(f) You are subject to the requirements of this subpart at least 6 months following the last date you met the definition of an EGU subject to this subpart (e.g., 6 months after a cogeneration unit provided more than one third of its potential electrical output capacity and more than 25 megawatts electrical output to any power distributions system for sale). You may opt to remain subject to the provisions of this subpart, unless you combust solid waste in which case you are a solid waste incineration unit subject to standards under CAA section 129 (e.g., 40 CFR Part 60, Subpart CCCC (New Source Performance Standards (NSPS) for Commercial and Industrial Solid Waste Incineration Units, or Subpart DDDD (Emissions Guidelines (EG) for Existing Commercial and Industrial Solid Waste Incineration Units). Notwithstanding the provisions of this subpart, an EGU that starts combusting solid waste is immediately subject to standards under CAA section 129 and the EGU remains subject to those standards until the EGU no longer meets the definition of a solid waste incineration unit consistent with the provisions of the applicable CAA section 129 standards.
(g) If you no longer meet the definition of an EGU subject to this subpart you must be in compliance with any newly applicable standards on the date you are no longer subject to this subpart. The date you are no longer subject to this subpart is a date selected by you, that must be at least 6 months from the date that you last met the definition of an EGU subject to this subpart or the date you begin combusting solid waste, consistent with §63.10000(a)(2). Your source must remain in compliance with this subpart until the date you select to cease complying with this subpart or the date you begin combusting solid waste, whichever is earlier.
(h) If you own or operate an EGU that does not meet the definition of an EGU subject to this subpart, and you commence or recommence operations that cause you to meet the definition of an EGU subject to this subpart, you are subject to the provisions of this subpart as of the first day you meet the definition of an EGU subject to this subpart. You must complete all initial compliance demonstrations for this subpart applicable to your EGU before you commence or recommence operations that cause you to meet the definition of an EGU subject to this subpart.
      You must provide 30 days prior notice of the date you intend to commence or recommence operations that cause you to meet the definition of an EGU subject to this subpart. The notification must identify:
(i) The name of the owner or operator of the EGU, the location of the facility, the unit(s) that will commence or recommence operations that will cause the unit(s) to meet the definition of an EGU subject to this subpart, and the date of the notice;
(ii) The 40 CFR part 60 or part 63 subpart and subcategory currently applicable to your unit(s), and the subcategory of this subpart that will be applicable after you commence or recommence operation that will cause the unit(s) to meet the definition of an EGU subject to this subpart;
(iii) The date on which you became subject to the currently applicable emission limits;
(iv) The date upon which you will commence or recommence operations that will cause your unit to meet the definition of an EGU subject to this subpart, consistent with (2) and (3)) above.
(i) If you own or operate an EGU subject to this subpart, and it has been (or will be) at least 6 months since you operated in a manner that caused you to meet the definition of an EGU subject to this subpart, you may select the date on which your EGU will no longer be subject to this subpart. You must complete all initial compliance demonstrations for any CAA section 112 or 129 standards that are applicable to your facility before you commence compliance with any newly applicable standards.
      You must provide 30 days prior notice of the date your EGU will cease complying with this subpart. The notification must identify:
(i) The name of the owner or operator of the EGU(s), the location of the facility, the EGU(s) that will cease complying with this subpart, and the date of the notice;
(ii) The currently applicable subcategory under this subpart, and any 40 CFR part 60 or part 63 subpart and subcategory that will be applicable after you cease complying with this subpart;
(iii) The date on which you became subject to this subpart;
(iv) The date upon which you will cease complying with this subpart, consistent with (2) and (3)) above.
(j) All air pollution control equipment necessary for compliance with any newly applicable emissions limits which apply as a result of the cessation or commencement or recommencement of operations that cause your EGU to meet the definition of an EGU subject to this subpart must be installed and operational as of the date your source ceases to be or becomes subject to this subpart.
(k) All monitoring systems necessary for compliance with any newly applicable monitoring requirements which apply as a result of the cessation or commencement or recommencement of operations that cause your EGU to meet the definition of an EGU subject to this subpart must be installed and operational as of the date your source ceases to be or becomes subject to this subpart. All calibration and drift checks must be performed as of the date your source ceases to be or becomes subject to this subpart. You must also comply with provisions of §§63.10010, 10020, and 10021 of this subpart. Relative accuracy tests must be performed as of the performance test deadline for PM CEMS. Relative accuracy testing for other CEMS need not be repeated if that testing was previously performed consistent with CAA section 112 monitoring requirements or monitoring requirements under this subpart.
§63.10001  Affirmative Defense for Exceedence of Emission Limit During Malfunction.
In response to an action to enforce the standards set forth in paragraph §63.9991 you may assert an affirmative defense to a claim for civil penalties for exceedances of such standards that are caused by malfunction, as defined at 40 CFR 63.2. Appropriate penalties may be assessed, however, if you fail to meet your burden of proving all of the requirements in the affirmative defense. The affirmative defense shall not be available for claims for injunctive relief.
(a) To establish the affirmative defense in any action to enforce such a limit, you must timely meet the notification requirements in paragraph (b) of this section, and must prove by a preponderance of evidence that:
(1) The excess emissions:
(i) Were 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, and
(ii) Could not have been prevented through careful planning, proper design or better operation and maintenance practices; and
(iii) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and
(iv) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and
(2) Repairs were made as expeditiously as possible when the applicable emission limitations were being exceeded. Off-shift and overtime labor were used, to the extent practicable to make these repairs; and
(3) The frequency, amount and duration of the excess emissions (including any bypass) were minimized to the maximum extent practicable during periods of such emissions; and
(4) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and
(5) All possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment and human health; and
(6) All emissions monitoring and control systems were kept in operation if at all possible, consistent with safety and good air pollution control practices; and
(7) All of the actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs; and
(8) At all times, the affected source was operated in a manner consistent with good practices for minimizing emissions; and
(9) A written root cause analysis has been prepared, the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the excess emissions resulting from the malfunction event at issue. The analysis shall also specify, using best monitoring methods and engineering judgment, the amount of excess emissions that were the result of the malfunction.
(b) Notification. The owner or operator of the affected source experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunction. The owner or operator seeking to assert an affirmative defense shall also submit a written report to the Administrator within 45 days of the initial occurrence of the exceedance of the standard in §63.9991 to demonstrate, with all necessary supporting documentation, that it has met the requirements set forth in paragraph (a) of this section. The owner or operator may seek an extension of this deadline for up to 30 additional days by submitting a written request to the Administrator before the expiration of the 45 day period. Until a request for an extension has been approved by the Administrator, the owner or operator is subject to the requirement to submit such report within 45 days of the initial occurrence of the exceedance.
                  Testing and Initial Compliance Requirements
§63.10005  What are my initial compliance requirements and by what date must I conduct them?
(a) General requirements. For each of your affected EGUs, you must demonstrate initial compliance with each applicable emissions limit in Table 1 or 2 of this subpart through performance testing. Where two emissions limits are specified for a particular pollutant (e.g., a heat input-based limit in lb/MMBtu and an electrical output-based limit in lb/MWh), you may demonstrate compliance with either emission limit. For a particular compliance demonstration, you may be required to conduct one or more of the following activities in conjunction with performance testing:  collection of hourly electrical load data (megawatts); establishment of operating limits according to §63.10011 and Tables 4 and 7 to this subpart; and CMS performance evaluations. In all cases, you must demonstrate initial compliance no later than the applicable date in paragraph (g), (h), or (j) of this section.
(1) To demonstrate initial compliance with an applicable emissions limit in Table 1 or 2 to this subpart using stack testing, the initial performance test generally consists of three runs at specified process operating conditions using approved methods. If you are required to establish operating limits (see paragraph (d) of this section and Table 4 to this subpart), you must collect all applicable parametric data during the performance test period. Also, if you choose to comply with an electrical output-based emission limit, you must collect hourly electrical load data during the test period.
(2) To demonstrate initial compliance using either a CMS that measures HAP concentrations directly (i.e., an Hg or HCl or HF CEMS or a sorbent trap monitoring system) or an SO2 CEMS, you must conduct an initial performance test consisting of 30 operating days of valid data collected with the certified monitoring system.
(i) The 30 operating day CMS performance test must demonstrate compliance with the applicable Hg, HCl, HF, or SO2 emissions limit in Table 1 or 2 to this subpart.
(iii) If you choose to comply with an electrical output-based emission limit, you must collect hourly electrical load data during the performance test period.
(b) Performance Testing Requirements. If you choose to use performance testing to demonstrate initial compliance with the applicable emissions limits in Tables 1 and 2 to this subpart for your EGUs, you must conduct the tests according to §63.10007 and Table 5 to this subpart. For the purposes of the initial compliance demonstration, you may use test data and results from a performance test conducted prior to the date on which your compliance clock starts (as specified in §63.9984), provided that the following conditions are fully met:
(1) For a performance test based on stack test data, the test was conducted no more than 12 months prior to the date on which your compliance clock starts;
(2) For a performance test based on data from a certified CEMS or sorbent trap monitoring system, the test consists of all valid data CMS data recorded in the 30 boiler operating days immediately preceding that date;
(3) The performance test was conducted in accordance with all applicable requirements in §63.10007 and Table 5 to this subpart;
(4) A record of all parameters needed to convert pollutant concentrations to units of the emission standard (e.g., stack flow rate, diluent gas concentrations, hourly electrical loads) is available for the entire performance test period; and
(5) For each performance test based on stack test data, you certify, and keep documentation demonstrating, that the EGU configuration, control devices, and fuel(s) have remained consistent with conditions since the prior performance test was conducted.
(c) Operating Limits. In accordance with §63.10010 and Table 4 to this subpart, you may be required to establish operating limits using PM CPMS as part of your initial compliance demonstration.
(d) CMS Requirements. If, for a particular pollutant or surrogate, you are required to (or elect to) demonstrate initial compliance using a continuous monitoring system, the CMS must pass a performance evaluation prior to the initial compliance demonstration. If a CMS has been previously certified under another State or Federal program and is continuing to meet the on-going quality-assurance (QA) requirements of that program, then, provided that the certification and QA provisions of that program meet the applicable requirements of §§63.10010(b) through (h), an additional performance evaluation of the CMS is not required under this subpart.
(1) For an affected coal-fired, solid oil-derived fuel-fired, or liquid oil-fired EGU, you may demonstrate initial compliance with the applicable SO2, HCl, or HF emissions limit in Table 1 or 2 of this subpart through use of an SO2, HCl, or HF CEMS installed and operated in accordance with Appendix B to this rule. Initial compliance is achieved if the arithmetic average of 30 operating days of quality-assured CEMS data, expressed in units of the standard (see §63.10007(e)), meets the applicable SO2, HCl, or HF emissions limit in Table 1 or 2 to this subpart. Use Equation 19-19 of Method 19 in appendix A-7 to part 60 of this chapter to calculate the 30 operating day average emissions rate. (Note: for this calculation, the term Ehj in Equation 19-19 must be in the same units of measure as the applicable HCl or HF emission limit in Table 1 or 2 to this subpart).
(2) For affected coal-fired or solid oil-derived fuel-fired EGUs that demonstrate compliance with the applicable emission limits for total non-mercury HAP metals, individual non-mercury HAP metals, total HAP metals, individual HAP metals, or filterable PM listed in Table 1 or 2 to this subpart using initial performance testing and continuous monitoring with PM CPMS:
(i) You must demonstrate initial compliance no later than the applicable date specified in paragraph (g), (h), or (j) of this section.
 (ii) You must demonstrate continuous compliance with the PM CPMS site-specific operating limit that corresponding to the results of the performance test demonstrating compliance with the pollutant with which you choose to comply.
 (iii) You must repeat the performance test annually for the selected pollutant emissions limit and reassess and adjust the site-specific operating limit in accordance with the results of the performance test.
(4) For affected EGUs that are either required to or elect to demonstrate initial compliance with the applicable Hg emission limit in Table 1 or 2 of this subpart using Hg CEMS or sorbent trap monitoring systems, initial compliance must be demonstrated no later than the applicable date specified in paragraph (g), (h), or (j) of this section. Initial compliance is achieved if the arithmetic average of 30 operating days of quality-assured CEMS (or sorbent trap monitoring system) data, expressed in units of the standard (see section 6.2 of appendix A to this subpart), meets the applicable Hg emission limit in Table 1 or 2 to this subpart.
(f) Tune-ups. All affected EGUs are subject to the work practice standards in Table 3 of this subpart. As part of your initial compliance demonstration, you must conduct a performance tune-up of your EGU according to §63.10021(e).
(g) For existing affected sources a tune-up may occur prior to the effective date, so that existing sources have up to 42 months (3 years from promulgation plus 180 days) after the date that is specified for your source in §63.9984 and according to the applicable provisions in §63.7(a)(2) as cited in Table 9 to this subpart to demonstrate compliance with this requirement. If a tune-up occurs prior to the effective date, the source must maintain adequate records to show that the tune-up met the requirements of this standard.
 (h) If your new or reconstructed affected source commenced construction or reconstruction between May 3, 2011, and July 2, 2011, you must demonstrate initial compliance with either the proposed emission limits or the promulgated emission limits no later than 180 days after [INSERT DATE 60 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER] or within 180 days after startup of the source, whichever is later, according to §63.7(a)(2)(ix).
(i) For the new or reconstructed affected source described in paragraph (h) of this section, if you choose to comply with the proposed emission limits when demonstrating initial compliance, you must conduct a second compliance demonstration for the promulgated emission limits within 3 years after [INSERT DATE 60 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER] or within 3 years after startup of the affected source, whichever is later.
(j) If your new or reconstructed affected source commences construction or reconstruction after [INSERT DATE 60 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER], you must demonstrate initial compliance with the promulgated emission limits no later than 180 days after startup of the source.
(k) Low emitting EGUs. The provisions of this paragraph (k) apply to pollutants with emissions limits except Hg from new EGUs and to all pollutants with emissions limits from existing EGUs. You may not pursue this compliance option if your existing EGU is equipped with an acid gas scrubber and has a main stack and bypass stack exhaust configuration.
(1) An EGU may qualify for low emitting EGU (LEE) status for Hg, HCl, HF, total non-Hg HAP metals, or individual non-Hg HAP metals if you collect initial performance test data that meet the requirements of this paragraph (k) and (if applicable) paragraph (l) of this section, and if those data demonstrate:
(i) For all pollutants except Hg, average emissions less than 50 percent of the applicable emissions limit in Table 1 or 2 to this subpart; or
(ii) For Hg emissions from an existing EGU, either:
(A) Average emissions less than 10 percent of the applicable Hg emissions limit in Table 2 to this subpart (expressed either in units of lb/TBtu or lb/GWh); or
(B) Potential Hg mass emissions of 22.0 or fewer pounds per year and compliance with the applicable Hg emission limit in Table 2 to this subpart (expressed either in units of lb/TBtu or lb/GWh).
(2) For all pollutants except Hg, you must conduct the initial performance tests described in §63.10007 to demonstrate that a unit qualifies for LEE status, except that the required minimum sampling volume must be increased nominally by a factor of two. Follow the instructions in §63.10007(e) and Table 5 to this subpart to convert the test data to the units of the applicable standard.
(3) For Hg, you must conduct a 30 operating day performance test using Method 30B in appendix A-8 to part 60 of this chapter to determine whether a unit qualifies for LEE status. Locate the Method 30B sampling probe tip at a point within the 10 percent centroidal area of the duct at a location that meets Method 1 in appendix A-1 to part 60 of this chapter and conduct at least three nominally equal length test runs over the 30 operating day test period. Collect Hg emissions data continuously over the entire test period (except when changing sorbent traps or performing required reference method QA procedures), under all process operating conditions. You may use a pair of sorbent traps to sample the stack gas for no more than 10 days.
(i) Depending on whether you intend to assess LEE status for Hg in terms of the lb/TBtu or lb/GWh emission limit in Table 2 to this subpart or in terms of the annual Hg mass emissions limit of 22.0 lb/year, you will have to collect some or all of the following data during the 30 day test period (see paragraph (k)(3)(iii) of this section):
(A) Diluent gas (CO2 or O2) data, using either Method 3A in appendix A-3 to part 60 of this chapter or a diluent gas monitor that has been certified according to part 75 of this chapter.
(B) Stack gas flow rate data, using either Method 2, 2F, or 2G in appendices A-1 and A-2 to part 60 of this chapter, or a flow rate monitor that has been certified according to part 75 of this chapter.
(C) Stack gas moisture content data, using either Method 4 in appendix A-1 to part 60 of this chapter, or a moisture monitoring system that has been certified according to part 75 of this chapter. Alternatively, an appropriate fuel-specific default moisture value from §75.11(b) of this chapter may be used in the calculations or you may petition the Administrator under §75.66 of this chapter for use of a default moisture value for non-coal-fired units.
(D) Hourly electrical load data (megawatts), from facility records.
(ii) If you use CEMS to measure CO2 (or O2) concentration, and/or flow rate, and/or moisture, record hourly average values of each parameter throughout the 30 operating day test period. If you opt to use EPA reference methods rather than CEMS for any parameter, you must perform at least one representative test run on each operating day of the test period, using the applicable reference method.
(iii) Calculate the average Hg concentration, in ug/m3 (dry basis), for the 30 operating day performance test, as the arithmetic average of all Method 30B sorbent trap results. Also calculate, as applicable, the average values of CO2 or O2 concentration, stack gas flow rate, stack gas moisture content, and electrical load for the test period. Then:
(A) To express the test results in units of lb/TBtu, follow the procedures in §63.10007(e). Use the average Hg concentration and diluent gas values in the calculations.
(B) To express the test results in units of lb/GWh, use Equations A-3 and A-4 in section 6.2.2 of appendix A to this subpart, replacing the hourly values "Ch", "Qh", "Bws" and "(MW)h" with the average values of these parameters from the performance test and replacing the hourly value of "th" with the number of hours in the performance test.
(C) To calculate pounds of Hg per year, use one of the following methods:
(1) Multiply the average lb/TBtu Hg emission rate (determined according to paragraph (k)(3)(iii)(A) of this section) by the maximum potential annual heat input to the unit (TBtu), which is equal to the maximum rated unit heat input (TBtu/hr) times 8,760 hours. If the maximum rated heat input value is expressed in units of MMBtu/hr, multiply it by 106 to convert it to TBtu/hr; or
(2) Multiply the average lb/GWh Hg emission rate (determined according to paragraph (k)(3)(iii)(B) of this section) by the maximum potential annual electricity generation (GWh), which is equal to the maximum rated electrical output of the unit (GW) times 8,760 hours. If the maximum rated electrical output value is expressed in units of MW, multiply it by 103 to convert it to GW; or
(3) If an EGU has a Federally-enforceable permit limit on either the annual heat input or the number of annual operating hours, you may modify the calculations in paragraph (k)(3)(iii)(C)(1) of this section by replacing the maximum potential annual heat input or 8,760 unit operating hours with the permit limit on annual heat input or operating hours (as applicable).
(4) For a group of affected units that vent to a common stack, you may either assess LEE status for the units individually by performing a separate emission test of each unit in the duct leading from the unit to the common stack, or you may perform a single emission test in the common stack. If you choose the common stack testing option, the units in the configuration qualify for LEE status if:
(i) The average emission rate measured at the common stack is less than 50 percent (10 percent for Hg) of the applicable Hg emission limit in Table 1 or 2 to this subpart; or
(ii) For Hg from an existing EGU, the applicable Hg emission limit in Table 2 to this subpart is met and the potential annual mass emissions, calculated according to paragraph (k)(3)(iii) of this section (with some modifications), are less than or equal to 22.0 pounds times the number of units sharing the common stack. Base your calculations on the combined heat input capacity of all units sharing the stack (i.e., either the combined maximum rated value or, if applicable, a lower combined value restricted by permit conditions or operating hours).
(5) For an affected unit with a multiple stack or duct configuration in which the exhaust stacks or ducts are downstream of all emission control devices, you must perform a separate emission test in each stack or duct. The unit qualifies for LEE status if:
(i) The average emission rate, based on all test runs performed at all of the stacks or ducts, is less than 50 percent (10 percent for Hg) of the applicable emission limit in Table 1 or 2 to this subpart; or
(ii) -For Hg from an existing EGU, the applicable Hg emission limit in Table 2 to this subpart is met and the potential annual mass emissions, calculated according to paragraph (k)(3)(iii) of this section, are less than or equal to 22.0 pounds. Use the average Hg emission rate from paragraph (k)(6)(i) of this section in your calculations.
(1) If your EGU combusts liquid fuels, if your fuel moisture content is no greater than 1.0 percent, and if you would like to demonstrate initial and ongoing compliance with HCl and HF emissions limits, you must
       (A) Measuring fuel moisture content of each shipment of fuel if your fuel arrives on a batch basis;
       (B) Measuring fuel moisture content daily if your fuel arrives on a continuous basis; or
       (C) Obtaining and maintaining a fuel moisture certification from your fuel supplier.
       (2) Should the moisture in your liquid fuel be more than 1.0 percent, you must
       (A) Conduct HCl and HF emissions testing quarterly and monitor acid gas control device parameters continuously or
       (B) Use an HCl CEMS and/or HF CEMS.

(m) Startup and Shutdown for coal-fired or solid oil derived-fired untis. You must follow the requirements given in Table 3.
(m) You must submit a Notification of Compliance Status summarizing the results of your initial compliance demonstration, as provided in §63.10030.
§63.10006  When must I conduct subsequent performance tests or tune-ups?
(a) For solid oil-derived fuel- and coal-fired EGUs using PM CPMS as the compliance method for either the total non-Hg HAP metals emissions limit or the individual non-Hg HAP metals emissions limits, you must conduct all applicable performance tests according to Table 5 and §63.10007 at least every year.
(b) For affected units meeting the LEE requirements of §63.1005(k), you must repeat the performance test once every 3 years according to Table 5 and §63.10007. Should subsequent emissions testing results show the unit does not meet the LEE eligibility requirements, LEE status is lost. If this should occur:
(i) For all pollutants or surrogates except for Hg, you must initiate periodic emissions testing every three months.
(ii) For Hg, you must install, certify, maintain, and operate a Hg CEMS or a sorbent trap monitoring system in accordance with appendix A to this subpart, within six months of losing LEE eligibility. Until the Hg CEMS or sorbent trap monitoring system is installed, certified, and operating, you must conduct Hg emissions testing every three months.
(c) For liquid oil-fired EGUs, you must conduct all applicable performance tests for individual or total non-Hg HAP metals emissions according to Table 5 and §63.10007 at least every three months.
(d) For solid oil-derived fuel- and coal-fired EGUs without SO2 CEMS used as the compliance method for HCl or without installed systems that use wet or dry flue gas desulfurization technology, you must conduct all applicable performance tests HCl emissions according to Table 5 and §63.10007 at least every 3 months.
(e) For solid oil-derived fuel- and coal-fired EGUs without HCl CEMS you must conduct all applicable performance tests for HCl emissions according to Table 5 and §63.10007 at least every three months.
(f) For liquid oil-fired EGUs without HCl CEMS, HF CEMS, or HCl and HF CEMS, you must conduct all applicable performance tests for HCl, HF, or HCl and HF emissions according to Table 5 and §63.10007 at least every three months.
(g) Unless you follow the requirements listed in paragraphs (h) through (j) of this section, performance tests required at least every 5 years must be completed within 58 to 62 months after the previous performance test; performance tests required at least every 3 years must be completed within 35 to 37 months after the previous performance test; performance tests required at least every year must be completed no more than 13 months after the previous performance test; and performance tests required at least every 3 months must be completed between 83 and 99 days after the previous performance test.
(h)If you elect to demonstrate compliance using emission averaging under §63.10009, you must continue to conduct performance stack tests at the appropriate frequency given in section (c) through (f) of this paragraph.
(i) If a performance test on a non-Hg LEE shows emissions in excess of 50 percent of the emission limit, you must conduct performance tests at the appropriate frequency given in section (c) through (f) of this paragraph for that pollutant until all performance tests over a consecutive 3-year period show compliance.
(j) If you are required to meet an applicable tune-up work practice standard, you must conduct a performance tune-up according to §63.10021(e).
(1) For EGUs not employing neural network combustion optimization during normal operation, each performance tune-up specified in §63.10021(e) must be no more than 36 months after the previous performance tune-up.
(2) For EGUs employing neural network combustion optimization systems during normal operation, each performance tune-up specified in §63.10021(e) must be no more than 48 months after the previous performance tune-up.
(k) You must report the results of performance tests and performance tune-ups within 60 days after the completion of the performance tests and performance tune-ups. The reports for all subsequent performance tests must include all applicable information required in §63.10031.
§63.10007  What methods and other procedures must I use for the performance tests?
(a) Except as otherwise provided in this section, you must conduct all required performance tests according to §63.7(d), (e), (f), and (h). You must also develop a site-specific test plan according to the requirements in §63.7(c).
(b) You must conduct each performance test (including traditional 3-run stack tests, 30 operating day tests based on CEMS data (or sorbent trap monitoring system data), and 30 operating day Hg emission tests for LEE qualification) according to the requirements in Table 5 to this subpart.
(c) You must conduct performance tests under normal operating conditions. If you choose to comply with the filterable PM emission limit and demonstrate continuous compliance using a PM CPMS, you must also establish an operating limit according to §63.10011(b)(5) and Tables 4 and 6 to this subpart. Should you desire to have operating limits that correspond to loads other than normal operating load, you must conduct testing at those other loads to determine the additional operating limits.
(d) Except for a 30 boiler operating day performance test based on CEMS (or sorbent trap monitoring system) data, where the concept of test runs does not apply, you must conduct a minimum of three separate test runs for each performance test, as specified in §63.7(e)(3). Each test run must comply with the minimum applicable sampling time or volume specified in Table 1 or 2 to this subpart. Sections 63.10005(d), (e) and (k), respectively, provide special instructions for conducting performance tests based on CEMS, sorbent trap monitoring systems, and for conducting emission tests for LEE qualification.
(e) To use the results of performance testing to determine compliance with the applicable emission limits in Table 1 or 2 to this subpart, proceed as follows:
(1) If the limits are expressed in lb/MMBtu or lb/TBtu, you must use the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA Method 19 in appendix A-7 to part 60 of this chapter. In cases where an appropriate F-factor is not listed in Table 19-2 of Method 19, you may use F-factors from Table 1 in section 3.3.5 of appendix F to part 75 of this chapter, or F-factors derived using the procedures in section 3.3.6 of appendix to part 75 of this chapter. Use the following factors to convert the pollutant concentrations measured during the initial performance tests to units of lb/scf, for use in the applicable Method 19 equations:
(i) Multiply SO2 ppm by 1.660 x 10[-7];
(ii) Multiply HCl and HAP metals concentrations (mg/dscm) by 6.24 x 10[-8]; and
(iii) Multiply Hg concentrations (ug/scm) by 6.24 x 10[-11].
(2) To determine compliance with emission limits expressed in lb/MWh or lb/GWh, you must first calculate the pollutant mass emission rate, in units of lb/hr, using an equation that has the general form of Equation A-2 or A-3 in appendix A to this subpart (as applicable), replacing the value of K with 1.66 x 10[-7] lb/scf-ppm for SO2 or 9.43 x 10-8 lb/scf-ppm for HCl, and defining Ch as the hourly average SO2 or HCl concentration in ppm. This calculation requires stack gas volumetric flow rate and (in some cases) moisture content data (see §§63.10005(k)(3)(i) and 63.10010). Then, use Equation A-4 in appendix A to this subpart to calculate the pollutant emission rate in lb/GWh. To express the applicable emissions limit in units of lb/MWh, divide the result from Equation A-4 by 10[3].
(f) Upon request, you shall make available to the EPA Administrator such records as may be necessary to determine whether the performance tests have been done according to the requirements of this section.
§63.10009  May I use emission averaging to comply with this subpart?
(a) As an alternative to meeting the requirements of §63.9991 for PM, HF, HCl, non-Hg HAP metals, or Hg on an EGU-specific basis, if you have more than one existing EGU in the same subcategory located at one or more contiguous properties, belonging to a single major industrial grouping, which are under common control of the same person (or persons under common control), you may demonstrate compliance by emission averaging among the existing EGUs in the same subcategory, if your averaged emissions for such EGUs are equal to or less than the applicable emission limit, according to the procedures in this section.
(b) Separate stack requirements. For a group of two or more existing EGUs in the same subcategory that each vent to a separate stack, you may average PM, HF, HCl, non-Hg HAP metals, or Hg emissions to demonstrate compliance with the limits in Table 2 to this subpart if you satisfy the requirements in paragraphs (c), (d), (e), (f), and (g) of this section.
(c) For each existing EGU in the averaging group, the emission rate achieved during the initial compliance test for the HAP being averaged must not exceed the emission level that was being achieved on [INSERT DATE 30 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER] or the control technology employed during the initial compliance test must not be less effective for the HAP being averaged than the control technology employed on [INSERT DATE 30 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER].
(d) The averaged emissions rate from the existing EGUs participating in the emissions averaging option must be in compliance with the limits in Table 2 to this subpart at all times following the compliance date specified in §63.9984.
(e) You must demonstrate initial compliance according to paragraph (e)(1) or (2) of this section using the maximum normal operating load of each EGU and the results of the initial performance tests.
(1) You must use Equation 1 of this section to demonstrate that the PM, HF, SO2, HCl, non-Hg HAP metals, or Hg emissions from all existing units participating in the emissions averaging option do not exceed the emission limits in Table 2 to this subpart.

Ave Weighted Emissions= i=1nErxHm/i=1nHm                               (Eq.1)
Where:
Ave Weighted Emissions = Average weighted emissions for PM, HF, SO2, HCl, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Er = Emissions rate (as determined during the most recent performance test, according to Table 5 to this subpart) for PM, HF, HCl, non-Hg HAP metals, or Hg for unit, i, for PM, HF, SO2, HCl, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Hm = Maximum rated heat input capacity of unit, i, in units of million Btu per hour.
n = Number of units participating in the emissions averaging option.

(2) If you are not capable of monitoring heat input, and the EGU generates steam for purposes other than generating electricity, you may use Equation 2 of this section as an alternative to using Equation 1 of this section to demonstrate that the PM, HF, HCl, non-Hg HAP metals, and Hg emissions from all existing units participating in the emissions averaging option do not exceed the emission limits in Table 2 to this subpart.
Ave Weighted Emissions= i=1n(ErxSmxCfi)/i=1nSmxCfi         (Eq.2)
Where:
Ave Weighted Emissions = Average weighted emission level for PM, HF, HCl, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Er = Emissions rate (as determined during the most recent performance test, according to Table 5 to this subpart) for PM, HF, HCl, non-Hg HAP metals, or Hg for unit, i, for PM, HCl, HF, HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Sm = Maximum steam generation by unit, i, in units of pounds.
Cf = Conversion factor, calculated from the most recent compliance test, in units of million Btu of heat input per pounds of steam generated for unit, i.
n = Number of units participating in the emissions averaging option.

(f) You must demonstrate compliance on a quarterly basis determined at the end of every three months (4 times per year) according to paragraphs (f)(1) through (3) of this section. The first quarterly period begins on the compliance date specified in §63.9984.
(1) For each quarter, you must use Equation 3 of this section to calculate the quarterly average weighted emission rate using the actual heat capacity for each existing unit participating in the emissions averaging option.

Ave Weighted Emissions= i=1n(ErxHb)/i=1nHb                      (Eq.3)
Where:
Ave Weighted Emissions = Quarterly average weighted emission level for PM, HCl, HF, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Er = Emissions rate, (as determined during the most recent performance test, according to Table 5 to this subpart) for PM, HCl, HF, non-Hg HAP metals, or Hg for unit, i, for PM, HCl, HF, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Hb = The average heat input for each calendar month of EGU, i, in units of million Btu.
n = Number of units participating in the emissions averaging option.

(2) If you are not capable of monitoring heat input, you may use Equation 4 of this section as an alternative to using Equation 3 of this section to calculate the monthly weighted emission rate using the actual steam generation from the units participating in the emissions averaging option.
Ave Weighted Emissions=i=1n(ErxSaxCfi)/i=1nSaxCfi     (Eq.4)
Where:
Ave Weighted Emissions = Monthly average weighted emission level for PM, HCl, HF, HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Er = Emissions rate, (as determined during the most recent performance test, as calculated according to Table 5 to this subpart) for PM, HCl, HF, non-Hg HAP metals, or Hg for unit, i, for PM, HCl, HF, non-Hg HAP metals, or Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat input.
Sa = Actual steam generation for each calendar month by EGU, i, in units of pounds.
Cf = Conversion factor, as calculated during the most recent compliance test, in units of million Btu of heat input per pounds of steam generated for unit, i.
n = Number of units participating in the emissions averaging option.

(3) Until 4 quarterly weighted average emission rates have been accumulated, calculate and report only the quarterly average weighted emission rate determined under paragraph (f)(1) or (2) of this section. After 4 quarterly weighted average emission rates have been accumulated, for each subsequent calendar month, use Equation 5 of this section to calculate the 12-month rolling average of the quarterly weighted average emission rates for the current quarter and the previous 3 quarters.
                Eavg= i=1nERi/4                         (Eq.5)
Where:
Eavg = 12-month rolling average emissions rate, (lb/MMBtu heat input; lb/TBtu for Hg).
ERi = Quarterly weighted average, for month "i" (lb/MMBtu (lb/TBtu for Hg) heat input)(as calculated by (f)(1) or (2)).

(g) You must develop, and submit to the applicable regulatory authority for review and approval upon request, an implementation plan for emission averaging according to the following procedures and requirements in paragraphs (g)(1) through (4) of this section.
(1) You must submit the implementation plan no later than 180 days before the date that the facility intends to demonstrate compliance using the emission averaging option.
(2) You must include the information contained in paragraphs (g)(2)(i) through (vii) of this section in your implementation plan for all emission sources included in an emissions average:
(i) The identification of all existing EGUs in the averaging group, including for each either the applicable HAP emission level or the control technology installed as of [INSERT DATE 60 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER] and the date on which you are requesting emission averaging to commence;
(ii) The process parameter (heat input or steam generated) that will be monitored for each averaging group;
(iii) The specific control technology or pollution prevention measure to be used for each emission EGU in the averaging group and the date of its installation or application. If the pollution prevention measure reduces or eliminates emissions from multiple EGUs, the owner or operator must identify each EGU;
(iv) The test plan for the measurement of PM, HF, HCl, individual or total non-Hg HAP metals, or Hg emissions in accordance with the requirements in §63.10007; and
(v) A demonstration that compliance with each of the applicable emission limit(s) will be achieved under representative operating conditions.
(3) The regulatory authority shall review and approve or disapprove the plan according to the following criteria:
(i) Whether the content of the plan includes all of the information specified in paragraph (g)(2) of this section; and
(ii) Whether the plan presents sufficient information to determine that compliance will be achieved and maintained.
(4) The applicable regulatory authority shall not approve an emission averaging implementation plan containing any of the following provisions:
(i) Any averaging between emissions of differing pollutants or between differing sources; or
(ii) The inclusion of any emission source other than an existing unit in the same subcategory.
(h) Common stack requirements. For a group of two or more existing affected units, each of which vents through a single common stack, you may average PM, HF, HCl, individual or total non-Hg HAP metals, or Hg emissions to demonstrate compliance with the limits in Table 2 to this subpart if you satisfy the requirements in paragraph (i) or (j) of this section.
(i) For a group of two or more existing units in the same subcategory, each of which vents through a common emissions control system to a common stack, that does not receive emissions from units in other subcategories or categories, you may treat such averaging group as a single existing unit for purposes of this subpart and comply with the requirements of this subpart as if the group were a single unit.
(j) For all other groups of units subject to paragraph (h) of this section, the owner or operator may elect to:
(1) Conduct performance tests according to procedures specified in §63.10007 in the common stack if affected units from other subcategories vent to the common stack. The emission limits that the group must comply with are determined by the use of equation 6.

            En= i=1n(ELixHi)/i=1nHi                       (Eq.6)
Where:
En = HAP emissions limit, lb/MMBtu (lb/TBtu for Hg), ppm, or ng/dscm.
ELi = Appropriate emissions limit from Table 2 to this subpart for unit i, in units of lb/MMBtu (lb/TBtu for Hg), ppm, or ng/dscm.
Hi = Heat input from unit i, MMBtu.
n = Number of units.

(2) Conduct performance tests according to procedures specified in §63.10007 in the common stack. If affected units from nonaffected units vent to the common stack, the nonaffected units must be shut down or vented to a different stack during the performance test or each affected and each nonaffected unit must meet the most stringent emissions limit; and
(3) Meet the applicable operating limit specified in §63.10021 and Table 4 to this subpart for each emissions control system (except that, if each unit venting to the common stack has an applicable opacity operating limit, then a single continuous opacity monitoring system may be located in the common stack instead of in each duct to the common stack).
(k) Combination requirements. The common stack of a group of two or more existing EGUs in the same subcategory subject to paragraph (h) of this section may be treated as a single stack for purposes of paragraph (b) of this section and included in an emissions averaging group subject to paragraph (b) of this section.
§63.10010  What are my monitoring, installation, operation, and maintenance requirements?
(a) Flue gases from the affected units under this subpart exhaust to the atmosphere through a variety of different configurations, including but not limited to individual stacks, common stack configuration or a main stack plus a bypass stack. For the CEMS, PM CPMS, and sorbent trap monitoring systems used to provide data under this subpart, the continuous monitoring system installation requirements for these exhaust configurations are as follows:
(1) Single Unit-Single Stack Configurations. For an affected unit that exhausts to the atmosphere through a single, dedicated stack, you shall either install the required CEMS, PM CPMS, and sorbent trap monitoring systems in the stack or at a location in the ductwork downstream of all emissions control devices, where the pollutant and diluents concentrations are representative of the emissions that exit to the atmosphere.
(2) Unit Utilizing Common Stack with Other Affected Unit(s). When an affected unit utilizes a common stack with one or more other affected units, but no non-affected units, you shall either:
(i) Install the required CEMS, PM CPMS, and sorbent trap monitoring systems in the duct leading to the common stack from each unit; or
(ii) Install the required CEMS, PM CPMS, and sorbent trap monitoring systems in the common stack.
(3) Unit(s) Utilizing Common Stack with Non-affected Unit(s). When one or more affected units shares a common stack with one or more non-affected units, you shall either:
(i) Install the required CEMS, PM CPMS, and sorbent trap monitoring systems in the ducts leading to the common stack from each affected unit; or
(ii) Install the required CEMS, PM CPMS, and sorbent trap monitoring systems described in this section in the common stack and attribute all of the emissions measured at the common stack to the affected unit(s).
(iii) If you choose the common stack monitoring option:
(A) For each hour in which valid data are obtained for all parameters, you must calculate the pollutant emission rate and
(B) You must assign the calculated pollutant emission rate to each unit that shares the common stack.
(4) Unit with a Main Stack and a Bypass Stack. If the exhaust configuration of an affected unit consists of a main stack and a bypass stack, you shall install CEMS on both the main stack and the bypass stack, or, if it is not feasible to certify and quality-assure the data from a monitoring system on the bypass stack, you shall install a CEMS only on the main stack and count bypass hours of deviation from the monitoring requirements.
(5) Unit with a Common Control Device with Multiple Stack or Duct Configuration. If the flue gases from an affected unit configured such that emissions are controlled with a common control device or series of control devices that are discharged to the atmosphere through more than one stack or are fed into a single stack through two or more ducts, you may:
(i) Install required CEMS, PM CPMS, and sorbent trap monitoring systems in each of the multiple stacks;
(ii) Install required CEMS, PM CPMS, and sorbent trap monitoring systems in each of the ducts that feed into the stack;
(iii) Install required CEMS, PM CPMS, and sorbent trap monitoring systems in one of the multiple stacks or ducts and monitor the flows and dilution rates in all multiple stacks or ducts in order to determine total exhaust gas flow rate and pollutant mass emissions rate in accordance with the applicable limit; or
(iv) In the case of multiple duct feeding into a single stack, install CEMS, PM CPMS, and sorbent trap monitoring systems in the single stack as described in paragraph (a)(1) of this section.
(6) Unit with Multiple Parallel Control Devices with Multiple Stacks. If the flue gases from an affected unit configured such that emissions are controlled with multiple parallel control devices or multiple series of control devices that are discharged to the atmosphere through more than one stack, you shall install the required CEMS, PM CPMS, and sorbent trap monitoring systems described in each of the multiple stacks. You shall calculate hourly flow-weighted average pollutant emission rates for the unit as follows:
(i) Calculate the pollutant emission rate at each stack or duct for each hour in which valid data are obtained for all parameters;
(ii) Multiply each calculated hourly pollutant emission rate at each stack or duct by the corresponding hourly stack gas flow rate at that stack or duct;
(iii) Sum the products determined under paragraph (a)(5)(iii)(B) of this section; and
(iv) Divide the result obtained in paragraph (a)(5)(iii)(c) of this section by the total hourly stack gas flow rate for the unit, summed across all of the stacks or ducts.
(b) If you use an oxygen (O2) or carbon dioxide (CO2) CEMS to convert measured pollutant concentrations to units of the applicable emissions limit, the O2 or CO2 concentrations shall be monitored at a location that represents emissions to the atmosphere, i.e., at the outlet of the EGU, downstream of all emission control devices. You must install, certify, maintain, and operate the CEMS according to part 75 of this chapter. Use only quality-assured O2 or CO2 data in the emissions calculations; do not use part 75 substitute data values.
(c) If you are required to use a stack gas flow rate monitor, either for routine operation of a sorbent trap monitoring system or to convert pollutant concentrations to units of an electrical output-based emission standard in Table 1 or 2 to this subpart, you must install, certify, operate, and maintain the monitoring system and conduct on-going quality-assurance testing of the system according to Part 75 of this chapter. Use only unadjusted, quality-assured flow rate data in the emissions calculations. Do not apply bias adjustment factors to the flow rate data and do not use substitute flow rate data in the calculations.
(d) If you are required to make corrections for stack gas moisture content when converting pollutant concentrations to the units of an emission standard in Table 1 of 2 to this subpart, you must install, certify, operate, and maintain a moisture monitoring system in accordance with part 75 of this chapter. Alternatively, for coal-fired units, you may use appropriate fuel-specific default moisture values from §75.11(b) of this chapter to estimate the moisture content of the stack gas or you may petition the Administrator under §75.66 of this chapter for use of a default moisture value for non-coal-fired units. If you install and operate a moisture monitoring system, do not use substitute moisture data in the emissions calculations.
(e) If you use an HCl and/or HF CEMS, you must install, certify, operate, maintain, and quality-assure the data from the monitoring system in accordance with appendix B to this subpart. Calculate and record a 30 boiler operating day rolling average HCl or HF emission rate in the units of the standard, updated after each new boiler operating day. Each 30-day rolling average emission rate is the average of all the valid hourly HCl or HF emission rates in the preceding 30 boiler operating days (see section 9.4 of appendix B to this subpart).
(f)(1) If you use an SO2 CEMS, you must install the monitor at the outlet of the EGU, downstream of all emission control devices, and you must certify, operate, and maintain the CEMS according to part 75 of this chapter.
(2) For on-going quality-assurance (QA), the SO2 CEMS must meet the applicable daily, quarterly, and semiannual or annual requirements in sections 2.1 through 2.3 of appendix B to part 75 of this chapter, with the following addition: You must perform the linearity checks required in section 2.2 of appendix A to part 75 of this chapter if the SO2 CEMS has a span value of 30 ppm or less.
(3) Calculate and record a 30 boiler operating day rolling average SO2 emission rate in the units of the standard, updated after each new boiler operating day. Each 30-day rolling average emission rate is the average of all of the valid SO2 emission rates in the preceding 30 boiler operating days.
(4) Use only unadjusted, quality-assured SO2 concentration values in the emissions calculations, i.e., do not apply bias adjustment factors to the part 75 SO2 data and do not use substitute data values from the emissions calculations.
(g) If you use a Hg CEMS or a sorbent trap monitoring system, you must install, certify, operate, maintain and quality-assure the data from the monitoring system in accordance with appendix A to this subpart. You must calculate and record a 30 boiler operating day rolling average Hg emission rate, in units of the standard, updated after each new boiler operating day. Each 30-day rolling average emission rate, calculated according to section 6.2 of appendix A to the subpart, is the average of all of the valid hourly Hg emission rates in the preceding 30 boiler operating days. Section <IP_ADDRESS> of appendix A to this subpart explains how to reduce sorbent trap monitoring system data to an hourly basis.
(h) If you use a PM CPMS to demonstrate continuous compliance with an operating limit, you must install, certify, maintain, and operate the PM CPMS and record the output of the system as specified in paragraphs (h)(1) through (5) of this section.
(1) Install, certify, operate, and maintain your PM CPMS according to the procedures in your approved site-specific monitoring plan developed in accordance with §63.10005(d), the requirements in section (h)(1)(i) through (iii) of this section.
(i) The operating principle of the PM CPMS must be based on in-stack or extractive light scatter, light scintillation, beta attenuation, or mass accumulation detection of the exhaust gas or representative sample. The reportable measurement output from the PM CPMS may be expressed as milliamps, stack concentration, or other raw data signal.
(ii) The PM CPMS must have a cycle time (i.e., period required to complete sampling, measurement, and reporting for each measurement) no longer than 60 minutes.
(iii) The PM CPMS must be capable of detecting and responding to particulate matter concentrations of 0.5 or fewer mg/acm.
(2) For a new unit, complete the initial performance evaluation no later than [INSERT DATE 240 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER] or 180 days after the date of initial startup, whichever is later. For an existing unit, complete the initial performance evaluation no later than [INSERT DATES 3 YEARS AND 180 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER].
(3) Collect PM CPMS hourly average output data for all boiler operating hours except as indicated in §63.7535(a) through (d). Express the PM CPMS output as milliamps, PM concentration, or other raw data signal value.
(4) Calculate the arithmetic 30-day rolling average of all of the hourly average PM CPMS output collected during all boiler operating hours data (e.g., milliamps, PM concentration, raw data signal).
 (c) You must collect data using the PM CPMS at all times the process unit is operating and at the intervals specified in paragraph (a) of this section, except for periods of monitoring system malfunctions, repairs associated with monitoring system malfunctions, required monitoring system quality assurance or quality control activities (including, as applicable, calibration checks and required zero and span adjustments), any scheduled maintenance as defined in your site-specific monitoring plan.
(1) You must use all the data collected during all boiler operating hours in assessing the compliance with your operating limit except:
(i) Any data collected during monitoring system malfunctions, repairs associated with monitoring system malfunctions, or required monitoring system quality assurance or control activities conducted during monitoring system malfunctions in calculations and report any such periods in your annual deviation report;
(ii) Any data collected during periods when the monitoring system is out of control as specified in your site-specific monitoring plan, repairs associated with periods when the monitoring system is out of control, or required monitoring system quality assurance or control activities conducted during out-of-control periods in calculations used to report emissions or operating levels and report any such periods in your annual deviation report;
(2) You must record and make available upon request results of PM CPMS system performance audits, dates and duration of periods when the PM CPMS is out of control to completion of the corrective actions necessary to return the PM CPMS to operation consistent with your site-specific monitoring plan.
§63.10011  How do I demonstrate initial compliance with the emissions limits and work practice standards?
(a) You must demonstrate initial compliance with each emissions limit that applies to you by conducting performance testing.
(b) If you demonstrate initial compliance through performance tests, you must also establish each site-specific operating limit in Table 4 to this subpart that applies to your EGU(s), according to the requirements in §63.10007 and Table 6 to this subpart. You may use only the parametric data recorded during successful performance tests (i.e., tests that demonstrate compliance with the applicable emissions limits) to establish operating limits.
(c)(1) If you use CEMS or sorbent trap monitoring systems to measure a HAP (i.e., Hg or HCl) directly, the first 30 boiler operating day average emission rate obtained with certified CEMS after the applicable date in §63.9984 (or, if applicable, prior to that date, as described in §63.10005(b)(2)), expressed in units of the standard, is the initial performance test. Initial compliance is demonstrated if the results of the performance test meet the applicable emission limit in Table 1 or 2 to this subpart.
(2) For a unit that uses a CEMS to measure SO2 emissions, initial compliance, the first 30 boiler operating day average emission rate obtained with certified CEMS after the applicable date in §63.9984 (or, if applicable, prior to that date, as described in §63.10005(b)(2)), expressed in units of the standard, is the initial performance test. Initial compliance is demonstrated if the results of the performance test meet the applicable SO2 emission limit in Table 1 or 2 to this subpart.
(e) For candidate LEE units, use the results of the performance testing described in §63.10005(k) to determine initial compliance with the applicable emission limit(s) in Table 1 or 2 to this subpart and to determine whether the unit qualifies for LEE status.
(f) You must submit a Notification of Compliance Status containing the results of the initial compliance demonstration, according to §63.10030(e).
(g) You must determine the fuel whose combustion produces the least uncontrolled emissions, i.e., the cleanest fuel, that is available on site or accessible nearby for use during periods of startup or shutdown.
(1) Your cleanest fuel for use during periods of startup or shutdown determination may take safety considerations into account.
(h) You must follow the startup or shutdown requirements given in Table 3 for each coal-fired and solid oil derived-fired EGU
.
                       Continuous Compliance Requirements
§63.10020  How do I monitor and collect data to demonstrate continuous compliance?
(a) You must monitor and collect data according to this section and the site-specific monitoring plan required by §63.10000(d).
(b) You must operate the monitoring system and collect data at all required intervals at all times that the affected EGU is operating, except for periods of monitoring system malfunctions or out-of-control periods (see §63.8(c)(7) of this part), and required monitoring system quality assurance or quality control activities, including, as applicable, calibration checks and required zero and span adjustments. A monitoring system malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring system to provide valid data. Monitoring system failures that are caused in part by poor maintenance or careless operation are not malfunctions. You are required to affect monitoring system repairs in response to monitoring system malfunctions and to return the monitoring system to operation as expeditiously as practicable.
(c) You may not use data recorded during EGU startup or shutdown or monitoring system malfunctions or out-of-control periods, repairs associated with monitoring system malfunctions or out-of-control periods, or required monitoring system quality assurance or control activities in calculations used to report emissions or operating levels. You must use all the data collected during all other periods in assessing the operation of the control device and associated control system.
(d) Except for periods of monitoring system malfunctions or out-of-control periods, repairs associated with monitoring system malfunctions or out-of-control periods, and required monitoring system quality assurance or quality control activities including, as applicable, calibration checks and required zero and span adjustments), failure to collect required data is a deviation of the monitoring requirements.
§63.10021  How do I demonstrate continuous compliance with the emission limitations, operating limits, and work practice standards?
(a) You must demonstrate continuous compliance with each emissions limit, operating limit, and work practice standard in Tables 1 through 4 to this subpart that applies to you, according to the monitoring specified in Tables 6 and 7 to this subpart and paragraphs (b) through (g) of this section.
(b) If you use a CEMS to measure SO2, HCl, HF, or Hg emissions, or using a sorbent trap monitoring system to measure Hg emissions, you must demonstrate continuous compliance by using all quality-assured hourly data recorded by the CEMS (or sorbent trap monitoring system) and the other required monitoring systems (e.g., flow rate, CO2, O2, or moisture systems) to calculate the arithmetic average emissions rate in units of the standard on a continuous 30 boiler operating day rolling average basis, updated at the end of each new boiler operating day.
(c) If you use a PM CPMS data to measure compliance with an operating limit in Table 4 to this subpart, you must record the PM CPMS output data for all periods when the process is operating, except as otherwise provided in §§63.9991(d). You must demonstrate continuous compliance by using all quality-assured hourly average data collected by the PM CPMS for all operating hours to calculate the arithmetic average operating parameter in units of the operating limit (e.g., milliamps, PM concentration, raw data signal) on a 30 operating day rolling average basis, updated at the end of each new boiler operating day.
(d) If you use quarterly performance testing to demonstrate compliance with one or more applicable emissions limit in Table 1 or 2 to this subpart, you
(1) May skip performance testing in those quarters during which less than 168 boiler operating hours occur, except that a performance test must be conducted at least during one quarter every calendar year
(2) Must conduct the performance test as defined in Table 5 to this subpart and calculate the results of the testing in units of the applicable emissions standard.
(e) If you must conduct periodic performance tune-ups of your EGU(s), as specified in paragraphs (e)(1) through (9) of this section, perform the first tune-up as part of your initial compliance demonstration. Notwithstanding this requirement, you may delay the first burner inspection until the next scheduled unit outage provided you meet the requirements of §63.10005. Subsequently, you must perform an inspection of the burner at least once every 36 months unless your EGU employs neural net combustion optimization during normal operations at which you must perform an inspection of the burner and combustion controls at least once every 48 months.
(i) As applicable, inspect the burner and combustion controls, and clean or replace any components of the burner or combustion controls as necessary upon initiation of the work practice program and at least once every required inspection period. Repair of a burner or combustion control component requiring special order parts may be scheduled as follows:
(A) Burner or combustion control component parts that affect the ability to optimize NOx and CO must be installed within 3 months after the burner inspection,
(B) Burner or combustion control component parts that do not affect the ability to optimize NOx and CO may be installed on a schedule determined by the operator;
(2) As applicable, inspect the flame pattern and make any adjustments to the burner or combustion controls necessary to optimize the flame pattern. The adjustment should be consistent with the manufacturer's specifications, if available, or in accordance with best combustion engineering practice for that burner type;
(3) As applicable, observe the damper operations as a function of mill and/or cyclone loadings, cyclone and pulverizer coal feeder loadings, or other pulverizer and coal mill performance parameters, making adjustments and effecting repair to dampers, controls, mills, pulverizers, cyclones, and sensors;
(4) As applicable, evaluate windbox pressures and air proportions, making adjustments and effecting repair to dampers, actuators, controls, and sensors;
(5) Inspect the system controlling the air-to-fuel ratio and ensure that it is correctly calibrated and functioning properly. Such inspection may include calibrating excess O2 probes and/or sensors, adjusting overfire air systems, changing software parameters, and calibrating associated actuators and dampers to ensure that the systems are operated as designed. Any component out of calibration, in or near failure, or in a state that is likely to negate combustion optimization efforts prior to the next tune-up, should be corrected or repaired as necessary;
(6) Optimize combustion to minimize generation of CO and NOx. This optimization should be consistent with the manufacturer's specifications, if available, or best combustion engineering practice for the applicable burner type. NOx optimization includes burners, overfire air controls, concentric firing system improvements, neural net or combustion efficiency software, control systems calibrations, adjusting combustion zone temperature profiles, and add-on controls such as SCR and SNCR; CO optimization includes burners, overfire air controls, concentric firing system improvements, neural net or combustion efficiency software, control systems calibrations, and adjusting combustion zone temperature profiles;
(7) While operating at full load or the predominantly operated load, measure the concentration in the effluent stream of CO and NOx in ppm, by volume, and oxygen in volume percent, before and after the tune-up adjustments are made (measurements may be either on a dry or wet basis, as long as it is the same basis before and after the adjustments are made). Utilizing portable CO, NOx and O2 monitors for this measurement will meet the requirements of this section. EGU's employing neural net optimization systems need only provide a single pre and post tune-up value rather than continual values before and after each optimization adjustment made by the system;
(8) Maintain on-site and submit, if requested by the Administrator, an annual report containing the information in paragraphs (e)(1) through (e)(9) of this section including:
(i) The concentrations of CO and NOx in the effluent stream in ppm by volume, and oxygen in volume percent, measured before and after the adjustments of the EGU;
(ii) A description of any corrective actions taken as a part of the combustion adjustment; and
(iii) The type and amount of fuel used over the 12 months prior to an adjustment, but only if the unit was physically and legally capable of using more than one type of fuel during that period; and
(9) Report the dates of the initial and subsequent tune-ups as follows:
(i) If the first required tune-up is performed as part of the initial compliance demonstration, report the date of the tune-up in hard copy (as specified in §63.10030) and electronically (as specified in §63.10031). Report the date of each subsequent tune-up electronically (as specified in §63.10031).
(ii) If the first tune-up is not conducted as part of the initial compliance demonstration, but is postponed until the next unit outage, report the date of that tune-up and all subsequent tune-ups electronically, in accordance with §63.10031.
 (f) Except where otherwise indicated, the reports required by this subpart must be sent to the Administrator electronically in an XML format prescribed by the Administrator, using EPA's Emissions Collection and Monitoring Plan System (ECMPS) Client Tool (see §63.10031).
(g) You must report each instance in which you did not meet an applicable emissions limit or operating limit in Tables 1 through 4 to this subpart or failed to conduct a required tune-up. These instances are deviations from the requirements of this subpart. These deviations must be reported according to §63.10031.
(h) You must keep records as specified in §63.10032 during periods of startup and shutdown.
(i) You must provide reports as specified in §63.10031 concerning activities and periods of startup and shutdown.
§63.10022  How do I demonstrate continuous compliance under the emission averaging provision?
(a) Following the compliance date, the owner or operator must demonstrate compliance with this subpart on a continuous basis by meeting the requirements of paragraphs (a)(1) through (8) of this section.
(1) For each calendar month, demonstrate compliance with the average weighted emissions limit for the existing units participating in the emissions averaging option as determined in §63.10009(f) and (g);
 (2) For each existing unit participating in the emissions averaging option that is equipped with PM CPMS, maintain the average parameter value at or below the operating limit established during the most recent performance test;
 (3) For each existing unit participating in the emissions averaging option venting to a common stack configuration containing affected units from other subcategories, maintain the appropriate operating limit for each unit as specified in Table 4 to this subpart that applies.
(b) Any instance where the owner or operator fails to comply with the continuous monitoring requirements in paragraphs (a)(1) through (3) of this section is a deviation.
§63.10023 How do I establish my PM CPMS operating limit and determine compliance with it?
(a) During the initial performance test or any such subsequent performance test that demonstrates compliance with the filterable PM, individual non-Hg HAP metals, or total non-Hg HAP metals limit in table 1 or 2, record all hourly average output values (e.g., milliamps, stack concentration, or other raw data signal) from the PM CPMS for the periods corresponding to the test runs (e.g., nine 1-hour average PM CPMS output values for three 3-hour test runs).
(b) Determine your operating limit as the highest 1-hour average PM CPMS output value recorded during performance test. You must establish a new operating limit after each repeated performance test.
 (c) You must operate and maintain your process and control equipment such that the 30 day average PM CPMS output as defined in paragraph 63.10022(a)(2) does not exceed the operating limit determined in (b) of this paragraph.
 Notification, Reports, and Records
§63.10030  What notifications must I submit and when?
(a) You must submit all of the notifications in §§63.7(b) and (c), 63.8 (e), (f)(4) and (6), and 63.9 (b) through (h) that apply to you by the dates specified.
(b) As specified in §63.9(b)(2), if you startup your affected source before [INSERT DATE 60 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER], you must submit an Initial Notification not later than 120 days after [INSERT DATE 60 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER].
(c) As specified in §63.9(b)(4) and (b)(5), if you startup your new or reconstructed affected source on or after [INSERT DATE 60 DAYS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER], you must submit an Initial Notification not later than 15 days after the actual date of startup of the affected source.
(d) If you are required to conduct a performance test you must submit a Notification of Intent to conduct a performance test at least 30 days before the performance test is scheduled to begin.
(e) If you are required to conduct an initial compliance demonstration as specified in §63.10011(a), you must submit a Notification of Compliance Status according to §63.9(h)(2)(ii). For each initial compliance demonstration, you must submit the Notification of Compliance Status, including all performance test results and fuel analyses, before the close of business on the 60[th] day following the completion of the performance test and/or other initial compliance demonstrations according to §63.10(d)(2). The Notification of Compliance Status report must contain all the information specified in paragraphs (e)(1) through (6), as applicable.
(1) A description of the affected source(s) including identification of which subcategory the source is in, the design capacity of the source, a description of the add-on controls used on the source, description of the fuel(s) burned, including whether the fuel(s) were determined by you or EPA through a petition process to be a non-waste under 40 CFR 241.3, whether the fuel(s) were processed from discarded non-hazardous secondary materials within the meaning of 40 CFR 241.3, and justification for the selection of fuel(s) burned during the performance test.
(2) Summary of the results of all performance tests and fuel analyses and calculations conducted to demonstrate initial compliance including all established operating limits.
(3) Identification of whether you plan to demonstrate compliance with each applicable emission limit through performance testing and fuel analysis; performance testing with operational limits (e.g., CEMS for surrogates or CPMS); CEMS; or sorbent trap monitoring system.
(4) Identification of whether you plan to demonstrate compliance by emissions averaging.
(5) A signed certification that you have met all applicable emission limits and work practice standards.
(6) If you had a deviation from any emission limit, work practice standard, or operating limit, you must also submit a description of the deviation, the duration of the deviation, and the corrective action taken in the Notification of Compliance Status report.
(7) In addition to the information required in §63.9(h)(2), your notification of compliance status must include the following:
(i) A summary of the results of the annual performance tests and documentation of any operating limits that were reestablished during this test, if applicable. If you are conducting stack tests once every three years consistent with §63.10006(o) or (p), the date of the last three stack tests, a comparison of the emission level you achieved in the last three stack tests to the 50 percent emission limit threshold required in §63.10006(o) or (p), and a statement as to whether there have been any operational changes since the last stack test that could increase emissions.
(ii) Certifications of compliance, as applicable, and must be signed by a responsible official stating:
(A) "This EGU complies with the requirements in §63.10021(a) to conduct an annual performance test of the unit." and
(B) "No secondary materials that are solid waste were combusted in any affected unit."

§63.10031  What reports must I submit and when?
(a) You must submit each report in Table 8 to this subpart that applies to you.
(b) Unless the EPA Administrator has approved a different schedule for submission of reports under §63.10(a), you must submit each report by the date in Table 8 to this subpart and according to the requirements in paragraphs (b)(1) through (5) of this section.
(1) The first compliance report must cover the period beginning on the compliance date that is specified for your affected source in §63.9984 and ending on June 30 or December 31, whichever date is the first date that occurs at least 180 days after the compliance date that is specified for your source in §63.9984.
(2) The first compliance report must be postmarked or delivered no later than July 31 or January 31, whichever date is the first date following the end of the first calendar half after the compliance date that is specified for your source in §63.9984.
(3) Each subsequent compliance report must cover the semiannual reporting period from January 1 through June 30 or the semiannual reporting period from July 1 through December 31.
(4) Each subsequent compliance report must be postmarked or delivered no later than July 31 or January 31, whichever date is the first date following the end of the semiannual reporting period.
(5) For each affected source that is subject to permitting regulations pursuant to 40 CFR part 70 or 40 CFR part 71, and if the permitting authority has established dates for submitting semiannual reports pursuant to 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), you may submit the first and subsequent compliance reports according to the dates the permitting authority has established instead of according to the dates in paragraphs (b)(1) through (4) of this section.
(c) The compliance report must contain the information required in paragraphs (c)(1) through (4) of this section.
(1) The information required by the summary report located in 63.10(e)(3)(vi).
(2) The total fuel use by each affected source subject to an emission limit, for each calendar month within the semiannual reporting period, including, but not limited to, a description of the fuel, whether the fuel has received a non-waste determination by EPA or your basis for concluding that the fuel is not a waste, and the total fuel usage amount with units of measure.
(3) Indicate whether you burned new types of fuel during the reporting period. If you did burn new types of fuel you must include the date of the performance test where that fuel was in use.
(4) Include the date of the most recent tune-up for each unit subject to the requirement to conduct a performance tune-up according to §63.10021(a)(16)(i) through (vi). Include the date of the most recent burner inspection if it was not done annually and was delayed until the next scheduled unit shutdown.

(d) For each excess emissions occurring at an affected source where you are using a CMS to comply with that emission limit or operating limit, you must include the information required in  §63.10(e)(3)(v) in the compliance report specified in section (c).
(e) Each affected source that has obtained a title V operating permit pursuant to 40 CFR part 70 or 40 CFR part 71 must report all deviations as defined in this subpart in the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A). If an affected source submits a compliance report pursuant to Table 8 to this subpart along with, or as part of, the semiannual monitoring report required by 40 CFR 70.6(a)(3)(iii)(A) or 40 CFR 71.6(a)(3)(iii)(A), and the compliance report includes all required information concerning deviations from any emission limit, operating limit, or work practice requirement in this subpart, submission of the compliance report satisfies any obligation to report the same deviations in the semiannual monitoring report. However, submission of a compliance report does not otherwise affect any obligation the affected source may have to report deviations from permit requirements to the permit authority.
(f) As of January 1, 2012, and within 60 days after the date of completing each performance test, you must transmit the results of the performance tests required by this subpart to EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX)(www.epa.gov/cdx). Performance test data must be submitted in the file format generated through use of EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using those test methods on the ERT website are subject to this requirement for submitting reports electronically to WebFIRE. Owners or operators who claim that some of the information being submitted for performance tests is confidential business information (CBI) must submit a complete ERT file including information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, but not limited to, flash drives) to EPA. The electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention:  WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC  27703. The same ERT file with the CBI omitted must be submitted to EPA via CDX as described earlier in this paragraph. At the discretion of the delegated authority, you must also submit these reports, including the confidential business information, to the delegated authority in the format specified by the delegated authority.
(1) Within 60 days after the date of completing each CEMS (SO2, HCl, HF, and Hg)performance evaluation test, as defined in 63.2 and required by this subpart, you must submit the relative accuracy test audit data electronically into EPA's Central Data Exchange by using the Electronic Reporting Tool as mentioned in paragraph (h) of this section. Only data collected using test methods compatible with ERT are subject to this requirement to be submitted electronically to EPA's CDX. (2) Within 60 days after the reporting periods ending on March 31[st], June 30[th], September 30[th], and December 31[st], you must transmit quarterly reports to EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX)(www.epa.gov/cdx). You must use the appropriate electronic reporting form in CEDRI or provide an alternate electronic file consistent with EPA's reporting form output format. For each reporting period, the quarterly reports must include all of the calculated 30 day rolling average values derived from the PM CPMS.
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(3) Transmit the compliance reports required under paragraphs (c) and (d) of this section and the notification required under §63.10030(e) to EPA's WebFIRE database by using the Compliance and Emissions Data Reporting Interface (CEDRI) that is accessed through EPA's Central Data Exchange (CDX)(www.epa.gov/cdx).  You must use the appropriate electronic reporting form in CEDRI or provide an alternate electronic file consistent with EPA's reporting form output format.(4) All reports required by this subpart not subject to the requirements in paragraphs (f)(1), (2), and (3) of this section must be sent to the Administrator at the appropriate address listed in §63.13. If acceptable to both the Administrator and the owner or operator of a source, these reports may be submitted on electronic media. The Administrator retains the right to require submittal of reports subject to paragraph (h)(1) and (2) of this section in paper format.
(i) If you had a malfunction during the reporting period, the report must include the number, duration, and a brief description for each type of malfunction which occurred during the reporting period and which caused or may have caused any applicable emission limitation to be exceeded. The report must also include a description of actions taken by an owner or operator during a malfunction of an affected source to minimize emissions in accordance with §63.10000(b), including actions taken to correct a malfunction.
§63.10032  What records must I keep?
(a) You must keep records according to paragraphs (a)(1) through (2) of this section.
(1) A copy of each notification and report that you submitted to comply with this subpart, including all documentation supporting any Initial Notification or Notification of Compliance Status or semiannual compliance report that you submitted, according to the requirements in §63.10(b)(2)(xiv).
(2) Records of performance stack tests, fuel analyses, or other compliance demonstrations and performance evaluations, as required in §63.10(b)(2)(viii).
(b) For each CEMS and CPMS, you must keep records according to paragraphs (b)(1) through (4) of this section.
(1) Records described in §63.10(b)(2)(vi) through (xi).
(2) Previous (i.e., superseded) versions of the performance evaluation plan as required in §63.8(d)(3).
(3) Request for alternatives to relative accuracy test for CEMS as required in §63.8(f)(6)(i).
(4) Records of the date and time that each deviation started and stopped, and whether the deviation occurred during a period of startup, shutdown, or malfunction or during another period.
(c) You must keep the records required in Table 8 to this subpart including records of all monitoring data and calculated averages for applicable operating limits such as pressure drop and pH to show continuous compliance with each emission limit and operating limit that applies to you.
(d) For each EGU subject to an emission limit, you must also keep the records in paragraphs (d)(1) through (3) of this section.
(1) You must keep records of monthly fuel use by each EGU, including the type(s) of fuel and amount(s) used.
(2) If you combust non-hazardous secondary materials that have been determined not to be solid waste pursuant to 40 CFR 241.3(b)(1), you must keep a record which documents how the secondary material meets each of the legitimacy criteria. If you combust a fuel that has been processed from a discarded non-hazardous secondary material pursuant to 40 CFR 241.3(b)(2), you must keep records as to how the operations that produced the fuel satisfies the definition of processing in 40 CFR 241.2. If the fuel received a non-waste determination pursuant to the petition process submitted under 40 CFR 241.3(c), you must keep a record which documents how the fuel satisfies the requirements of the petition process.
(3) If consistent with §63.10032(b) and (c), you choose to stack test less frequently than annually, you must keep annual records that document that your emissions in the previous stack test(s) were less than 50 percent of the applicable emission limit for pollutants other than Hg from existing or new EGUs, or for Hg from new EGUs, less than 10 percent of the applicable emissions limit or less than 22 pounds of Hg per year, and document that there was no change in source operations including fuel composition and operation of air pollution control equipment that would cause emissions of the pollutant to increase within the past year.
(e) If you elect to average emissions consistent with §63.10009, you must additionally keep a copy of the emission averaging implementation plan required in §63.10009(g), all calculations required under §63.10009, including daily records of heat input or steam generation, as applicable, and monitoring records consistent with §63.10022.
(f) Records of the occurrence and duration of each startup and/or shutdown.
(g) Records of the occurrence and duration of each malfunction of operation (i.e., process equipment) or the air pollution control and monitoring equipment.
(h) Records of actions taken during periods of malfunction to minimize emissions in accordance with §63.10000(b), including corrective actions to restore malfunctioning process and air pollution control and monitoring equipment to its normal or usual manner of operation.
(i) Records of the type and amount of fuel used during each startup or shutdown.
§63.10033  In what form and how long must I keep my records?
(a) Your records must be in a form suitable and readily available for expeditious review, according to §63.10(b)(1).
(b) As specified in §63.10(b)(1), you must keep each record for 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record.
(c) You must keep each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to §63.10(b)(1). You can keep the records off site for the remaining 3 years.
                       Other Requirements and Information
§63.10040  What parts of the General Provisions apply to me?
Table 9 to this subpart shows which parts of the General Provisions in §§63.1 through 63.15 apply to you.
§63.10041  Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by U.S. EPA, or a delegated authority such as your state, local, or tribal agency. If the EPA Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the U.S. EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency under 40 CFR part 63, subpart E, the authorities listed in paragraphs (b)(1) through (4) of this section are retained by the EPA Administrator and are not transferred to the state, local, or tribal agency; however, the U.S. EPA retains oversight of this subpart and can take enforcement actions, as appropriate.
(1) Approval of alternatives to the non-opacity emission limits and work practice standards in §63.9991(a) and (b) under §63.6(g).
(2) Approval of major change to test methods in Table 5 to this subpart under §63.7(e)(2)(ii) and (f) and as defined in §63.90, approval of minor and intermediate changes to monitoring performance specifications/procedures in Table 5 where the monitoring serves as the performance test method (see definition of "test method" in §63.2), and approval of alternative analytical methods requested under §63.10008(b)(2).
(3) Approval of major change to monitoring under §63.8(f) and as defined in §63.90, and approval of alternative operating parameters under §§63.9991(a)(2) and 63.10009(g)(2).
(4) Approval of major change to recordkeeping and reporting under §63.10(e) and as defined in §63.90.
§63.10042  What definitions apply to this subpart?
Terms used in this subpart are defined in the Clean Air Act (CAA), in §63.2 (the General Provisions), and in this section as follows:
Affirmative defense means, 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.
Anthracite coal means solid fossil fuel classified as anthracite coal by American Society of Testing and Materials (ASTM) Method D388-77, 90, 91, 95, 98a, or 99 (incorporated by reference, see 40 CFR 63.14(b)(39)).
Bituminous coal means coal that is classified as bituminous according to ASTM Method D388-77, 90, 91, 95, 98a, or 99 (Reapproved 2004)[1] (incorporated by reference, see 40 CFR 63.14(b)(39)).
Boiler operating day means a 24-hour period between midnight and the following midnight during which any fuel is combusted at any time in the steam generating unit. It is not necessary for the fuel to be combusted the entire 24-hour period.
Coal means all solid fuels classifiable as anthracite, bituminous, sub-bituminous, or lignite by ASTM Method D388 - 991[1] (incorporated by reference, see 40 CFR 63.14(b)(39)), and coal refuse. Synthetic fuels derived from coal for the purpose of creating useful heat including but not limited to, coal derived gases (not meeting the definition of natural gas), solvent-refined coal, coal-oil mixtures, and coal-water mixtures, are considered "coal" for the purposes of this subpart.
Coal-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that burns coal or coal refuse for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.
Coal refuse means any by-product of coal mining, physical coal cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material with an ash content greater than 50 percent (by weight) and a heating value less than 13,900 kilojoules per kilogram (6,000 Btu per pound) on a dry basis.
Cogeneration means a steam-generating unit that simultaneously produces both electrical and useful thermal (or mechanical) energy from the same primary energy source.
Cogeneration unit means a stationary, fossil fuel-fired EGU meeting the definition of "fossil fuel-fired" or stationary, integrated gasification combined cycle:
(1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the unit first produces electricity and during any calendar year after which the unit first produces electricity:
(i) For a topping-cycle cogeneration unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input.
(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit's total energy input from all fuel except biomass if the unit is a boiler.
Combined-cycle gas stationary combustion turbine means a stationary combustion turbine system where heat from the turbine exhaust gases is recovered by a waste heat boiler.
Common stack means the exhaust of emissions from two or more affected units through a single flue.
Continental liquid oil-fired subcategory means any oil-fired electric utility steam generating unit that burns liquid oil and is located in the continental United States.
Deviation. (1) Deviation means any instance in which an affected source subject to this subpart, or an owner or operator of such a source:
(i) Fails to meet any requirement or obligation established by this subpart including, but not limited to, any emission limit, operating limit, work practice standard, or monitoring requirement; or
(ii) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any affected source required to obtain such a permit.
(2) A deviation is not always a violation. The determination of whether a deviation constitutes a violation of the standard is up to the discretion of the entity responsible for enforcement of the standards.
Distillate oil means fuel oils, including recycled oils, that comply with the specifications for fuel oil numbers 1 and 2, as defined by ASTM Method D396 - 02a (incorporated by reference, see §63.14(b)(40)).
Dry flue gas desulfurization technology, or dry FGD, or spray dryer absorber (SDA), or spray dryer, or dry scrubber means an add-on air pollution control system located downstream of the steam generating unit that injects a dry alkaline sorbent (dry sorbent injection) or sprays an alkaline sorbent slurry (spray dryer) to react with and neutralize acid gases such as SO2 and HCl in the exhaust stream forming a dry powder material. Alkaline sorbent injection systems in fluidized bed combustors (FBC) or circulating fluidized bed (CFB) boilers are included in this definition.
Dry sorbent injection (DSI) means an add-on air pollution control system in which sorbent (e.g., conventional activated carbon, brominated activated carbon, Trona, hydrated lime, sodium carbonate, etc.) is injected into the flue gas steam upstream of a PM control device to react with and neutralize acid gases (such as SO2 and HCl) or Hg in the exhaust stream forming a dry powder material that may be removed in a primary or secondary PM control device.
Electric utility steam generating unit (EGU) means 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.
Emission limitation means any emissions limit, work practice standard, or operating limit.
Equivalent means the following only as this term is used in Table 6 to subpart UUUUU:
(1) An equivalent sample collection procedure means a published voluntary consensus standard or practice (VCS) or EPA method that includes collection of a minimum of three composite fuel samples, with each composite consisting of a minimum of three increments collected at approximately equal intervals over the test period.
(2) An equivalent sample compositing procedure means a published VCS or EPA method to systematically mix and obtain a representative subsample (part) of the composite sample.
(3) An equivalent sample preparation procedure means a published VCS or EPA method that: Clearly states that the standard, practice or method is appropriate for the pollutant and the fuel matrix; or is cited as an appropriate sample preparation standard, practice or method for the pollutant in the chosen VCS or EPA determinative or analytical method.
(4) An equivalent procedure for determining heat content means a published VCS or EPA method to obtain gross calorific (or higher heating) value.
(5) An equivalent procedure for determining fuel moisture content means a published VCS or EPA method to obtain moisture content. If the sample analysis plan calls for determining metals (especially the Hg, selenium, or arsenic) using an aliquot of the dried sample, then the drying temperature must be modified to prevent vaporizing these metals. On the other hand, if metals analysis is done on an "as received" basis, a separate aliquot can be dried to determine moisture content and the metals concentration mathematically adjusted to a dry basis.
(6) An equivalent pollutant (Hg) determinative or analytical procedure means a published VCS or EPA method that clearly states that the standard, practice, or method is appropriate for the pollutant and the fuel matrix and has a published detection limit equal or lower than the methods listed in Table 6 to subpart UUUUU for the same purpose.
Federally enforceable means all limitations and conditions that are enforceable by the EPA Administrator, including the requirements of 40 CFR parts 60, 61, and 63; requirements within any applicable State implementation plan; and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 40 CFR 51.24.
Flue gas desulfurization system means any add-on air pollution control system located downstream of the steam generating unit whose purpose or effect is to remove at least 50 percent of the SO2 in the exhaust gas stream.
Fossil fuel means natural gas, oil, coal, and any form of solid, liquid, or gaseous fuel derived from such material.
Fossil fuel-fired means an electric utility steam generating unit (EGU) that is capable of combusting more than 25 MW of fossil fuels. To be "capable of combusting" fossil fuels, an EGU would need to have these fuels allowed in their operating permits and have the appropriate fuel handling facilities on-site or otherwise available (e.g., coal handling equipment, including coal storage area, belts and conveyers, pulverizers, etc.; oil storage facilities). In addition, fossil fuel-fired means any EGU that fired fossil fuels for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.
Fuel type means each category of fuels that share a common name or classification. Examples include, but are not limited to, bituminous coal, subbituminous coal, lignite, anthracite, biomass, residual oil. Individual fuel types received from different suppliers are not considered new fuel types.
Fluidized bed boiler, or fluidized bed combustor, or circulating fluidized boiler, or CFB means a boiler utilizing a fluidized bed combustion process.
Fluidized bed combustion means a process where a fuel is burned in a bed of granulated particles which are maintained in a mobile suspension by the forward flow of air and combustion products.
Gaseous fuel includes, but is not limited to, natural gas, process gas, landfill gas, coal derived gas, solid oil-derived gas, refinery gas, and biogas.
Generator means a device that produces electricity.
Gross output means the gross useful work performed by the steam generated and, for an IGCC electric utility steam generating unit, the work performed by the stationary combustion turbines. For a unit generating only electricity, the gross useful work performed is the gross electrical output from the unit's turbine/generator sets. For a cogeneration unit, the gross useful work performed is the gross electrical, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls), or mechanical output plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process).
Heat input means heat derived from combustion of fuel in an EGU (synthetic gas for an IGCC) and does not include the heat input from preheated combustion air, recirculated flue gases, or exhaust gases from other sources such as gas turbines, internal combustion engines, etc.
Integrated gasification combined cycle electric utility steam generating unit or IGCC means an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that burns a synthetic gas derived from coal and/or solid oil-derived fuel for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year in a combined-cycle gas turbine. No coal or solid oil-derived fuel is directly burned in the unit during operation.
ISO conditions means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 101.3 kilopascals.
Lignite coal means coal that is classified as lignite A or B according to ASTM Method D388-77, 90, 91, 95, 98a, or 99 (Reapproved 2004)[1] (incorporated by reference, see §63.14(a)(39)).
Limited-use liquid oil-fired subcategory means an EGU with an annual oil-fired capacity factor of less than 5 percent.
Liquid fuel includes, but is not limited to, distillate oil and residual oil.
Natural gas means a naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, or propane) produced in geological formations beneath the Earth's surface that maintains a gaseous state at standard atmospheric temperature and pressure under ordinary conditions. Natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 950 and 1,100 Btu per standard cubic foot. Natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value.
Natural gas-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that is not a coal-fired, oil-fired, or IGCC electric utility steam generating unit and that burns natural gas for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.
Net-electric output means the gross electric sales to the utility power distribution system minus purchased power on a calendar year basis.
Non-continental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands.
Non-continental liquid oil-fired subcategory means any oil-fired electric utility steam generating unit that burns liquid oil and is located outside the continental United States.
Non-mercury (Hg) HAP metals means Antimony (Sb), Arsenic (As), Beryllium (Be), Cadmium (Cd), Chromium (Cr), Cobalt (Co), Lead (Pb), Manganese (Mn), Nickel (Ni), and Selenium (Se).
Oil means crude oil or petroleum or a fuel derived from crude oil or petroleum, including distillate and residual oil, solid oil-derived fuel (e.g., petroleum coke) and gases derived from solid oil-derived fuels (not meeting the definition of natural gas).
Oil-fired electric utility steam generating unit means an electric utility steam generating unit meeting the definition of "fossil fuel-fired" that is not a coal-fired electric utility steam generating unit and that burns oil for more than 10.0 percent of the average annual heat input during any 3 consecutive calendar years or for more than 15.0 percent of the annual heat input during any one calendar year.
Particulate matter or PM means any finely divided solid material as measured by the test methods specified under this subpart, or an alternative method.
Pulverized coal boiler means an EGU in which pulverized coal is introduced into an air stream that carries the coal to the combustion chamber of the EGU where it is fired in suspension.
Residual oil means crude oil, and all fuel oil numbers 4, 5 and 6, as defined by ASTM Method D396 - 02a (incorporated by reference, see §63.14(b)(40)).
Responsible official means responsible official as defined in 40 CFR 70.2.
Stationary combustion turbine means all equipment, including but not limited to the turbine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), and any ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any regenerative/recuperative cycle stationary combustion turbine, the combustion turbine portion of any stationary cogeneration cycle combustion system, or the combustion turbine portion of any stationary combined cycle steam/electric generating system. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. Stationary combustion turbines do not include turbines located at a research or laboratory facility, if research is conducted on the turbine itself and the turbine is not being used to power other applications at the research or laboratory facility.
Steam generating unit means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators associated with integrated gasification combined cycle gas turbines; nuclear steam generators are not included).
Stoker means a unit consisting of a mechanically operated fuel feeding mechanism, a stationary or moving grate to support the burning of fuel and admit undergrate air to the fuel, an overfire air system to complete combustion, and an ash discharge system. There are two general types of stokers: underfeed and overfeed. Overfeed stokers include mass feed and spreader stokers.
Subbituminous coal means coal that is classified as subbituminous A, B, or C according to ASTM Method D388-77, 90, 91, 95, 98a, or 99 (Reapproved 2004)[1] (incorporated by reference, see §60.14(a)(39)).
Unit designed for coal > 8,300 Btu/lb subcategory means any coal-fired EGU that is not a coal-fired EGU in the "unit designed for low rank, virgin coal" subcategory.
Unit designed for low rank, virgin coal means any coal-fired EGU designed to burn and is burning nonagglomerating virgin coal having a calorific value (moist, mineral matter-free basis) of less than 19,305 kJ/kg (8,300 Btu/lb) that is constructed and operates at or near the mine that produces such coal.
Unit designed to burn solid oil-derived fuel subcategory means any oil-fired EGU that burns solid oil-derived fuel.
Voluntary Consensus Standards or VCS mean technical standards (e.g., materials specifications, test methods, sampling procedures, business practices) developed or adopted by one or more voluntary consensus bodies. EPA/OAQPS has by precedent only used VCS that are written in English. Examples of VCS bodies are: American Society of Testing and Materials (ASTM), American Society of Mechanical Engineers (ASME), International Standards Organization (ISO), Standards Australia (AS), British Standards (BS), Canadian Standards (CSA), European Standard (EN or CEN) and German Engineering Standards (VDI). The types of standards that are not considered VCS are standards developed by: the U.S. states, e.g., California (CARB) and Texas (TCEQ); industry groups, such as American Petroleum Institute (API), Gas Processors Association (GPA), and Gas Research Institute (GRI); and other branches of the U.S. government, e.g. Department of Defense (DOD) and Department of Transportation (DOT). This does not preclude EPA from using standards developed by groups that are not VCS bodies within their rule. When this occurs, EPA has done searches and reviews for VCS equivalent to these non-EPA methods.
Wet flue gas desulfurization technology, or wet FGD, or wet scrubber means any add-on air pollution control device that is located downstream of the steam generating unit that mixes an aqueous stream or slurry with the exhaust gases from an EGU to control emissions of PM and/or to absorb and neutralize acid gases, such as SO2 and HCl.
Work practice standard means any design, equipment, work practice, or operational standard, or combination thereof, which is promulgated pursuant to CAA section 112(h).
                      Tables to Subpart UUUUU of Part 63
Table 1 to Subpart UUUUU of Part 63  --  Emission Limits for New or Reconstructed EGUs

As stated in §63.9991, you must comply with the following applicable emission limits:

If your EGU is in this subcategory ...
For the following pollutants ...
You must meet the following emission limits and work practice standards ...
Using these requirements, as appropriate, (e.g., specified sampling volume or test run duration) with the test methods in Table 5...
1. Coal-fired unit designed for coal > 8,300 Btu/lb.

a. Filterable particulate matter (PM)
 7.0E-3 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Total non-Hg HAP metals
 2.0E-5 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Individual HAP metals:
Antimony (Sb)
Arsenic (As)
Beryllium (Be)
Cadmium (Cd)
Chromium (Cr)
Cobalt (Co)
Lead (Pb)
Manganese (Mn)
Nickel (Ni)
Selenium (Se)

 2.0E-4 lb/GWh
 8.0E-4 lb/GWh
 6.0E-5 lb/GWh
 4.0E-4 lb/GWh
 7.0E-3 lb/GWh
 8.0E-4 lb/GWh
 3.0E-3 lb/GWh
 4.0E-3 lb/GWh
 4.0E-3 lb/GWh
 3.0E-4 lb/GWh
Collect a minimum of 4 dscm per run

b. Hydrogen chloride (HCl)
 4.0E-1 lb/GWh
For Method 26A, collect a minimum of 2 dscm per run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.

OR

Sulfur dioxide (SO2)
 4.0E-1 lb/MWh
SO2 CEMS

c. Mercury (Hg)
 2.0E-4 lb/GWh
Hg CEMS or Sorbent trap monitoring system
2. Low Btu, virgin coal

a. Filterable particulate matter (PM)
 7.0E-3 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Total non-Hg HAP metals
 2.0E-5 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Individual HAP metals:
Antimony (Sb)
Arsenic (As)
Beryllium (Be)
Cadmium (Cd)
Chromium (Cr)
Cobalt (Co)
Lead (Pb)
Manganese (Mn)
Nickel (Ni)
Selenium (Se)

 2.0E-4 lb/GWh
 8.0E-4 lb/GWh
 6.0E-5 lb/GWh
 4.0E-4 lb/GWh
 7.0E-3 lb/GWh
 8.0E-4 lb/GWh
 3.0E-3 lb/GWh
 4.0E-3 lb/GWh
 4.0E-3 lb/GWh
 3.0E-4 lb/GWh
Collect a minimum of 4 dscm per run

b. Hydrogen chloride (HCl)
 4.0E-1 lb/GWh
For Method 26A, collect a minimum of 2 dscm per run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.

OR

Sulfur dioxide (SO2)
 4.0E-1 lb/MWh
SO2 CEMS

c. Mercury (Hg)
 4.0E-2 lb/GWh
Hg CEMS or Sorbent trap monitoring system
3. IGCC unit

a. Filterable particulate matter (PM)
  7.0E-2 lb/MWh
 9.0E-2 lb/MWh
Collect a minimum of 1 dscm per run

OR
OR

Total non-Hg HAP metals
 3.0E-4 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Individual HAP metals:
Antimony (Sb)
Arsenic (As)
Beryllium (Be)
Cadmium (Cd)
Chromium (Cr)
Cobalt (Co)
Lead (Pb)
Manganese (Mn)
Nickel (Ni)
Selenium (Se)

 1.0E-2 lb/GWh
 8.0E-3 lb/GWh
 9.0E-5 lb/GWh
 1.0E-3 lb/GWh
 3.0E-2 lb/GWh
 3.0E-3 lb/GWh
 6.0E-3 lb/GWh
 2.0E-2 lb/GWh
 2.0E-2 lb/GWh
 3.0E-1 lb/GWh
Collect a minimum of 4 dscm per run

b. Hydrogen chloride (HCl)
 3.0E-1 lb/GWh
For Method 26A, collect a minimum of 3 dscm per run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.

OR

Sulfur dioxide (SO2)
 4.0E-1 lb/MWh
SO2 CEMS

c. Mercury (Hg)
 3.0E-3 lb/GWh
Hg CEMS or Sorbent trap monitoring system
4. Liquid oil-fired unit - continental

a. Filterable particulate matter (PM)
 7.0E-2 lb/MWh
Collect a minimum of 1 dscm per run

OR
OR

Total HAP metals
 4.0E-4 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Individual HAP metals:
Antimony (Sb)
Arsenic (As)
Beryllium (Be)
Cadmium (Cd)
Chromium (Cr)
Cobalt (Co)
Lead (Pb)
Manganese (Mn)
Nickel (Ni)
Selenium (Se)

 2.0E-3 lb/GWh
 2.0E-3 lb/GWh
 7.0E-4 lb/GWh
 4.0E-4 lb/GWh
 2.0E-2 lb/GWh
 6.0E-3 lb/GWh
 6.0E-3 lb/GWh
 3.0E-2 lb/GWh
 4.0E-2 lb/GWh
 4.0E-3 lb/GWh
Collect a minimum of 4 dscm per run

Mercury (Hg)
 1.0E-5 lb/GWh
For Method 30B sample volume determination (8.2.4), the estimated Hg concentration should nominally be < (1/2) the standard

b. Hydrogen chloride (HCl)
 5.0E-4 lb/MWh
For Method 26A, collect a minimum of 2 dscm per run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.

c. Hydrogen fluoride (HF)
 5.0E-4 lb/MWh
For Method 26A, collect a minimum of 2 dscm per run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.
5. Liquid oil-fired unit  -  non-continental
a. Filterable particulate matter (PM)
 2.0E-1 lb/MWh
Collect a minimum of 1 dscm per run

OR
OR

Total HAP metals
 7.0E-3 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Individual HAP metals:
Antimony (Sb)
Arsenic (As)
Beryllium (Be)
Cadmium (Cd)
Chromium (Cr)
Cobalt (Co)
Lead (Pb)
Manganese (Mn)
Nickel (Ni)
Selenium (Se)

 8.0E-3 lb/GWh
 7.0E-2 lb/GWh
 3.0E-3 lb/GWh
 2.0E-3 lb/GWh
 2.0E-2 lb/GWh
 3.0E-1 lb/GWh
 3.0E-2 lb/GWh
 1.0E-1 lb/GWh
 7.5E0 lb/GWh
 2.0E-2 lb/GWh
Collect a minimum of 4 dscm per run

Mercury (Hg)
 1.0E-4 lb/GWh
For Method 30B sample volume determination (8.2.4), the estimated Hg concentration should nominally be < (1/2) the standard

b. Hydrogen chloride (HCl)
 5.0E-4 lb/MWh
For Method 26A, collect a minimum of 2 dscm per run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.

c. Hydrogen fluoride (HF)
 5.0E-4 lb/MWh
For Method 26A, collect a minimum of 2 dscm per run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.
6. Solid oil-derived fuel-fired unit

a. Filterable particulate matter (PM)
 2.0E-2 lb/MWh
Collect a minimum of 1 dscm per run

OR
OR

Total non-Hg HAP metals
 6.0E-4 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Individual HAP metals:
Antimony (Sb)
Arsenic (As)
Beryllium (Be)
Cadmium (Cd)
Chromium (Cr)
Cobalt (Co)
Lead (Pb)
Manganese (Mn)
Nickel (Ni)
Selenium (Se)

 9.0E-4 lb/GWh
 2.0E-3 lb/GWh
 8.0E-5 lb/GWh
 7.0E-4 lb/GWh
 6.0E-3 lb/GWh
 2.0E-3 lb/GWh
 2.0E-2 lb/GWh
 7.0E-3 lb/GWh
 7.0E-3 lb/GWh
 9.0E-4 lb/GWh
Collect a minimum of 4 dscm per run

b. Hydrogen chloride (HCl)
 3.0E-4 lb/MWh
For Method 26A, collect a minimum of 3 dscm per run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.

OR

Sulfur dioxide (SO2)
 4.0E-1 lb/MWh
SO2 CEMS

c. Mercury (Hg)
 2.0E-3 lb/GWh
Hg CEMS or Sorbent trap monitoring system

Table 2 to Subpart UUUUU of Part 63  --  Emission Limits for Existing EGUs

As stated in §63.9991, you must comply with the following applicable emission limits:

If your EGU is in this subcategory ...
For the following pollutants ...
You must meet the following emission limits and work practice standards ...
Using these requirements, as appropriate (e.g., specified sampling volume or test run duration) with the test methods in Table 5...
1. Coal-fired unit designed for coal > 8,300 Btu/lb.

a. Filterable particulate matter (PM)
 3.0E-2 lb/MMBtu or
 3.0E-1 lb/MWh
Collect a minimum of 1 dscm per run

OR
OR

Total non-Hg HAP metals
 5.0E-5 lb/MMBtu
 5.0E-4 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Individual HAP metals:
Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

 6.0E-1 lb/TBtu or
 6.0E-3 lb/GWh
 1.1E0  lb/TBtu or
 2.0E-2 lb/GWh
 2.0E-1 lb/TBtu or
 2.0E-3 lb/GWh
 3.0E-1 lb/TBtu or
 3.0E-3 lb/GWh
 2.8E0 lb/TBtu or
 3.0E-2 lb/GWh
 8.0E-1 lb/TBtu or
 8.0E-3 lb/GWh
 1.2E0  lb/TBtu or
 2.0E-2 lb/GWh
 4.0E0  lb/TBtu or
 5.0E-2 lb/GWh
 3.1E0  lb/TBtu or
 4.0E-2 lb/GWh
 5.0E0 lb/TBtu or
 6.0E-2 lb/GWh
Collect a minimum of 4 dscm per run

b. Hydrogen chloride (HCl)
 2.0E-3 lb/MMBtu or
 2.0E-2 lb/MWh
For Method 26A, collect a minimum of 0.75 dscm per run; for Method 26, collect a minimum of 60 liters per run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.

OR

Sulfur dioxide (SO2)
 2.0E-1 lb per MMBtu or
 1.5E0 lb per MWh
SO2 CEMS

c. Mercury (Hg)
 1.2E0 lb/TBtu or
 2.0E-2 lb/GWh
LEE Testing for 30 days with 10 days maximum per Method 30B  run or Hg CEMS or Sorbent trap monitoring  system
2. Low Btu, virgin coal

a. Filterable particulate matter (PM)
 3.0E-2 lb/MMBtu or
 3.0E-1 lb/MWh
Collect a minimum of 1 dscm per run

OR
OR

Total non-Hg HAP metals
 5.0E-5 lb/MMBtu or
 5.0E-4 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Individual HAP metals:
Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

 6.0E-1 lb/TBtu or
 6.0E-3 lb/GWh
 1.1E0  lb/TBtu or
 2.0E-2 lb/GWh
 2.0E-1 lb/TBtu or
 2.0E-3 lb/GWh
 3.0E-1 lb/TBtu or
 3.0E-3 lb/GWh
 2.8E0 lb/TBtu or
 3.0E-2 lb/GWh
 8.0E-1 lb/TBtu or
 8.0E-3 lb/GWh
 1.2E0  lb/TBtu or
 2.0E-2 lb/GWh
 4.1E0 lb/TBtu or
 5.0E-2 lb/GWh
 3.1E0 lb/TBtu or
 4.0E-2 lb/GWh
 5.0E0 lb/TBtu or
 6.0E-2 lb/GWh
Collect a minimum of 4 dscm per run

b. Hydrogen chloride (HCl)
 2.0E-3 lb/MMBtu or
 2.0E-2 lb/MWh
For Method 26A, collect a minimum of 0.75 dscm per run; for Method 26, collect a minimum of 120 liters per run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.

OR

Sulfur dioxide (SO2)
 2.0E-1 lb/MMBtu or
 1.5E0 lb per MWh
SO2 CEMS

c. Mercury (Hg)
 3.3E0 lb/TBtu or
 4.0E-2 lb/GWh
LEE Testing for 30 days with 10 days maximum per Method 30B  run or Hg CEMS or Sorbent trap monitoring  system
3. IGCC unit

a. Filterable particulate matter (PM)
 4.0E-2 lb/MMBtu or
 2.0E-2 lb/MWh
Collect a minimum of 1 dscm per run

OR
OR

Total non-Hg HAP metals
 5.0E-5 lb/MMBtu or
 3.0E-3 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Individual HAP metals:
Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

 4.0E-1 lb/TBtu or
 4.0E-3 lb/GWh
 1.2E0  lb/TBtu or
 2.0E-2 lb/GWh
 3.0E-2 lb/TBtu or
 3.0E-4 lb/GWh
 2.0E-1 lb/TBtu or
 2.0E-3 lb/GWh
 2.9E0  lb/TBtu or
 2.0E-2 lb/GWh
 1.2E0 lb/TBtu or
 4.0E-3 lb/GWh
 2.0E-4 lb/MMBtu or
 3.0E-3 lb/MWh
  2.5E0  lb/TBtu or
 2.0E-2 lb/GWh
 4.2E0  lb/TBtu or
 5.0E-2 lb/GWh
 2.2E1  lb/TBtu or
 2.0E-1 lb/GWh
Collect a minimum of 4 dscm per run

b. Hydrogen chloride (HCl)
 5.0E-4 lb/MMBtu or
 3.0E-3 lb/MWh
For Method 26A, collect a minimum of 2 dscm per
Run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.

c. Mercury (Hg)
 2.2E0 lb/TBtu or
 2.0E-2 lb/GWh
LEE Testing for 30 days with 10 days maximum per Method 30B run or Hg CEMS or Sorbent trap monitoring  system
4. Liquid oil-fired unit  -  continental

a. Filterable particulate matter (PM)
 3.0E-2 lb/MMBtu or
 2.0E-1 lb/MWh
Collect a minimum of 1 dscm per run

OR
OR

Total HAP metals
 8.0E-5 lb/MMBtu or
 2.0E-04 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Individual HAP metals:
Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

 3.0E-1 lb/TBtu or
 3.0E-3 lb/GWh
 5.0E-1 lb/TBtu or
 7.0E-3 lb/GWh
 6.0E-2 lb/TBtu or
 7.0E-4 lb/GWh
 2.0E-1 lb/TBtu or
 2.0E-3 lb/GWh
 1.8E0 lb/TBtu or
 3.0E-2 lb/GWh
 1.0E0 lb/TBtu or
 3.0E-2 lb/GWh
 2.3E0 lb/TBtu or
 4.E-20 lb/GWh
 2.9E0 lb/TBtu or
 7.0E-2 lb/GWh
 5.6E0 lb/TBtu or
 7.0E-2 lb/GWh
 1.2E0 lb/TBtu or
 2.E-20 lb/GWh
Collect a minimum of 4 dscm per run

Mercury (Hg)
 2.0E-1 lb/TBtu or
 8.0E-4 lb/GWh
For Method 30B sample volume determination (8.2.4), the estimated Hg concentration should nominally be < (1/2) the standard

b. Hydrogen chloride (HCl)
 3.0E-4 lb/MMBtu or
 4.0E-3 lb/MWh
For Method 26A, collect a minimum of 3 dscm per
run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.

c. Hydrogen fluoride (HF)
 2.0E-4 lb/MMBtu or
 2.0E-3 lb/MWh
For Method 26A, collect a minimum of 3 dscm per
Run. For ASTM D6348-03 or Method 320, sample for a minimum of 1 hour.
5. Liquid oil-fired unit  -  non-continental

a. Filterable particulate matter (PM)
 8.0E-2 lb/MMBtu or
 8.0E-1 lb/MWh
Collect a minimum of 1 dscm per run

OR
OR

Total HAP metals
 2.0E-3 lb/MMBtu or
 2.0E-2 lb/MWh
Collect a minimum of 4 dscm per run

OR
OR

Individual HAP metals:
Antimony (Sb)

Arsenic (As)

Beryllium (Be)

Cadmium (Cd)

Chromium (Cr)

Cobalt (Co)

Lead (Pb)

Manganese (Mn)

Nickel (Ni)

Selenium (Se)

 1.4E0 lb/TBtu or
 2.0E-2 lb/GWh
 4.0E0 lb/TBtu or
 4.0E-2 lb/GWh
 5.0E-1 lb/TBtu or
 4.0E-3 lb/GWh
 2.0E-2 lb/TBtu or
 2.0E-3 lb/GWh
 5.2E0 lb/TBtu or
 6.0E-2 lb/GWh
 5.1E1 lb/TBtu or
 6.0E-1 lb/GWh
 3.0E0 lb/TBtu or
 3.0E-2 lb/GWh
 2.0E1 lb/TBtu or
 3.0E-1 lb/GWh
 5.3E2 lb/TBtu or
 6.2E0 lb/GWh
 2.3E0 lb/TBtu or
 3.0E-2 lb/GWh
Collect a minimum of 4 dscm per run

Mercury (Hg)
 5.0E-2 lb/TBtu or
 5.0E-4 lb/GWh
For Method 29 collect a minimum of 4 dscm per run or for Method 30B sample volume determination (8.2.4), the estimated Hg concentration should nominally be < (1/2) the standard

b. Hydrogen chloride (HCl)
 7.0E-4 lb/MMBtu or
 7.0E-3 lb/MWh
For Method 26A, collect a minimum of 2 dscm per
run. For ASTM D6348-03 or Method 320, sample for a minimum of 2 hours.

c. Hydrogen fluoride (HF)
 8.0E-5 lb/MMBtu or
 7.0E-4 lb/MWh
For Method 26A, collect a minimum of 4 dscm per run. For ASTM D6348-03 or Method 320, sample for a minimum of 2 hours.
6. Solid oil-derived fuel-fired unit

a. Filterable particulate matter (PM)
 8.0E-3 lb/MMBtu or
 9.0E-2 lb/MWh
Collect a minimum of 1 dscm per run

OR
OR

Total non-Hg HAP metals