# Appendix — Nat'l Mining Ass'n v. Envtl. Prot. Agency, 135 S. Ct. 703 (2014) (No. 14-49) > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385016_0333%3A03 ## Record - **Collection:** Supreme Court brief - **Document type:** Appendix - **Published:** January 1, 2014 ## Text 14- 49 No. 14-___ IN THE Supreme Court of the Anited States NATIONAL MINING ASSOCIATION, PETITIONER Vv. ENVIRONMENTAL PROTECTION AGENCY, RESPONDENT Se ee ON PETITION FOR WRIT OF CERTIORARI TO THE UNITED STATES COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT PETITION FOR A WRIT OF CERTIORARI VOLUME 2 of 4 CARROLL W. MCGUFFEY III PETER S. GLASER JUSTIN WONG (Counsel of Record) TROUTMAN SANDERS LLP TROUTMAN SANDERS LLP 600 PEACHTREE STREET, NE 401 NINTH STREET N.W. SUITE 5200 SUITE 1000 ATLAN14, GA 30308-2216 WASHINGTON, D.C. 20004 202-274-2998 Peter.glaser @troutmansanders.com duly 14, 2014 Counsel of Petitioner Gauson- Eres Pravina CO, Inc. — (202) 789-0096 — WaSHinGTON,D C 20002 New-—Liquid oil— continental New-—Liquid oil— non- continental We are also finalizing alternate equivalent emission standards (for certain subcategories) to the final surrogate standards in three areas: SO: (for HCl), 483a Table 4--Emission Limitations for Filterable particulate matter 3.0E-2 lb/MMBtu (3.0E-1 Ib/MWh) 3.0E-2 Ib/MMBtu (3.0E-1 Ib/MWh) 7.0E-2 lb/MWh 2.0E-1 lb/MWh Liquid Oil-Fired EGUs Hydrogen chloride 2.0E-3 Ib/MMBtu (1.0E-2 lb/MWh) 2.0E-4 lb/MMBtu (2.0E-3 Ib/MWh) 4.0E-4 lb/MWh 2.0E-3 IhyMWh Hydrogen fluoride 4.0E-4 lb/MMBtu. (4.0E-3 lb/MWh). 6.0E-5 Ib/MMBtu. (5.0E-4 Ib/MWh). 4.0E-4 lb/MWh. 5.0E-4 Ib/MWh. individual non-mercury metals and total non-mercury metals (for filterable PM) from coal- and solid oil- derived fuel-fired EGUs, and individual and total metals (for filterable PM) from oil-fired EGUs. The final alternate emission limitations are provided in Tables 5 and 6 of this preamble. Subcatego Coal- ry/ Pollutant SO[2)} Cadmium, fired EGUs 484a Table 5—Alternate Emission Limitations for IGCC NA Liquid oil, continent al NA Existing Coal- and Oil-Fired EGUs Liquid oil, non- continent al NA Solid oil- derived Existing Coal- and Oil-Fired EGUs Subcatego ry/ Pollutant Chromium Cr Cobalt, Co Lead, Pb Nickel, Ni Coal- fired EGUs 2.8E0 Ib/TBtu (3.0E-2 lb/GWh) 8.0E-1 lb/TBtu (8.0E-3 lb/GWh) 1.2E0 lb/TBtu (2.0E-2 Ib/GWh) 4.0E0 lb/TBtu (5.0E-2 Ib/GWh NA 3.5E0 Ib/TBtu (4.0E-2 Ib/GWh) 5.0E0 lb/TBtu (6.0E-2 485a Table 5—-Alternate Emission Limitations for IGCC 2.9E0 lb/TBtu (3.0E-2 lb/GWh) 1.2E0 lb/TBtu (2.0E-2 Ib/GWh) 1.9E+2 lb/MMB tu (1.8E0 Ib/MWh) 2.5E0 lb/TBtu (3.0E-2 Ib/GWh) NA 6.5E0 lb/TBtu (7.0E-2 lb/GWh) 2.2E+1 Ib/TBtu (3.0E-1 Liquid oil, continent al 5.5E0 Ib/TBtu (6.0E-2 lb/GWh) 2.1E+1 lb/TBtu (3.0E-1 lb/GWh) 8.1E0 Ib/TBtu (8.0E-2 Ib/GWh) 2.2E+1 Ib/TBtu (3.0E-1 Ib/GWh) 2.0E-1 Ib/TBtu (2.0E-3 Ib/GWh) 1.1E+2 ib/TBtu (1.1E0 Ib/GWh) 3.3E0 lb/TBtu (4.0E-2 Liquid oil, non- continent al 3.1E+1 lb/TBtu (3.0E-1 lb/GWh) 1.1E+2 lb/TBtu (1.4E0 lbyYGWh) 4.9E0 IbvTBtu (8.0E-2 Ib/GWh) 2.0E+1 ib/TBtu (3.0E-1 Ib/GWh) 4.0E-2 Ib/TBtu (4.0E-4 Ib/GWh) 4.7E+2 lb/TBtu (4.1E0 IWGWh) 9.8E0 Ib/TBtu (2.0E-1 Solid oil- derived 8.0E-1 ib/TBtu. (2.0E-2 lb/GWh). 1.1E0 Ib/TBtu. (2.0E-2 Ib/GWh). 8.0E-1 ib/TBtu. (2.0E-2 Ib/GWh). 2.3E0 Ib/TBtu. (4.0E-2 Ib/GWh). NA. 9.0E0 lb/TBtu. (2.0E-1 Ib/GWh). 1.2E0 Ib/TBtu. (2.0E-2 486a Table 5--Alternate Emission Limitations for Existing Coal- and Oil-Fired EGUs Subcatego Coal- IGCC Liquid Liquid Solid oil- ry/ fired oil, oil, Pollutant EGUs continent non- ésrived al continent al Ib/GWh) ib/GWh) Ib/GWh) Ib/GWh) Ilb/GWh). NA = Not applicable. fna Includes Hg. Table 6--Alternate Emission Limitations for New Coal- and Oil-Fired EGUs Subcategory/ Coal- IGCC Liquid Liquid Solid fired fna oil, oil, Pollutant EGUs continen- non- oil- tal, continen- derived Iv¥GWh tal, lb/GWh SO[2] 4.0E-1 4.0E-1 NA NA 4.0E-1 lbyYMWh lb/MWh Ib/MWh Total non- 6.0E-2 4.0E-1 2.0E-4 7.0E-3 6.0E-1 mercury metals IbyYGWh Ib/GWh Ib/MWh ib/MWh Ib/GWh fnb Antimony, 8.0E-3 2.0E-2 1.0E-2 8.0E-3 Sb lb/GWh lb/GWh lb/GWh Arsenic, As 3.0E-3 2.0E-2 3.0E-3 6.0E-2 3.0E-3 lb/GWh Ib/GWh lb/GWh Beryllium, 6.0E-4 1.0E-3 5.0E-4 2.0E-3 6.0E-4 Be lb/GWh _ Iib/GWh Ib/GWh Cadmium, 4.0E-4 2.0E-3 2.0E-4 2.0E-3 7.0E-4 Cd lb/GWh lb/GWh lb/GWh 487a Table 6—Alternate Emission Limitations for New Coal- and Oil-Fired EGUs Subcategory/ Coal- IGCC Liquid Liquid Solid fired fna oil, oil, Pollutant EGUs continen- non- oil- tal, continen- derived IbvYGWh tal, lb/GWh Chromium, 7.0E-3 4.0E-2 2.0E-2 2.0E-2 6.0E-3 Cr lb/GWh_ \ib/GWh lb/GWh Cobalt, Co 2.0E-3 4.0E-3 3.0E-2 3.0E-1 2.0E-3 lb/GWh _ ib/GWh Ib/GWh Lead, Pb 2.0E-3 9.0E-3 8.0E-3 3.0E-2 2.0E-2 Ib/GWh lb/GWh lb/GWh Mercury, Hg NA NA 1.0E-4 4.0E-4 2.0E-3 Ib/GWh Manganese, 4.0E-3 2.0E-2 2.0E-2 1.0E-1 7.0E-3 Mn lb/YGWh_ ib/GWh lb/GWh Nickel, Ni 4.0E-2 7.0E-2 9.0E-2 4.1E0 4.0E-2 Ib/GWh_ 1lb/GWh Ib/GWh Selenium,Se 6.0E-3 3.0E-1 2.0E-2 2.0E-2 6.0E-3 Ib/GWh itb/GWh Ib/GWh NA = Not applicable. fna Based on best-performing similar source. fnb Includes Hg. 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 a requirement to use filterable PM as a surrogate for the total metallic HAP, and we are finalizing HCl and HF limits. 488a In addition, we are finalizing alternative standards for certain HAP for some subcategories. The alternative pollutants and subcategories are as follows: (1) SO2 as a surrogate to HC) for all subcategories with add-on FGD systems (except liquid oil-fired subcategories as there were no existing units from which to base an alternate SO[2] limit); (2) individual non-mercury metallic HAP as an alternate to filterable PM for all subcategories (except that it includes Hg for liquid oil-fired subcategories); and (3) total non-mercury metallic HAP as an alternate to filterable PM for all subcategories (except that it includes Hg for liquid oil-fired subcategories). These alternative standards are discussed elsewhere in this preamble. 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 is achievable after considering the relevant CAA section 112(d)(2) provisions. As noted elsewhere in this preamble, we are also finalizing a compliance assurance option that would allow you to monitor liquid oil fuel moisture to demonstrate that fuel moisture content is no greater than 1.0 percent. Provided that demonstration is made, you will not have to conduct additional testing and monitoring to demonstrate compliance with the HC] and HF emission limits for units in both liquid oil subcategories (i.e., continental and non-continental). Pursuant to CAA section 112(h), we are finalizing a work practice standard for organic HAP, including emissions of dioxins and furans, for all subcategories of EGUs. The work practice standard being finalized 489a 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 believe that a work practice standard will lead to a better environmental outcome than would be obtained through a requirement to measure a pollutant for which results may or may not be obtained. We believe that the work practice standard will result in actions being taken that will reduce emissions of these HAP. In addition, as discussed below, we are creating a subcategory for limited use liquid oil-fired electric utility steam generating unit with an annual capacity factor of less than 8 percent of its maximum or nameplate heat input and we are establishing work practice standards applicable to such units pursuant to CAA section 112(h). We are finalizing that new or existing EGUs are “coal-fired” if they combust coal more than 10 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15 percent of the annual heat input during any one calendar year %#® We would also note that the EPA, as a part of the Industrial Boiler MACT reconsideration proposal that was signed on December 2, 2011, is proposing to establish work practice stand- ards for control of dioxins and furans from industrial boilers. 490a and meet the final definition of “fossil fuel-fired.” We are finalizing that an EGU is considered to be in the coal-fired “unit designed for coal greater than or equal to 8,300 Btu/Ib” subcategory if the EGU: (1) meets the final definitions of “fossil fuel-fired” and “coal-fired electric utility steam generating unit;” and (2) 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 in the “unit designed for low rank virgin coal” subcategory if the EGU: (1) meets the final definitions of “fossil fuel-fired” and “coal-fired electric utility steam generating unit;” and (2) 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/Ilb) 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, pet coke), (2) meets tle 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 have similar HAP content and similar HAP *” ASTM Method D388-05, “Standard Classification of Coals by Rank” (incorporated by reference, see § 63.14). 49la emissions characteristics that can be controlled in a similar manner.“ We are finalizing that the EGU is considered to be in the “Continental liquid oil-fired” subcategory if (1) meets the final definitions of “oil-fired electric utility steam generating unit” and “fossil fuel-fired;” and (2) is located in the continental United States (U.S.). We are finalizing that the EGU is considered to be “Non-continental liquid oil-fired” subcategory if (1) meets the final definitions of “oil-fired electric utility steam generating unit” and “fossil fuel-fired;” and (2) is located outside continental U.S. We are finalizing that the EGU is considered to be “solid oil-derived fuel-fired” if (1) the EGU is not a coal- fired EGU and burns solid oil-derived fuel (e.g., petroleum coke, pet coke); and (2) meets the final definitions of “oil-fired electric utility steam generating unit” and “fossil fuel-fired.” We are finalizing that the EGU is considered to be a “limited-use liquid oil-fired” if (1) the EGU meets the final definitions of “oil-fired electric utility steam generating unit” and “fossil fuel-fired;” and (2) has an annual capacity factor of less than 8 percent of its maximum or nameplate heat input, whichever is greater, averaged over a 24-month block contiguous period commencing. E. What are the requirements during periods of startup, shutdown, and malfunction? *¢ U.S. Department of Energy, Wabash River Coal Gaification Repowering Project. Project Performance Summary; Clean Coal Technology Demonstration Program. DOE/FE-0448. July 2002. EPA-HQ-OAR-2009-0234-2933. 492a As discussed below in section VI1.E., for startup and shutdown, the requirements have changed since proposal. For periods of startup and shutdown, the EPA is finalizing work practice standards in lieu of numeric emission limits. Numeric emission limits apply for all other periods for all pollutants, except organic HAP. For malfunctions, the EPA is finalizing an affirmative defense for exceedances of the numerics! emission limits that are caused by malfunc- tions. 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 regulated pollutant under final 40 CFR part 63, subpart UUUUU (e.zg., Hg CEMS, HCl CEMS, HF CEMS, SO, CEMS (where an SO[2] limit applies as the alternative equivalent standard)), 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 of data collected with the certified monitoring system prior to the initial compli- ance demonstration date specified in § 63.10005. A source may also elect to use a PM CEMS to demonstrate compliance with the filterable PM emission limit. If this option is selected, then the same provisions as noted above for other CEMS will apply. (Note that EPA anticipates that the PM monitoring device that may most often will be used is a PM continuous parameter monitoring system (CPMS) in conjunction with an operating limit, as more fully 493a described below.) For units and pollutants not being monitored via CEMS, the owner or operator of an affected unit must perform the initial performance testing in accordance with established EPA reference test methods or the voluntary consensus standard methods incorporated by reference. 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 filterable PM emissions testing using EPA Method 5 from Appendix A to part 60 of chapter 40 to determine initial compliance. Alternatively, 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 40. Note for this rule that the filter temperature for each Method 5 or 29 emissions test must be maintained at 160 [degrees] +/- 14 [degrees] C (320 [degrees] +/- 25 [degrees] F), 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 a sorbent trap monitoring system for both initial compliance and 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 494a the 30 boiler operating days of data collected with the certified monitoring system by the initial compliance demonstration date specified in § 63.10005. (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 alterna- tive SOzlimit in place of the HCl limit, you need not conduct an initial stack test for HC] or. Instead, the 30 boiler operating days of data collected with the certi- fied SO. CEMS by the initial compliance demonstra- tion date specified in § 63.10005 are used to determine initial compliance, and the SO[2] CEMS is used there- after 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 30 boiler operating days of data collected with the certified HC] CEMS by the initial compliance demonstration date specified in § 63.10005 are used to determine initial compliance. For units not using the SO[2] or HC] CEMS options, you must conduct an initial stack test for HCl using EPA Method 26, 26A, or 320 from Appendix A to part 60 of chapter 40. You may use EPA Method 26 or 320 or ASTM Method D6348-03 (Reapproved 2010) with additional quality assurance 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. If you elect to meet the filterable PM limit instead of the non-mercury metals limit (total or individual), then use Method 5 with the filter material maintained at 160 [degrees] +/- 14 [degrees] C (320 [degrees) +/- 25 [degrees] F). Alterna- tively, you may use a PM CEMS as discussed 495a elsewhere in this preamble. If you elect to meet either the total or individual HAP metals limit, you will use Method 29 for all non-mercury HAP metals. For Hg, conduct emissions testing using EPA Method 29 or 30B from Appendix A to part 60 of chapter 40, or ASTM Method D6784-02 (Reapproved 2008). For acid gases, conduct HC] and HF testing using EPA Method 26A, 320, or 26; or you may elect to comply by using an HCl CEMS and/or an HF CEMS; or under certain conditions you may choose to demonstrate compliance by measuring fuel moisture to demonstrate that moisture content is no greater than 1.0 percent. You must measure daily if fuel is delivered continuously or per shipment if fuel is delivered on a batch basis, or you may use a fuel moisture content certification provided by your fuel supplier. If you use a CEMS, then use the 30 boiler operating days of data collected with the certified monitoring system by the initial compliance demonstration date specified in § 63.10005 to determine initial compliance. (5) For the required performance stack tests, if you are demonstrating compliance with a heat-input based standard, you must conduct concurrent O[2] or carbon dioxide (SO2) emission testing using EPA Method 3A or 3B from appendix A to part 60 of chapter 40 or ANSVASME PTC 19.10-1981 and then use an appropriate equation, selected from among Equations 19-1 through 19-9 in EPA Method 19 from appendix A to part 60 of chapter 40, to convert measured pollutant concentrations to Ib/MMBtu values. Multiply the lb/MMBtu value by one million to get the lb/TBtu value (where applicable). If you choose to meet an electrical output-based emissions limit, you must also collect concurrent stack gas flow rate and electrical production data. 496a (6) For an existing unit that you believe will qualify as LEE for Hg, you must condvct an initial Method 30B test over 30 days and follu.. the calculation procedures in the final rule to document a potential to emit less than 10 percent of the applicable Hg emissions limit or less than 29 pounds of Hg per year. If your unit qualifies as a LEE for Hg, you must conduct subsequent performance tests on an annual basis to demonstrate that the unit continues to qualify. For all other pollutants, you must conduct the initial compliance test, and then all other required tests over a 3-year period, and in all such tests, your emission results must be less than 50 percent of the applicable emission limit. If you qualify as a LEE on that basis, you must conduct subsequent performance tests every 3 years 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 and keep records demonstrating that no significant changes have occurred, b. Tests were conducted using methods allowed in this rule in accordance with § 63.10007 and Table 5, c. You have records of all parameters needed to convert results to units of the standard for the entire period, and d. For a CEMS-based performance test, you have all the required data for the entire 30-boiler operating day rolling average period. Operating Limit for PM CEMS 497a Under the final rule, you may elect to comply con- tinuously with an operating limit, established during the initial performance test, to demonstrate continu- ous compliance with the filterable PM, total non- mercury HAP metals, or individual non-mercury HAP metals limit. You will use a PM CPMS to monitor compliance with the operating limit. The PM CPMS operating principle must be based on in-stack or extractive light scatter, light scintillation, beta atten- uation, or mass accumulation detection of the exhaust gas or representative exhaust gas sample. The report- able measurement output from the PM CPMS may be expressed as milliamps, stack concentration, or other raw data signal. Meeting the operating limit serves as your demonstration of continuous compliance with the filterable PM, total non-mercury HAP metals, or indi- vidual non-mercury HAP metals limit. As mentioned earlier, if you use this method to demonstrate contin- uous compliance, you must install a PM CPMS and establish the operating limit during the initia] compli- ance test for filterable PM, total non-merecury 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. You may also opt to install and operate a PM CEMS certified in accordance with Per- formance Specification 11 and Procedure 2 of 40 CFR part 60, Appendices B and F, respectively. If you elect to use this option, then the requirements for quarterly testing with Method 5, or annual testing and use of a PM CPMS, are no longer applicable. Dioxins/Furans and Non-Dioxin/Furan Organic HAP 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 498a equipment inspection, and an optimization to minimize generation of CO and NO[X], all meeting the requirements of this final rule. The work practice standard involves maintaining and inspecting the burners and associated combustion controls, tuning the specific burner type to optimize combustion, obtaining and recording CO and NO[X] values before and after burner adjustments, keeping records of activity and measurements, and submitting a report for each tune-up conducted. You must collect CO and NO[X] data and may use portable analyzers (which include handheld or similar devices) to monitor and verify the results. The specific details are addressed in 40 CFR 63.10021 of the final rule. This same work practice standard also applies in place of any emission limits for Hg, non-mercury metals HAP, acid gas HAP, dioxins and furans, and non-dioxin/furan organic HAP from a limited-use, liquid oil-fired EGU (i.e., a unit that has an annual capacity factor on oil of less than 8 percent of its maximum or nameplate heat input, whichever is greater). The EPA established this subcategory in response to comments and a further analysis of the units within this subcategory in the ICR database. For these units, EPA believes that the required work practice standards are appropriate and consistent with the requirement of CAA section 112(h). G. What are the continuous compliance requirements? To demonstrate continuous compliance with the emission limitations, the final rule includes the following requirements: (1) Use of CEMS. Where a CEMS or a sorbent trap monitoring system is used for demonstrating initial compliance, you also must use the CEMS or sorbent 499a trap monitoring system on a continuous basis to demonstrate ongoing compliance with the numerical emission limits. CEMS or sorbent trap monitoring system data are not used to determine compliance with the work practice standards applicable during periods of startup and shutdown, but sources that install a CEMS or a sorbent trap monitoring system to demonstrate compliance with the numerical emission limits must operate the system at ail times, as EPA intends to evaluate the continuous monitoring data from start-up and shutdown periods as discussed below. You must calculate a rolling average for each successive 30-boiler operating day rolling average period. All valid data collected during each successive period will be used to demonstrate compliancr . except for data collected during periods of startup and shutdown; during those periods, the owner or operator must meet work practice requirements instead of the numerical emission limits. There is no numerical minimum data availability required to constitute a valid 30-boiler operating day rolling average; however, you must monitor at all times that the process is in operation (including during startups and shutdowns, although emissions during these periods are not included in the 30-boiler operating day average). You must operate, maintain, and quality-assure the CEMS or sorbent trap monitoring systems in accordance with the provisions in 40 CFR 63.10010 and Appendix A and B of the final rule (for Hg, HCl, and HF CEMS), in accordance with Performance Specification 11 in Appendix B to 40 CFR part 60 and Procedure 2 in Appendix F to part 60 (for PM CEMS used for direct compliance), or in accordance with 40 CFR part 75 (for SO2z CEMS, and certain ancillary monitors such as a diluent or moisture monitor). 500a For each unit using HCl, HF, SO:, PM, or Hg CEMS or a sorbent trap monitoring system for continuous compliance, you must install, certify, maintain, operate and quality-assure the additional CEMS (e.z., CEMS that measure O, or CO: 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. For HC] and HF CEMS, the EPA is adding monitoring provisions as Appendix B to 40 CFR part 63, subpart UUUUU. Appendix A references perfor- mance specification (PS) 15 of Appendix B to 40 CFR part 60 for Fourier Transform Infrared (FTIR) CEMS for procedures to certify and conduct ongoing quality assurance on these FTIR CEMS. In addition, we expect to publish a PS specific to HC] CEMS in the near future (prior to the compliance date of this rule). In the meantime, you may petition the Administrator under the procedure given in 40 CFR 63.7(f) for an alternative approach to compliance monitoring or testing 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 boiler operating days. Under the general duty to monitor at all times, you must replace traps in a timely manner to ensure that Hg emissions are sampled continuously. For Hg monitoring, the EPA is adding Hg monitor- ing provisions as Appendix A to 40 CFR part 63, subpart UUUUU, and requiring use of these provi- sions to document continuous compliance with the rule for coal-fired, IGCC, and solid oil derived-fired units 501la 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 cer- tification 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 integ- rity checks, quarterly linearity checks (or 3-level system integrity checks), and annual RATAs. Table A- 2 in Appendix A summarizes these ongoing QA test requirements and the applicable performance criteria for Hg CEMS, which are consistent with those published in support of CAMR and are, thus, familiar to the industry. 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 Appendix K to 40 CFR part 75, published in support of CAMR and 502a with which the industry is familiar. The 40 CFR 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., |b/TBtu or lb/GWh). Section 6 of Appendix A provides the necessary equations for these unit conversions. For HCl and HF CEMS, the EPA is adding monitor- ing provisions as Appendix B to 40 CFR part 63, Subpart UUUUU. Appendix A references performance specification (PS) 15 of Appendix B to 40 CFR part 60 for Fourier Transform Infrared (FTIR) CEMS for procedures to certify and conduct ongoing quality assurance on these FTIR CEMS. In addition, we expect to promulgate a generic 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 63.7(f) for an alternative approach to compliance monitoring or testing for HC] or any other regulated pollutant. (2) Use of stack tests. If you demonstrate initial com- pliance on the basis of a stack test, you must demon- strate continuous compliance by conducting periodic stack tests on a quarterly basis. This includes filtera- ble PM (or non-mercury HAP metals) and HC) from coal-fired and solid oil-derived fuel-fired EGUs, and filterable PM (or HAP metals) and HCl and HF from liquid oil-fired EGUs with the following exceptions: 503a a. If you use a PM CPMS and associated operating limit, you may conduct the applicable Method 5 or Method 29 test once annually rather than quarterly, in which case you must 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 a require- ment for you to develop and follow a site-specific mon- itoring 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-boiler operating day period rolled daily. The 30-boiler operating day rolling average is calculated by all of the valid hourly average PM CPMS output values collected for the 30 boiler operating days (excluding hours of startup and shutdown; See section V.E. of this preamble). 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 quar- terly and establish site-specific monitoring to 504a demonstrate continued acid gas control performance between periodic tests, or ii. Use an HC] CEMS and/or HF CEMS. c. If your existing unit qualifies as an LEE for Hg, you must conduct another 30-day Method 30B 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 29 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 performance testing until you install, certify, and operate a Hg CEMS or a sorbent trap monitoring system, and you must complete the installation and certification within 6 months of losing LEE status; for a liquid fuel unit, you must commence quarterly performance testing. d. If a liquid oil-fired EGU has an annual capacity factor on oil of less than 8 percent of its maximum or nameplate heat input, whichever is greater, you must demonstrate continuous compliance with the applica- ble work practice standard by conducting at least once every 36 calendar months (48 calendar months if a neural network is employed) a combustion process tune-up, a thorough equipment inspection, and an optimization to minimize generation of CO and NOx, 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, 505a keeping records of activity and measurements, and submitting a report for each tune-up conducted. You must collect CO and NOx data using portable analyz- ers (which typically include handheld or similar devices). Specific details are addressed in 40 CFR 63.10021 of the final rule. 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 non- mercury 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. f. For liquid oil-fired units that demonstrate con- tinuous compliance with quarterly performance tests for HC] and HF emission limits rather than through use of HC] and HF CEMS, the final rule requires a site-specific monitoring plan in addition to the quar- terly tests. For these pollutants, there is unlikely to be any existing underlying monitoring (such as compli- ance assurance monitoring) that serves as an addi- tional tool to ensure the source’s operations remain consistent with operating conditions during a recent successful performance test. The requirement for a site-specific monitoring plan fills this gap and ensures 506a that in between tests, the source continues to operate in a manner designed to maintain HC] and HF emis- sions in compliance with the emission limits under this rule. The appropriate parameters to monitor will depend on the compliance strategy employed by a spe- cific source, and thus EPA is enabling the monitori approach to be established on a case-by-case basis. Given the relatively small number of these units and the other compliance options available, we anticipate that this approach will apply to a small set of units. The monitoring plan will identify the parameters mon- itored, the monitoring methods, the QA/QC elements that apply, and the data reduction elements (including appropriate averaging periods, as applicable). See 40 CFR 63.10000(cX2 ii). keeping records of activity and measurements, and submitting a report for each tune-up conducted. A combustion tune-up will involve optimizing combus- tion 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 in al] subcategories must comply with certain requirements of the General 507a Provisions (40 CFR part 63, subpart A), which are identified in Table 9 of this final rule. The General Provisions include specific requirements for notifica- tions, recordkeeping, and reporting. You must submit a notification of compliance status report for each unit, according to the schedule required by 40 CFR 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 semian- nual compliance reports, as required by 40 CFR 63.10(e)(3) of subpart A, 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 reevalu- ated. As discussed below, we are finalizing a requirement to use the 40 CFR part 75-based Emissions Collection and Monitoring Plan System (ECMPS) for reporting emissions and related data for units using CEMS for most pollutants. Also, as discussed below, for the PM CPMS, PM CEMS, and performance test results, we require you to use EPA’s WebFIRE*™ database for reporting. This rule requires you to keep certain records to demonstrate compliance with each emission limit and work practice standard. The General Provisions to 40 CFR part 63 specify these recordkeeping requirements (see Table 9 to this subpart). Among other specific records, you must keep the following: 38 WebFIRE is the Internet version of FIRE. The Factor Information Retrieval (FIRE) Data System is a database management system containing EPA’s recommended emission estimation factors for criteria and HAP. It includes information about industries and their emitting processes, the chemicals emitted, and the emission factors themselves. 508a (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) As part of the general duty to keep all monitoring data, 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 demon- strate initial or continuous compliance with this rule. (7) A copy of your site-specific performance evalua- tion test plans developed for this rule as specified in 40 CFR 63.8(e), if applicable. (8) A copy of your acid gas control system parameter monitoring plan under 40 CFR 63.10000(c2 ii). 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. 509a (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 alterna- tive 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 submittal 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 by this rule. Use of Electronic Reporting System We are requiring that you submit certain reports electronically. In addition to supporting regulation development, control strategy development, and other air pollution control activities, having an electronic database populated with these reports will save industry, state, local, tribal agencies, the public, and the EPA significant time, money, and effort while also improving the transparency and quality of emission inventories and, as a result, air quality regulations. 510a The reports to be submitted electronically include all performance test reports, notification of compliance status reports, compliance, and continuous monitoring data summaries specified in 40 CFR 63.10031 of this rule. Performance tests are required to be conducted as described in 40 CFR 63.7 of the General Provisions. The data that must be submitted as the performance test report are also described in 40 CFR 63.7. These data must be submitted (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 requirements for the notification of compliance status and compliance reports are described in detail in the regulatory text (40 CFR 63.10031) of this rule, but they essentially mirror the requirements in 40 CFR 63.6 of the General Provisions. These reports will also be submitted to WebFIRE using an electronic form found in CEDRI and through the CDX as described below. As required in 40 CFR 63.10031(f)(2) of the final rule, the continuous monitoring summaries are required to be submitted quarterly. The quarterly reports must include all of the calculated 30-boiler operating day rolling average values derived from the PM CPMS. These reports will also be submitted to WebFIRE using an electronic form found in CEDRI and through the CDX, as described below. This same approach will apply if a source elects to use a PM CEMS or receives approval to use a HAP metals CEMS as an alternative monitoring method. The availability of electronic reporting for sources subject to the Subpart UUUUU will provide efficiency, improved services, better accessibility of information, 5lia and more transparency and accountability. Addition- ally, 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 gener- ated, subsequent data submittal will only consist of electronic updates to existing information in the system. Such a system will effectively reduce the bur- den 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 will also ben- efit from having access to the more streamlined and accurate electronic data submitted to the EPA. Electronic reporting will allow for an electronic review process rather than a manual data assessment, mak- ing review and evaluation of the source-provided data and calculations easier and more efficient. Electronic reporting will also benefit the public by generating a more transparent review process and increasing the ease and efficiency of data accessibility. Furthermore, electronic reporting will reduce the burden on the reg- ulated 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 prospec- tive required residual risk assessments or technology reviews. Electronic reporting will substantially reduce this burden, because the EPA will already have these data available and consolidated in an electronic data- base named WebFTIRE. We anticipate that using elec- tronic reporting for the required reports will result in an overall reduction in reporting costs; for a discussion 512a of the economic and cost impacts of electronic report- ing, see section XII.D. of this preamble. Another benefit of electronic data submittal is that these data will greatly i 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, the EPA will be able to ensure that emission factors, when updated, represent the most current range of operational practices. Data entry of these electronic reports will be through the CEDRI that is accessed through EPA’s CDX (www.epa.govu/cdx). Data submitted 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 report being submitted, 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 value 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 513a used successfully to provide alternatives for other electronic forms (e.g., income tax submittal). In cases where performance test data are to be submitted to the EPA, you must enter the performance test data and information into the electronic reporting tool (ERT) which can be accessed at http://www. epa.gou/ttn/chief/ert /index.html. In CEDRI, the user must then upload the ERT file. CEDRI submits a copy of the ERT project data file directly to WebFIRE where the data are made available. Where performance test reports are submitted, WebFIRE notifies the appropriate state, local, or tribal agency contact that an ERT project data file was received from the source. Submitting performance test data electronically to the EPA will 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 - Web site listed above. I. Submission of Emissions Test Results to the 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 most CEMS that are consistent with 40 CFR part 75. You must report CEMS data (other than PM CEMS data or data from alternative monitoring subject to site- specific approval such as a HAP metals CEMS) to the 5l4a 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 Oz, 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. These data include 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 obtain 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 515a and QA data from SO2, COs, Ox, flow rate, and moisture monitoring systems that are installed, certified, maintained, operated, and quality-assured according to 40 CFR 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’ 40 CFR part 75 bias test (which is required for certain types of monitors under the EPA’s SO, and NOx 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 hourly 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); 516a (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 measure- ments 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 Ib/MMBtu, the DHV record can be used to report hourly pollutant concentration values in these units of measure, since the Ib/MMBtu values can be derived from the hourly pollutant and diluent gas (CO, or O2) concentrations reported in the MHV records. The 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., Ib/MMBtu, lb/TBtu, Ib/GWh, etc.) when hourly Hg concentration data are reported through ECMPS using the DHV record, in conjunction with the appropriste 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 40 CFR 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 517a 40 CFR 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, as it does 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 WebFTRE database by using CEDRI that is accessed through EPA’s CDX (www.epa.gouv/cdx). You must submit performance test data in the file format generated through use of EPA’s ERT (see http://www. epa.gou/ttn/chief/ert /index.html) within 60 days of performance test completion. Electronic data submittal requirements are described in section V.H. of this preamble. Other notifications and reports not currently accepted by the electronic reporting system will be submitted in hardcopy form at this time. VI. Summary of Significant Changes Since Proposal The previous section described the requirements that EPA is finalizing in this rule. This section will discuss in greater detail the key changes EPA is making from the proposed. These changes result from EPA’s review of the additional data and information 518a provided to us and our consideration of the man’ substantive and thoughtful comments submitted on the proposal. While our approach and methodology to establishing the standards remain the same, the changes make the final rule more flexible and cost- effective, reduce reliability concerns and improve clarity, while fully preserving, or improving, the public health and environmental protection required by the CAA. A. Applicability Since proposal, the EPA has made certain changes to the applicability provisions of the final rule to provide clarity. These changes do not change the universe of sources subject to the 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 “(ellectric utility steam generating unit” consistent with the CAA section 112(aX8) 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 CFR 63.10042. 519a 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 EGuUs were not included in the December 2000 listing so such units that otherwise met the CAA section 112(aX8) definition of EGU because of natural gas combustion are not subject to the final rule. In the 520a 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. Jd. The references to 90 percent natura! 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 “lajny 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 521la 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. The 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 common- place, 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 EGUs 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. 522a 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. 523a 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 set out in 40 CFR 63.10042. In addition to these changes, we are revising the definition of “fossil fuel-fired” based on comments. We are revising the definition to remove the heat input equivalent of 25 MW 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 applicable compliance date of the final rule on a rolling basis. Commenters correctly noted that some existing coal- and oil-fired EGUs will convert their units to alternative fuels (e.g., natural gas or biomass) and if the definition were finalized as 524a proposed such units could be improperly subjected to the final standards. The new definition is set out in 40 CFR 63.10042. For clarity, we are also removing the definition of “[ujnit 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 set out in 40 CFR 63.10042. 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 MW). 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. n310 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 would 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 525a included in the final CISWI (40 CFR 60.2145) to address such situations. Jd. n310 Although we clearly stated the intent to require sources to comply for 6 months after meeting the definition of an EGU, we inadvertently failed to include the provision in the proposed rule. Several commenters asked the Agency to include provisions in the final rule that would address situations like the ones described in the preamble to the proposed rule. Because appiicability to the final rule is based in part on the statutory definition of an EGU is CAA section 112(aX8), similar to the situation with units combusting solid waste under CAA section 129(g)(1) (e.g., CISWI Rule), we are adopting provi- sions 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). For example, a cogeneration unit that did not historically provide more than one third of its potential electrical output capacity to a power distribution system could change its output and provide more than 25 megawatts electrical output to any power distribution system for sale. Such units would be subject to MATS. If the cogeneration unit later reduced its output such that it no longer met the definition of an EGU, that source would nevertheless remain subject to MATS for at least 6 months from the date that the unit first qualified as an EGU. 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 526a 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 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. The changes to the definitions described above provide clarity to sources, permitting agencies, and the public about the applicability of the rule and help ensure that sources are appropriately covered by the regulation. B. Subcategories In this final rule, the EPA is adding subcategories for limited-use oil-fired units and non-continental oil- fired units and revising the definitions for the coal- fired EGU subcategories. The proposed rule subcategorized EGUs burning coal into two subcategories: EGUs designed for coal >/=8,300 Btu/lb and EGUs designed for virgin coal /=8,300 Btu/lb subcategory. We were particularly concerned about the CFB units because other CFB units are well represented among the best performing EGUs for Hg in the >/=8,300 Btu/lb subcategory, but the CFB units burning low rank virgin coal are not achieving the same levels of Hg emissions control. Including the best performing CFB units from the other subcategory in the low rank virgin coal subcategory would likely lead to a Hg standard as stringent as the standard for EGUs in the >/=8,300 Btu/lb subcategory because the CFB units from the other subcategory would be used to establish the floor. We believe that result would be inconsistent with the intent of the proposed rule. We were also concerned about the information that some EGUs that fired low 53la rank virgin coal had a height-to-depth ratio of 3.5, not 3.82, and that some EGUs that fired other ranks of coal had a height-to-depth ratio greater than 3.82. For these reasons, we did not revise the definition to include CFB units and PC EGUs with a height-to- depth ratio greater than 3.5. After fully considering the available information, including the comments received, we have concluded that it is appropriate to continue to base the subcategory definitions, at least in part, on whether the EGUs were designed to burn and, in fact, did burn low rank-virgin coal, but that it is not appropriate to continue to use the height-to-depth ratio criteria because that approach would potentially exclude EGUs we identified as having different Hg emission characteristics and include EGUs that did not have different emissions characteristics. We recognize that some commenters have taken the position that it is unlawful to subcategorize based on factors such as fuel type but nothing in the statute prohibits such an approach and the case law supports this approach to the extent courts have considered subcategorization based on such factors. See Sierra Club v. Costle, 657 F 2d 298, 318-19 (D.C. Cir. 1981) (differing pollutant content of input material can justify a different standard based on subcategorization authority to “distinguish among classes, types and sizes within categories of new sources”). Furthermore, we believe had Congress intended to prohibit the EPA from subcategorizing based on an EGU being designed to use and using a certain material input (e.g., fuel) it would have clearly stated such intent in the CAA. However, we believe the Agency could decline to exercise its discretion to subcategorize even if the potential result would be the prohibition of the use of some materials if the circumstances warranted. We 532a note that even if we did not subcategorize on the final basis selected, the Hg emissions standard of 1.2E0 Ib/Tbtu for the “unit designed for coal >/=8,300 Btu/1b” would remain the same. We considered basing the subcategory solely on an EGU being designed to burn and burning low rank virgin coal. We decided not to do so because we were concerned that such a definition would allow sources to potentially meet the definition by combusting very small amounts of low rank virgin coal. For example, an EGU on the east coast (or any other region) that was not designed to burn and did not routinely burn low rank virgin coal could import one truck full of low rank virgin coal and burn a very small quantity of it periodically to meet the subcategory definition. To avoid creating this potential loophole, we considered other characteristics that would distinguish EGUs combusting low rank virgin coal. We determined that these EGUs are universally constructed “at or near” a mine containing low rank virgin coal because it is not cost-effective to transport large quantities of such fuel long distances. Further- more, we believe that this subcategory of EGUs are almost always built at a mine and limited transportation of the coal is only required as the mine face moves over the course of time. Many such EGUs construct dedicated rail lines, private roads, or conveyor systems to transport the coal to the EGU as the mine face moves. We obtained information from data acquired to develop the CSAPR indicating that the longest distance any EGU firing low rank virgin coal transports that coal is 40 miles. We believe that this distance is near the outer limits for the transport of such coal, but, even for those EGUs, the EGUs were constructed closer to a now idle mine or closer to the 533a working face of a mine that has now expanded away from the EGU site. For these reasons, we are including a requirement that the unit be constructed and operated at or near a mine containing the low rank virgin coal it burns. We are revising the coal-fired EGU subcategory definitions as set out in 40 CFR 63.10042. We believe the revised subcategory definitions are reasonable for all the reasons set forth above. The revised definitions maintain the EGUs we identified as having different Hg emissions characteristics in one subcategory and the definitions prevent other EGUs that are not firing low rank virgin coal from being required to comply only with the less stringent Hg emission standard. As discussed in response to comments, we do not believe that additional subcategorization of other coal- fred EGUs is reasonable or appropriate. All other coal-fired EGUs that are not designed to burn and are burning low rank virgin coal are represented among the best performing sources for Hg, such that no ent exists to support that the Hg emissions from those EGUs are different. In any case, even if emissions are somewhat different as some comment- ers suggest, we would decline to exercise our discretion because the data demonstrate that the best performing EGUs designed to burn and burning all other ranks of coal are able to achieve the MACT level of control using currently available controls and other HAP emission reduction mechanisms (e.Z., coal washing) for the >/=8,300 Btu/lb subcategory. A second issue related to subcategorization concerns non-continental liquid oil-fired EGUs. At proposal, the EPA did not have sufficient emissions data from non- 534a continental liquid oil-fired EGUs upon which to base a subcategory and took comment on the issue. The data have since been provided in response to the ICR and we received comments suggesting that a non- continental subcategory is appropriate based on the location of such units, the limited availability of alternative fuel sources, and the fact that the emissions characteristics of such units are distinct from continental liquid oil-fired EGUs. The EPA has evaluated the data and comments and we agree that a subcategory is warranted based for the reasons suggested by the commenters. Therefore, the Agency is finalizing the liquid oil-fired EGU subcategories of “continental” and “non-continental.” Lastly, the EPA did not have sufficient information on limited-use liquid oil-fired EGUs upon which to base a subcategory at proposal because some sources required to test under the ICR did not submit the data until after proposal. We took comment on whether a limited-use subcategory was warranted. Commenters indicated that their units were a different class and type of units because many of them were only called to service to address reliability issues associated with, for example, natural gas curtailments. The commenters further indicated that their units are different because of the generally infrequent use and the sporadic, and at times frequent, start-up and shutdown periods (e.z., they are often only required to run for a couple of hours). These factors would lead to differences in the emissions characteristics for these units such that a numeric standard based on base load units would not likely be achievable during the very limited times that these limited use oil-fired units operate. Based on comments received and our own analysis, we are finalizing a subcategory for limited-use liquid oil-fired 535a EGUs as discussed further elsewhere in this preamble. C. Emission Limits The proposed rule included numerical emission limits for PM, Hg, HCl, HF, SO:2, total HAP metals, and individual HAP metals, depending on the subcategory and specific situation. These proposed limits resulted from calculations of MACT floors using information and data available to the Agency prior to proposal, as required by CAA section 112. Based on information and data received during the comment period, we have made data and calculation corrections where necessary and then re-ranked the best performing units in the MACT floor pools. Based on the new ranking, a limited number of the emission limits in the final rule have changed from those proposed. In addition to adjustments to the emission limits themselves, we are finalizing several] other changes to the emission standards that will simplify and improve compliance for sources without compromising the toxics reductions achieved. One key change, as discussed elsewhere in this notice, is that we have changed the surrogate for non-mercury metallic HAP from total particulate matter (PM) to filterable PM for coal-fired and solid oil-derived EGUs. This change is based on information provided in comments and our own conclusion that measurement of filterable PM provided assurance of equivalent HAP emissions control. Most of the non-mercury metal HAP, for which PM is a surrogate, are filterable PM and the one that is not (Se) is well controlled by the limit on acid gases. Using filterable PM as the surrogate will allow us to use continuous PM monitoring systems, which 536a measure filterable (but not total) PM, thereby providing a more continuous measure of compliance. For liquid oil-fired EGUs, based on comments received and corrections made to the data submitted, we have added a filterable PM limit in the final rule as an alternative equivalent standard for the total metal-HAP limit in the proposed rule. In addition, as discussed elsewhere in this notice, we have added measurement of the moisture content of the oil (with a 1 percent limit) as an alternate compliance assurance measure for liquid oil-fired EGUs for determining compliance with the HCl and HF limits. Direct measurement of HCl] and HF remains a compliance demonstration method in the final rule. Finally, as discussed in section VI.D of this notice, the final work practice standard consisting of burner tune-ups, much like those required for organic HAP control, for those limited-use liquid oil-fired EGUs whose annual capacity factor is less than 8 percent. D. Work Practice Standards for Organic HAP Emissions As noted earlier in section V.D., the final rule includes a work practice standard for organic HAP, including dioxins and furans, applicable to all EGUs. As noted in section V.D. above, the majority of emissions of these pollutants are below the detection levels of EPA test methods and, therefore, are impractical to measure. The work practice standard, described below, is a practical approach to ensuring that equipment is maintained and run so as to minimize emissions of dioxins and furans, and we expect it to be more effective than establishing a numeric standard that cannot reliably be measured or monitored. The work practice also applies to the 537a limited-use liquid oil-fired subcategory included in the final rule. The work practice involves maintaining and inspecting the burners and associated combustion controls (as applicable), tuning the specific burner type to optimize combustion, obtaining and recording CO and NOx values before and after the burner adjustments, keeping records of activity and measurements, and submitting a report for each tune- up conducted. In Table 3 of the final regulation, we have clarified that this refers to performance tune- ups, not tests, and have addressed the frequency requirement as discussed in response to comments about the appropriateness of the 18-month frequency. The provisions of 40 CFR 63.10006(h\i) refer to 40 CFR 63.10021(e) for the specific steps required to be part of the periodic tune-up. We have also adjusted the language in the final rule to recognize the value of automated boiler optimization tools such as neural network systems. Under the final rule, the tune-up must be conducted at each planned major outage and in no event less frequently than every 36 calendar months, with an exception that if the unit employs a neural-network system for combustion optimization during hours of normal unit operation, the required frequency is a minimum of once every 4 years (48 calendar months). Initial compliance with the work practice standard of maintaining burners must occur within 180 days of the compliance date of the rule. The initial compliance demonstration for the work practice standard of conducting a tune-up may occur prior to the compliance date of the rule, but must occur no later than 42 months (36 months plus 180 days) from the compliance date of the rule or, in the case of units 538a employing neural network combustion controls, 54 months (48 months plus 180 days). If the tune-up occurs prior to the compliance date of the rule, you must maintain adequate records to show that the tune-up met the requirements of this standard. We have made a number of specific changes to address what to do for repairs that may require longer term corrective actions, additional methods for evaluating combustion effectiveness, and clarification on procedures for recording CO and NOx information. There were specific comments that opposed the reference to manufacturer specifications, if available. We retained this language in the final rule, but note that these specifications apply only to the extent applicable. Specifically, if manufacturer specifications only address equipment or conditions that are no longer present given current boiler operations, then those specifications are not applicable and other combustion engineering best practice procedures for that burner type would apply. We have also clarified that portable emission monitoring equipment may be used to collect the required emissions optimization data regarding pre- and post-tune-up CO and NOx emission levels. E. Requirements During 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 did propose different standards for startup and shutdown by our inclusion of the default values described below, which applied only during startup and shutdown. Specifi- cally, we stated: 539a 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 O[2] or the corresponding fuel specific CO[2] concentration for calculating emissions in units of Ib/MMBtu or lb/TBtu during startup or shutdown periods. For calculating emissions in units of Jb/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 “urther solicit comment on the proposed approach described above and whether the values we are proposing are appropriate. 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. The default values were meant to account for the fact that during startup and shutdown events, production (in this case the generation of electricity) is by definition nonexist- ent. 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 540a 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 measure- ments obtained from EGUs during such periods. In reaponse to the Agency's ICR to the utility industry, seven owners or operators indicated that they provided startup and shutdown data for their EGUs. These data were submitted in response to the requirement in the ICR to provide all available data from the 5 years prior to the date the ICR was issued. Of these data, there were almost no HAP data for startup and shutdown periods and almost all of the data failed to meet our data quality requirements.*” 312 In response to the ICR, we also received SO, CEMS data and the Agency had additional SO, CEMS data available through the CAMD ARP database. We are not able to identify specific periods of start-up and shutdown in either the ICR CEMS data or the CAMD ARP data, and the ICR respondents do not indicate that the ICR data includes periods of startup and shutdown. We set the emission limits for SO,and HC) using the data provided to the EPA from the 2010 ICR, not the CAMD data, since those data were taken concurrently under the same specified operating conditions using the same fuel. We used the SO,CEMS data that was submitted in response to the ICR by converting it to single point data to correlate to the data from units that did not provide CEMS data from the relevant testing period. The emissions limits for the NESHAP incorporated variability by applying the 99 percent UPL to the average emissions developed from the stack test data and SO, CEMS data that was converted to stack test data. Thus, we did not have data on which to establish an SO, standard during periods of startup and shutdown and the numeric standards do not apply to those periods in the final rule. In contrast, the NSPS for SO, is applicable during periods of startup and shutdown since the long term CAMD ARP CEMS 54la Thus, we do not have sufficient data on emissions that occur during startup and shutdown on which to set emission standards. We are therefore establishing work practice standards rather than numeric emissions standards 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 generally routine, normal operations with production (i.e., generation of electricity) taking place. We maintain that the standards as promulgated account for any variability in emissions that may occur during these periods over a 30-day averaging period, and commenters have provided no data that cause us to doubt that determination. 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 defined startup as the setting in operation of an affected source or portion of an affected source for any purpose, and shutdown as 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 are data were used to determine the average performance of the best demonstrated technology. Those long term data were assumed to incorporate process variability including that associated with fuel and process/operational changes and periods of startup and shutdown. 542a revising the definitions in the final rule as set out in 40 CFR 63.10042. These interpretations are tailored for EGUs and are consistent with the definitions of “startup” and “shut- down” contained in the 40 CFR part 63, subpart A General Provisions. We believe these revised defini- tions address the comments and are rational based on the fact that EGUs function to provide electricity primarily for sale to the grid but also at times for use on-site; therefore, EGUs should be considered to be operating normally at all times electricity is gener- ated. We further believe these revised definitions address what some commenters describe as “warm” and “hot” startups as long as the EGU is shutdown (i.e., no fuel fired and no electricity generation) prior to the “warm” or “hot” startup period. 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 vent emissions to the main stack(s) and operate all control devices necessary to meet the normal operating standards under this final rule (with the exception of dry scrubbers and SCRs) when coal, solid oil-derived fuel, or residual oil is fired in the boiler during startup or shutdown. It is the responsibility of the operators of EGUs to start their dry scrubber and SCR systems appropriately to comply with relevant standards applicable during normal operation. The EPA carefully considered fuels and potential operational constraints of air pollution control devices (APCDs) when designing its work practices for periods of startup and shutdown. The EPA notes that there is no technical barrier to burning natural gas or distillate oil for longer portions of startup or shutdown 543a periods, if needed, at a boiler, and the HAP emission reduction benefits warrant additional utilization of such fuels until the temperature and stack emissions pressure is sufficient to engage the APCDs. The EPA is aware that SCR systems with ammonia injection need to be operated within a prescribed and relatively narrow temperature window to provide NOx reduc- tions. Further, the EPA is aware that dry scrubbers also need to be operated close to flue gas saturation temperature. Because these devices have specific temperature requirements for proper operation, the EPA notes in its work practices that it is the responsibility of the operators of EGUs to start their SCR and dry scrubber systems appropriately to comply with relevant standards applicable during normat operation. Some commenters have asserted that firing of fuel oil during periods of startup and shutdown constrains operation of PM controls (ESPs and baghouses) because under cooler conditions, acids and tars can condense on surfaces in these controls. The comment- ers assert that such condensation can cause detrimental impacts on hardware and operation of these controls, and could cause safety concerns. The EPA understands that concerns with acidic and tarry deposits are related to firing of heavy (residual) oil and hot distillate oil. Accordingly, with residual fuel oil firing, site-specific flue gas temperature and oxygen (O2) concentration thresholds may be applicable to minimize condensation of acids and tars and thereby minimize any potential for detrimental impacts on hardware and any safety concerns. However, the EPA fotes that its work practice requirements provide flexibility to the operator to take appropriate site- specific remedial measures, if needed. The EPA further notes that boilers have several options to 544a prevent detrimental impacts by: (1) Using startup fuels, natural gas or distillate oil, until appropriate flue gas conditions have been reached and then fire residual oil; (2) pre-coating the PM control surfaces*® with an alkaline powder (e.g., limestone); (3) installing chemically resistant bags*™ in baghouses if applicable; and (4) using low-sulfur oils. The EPA also notes that currently the industry has many operational residual oil-fired boilers that are started up with either natural gas or distillate fuel oil. At these boilers, the transition from the startup fuel, distillate oil or natural gas, to residual oil is already being practiced without unac- ceptable impacts on APCDs including PM controls, which are operated to meet applicable opacity limits. Based on this experience and the options described above, those boilers where residual oil is used for either a part of the startup period, or as the main fuel, will also be able to operate their PM controls to meet the work practice requirements of the rule. Note that coal firing is done at high enough temperatures that concerns with condensation are not relevant. None of the commenters have specifically commented on this aspect of coal firing. The EPA is not aware of any operational constraints applicable to operation of wet scrubbers during startup that could cause detrimental impacts on wet scrubber hardware and safety concerns and none of the commenters have commented on this aspect of wet scrubber operation. 313 Coal Power, May 1, 2007: Attp:/ /www.coal powermag.com / plant_design / Coal-Plant-O-and-M-River-Locks-and-Barges-Are- an-Aging-Workforce-Too 36.html. 344 Neundorfer: Lesson #r, p.4-7, Table 4-1: Attp://www. neundorfer.com / FileUploads/CMSFiles/Fabric%20Filter%#20M aterial [0].pdf. 545a Finally, the EPA notes that dry sorbent injection (DSI) can be applied across a very broad temperature range and will be engaged when residual oil or coal is fired in a boiler to comply with HC] requirements. Again, no comments have been received on this aspect of DSI 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 al] times, including periods of startup and shutdown, when continuous monitoring is used to demonstrate compliance. 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. We now address malfunctions. In contrast to the exclusion of startup and shutdown period emissions from 30-boiler operating day rolling average emis- sions, the final rule requires inclusion of emissions during periods of source or APCD malfunction. We have concluded that when combined with the availa- bility of an affirmative defense as described below, this is an appropriate and practical approach. 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 546a 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. 547a 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 !ess 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 we believe it is a reasonable interpretation of the statute. This approach to malfunctions has been used consistently in CAA section 112 and CAA section 129 rulemaking actions since the D.C. Circuit’s decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008) vacated the SSM exemption contained in CFR 63.6(f)(1) and 40 CFR 63.6(h)(1). (See, e.g., National Emission Standards for Hazardous Air Pollutants From the Portland Cement Manufacturing Industry and Standards of Performance for Portland Cement Plants, 75 FR 54970 (September 9, 2010); Standards of Performance for New Stationary Sources and Emission Guidelines for Existing Sources: Sewage Sludge Incineration Units; Final Rule, 76 FR 15372 (March 21, 2011). 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, 548a the good faith efforts of the source to minimize emis- sions during malfunction periods, including preventa- tive 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 preventa- ble” and was not instead “caused in part by poor maintenance or careless operation.” 40 CFR 63.2 (def- inition 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 CFR 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 549a definition of malfunction in 40 CFR 63.2 (i.e., sudden, infrequent, not reasonable preventable and not caused by poor maintenance and or careless operation). For example, to assert the affirmative defense success- fully, the source must prove by a preponderance of the evidence that excess emissions “[w]jere 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 “[rjepairs were made as expeditiously as possible when the applicable emission limitations were being exceeded * * *” and that “[a]Jll 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 22.27). The EPA is including an affirmative defense in the final rule as we have in other recent MACT rules so as to balance the 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. 550a 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 some 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 calls into question 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 (9th Cir. 1977). But see, Weyerhaeuser Co. v. 55la 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 ensure both 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. Testing and Initial Compliance We have carefully evaluated the wide-ranging comments on testing, continuous monitoring, and other provisions regarding initial compliance demon- strations, and we have made adjustments intended to help streamline implementation while still ensuring adequate demonstration of compliance with the emission limits and other standards established under this final rule. The significant changes include: 1. No Fuel Analysis Requirements Apart from an alternative that allows you to analyze fuel moisture for liquid oil-fired EGUs rather than measuring HC! and HF, the final rule does not include any of the fuel analysis requirements that were in the proposed rule, either as part of initial compliance demonstrations or ongoing compliance demonstra- tions. In reviewing the results of the fuel analyses and the expected range of results that would be received from laboratories conducting the proposed analyses, we determined that too many results would be returned as “below detection level” and, thus, provide little information to assist with rule implementation and compliance oversight. Given the costs and efforts involved, we determined that the proposed fuel analysis requirements would not be an effective compliance monitoring tool for this final rule. 552a 2. Clarification of Testing We have clarified that where options for emission limits apply (such as filterable PM versus non- mercury HAP metals, or SO2 versus HCl), you need only perform stack testing to demonstrate compliance with the selected emission limit. For example, if you elect to meet the individual non- mercury HAP metals standards, you must conduct the Method 29 test for the metals, and you do not have to conduct a Method 5 test for PM. 3. Low Emitting EGU Qualification We have significantly modified the proposed requirements to qualify as a LEE unit for a pollutant other than Hg based on an initial performance test. Under the proposed rule, the operating limit monitor- ing provided additiona) assurance of compliance for a source qualified for non-mercury LEE status based on an initial compliance demonstration. Under the final rule, to qualify for LEE status for pollutants other than Hg, a unit must meet the LEE criteria for a series of performance tests over a 3-year period to demonstrate that the unit continues to perform well below the standard for which the source has obtained LEE status. G. Continuous Compliance The most significant changes to the testing and monitoring requirements involve the procedures for demonstrating continuous compliance. The proposed rule contained different options involving CEMS, periodic stack tests, fuel analysis, and various PM and control device operating limits. The final rule greatly simplifies the requirements and provides two basic approaches for most situations: use of continuous 553a monitoring (either CEMS or PM continuous paramet- ric monitoring system, CPMS) or periodic quarterly testing. The final rule does not contain the proposed fuel analysis requirements. For periodic testing, the proposed rule required testing every month or every 2 months. For those EGU owners or operators who choose to use emissions testing to demonstrate compliance, the final rule requires quarterly filterable PM or non-mercury metals HAP, whether individual or total metals, testing for coal- and liquid oil-fired units. The rule requires quarterly HC] testing for coal- fired units and quarterly HC) and HF testing, along with site-specific monitoring for liquid oil-fired units to ensure compliance with the HCl and HF standards. The final rule also has a separate compliance demonstration for those liquid oil-fired EGUs that have an annual capacity factor of less than 8 percent (emission limits do not apply, just the tune-up work practice standard). For those EGU owners or operators who choose to use emissions testing to demonstrate compliance, the final rule requires quarterly filterable PM or non-mercury metals HAP, whether individual or total metals, testing for coal- and liquid oil- fired units; quarterly HC] testing for coal-fired units and quarterly HCl and HF testing, along with site-specific parameter monitoring for liquid oil-fired units to ensure compliance with the HCl and HF standards. The continuous monitoring options remain gener- ally intact from the proposed rule, with relatively minor clarifications concerning calculation of 30-boiler operating day averages and QA requirements. The final rule eliminates all operating limits for PM except for the use of a PM CPMS. For the PM CPMS, the final rule clarifies procedures for setting this 554a operating limit and how it is distinct from the PM emission limit. The PM CPMS will not be correlated as a PM CEMS under PS 11 and will produce data in terms of a signal you define. That signal could be milliamps, stack concentration, or other output signal instead of PM emissions in units of the standard. The operating limit will be set using the highest hourly average obtained from the PM CPMS during the performance test. Compliance with the limit is based on a 30-boiler operating day rolling average basis. However, the final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach. The EPA believes that some sources may be interested in adopting this direct approach, and so has included that option in the final rule. If this approach is selected, the PM CEMS is used as the direct method of compliance and no additional testing is required other than tests that are required as part of the QA requirements in PS 11 and Procedure 2. To use this option, the source must elect to meet the filterable PM standard, and not one of the HAP metals standards. Apart from the operating limit for site-specific monitoring associated with liquid oil-fired EGUs, we removed the other operating limits for control devices based on a review of the comments, after considering other programs in place to ensure proper operations of controls at EGUs. Those other programs include compliance assurance monitoring under part 64, part 70, and New Source Review permit conditions, and other SIP and NSPS requirements for operating and maintaining equipment in accordance with good air pollution control practices. Those requirements, in combination with the CEMS, PM CPMS, and frequent periodic testing provisions under the final rule, will 555a enhance the monitoring of continuous compliance with the requirements of this rule. Because the EPA is concerned that there will be little or no monitoring in these underlying applicable requirements for acid gases at liquid oil-fired EGUs, the final rule requires a site-specific monitoring plan for those units in this subcategory that demonstrate compliance with the HCl and HF standards through quarterly performance tests. With the exception for limited-use liquid oil-fired EGUs and other monitoring options available (such as fuel moisture monitoring or HCVHF CEMS), the EPA believes this provision will apply to few units. The owner or operator will submit the site-specific plan to identify appropriate parameters that ensure that the operations of the unit critical to meeting the HCI/HF emission limits remain consistent with conditions during performance testing. This will be approved similarly to an alterna- tive monitoring request. The plan should include the parameters, monitoring approach, QA/QC elements, and data reduction (including averaging period) elements. Like the PM CPMS operating limit, the operating limit for acid gas control devices on liquid oil-fired EGUs will be set using the highest hourly average obtained during the HC! and HF performance teats. Compliance with the limit is based on a 30-boiler operating day rolling average basis. Finally, we have changed the continuous compliance requirements for the performance tune-up work practice standard since the proposal. Our intent was that this work practice standard could be performed in conjunction with routine maintenance operations at a facility and be a logical extension of routine best practices for boiler inspection and optimization. Based on the comments received, we have reduced the 556a required frequency for this inspection to every 3 years and provided incentives for neural network combus- tion management and optimization practices by providing a longer interval of 4 years between inspections when such systems are in use at a given EGU. H. Emissions Averaging We are finalizing that owners and operators of existing affected sources may demonstrate compliance by emissions averaging for existing EGUs that are located at the same facility that are within a single subcategory and that rely on emissions testing as the compliance demonstration method. In response to our request for comments on the suitability of emissions averaging and need for a discount factor, we received a range of suggestions, including requests for clarification regarding eligibility, points for and against the need for a discount factor, and suggestions to ease implementation. As we noted at proposal, part of the EPA’s general policy of encouraging the use of flexible compliance approaches where they can be properly monitored and enforced is to include emissions averaging. Emissions averaging can provide sources the flexibility to comply in the least costly manner while still maintaining a regulation that is workable and _ enforceable. Emissions averaging would not be applicable to new affected sources and could only be used between EGUs in the same subcategory at a particular facility. Also, owners or operators of existing sources subject to the EGU NSPS (40 CFR part 60, subparts D and Da) would be required to continue to meet the PM emission standard of that NSPS regardless of whether or not they are using emissions averaging (i.e, an EGU subject to 40 CFR part 60, subpart D or Da must meet 557a its applicable NSPS filterable PM emission limit even if it is included in a 40 CFR part 63, subpart UUUUU, emissions averaging group for filterable PM). Emissions averaging allows owners and operators of a facility that includes existing EGUs within a subcategory to demonstrate that the source complies with the proposed emission limits by averaging the emissions from an individual affected EGU that is emitting above the proposed emission limits with other affected EGUs at the same facility that are emitting below the proposed emission limits and that are within the same subcategory. Although some commenters note that the MACT limits are low, based on the data available to the Agency, we believe that dozens of existing EGUs are achieving all of the limits and, thus, emissions averaging is a possible approach. The fina) rule includes an emissions averaging compliance alternative because emissions averaging®*® represents an equivalent, more flexible, and less costly alternative to controlling certain emission points to MACT levels. We have concluded that averaging in the proposed rule could be implemented and that it would not lessen the stringency of the MACT floor limits and would provide flexibility in compliance, cost and energy savings to owners and operators. We also recognize that we must ensure that any emissions averaging option can be implemented and enforced, wi [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/brief%3Amicro_IA40385016_0333%3A03. Public record. Not legal advice.