## MEMORANDUM

From: Christian Fellner

To: Steam Generating Unit N SPS Docket (EPA-HQ-OAR-2005-0031)

Date: December, 2010

Subject: Redline of Proposed Amendments to the Boiler NSPS (40 CFR Part 60, Subparts D, Da, Db, & Dc).

Introduction

For references purposes, EPA prepared a red line of the proposed amendments against the existing regulatory text. The redline documen ts only include edited sections and are only intended to assist interested parties to unde rstand the proposed amendments. The redline documents and are not intended to supersede the amendments included in the FR package.Subpart D—Standards of Performance for Foss il-Fuel-Fired Steam Generators for Which Construction Is Commenced After August 17, 1971 §60.42 Standard for particulate matter (PM). (a) On and after the date on wh ich the performance test requir ed to be conducted by §60.8 is completed, no owner or operator subject to the provi sions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that: (1) Contain PM in excess of 43 nanograms per joul e (ng/J) heat input (0.10 lb/MMBtu) derived from fossil fuel or fossil fuel and wood residue. (2) Exhibit greater than 20 percent opacity except fo r one six-minute period per hour of not more than 27 percent opacity. (b)(1) On or after December 28, 1979, no owner or operator shall cause to be discharged into the atmosphere from the Southwestern Public Service Company's Harrington Station #1, in Amarillo, TX, any gases which exhibit greater than 35 percent opac ity, except that a maximum or 42 percent opacity shall be permitted for not more than 6 minutes in any hour. (2) Interstate Power Company shall not cause to be discharged into the atmosphere from its Lansing Station Unit No. 4 in Lansing, IA, any gases which exhibit greater than 32 percent opacity, except that a maximum of 39 percent opacity shall be permitte d for not more than six minutes in any hour. (c) As an alternate to meeting the requirements of paragraph (a) of this section, an owner or operator that elects to install, calibrate, maintain, and operate a continuous emissions monitoring systems (CEMS) for measuring PM emissions can petition the Administrator (in writing) to comply with §60.42Da(a) of subpart Da of this part. If the Administrator grants the petition, the source will from then on (unless the unit is modified or reconstructed in the future) have to comply with the requirements in §60.4 2 3 Da(a) of subpart Da of this part.
§60.45 Emissions and fuel monitoring. (a) Each owner or operator shall install, calibrate, maintain, and operate continuous opacity monitoring system (COMS) for measuring opacity and a CEMS for measuring SO 2 emissions, NO X emissions, and either oxygen (O 2 ) or carbon dioxide (CO 2 ) except as provided in paragraph (b) of this section. (b) Certain of the CEMS requirements under paragrap h (a) of this section do not apply to owners or operators under the following conditions: (1) For a fossil-fuel-fired steam ge nerator that burns only gaseous or liquid fossil fuel (excluding residual oil) with potential SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and that does not use post-combustion technology to reduce emissions of SO 2 or PM, CEMS for measuring the opacity of emissions and SO 2 emissions are not required if the owner or operator monitors SO 2 emissions by fuel sampling and analysis or fuel receipts. (2) For a fossil-fuel-fired steam ge nerator that does not use a flue ga s desulfurization device, a CEMS for measuring SO 2 emissions is not required if the owner or operator monitors SO 2 emissions by fuel sampling and analysis. Comment [CF1]: Typo error in earlier rulemkaing(3) Notwithstanding §60.13(b), installation of a CEMS for NO X may be delayed until after the initial performance tests under §60.8 have be en conducted. If the owner or operator demonstrates during the performance test th at emissions of NO X are less than 70 percent of the applicable standards in §60.44, a CEMS for measuring NO X emissions is not required. If the initial performance test results show that NO X emissions are greater than 70 percent of the applicable standard, the owner or operator shall install a CEMS for NO X within one year after the date of the in itial performance tests under §60.8 and comply with all other applicable monitoring requirements under this part. (4) If an owner or operator does not install any CEMS for sulfur oxides and NO X , as provided under paragraphs (b)(1) and (b)(3) or paragraphs (b)(2) and (b)(3) of this section a CEMS for measuring either O 2 or CO 2 is not required. (5) An owner or operator may petition the Administrator (in writing) to install a PM CEMS as an alternative to the CEMS for monitoring opacity emissions. (6) A CEMS for measuring the opacity of emissi ons is not required for a fossil fuel-fired steam generator that does not use post-combustion tec hnology (except a wet scrubber) for reducing PM, SO 2 , or carbon monoxide (CO) emissions, burns only gase ous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur , and is operated such that emissi ons of CO to the atmosphere from the affected source are maintained at levels less than or equal to 0.15 lb/MMBtu on a boiler operating day average basis. Owners and operators of affected sources electing to comply with this paragraph must demonstrate compliance according to the proced ures specified in paragraphs (b)(6)(i) through (iv) of this section. (i) You must monitor CO emissions using a CEMS acco rding to the procedures specified in paragraphs (b)(6)(i)(A) through (D) of this section. (A) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in §60.58b(i)(3) of subpart Eb of this part. (B) Each 1-hour CO emissions average is calculatedusing the data points ge nerated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). (C) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data points required in §60.13(h)(2). (D) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part. (ii) You must calculate the 1-hour average CO em issions levels for each boiler operating day by multiplying the average hourly CO output concen tration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission le vels computed for each boiler operating day. (iii) You must evaluate the preceding 24-hour aver age CO emission level each boiler operating day excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour average CO emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discove ry of the high emission incident and, take theappropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less. (iv) You must record the CO measurements and calc ulations performed according to paragraph (b)(6) of this section and any corrective act ions taken. The record of correc tive action taken must include the date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, and the date, time, and descript ion of the corrective action. (7) The Anowner or operator of an affected facility subject to an opacity standard under §60.42 and that elects to not install use a COMS because the affected facility burns only fuels as specified under paragraph (b)(1) of this section, monitors PM emi ssions as specified under paragraph (b)(5) of this section, or monitors CO emissions as specified under paragraph (b)(6) of this section
, shall conduct a performance test using Method 9 of appendix A–4 of this part and the procedures in §60.11 to demonstrate compliance with the applicable limit in §60.42 by April 29, 2011 or within 45 days after stopping use of an existing COMS, whichever is later, and shall comply with either paragraph s (b)(7)(i), (b)(7)(ii), or (b)(7)(iii) of this section. The observation period for Method 9 of appendix A-4 of this part performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are less than 10 percent and all indi vidual 15-second observations are le ss than or equal to 20 percent during the initial 60 minutes of observation If during the initial 60 minu tes of observation all 6

- minute averages are less than 10 percent and all individual 15

- second observations are less than or equal to 20 percent, the observation pe riod may be reduced from 3 hours to 60 minutes

. The permitting authority may exempt owners or operators of affected faci lities burning only natural gas from the opacity monitoring requirements. (i) Except as provided in paragraph (b)(7)(ii) or (b)( 7)(iii) of this section, the owner or operator shall conduct subsequent Me thod 9 of appendix A–4 of this part performance tests using the procedures in paragraph (b)(7) of this section according to the app licable schedule in paragr aphs (b)(7)(i)(A) through (b)(7)(i)(D) of this section, as determined by th e most recent Method 9 of appendix A–4 of this part performance test results. (A) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted; (B) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 6 calendar months from the date that th e most recent performance test was conducted; (C) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A–4 of this part perf ormance test must be completed within 3 calendar months from the date that the most recent performance test was conducted; or (D) If the maximum 6-minute average opacity is greater th an 10 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 30 45 calendar days from the date that the most recent pe rformance test was conducted. (ii) If the maximum 6-minute opacity is less th an 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owne r or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 of this part performance test, elect to perform subsequentmonitoring using Method 22 of appe ndix A–7 of this part according to the procedures specified in paragraphs (b)(7)(ii)(A) an d (B) of this section. (A) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the affected facility fires fuel for which an opacity standard is applicable using Method 22 of appendix A–7 of this partand demonstrate that the sum of the occurrences of any visible emissions is not in ex cess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the occurrence of visible emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds per 30 minute period)
, the owner or operator shall either document and adjust the operation of the facility and demonstrate within 24 hours that the su m of the occurrence of visible emissions is equal to or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of appendix A–4 of this part performance test using the procedures in paragraph (b)(7) of this section within 30 45 calendar days according to the requirements in §60.46(b)(3). (B) If no visible emissions are observed for 30 operating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any vi sible emissions are observed, dail y observations shall be resumed. (iii) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 performance tests, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitoring plan approved by the Administrator. The observations shall be similar, but not necessarily identical, to the requirements in paragraph (b)(7)(ii) of this sect ion. For reference purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Preliminary Methods. (c) For performance evaluations under §60.13(c) and calibration ch ecks under §60.13(d), the following procedures shall be used: (1) Methods 6, 7, and 3B of appendix A of this pa rt, as applicable, shall be used for the performance evaluations of SO 2 and NO X continuous monitoring systems. Acceptable alternative methods for Methods 6, 7, and 3B of appendix A of this part are given in §60.46(d). (2) Sulfur dioxide or nitric oxide, as applicable, sh all be used for preparing calibration gas mixtures under Performance Specification 2 of appendix B to this part. (3) For affected facilities burning fossil fuel(s), the span value for a continuous monitoring system measuring the opacity of emissions shall be 80, 90, or 100 percent. For a continuous monitoring system measuring sulfur oxides or NO X the span value shall be determined using one of the following procedures: (i) Except as provided under paragr aph (c)(3)(ii) of this section, SO 2 and NO X span values shall be determined as follows:Fossil fuel In parts per million
Span value for SO 2 Span value for NO X Gas ( 1 ) 500.
Liquid 1,000 500.

Solid 1,500 1,000.
Combinations 1,000y + 1,500z 500 (x + y) + 1,000z.

1 Not applicable.

Where: x = Fraction of total heat input derived from gaseous fossil fuel; y = Fraction of total heat input de rived from liquid fossil fuel; and z = Fraction of total heat input derived from solid fossil fuel. (ii) As an alternative to meeting the requirements of paragraph (c)(3)(i) of this section, the owner or operator of an affected facility may elect to use the SO 2 and NO X span values determined according to sections 2.1.1 and 2.1.2 in appendi x A to part 75 of this chapter. (4) All span values computed under paragraph (c)(3)(i) of this section for burning combinations of fossil fuels shall be rounded to the nearest 500 ppm. Span values that are computed under paragraph (c)(3)(ii) of this section shall be rounded off accor ding to the applicable proc edures in section 2 of appendix A to part 75 of this chapter. (5) For a fossil-fuel-fired steam ge nerator that simultaneously burns fossil fuel and nonfossil fuel, the span value of all CEMS shall be subject to the Administrator's approval. (d) [Reserved] (e) For any CEMS installed under paragraph (a) of th is section, the following conversion procedures shall be used to convert the continuous monitoring data into units of the applicable standards (ng/J, lb/MMBtu): (1) When a CEMS for measuring O 2 is selected, the measurement of the pollutant concentration and O 2 concentration shall each be on a consistent basis (wet or dry). Alternative procedures approved by the Administrator shall be used when measurements are on a wet basis. When measurements are on a dry basis, the following conversion procedure shall be used:

Where E, C, F, and %O 2 are determined under paragraph (f) of this section. The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted . Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.(2) When a CEMS for measuring CO 2 is selected, the measurement of the pollutant concentration and CO 2 concentration shall each be on a consistent ba sis (wet or dry) and the following conversion procedure shall be used:

Where E, C, F c and %CO 2 are determined under paragr aph (f) of this section. (f) The values used in the equations under paragraphs (e)(1) and (2) of this section are derived as follows: (1) E = pollutant emissions, ng/J (lb/MMBtu). (2) C = pollutant concentration, ng/dscm (lb/dscf), determined by multiplying the average concentration (ppm) for each one-hour period by 4.15 × 10 4 M ng/dscm per ppm (2.59 × 10 − 9 M lb/dscf per ppm) where M = pollutant molecular weight, g/g-mole (lb/lb-mole). M = 64.07 for SO 2 and 46.01 for NO X . (3) %O 2 , %CO 2 = O 2 or CO 2 volume (expressed as percent), determined with equipment specified under paragraph (a) of this section. (4) F, F c = a factor representing a ratio of the volume of dry flue gases generated to the calorific value of the fuel combusted (F), and a factor representing a ratio of the volume of CO 2 generated to the calorific value of the fuel combusted (F c ), respectively. Values of F and F c are given as follows: (i) For anthracite coal as classified according to ASTM D388 (incorporated by reference, see §60.17), F = 2,723 × 10 − 17 dscm/J (10,140 dscf/MMBtu) and F c = 0.532 × 10 − 17 scm CO 2 /J (1,980 scf CO 2 /MMBtu). (ii) For subbituminous and bituminous coal as cl assified according to ASTM D388 (incorporated by reference, see §60.17), F = 2.637 × 10 − 7 dscm/J (9,820 dscf/MMBtu) and F c = 0.486 × 10 − 7 scm CO 2 /J (1,810 scf CO 2 /MMBtu). (iii) For liquid fossil fuels including crude, residual, and distillate oils, F = 2.476 × 10 − 7 dscm/J (9,220 dscf/MMBtu) and F c = 0.384 × 10 − 7 scm CO 2 /J (1,430 scf CO 2 /MMBtu). (iv) For gaseous fossil fuels, F = 2.347 × 10 − 7 dscm/J (8,740 dscf/MMBtu). For natural gas, propane, and butane fuels, F c = 0.279 × 10 − 7 scm CO 2 /J (1,040 scf CO 2 /MMBtu) for natural gas, 0.322 × 10 − 7 scm CO 2 /J (1,200 scf CO 2 /MMBtu) for propane, and 0.338 × 10 − 7 scm CO 2 /J (1,260 scf CO 2 /MMBtu) for butane. (v) For bark F = 2.589 × 10 − 7 dscm/J (9,640 dscf/MMBtu) and F c = 0.500 × 10 − 7 scm CO 2 /J (1,840 scf CO 2 /MMBtu). For wood residue other than bark F = 2.492 × 10 − 7 dscm/J (9,280 dscf/MMBtu) and F c = 0.494 × 10 − 7 scm CO 2 /J (1,860 scf CO 2 /MMBtu). (vi) For lignite coal as classifi ed according to ASTM D388 (incorporated by reference, see §60.17), F = 2.659 × 10 − 7 dscm/J (9,900 dscf/MMBtu) and F c = 0.516 × 10 − 7 scm CO 2 /J (1,920 scf CO 2 /MMBtu). The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted . Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.(5) The owner or operator may use the following e quation to determine an F factor (dscm/J or dscf/MMBtu) on a dry basis (if it is desired to calculate F on a wet basis, consult the Administrator) or Fc factor (scm CO 2 /J, or scf CO 2 /MMBtu) on either basis in lieu of the F or F c factors specified in paragraph (f)(4) of this section:

(i) %H, %C, %S, %N, and %O are content by weig ht of hydrogen, carbon, sulfur, nitrogen, and O 2 (expressed as percent), respectively, as determined on the same basis as GCV by ultimate analysis of the fuel fired, using ASTM D3178 or D3176 (solid fuels), or computed from results using ASTM D1137, D1945, or D1946 (gaseous fuels) as applic able. (These five methods are incorporated by reference, see §60.17.) (ii) GVC is the gross calorific value (kJ/kg, Btu/lb) of the fuel combusted determined by the ASTM test methods D2015 or D5865 for solid fuels and D1 826 for gaseous fuels as ap plicable. (These three methods are incorporated by reference, see §60.17.) (iii) For affected facilities which fire both fossil fuels and nonfossil fuels, the F or Fc value shall be subject to the Administrator's approval. (6) For affected facilities firing combinations of fossil fuels or fossil fuels and wood residue, the F or Fc factors determined by paragraphs (f)(4) or (f)(5) of this section shall be pr orated in accordance with the applicable formula as follows:

Where:

X i = Fraction of total heat input derived from each type of fuel (e.g. natural gas, bituminous coal, wood residue, etc.);

F i or (F c ) i = Applicable F or F c factor for each fuel type determined in accordance with paragraphs (f)(4) and (f)(5) of this section; and The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted . Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.

The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted . Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.n = Number of fuels being burned in combination. (g) Excess emission and monitoring system performance reports shall be submitted to the Administrator semiannually for each six-month pe riod in the calendar year. All semiannual reports shall be postmarked by the 30th day following the end of each six-month period. Each excess emission and MSP report shall include the information requir ed in §60.7(c). Periods of excess emissions and monitoring systems (MS) downtime that sh all be reported are defined as follows: (1) Opacity . Excess emissions are defined as any six-mi nute period during which the average opacity of emissions exceeds 20 percent opacity, except that one six-minute average per hour of up to 27 percent opacity need not be reported. (i) For sources subject to the opacity standard of §60.42(b)(1), excess emission s are defined as any sixminute period during which the average opacity of emissions exceeds 35 percent opacity, except that one six-minute average per hour of up to 42 percent opacity need not be reported. (ii) For sources subject to the opacity standard of §60.42(b)(2), excess emissions are defined as any six-minute period during which the average opacity of emissions exceeds 32 percent opacity, except that one six-minute average per hour of up to 39 percent opacity need not be reported. (2) Sulfur dioxide. Excess emissions for affected facilities are defined as: (i) For affected facilities electing not to comply w ith §60.43(d), any three-hour period during which the average emissions (arithmetic average of three contiguous one-hour periods) of SO 2 as measured by a CEMS exceed the applicable standard in §60.43; or (ii) For affected facilities electing to comply with §60.43(d), any 30 operating day period during which the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of SO 2 as measured by a CEMS exceed the applicable st andard in §60.43. Facilities complying with the 30-day SO 2 standard shall use the most current associated SO 2 compliance and monitoring requirements in §§60.48Da and 60.49Da of subpart Da of this partor §§60.45b and 60.47b of subpart Db of this part, as applicable. (3) Nitrogen oxides. Excess emissions for affected facilities using a CEMS for measuring NO X are defined as: (i) For affected facilities electing not to comply w ith §60.44(e), any three-hour period during which the average emissions (arithmetic average of three c ontiguous one-hour periods) exceed the applicable standards in §60.44; or (ii) For affected facilities electing to comply with §60.44(e), any 30 operating day period during which the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of NO X as measured by a CEMS exceed the applicable st andard in §60.44. Facilities complying with the 30-day NO X standard shall use the most current associated NO X compliance and monitoring requirements in §§60.48Da and 60.49Da of subpart Da of this part. (4) Particulate matter. Excess emissions for affected facilities using a CEMS for measuring PM are defined as any boiler operating day period during which the average emissions (arithmetic average of all operating one-hour periods) exceed the applicable standards in §60.42. Affe cted facilities using PM CEMS must follow the most current applicable compliance and monitoring provisions in §§60.48Da and 60.49Da of subpart Da of this part.(h) The owner or operator of an affected facility subject to the opacity limits in §60.42 that elects to monitor emissions according to the requirements in§60.45(b)(7) shall maintain records according to the requirements spec ified in paragraphs (h)(1) through (3) of this section, as applicable to the visible emissions monitoring method used. (1) For each performance test condu cted using Method 9 of appendix A–4 of this part, the owner or operator shall keep the records including the informat ion specified in paragraphs (h)(1)(i) through (iii) of this section. (i) Dates and time intervals of all opacity observation periods; (ii) Name, affiliation, and copy of current visi ble emission reading certification for each visible emission observer participating in the performance test; and (iii) Copies of all visible emission observer opacity field data sheets; (2) For each performance test condu cted using Method 22 of appendix A–4 of this part, the owner or operator shall keep the records including the informat ion specified in paragraphs (h)(2)(i) through (iv) of this section. (i) Dates and time intervals of all visible emissions observation periods; (ii) Name and affiliation for each visible emission observer participating in the performance test; (iii) Copies of all visible emission ob server opacity field data sheets; and (iv) Documentation of any adjustments made and the time the adjustments were completed to the affected facility operation by the owner or operator to demonstrate compliance with the applicable monitoring requirements. (3) For each digital opacity compliance system, th e owner or operator shall maintain records and submit reports according to the requirements specified in the site-specific monitoring plan approved by the Administrator.Subpart Da—Standards of Performance for Electr ic Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978

§60.48Da Compliance provisions. (a) Compliance with the PM emission limitation under §60.42Da(a)(1) constitutes compliance with the percent reduction requirements for PM under §60.42Da(a)(2) and (3). (b) Compliance with the NO X emission limitation under §60.44Da(a)(1) constitutes compliance with the percent reduction requirem ents under §60.44Da(a)(2). (c) The PM emission standards under §60.42Da, and the NO X emission standards under §60.44Da
, and the Hg emission standards under §60.45Daapply at all times except during periods of startup, shutdown, or malfunction. The sulfur dioxide emission standards under §60.43Da apply at all times except during periods of startup, shutdown, or when both emergency conditions exist and the procedures under paragraph (d) of this section are implemented. (d) During emergency conditions in the principal company, an affected facility with a malfunctioning flue gas desulfurization sy stem may be operated if SO 2 emissions are minimized by: (1) Operating all operable flue gas desulfurization system modules, and bringing back into operation any malfunctioned module as soon as repairs are completed, (2) Bypassing flue gases around only those flue gas desulfurization system modules that have been taken out of operation because they were incapable of any SO 2 emission reduction or which would have suffered significant physical damage if they had remained in operation, and (3) Designing, constructi ng, and operating a spare flue gas desulfurization system module for an affected facility larger than 365 MW (1,250 MMBtu/hr) heat input (approximately 125 MW electrical output capacity). The Administrator may at his discre tion require the owner or operator within 60 days of notification to demonstrate spar e module capability. To demonstrate this capability, the owner or operator must demonstrate compliance with th e appropriate requirements under paragraph under §60.43Da(a), (b), (d), (e), and (h) for any period of operation lasting from 24 hours to 30 days when: (i) Any one flue gas desulfurization module is not operated, (ii) The affected facility is operating at the maximum heat input rate, (iii) The fuel fired during the 24-hour to 30-day peri od is representative of the type and average sulfur content of fuel used over a typical 30-day period, and (iv) The owner or operator has given the Administrator at least 30 days notice of the date and period of time over which the demonstration will be performed. (e) After the initial performa nce test required under §60.8, compliance with the SO 2 emission limitations and percenta ge reduction requi rements under §60. 43Da and the NO X emission limitations under §60.44Da is based on the average emission rate for 30 successive boiler operating days. A separate performanc e test is completed at the end of each boiler operating day after the initial performance test, and a new 30 day average emission rate for both SO 2 and NO X and a new percent reduction for SO 2 are calculated to show compliance with the standards. (f) For the initial performance test required under §60.8, compliance with the SO 2 emission limitations and percent reduction require ments under §60.43Da and the NO X emission limitation under §60.44Da is based on the average emission rates for SO 2 , NO X , and percent reduction for SO 2 for the first 30 Comment [CF1]: Correct FR error ‐ Never intended to drop the last sentence. The Clean Air Mercury Rule (CAMR) was vacated so the Hg provision is no longer relevant.successive boiler operating days. The initial performance test is the only test in which at least 30 days prior notice is required unless otherwise specified by the Administrator. The initial performance test is to be scheduled so that the first boiler operati ng day of the 30 successive boiler operating days is completed within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility. (g) The owner or operator of an affected facility s ubject to emission limitations in this subpart shall determine compliance as follows: (1) Compliance with applicable 30-day rolling average SO 2 and NO X emission limitations is determined by calculating the arithmetic average of all hourly emission rates for SO 2 and NO X for the 30 successive boiler operating days, except for data obtain ed during startup, shutdown, malfunction (NO X only), or emergency conditions (SO 2 only). (2) Compliance with applicable SO 2 percentage reduction requirements is determined based on the average inlet and outlet SO 2 emission rates for the 30 successive boiler operating days. (3) Compliance with applicable daily average PM emission limitations is determined by calculating the arithmetic average of all hourly emission rates for PM each boiler operating day, except for data obtained during startup, shutdown, and malfunction. Averages are only calculated for boiler operating days that have valid data for at least 18 hours of unit operation during which the standard applies. Instead, all of the valid hourly emission rates of the operating day(s) not meeting the minimum 18 hours valid data daily average requirement are averag ed with all of the valid hourly emission rates of the next boiler operating day with 18 hours or more of valid PM CEMS data to determine compliance. (h) If an owner or operator has not obtained the minimum quantity of emissi on data as required under §60.49Da of this subpart, complianc e of the affected facility with the emission requirements under §§60.43Da and 60.44Da of this subpart for th e day on which the 30-day period ends may be determined by the Administrator by following the applicable procedures in section 7 of Method 19 of appendix A of this part. (i) Compliance provisions for sources subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f) . The owner or operator of an affected facility subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f) shall calculate NO X emissions as 1.194 × 10 − 7 lb/scf-ppm times the average hourly NO X output concentration in ppm (measured according to the provisions of §60.49Da(c)), times the average hourly flow rate (measured in scfh, according to the prov isions of §60.49Da(l) or §60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)). Alternatively, for oil-fi red and gas-fired units, NO X emissions may be calculated by multiplying the hourly NO X emission rate in lb/MMBtu (measured by the CEMS required under §§60.49Da(c) and (d)), by the hourly heat input rate (measured according to the provisions of §60.49Da(n)), and dividing the result by the average gross energy output (measure d according to the provisions of §60.49Da(k)). (j) Compliance provisions for duct burners subject to §60.44Da(a)(1) . To determine compliance with the emissions limits for NO X required by §60.44Da(a) for duct burners used in combined cycle systems, either of the procedures descri bed in paragraph (j)(1) or (2) of this section may be used: (1) The owner or operator of an affected duct burner shall conduct the performa nce test required under §60.8 using the appropriate methods in appendix A of this part. Compliance with the emissions limits under §60.44Da(a)(1) is determined on the average of three (nominal 1-hour) runs for the initial and subsequent performance tests. During the performance test, one sampling site shall be located in the exhaust of the turbine prior to the duct burner. A second sampling site shall be located at the outletfrom the heat recovery steam generating unit. Meas urements shall be taken at both sampling sites during the performance test; or (2) The owner or operator of an affected duct burne r may elect to determine compliance by using the CEMS specified under §60.49Da for measuring NO X and oxygen (O 2 ) (or carbon dioxide (CO 2 )) and meet the requirements of §60.49Da. Alternatively, data from a NO X emission rate ( i.e. , NO X -diluent) CEMS certified according to the provisions of §75.20( c) of this chapter and appendix A to part 75 of this chapter, and meeting the qual ity assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, may be used, with the following caveats. Data used to meet the requirements of §60.51Da shall not include substitute data values de rived from the missing data procedures in subpart D of part 75 of this chapter, nor shall th e data have been bias adjusted according to the procedures of part 75 of this chapter. The sampling site shall be located at the outlet from the steam generating unit. The NO X emission rate at the outlet from the steam generating unit shall constitute the NO X emission rate from the duct burner of the combined cycle system. (k) Compliance provisions for duct burners subject to §60.44Da(d)(1) or (e)(1) . To determine compliance with the emission limitation for NO X required by §60.44Da(d)(1) or (e)(1) for duct burners used in combined cycle systems, either of the proce dures described in paragraphs (k)(1) and (2) of this section may be used: (1) The owner or operator of an affected duct burne r used in combined cycle systems shall determine compliance with the applicable NO X emission limitation in §60.44Da(d)(1) or (e)(1) as follows: (i) The emission rate (E) of NO X shall be computed using Equation 2 in this section:

Where:
E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross output;
C sg = Average hourly concentration of NO X exiting the steam generating unit, ng/dscm (lb/dscf);
C te = Average hourly concentration of NO X in the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf); Q sg = Average hourly volumetric flow rate of e xhaust gas from steam generating unit, dscm/hr (dscf/hr); Q te = Average hourly volumetric flow rate of exhaust gas from combustion turbine, dscm/hr (dscf/hr);
O sg = Average hourly gross energy output from steam generating unit, J (MWh); and h = Average hourly fraction of the total heat input to the steam generating unit derived from the combustion of fuel in the affected duct burner. (ii) Method 7E of appendix A of this part shall be used to determine the NO X concentrations (C sg and C te ). Method 2, 2F or 2G of appendix A of this part, as appropriate, shall be used to determine the volumetric flow rates (Q sg and Q te ) of the exhaust gases. The volumetric flow rate measurements shall be taken at the same time as the concentration measurements. (iii) The owner or operator shall develop, demons trate, and provide information satisfactory to the Administrator to determine the average hourly gro ss energy output from the steam generating unit, and The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted . Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.the average hourly percentage of the total heat input to the steam generating unit derived from the combustion of fuel in the affected duct burner. (iv) Compliance with the applicable NO X emission limitation in §60.44Da(d )(1) or (e)(1) is determined by the three-run average (nominal 1-hour runs) fo r the initial and subseque nt performance tests. (2) The owner or operator of an affected duct burner used in a combined cycle system may elect to determine compliance with the applicable NO X emission limitation in §60.44 Da(d)(1) or (e)(1) on a 30- day rolling average basis as indicated in paragraphs (k)(2)(i) through (iv) of this section. (i) The emission rate (E) of NO X shall be computed using Equation 3 in this section:

Where:
E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross output;
C sg = Average hourly concentration of NO X exiting the steam generating unit, ng/dscm (lb/dscf); Q sg = Average hourly volumetric flow rate of e xhaust gas from steam generating unit, dscm/hr (dscf/hr); and
O cc = Average hourly gross energy output from entire combined cycle unit, J (MWh). (ii) The CEMS specified u nder §60.49Da for measuring NO X and O 2 (or CO 2 ) shall be used to determine the average hourly NO X concentrations (C sg ). The continuous flow monitoring system specified in §60.49Da(l) or §60.49Da(m) shall be used to determine the volumetric flow rate (Q sg ) of the exhaust gas. If the option to use the flow mon itoring system in §60.49Da(m) is selected, the flow rate data used to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. The sampling site shall be located at the outlet from the steam generating unit. (iii) The continuous monitoring system specified under §60.49Da(k) for measuring and determining gross energy output shall be used to determine the average hourly gross energy output from the entire combined cycle unit (O cc ), which is the combined output from the combustion turbine and the steam generating unit. (iv) The owner or operator may, in lieu of installi ng, operating, and recordi ng data from the continuous flow monitoring system specified in §60.49 Da(l), determine the mass rate (lb/hr) of NO X emissions by installing, operating, and maintaining conti nuous fuel flowmeters fo llowing the appropriate measurements procedures specified in appendix D of part 75 of this chapter. If this compliance option is selected, the emission rate (E) of NO X shall be computed using Equation 4 in this section:

Where:
E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross output; The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted . Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.

The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted . Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.ER sg = Average hourly emission rate of NO X exiting the steam generating unit heat input calculated using appropriate F factor as described in Method 19 of appendix A of this part, ng/J (lb/MMBtu);

H cc = Average hourly heat input rate of entire combined cycle unit, J/hr (MMBtu/hr); and
O cc = Average hourly gross energy output from entire combined cycle unit, J (MWh). (3) When an affected duct burner steam generating unit utilizes a common steam turbine with one or more affected duct burner steam generating units, the owner or operator shall either: (i) Determine compliance with the applicable NO X emissions limits by me asuring the emissions combined with the emissions from the other unit(s) utilizing the common steam turbine; or (ii) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined gross energy output from the steam turbine for each of the affected duct burners. The Administrator may approve such dem onstrated substitute methods for apportioning the combined gross energy output measured at the steam turbine whenever the demonstration ensures accurate estimation of emissions regulated under this part. (l) Compliance provisions for sources subject to §60.45Da. The owner or operator of an affected facility subject to §60.45Da (new sources constructed or reconstructed after January 30, 2004) shall calculate the Hg emission rate (lb/MWh) for each calendar month of the year, using hourly Hg concentrations measured according to the provisions of §60.49Da(p) in conjunction with hourly stack gas volumetric flow rates measured according to the provisions of §60.49Da(l) or (m), and hourly gross electrical outputs, determined according to the provisions in §60.49Da(k). Compliance with the applicable standard under §60. 45Da is determined on a 12-m onth rolling average basis. (m) Compliance provisions for sources subject to §60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), or (j)(3)(i). The owner or operator of an affected fac ility subject to §60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), or (j)(3)(i) shall calculate SO 2 emissions as 1.660 × 10 –7 lb/scf-ppm times the average hourly SO 2 output concentration in ppm (measured according to the provisions of §60.49Da(b)), times the average hourly flow rate (m easured according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)) . Alternatively, for oil-fi red and gas-fired units, SO 2 emissions may be calculated by multiplying the hourly SO 2 emission rate (in lb/MMBtu), measured by the CEMS required under §60.49Da, by the hourly heat input rate (measured according to the provisions of §60.49Da(n)), and dividing the result by the average gross energy output (measured according to the provisions of §60.49Da(k)). (n) Compliance provisions for sources subject to §60.42Da(c)(1) . The owner or operator of an affected facility subject to §60.42Da(c)(1) shall calculate PM emissions by multiplying the average hourly PM output concentration (measured according to the provisions of §60.49Da(t)), by the average hourly flow rate (measured according to the provis ions of §60.49Da(l) or §60.49Da(m)), and divided by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)). Compliance with the emission limit is determined by calculating the arithmetic average of the hourly emission rates computed for each boiler operating day. (o) Compliance provisions for sources subject to §60.42Da(c)(2) or (d) . Except as provided for in paragraph (p) of this section, the owner or operator of an affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, shall demonstrate compliance with each applicable emission limit according to the requirements in paragraphs (o)(1) through (o)(5) of this section.(1) You must conduct a performance test to demonstrate initial compliance with the applicable PM emissions limit in §60.42Da(c)(2) or (d) by the app licable date specified in §60.8(a). Thereafter, you must conduct each subsequent performance test w ithin 12 calendar months following the date the previous performance test was re quired to be conducted. You must conduct each performance test according to the requirements in §60.8 using the te st methods and procedures in §60.50Da. The owner or operator of an affected facility that has not operated for 60 consecutive ca lendar days prior to the date that the subsequent performanc e test would have been required had the unit been operating is not required to perform the subsequent performance te st until 30 calendar days after the next boiler operating day. Requests for additional 30 day extensi ons shall be granted by the relevant air division or office director of the appropriate Regional Office of the U.S. EPA. (2) You must monitor the performance of each elec trostatic precipitator or fabric filter (baghouse) operated to comply with the applicable PM emissions limit in §60.42Da(c)(2) or (d) using a continuous opacity monitoring system (COMS) according to the requirements in paragraphs (o)(2)(i) through (vi) unless you elect to comply with one of the alternatives provided in paragraphs (o)(3) and (o)(4) of this section, as applicable to your control device. (i) Each COMS must meet Performance Specif ication 1 in 40 CFR part 60, appendix B. (ii) You must comply with the quality assurance requirements in paragraphs (o)(2)(ii)(A) through (E) of this section. (A) You must automatically (intrinsic to the opa city monitor) check the zero and upscale (span) calibration drifts at least once daily. For a particular COMS, the acceptable range of zero and upscale calibration materials is as defined in the applicable version of Performance Specification 1 in 40 CFR part 60, appendix B. (B) You must adjust the zero and span whenever the 24-hour zero drift or 24-hour span drift exceeds 4 percent opacity. The COMS must allow for the amount of excess zero and span drift measured at the 24-hour interval checks to be recorded and quanti fied. The optical surfaces exposed to the effluent gases must be cleaned prior to performing the zero and span drift adjustments, except for systems using automatic zero adjustments. For systems using automatic zero adjustments, the optical surfaces must be cleaned when the cumulative automatic zero compensation exceeds 4 percent opacity. (C) You must apply a method for producing a simu lated zero opacity condition and an upscale (span) opacity condition using a certified neutral density filter or other related technique to produce a known obscuration of the light beam. All procedures app lied must provide a system check of the analyzer internal optical surfaces and all electronic circ uitry including the lamp and photodetector assembly. (D) Except during periods of system breakdowns , repairs, calibration checks, and zero and span adjustments, the COMS must be in continuous operation and must complete a minimum of one cycle of sampling and analyzing for each successive 10 second period and one cycle of data recording for each successive 6-minute period. (E) You must reduce all data from the COMS to 6-mi nute averages. Six-minute opacity averages must be calculated from 36 or more data points equall y spaced over each 6-minute period. Data recorded during periods of system breakdowns, repairs, ca libration checks, and zero and span adjustments must not be included in the data averages. An arithmetic or integrated average of all data may be used. (iii) During each performance test conducted according to paragraph (o )(1) of this section, you must establish an opacity baseline level. The value of the opacity baseline level is determined by averaging all of the 6-minute average opacity values (reported to the nearest 0.1 percent opacity) from the COMS measurements recorded during each of the test run intervals conducted for the performance test, andthen adding 2.5 percent opacity to your calculated aver age opacity value for all of the test runs. If your opacity baseline level is less than 5.0 percent, then the opacity baseline level is set at 5.0 percent. (iv) You must evaluate the preceding 24-hour aver age opacity level measured by the COMS each boiler operating day excluding periods of affected fa cility startup, shutdown, or malfunction. If the measured 24-hour average opacity emission level is greater than the baseline opacity level determined in paragraph (o)(2)(iii) of this section, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first disc overy of the high opacity incident and take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the measured 24-hour average opacity to a level below the baseline opacity level. In cases when a wet scrubber is used in combinat ion with another PM control device that serves as the primary PM control device, the wet scrubber mu st be maintained and operated. (v) You must record the opacity measurements, calculations performed, and any corrective actions taken. The record of corrective action taken must in clude the date and time during which the measured 24-hour average opacity was greater than baseline opacity level, and the date, time, and description of the corrective action. (vi) If the measured 24-hour average opacity for your affected facility remains at a level greater than the opacity baseline level after 7 boiler operating days, then you must conduct a new PM performance test according to paragraph (o)(1) of this section and establish a new opacity baseline value according to paragraph (o)(2) of this section. This new performa nce test must be conducted within 60 days of the date that the measured 24-hour average opacity wa s first determined to exceed the baseline opacity level unless a waiver is granted by the permitting authority. (3) As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner or operator may elect to monitor the performance of an electrostatic precipitator (ESP) operated to comply with the applicable PM emissions limit in §60.42Da(c)(2) or (d) using an ESP predictive model developed in accorda nce with the requirements in paragraphs (o)(3)(i) through (v) of this section. (i) You must calibrate the ESP predictive model with each PM control device used to comply with the applicable PM emissions limit in §60.42Da(c)(2) or (d) operating under norm al conditions. In cases when a wet scrubber is used in combination with anESP to comply with the PM emissions limit, the wet scrubber must be maintained and operated. (ii) You must develop a s ite-specific monitoring plan that includes a description of the ESP predictive model used, the model input parame ters, and the procedures and crite ria for establishing monitoring parameter baseline levels indicative of compliance with the PM emissions limit. You must submit the site-specific moni toring plan for approval by the permitting authority. For reference purposes in preparing the monitoring plan, see the OAQPS “C ompliance Assurance Mon itoring (CAM) Protocolfor an Electrostatic Precipitator (ESP) Controlling Particulate Matter (PM) Emissions from a CoalFired Boiler.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality Planning and Standards; Sector Policies and Programs Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Continuous Emission Monitoring. (iii) You must run the ESP predictive model using the applicable input data each boiler operating day and evaluate the model output for the preceding boile r operating day excluding periods of affected facility startup, shutdown, or malfunction. If the values for one or more of the model parametersexceed the applicable baseline levels determined according to your approved site-specific monitoring plan, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of a model parame ter deviation and, take the appropriate correc tive action as soon as practicable to adjust control settings or repair equipment to return the model output to within the applicable baseline levels. (iv) You must record the ESP predictive model inpu ts and outputs and any co rrective actions taken. The record of corrective action taken must include the date and time during which the model output values exceeded the applicable baseline levels, and the date, time, and description of the corrective action. (v) If after 7 consecutive days a model parameter continues to exceed the applicable baseline level, then you must conduct a new PM perf ormance test according to paragrap h (o)(1) of this section. This new performance test must be con ducted within 60 calendar days of the date that the model parameter was first determined to exceed its baseline level unless a waiver is granted by the permitting authority. (4) As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner or operator may elect to monitor the performance of a fabric filter (baghouse) operated to comply with the applicable PM emissions limit in §60.42Da(c)(2) or (d) by using a bag leak detection system according to the requirements in paragraphs (o)(4)(i) through (v) of this section. (i) Each bag leak detection system must meet the specifications and requirements in paragraphs (o)(4)(i)(A) through (H) of this section. (A) The bag leak detection system mu st be certified by the manufacture r to be capable of detecting PM emissions at concentrations of 1 milligram per actu al cubic meter (0.00044 grains per actual cubic foot) or less. (B) The bag leak detection system sensor must pr ovide output of relative PM loadings. The owner or operator must continuously record the output from the bag leak detection system using electronic or other means ( e.g. , using a strip chart recorder or a data logger.) (C) The bag leak detection system must be equipped with an alarm system that will react when the system detects an increase in relative particulate loading over the alarm set point established according to paragraph (o)(4)(i)(D) of this section, and the alarm must be located such that it can be noticed by the appropriate plant personnel. (D) In the initial adjustment of the bag leak detection system, you must establish, at a minimum, the baseline output by adjusting the sens itivity (range) and the averaging period of the device, the alarm set points, and the alarm delay time. (E) Following initial adjustment, you must not adjust the averaging period, alarm set point, or alarm delay time without approval from the permitting auth ority except as provided in paragraph (d)(1)(vi) of this section. (F) Once per quarter, you may adjust the sensitivity of the bag leak detection system to account for seasonal effects, including temperature and humidity, ac cording to the procedures identified in the sitespecific monitoring plan required by paragraph (o)(4)(ii) of this section. (G) You must install the bag leak detection sensor do wnstream of the fabric filter and upstream of any wet scrubber. (H) Where multiple detectors are required, the system's instrumentation and alarm may be shared among detectors.(ii) You must develop and submit to the permitting authority for approval a site-specific monitoring plan for each bag leak detection system. You must operate and maintain the bag leak detection system according to the site-specific monitoring plan at all times. Each monitoring plan must describe the items in paragraphs (o)(4)(ii)(A) through (F) of this section. (A) Installation of the bag leak detection system; (B) Initial and periodic adjustment of the bag leak detection system, including how the alarm set-point will be established; (C) Operation of the bag leak detection syst em, including quality assurance procedures; (D) How the bag leak detection system will be maintained, including a routine maintenance schedule and spare parts inventory list; (E) How the bag leak detection system output will be recorded and stored; and (F) Corrective action procedures as specified in paragr aph (o)(4)(iii) of this section. In approving the site-specific moni toring plan, the permitting authority may allow owners and operators more than 3 hours to alleviate a specific condition that causes an alarm if the owner or operator identifies in the monitoring plan this specific condition as one that could lead to an alarm, adequately explains why it is not feasible to alleviate this condition within 3 hours of the time the alarm occurs, and demonstrates that the requested time will ensure alleviation of this condition as expe ditiously as practicable. (iii) For each bag leak detection system, you must initiate procedures to determine the cause of every alarm within 1 hour of the alarm. Except as provid ed in paragraph (o)(4)(ii)(F) of this section, you must alleviate the cause of the alarm within 3 hours of the alarm by taking whatever corrective action(s) are necessary. Corrective actions may include, but are not limited to the following: (A) Inspecting the fabric filter for air leaks, torn or broken bags or filter media, or any other condition that may cause an increase in particulate emissions; (B) Sealing off defective bags or filter media; (C) Replacing defective bags or filter media or otherwise repairing the control device; (D) Sealing off a defective fabric filter compartment; (E) Cleaning the bag leak detectio n system probe or otherwise repairing the bag leak detection system;

or (F) Shutting down the process produci ng the particulate emissions. (iv) You must maintain records of the information specified in paragraphs (o)(4)(iv)(A) through (C) of this section for each bag leak detection system. (A) Records of the bag leak detection system output; (B) Records of bag leak detection system adjustment s, including the date and time of the adjustment, the initial bag leak detection system settings, and the final bag leak detection system settings; and (C) The date and time of all bag leak detection system alarms, the time that procedures to determine the cause of the alarm were initiated, if procedures were initiated within 1 hour of the alarm, the cause of the alarm, an explanation of the actions take n, the date and time the cause of the alarm was alleviated, and if the alarm was alleviated within 3 hours of the alarm. (v) If after any period composed of 30 boiler ope rating days during which the alarm rate exceeds 5 percent of the process operating tim e (excluding control device or process startup, shutdown, andmalfunction), then you must conduct a new PM performance test according to paragraph (o)(1) of this section. This new performance test must be conducted within 60 calendar days of the date that the alarm rate was first determined to exceed 5 percent limit unless a waiver is granted by the permitting authority. (5) An owner or operator of a modified affected fa cility electing to meet the emission limitations in §60.42Da(d) shall determine the percent reduction in PM by using the emission rate for PM determined by the performance test conducted accordi ng to the requirements in pa ragraph (o)(1) of this section and the ash content on a mass basis of the fuel burned during each performance test run as determined by analysis of the fuel as fired. (p) As an alternative to meeting the compliance provisions specified in paragraph (o) of this section, an owner or operator may elect to install, evaluate, maintain, and operate a CEMS measuring PM emissions discharged from the affected facility to the atmosphere and record the output of the system as specified in paragraphs (p)(1) through (p)(8) of this section. (1) The owner or operator shall submit a written notification to the Administrator of intent to demonstrate compliance with this subpart by using a CEMS measuring PM. This notification shall be sent at least 30 calendar days before the initial startup of the monitor for compliance determination purposes. The owner or operator may discontinue operation of the monitor and instead return to demonstration of compliance with this subpart accord ing to the requirements in paragraph (o) of this section by submitting written notification to the Administrator of such intent at least 30 calendar days before shutdown of the monitor for compliance determination purposes. (2) Each CEMS shall be installed, evaluated, operated, and maintained according to the requirements in §60.49Da(v). (3) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under §60. 8 of subpart A of this part or within 180 days of the date of notification to the Administrator required under paragraph (p)(1) of this section, whichever is later. (4) Compliance with the applicable emissions lim it shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emissions concentrations using the continuous monitoring system outlet data. The 24-hour block ar ithmetic average emission concentration shall be calculated using EPA Referenc e Method 19 of appendix A of this part, section 4.1. (5) At a minimum, valid CEMS hourly averages shall be obtained for 75 percent of all operating hours on a 30-day rolling average basis. Beginning on Janua ry 1, 2012, valid CEMS hourly averages shall be obtained for 90 percent of all operating hours on a 30-day rolling average basis. (i) At least two data points per h our shall be used to calculate each 1-hour arithmetic average. (ii) [Reserved] (6) The 1-hour arithmetic averages required shall be expressed in ng/J, MMBtu/hr, or lb/MWh and shall be used to calculate the boiler operating day daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be calculated us ing the data points required under §60.13(e)(2) of subpart A of this part. (7) All valid CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (j)(5) of this section are not met.(8) When PM emissions data are not obtained be cause of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, valid emissi ons data for a minimum of 90 percent (only 75 percent is required prior to January 1, 2012) of all operating hours per 30-day rolling average. (q) Compliance provisions for sources subject to §60.42Da(b) . An owner or operator of an affected facility subject to the opacity standard in §60. 42Da(b) shall monitor the opacity of emissions discharged from the affected facility to the atmosphere according to the requirements in §60.49Da(a), as applicable to the affected facility. §60.49Da Emission monitoring. (a) An owner or operator of an affected facility subject to the opacity standard in §60.42Da(b) shall monitor the opacity of emissions discharged from the affected facility to the atmosphere according to the applicable requirements in paragraphs (a)(1) through (3) of this section. (1) Except as provided for in paragraph (a)(2) of this section, the owner or operator of an affected facility, shall install, calibrate, maintain, and operate a COMS, and record the output of the system, for measuring the opacity of emissions discharged to the atmosphere. If opacity interference due to water droplets exists in the stack (for example, from th e use of an FGD system), the opacity is monitored upstream of the interference (at the inlet to the FGD system). If opacity interference is experienced at all locations (both at the inlet and outlet of the SO 2 control system), alternate parameters indicative of the PM control system's performa nce and/or good combustion are monitored (subject to the approval of the Administrator). (2) As an alternative to the monitoring requirements in paragraph (a)(1) of this section, an owner or operator of an affected facility that meets the conditions in either paragraph (a)(2)(i), (ii), or (iii) of this section may elect to monitor opacity as specified in paragraph (a)(3) of this section. (i) The affected facility uses a fabr ic filter (baghouse) to meet the st andards in §60.42Da and a bag leak detection system is installed and operated according to the requirements in paragraphs §60.48Da(o)(4)(i) through (v); (ii) The affected facility burns only gaseous or liquid fuels (excluding residual oil) with potential SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion technology to reduce emissions of SO 2 or PM; or (iii) The affected facility meets all of the conditions specified in paragraphs (a)(2)(iii)(A) through (C) of this section. (A) No post-combustion technology (except a wet scrubber) is used for reducing PM, SO 2 , or carbon monoxide (CO) emissions; (B) Only natural gas, gaseous fuels, or fuel oils th at contain less than or e qual to 0.30 weight percent sulfur are burned; and (C) Emissions of CO discharged to the atmosphere are maintained at levels less than or equal to 1.4 lb/MWh on a boiler operating day average basis as de monstrated by the use of a CEMS measuring CO emissions according to the procedures speci fied in paragraph (u) of this section. (3) The owner or operators of an affected facility that meets the conditions in paragraph (a)(2) of this section may, as an alternative to using a COMS, elect to monitor visible emissions using the applicable procedures specified in paragraphs (a )(3)(i) through (iv) of this section. The opacity performance testrequirement in paragraph (a)(3)(i) must be conducte d by April 29, 2011, within 45 days after stopping use of an existing COMS, or within 180 days after initial startup of the facility, whichever is later. The permitting authority may exempt owne rs or operators of affected faci lities burning only natural gas from the opacity monitoring requirements. (i) The owner or operator shall conduct a performance test using Method 9 of appendix A–4 of this part and the procedures in §60.11. If during the init ial 60 minutes of the observation all the 6-minute averages are less than 10 percent and all the indivi dual 15-second observations are less than or equal to 20 percent, then the observation period may be reduced from 3 hours to 60 minutes. (ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this section, the owner or operator shall conduct subsequent Me thod 9 of appendix A–4 of this part performance tests using the procedures in paragraph (a)(3)(i) of this section according to the applicable schedule in paragraphs (a)(3)(ii)(A) through (a)(3)(ii)(D) of this section, as determined by the most recent Method 9 of appendix A–4 of this part performance test results. (A) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted; (B) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 6 calendar months from the date that th e most recent performance test was conducted; (C) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A–4 of this part perf ormance test must be completed within 3 calendar months from the date that the most recent performance test was conducted; or (D) If the maximum 6-minute average opacity is greater than 10 perc ent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 30 45 calendar days from the date that the most recent pe rformance test was conducted. (iii) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owne r or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 of this part performance tests, elect to perform subsequent monitoring using Method 22 of appe ndix A–7 of this part according to the procedures specified in paragraphs (a)(3)(iii)(A) and (B) of this section. (A) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the affected facility fires fuel for which an opacity standard is applicable using Method 22 of appendix A–7 of this partand demonstrate that the sum of the occurrences of any visible emissions is not in ex cess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the occurrence of visible emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds per 30 minute period) the owner or operator shall either document and adjust the operation of the facility and demonstrate within 24 hours that the su m of the occurrence of visible emissions is equal to or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of appendix A–4 of this part performa nce test using the procedures in paragraph (a)(3)(i) of this section within 30 45 calendar days according to the requirements in §60.50Da(b)(3).(B) If no visible emissions are observed for 30 operating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any vi sible emissions are observed, dail y observations shall be resumed. (iv) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owne r or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 performance tests, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitoring plan approved by the Administrator. The observations shall be similar, but not necessarily identical, to the requirements in paragraph (a)(3)(iii) of this section. For refere nce purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Preliminary Methods. (b) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring SO 2 emissions, except where natural gas is the only fuel combusted, as follows: (1) Sulfur dioxide emissions are monitored at both the inlet and outlet of the SO 2 control device. (2) For a facility that qualifies under the numerical limit provisions of §60.43Da(d), (i), (j), or (k) SO 2 emissions are only monitored as discharged to the atmosphere. (3) An “as fired” fuel monitoring system (upstream of coal pulverizers) meeting the requirements of Method 19 of appendix A of this part may be used to determine potential SO 2 emissions in place of a continuous SO 2 emission monitor at the inlet to the SO 2 control device as re quired under paragraph (b)(1) of this section. (4) If the owner or operator has installed and certified a SO 2 CEMS according to the requirements of §75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the ongoing quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, that CEMS may be used to meet the requirements of this section, provided that: (i) A CO 2 or O 2 continuous monitoring system is installed, calibrated, maintained and operated at the same location, according to paragraph (d) of this section; and (ii) For sources subject to an SO 2 emission limit in lb/MMBtu under §60.43Da: (A) When relative accuracy testing is conducted, SO 2 concentration data and CO 2 (or O 2 ) data are collected simultaneously; and (B) In addition to meeting the applicable SO 2 and CO 2 (or O 2 ) relative accuracy specifications in Figure 2 of appendix B to part 75 of this chapter, the relative accuracy (RA) standard in section 13.2 of Performance Specification 2 in appendix B to this part is met when the RA is calculated on a lb/MMBtu basis; and (iii) The reporting requirements of §60.51Da are met. The SO 2 and, if required, CO 2 (or O 2 ) data reported to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of pa rt 75 of this chapter, nor shall the SO 2 data have been bias adjusted according to the procedures of part 75 of this chapter.(c)(1) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring NO X emissions discharged to the atmosphere; or (2) If the owner or operator has installed a NO X emission rate CEMS to meet the requirements of part 75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that CEMS may be used to meet the requirements of this section, except that th e owner or operator shall also meet the requirements of §60.51Da. Data reported to meet the requirements of §60.51Da shall not include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. (d) The owner or operator of an affected facility not complying with an output based limit shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring the O 2 or carbon dioxide (CO 2 ) content of the flue gases at each location where SO 2 or NO X emissions are monitored. For affected facilities subject to a lb/MMBtu SO 2 emission limit under §60.43Da, if the owner or operator has inst alled and certified a CO 2 or O 2 monitoring system according to §75.20(c) of this chapter and appendix A to part 75 of this chap ter and the monitoring system continues to meet the applicable quality-assurance provisio ns of §75.21 of this chapter and appendix B to part 75 of this chapter, that CEMS may be used together with the part 75 SO 2 concentration monitoring system described in paragraph (b) of this section, to determine the SO 2 emission rate in lb/MMBtu. SO 2 data used to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, norshall the data have been bias adjusted according to the procedures of part 75 of this chapter. (e) The CEMS under paragraphs (b), (c), and (d) of this section are operated and data recorded during all periods of operation of the affected facility in cluding periods of startup, shutdown, malfunction or emergency conditions, except for CEMS breakdowns , repairs, calibration checks, and zero and span adjustments. (f)(1) For units that began construction, reconstruc tion, or modification on or before February 28, 2005, the owner or operator shall ob tain emission data for at least 18 hours in at least 22 out of 30 successive boiler operating days. If this minimum data requirement cannot be met with CEMS, the owner or operator shall supplement emission datawith other monitoring systems approved by the Administrator or the reference methods and procedures as described in paragraph (h) of this section. (2) For units that began construc tion, reconstruction, or modifica tion after February 28, 2005, the owner or operator shall obtain emission data for at le ast 90 percent of all operating hours for each 30 successive boiler operating days. If this minimum data requirement cannot be met with a CEMS, the owner or operator shall supplement emission datawith other monitoring systems approved by the Administrator or the reference methods and procedures as described in paragraph (h) of this section. (g) The 1-hour averages required under paragra ph §60.13(h) are expressed in ng/J (lb/MMBtu) heat input and used to calculate the average emissionrates under §60.48Da. The 1-hour averages are calculated using the data points required under §60.13(h)(2). (h) When it becomes necessary to supplement CEMS data to meet the minimum data requi rements in paragraph (f) of this section, the owner or operator shall use the refe rence methods and procedures as specified in this paragraph. Acce ptable alternative methods and proc edures are given in paragraph (j) of this section. (1) Method 6 of appendix A of this part shall be used to determine the SO 2 concentration at the same location as the SO 2 monitor. Samples shall be taken at 60-minute intervals. The sampling time andsample volume for each sample shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Each sample represents a 1-hour average. (2) Method 7 of appendix A of this part shall be used to determine the NO X concentration at the same location as the NO X monitor. Samples shall be taken at 30-minute intervals. The arithmetic average of two consecutive samples represents a 1-hour average. (3) The emission rate correction factor, integrated bag sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O 2 or CO 2 concentration at the same location as the O 2 or CO 2 monitor. Samples shall be taken for at least 30 minutes in each hour. Each sample represents a 1-hour average. (4) The procedures in Method 19 of appendix A of this part shall be used to compute each 1-hour average concentration in ng/J (lb/MMBtu) heat input. (i) The owner or operator shall use methods and proc edures in this paragrap h to conduct monitoring system performance evaluations under §60.13(c) and calibration checks unde r §60.13(d). Acceptable alternative methods and procedures are gi ven in paragraph (j) of this section. (1) Methods 3B, 6, and 7 of appendix A of this part shall be used to determine O 2 , SO 2 , and NO X concentrations, respectively. (2) SO 2 or NO X (NO), as applicable, shall be used for preparing the calibration gas mixtures (in N 2 , as applicable) under Performance Specificat ion 2 of appendix B of this part. (3) For affected facilities burning only fossil fuel, the span value for a COMS is between 60 and 80 percent. Span values for a CEMS measuring NO X shall be determined using one of the following procedures: (i) Except as provided under paragraph (i)(3)(ii) of this section, NO X span values shall be determined as follows:

Fossil fuel Span values for NO X (ppm)

Gas 500.

Liquid 500.

Solid 1,000.

Combination 500 (x + y) + 1,000z.

Where: x = Fraction of total heat input derived from gaseous fossil fuel, y = Fraction of total heat input de rived from liquid fossil fuel, and z = Fraction of total heat input derived from solid fossil fuel. (ii) As an alternative to meeting the requirements of paragraph (i)(3)(i) of this section, the owner or operator of an affected facility may elect to use the NO X span values determined according to section 2.1.2 in appendix A to part 75 of this chapter.(4) All span values computed under paragraph (i)(3)(i) of this section for burning combinations of fossil fuels are rounded to the nearest 500 ppm. Span va lues computed under paragraph (i)(3)(ii) of this section shall be rounded off according to section 2. 1.2 in appendix A to part 75 of this chapter. (5) For affected facilities burning fossil fuel, alone or in combination with non-fossil fuel and determining span values under pa ragraph (i)(3)(i) of this section, the span value of the SO 2 CEMS at the inlet to the SO 2 control device is 125 percent of the maxi mum estimated hourly potential emissions of the fuel fired, and the outlet of the SO 2 control device is 50 percent of maximum estimated hourly potential emissions of the fuel fired. For affected facilities determining spanvalues under paragraph (i)(3)(ii) of this section, SO 2 span values shall be determined acco rding to section 2.1.1 in appendix A to part 75 of this chapter. (j) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this section: (1) For Method 6 of appendix A of this part, Method 6A or 6B (whenever Methods 6 and 3 or 3B of appendix A of this part data are used) or 6C of appendix A of this part may be used. Each Method 6B of appendix A of this part sample obtained over 24 hours represents 24 1-hour averages. If Method 6A or 6B of appendix A of this part is used under paragraph (i) of this se ction, the conditions under §60.48Da(d)(1) apply; these conditions do not apply under paragraph (h) of this section. (2) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run shall be 1 hour. (3) For Method 3 of appendix A of this part, Method 3Aor 3B of appendix A of this part may be used if the sampling time is 1 hour. (4) For Method 3B of appendix A of this part, Method 3A of appendix A of this part may be used. (k) The procedures specified in paragraphs (k)(1) thr ough (3) of this section sh all be used to determine gross output for sources demonstrating compliance with the output-based standard under §§60.42Da(c), 60.43Da(i), 60.43Da(j), 60.44Da(d)(1), and 60.44Da(e). (1) The owner or operator of an affected facility with electricity generation shall install, calibrate, maintain, and operate a wattmeter; measure gross el ectrical output in MWh on a continuous basis; and record the output of the monitor. (2) The owner or operator of an affected facility with process steam generation shall install, calibrate, maintain, and operate meters for steam flow, temper ature, and pressure; measure gross process steam output in joules per hour (or Btu per hour) on a continuous basis; and record the output of the monitor. (3) For affected facilities generating process steam in combination with electrical generation, the gross energy output is determined from the gross electric al output measured in accordance with paragraph (k)(1) of this section plus 75 percent of the gross thermal output (measured relative to ISO conditions) of the process steam measured in accordan ce with paragraph (k)(2) of this section. (l) The owner or operator of an affected facili ty demonstrating compliance with an output-based standard under §60.42Da, §60.43Da, §60.44Da, or §60.45Da shall install, certify, operate, and maintain a continuous flow monito ring system meeting the requiremen ts of Performance Specification 6 of appendix B of this part and the CD assessment, RATA and reporting provisions of procedure 1 of appendix F of this part, and record the output of the system, for measuring the volumetric flow rate of exhaust gases discharged to the atmosphere; or(m) Alternatively, data from a continuous flow monitoring system certified according to the requirements of §75.20(c) of this ch apter and appendix A to part 75 of this chapter, and continuing to meet the applicable quality control and quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, may be used. Flow rate data reported to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted accor ding to the procedures of part 75 of this chapter. (n) Gas-fired and oil-fired units. The owner or operator of an affected unit that qualifies as a gas-fired or oil-fired unit, as defined in 40 CFR 72.2, may use, as an alternative to the requirements specified in either paragraph (l) or (m) of th is section, a fuel flow monitori ng system certified and operated according to the requirements of appendix D of part 75 of this chapter. (o) The owner or operator of a duct burner, as described in §60.41Da, which is subject to the NO X standards of §60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate a CEMS to measure NO X emissions; a wattmeter to measure gross electrical output; meters to measure steam flow, temperature, and pressure; and a continuous flow mo nitoring system to measure the flow of exhaust gases discharged to the atmosphere. (p) The owner or operator of an affected facility demonstrating compliance with an Hg limit in §60.45Da shall install and operate a CEMS to measure and record the concentration of Hg in the exhaust gases from each stack accord ing to the requirements in paragraphs (p)(1) through (p)(3) of this section. Alternatively, for an affected facility that is also subject to the requirements of subpart I of part 75 of this chapter, the owner or operator may install, certify, maintain, operate and quality-assure the data from a Hg CEMS according to §75.10 of this chapter and appendi ces A and B to part 75 of this chapter, in lieu of following the procedures in paragraphs (p)(1) through (p)(3) of this section. (1) The owner or operator must install, operate, and maintain each CEMS according to Performance Specification 12A in appendix B to this part. (2) The owner or operator must conduct a performance evaluation of each CEMS according to the requirements of §60.13 and Performance Specif ication 12A in appendix B to this part. (3) The owner or operator must operate each CEMS according to the requirements in paragraphs (p)(3)(i) through (iv) of this section. (i) As specified in §60.13(e)(2), each CEMS must complete a minimum of one cycle of operation (sampling, analyzing, and data recordi ng) for each successive 15-minute period. (ii) The owner or operator must reduce CEMS data as specified in §60.13(h). (iii) The owner or operator shall use all valid data point s collected during the hour to calculate the hourly average Hg concentration. (iv) The owner or operator must record the results of each required certification and quality assurance test of the CEMS. (4) Mercury CEMS data collection must conform to paragraphs (p)(4)(i) through (iv) of this section. (i) For each calendar month in which the affected unit operates, valid hourly Hg concentration data, stack gas volumetric flow rate data, moisture data (if required), and electrical output data (i.e., valid data for all of these parameters) shall be obtained for at least 75 percent of the unit operating hours in the month.(ii) Data reported to meet the requirements of th is subpart shall not include hours of unit startup, shutdown, or malfunction. In addition, for an affected fa cility that is also subject to subpart I of part 75 of this chapter, data reported to meet the require ments of this subpart shall not include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. (iii) If valid data are obtained for less than 75 perc ent of the unit operating hours in a month, you must discard the data collected in that month and replace the data with the mean of the individual monthly emission rate values determined in the last 12 months. In the 12-month rolling average calculation, this substitute Hg emission rate shall be weighted according to the number of unit operating hours in the month for which the data capture requir ement of §60.49Da(p)(4)(i) was not met. (iv) Notwithstanding the requirements of paragraph (p)(4)(iii) of this section, if valid data are obtained for less than 75 percent of the unit operating hours in another month in that same 12-month rolling average cycle, discard the data collected in that mo nth and replace the data with the highest individual monthly emission rate determined in the last 12 months. In the 12-month rolling average calculation, this substitute Hg emission rate shall be weighted according to the number of unit operating hours in the month for which the data capture requirement of §60.49Da(p)(4)(i) was not met. (q) As an alternative to the CEMS required in paragraph (p) of this section, the owner or operator may use a sorbent trap monitoring system (as defined in §72.2 of this chapter) to monitor Hg concentration, according to the procedures described in §75.15 of this chapter and appendix K to part 75 of this chapter. (r) For Hg CEMS that measure Hg concentration on a dry basis or for sorbent trap monitoring systems, the emissions data must be corrected for the stack gas moisture content. A certified continuous moisture monitoring system that meets the requirement s of §75.11(b) of this chapter is acceptable for this purpose. Alternatively, the appropriate default moisture value, as specified in §75.11(b) or §75.12(b) of this chapter, may be used. (s) The owner or operator shall prepare and submit to the Administrator for approval a unit-specific monitoring plan for each monitoring system, at leas t 45 days before commencing certification testing of the monitoring systems. The owner or operator shall comply with the requirements in your plan. The plan must address the requirements in para graphs (s)(1) through (6) of this section. (1) Installation of the CEMS sampling probe or ot her interface at a measurement location relative to each affected process unit such that the measurem ent is representative of the exhaust emissions ( e.g. , on or downstream of the last control device); (2) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the data collection and reduction systems; (3) Performance evaluation proce dures and acceptance criteria ( e.g., calibrations, relative accuracy test audits (RATA), etc.); (4) Ongoing operation and maintenance procedures inaccordance with the general requirements of §60.13(d) or part 75 of this chapter (as applicable); (5) Ongoing data quality assurance procedures in ac cordance with the general requirements of §60.13 or part 75 of this chapter (as applicable); and (6) Ongoing recordkeeping and reporting procedures in accordance with the requirements of this subpart.(t) The owner or operator of an affected facility demonstrating compliance with the output-based emissions limitation under §60.42Da(c)(1) shall install, certify, operate, and maintain a CEMS for measuring PM emissions according to the requirements of paragraph (v) of this section. An owner or operator of an affected facility demonstrating compliance with the input-based emission limitation in §60.42Da(a)(1) or §60.42Da(c)(2) may install, cert ify, operate, and maintain a CEMS for measuring PM emissions according to the requirements of paragraph (v) of this section. (u) The owner or operator of an affected facility using a CEMS measuring CO emissions to meet requirements of this subpart shall meet the requirements specified in paragraphs (u)(1) through (4) of this section. (1) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (u)(1)(i) through (iv) of this section. (i) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in §60.58b(i)(3) of subpart Eb of this part. (ii) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). (iii) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data points required in §60.13(h)(2). (iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part. (2) You must calculate the 1-hour average CO em issions levels for each boiler operating day by multiplying the average hourly CO output concen tration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly useful energy output from the affected facility. Th e 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each boiler operating day. (3) You must evaluate the preceding 24-hour aver age CO emission level each boiler operating day excluding periods of affected facility startup, s hutdown, or malfunction. If the 24-hour average CO emission level is greater than 1.4 lb/MWh, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discove ry of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emissi on level to 1.4 lb/MWh or less. (4) You must record the CO measurements and calc ulations performed according to paragraph (u)(3) of this section and any corrective act ions taken. The record of correc tive action taken must include the date and time during which the 24-hour average CO emission level was greater than 1.4 lb/MWh, and the date, time, and description of the corrective action. (v) The owner or operator of an affected facility using a CEMS measuring PM emissions to meet requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (v)(1) through (v)(4) of this section. (1) The owner or operator shall conduct a performance evaluation of the CEMS according to the applicable requirements of §60.13, Performance Sp ecification 11 in appendix B of this part, and procedure 2 in appendix F of this part.(2) During each PM correlation testing run of the CE MS required by Performance Specification 11 in appendix B of this part, PM and O 2 (or CO 2 ) data shall be coll ected concurrently (or within a 30- to 60- minute period) by both the CEMS and performance tests conducted using the fo llowing test methods. (i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part shall be used; and (ii) After July 1, 2010 or after Method 202 of ap pendix M of part 51 has been revised to minimize artifact measurement and notice of that change has be en published in theFederal Register,whichever is later, for condensable PM emissions, Method 2 02 of appendix M of part 51 shall be used; and (ii i ) For O 2 (or CO 2 ), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used. (3) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part. Relativ e Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years. (4) After July 1, 2011, within 90 days after the date of completing each performance evaluation required by paragraph (v) of this section, the owner or operator of the affected facility must either submit the test data to EPA by successfully entering the data electronically into EPA's WebFIRE data base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to: United States Environmental Protection Agency; Energy Strategies Group; 109 TW Alexander DR; Mail Code: D243–01; RTP, NC 27711. (w) The owner or operator using a SO 2 , NO X , CO 2 , and O 2 CEMS to meet the requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (w)(1) through (w)(5) of this section. (1) Except as provided for under paragraphs (w)(2), (w)(3), and (w)(4) of this section, each SO 2 , NO X , CO 2 , and O 2 CEMS required under paragraphs (b) through (d) of this section shall be installed, certified, and operated in accordance with the applicable procedures in Performance Specification 2 or 3 in appendix B to this part or according to the pr ocedures in appendices A an d B to part 75 of this chapter. Daily calibration drift assessments and quarterly accuracy determinations shall be done in accordance with Procedure 1 in appendix F to this pa rt, and a data assessment report (DAR), prepared according to section 7 of Procedure 1 in appendix F to this part, shall be submitted with each compliance report required under §60.51Da. (2) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to implement the following altern ative data accuracy assessment procedures. For all required CO 2 and O 2 CEMS and for SO 2 and NO X CEMS with span values greater than or equal to 100 ppm, the daily calibration error test and calibration adjustment procedures described in sections 2.1.1 and 2.1.3 of appendix B to part 75 of this chapter may be followed instead of the CD assessment procedures in Procedure 1, section 4.1 of appendix F of this part. If this option is selected, the data validation and out-of-control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75 of this chapter shall be followed instead of the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part. For the purposes of data validation under this subpart, the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part shall apply to SO 2 and NO X span values less than 100 ppm; (3) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alternative data accuracy assessment procedures. For all required CO 2 and O 2 CEMS and for SO 2 and NO X CEMS with span values greater than 30 ppm, quarterly linearity checks may be perf ormed in accordance with section 2.2.1 of appendix Comment [CF2]: Condensable PM testing no longer required since will gather significant data from the EGU MACT ICRB to part 75 of this chapter, instead of perfo rming the cylinder gas aud its (CGAs) described in Procedure 1, section 5.1.2 of appendix F to this part. If this option is selected: The frequency of the linearity checks shall be as specified in section 2.2.1 of appendix B to part 75 of this chapter; the applicable linearity specifications in section 3.2 of appendix A to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.2.3 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this pa rt; and the grace period provisions in section 2.2.4 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the cylinder gas audits described in Procedure 1, section 5.1.2 of appendix F to this part shall be performed for SO 2 and NO X span values less than or equal to 30 ppm; (4) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alternative data accuracy assessment procedures. For SO 2 , CO 2 , and O 2 CEMS and for NO X CEMS, RATAs may be performed in accordance with section 2.3 of appendix B to pa rt 75 of this chapter instead of following the procedures described in Procedure 1, section 5.1.1 of appe ndix F to this part. If this option is selected: The frequency of each RATA shall be as specified in section 2.3.1 of appendix B to part 75 of this chapter; the applicable relative accuracy specifications shown in Figure 2 in appendix B to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.3.2 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this pa rt; and the grace period provisions in section 2.3.3 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the relative accuracy specification in section 13.2 of Performance Specification 2 in appendix B to this part shall be met on a lb/MMBtu basis for SO 2 (regardless of the SO 2 emission level during the RATA), and for NO X when the average NO X emission rate measured by the refere nce method during the RATA is less than 0.100 lb/MMBtu; (5) If the owner or operator elects to implement the alternative data assessment procedures described in paragraphs (w)(2) through (w)(4) of this section, each data assessment report shall include a summary of the results of all of the RATAs, linearity checks, CGAs, and calibration error or drift assessments required by paragraphs (w)(2) through (w)(4) of this section.

### Subpart Db—Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units
§60.42b Standard for sulfur dioxide (SO 2 

### ). (a) Except as provided in paragraphs (b), (c), (d), or (j) of this section, on and after the date on which the performance test is completed or required to be completed under §60.8, whichever comes first, no owner or operator of an af fected facility that co mmenced construction, reconstruction, or modification on or before February 28, 2005, that combusts coal or oil shall cause to be discharged into the atmosphere any gases that contain SO 2 

### in excess of 87 ng/J (0.20 lb/MMBtu) or 10 percent (0.10) of the potential SO 2 

### emission rate (90 percent reduction) and the emission limit determined according to the following formula:

Where:

E s 

### = SO 2 

### emission limit, in ng/J or lb/MMBtu heat input;

K a 

### = 520 ng/J (or 1.2 lb/MMBtu);

Kb 

### = 340 ng/J (or 0.80 lb/MMBtu);

H a 

### = Heat input from the combustion of coal, in J (MMBtu); and

H b 

### = Heat input from the combustion of oil, in J (MMBtu). For facilities complying with the percent reductio n standard, only the heat input supplied to the affected facility from the combustion of coal and o il is counted in this paragraph. No credit is provided for the heat input to the affected facil ity from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or h eat derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc. (b) On and after the date on which the performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts coal refuse alone in a fluidized bed combustion steam generating unit shall cause to be discharged into the atmosphere any gases that contain SO 2 

### in excess of 87 ng/J (0.20 lb/MMBtu) or 20 percent (0.20) of the potential SO 2 

### emission rate (80 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. If coal or oil is fired withcoal refuse, the affectedfacility is subject to paragraph (a) or (d) of this section, as app licable. For facilities complying with the percent reduction standard, only the heat input supplied to the affected facility from the combustion of coal and oil is counted in this paragraph. No credit is provided for the heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.

### (c) On and after the date on which the performan ce test is completed or is required to be completed under §60.8, whichever comes first, no ow ner or operator of an affected facility that combusts coal or oil, either alone or in combination with any other fuel, and that uses an emerging technology for the control of SO 2 

### emissions, shall cause to be discharged into the atmosphere any gases that contain SO 2 

### in excess of 50 percent of the potential SO 2 

### emission rate (50 percent reduction) and that contain SO 2 

### in excess of the emission limit determined according to the following formula:

Where:

E s 

### = SO2 emission limit, in ng/J or lb/MM Btu heat input;

K c 

### = 260 ng/J (or 0.60 lb/MMBtu);

K d 

### = 170 ng/J (or 0.40 lb/MMBtu);

H c 

### = Heat input from the combustion of coal, in J (MMBtu); and

H d 

### = Heat input from the combustion of oil, in J (MMBtu). For facilities complying with the percent reductio n standard, only the heat input supplied to the affected facility from the combustion of coal and o il is counted in this paragraph. No credit is provided for the heat input to the affected facil ity from the combustion of natural gas, wood, municipal-type solid waste, or other fuels, or from the heat input derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc. (d) On and after the date on which the performance test is completed or required to be completed under §60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005 and listed in paragraphs (d)(1), (2), (3), or (4) of this section shall cause to be discharged into the atmosphere any gases that contain SO 2 

### in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected facility combusts coal, or 215 ng/J (0.5 lb/MMBtu) heat input if the affected facility combusts oil other than very low sulfur oil. Per cent reduction requirements are not applicable to affected facilities under paragraphs (d)(1), (2), (3) or (4) of this section. For facilities complying with paragraphs (d)(1), (2), or (3) of this section, only the heat input supplied to the affected facility from the combustion of coal and oil is counted in this paragraph. No credit is provided for the heat input to the affected facility from the combustion of natu ral gas, wood, municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc.
(1) Affected facilities that have an annual capacity factorfor coal and oil of 30 percent (0.30) or less and are subject to a federally enforceable permit limiting the operation of the affected facility to an annual capacity factor for coal and oil of 30 percent (0.30) or less;
(2) Affected facilities located in a noncontinental area; or

### (3) Affected facilities co mbusting coal or oil, alone or in combination with any fuel, in a duct burner as part of a combined cycle system where 30 percent (0.30) or less of the heat entering the steam generating unit is from combustion of coal and oil in the duct burner and 70 percent (0.70) or more of the heat entering the steam generating unit is from the exhaust gases entering the duct burner; or (4) The affected facility burns coke oven gas aloneor in combination withnatural gas or very low sulfur distillate oil. (e) Except as provided in paragraph (f) of this s ection, compliance with the emission limits, fuel oil sulfur limits, and/or percent reduction require ments under this section are determined on a 30- day rolling average basis. (f) Except as provided in paragraph (j)(2) of this section, compliance with the emission limits or fuel oil sulfur limits under this section is determined on a 24-hour average basis for affected facilities that (1) have a federally enforceable pe rmit limiting the annual capacity factor for oil to 10 percent or less, (2) combust only very low sulfur oil, and (3) do not combust any other fuel. (g) Except as provided in paragraph (i) of this section and §60.45b(a), the SO 2 

### emission limits and percent reduction requirements under this section apply at all times, including periods of startup, shutdown, and malfunction. (h) Reductions in the potential SO 2 

### emission rate through fuel pretreatment are not credited toward the percent reduction requirement under paragraph (c) of this section unless: (1) Fuel pretreatment results in a 50 percent or greater reduction in potential SO 2 

### emissions and (2) Emissions from the pretreated fuel (without combustion or post-combustion SO 2 

### control) are equal to or less than the emission limits sp ecified in paragraph (c) of this section. (i) An affected facility subject to paragraph (a), (b), or (c) of this section may combust very low sulfur oil or natural gas when the SO 2 

### control system is not being operated because of malfunction or maintenance of the SO 2 

### control system. (j) Percent reduction requirements are not applicab le to affected facilities combusting only very low sulfur oil. The owner or operator of an affected facility combusting very low sulfur oil shall demonstrate that the oil meets the definition of very low sulfur oil by: (1) Following the performance testing procedures as described in §60.45b(c) or §60.45b(d), and following the monitoring procedures as described in §60.47b(a) or §60.47b(b) to determine SO 2 

### emission rate or fuel oil sulfur content; or (2) maintaining fuel records as described in §60.49b(r). (k)(1) Except as provided in paragraphs (k)(2), (k)(3), and (k)(4) of this section, on and after the date on which the initial performance test is co mpleted or is required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commences construction, reconstruction, or modification after February 28, 2005, and that combusts coal, oil, natural gas, a mixture of these fuels, or a mixture of these fuels with any other fuels shall cause to be discharged into the atmosphere any gases that contain SO 2 

### in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 8 per cent (0.08) of the potential SO 2 

### emission rate (92 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat i nput. For facilities complying with the percent

### reduction standard and paragraph (k)(3) of this section, only the heat input supplied to the affected facility from the combustion of coal and oil is counted in paragraph (k) of this section. No credit is provided for the heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, such as gas turbines, internal combustion engines, kilns, etc. (2) Units firing only very low sulfur oil, gaseous fuel, a mixture of these fuels, or a mixture of these fuels with any other fuels with a potential SO 2 

### emission rate of 140 ng/J (0.32 lb/MMBtu) heat input or less are exempt from the SO 2 

### emissions limit in paragraph (k)(1) of this section. (3) Units that are located in a noncontinental area and that combust coal, oil, or natural gas shall not discharge any gases that contain SO 2 

### in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected facility combusts coal, or 215 ng/J (0.50 lb/MMBtu) heat input if the affected facility combusts oil or natural gas. (4) As an alternative to meeting the requirem ents under paragraph (k)(1) of this section, modified facilities that combust co al or a mixture of coal with other fuels shall not cause to be discharged into the atmosphere any gases that contain SO 2 

### in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO 2 

### emission rate (90 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. §60.46b Compliance and performance test methods and procedures for particulate matter and nitrogen oxides. (a) The PM emission standards and opacity limits under §60.43b apply at all times except during periods of startup, shutdown, or malfunction. The NO X 

### emission standards under §60.44b apply at all times. (b) Compliance with the PM emission standards under §60.43b shall be determined through performance testing as described in paragraph (d) of this section, except as provided in paragraph (i) of this section. (c) Compliance with the NO X 

### emission standards under §60.44b shall be determined through performance testing under paragraph (e) or (f), or under paragraphs (g) and (h) of this section, as applicable. (d) To determine compliance with the PM emission limits and opacity limits under §60.43b, the owner or operator of an affected facility shall conduct an initial performance test as required under §60.8, and shall conduct subsequent perfor mance tests as requested by the Administrator, using the following procedures and reference methods: (1) Method 3A or 3B of appendix A–2 of this part is used for gas analysis when applying Method 5 of appendix A–3 of this part or Method 17 of appendix A–6 of this part. (2) Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of PM as follows: (i) Method 5 of appendix A of this part shall be used at affected facilities without wet flue gas desulfurization (FGD) systems; and Comment [CF1]: Correct FR mistake

– never intended to delete paragraph 60.42b(k)(4)

### (ii) Method 17 of appendix A–6 of this part may be used at facilities with or without wet scrubber systems provided the stack gas temperature does not exceed a temperature of 160 °C (320 °F). The procedures of sections 8.1 and 11.1 of Method 5B of appendix A–3 of this part may be used in Method 17 of appendix A–6 of this part only if it is used after a wet FGD system. Do not use Method 17 of appendix A–6 of this pa rt after wet FGD systems if the effluent is saturated or laden with water droplets. (iii) Method 5B of appendix A of this part is to be used only after wet FGD systems. (3) Method 1 of appendix A of this part is used to select the sampling site and the number of traverse sampling points. The sampling time for each run is at least 120 minutes and the minimum sampling volume is 1.7 dscm (60 dscf) except that smaller sampling times or volumes may be approved by the Administrator when necessitated by process variables or other factors. (4) For Method 5 of appendix A of this part, the temperature of the sample gas in the probe and filter holder is monitored and is maintained at 160±14 °C (320±25 °F). (5) For determination of PM emissions, the oxygen (O 2 

### ) or CO 2 

### sample is obtained simultaneously with each run of Method 5, 5B, or 17 of appendix A of this part by traversing the duct at the same sampling location. (6) For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rate expressed in ng/J heat in put is determined using:
(i) The O 2 

### or CO 2 

### measurements and PM measurements obtained under this section; (ii) The dry basis F factor; and (iii) The dry basis emission rate calculation procedure contained in Method 19 of appendix A of this part. (7) Method 9 of appendix A of this part is used for determining the opacity of stack emissions. (e) To determine compliance with the emission limits for NO X 

### required under §60.44b, the owner or operator of an affected facility shall conduct the performance test as required under §60.8 using the continuous system for monitoring NO X 

### under §60.48(b). (1) For the initial compliance test, NO X 

### from the steam generating unit are monitored for 30 successive steam generating unit operating days and the 30-day average emission rate is used to determine compliance with the NO X 

### emission standards under §60.44b. The 30-day average emission rate is calculated as the average of all hourly emissions data recorded by the monitoring system during the 30-day test period. (2) Following the date on which the initial perform ance test is completed or is required to be completed in §60.8, whichever date comes first, the owner or operator of an affected facility which combusts coal (except as specified under §60.46b(e)(4)) or which combusts residual oil having a nitrogen content greater than 0.30 weight percent shall determine compliance with the NO X 

### emission standards in §60.44b on a continuous basis through the use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is calculated for each steam

### generating unit operating day as the average of all of the hourly NO X 

### emission data for the preceding 30 steam generating unit operating days. (3) Following the date on which the initial perform ance test is completed or is required to be completed under §60.8, whichever date comes first, the owner or operator of an affected facility that has a heat input capacity greater than 73 MW (250 MMBtu/hr) and that combusts natural gas, distillate oil, or residual oil having a nitr ogen content of 0.30 weight percent or less shall determine compliance with the NO X 

### standards under §60.44b on a continuous basis through the use of a 30-day rolling average emission rate. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly NO X 

### emission data for the preceding 30 steam generating unit operating days. (4) Following the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, the owner or operator of an affected facility that has a heat input capacity of 73 MW (250 MMBtu/hr) or less and that combusts natural gas, distillate oil, gasified coal, or residual oil having a nitrogen content of 0.30 weight percent or less shall upon request determine compliance with the NO X 

### standards in §60.44b through the use of a 30-day performance test. During periods when performance tests are not requested, NO X 

### emissions data collected pursuant to §60.48b(g)(1) or §60.48b(g)(2) are used to calculate a 30-day rolling average emission rate on a daily basis and used to prepare excess emission reports, but will not be used to determine compliance with the NO X 

### emission standards. A new 30-day rolling average emission rate is calculated each steam generating unit operating day as the average of all of the hourly NO X 

### emission data for the preceding 30 steam generating unit operating days. (5) If the owner or operator of an affected facility that combusts residual oil does not sample and analyze the residual oil for nitrogen content, as specified in §60.49b(e), the requirements of §60.48b(g)(1) apply and the provisions of §60.48b(g)(2) are inapplicable. (f) To determine compliance with the emissions limits for NO X 

### required by §60.44b(a)(4) or §60.44b(l) for duct burners used in combined cycle systems, either of the procedures described in paragraph (f)(1) or (2) of this section may be used: (1) The owner or operator of an affected facility shall conduct the performance test required under §60.8 as follows:
(i) The emissions rate (E) of NO X 

### shall be computed using Equation 1 in this section:

Where:

E = Emissions rate of NO X 

### from the duct burner, ng/J (lb/MMBtu) heat input;

E sg 

### = Combined effluent emissions rate, in ng/J (l b/MMBtu) heat input using appropriate F factor as described in Method 19 of appendix A of this part; The image cannot be displayed. Your computer may not have enough memory to open the image, or the image may have been corrupted . Restart your computer, and then open the file again. If the red x still appears, you may have to delete the image and then insert it again.

### H g 

### = Heat input rate to the combustion turbine, in J/hr (MMBtu/hr);

H b 

### = Heat input rate to the duct burner, in J/hr (MMBtu/hr); and

E g 

### = Emissions rate from the combustion turbine, in ng/J (lb/MMBtu) heat input calculated using appropriate F factor as described in Method 19 of appendix A of this part. (ii) Method 7E of appendix A of this part shall be used to determine the NO X 

### concentrations. Method 3A or 3B of appendix A of this part shall be used to determine O 2 

### concentration. (iii) The owner or operator sha ll identify and demonstrate to the Administrator's satisfaction suitable methods to determine the average hourly heat input rate to the combustion turbine and the average hourly heat input rate to the affected duct burner. (iv) Compliance with the emission s limits under §60.44b(a)(4) or §60.44b(l) is determined by the three-run average (nominal 1-hour runs) for the initial and subsequent performance tests; or (2) The owner or operator of an affected facility may elect to determine compliance on a 30-day rolling average basis by using the CEMS specified under §60.48b for measuring NO X 

### and O 2 

### and meet the requirements of §60.48b. The sampling site shall be located at the outlet from the steam generating unit. The NO X 

### emissions rate at the outlet from the steam generating unit shall constitute the NO X 

### emissions rate from the duct burner of the combined cycle system. (g) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) shall demonstrate the maximum heat input capacity of the steam generating unit by operating the facility at maximum capacity for 24 hours. The owner or operator of an affected facility shall determine the maximum heat input capacity using the heat loss method or the heat input method described in sections 5 and 7.3 of the ASME Power Test Codes 4.1 (incorporated by reference, see §60.17). This demonstration of maximum heat input capacity shall be made during the initial performance test for affected facilities that meet th e criteria of §60.44b(j). It shall be made within 60 days after achieving the maximum production ra te at which the affected facility will be operated, but not later than 180 days after initial start-up of each facility, for affected facilities meeting the criteria of §60.44b(k). Subsequent demonstrations may be required by the Administrator at any other time. If this demons tration indicates that the maximum heat input capacity of the affected facility is less than that stated by the manufacturer of the affected facility, the maximum heat input capacity determinedduring this demonstration shall be used to determine the capacity utilization rate for the affected facility . Otherwise, the maximum heat input capacity provided by the manufacturer is used. (h) The owner or operator of an affected facility described in §60.44b(j) that has a heat input capacity greater than 73 MW (250 MMBtu/hr) shall: (1) Conduct an initial performance test as required under §60.8 over a minimum of 24 consecutive steam generating unit operating hours at maximum heat input capacity to demonstrate compliance with the NO X 

### emission standards under §60.44b using Method 7, 7A, 7E of appendix A of this part, or other approved reference methods; and (2) Conduct subsequent performance tests once per calendar year or every 400 hours of operation (whichever comes first) to demonstrate compliance with the NO X 

### emission standards under

### §60.44b over a minimum of 3 consecutive steam generating unit operating hours at maximum heat input capacity using Method 7, 7A, 7E of appendix A of this part, or other approved reference methods. (i) The owner or operator of an affected facility seeking to demonstrate compliance with the PM limit in paragraphs §60.43b(a)(4) or §60.43b(h)( 5) shall follow the applicable procedures in §60.49b(r). (j) In place of PM testing with Method 5 or 5B of appendix A–3 of this part, or Method 17 of appendix A–6 of this part, an owner or operator may elect to install, calibrate, maintain, and operate a CEMS for monitoring PM emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility who elects to continuously monitor PM emissions instead of conducting performance testing using Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part shall comply with the requirements specified in paragraphs (j )(1) through (j)(14) of this section. (1) Notify the Administrator one month before starting use of the system. (2) Notify the Administrator one month before stopping use of the system. (3) The monitor shall be installed, evaluated, and operated in accordance with §60.13 of subpart A of this part. (4) The initial performance evaluation shall be comp leted no later than 180 days after the date of initial startup of the affected facility, as specified under §60.8 of subpart A of this part or within 180 days of notification to the Administrator of use of the CEMS if the owner or operator was previously determining compliance by Method 5, 5B, or 17 of appendix A of this part performance tests, whichever is later. (5) The owner or operator of an affected facility shall conduct an initial performance test for PM emissions as required under §60.8 of subpart A of this part. Compliance with the PM emission limit shall be determined by using the CEMS specifi ed in paragraph (j) of this section to measure PM and calculating a 24-hour block arithmetic average emission concentration using EPA Reference Method 19 of appendix A of this part, section 4.1. (6) Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emission concentrations using CEMS outlet data. (7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraphs (j)(7)(i) of this section for 75 percent of the total operating hours per 30-day rolling average. (i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
(ii) [Reserved] (8) The 1-hour arithmetic averages required under paragraph (j)(7) of this section shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the boiler operating day daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under §60.13(e)(2) of subpart A of this part.

### (9) All valid CEMS data shall be used in calculati ng average emission concentrations even if the minimum CEMS data requirements of paragraph (j)(7) of this section are not met. (10) The CEMS shall be operated according to Performance Specification 11 in appendix B of this part. (11) During the correlation testing runs of th e CEMS required by Performance Specification 11 in appendix B of this part, PM and O 2 

### (or CO 2 

### ) data shall be collected concurrently (or within a 30-to 60-minute period) by both the continuous emission monitors and performance tests conducted using the following test methods. (i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part shall be used; and (ii) After July 1, 2010 or after Method 202 of appendix M of part 51 has been revised to minimize artifact measurement and notice of that change has been published in theFederal Register,whichever is later , for condensable PM emissions, Method 202 of appendix M of part 51 shall be used; and
(ii i ) For O 2 

### (or CO 2 

### ), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used. (12) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years. (13) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by the Ad ministrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, valid emissions data for a minimum of 75 percent of total operating hours per 30-day rolling average. (14) After July 1, 2011, within 90 days after completing a correlation testing run, the owner or operator of an affected facility shall either successfully enter the test data into EPA's WebFIRE data base located at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to: United States Environmental Protection Agency; Energy Strategies Group; 109 TW Alexander DR; Mail Code: D243–01; RTP, NC 27711. §60.48b Emission monitoring for particulate matter and nitrogen oxides.
(a) Except as provided in paragraph (j) of this section, the owner or operator of an affected facility subject to the opacity standard under §60.43b shall install, calibrate, maintain, and operate a continuous opacity monitoring systems (COMS) for measuring the opacity of emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility subject to an opacity standard under §60.43b and meeting the conditions under paragraphs (j)(1), (2), (3), (4), or (5) of this section who elects not to use install a COMS shall conduct a performance test using Method 9 of appendix A–4 of this part and the procedures in §60.11 to demonstrate compliance with the applicable limit in §60.43b by April 29, 2011, within 45 days of stopping use of an existing COMS, or 180 days after initial startup of the facility, whichever is later, and shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of

### this section. The observation period for Method 9 of appendix A-4 of this part performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are less than 10 percent and all individual 15-second observations are less than or equal to 20 percent during the initial 60 minutes of observation. If during the initial 60 minutes of observation all 6

- minute averages are less than 10 percent and all individual 15

- second observations are less than or equal to 20 percent, the observation period may be reduced from 3 hours to 60 minutes. (1) Except as provided in paragraph (a)(2) and (a)(3) of this section, the owner or operator shall conduct subsequent Method 9 of appendix A–4 of this part performance tests using the procedures in paragraph (a) of this section according to the applicable schedule in paragraphs (a)(1)(i) through (a)(1)(iv) of this section, as determined by the most recent Method 9 of appendix A–4 of this part performance test results.
(i) If no visible emissions are observed, a subs equent Method 9 of appendix A–4 of this part performance test must be comple ted within 12 calendar months from the date that the most recent performance test was conducted; (ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 6 calendar months from the da te that the most recent performance test was conducted; (iii) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 3 calendar months from the da te that the most recent performance test was conducted; or
(iv) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 45 30 calendar days from the date that the most recent performance test was conducted. (2) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 of this part performance tests, elect to perform subsequent monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in paragraphs (a)(2)(i) and (ii) of this section.
(i) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the affected facility fires fuel for which an opacity standard is applicable using Method 22 of appendix A–7 of this part and demonstrate that the sum of the occurrences of any visible emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute period). If the sum of the occurrence of any visibl e emissions is greater than 30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the occurrence of visible emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds per 30 minute period)
, the owner or operator shall either document and adjust the operation of the facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to or less th an 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of appendix A–4 of this part performance test using the

### procedures in paragraph (a) of this section within 45 30 calendar days according to the requirements in §60.46d(d)(7). (ii) If no visible emissions are observed for 30 op erating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any visible emissions are observed, daily observations shall be resumed. (3) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 performance tests, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitoring plan approved by the Administrator. The observations shall be similar, but not necessarily identical, to the requirements in paragraph (a)(2) of this section. For reference purposes in preparing the monitoring plan, s ee OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Compute r-Based Photographic Analysis Systems.” This document is available from the U.S. Environmenta l Protection Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Preliminary Methods. (b) Except as provided under paragraphs (g), (h), and (i) of this section, the owner or operator of an affected facility subject to a NO X 

### standard under §60.44b shall comply with either paragraphs (b)(1) or (b)(2) of this section.
(1) Install, calibrate, maintain, and operate CEMS for measuring NO X 

### and O 2 

### (or CO 2 

### ) emissions discharged to the atmosphere, and shall record the output of the system; or (2) If the owner or operator has installed a NO X 

### emission rate CEMS to meet the requirements of part 75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that CEMS may be used to meet the requirements of this section, except that the owner or operator shall also meet the requirements of §60.49b. Data reported to meet the requirements of §60.49b shall not include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. (c) The CEMS required under paragraph (b) of this section shall be operated and data recorded during all periods of operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments. (d) The 1-hour average NO X 

### emission rates measured by the continuous NO X 

### monitor required by paragraph (b) of this section and required under §60.13(h) shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calcu late the average emission rates under §60.44b. The 1-hour averages shall be calculated using the data points required under §60.13(h)(2). (e) The procedures under §60.13 shall be followed for installation, evaluation, and operation of the continuous monitoring systems.

### (1) For affected facilities comb usting coal, wood or municipal-type solid waste, the span value for a COMS shall be between 60 and 80 percent. (2) For affected facilities combusting coal, oil, or natural gas, the span value for NO X 

### is determined using one of the following procedures: (i) Except as provided under paragraph (e)(2)(ii) of this section, NO X 

### span values shall be determined as follows:

Fuel Span values for NO X 

### (ppm)

N atural gas 500.

Oil 500.

Coal 1,000.
Mixtures 500 (x + y) + 1,000z.

Where: x = Fraction of total heat input derived from natural gas; y = Fraction of total heat input derived from oil; and z = Fraction of total heat input derived from coal. (ii) As an alternative to meeting the requirements of paragraph (e)(2)(i) of this section, the owner or operator of an affected facility may elect to use the NO X 

### span values determined according to section 2.1.2 in appendix A to part 75 of this chapter. (3) All span values computed under paragraph (e )(2)(i) of this section for combusting mixtures of regulated fuels are rounded to the nearest 500 ppm. Span values computed under paragraph (e)(2)(ii) of this section shall be rounded off according to section 2.1.2 in appendix A to part 75 of this chapter.
(f) When NO X 

### emission data are not obtained because of CEMS breakdowns, repairs, calibration checks and zero and span adjustments, emission data will be obtained by using standby monitoring systems, Method 7 of appendix A of th is part, Method 7A of appendix A of this part, or other approved reference methods to provide emission data for a minimum of 75 percent of the operating hours in each steam generating unit operating day, in at least 22 out of 30 successive steam generating unit operating days. (g) The owner or operator of an affected facility that has a heat input capacity of 73 MW (250 MMBtu/hr) or less, and that has an annual capacity factor for residual oil having a nitrogen content of 0.30 weight percent or less, natural gas, distillate oil, gasified coal, or any mixture of these fuels, greater than 10 percent (0.10) shall: (1) Comply with the provisions of paragraphs (b), (c ), (d), (e)(2), (e)(3), and (f) of this section; or

### (2) Monitor steam generating unit operating conditions and predict NO X 

### emission rates as specified in a plan submitted pursuant to §60.49b(c). (h) The owner or operator of a duct burner, as described in §60.41b, that is subject to the NO X 

### standards in §60.44b(a)(4), §60.44b(e), or §60.44b(l) is not required to install or operate a continuous emissions monitoring system to measure NO X 

### emissions. (i) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) is not required to install or operate a CEMS for measuring NO X 

### emissions. (j) The owner or operator of an affected facili ty that meets the conditions in either paragraph (j)(1), (2), (3), (4), (5), or (6) of this section is not required to install or operate a COMS if: (1) The affected facility uses a PM CEMS to monitor PM emissions; or (2) The affected facility burns onl y liquid (excluding residual oil) or gaseous fuels with potential SO 2 

### emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and does not use a post-combustion technology to reduce SO 2 

### or PM emissions. The owner or operator must maintain fuel records of the sulfur content of the fuels burne d, as described under §60.49b(r); or (3) The affected facility burns coke oven gas al one or in combination with fuels meeting the criteria in paragraph (j)(2) of this section and does not use a post-combustion technology to reduce SO 2 

### or PM emissions; or (4) The affected facility does not use post-com bustion technology (excep t a wet scrubber) for reducing PM, SO 2 

### , or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur, and is operated such that emissions of CO to the atmosphere from the affected facility are maintained at levels less than or equal to 0.15 lb/MMBtu on a steam generating unit operating day average basis. Owners and operators of affected facilities electing to comply with this paragraph must demonstrate compliance according to the procedures specified in paragraphs (j)(4)(i) through (iv) of this section; or (i) You must monitor CO emissions using a CE MS according to the procedures specified in paragraphs (j)(4)(i)(A) through (D) of this section. (A) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in §60.58b(i)(3) of subpart Eb of this part. (B) Each 1-hour CO emissions average is calculate d using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis).
(C) At a minimum, valid 1-hour CO emissions aver ages must be obtained for at least 90 percent of the operating h ours on a 30-day rolling average basis. The 1-hour averag es are calculated using the data points required in §60.13(h)(2). (D) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part. (ii) You must calculate the 1-hour average CO emissions levels for each steam generating unit operating day by multiplying the average hourly CO output concentration measured by the CO

### CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each steam generating unit operating day. (iii) You must evaluate the preceding 24-hour average CO emission level each steam generating unit operating day excluding periods of affected s ource startup, shutdown, or malfunction. If the 24-hour average CO emission level is greate r than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less. (iv) You must record the CO measurements and calculations performed according to paragraph (j)(4) of this section and any corrective actions taken. The record of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, and the date, time, and description of the corrective action. (5) The affected facility uses a ba g leak detection system to mon itor the performance of a fabric filter (baghouse) according to the most recent requ irements in section §60.48Da of this part; or (6) The affected facility burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 weight percent sulfur and operates according to a written site-specific monitoring plan approved by the permitting authority. This monitoring plan must include procedures and criteria for establishing and monitoring specific parame ters for the affected facility indicative of compliance with the opacity standard. (k) Owners or operators complying with the PM emission limit by using a PM CEMS must calibrate, maintain, operate, and record the output of the system for PM emissions discharged to the atmosphere as specified in §60.46b(j). The CEMS specified in paragraph §60.46b(j) shall be operated and data recorded during all periods of operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments.

## Subpart Dc—Standards of Performance for Small Industrial -Commercial-Institutional Steam Generating Units
§60.45c Compliance and performance test method s and procedures for particulate matter. (a) The owner or operator of an af fected facility subject to the PM and/or opacity standards under §60.43c shall conduct an initial performance test as required under §60.8, and sh all conduct subsequent performance tests as requested by the Administrator, to determine compliance with the standards using the following procedures and reference methods, excep t as specified in paragr aph (c) of th is section. (1) Method 1 of appendix A of this part shall be us ed to select the sampling site and the number of traverse sampling points. (2) Method 3A or 3B of appendix A–2 of this part shall be used for gas analysis when applying Method 5 or 5B of appendix A–3 of this part or 17 of appendix A–6 of this part. (3) Method 5, 5B, or 17 of appendix A of this part shall be used to m easure the concentration of PM as follows: (i) Method 5 of appendix A of this part may be used only at affected facilities without wet scrubber systems. (ii) Method 17 of appendix A of this part may be used at affected facilities with or without wet scrubber systems provided the stack gas temperature does not exceed a temp erature of 160 °C (320 °F). The procedures of Sections 8.1 and 11.1 of Method 5B of appendix A of this part may be used in Method 17 of appendix A of this part only if Method 17 of appendix A of this part is used in conjunction with a wet scrubber syst em. Method 17 of appendix A of this part shall not be used in conjunction with a wet scrubber syst em if the effluent is saturate d or laden with water droplets. (iii) Method 5B of appendix A of this part may be used in conj unction with a wet scrubber system. (4) The sampling time for each run shall be at least 120 minutes and the minimum sampling volume shall be 1.7 dry standard cubic meters (dscm) [60 dry standard cubic feet (dscf)] except that smaller sampling times or volumes may beapproved by the Administrator when necessitated by process variables or other factors. (5) For Method 5 or 5B of appendix A of this part, the temperature of the samp le gas in the probe and filter holder shall be mon itored and maintained at 160 ±14 °C (320±25 °F). (6) For determination of PM emissions, an oxygen (O 2 

## ) or carbon dioxide (CO 2 

## ) measurement shall be obtained simultaneously with each run of Method 5, 5B, or 17 of appendi x A of this part by traversing the duct at the same sampling location. (7) For each run using Method 5, 5B, or 17 of appendix A of this part, the emi ssion rates expressed in ng/J (lb/MMBtu) heat input sh all be determined using:
(i) The O 2 

## or CO 2 

## measurements and PM measurements obtaine d under this section, (ii) The dry basis F factor, and (iii) The dry basis emission rate calculation proce dure contained in Method 19 of appendix A of this part.

## (8) Method 9 of appendix A–4 of this part shall be used for determin ing the opacity of stack emissions. (b) The owner or operator of an affected facility seeking to demonstrate compliance with the PM standards under §60.43c(b)(2) shall demonstrate the maxi mum design heat input capacity of the steam generating unit by operating the steam generating unit at this capacity for 24 hours. This demonstration shall be made during the initial pe rformance test, and a subsequent de monstration may be requested at any other time. If the dem onstrated 24-hour average firi ng rate for the affected facility is less than the maximum design heat input capacity stated by the manufacturer of the affected facility, the demonstrated 24-hour average firing ra te shall be used to determine th e annual capacity factor for the affected facility; otherwise, the maximum design heat input capaci ty provided by the manufacturer shall be used. (c) In place of PM testing with Me thod 5 or 5B of appendix A–3 of th is part or Method 17 of appendix A–6 of this part, an owner or opera tor may elect to install, calibrate , maintain, and ope rate a CEMS for monitoring PM emissions dischargedto the atmosphere and record the output of the system. The owner or operator of an affected facility who elects to continuously monitor PM emissions instead of conducting performance testing using Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part shall in stall, calibrate, maintain, and opera te a CEMS and shall comply with the requirements specified in paragraphs (c)(1) through (c)(14) of this section. (1) Notify the Administrator 1 month before starting use of the system. (2) Notify the Administrator 1 month before stopping use of the system.
(3) The monitor shall be instal led, evaluated, and operated in acco rdance with §60.13 of subpart A of this part. (4) The initial performance evaluation shall be completed no later than 180 days af ter the date of initial startup of the affected facility, as specified under §60.8 of subpart A of this part or within 180 days of notification to the Administrator of use of CEMS if the owner or ope rator was previously determining compliance by Method 5, 5B, or 17 of appendix A of this part performa nce tests, whichever is later. (5) The owner or operator of an affected facility shall conduct an initial performance test for PM emissions as required under §60.8 of subpart A of this part. Compliance with the PM emission limit shall be determined by using the CEMS specified in paragraph (d) of this section to measure PM and calculating a 24-hour block arithme tic average emission concentrat ion using EPA Reference Method 19 of appendix A of this part, section 4.1. (6) Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emissi on concentrations us ing CEMS outlet data. (7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraph (c)(7)(i) of this section for 75 percent of the total operating hours per 30-day rolling average. (i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average.
(ii) [Reserved] (8) The 1-hour arithmetic averages re quired under paragraph (c)(7) of th is section shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the boiler opera ting day daily arithmetic

## average emission concentrations. Th e 1-hour arithmetic averages shall be calculated using the data points required under §60.13(e)(2) of subpart A of this part.
(9) All valid CEMS data shall be used in calcula ting average emission concentrations even if the minimum CEMS data requirement s of paragraph (c)(7) of this section are not met. (10) The CEMS shall be operated according to Pe rformance Specification 11 in appendix B of this part. (11) During the correlation testi ng runs of the CEMS required by Performance Specification 11 in appendix B of this part, PM and O 2 

## (or CO 2 

## ) data shall be collected concu rrently (or within a 30- to 60- minute period) by both the continuous emission m onitors and performance te sts conducted using the following test methods. (i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part shall be used; and (ii) After July 1, 2010 or after Me thod 202 of appendix M of part 51 has been revised to minimize artifact measurement and notice of that change has been publishe d in theFederal Register,whichever is later, for condensable PM emissions, Method 202 of appe ndix M of part 51 shall be u sed; and
(ii i ) For O2 (or CO 2 

## ), Method 3A or 3B of appendix A–2 of th is part, as applicable shall be used. (12) Quarterly accuracy determin ations and daily calib ration drift tests shal l be performed in accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years.
(13) When PM emissions data ar e not obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions da ta shall be obtained by using other monitoring systems as approved by the Administrator or EPA Re ference Method 19 of appendix A of this part to provide, as necessary, valid emissions data for a minimum of 75 percent of total operating hours on a 30-day rolling average. (14) After July 1, 2011, within 90 days after th e date of completing each performance evaluation required by paragraph (c)(11) of this section, the owne r or operator of the affected facility must either submit the test data to EPA by successfully entering the data electro nically into EPA's WebFIRE data base available at http://cfpub.epa.gov/oarweb/in dex.cfm?action=fire.main or mail a copy to: United States Environmental Protecti on Agency; Energy Strategies Group; 109 TW Alexander DR; Mail Code: D243–01; RTP, NC 27711. (d) The owner or operator of an affected faci lity seeking to demonstrate compliance under §60.43c(e)(4) shall follow the applicable procedures under §60.48c(f). For residual oil-fired affected facilities, fuel supplier certificati ons are only allowed for facilities with heat input capacities between 2.9 and 8.7 MW (10 to 30 MMBtu/hr).
§60.47c Emission monitoring for particulate matter.
(a) Except as provided in paragraphs (c), (d), (e), (f), and (g) of this section, the owne r or operator of an affected facility combusting coal, oil, or wood that is subject to the opacity standards under §60.43c shall install, calibrate, maintai n, and operate a continuous opacity monitoring system (COMS) for measuring the opacity of the emissi ons discharged to the atmosphere and record the output of the

## system. The owner or operator of an affected facility subject to an opacity standard in §60.43c(c) a nd that is not required to use install a COMS due to paragraphs (c ), (d), (e), or (f) of this section that elects not to use install a COMS shall conduct a performance test usi ng Method 9 of appendix A–4 of this part and the procedures in §60.11 to demonstrate compliance with the applicable limit in §60.43c by April 29, 2011, within 45 days of stopping use of an existi ng COMS, or 180 days after initial startup of the facility, whichever is later, and shall comply with either paragraphs (a)(1), (a)(2), or (a)(3) of this section. The observation period for Method 9 of appendix A-4 of this part performance tests may be reduced from 3 hour s to 60 minutes I i f during the initial 60 minutes of observation all 6-minute averages are less than 10 percent and all individual 15-second observations are less than or equal to 20 percent during the initial 60 minutes of observation.. , the observation period may be reduced from 3 hours to 60 minutes. (1) Except as provided in paragraph (a)(2) and (a )(3) of this section, the owner or operator shall conduct subsequent Method 9 of appendix A–4 of this part performance tests using the procedures in paragraph (a) of this section acco rding to the applicable schedule in paragraphs (a)(1)(i) through (a)(1)(iv) of this secti on, as determined by the most recent Me thod 9 of appendix A–4 of this part performance test results.
(i) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part performance test must be complete d within 12 calendar mo nths from the date th at the most recent performance test was conducted;
(ii) If visible emissions are observed but the maximum 6-minute av erage opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A–4 of this part pe rformance test must be completed within 6 calendar months from the date that the most recent performance test was conducted; (iii) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A–4 of this part performance te st must be completed within 3 calendar months from the date that the most recen t performance test was conducted; or
(iv) If the maximum 6-minute average opacity is greater than 10 per cent, a subsequent Method 9 of appendix A–4 of this part performan ce test must be completed within 30 45 calendar days from the date that the most recent pe rformance test was conducted. (2) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performan ce test, the owner or operator may, as an alternativ e to performing subsequent Method 9 of appendix A –4 of this part performance tests, elect to perform subsequent monitoring using Method 22 of appe ndix A–7 of this part according to the procedures specified in paragraphs (a)(2)(i) and (ii) of this section. (i) The owner or operato r shall conduct 10 minute observations (during normal operation) each operating day the affected facility fires fuel for which an opacity st andard is applicable using Method 22 of appendix A–7 of this part and demonstrate that the sum of the occu rrences of any visible emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute period). If the sum of the occurrence of any visi ble emissions is greater than 30 seconds during the initial 10 minute observation, i mmediately conduct a 30 minute observation. If the sum of the occurrence of visible emissions is greater than 5 percen t of the observation period ( i.e. , 90 seconds per 30 minute period) the owner or operator shall either docum ent and adjust the operation of the facility and demonstrate within 24 h ours that the sum of th e occurrence of visible emissions is equal to

## or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of appendix A–4 of this part performance test using the procedures in paragraph (a) of th is section within 30 45 calendar days according to th e requirements in §60.45c(a)(8).
(ii) If no visible emissi ons are observed for 30 operating days during which an opacity standard is applicable, observations can be reduced to on ce every 7 operating days during which an opacity standard is applicable. If any vi sible emissions are observed, dail y observations shall be resumed. (3) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performan ce test, the owner or operator may, as an alternativ e to performing subsequent Method 9 of appendix A–4 performance te sts, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitori ng plan approved by the Administrator. The observations shal l be similar, but not necessarily identical, to the requirements in paragraph (a)(2) of this section. For reference purposes in preparing the monito ring plan, see OAQPS “Determination of Visible Emi ssion Opacity from Stationary S ources Using Computer-Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Pl anning Standards; Sector Policies and Programs Division; Measurement Policy Gr oup (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technol ogy Transfer Network (TTN) unde r Emission Measurement Center Preliminary Methods. (b) All COMS shall be operated in accordance with the applicable procedures under Performance Specification 1 of appendix B of this part. The spanvalue of the opacity COMS shall be between 60 and 80 percent. (c) Owners and operators of an affected facilities that burn only distillate oil th at contains no more than 0.5 weight percent sulfur and/or liqu id or gaseous fuels with potentia l sulfur dioxide emission rates of 26 ng/J (0.060 lb/MMBtu) heat input or less and that do not use a post-combustion technology to reduce SO2 or PM emissions and that are subject to an opacity standard in §60.43c(c) are not required to operate a COMS if th ey follow the applicable procedures in §60.48c(f). (d) Owners or operators complying with the PM e mission limit by using a PM CEMS must calibrate, maintain, operate, and record the output of the system for PM emissions discharged to the atmosphere as specified in §60.45c(c). The CEMS specified inparagraph §60.45c(c) shall be operated and data recorded during all periods of operation of the a ffected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments. (e) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and that does not use post-combustion technology (except a wet scrubbe r) for reducing PM, SO 2 

## , or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.5 weight percent sulfur, and is operated such that e missions of CO di scharged to the atmosphere from the affected facility are maintain ed at levels less than or equa l to 0.15 lb/MMBtu on a boiler operating day average basis is not required to operate a COMS . Owners and operators of affected facilities electing to comply with this paragraph must demonstr ate compliance according to the procedures specified in paragraphs (e)(1) th rough (4) of this section; or
(1) You must monitor CO emissi ons using a CEMS according to the procedures specified in paragraphs (e)(1)( i) through (iv) of this section.

## (i) The CO CEMS must be instal led, certified, maintaine d, and operated according to the provisions in §60.58b(i)(3) of subpart Eb of this part.
(ii) Each 1-hour CO emissions av erage is calculated using the data points generated by the CO CEMS expressed in parts per milli on by volume corrected to 3 percent oxygen (dry basis).
(iii) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling average basis. Th e 1-hour averages are calculated using the data points required in §60.13(h)(2). (iv) Quarterly accuracy determin ations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part. (2) You must calculate the 1-hour average CO emissions levels for each steam generating unit operating day by multiplying the av erage hourly CO output concentrat ion measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission le vels computed for each steam generating unit operating day. (3) You must evaluate the preceding 24-hour averag e CO emission level each steam generating unit operating day excluding periods of affected source startup, shutdow n, or malfunction. If the 24-hour average CO emission level is great er than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control sy stems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce th e 24-hour average CO emission le vel to 0.15 lb/MMBtu or less.
(4) You must record the CO meas urements and calculations performedaccording to paragraph (e) of this section and any corrective actions taken. The r ecord of corrective action taken must include the date and time during which the 24-hour average CO emission level was grea ter than 0.15 lb/MMBtu, and the date, time, and description of the corrective action. (f) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and that uses a bag leak detection sy stem to monitor the performance of a fabric filter (baghouse) according to the most recent requirements in section §60.48Da of this part is not required to operate a COMS. (g) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and that burns only gaseous fuels or fuel oils that contain less than or e qual to 0.5 weight percent sulfur and operates according to a written site -specific monitoring plan approved by the permitting authority is not required to operate a COMS. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard.