40 CFR 60.49Da - Emission monitoring.

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§ 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 paragraphs (a)(2) and (4) of this section, the owner or operator of an affected facility subject to an opacity standard, 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 the 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 SO2 control system), alternate parameters indicative of the PM control system's performance 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), (iii), or (iv) of this section may elect to monitor opacity as specified in paragraph (a)(3) of this section.
(i) The affected facility uses a fabric filter (baghouse) to meet the standards 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 SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion technology to reduce emissions of SO2 or PM;
(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, SO2, or CO emissions;
(B) Only natural gas, gaseous fuels, or fuel oils that contain less than or equal 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 demonstrated by the use of a CEMS measuring CO emissions according to the procedures specified in paragraph (u) of this section; or
(iv) The affected facility uses an ESP and uses 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.
(3) The owner or operator 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 test requirement in paragraph (a)(3)(i) must be conducted 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.
(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 initial 60 minutes of the observation all the 6-minute averages are less than 10 percent and all the individual 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 Method 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)(C) of this section, as determined by the most recent Method 9 of appendix A-4 of this part performance test results.
(A) If 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 12 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 opacity standard is combusted, whichever is later;
(B) 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 most 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
(C) 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 calendar days from the date that the most recent performance 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 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)(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 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 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 sum 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 (a)(3)(i) of this section within 45 calendar days according to the requirements in § 60.50Da(b)(3).
(B) If no visible emissions are observed for 10 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 visible emissions are observed, daily observations shall be resumed.
(4) An owner or operator of an affected facility that is subject to an opacity standard under § 60.42a(b) is not required to operate a COMS provided that affected facility meets the conditions in either paragraph (a)(4)(i) or (ii) of this section.
(i) The affected facility combusts only gaseous fuels and/or liquid fuels (excluding residue oil) with a potential SO2 emissions rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit 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 parameters for the affected facility indicative of compliance with the opacity standard. For testing performed as part of this site-specific monitoring plan, the permitting authority may require as an alternative to the notification and reporting requirements specified in §§ 60.8 and 60.11 that the owner or operator submit any deviations with the excess emissions report required under § 60.51Da(d).
(ii) The owner or operator of the affected facility installs, calibrates, operates, and maintains a particulate matter continuous parametric monitoring system (PM CPMS) according to the requirements specified in subpart UUUUU of part 63.
(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 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)(3)(iii) of this section. 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.
(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 SO2 emissions, except where natural gas and/or liquid fuels (excluding residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less are the only fuels combusted, as follows:
(1) Sulfur dioxide emissions are monitored at both the inlet and outlet of the SO2 control device.
(2) For a facility that qualifies under the numerical limit provisions of § 60.43Da, SO2 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 SO2 emissions in place of a continuous SO2 emission monitor at the inlet to the SO2 control device as required under paragraph (b)(1) of this section.
(4) If the owner or operator has installed and certified a SO2 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 CO2 or O2 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 SO2 emission limit in lb/MMBtu under § 60.43Da:
(A) When relative accuracy testing is conducted, SO2 concentration data and CO2 (or O2) data are collected simultaneously; and
(B) In addition to meeting the applicable SO2 and CO2 (or O2) 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 SO2 and, if required, CO2 (or O2) 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 SO2 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 NOX emissions discharged to the atmosphere; or
(2) If the owner or operator has installed a NOX 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 § 60.51Da. 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 O2 or carbon dioxide (CO2) content of the flue gases at each location where SO2 or NOX emissions are monitored. For affected facilities subject to a lb/MMBtu SO2 emission limit under § 60.43Da, if the owner or operator has installed and certified a CO2 or O2 monitoring system according to § 75.20(c) of this chapter and appendix A to part 75 of this chapter and the monitoring system continues to meet the applicable quality-assurance provisions 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 SO2 concentration monitoring system described in paragraph (b) of this section, to determine the SO2 emission rate in lb/MMBtu. SO2 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.
(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 including periods of startup, shutdown, and malfunction, except for CEMS breakdowns, repairs, calibration checks, and zero and span adjustments.
(f)
(1) For units that began construction, reconstruction, or modification on or before February 28, 2005, the owner or operator shall obtain 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 data with 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 construction, reconstruction, or modification after February 28, 2005, the owner or operator shall obtain emission data for at least 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 data with 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 paragraph § 60.13(h) are expressed in ng/J (lb/MMBtu) heat input and used to calculate the average emission rates 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 requirements in paragraph (f) of this section, the owner or operator shall use the reference methods and procedures as specified in this paragraph. Acceptable alternative methods and procedures are given in paragraph (j) of this section.
(1) Method 6 of appendix A of this part shall be used to determine the SO2 concentration at the same location as the SO2 monitor. Samples shall be taken at 60-minute intervals. The sampling time and sample 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 NOX concentration at the same location as the NOX 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 O2 or CO2 concentration at the same location as the O2 or CO2 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 procedures in this paragraph to conduct monitoring system performance evaluations under § 60.13(c) and calibration checks under § 60.13(d). Acceptable alternative methods and procedures are given in paragraph (j) of this section.
(1) Methods 3B, 6, and 7 of appendix A of this part shall be used to determine O2, SO2, and NOX concentrations, respectively.
(2) SO2 or NOX (NO), as applicable, shall be used for preparing the calibration gas mixtures (in N2, as applicable) under Performance Specification 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 NOX shall be determined using one of the following procedures:
(i) Except as provided under paragraph (i)(3)(ii) of this section, NOX span values shall be determined as follows:
Fossil fuel Span values for NOX (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 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 (i)(3)(i) of this section, the owner or operator of an affected facility may elect to use the NOX 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 values 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 paragraph (i)(3)(i) of this section, the span value of the SO2 CEMS at the inlet to the SO2 control device is 125 percent of the maximum estimated hourly potential emissions of the fuel fired, and the outlet of the SO2 control device is 50 percent of maximum estimated hourly potential emissions of the fuel fired. For affected facilities determining span values under paragraph (i)(3)(ii) of this section, SO2 span values shall be determined according 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 section, 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 3A or 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) through (3) of this section shall be used to determine gross energy output for sources demonstrating compliance with an output-based standard.
(1) The owner or operator of an affected facility with electricity generation shall install, calibrate, maintain, and operate a wattmeter; measure gross electrical 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, temperature, 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 an affected facility generating process steam in combination with electrical generation, the gross energy output is determined according to the definition of “gross energy output” specified in § 60.41Da that is applicable to the affected facility.
(l) The owner or operator of an affected facility demonstrating compliance with an output-based standard shall install, certify, operate, and maintain a continuous flow monitoring system meeting the requirements of Performance Specification 6 of appendix B of this part and the calibration drift (CD) assessment, relative accuracy test audit (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 chapter 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 according 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 this section, a fuel flow monitoring 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 NOX standards of § 60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate a CEMS to measure NOX emissions; a wattmeter to measure gross electrical output; meters to measure steam flow, temperature, and pressure; and a continuous flow monitoring system to measure the flow of exhaust gases discharged to the atmosphere.
(p) -(r) [Reserved]
(s) The owner or operator shall prepare and submit to the Administrator for approval a unit-specific monitoring plan for each monitoring system, at least 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 paragraphs (s)(1) through (6) of this section.
(1) Installation of the CEMS sampling probe or other interface at a measurement location relative to each affected process unit such that the measurement 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 procedures and acceptance criteria (e.g., calibrations, relative accuracy test audits (RATA), etc.);
(4) Ongoing operation and maintenance procedures in accordance with the general requirements of § 60.13(d) or part 75 of this chapter (as applicable);
(5) Ongoing data quality assurance procedures in accordance 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 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 emissions limit in § 60.42Da may install, certify, 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, non-out-of-control 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-boiler operating 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 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 and divided by the corresponding average hourly useful energy output from the affected facility. The 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 average CO emission level each boiler operating day excluding periods of affected facility startup, shutdown, 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 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 1.4 lb/MWh or less.
(4) You must record the CO measurements and calculations performed according to paragraph (u)(3) 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 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 Specification 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 CEMS required by Performance Specification 11 in appendix B of this part, PM and O2 (or CO2) data shall be collected concurrently (or within a 30- to 60-minute period) by both the CEMS 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) For O2 (or CO2), 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. Relative Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years.
(4) As of January 1, 2012, and within 90 days after the date of completing each performance test, as defined in § 60.8, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data, except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/ ) or other compatible electronic spreadsheet. Only data collected using test methods compatible with ERT are subject to this requirement to be submitted electronically into EPA's WebFire database.
(w) The owner or operator using a SO2, NOX, CO2, and O2 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 SO2, NOX, CO2, and O2 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 procedures in appendices A and 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 part, 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 alternative data accuracy assessment procedures. For all required CO2 and O2 CEMS and for SO2 and NOX 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 SO2 and NOX 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 CO2 and O2 CEMS and for SO2 and NOX CEMS with span values greater than 30 ppm, quarterly linearity checks may be performed in accordance with section 2.2.1 of appendix B to part 75 of this chapter, instead of performing the cylinder gas audits (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 part; 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 SO2 and NOX 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 SO2, CO2, and O2 CEMS and for NOX CEMS, RATAs may be performed in accordance with section 2.3 of appendix B to part 75 of this chapter instead of following the procedures described in Procedure 1, section 5.1.1 of appendix 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 part; 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 SO2 (regardless of the SO2 emission level during the RATA), and for NOX when the average NOX emission rate measured by the reference 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.
[72 FR 32722, June 13, 2007, as amended at 74 FR 5081, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011; 77 FR 9456, Feb. 16, 2012; 77 FR 23402, Apr. 19, 2012]

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  • 2014-11-19; vol. 79 # 223 - Wednesday, November 19, 2014
    1. 79 FR 68777 - Reconsideration of Certain Startup/Shutdown Issues: National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units
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      ENVIRONMENTAL PROTECTION AGENCY
      Final rule; notice of final action on reconsideration.
      The effective date of the rule is November 19, 2014.
      40 CFR Parts 60 and 63

This is a list of United States Code sections, Statutes at Large, Public Laws, and Presidential Documents, which provide rulemaking authority for this CFR Part.

This list is taken from the Parallel Table of Authorities and Rules provided by GPO [Government Printing Office].

It is not guaranteed to be accurate or up-to-date, though we do refresh the database weekly. More limitations on accuracy are described at the GPO site.


United States Code
U.S. Code: Title 42 - THE PUBLIC HEALTH AND WELFARE

§ 7401 - Congressional findings and declaration of purpose

§ 7402 - Cooperative activities

§ 7403 - Research, investigation, training, and other activities

§ 7404 - Research relating to fuels and vehicles

§ 7405 - Grants for support of air pollution planning and control programs

§ 7406 - Interstate air quality agencies; program cost limitations

§ 7407 - Air quality control regions

§ 7408 - Air quality criteria and control techniques

§ 7409 - National primary and secondary ambient air quality standards

§ 7410 - State implementation plans for national primary and secondary ambient air quality standards

§ 7411 - Standards of performance for new stationary sources

§ 7412 - Hazardous air pollutants

§ 7413 - Federal enforcement

§ 7414 - Recordkeeping, inspections, monitoring, and entry

§ 7415 - International air pollution

§ 7416 - Retention of State authority

§ 7417 - Advisory committees

§ 7418 - Control of pollution from Federal facilities

§ 7419 - Primary nonferrous smelter orders

§ 7420 - Noncompliance penalty

§ 7421 - Consultation

§ 7422 - Listing of certain unregulated pollutants

§ 7423 - Stack heights

§ 7424 - Assurance of adequacy of State plans

§ 7425 - Measures to prevent economic disruption or unemployment

§ 7426 - Interstate pollution abatement

§ 7427 - Public notification

§ 7428 - State boards

§ 7429 - Solid waste combustion

§ 7430 - Emission factors

§ 7431 - Land use authority

§ 7450 to 7459 - Repealed.

§ 7470 - Congressional declaration of purpose

§ 7471 - Plan requirements

§ 7472 - Initial classifications

§ 7473 - Increments and ceilings

§ 7474 - Area redesignation

§ 7475 - Preconstruction requirements

§ 7476 - Other pollutants

§ 7477 - Enforcement

§ 7478 - Period before plan approval

§ 7479 - Definitions

§ 7491 - Visibility protection for Federal class I areas

§ 7492 - Visibility

§ 7501 - Definitions

§ 7502 - Nonattainment plan provisions in general

§ 7503 - Permit requirements

§ 7504 - Planning procedures

§ 7505 - Environmental Protection Agency grants

§ 7505a - Maintenance plans

§ 7506 - Limitations on certain Federal assistance

§ 7506a - Interstate transport commissions

§ 7507 - New motor vehicle emission standards in nonattainment areas

§ 7508 - Guidance documents

§ 7509 - Sanctions and consequences of failure to attain

§ 7509a - International border areas

§ 7511 - Classifications and attainment dates

§ 7511a - Plan submissions and requirements

§ 7511b - Federal ozone measures

§ 7511c - Control of interstate ozone air pollution

§ 7511d - Enforcement for Severe and Extreme ozone nonattainment areas for failure to attain

§ 7511e - Transitional areas

§ 7511f - NO

§ 7512 - Classification and attainment dates

§ 7512a - Plan submissions and requirements

§ 7513 - Classifications and attainment dates

§ 7513a - Plan provisions and schedules for plan submissions

§ 7513b - Issuance of RACM and BACM guidance

§ 7514 - Plan submission deadlines

§ 7514a - Attainment dates

§ 7515 - General savings clause

§ 7521 - Emission standards for new motor vehicles or new motor vehicle engines

§ 7522 - Prohibited acts

§ 7523 - Actions to restrain violations

§ 7524 - Civil penalties

§ 7525 - Motor vehicle and motor vehicle engine compliance testing and certification

§ 7541 - Compliance by vehicles and engines in actual use

§ 7542 - Information collection

§ 7543 - State standards

§ 7544 - State grants

§ 7545 - Regulation of fuels

§ 7546 - Renewable fuel

§ 7547 - Nonroad engines and vehicles

§ 7548 - Study of particulate emissions from motor vehicles

§ 7549 - High altitude performance adjustments

§ 7550 - Definitions

§ 7551 - Omitted

§ 7552 - Motor vehicle compliance program fees

§ 7553 - Prohibition on production of engines requiring leaded gasoline

§ 7554 - Urban bus standards

§ 7571 - Establishment of standards

§ 7572 - Enforcement of standards

§ 7573 - State standards and controls

§ 7574 - Definitions

§ 7581 - Definitions

§ 7582 - Requirements applicable to clean-fuel vehicles

§ 7583 - Standards for light-duty clean-fuel vehicles

§ 7584 - Administration and enforcement as per California standards

§ 7585 - Standards for heavy-duty clean-fuel vehicles (GVWR above 8,500 up to 26,000 lbs.)

§ 7586 - Centrally fueled fleets

§ 7587 - Vehicle conversions

§ 7588 - Federal agency fleets

§ 7589 - California pilot test program

§ 7590 - General provisions

§ 7601 - Administration

Title 40 published on 2014-07-01

The following are ALL rules, proposed rules, and notices (chronologically) published in the Federal Register relating to 40 CFR 60 after this date.

  • 2014-11-19; vol. 79 # 223 - Wednesday, November 19, 2014
    1. 79 FR 68777 - Reconsideration of Certain Startup/Shutdown Issues: National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units
      GPO FDSys XML | Text
      ENVIRONMENTAL PROTECTION AGENCY
      Final rule; notice of final action on reconsideration.
      The effective date of the rule is November 19, 2014.
      40 CFR Parts 60 and 63