and NOX values before and after burner adjustments, keeping records of activity and measurements, and submitting a report for each tune-up conducted. You may collect CO and NOX data and use handheld portable analyzers or similar devices to monitor and verify the results. 40 CFR section 63.10021 of the final rule addresses specific details.
      For Hg, non-mercury metals HAP, acid gas HAP, dioxins and furans, and non-dioxin/furan organic HAP from a liquid oil-fired EGU that has an annual capacity factor on oil of less than 5 percent of its maximum or nameplate heat input, whichever is greater, you must demonstrate initial compliance by conducting at least every 36 months (48 months if a neural net is employed) a combustion process tune-up, a thorough equipment inspection, and an optimization service, all meeting the requirements of this final rule. You must maintain and inspect the burners and associated combustion controls, tuning the specific burner type to optimize combustion, obtaining and recording CO and NOX values before and after burner adjustments, keeping records of activity and measurements, and submitting a report for each tune-up conducted. You may collect CO and NOX data and use handheld portable analyzers or similar devices to monitor and verify the results.
 G. What are the continuous compliance requirements?
       To demonstrate continuous compliance with the emission limitations, the final rule includes the following requirements:
       (1) Where a CEMS (including a sorbent trap monitoring system) is used for demonstrating initial compliance, you also must use the CEMS on a continuous basis to demonstrate ongoing compliance. You must calculate a rolling average for each successive 30 boiler operating day period. All valid data collected during each successive period will be used to demonstrate compliance. There is no numerical minimum data availability required to constitute a valid 30-day rolling average. You must operate, maintain, and quality assure the CEMS in accordance with the provisions in 40 CFR section 63.10010 and Appendix A and B of the final rule or in accordance with 40 CFR Part 75, as applicable.
       For each unit using HCl, HF, SO2, or Hg CEMS for continuous compliance, you must install, certify, maintain, operate and quality-assure the additional CEMS (e.g., CEMS that measure oxygen or CO2 concentration, stack gas flow rate, and, if default moisture values are not used, moisture content) needed to convert pollutant concentrations to units of the emission standards or operating limits. Where appropriate, you must certify and quality-assure these additional CEMS according to 40 CFR Part 75, because almost all coal-fired utility units already have the necessary monitors in place under the ARP.
       For HCl and HF CEMS, this rule requires use of performance specification (PS) 15 and Procedure 1 for certification and ongoing compliance. In addition, we expect to promulgate a PS specific to HCl CEMS prior to the compliance date of this rule. In the meantime, you may petition the Administrator under the procedure given in 40 CFR section 63.7(f) for an alternative approach to compliance monitoring for HCl or any other regulated pollutant.
       When using a sorbent trap monitoring system, you may use each pair of sorbent traps to collect Hg samples for no more than 15 operating days, and you must replace traps in a timely manner to ensure that Hg emissions are sampled continuously.
       For Hg monitoring, the EPA is adding Hg monitoring provisions as Appendix A to 40 CFR Part 63, subpart UUUUU, and requiring use of these provisions to document continuous compliance with the rule for coal-fired, IGCC, and solid oil derived-fired units that cannot qualify as LEEs. Appendix A consolidates all Hg monitoring provisions. Today's rule provides two basic Hg continuous monitoring options: Hg CEMS and sorbent trap monitoring systems. Appendix A requires initial certification and periodic quality assurance (QA) testing of the Hg CEMS and sorbent trap monitoring systems. The certification tests required for the Hg CEMS are a 7-day calibration error test; a linearity check, using NIST-traceable elemental Hg standards; a 3-level system integrity check (similar to a linearity check), using NIST-traceable oxidized Hg standards; a cycle time test; and a relative accuracy test audit (RATA). Table A - 1 of Appendix A summarizes the performance specifications for the required certification tests. For ongoing QA of the Hg CEMS, Appendix A requires daily calibrations, weekly single-point system integrity checks, quarterly linearity checks (or 3-level system integrity checks), and annual RATAs. Table A-2 in Appendix A summarizes these QA test requirements and the applicable performance criteria, which are consistent with those published in support of CAMR. For sorbent trap monitoring systems, a RATA is required for initial certification, and annual RATAs are required for ongoing QA. The performance specification for these RATAs is the same as for the RATAs of the Hg CEMS. Bias adjustment of the measured Hg concentration data is not required. For day-to-day operation of the sorbent trap system, Appendix A requires you to follow the procedures and QA/QC criteria in PS 12B in Appendix B to 40 CFR Part 60. PS 12B is nearly identical to the vacated Appendix K to Part 75. The Part 75 concepts of:
       a. determining the due dates for certain QA tests on the basis of "QA operating quarters" and
       b. grace periods for certain QA tests
 apply to both Hg CEMS and sorbent trap monitoring systems. Mercury concentrations measured by Hg CEMS or sorbent trap systems are used together with hourly flow rate, diluent gas, moisture, and electrical load data, to express the Hg emissions in units of the rule, on an hourly basis (i.e., lb/TBtu or lb/GWh). Section 6 of Appendix A provides the necessary equations for these unit conversions.
       (2) If you demonstrate initial compliance on the basis of a stack test (e.g., as oil-fired units are required to do for Hg), you must demonstrate continuous compliance by conducting periodic stack tests on a monthly basis for PM, non-mercury HAP metals, and HAP metals from coal-fired and liquid oil-fired EGUs or on a quarterly basis for HCl and HF from liquid oil-fired EGUs with the following certain exceptions:
       a. If you use a PM CPMS and associated operating limit, you must conduct the applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. The final rule includes basic quality checks that the PM CPMS must meet and requirements for you to develop and follow a site-specific monitoring plan to be approved by the delegated authority. You must demonstrate compliance with the operating limit by using all valid hourly data collected during each successive 30 operating day period. The 30-day average is calculated by all of the valid hourly average PM CPMS output values collected for the 30 boiler operating days.
       b. If you combust liquid fuels and if your fuel moisture content is no greater than 1.0 percent, you may demonstrate ongoing compliance with HCl and HF emissions limits by
       i. Measuring fuel moisture content of each shipment of fuel if your fuel arrives on a batch basis;
       ii. Measuring fuel moisture content daily if your fuel arrives on a continuous basis; or
       iii. Obtaining and maintaining a fuel moisture certification from your fuel supplier.
       Should the moisture in your liquid fuel be more than 1.0 percent, you must
       i. conduct HCl and HF emissions testing quarterly and monitor acid gas control device parameters continuously or
       ii. use an HCl CEMS and/or HF CEMS.
       c. If your existing unit qualifies as an LEE for Hg, you must conduct a performance test on your unit once per year to reestablish that the unit continues to qualify as a LEE for Hg. If the results of the LEE test show that the unit exceeds 10 percent of the emissions limit or exceeds the potential to emit 22 pounds of Hg per year, you will lose LEE status for the unit. You can regain LEE status for that unit if every required performance test for a 3-year period shows that emissions from the unit did not exceed the LEE limit. If LEE status is lost for a solid fuel unit, you must commence quarterly testing until you install, certify, and operate a Hg CEMS or sorbent trap monitor, and you must complete the installation and certification within 6 months of losing LEE status; for a liquid fuel unit, you must commence quarterly testing.
       d. If a liquid oil-fired EGU has an annual capacity factor on oil of less than 5 percent of its maximum or nameplate heat input, whichever is greater, you must demonstrate continuous compliance with the applicable limits (e.g., Hg, non-mercury HAP metals, acid gas HAP, dioxin and furan, and non-dioxin/furan organic HAP limits) by conducting at least every 36 months (48 months if a neural net is employed) a combustion process tune-up, a thorough equipment inspection, and an optimization service, all meeting the requirements of this final rule. You must maintain and inspect the burners and associated combustion controls, tuning the specific burner type to optimize combustion, obtaining and recording CO and NOX values before and after burner adjustments, keeping records of activity and measurements, and submitting a report for each tune-up conducted. You may collect CO and NOX data and use handheld portable analyzers or similar devices to monitor and verify the results. 40 CFR section 63.10021 of the final rule addresses specific details. In addition, you must record boiler operating hours, by fuel type, in each calendar quarter.
       e. The rule allows a grant of LEE status to existing units with test results that show a history of low, non-mercury emissions. As mentioned earlier, LEE status reduces testing frequency for units. After a 3-year period during which every emissions test for a specific pollutant shows emissions no greater than 50 percent of the emissions limit, you may reduce the emissions testing frequency for that specific pollutant to once every 36 months. If any subsequent emissions test for that pollutant exhibits emissions greater than 50 percent of the emissions limit, you must revert to the original emissions testing frequency until you re-establish a 3-year period of very low emissions no greater than 50 percent of the standard.
       3. For the performance tune-up work practice requirement for organic HAP control, you must demonstrate continuous compliance by conducting the work practice at least every 36 months (48 months if a neural net is employed). The work practice involves maintaining and inspecting the burners and associated combustion controls, tuning the specific burner type, as applicable, to optimize combustion, obtaining and recording CO and NOX values before and after burner adjustments, keeping records of activity and measurements, and submitting a report for each tune-up conducted. A combustion tune-up will involve optimizing combustion of the unit consistent with manufacturer's instruction as applicable, or in accordance with best combustion engineering practice for that burner type.
 H. What are the notification, recordkeeping and reporting requirements?
       All new and existing sources must comply with certain requirements of the General Provisions (40 CFR Part 63, subpart A), which are identified in Table 9 of this final rule. The General Provisions include specific requirements for notifications, recordkeeping, and reporting. You must submit a notification of compliance status report for each unit, as required by 40 CFR section 63.9(h) of the General Provisions, including a certification of compliance.
       Except for units that use CEMS for continuous compliance, under this rule you must provide semiannual compliance reports, as required by 40 CFR section 63.10(e)(3) of subpart A, for semiannual reporting periods, that indicate whether a deviation from any of the requirements in the rule occurred and whether or not any process changes occurred and compliance certifications were reevaluated. As discussed below, we are finalizing a requirement to use the Part 75-based Emissions Collection and Monitoring Plan System (ECMPS) reporting emissions and related data for units using CEMS. Also as discussed below, for the PM CPMS and performance test results, we will require you to use EPA's WebFIRE database for reporting.
       This rule will require records to demonstrate compliance with each emission limit and work practice standard. The General Provisions to 40 CFR Part 63 specify these recordkeeping requirements, and Table 8 of this final rule identifies them. You must keep the following records:
       (1) All reports and notifications submitted to comply with this rule.
       (2) Continuous monitoring data as required in this rule.
       (3) Each instance in which you did not meet an emission limit, work practice requirement, operating limit, or other compliance obligation (i.e., deviations from this rule).
       (4) Daily hours of operation by each unit.
       (5) Fuel moisture content of liquid fuel, if you elect to demonstrate compliance using that information.
       (6) A copy of the results of all performance tests, monitor certifications, performance evaluations, or other compliance demonstrations conducted to demonstrate initial or continuous compliance with this rule.
       (7) A copy of your site-specific monitoring plans developed for this rule as specified in 40 CFR 63.8(e), if applicable.
       You also must submit the following additional notifications:
       (1) Notifications required by the General Provisions.
       (2) Initial Notification no later than 120 calendar days after you become subject to this subpart.
       (3) Notification of Intent to conduct performance tests and/or compliance demonstration at least 60 calendar days before the performance test and/or compliance demonstration is scheduled.
       (4) Notification of Compliance Status 60 calendar days following completion of the performance test and/or compliance demonstration.
       Electronic reporting is becoming a common element of modern life (as evidenced by electronic banking and income tax filing), and the EPA is beginning to require electronic submittal of environmental data. Electronic reporting is already common in environmental data collection and many media offices at EPA are reducing reporting burden for the regulated community by embracing electronic reporting systems as an alternative to paper-based reporting.
       One of the major benefits of reporting electronically is standardization, to the extent possible, of the data reporting formats that provides more certainty to users of what data are required in specific reports. For example, electronic reporting software allows for more efficient data transmittal and the software's validation mechanism helps industry users submit fewer incomplete reports. This alone saves industry report processing resources and reduces transaction times. Standardization also allows for development of efficient methods to compile and store much of the documentation required to be reported this rule.
       We are requiring that certain reports required to be submitted in this rule would be submitted electronically. These reports would include all performance test reports, notification of compliance status reports, compliance, and continuous monitoring data summaries specified in 40 CFR part 63, "§63.10031 What reports must I submit and when?" Performance tests are required to be conducted as described in §63.7 of the general provisions. The information and data that must be submitted as the performance test report is also described in §63.7. This information and data must be transmitted (except in limited cases) to EPA's WebFIRE database by using the electronic reporting tool (ERT) and the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX) as described below. The data and information requirements for the notification of compliance status and compliance reports are described in detail in the regulatory text (§63.10031) of this rule, but they essentially mirror the requirements in §63.6 of the general provisions. These reports will also be transmitted to WebFIRE using an electronic form found in CEDRI and through the CDX as described below. The continuous monitoring summaries are required to be transmitted quarterly in §63.10031(f)(2). The quarterly reports must include all of the calculated 30 day rolling average values derived from the PM CPMS. These reports will also be transmitted to WebFIRE using an electronic form found in CEDRI and through the CDX as described below.
       The availability of electronic reporting for sources subject to the Subpart UUUUU will provide efficiency, improved services, better accessibility of information, and more transparency and accountability. Additionally, submittal of these required reports electronically provides significant benefits for regulatory agencies, industry, and the public. The compliance data electronic reporting system (CEDRI and CDX) is being developed such that once a facility's initial data entry into the system is established and a report is generated, subsequent data submittal would only consist of electronic updates to existing information in the system. Such a system would effectively reduce the burden associated with submittal of data and reports by reducing the time, costs, and effort required to submit and update hard copies of documentation. State, local, and tribal air pollution control agencies could also benefit from more streamlined and accurate electronic data submitted to them. Electronic reporting would allow for an electronic review process rather than a manual data assessment, making review and evaluation of the source provided data and calculations easier and more efficient. Electronic reporting would also benefit the public by generating a more transparent review process and increasing the ease and efficiency of data accessibility. Furthermore, electronic reporting would reduce the burden on the regulated community by reducing the effort involved in data collection and reporting activities. In the future, we anticipate there will be fewer and less substantial data collection requests in conjunction with prospective required residual risk assessments or technology reviews. Electronic reporting would substantially reduce this burden, because EPA would already have this data available and consolidated in an electronic database named WebFIRE. We anticipate that using electronic reporting for the required reports will result in an overall reduction in reporting costs; for a discussion of the economic and cost impacts of electronic reporting, see Section XII.D. of this preamble.
       Another benefit of electronic data submittal is that these data will greatly improve the overall quality of existing and new emissions factors by supplementing the pool of emissions test data for establishing emissions factors and by ensuring that the factors are more representative of current industry operational procedures. A common complaint heard from industry and regulators is that emission factors are outdated or not representative of a particular source category. With timely receipt and incorporation of data from most performance tests, EPA would be able to ensure that emission factors, when updated, represent the most current range of operational practices.
       Data entry of these electronic reports would be through the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). Data transmitted electronically through CEDRI will be stored in CDX as an official copy of record.
       Once you have accessed CEDRI, you will select the applicable subpart for the report that you are submitting. You will then select the icon that corresponds to the report being transmitted, enter the data into the form, and click on the submit button. In some cases, such as with submittal of a notification of compliance status report, you will select the report icon, enter basic facility information, and then upload the report in a specified file format.
       In addition, we believe that there will be utility in allowing other reporting forms to be developed and used in cases where the other reporting forms can provide an alternate electronic file consistent with EPA's form output format. This approach has been used successfully to provide alternatives for other electronic forms, e.g., income tax transmittal.
       In cases where performance test data are to be transmitted to EPA, you must enter the performance test data and information into the electronic reporting tool (ERT) which can be accessed at http://www.epa.gov/ttn/chief/ert/index.html. In CEDRI, the user must then upload the ERT file. CEDRI transmits a copy of the ERT project data file directly to WebFIRE where the data are made available. Where performance test reports are transmitted, WebFIRE notifies the appropriate state, local, or tribal agency contact that an ERT project data file was received from the source.
       Transmitting performance test data electronically to the EPA would apply only to those performance tests conducted using test methods that will be supported by the ERT. The ERT contains a specific electronic data entry form for most of the commonly used EPA reference methods. A listing of the pollutants and test methods supported by the ERT is available at the ERT website listed above.
       In summary, in addition to supporting regulation development, control strategy development, and other air pollution control activities, having an electronic database populated with these reports would save industry, state, local, tribal agencies, and EPA significant time, money, and effort while also improving the quality of emission inventories and, as a result, air quality regulations.
I. Submission of Emissions Test Results to EPA
      The EPA has determined that harmonization of the monitoring and reporting requirements of this final rule with 40 CFR Part 75 is appropriate, where the affected industry already has a well-defined system for continuous monitoring and reporting of emissions under that part. Therefore, the Agency is finalizing monitoring and reporting requirements for CEMS that are consistent with Part 75 and similar to those that had been promulgated for the vacated CAMR regulation. You must report CEMS data to the EPA electronically, on a quarterly basis, using the ECMPS.
      The ECMPS process divides electronic data into three categories, the first of which is monitoring plan data. You must maintain the electronic monitoring plan separately and can update it at any time if necessary. The monitoring plan documents the characteristics of the affected units (e.g., unit type, rated heat input capacity, etc.) and the monitoring methodology used for each parameter (e.g., CEMS). The monitoring plan also describes the type of monitoring equipment used (hardware and software components), includes analyzer span and range settings, and provides other useful information. Nearly all coal-fired EGUs are subject to the ARP and thus have established electronic monitoring plans that describe their required SO2, flow rate, CO2 or O2, and, in some cases, moisture monitoring systems. The EPA will adjust the ECMPS monitoring plan format to accommodate this same type of information for Hg, HCl, and HF CEMS, with the addition of a few codes for the new parameters.
      The second type of data collected through ECMPS is certification and QA test data. This includes data from linearity checks, RATAs, cycle time tests, 7-day calibration error tests, and a number of other QA tests that are required to validate the emissions data. You may submit the results of these tests to the EPA as soon as you receive the results, with one notable exception. Daily calibration error tests are not treated as individual QA tests, due to the large number of records generated each quarter. Rather, these tests must be included in the quarterly electronic reports, along with the hourly emissions data. The ECMPS system is set up to receive and process certification and QA data from SO2, CO2, O2, flow rate, and moisture monitoring systems that are installed, certified, maintained, operated, and quality-assured according to Part 75. EGUs routinely submit these data to the EPA under the ARP and other emissions trading programs.
      To accommodate the certification and QA tests for Hg CEMS, other CEMS, and sorbent trap monitoring systems, the structure and functionality of ECMPS needs relatively few changes, because most of the tests are the same as those required for other gas monitors. For reporting Hg, HCl, SO2, and HF CEMS data under this rule, we are disabling ECMPS' Part 75 bias test (which is required for certain types of monitors under the EPA's emissions trading programs). The bias adjustment of the data from these monitors is unnecessary for compliance with the rule.
      The third type of data collected through ECMPS is the emissions data, which, as previously noted, is reported on a quarterly schedule. You must submit reports within 30 days after the end of each calendar quarter. The emissions data format requires hourly reporting of all measured and calculated emissions values, in a standardized electronic format. You must report direct measurements made with CEMS, such as gas concentrations, in a Monitor Hourly Value (MHV) record. A typical MHV record for gas concentration includes data fields for:
      (1) The parameter monitored (e.g., SO2);
      (2) The unadjusted and bias-adjusted hourly concentration values (note that if bias adjustment is not required, only the unadjusted hourly value is reported);
      (3) The source of the data, i.e., a code indicating either that each reported hourly concentration is a quality assured value from a primary or backup monitor, or that quality-assured data were not obtained for the hour; and
      (4) The percent monitor availability (PMA), which is updated hour-by-hour. This generic record structure could easily accommodate hourly average measurements from CEMS used under this rule.
      The ECMPS reporting structure is quite flexible, which makes it useful for assessing compliance with various emission limits. The Derived Hourly Value (DHV) record allows calculations of a wide variety of quantities from the reported hourly emissions data. For instance, if an emission limit is expressed in units of lb/MMBtu, the DHV record can be used to report hourly pollutant concentration values in these units of measure, since the lb/MMBtu values can be derived from the hourly pollutant and diluent gas (CO2 or O2) concentrations reported in the MHV records. ECMPS can also accommodate multiple DHV records for a given hour in which more than one derived value is required to be reported. The system will support reporting hourly data in the units of the emission standards (e.g., lb/MMBtu, lb/TBtu, lb/GWh, etc.) when hourly Hg concentration data are reported through ECMPS using the DHV record, in conjunction with the appropriate equations and auxiliary information such as heat input and electrical load (all of which are reported hourly in the emissions reports).
      One change in this rule from standard Part 75 emissions data reporting is elimination of the requirement to provide[?] substitute data calculations within ECMPS. The ARP and other emissions trading programs that report emissions data to the EPA using Part 75 require provision of a complete data record. Emissions data are required to be reported for every unit operating hour. When CEMS are out of service, substitute data must be reported to fill in the gaps. However, for the purposes of compliance with a NESHAP, reporting substitute data during monitor outages is not necessary, as quantification of total mass emissions is not the focus of the rule. Hours when a monitoring system is out of service would be counted as hours of monitor down-time and may be a deviation from the monitoring requirements of this rule unless the rule provides an exception, such as for routine quality control and maintenance activities.
      In contrast to the CEMS-related data that would be submitted through ECMPS, you must submit reports of performance tests and PM CPMS data to EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). You must submit performance test data in the file format generated through use of EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html) within 60 days of performance test completion. Electronic data transmittal requirements are described in Section V.H. of this preamble
      Other notifications and reports will be submitted in hardcopy form at this time.
VI. Summary of Significant Changes Since Proposal
A. Applicability
       Since proposal, the EPA has made several changes to the applicability of this final rule.
      The EPA is revising a number of the proposed definitions and adding a definition for "natural gas-fired electric utility steam generating unit" in the final rule to provide clarity to the regulated community concerning the standards applicable to coal- and oil-fired EGUs.
      In the proposed rule, the EPA defined "[e]lectric utility steam generating unit" consistent with the CAA section 112(a)(8) definition:
      a fossil fuel-fired combustion unit of more than 25 megawatts electric (MWe) that serves a generator that produces electricity for sale. A fossil fuel-fired unit that cogenerates steam and electricity and supplies more than one-third of its potential electric output capacity and more than 25 MWe output to any utility power distribution system for sale is considered an electric utility steam generating unit.
      40 C.F.R. 63.10042.
      We also indicated how we would determine whether units were coal-fired or oil-fired fired EGUs: "If an EGU burns coal (either as a primary fuel or as a supplementary fuel), or any combination of coal with another fuel (except solid waste as noted below), the unit is considered to be coal fired under this proposed rule. If a unit is not a coal-fired unit and burns only oil, or oil in combination with another fuel other than coal (except as noted below), the unit is considered to be oil fired under this proposed rule." 76 FR 25020.
      We proposed a definition for the term "fossil fuel-fired" because that term was not defined in the statute and we wanted to clarify the level of fossil fuel combustion necessary to satisfy the CAA section 112(a)(8) definition of EGU. The definition focused on coal and oil combustion because the EPA was only regulating coal- and oil-fired EGUs in this final rule. The proposed definition contained two primary elements: 1) the unit must be capable of combusting sufficient amounts of coal or oil to generate the equivalent of 25 megawatts electrical output; and 2) the unit must have fired coal or oil for 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 years. 76 FR 25025. We further stated that for a unit to be "capable of combusting" coal or oil the unit must have a permit that authorized the combustion of coal or oil and also have the appropriate fuel handling facilities on-site. Id.
      As explained in the proposed rule, natural gas-fired EGUs were not included in the December 2000 listing so such units that otherwise met the CAA section 112(a)(8) definition of EGU because of natural gas combustion are not be subject to the final rule. In the proposed rule, we stated that an EGU that "combusts natural gas exclusively or natural gas in combination with another fuel where the natural gas constitutes 90 percent or more of the average annual heat input during the previous 3 calendar years or 85.0 percent or more of the annual heat input during any one of those calendar years" was not subject to the rule. Id. The references to 90 percent natural gas combustion over 3 years and 85 percent natural gas combustion in any one year were included to align with the definitions of "fossil fuel-fired" so that it would be clear that units combusting primarily natural gas would not be considered coal-fired, oil-fired, or IGCC EGUs if they burned 10 percent or less of coal, oil, or synthetic gas derived from coal or solid oil over 3 years or 15 percent or less of such fuels in any one year. We did not intend to suggest that to be considered a fossil fuel-fired EGU a natural gas-fired unit that is not a coal-fired or oil-fired EGU would have to combust natural gas that exceeded the 10 percent/15 percent thresholds set forth in the proposed rule. In fact, in 40 CFR 63.9983 of the proposed rule, we stated that "[a]ny 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 years" is not subject to this subpart.
      We further explained that the percentages included in the definition of "fossil fuel-fired" would prevent units that primarily combusted fuels other than fossil fuels from being subjected to the final rule:
      Units that do not meet the definition of fossil-fuel fired would, in most cases, be considered IB units subject to one of the Boiler NESHAP. Thus, for example, a biomass-fired EGU, regardless of size, that utilizes fossil fuels for startup and flame stabilization purposes only (i.e., less than or equal to 250 MMBtu/hr and used less than 10.0 percent of the average annual heat input during the previous 3 calendar years or less than 15.0 percent of the annual heat input during any one of those calendar years) is not considered to be a fossil fuel-fired EGU under this proposed rule. EPA has based its threshold value on the definition of "oil-fired" in the ARP found at 40 CFR 72.2. As EPA has no data on such use for (e.g.) biomass co-fired EGUs because their use has not yet become commonplace, we believe this definition also accounts for the use of fossil fuels for flame stabilization use without inappropriately subjecting such units to this proposed rule. Id.
      Thus, in the proposed rule, we intended to create thresholds to determine when a unit is fossil fuel-fired and for which fossil fuel the unit is fossil fuel-fired. We intended to include a unit combusting more than the defined amount of coal in one of the coal-fired EGU subcategories. If a unit is not coal-fired and it is combusting more than the defined amount of oil, we intended to include the unit in one of the oil-fired EGU subcategories. We also intended to make clear that electric steam generating units that are neither coal-fired nor oil-fired but combust more than the defined amount of natural gas are natural gas-fired EGUs not subject to the final standards. However, the definitions, as proposed, were not sufficiently descriptive.
      For example, we included a definition for "coal-fired electric utility steam generating unit" that did not include the requirement that the unit must combust coal for at least 10 percent of the heat input over 3 years or 15 percent of the heat input in any one year. Instead, in the proposed rule we indicated that a unit was coal-fired if it burned coal in any amount. We did not intend to define a unit as coal-fired if it burned coal that accounted for 10 percent or less over 3 years or 15 percent of less in any one year, as that would be inconsistent with the definition of fossil fuel- fired and the definitions for the oil-fired EGU subcategories. Under the proposed rule construct, a unit that combusts mostly biomass and less than 10 percent coal over 3 years would not be a coal-fired EGU because it would not meet the "fossil fuel-fired" definition. But a unit burning mostly petroleum coke and less than 10 percent coal over 3 years might be considered a coal-fired EGU because it would meet the definition of "fossil fuel-fired" and be burning some coal, even though that level of coal combustion alone would not be sufficient to make the unit "fossil fuel-fired" for coal. That result is at odds with our intent. The same would hold true for an EGU that combusts mostly natural gas and less than 10 percent synthetic gas derived from coal over a 3-year period. Our proposal preamble makes clear that we did not intend this result because we specifically stated that units burning 90 percent or more natural gas over a 3-year period would be considered natural-gas fired EGUs. 76 FR 25025.
      In addition, we proposed to define "[u]nit designed to burn solid oil fuel subcategory" to include any EGU that burned a solid fuel derived from oil for 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 years, either alone or in combination with other fuels. We also included the 10 percent/15 percent thresholds in the definition for the liquid oil subcategory, but, as stated above, we did not include the thresholds in the definition of "coal-fired" EGU. Therefore, there would be some confusion for a source that blended coal with solid oil derived fuel (e.g., petroleum coke). For example, the owner or operator of an EGU that burned sufficient solid oil-derived fuel that accounted for 80 percent of the heat input in a given year and the remainder of the fuel was coal would not be sure which standard applied because the definitions in the proposed rule were internally inconsistent.
      For these reasons, we are revising the definitions for "coal-fired electric utility steam generating unit," "integrated gasification combined cycle electric utility steam generating unit," and "oil-fired electric utility steam generating unit," and we are adding a definition of "natural-gas fired electric utility steam generating unit" as follows:
      Coal-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that burns coal or coal refuse for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.
      Integrated gasification combined cycle electric utility steam generating unit or IGCC means an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that burns a synthetic gas derived from coal and/or solid oil-derived fuel for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year in a combined-cycle gas turbine. No coal or solid oil-derived fuel is directly burned in the unit during operation.
      Oil-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that is not a coal-fired electric utility steam generating unit and that burns oil for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.
      Natural gas-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that is not a coal-fired, oil-fired, or IGCC electric utility steam generating unit and that burns natural gas for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.
      In addition to these changes, we are also revising the definition of "fossil fuel-fired" based on comments. We are revising the definition to remove the heat input equivalent of 25 MWe because commenters noted that the equivalency used (taken from 40 CFR Part 60, subpart Da) could not be applied consistently because of differing boiler efficiencies. Commenters noted that owners/operators were familiar with the use of the "MW" term for the boilers and boilers include nameplate capacities that are readily identifiable. We are also including a revision to the definition so that the fossil fuel combustion thresholds of 10 percent over 3 consecutive years and 15 percent in one year are evaluated after the compliance date of the final rule on a rolling basis. Commenters correctly noted that some coal- and oil-fired EGUs will convert their units to alternative fuels (e.g., natural gas or biomass) and if the definition was finalized as proposed such units could be improperly subjected to the final standards. The new definition is as follows:
      Fossil fuel-fired means an electric utility steam generating unit (EGU) that is capable of combusting more than 25 MW of fossil fuels. To be "capable of combusting" fossil fuels, an EGU would need to have these fuels allowed in their operating permits and have the appropriate fuel handling facilities on-site or otherwise available (e.g., coal handling equipment, including coal storage area, belts and conveyers, pulverizers, etc.; oil storage facilities). In addition, fossil fuel-fired means any EGU that fired fossil fuels for more than 10.0 percent of the average annual heat input in any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year after [COMPLIANCE DATE OF THE FINAL RULE].
      We are also removing the definition of "[u]nit designed to burn liquid oil fuel subcategory," revising the definition of "[u]nit designed to burn solid oil fuel subcategory," adding definitions for the continental and non-continental liquid oil-fired EGU subcategories, and adding a definition of a limited-use liquid oil-fired EGU as follows:
      Unit designed to burn solid oil-derived fuel subcategory means any oil-fired EGU that burns solid oil-derived fuel.
      Continental liquid oil-fired subcategory means any oil-fired electric utility steam generating unit that burns liquid oil and is located in the continental United States.
      Non-continental liquid oil-fired subcategory means any oil-fired electric utility steam generating unit that burns liquid oil and is located outside the continental United States.
      Limited-use liquid oil-fired subcategory means an EGU with an annual oil-fired capacity factor of less than 5 percent.
      In the proposed rule, we stated that we believed EGUs may at times not meet the definition of an EGU subject to this subpart. For example, we explained that there may be some cogeneration units that are determined to be covered under the Boiler NESHAP. Such unit(s) may make a decision to increase the proportion of production output being supplied to the electric utility grid, thus causing the unit(s) to meet the EGU cogeneration criteria (i.e., greater than one-third of its potential output capacity and greater than 25 MWe). In the preamble to the proposed rule, we indicated that a unit subject to one of the Boiler NESHAP that increases its electricity output and meets the definition of an EGU would be subject to the EGU NESHAP for the 6-month period after the unit meets the EGU definition. 76 FR 25026. Assuming the EGU did not meet the definition of an EGU following that initial occurrence, at the end of the 6-month period it could revert back to being subject to the Boiler NESHAP, or other applicable standard. We solicited comment on the extent to which situations like this might occur, how the EPA should address situations where units change applicability, and whether we should include provisions similar to those included in the final CISWI (40 CFR 60.2145) to address such situations. Id.
      We received comment that requested the Agency provide provisions that would address situations where sources become or cease being subject to this subpart. Because applicability to the final rule is based in part on the statutory definition of an EGU is CAA section 112(a)(8), similar to the situation with units combusting solid waste under CAA section 129(g)(1) (e.g., CISWI Rule), we are adopting provisions in the final rule that are based on the fuel switching provisions of the final CISWI Rule (See Final CISWI Rule, 40 CFR 60.2145). We are finalizing that you are subject to the requirements of this final rule at least 6 months following the last date you met the definition of an EGU subject to this 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 are finalizing a provision whereby you may opt to remain subject to the provisions of this final rule, 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.
 B. Subcategories
       The proposed rule subcategorized EGUs burning coal into two subcategories: EGUs designed for coal >8,300 Btu/lb and EGUs designed for low rank virgin coal. We received a number of comments indicating that the definition of the low rank virgin coal subcategory was technically deficient.
       Under CAA section 112(d)(1), the Administrator has the discretion to "...distinguish among classes, types, and sizes of sources within a category or subcategory in establishing..." standards. The EPA maintains that any basis for subcategorization (i.e. class, type, or size) must be related to an effect on HAP emissions that is due to the difference in class, type or size of the units. See 76 FR 25036-25037. The EPA believes it is not reasonable to exercise our discretion without such a difference because if sources can achieve the same level of emissions reductions notwithstanding a difference in class, type, or size the purposes of CAA section 112 are better served by requiring a similar level of control for all such units in the category or subcategory. See Lignite Energy Council v. EPA, 198 F. 3d 930, 933 (D.C. Cir. 1999) ("EPA is not required by law to subcategorize--section 111 [b] [2] merely states that `the Administrator may distinguish among classes, types, and sizes within categories of new sources'" (emphasis original)); see also CAA section 112(d)(1) (containing almost identical language to CAA section 111, CAA section 112(d)(1) provides that "the Administrator may distinguish among classes, types, and sizes of sources within a category or subcategory in establishing [] standards..."). Even if we determine that emissions characteristics are different for units that differ in class, type or size, the Agency may still decline to subcategorize if there are compelling policy justifications that suggest subcategorization is not appropriate. Id.
       When developing the proposed rule, we examined the EGUs in the top performing 12 percent of sources for Hg emissions. We determined that: