Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which Construction Is Commenced After August 17, 1971 §60.40 Applicability and designation of affected facility. (a) The affected facilities to which the provisions of this subpart apply are: (1) Each fossil-fuel-fired steam generating unit of more than 73 megawatts (MW) heat input rate (250 million British thermal units per hour (MMBtu/hr)). (2) Each fossil-fuel and wood-residue-fired steam ge nerating unit capable of firing fossil fuel at a heat input rate of more than 73 MW (250 MMBtu/hr). (b) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels as defi ned in this subpart, shall not bring that unit under the applicability of this subpart. (c) Except as provided in paragraph (d) of this section, any facility under paragraph (a) of this section that commenced construction or modification after Au gust 17, 1971, is subject to the requirements of this subpart.(d) The requirements of §§60.44 (a)(4), (a)(5), (b) and (d), and 60.45(f)(4)(vi) are applicable to lignitefired steam generating units that commenced constr uction or modification after December 22, 1976. (e) Any facility covered under either subpart Da or KKKK is not covered under this subpart.

§60.41 Definitions. As used in this subpart, all terms not defined herein shall have the meaning given them in the Act, and in subpart A of this part. Boiler operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the steam- generating unit. It is not necessary for fuel to be combusted the entire 24-hour period.

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by ASTM D388 (incorporated by reference, see §60.17). Coal refuse means waste-products of coal mining, cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, cl ay, and other organic and inorganic material. Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such materials for the purpose of creating useful heat. Fossil fuel and wood residue-fired steam generating unit means a furnace or boiler used in the process of burning fossil fuel and wood residue for th e purpose of producing steam by heat transfer. Fossil-fuel-fired steam generating unit means a furnace or boiler used in the process of burning fossil fuel for the purpose of producing steam by heat transfer. Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gr oss calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value. Comment [CF1]: Simplify title.

Comment [CF2]: Adjusting applicability since heat recovery steam generators covered under Da reverted to D after they were exempted from Da. The intent of KKKK is to cover the HRSG in combined cycle and CHP facilities and to exempt them from all boiler NSPS.

Comment [CF3]: Definition required for PM exemption.Wood residue means bark, sawdust, slabs, chips, shavings , mill trim, and other wood products derived from wood processing and forest management operations. §60.42 Standard for particulate matter (PM). (a) Except as provided under paragraphs (b), (c), (d), and (e) of this section, o O n and after the date on which the performance test required to be conduct ed by §60.8 is completed, no owner or operator subject to the provisions 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 Servic e Company's Harrington Station #1, in Amarillo, TX, any gases which exhibit greater than 35 percent op acity, 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 atmo sphere from its Lansing Station Unit No. 4 in Lansing, IA, any gases which e xhibit greater than 32 percent opacity, except that a maximum of 39 percent opacity shall be permitted for not more than six minutes in any hour. (c) As an alternate to meeting the requirements of para graph (a) of this section, an owner or operator that elects to install, calibrate, maintain, and operat e a continuous emissions mon itoring 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 §60.42Da(a) of subpart Da of this part. (d) An owner and operator of an affected facility that combusts only natural gas is exempt from the PM and opacity standards specified in paragraph (a) of this section. (e) An owner or operator of an affected facility that combusts 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 is exempt from the PM standards specified in paragraph (a) of this section. §60.43 Standard for sulfur dioxide (SO 2 ). (a) Except as provided under para graph (d) of this section, on and after the date on which the performance test required to be conducted by §60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that contain SO 2 in excess of: (1) 340 ng/J heat input (0.80 lb/MMBtu) derived from liquid fossil fuel or liquid fossil fuel and wood residue. (2) 520 ng/J heat input (1.2 lb/MMBtu) derived fro m solid fossil fuel or solid fossil fuel and wood residue, except as provided in paragraph (e) of this section. (b) Except as provided under paragraph (d) of this section, when different fossil fuels are burned simultaneously in any combination, the applicable st andard (in ng/J) shall be determined by proration using the following formula: Comment [CF4]: Owner/operators of natural

gas

‐ fired facilities also presently subject to the opacity & PM standard.

Comment [CF5]: Exempt owners/operators of facilities burning natural gas from the PM & opacity standards.

Comment [CF6]: Exempt owners/operators of facilities burning natural gas and low sulfur oil from the PM standard.Where:

PS SO 2= Prorated standard for S O2 when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels or from all fo ssil fuels and wood residue fired; y = Percentage of total heat input derived from liquid fossil fuel; and z = Percentage of total heat input derived from solid fossil fuel. (c) Compliance shall be based on the total heat i nput from all fossil fuels burned, including gaseous fuels. (d) As an alternate to meeting the requirements of pa ragraphs (a) and (b) of this section, an owner or operator can petition the Administrator (in writing) to comply with §60.43Da(i)(3) of subpart Da of this part or comply with §60.42b(k)(4) of subpart Db of this part, as applicable to the affected source. 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 §60.43Da(i)(3) of subpart Da of this part or §60.42b(k)(4) of subpart Db of this part, as applicable to the affected source. (e) Units 1 and 2 (as defined in appendix G of this part) at the Newton Power Station owned or operated by the Central Illinois Public Service Company will be in compliance with paragraph (a)(2) of this section if Unit 1 and Unit 2 individually comply with paragraph (a)(2) of this section or if the combined emission rate from Units 1 and 2 does not exceed 470 ng/J (1.1 lb/MMBtu) combined heat input to Units 1 and 2. §60.44 Standard for nitrogen oxides (NO X ). (a) Except as provided under para graph (e) of this section, on and after the date on which the performance test required to be conducted by §60.8 is completed, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any gases that contain NO X , expressed as NO 2 in excess of: (1) 86 ng/J heat input (0.20 lb/MMB tu) derived from gaseous fossil fuel. (2) 129 ng/J heat input (0.30 lb/MMBtu) derived fr om liquid fossil fuel, liquid fossil fuel and wood residue, or gaseous fossil fuel and wood residue. (3) 300 ng/J heat input (0.70 lb/MMBtu) derived from solid fossil fuel or solid fossil fuel and wood residue (except lignite or a solid fossil fuel containi ng 25 percent, by weight, or more of coal refuse). (4) 260 ng/J heat input (0.60 lb MMBtu) derived fr om lignite or lignite and wood residue (except as provided under paragraph (a)(5) of this section). (5) 340 ng/J heat input (0.80 lb MMBtu) derived fr om lignite which is mined in North Dakota, South Dakota, or Montana and which is burned in a cyclone-fired unit. (b) Except as provided under paragraphs (c), (d), and (e ) of this section, when different fossil fuels are burned simultaneously in any combination, the applic able standard (in ng/J) is determined by proration using the following formula:Where:

PS NOX = Prorated standard for NO X when burning different fuels simultaneously, in ng/J heat input derived from all fossil fuels fired or from all fossil fuels and wood residue fired; w = Percentage of total heat input derived from lignite; x = Percentage of total heat input derived from gaseous fossil fuel; y = Percentage of total heat input derived from liquid fossil fuel; and z = Percentage of total heat input derive d from solid fossil fuel (except lignite). (c) When a fossil fuel containing at least 25 percent, by weight, of coal refuse is burned in combination with gaseous, liquid, or other solid fossil fuel or wood residue, the standard for NO X does not apply. (d) Except as provided under paragraph (e) of this section, cyclone-fired units which burn fuels containing at least 25 percent of lignite that is mine d in North Dakota, South Dakota, or Montana remain subject to paragraph (a)(5) of this section regardless of the types of fuel combusted in combination with that lignite. (e) As an alternate to meeting the requirements of para graphs (a), (b), and (d) of this section, an owner or operator can petition the Administrator (in writing) to comply with §60.44Da(e)(3) 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 §60.44Da(e)(3) of subpart Da of this part. §60.45 Emissions and fuel monitoring. (a) Each owner or operator of an affected facility subject to the applicable emissions standard shall install, calibrate, maintain, and operate continuo us 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 and COMS requirements under paragraph (a) of this section do not apply to owners or operators under the following conditions: (1) For a fossil-fuel-fired steam generator that burns combusts 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 COMS for measuring the opacity of emissions and CEMS for measuring 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. (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 been conducted. If the owner or operator demonstrates during the performance test that 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 initia l performance test results show that NO X emissions are greater than 70 percent of the applicab le standard, the owner or operator shall install a CEMS for NO X within one year after the date of the initial performance tests under §60.8 and comply with all other applicable monito ring requirements under this part. (4) If an owner or operator is not required to and elects does not install any CEMS for sulfur oxides SO 2 and NO X , as provided under paragraphs (b)(1) and (b)(3) or par agraphs (b)(2) and (b)(3) of this section a CEMS for measuring either O 2 or CO 2 is not required. Comment [CF7]: Clarify that COMS exemption for opacity monitoring(5) For affected facilities using a An owner or operator may petition the Administrator (in writing) to install a PM CEMS , a bag leak detection system to monitor the performance of a fabric filter (baghouse) according to the most current requirements in section §60.48Da of this part, or an ESP predictive model to monitor the performance of the ESP developed in accordance and operated according to the most current requirements in section §60.48Da of this part a COMS is not required as an alternative to the CEMS for monitoring opacity emissions. (6) A CEMS COMS for measuring the opacity of emissions is not required for a n affected facility fossil fuel

- fired steam generator that does not use post-combustion technology (except 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 sulf ur, and is operated such that emissions 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 accor ding to the procedures 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, ma intained, 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 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 ca libration 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 boiler operating day by multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate a nd 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 average 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 disc overy 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 calc ulations performed according to paragraph (b)(6) of this section and any corrective actions taken. The reco rd 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. (7) An owner or operator of an affected facility subject to an opacity standard under §60.42 that elects to not use a COMS because the affected facility burns on ly fuels as specified under paragraph (b)(1) of this section, monitors PM emissions as specified under pa ragraph (b)(5) of this section, or monitors CO emissions as specified under paragraph (b)(6) of th is section, shall conduct a performance test using Method 9 of appendix A–4 of this part and the pro cedures in §60.11 to demonstrate compliance with the Comment [CF8]: Add bag leak detection system and ESP model to COMS exemption optionsapplicable limit in §60.42 by April 29, 2011 or with in 45 days after stopping use of an existing COMS, whichever is later, and shall comply with either pa ragraph (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 individual 15-second observations are less than or equal to 20 percent during the initial 60 minutes of observation. The permitting authority may exempt owners or operators of affected facilities burning only natural gas from the opacity monitoring requirements

. (i) Except as provided in paragraph (b)(7)(ii) or (b)(7)(iii) of this se ction, the owner or operator shall conduct subsequent Method 9 of appendix A–4 of this part performance tests using the procedures in paragraph (b)(7) of this section acco rding to the applicable schedule in paragraphs (b)(7)(i)(A) through (b)(7)(i)(D) of this section, as determined by the mo st recent Method 9 of appendix A–4 of this part performance test results. (A) If no visible emissions are observed, a subse quent Method 9 of appendix A–4 of this part performance test must be completed within 12 cale ndar months from the date that the most recent performance test was conducted or within 45 days of the next day th at fuel with an opacity standard is combusted, whichever is later ; (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 the most recent performance test was conducted or within 45 days of the next day that fuel with an opaci ty standard is combusted, whichever is later ; (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 performance test must be completed within 3 calendar months from the date that the mo st recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later ; or (D) If the maximum 6-minute average opacity is gr eater than 10 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 45 calendar days from the date that the most recent performance test was conducted. (ii) 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 test, elect to perform subsequent monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in paragraphs (b)(7)(ii)(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 part and demonstrate that th e 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 visible emissions is gr eater 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 emis sions 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 45 calendar days according to the requirements in §60.46(b)(3). Comment [CF9]: No longer necessary since natural gas

‐ fired facilities exempt from the opacity standard.

Comment [CF10]: Allow flexibility to account for intermittent use of fuels with an opacity standard.(B) If no visible emissions are observed for 30 10 operating days during which an opacity standard is applicable, observations can be reduced to once ever y 7 operating days during which an opacity standard is applicable. If any visible emissions are obs erved, daily observations shall be resumed. (iii) 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 owner or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 performance test s, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitoring plan approved by the Administrator. The observations shal l be similar, but not necessarily identical, to the requirements in paragraph (b)(7)(ii) of this section. For reference purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission Opacity fro m 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 Pl anning 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 Netw ork (TTN) under Emission Measurement Center Preliminary Methods. (c) For performance evaluations under §60.13(c) an d calibration checks under §60.13(d), the following procedures shall be used: (1) Methods 6, 7, and 3B of appendix A of this part , as applicable, shall be used for the performance evaluations of SO 2 and NO X continuous monitoring systems. Accept able 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, shall 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 paragraph (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 derived 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 appendix 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 according to the applicable procedures in section 2 of appendix A to part 75 of this chapter. (5) For a fossil-fuel-fired steam generator that si multaneously 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 this section, the following conversion procedures shall be used to convert the continuous monitoring da ta into units of the app licable 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 c onsistent 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. (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 basis (wet or dry) and the following conversion procedure shall be used:

Where E, C, F c and %CO 2 are determined under paragraph (f) of this section. (f) The values used in the equations under paragra phs (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), determ ined with equipment specified under paragraph (a) of this section. (4) F, F c = a factor representing a ratio of the volume of dr y 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 cla ssified 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 classified 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). (5) The owner or operator may use the following equation 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 weight 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 appl icable. (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 D1826 for gaseous fuels as applicable. (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 prorated 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 n = Number of fuels being burned in combination. (g) Excess emission and monitoring system performanc e reports shall be submitted to the Administrator semiannually for each six-month period in the calenda r year. All semiannual reports shall be postmarked by the 30th day following the end of each six-month period. Each excess emis sion and MSP report shall include the information required in §60.7(c). Periods of excess emissions and monitoring systems (MS) downtime that shall be reported are defined as follows: (1) Opacity . Excess emissions are defined as any six-minute 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 emissions 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 sixminute 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 with §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 standard 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 part or §§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 with §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 sta ndard 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 facilitie s 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 st andards in §60.42. Affected facilities using PM CEMS must follow the most current applicable co mpliance and monitoring provisions in §§60.48Da and 60.49Da of subpart Da of this part. (h) The owner or operator of an affected facility s ubject 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 specified in paragraphs (h)(1) through (3 ) of this section, as applicable to the visible emissions monitoring method used. (1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner or operator shall keep the records including the information 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 visible 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 conducted using Method 22 of appendix A–4 of this part, the owner or operator shall keep the records including the information 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 observer 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 operato r to demonstrate compliance with the applicable monitoring requirements. (3) For each digital opacity compliance system, the owner or operator shall maintain records and submit reports according to the requirements specified in the site-specific monitoring plan approved by the Administrator. §60.46 Test methods and procedures. (a) In conducting the performance tests required in §60. 8, and subsequent performance tests as requested by the EPA Administrator, the owner or operator shall use as reference methods and procedures the test methods in appendix A of this part or other methods and procedures as specifie d in this section, except as provided in §60.8(b). Acceptable alternative met hods and procedures are given in paragraph (d) of this section. (b) The owner or operator shall determine compliance with the PM, SO 2 , and NO X standards in §§60.42, 60.43, and 60.44 as follows:(1) The emission rate (E) of PM, SO 2 , or NO X shall be computed for each run using the following equation:

Where: E = Emission rate of pollutant, ng/J (1b/million Btu); C = Concentration of pollutant, ng/dscm (1b/dscf);

%O 2 = O 2 concentration, percent dry basis; and

F d = Factor as determined from Method 19 of appendix A of this part. (2) Method 5 of appendix A of this part shall be used to determine the PM concentration (C) at affected facilities without wet flue-gas-desulfurization (FGD) sy stems and Method 5B of appendix A of this part shall be used to determine the PM concentration (C) after FGD systems. (i) The sampling time and sample volume for each ru n shall be at least 60 minutes and 0.85 dscm (30 dscf). The probe and filter holder heating systems in the sampling train shall be set to provide an average gas temperature of 160±14 °C (320±25 °F). (ii) The emission rate correction factor, integrated or grab sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O 2 concentration (%O 2 ). The O 2 sample shall be obtained simultaneously with, and at the same tr averse points as, the particulate sample. If the grab sampling procedure is used, the O 2 concentration for the run shall be the arithmetic mean of the sample O 2 concentrations at all traverse points. (iii) If the particulate run has more than 12 traverse points, the O 2 traverse points may be reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O 2 traverse points. (3) Method 9 of appendix A of this part and the proc edures in §60.11 shall be used to determine opacity. (4) Method 6 of appendix A of this part shall be used to determine the SO 2 concentration. (i) The sampling site shall be the same as that selected for the particulate sample. The sampling location in the duct shall be at the centroid of the cross section or at a point no closer to the walls than 1 m (3.28 ft). The sampling time and sample volume for each sample run shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Two samples shal l be taken during a 1-hour period, with each sample taken within a 30-minute interval. (ii) The emission rate correction factor, integrated sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O 2 concentration (%O 2 ). The O 2 sample shall be taken simultaneously with, and at the same point as, the SO 2 sample. The SO 2 emission rate shall be computed for each pair of SO 2 and O 2 samples. The SO 2 emission rate (E) for each run shall be the arithmetic mean of the results of the two pairs of samples. (5) Method 7 of appendix A of this part shall be used to determine the NO X concentration. (i) The sampling site and location shall be the same as for the SO 2 sample. Each run shall consist of four grab samples, with each sample taken at about 15-minute intervals. (ii) For each NO X sample, the emission rate correction factor , grab sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O 2 concentration (%O 2 ). The sample shall be taken simultaneously with, and at the same point as, the NO X sample.(iii) The NO X emission rate shall be computed for each pair of NO X and O 2 samples. The NO X emission rate (E) for each run shall be the arithmetic mean of the results of the four pairs of samples. (c) When combinations of fossil fuels or fossil fuel and wood residue are fired, the owner or operator (in order to compute the prorated standard as s hown in §§60.43(b) and 60.44(b)) shall determine the percentage (w, x, y, or z) of the total heat i nput derived from each type of fuel as follows: (1) The heat input rate of each fuel shall be determ ined by multiplying the gross calorific value of each fuel fired by the rate of each fuel burned. (2) ASTM Methods D2015, or D5865 (solid fuels), D240 (liquid fuels), or D1826 (gaseous fuels) (all of these methods are incorporated by reference, see §60.17) shall be used to determine the gross calorific values of the fuels. The method used to determine the calorific value of wood residue must be approved by the Administrator. (3) Suitable methods shall be used to determine the rate of each fuel burned during each test period, and a material balance over the steam generating sy stem shall be used to confirm the rate. (d) The owner or operator may use the following as a lternatives to the reference methods and procedures in this section or in other sections as specified: (1) The emission rate (E) of PM, SO 2 and NO X may be determined by using the Fc factor, provided that the following procedure is used: (i) The emission rate (E) shall be co mputed using the following equation:

Where: E = Emission rate of pollutant, ng/J (lb/MMBtu); C = Concentration of pollutant, ng/dscm (lb/dscf);

%CO 2 = CO 2 concentration, percent dry basis; and

F c = Factor as determined in appropriate secti ons of Method 19 of appendix A of this part. (ii) If and only if the average Fc factor in Method 19 of appendix A of this part is used to calculate E and either E is from 0.97 to 1.00 of the emission standa rd or the relative accuracy of a continuous emission monitoring system is from 17 to 20 percent, then th ree runs of Method 3B of appendix A of this part shall be used to determine the O 2 and CO 2 concentration according to the procedures in paragraph (b)(2)(ii), (4)(ii), or (5)(ii) of this section. Then if F o (average of three runs), as calculated from the equation in Method 3B of appendix A of this part, is more than ±3 percent than the average F o value, as determined from the average values of F d and F c in Method 19 of appendix A of this part, i.e. , F oa = 0.209 (F da /F ca ), then the following procedure shall be followed: (A) When F o is less than 0.97 F oa , then E shall be increased by that proportion under 0.97 F oa , e.g. , if F o is 0.95 F oa , E shall be increased by 2 percent. This recalculated value shall be used to determine compliance with the emission standard. (B) When F o is less than 0.97 F oa and when the average difference (d) between the continuous monitor minus the reference methods is negative, then E shall be increased by that proportion under 0.97 F oa , e.g. , if F o is 0.95 F oa , E shall be increased by 2 percent. This recalculated value shall be used to determine compliance with the relative accuracy specification.(C) When F o is greater than 1.03 F oa and when the average difference d is positive, then E shall be decreased by that proportion over 1.03 F oa , e.g. , if F o is 1.05 F oa , E shall be decreased by 2 percent. This recalculated value shall be used to determine comp liance with the relative accuracy specification. (2) For Method 5 or 5B of appendix A–3 of this part , Method 17 of appendix A–6 of this part may be used at facilities with or without wet FGD systems if the stack gas temperature at the sampling location does not exceed an average 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 with Method 17 of appendix A–6 of this part only if it is used after wet FGD systems. Method 17 of appe ndix A–6 of this part shall not be used after wet FGD systems if the effluent gas is saturated or laden with water droplets. (3) Particulate matter and SO 2 may be determined simultaneously with the Method 5 of appendix A of this part train provided that the following changes are made: (i) The filter and impinger apparatus in sections 2.1.5 a nd 2.1.6 of Method 8 of appendix A of this part is used in place of the condenser (section 2.1.7) of Method 5 of appendix A of this part. (ii) All applicable procedures in Method 8 of appendix A of this part for the determination of SO 2 (including moisture) are used: (4) For Method 6 of appendix A of this part, Method 6C of appendix A of this part may be used. Method 6A of appendix A of this part may also be used wh enever Methods 6 and 3B of appendix A of this part data are specified to determine the SO 2 emission rate, under the conditions in paragraph (d)(1) of this section. (5) 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 at least 1 hour and the integrated sampling approach shall be used to determine the O 2 concentration (%O 2 ) for the emission rate correction factor. (6) For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used. (7) For Method 3B of appendix A of this part, Met hod 3A of appendix A of this part may be used.