40 CFR 60.104a - Performance tests.

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§ 60.104a Performance tests.
Link to an amendment published at 80 FR 75231, Dec. 1, 2015.

(a) The owner or operator shall conduct a performance test for each FCCU, FCU, sulfur recovery plant, flare and fuel gas combustion device to demonstrate initial compliance with each applicable emissions limit in § 60.102a according to the requirements of § 60.8. The notification requirements of § 60.8(d) apply to the initial performance test and to subsequent performance tests required by paragraph (b) of this section (or as required by the Administrator), but does not apply to performance tests conducted for the purpose of obtaining supplemental data because of continuous monitoring system breakdowns, repairs, calibration checks and zero and span adjustments.

(b) The owner or operator of a FCCU or FCU that elects to monitor control device operating parameters according to the requirements in § 60.105a(b), to use bag leak detectors according to the requirements in § 60.105a(c), or to use COMS according to the requirements in § 60.105a(e) shall conduct a PM performance test at least once every 12 months and furnish the Administrator a written report of the results of each test.

(c) In conducting the performance tests required by this subpart (or as requested by the Administrator), the owner or operator shall use the test methods in 40 CFR part 60, Appendices A-1 through A-8 or other methods as specified in this section, except as provided in § 60.8(b).

(d) The owner or operator shall determine compliance with the PM, NOX, SO2, and CO emissions limits in § 60.102a(b) for FCCU and FCU using the following methods and procedures:

(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses.

(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate.

(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

(4) Method 5, 5B, or 5F of appendix A-3 to part 60 for determining PM emissions and associated moisture content from a FCCU or FCU without a wet scrubber subject to the emissions limit in § 63.102a(b)(1). Use Method 5 or 5B of appendix A-3 to part 60 for determining PM emissions and associated moisture content from a FCCU or FCU with a wet scrubber subject to the emissions limit in § 63.102a(b)(1).

(i) The PM performance test consists of 3 valid test runs; the duration of each test run must be no less than 60 minutes.

(ii) The emissions rate of PM (EPM) is computed for each run using Equation 5 of this section:

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Where:
E = Emission rate of PM, g/kg (lb/1,000 lb) of coke burn-off;
cs = Concentration of total PM, grams per dry standard cubic meter (g/dscm) (gr/dscf);
Qsd = Volumetric flow rate of effluent gas, dry standard cubic meters per hour (dry standard cubic feet per hour);
Rc = Coke burn-off rate, kilograms per hour (kg/hr) [lb per hour (lb/hr)] coke; and
K = Conversion factor, 1.0 grams per gram (7,000 grains per lb).

(iii) The coke burn-off rate (Rc) is computed for each run using Equation 6 of this section:

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Where:
Rc = Coke burn-off rate, kg/hr (lb/hr);
Qr = Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before any emissions control or energy recovery system that burns auxiliary fuel, dry standard cubic meters per minute (dscm/min) [dry standard cubic feet per minute (dscf/min)];
Qa = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air to FCCU regenerator or fluid coking unit, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide (CO2) concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
%CO = CO concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
%O2 = O2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
%Ooxy = O2 concentration in O2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis);
K1 = Material balance and conversion factor, 0.2982 (kg-min)/(hr-dscm-%) [0.0186 (lb-min)/(hr-dscf-%)];
K2 = Material balance and conversion factor, 2.088 (kg-min)/(hr-dscm) [0.1303 (lb-min)/(hr-dscf)]; and
K3 = Material balance and conversion factor, 0.0994 (kg-min)/(hr-dscm-%) [0.00624 (lb-min)/(hr-dscf-%)].

(iv) During the performance test, the volumetric flow rate of exhaust gas from catalyst regenerator (Qr) before any emission control or energy recovery system that burns auxiliary fuel is measured using Method 2 of appendix A-1 to part 60.

(v) For subsequent calculations of coke burn-off rates or exhaust gas flow rates, the volumetric flow rate of Qr is calculated using average exhaust gas concentrations as measured by the monitors required in § 60.105a(b)(2), if applicable, using Equation 7 of this section:

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Where:
Qr = Volumetric flow rate of exhaust gas from FCCU regenerator or fluid coking burner before any emission control or energy recovery system that burns auxiliary fuel, dscm/min (dscf/min);
Qa = Volumetric flow rate of air to FCCU regenerator or fluid coking burner, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
Qoxy = Volumetric flow rate of O2 enriched air to FCCU regenerator or fluid coking unit, as determined from the unit's control room instrumentation, dscm/min (dscf/min);
%CO2 = Carbon dioxide concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis);
%CO = CO concentration FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis). When no auxiliary fuel is burned and a continuous CO monitor is not required in accordance with § 60.105a(h)(3), assume %CO to be zero;
%O2 = O2 concentration in FCCU regenerator or fluid coking burner exhaust, percent by volume (dry basis); and
%Ooxy = O2 concentration in O2 enriched air stream inlet to the FCCU regenerator or fluid coking burner, percent by volume (dry basis).

(5) Method 6, 6A, or 6C of appendix A-4 to part 60 for moisture content and for the concentration of SO2; the duration of each test run must be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60.

(6) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the concentration of NOX calculated as nitrogen dioxide (NO2); the duration of each test run must be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60.

(7) Method 10, 10A, or 10B of appendix A-4 to part 60 for moisture content and for the concentration of CO. The sampling time for each run must be 60 minutes.

(8) The owner or operator shall adjust PM, NOX, SO2 and CO pollutant concentrations to 0-percent excess air or 0-percent O2 using Equation 8 of this section:

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Where:
Cadj = pollutant concentration adjusted to 0-percent excess air or O2, parts per million (ppm) or g/dscm;
Cmeas = pollutant concentration measured on a dry basis, ppm or g/dscm;
20.9c = 20.9 percent O2−0.0 percent O2 (defined O2 correction basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry basis, percent.

(e) The owner or operator of a FCCU or FCU that is controlled by an electrostatic precipitator or wet scrubber and that is subject to control device operating parameter limits in § 60.102a(c) shall establish the limits based on the performance test results according to the following procedures:

(1) Reduce the parameter monitoring data to hourly averages for each test run;

(2) Determine the hourly average operating limit for each required parameter as the average of the three test runs.

(f) The owner or operator of an FCCU or FCU that uses cyclones to comply with the PM limit in § 60.102a(b)(1) and elects to comply with the COMS alternative monitoring option in § 60.105a(d) shall establish a site-specific opacity operating limit according to the procedures in paragraphs (f)(1) through (3) of this section.

(1) Collect COMS data every 10 seconds during the entire period of the PM performance test and reduce the data to 6-minute averages.

(2) Determine and record the hourly average opacity from all the 6-minute averages.

(3) Compute the site-specific limit using Equation 9 of this section:

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Where:
Opacity limit = Maximum permissible 3-hour average opacity, percent, or 10 percent, whichever is greater;
Opacityst = Hourly average opacity measured during the source test, percent; and
PMEmRst = PM emission rate measured during the source test, lb/1,000 lb coke burn.

(g) The owner or operator of a FCCU or FCU that is exempt from the requirement to install and operate a CO CEMS pursuant to § 60.105a(h)(3) and that is subject to control device operating parameter limits in § 60.102a(c) shall establish the limits based on the performance test results using the procedures in paragraphs (g)(1) and (2) of this section.

(1) Reduce the temperature and O2 concentrations from the parameter monitoring systems to hourly averages for each test run.

(2) Determine the operating limit for temperature and O2 concentrations as the average of the average temperature and O2 concentration for the three test runs.

(h) The owner or operator shall determine compliance with the SO2 and H2S emissions limits for sulfur recovery plants in §§ 60.102a(f)(1)(i), 60.102a(f)(1)(iii), 60.102a(f)(1)(iii), 60.102a(f)(2)(i), and 60.102a(f)(2)(iii) and the reduced sulfur compounds and H2S emissions limits for sulfur recovery plants in § 60.102a(f)(1)(ii) and § 60.102a(f)(2)(ii) using the following methods and procedures:

(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses.

(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate.

(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60.

(4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO2 concentration. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60.

(5) Method 15 or 15A of appendix A-5 to part 60 or Method 16 of appendix A-6 to part 60 to determine the reduced sulfur compounds and H2S concentrations. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.

(i) Each run consists of 16 samples taken over a minimum of 3 hours.

(ii) The owner or operator shall calculate the average H2S concentration after correcting for moisture and O2 as the arithmetic average of the H2S concentration for each sample during the run (ppmv, dry basis, corrected to 0 percent excess air).

(iii) The owner or operator shall calculate the SO2 equivalent for each run after correcting for moisture and O2 as the arithmetic average of the SO2 equivalent of reduced sulfur compounds for each sample during the run (ppmv, dry basis, corrected to 0 percent excess air).

(iv) The owner or operator shall use Equation 8 of this section to adjust pollutant concentrations to 0-percent O2 or 0- percent excess air.

(i) The owner or operator shall determine compliance with the SO2 and NOX emissions limits in § 60.102a(g) for a fuel gas combustion device according to the following test methods and procedures:

(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses;

(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate;

(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60;

(4) Method 6, 6A, or 6C of appendix A-4 to part 60 to determine the SO2 concentration. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 6 or 6A of appendix A-4 to part 60.

(i) The performance test consists of 3 valid test runs; the duration of each test run must be no less than 1 hour.

(ii) If a single fuel gas combustion device having a common source of fuel gas is monitored as allowed under § 60.107a(a)(1)(v), only one performance test is required. That is, performance tests are not required when a new affected fuel gas combustion device is added to a common source of fuel gas that previously demonstrated compliance.

(5) Method 7, 7A, 7C, 7D, or 7E of appendix A-4 to part 60 for moisture content and for the concentration of NOX calculated as NO2; the duration of each test run must be no less than 4 hours. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 7 or 7C of appendix A-4 to part 60.

(6) For process heaters with a rated heat capacity between 40 and 100 MMBtu/hr that elect to demonstrate continuous compliance with a maximum excess oxygen limit as provided in § 60.107a(c)(6) or (d)(8), the owner or operator shall establish the O2 operating limit or O2 operating curve based on the performance test results according to the requirements in paragraph (i)(6)(i) or (ii) of this section, respectively.

(i) If a single O2 operating limit will be used:

(A) Conduct the performance test following the methods provided in paragraphs (i)(1), (2), (3) and (5) of this section when the process heater is firing at no less than 70 percent of the rated heat capacity. For co-fired process heaters, conduct at least one of the test runs while the process heater is being supplied by both fuel gas and fuel oil and conduct at least one of the test runs while the process heater is being supplied solely by fuel gas.

(B) Each test will consist of three test runs. Calculate the NOX concentration for the performance test as the average of the NOX concentrations from each of the three test runs. If the NOX concentration for the performance test is less than or equal to the numerical value of the applicable NOX emissions limit (regardless of averaging time), then the test is considered to be a valid test.

(C) Determine the average O2 concentration for each test run of a valid test.

(D) Calculate the O2 operating limit as the average O2 concentration of the three test runs from a valid test.

(ii) If an O2 operating curve will be used:

(A) Conduct a performance test following the methods provided in paragraphs (i)(1), (2), (3) and (5) of this section at a representative condition for each operating range for which different O2 operating limits will be established. Different operating conditions may be defined as different firing rates (e.g., above 50 percent of rated heat capacity and at or below 50 percent of rated heat capacity) and/or, for co-fired process heaters, different fuel mixtures (e.g., primarily gas fired, primarily oil fired, and equally co-fired, i.e., approximately 50 percent of the input heating value is from fuel gas and approximately 50 percent of the input heating value is from fuel oil). Performance tests for different operating ranges may be conducted at different times.

(B) Each test will consist of three test runs. Calculate the NOX concentration for the performance test as the average of the NOX concentrations from each of the three test runs. If the NOX concentration for the performance test is less than or equal to the numerical value of the applicable NOX emissions limit (regardless of averaging time), then the test is considered to be a valid test.

(C) If an operating curve is developed for different firing rates, conduct at least one test when the process heater is firing at no less than 70 percent of the rated heat capacity and at least one test under turndown conditions (i.e., when the process heater is firing at 50 percent or less of the rated heat capacity). If O2 operating limits are developed for co-fired process heaters based only on overall firing rates (and not by fuel mixtures), conduct at least one of the test runs for each test while the process heater is being supplied by both fuel gas and fuel oil and conduct at least one of the test runs while the process heater is being supplied solely by fuel gas.

(D) Determine the average O2 concentration for each test run of a valid test.

(E) Calculate the O2 operating limit for each operating range as the average O2 concentration of the three test runs from a valid test conducted at the representative conditions for that given operating range.

(F) Identify the firing rates for which the different operating limits apply. If only two operating limits are established based on firing rates, the O2 operating limits established when the process heater is firing at no less than 70 percent of the rated heat capacity must apply when the process heater is firing above 50 percent of the rated heat capacity and the O2 operating limits established for turndown conditions must apply when the process heater is firing at 50 percent or less of the rated heat capacity.

(G) Operating limits associated with each interval will be valid for 2 years or until another operating limit is established for that interval based on a more recent performance test specific for that interval, whichever occurs first. Owners and operators must use the operating limits determined for a given interval based on the most recent performance test conducted for that interval.

(7) The owner or operator of a process heater complying with a NOX limit in terms of lb/MMBtu as provided in § 60.102a(g)(2)(i)(B), (g)(2)(ii)(B), (g)(2)(iii)(B) or (g)(2)(iv)(B) or a process heater with a rated heat capacity between 40 and 100 MMBtu/hr that elects to demonstrate continuous compliance with a maximum excess O2 limit, as provided in § 60.107a(c)(6) or (d)(8), shall determine heat input to the process heater in MMBtu/hr during each performance test run by measuring fuel gas flow rate, fuel oil flow rate (as applicable) and heating value content according to the methods provided in § 60.107a(d)(5), (d)(6), and (d)(4) or (d)(7), respectively.

(8) The owner or operator shall use Equation 8 of this section to adjust pollutant concentrations to 0-percent O2 or 0- percent excess air.

(j) The owner or operator shall determine compliance with the applicable H2S emissions limit in § 60.102a(g)(1) for a fuel gas combustion device or the concentration requirement in § 60.103a(h) for a flare according to the following test methods and procedures:

(1) Method 1 of appendix A-1 to part 60 for sample and velocity traverses;

(2) Method 2 of appendix A-1 to part 60 for velocity and volumetric flow rate;

(3) Method 3, 3A, or 3B of appendix A-2 to part 60 for gas analysis. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 3B of appendix A-2 to part 60;

(4) EPA Method 11, 15 or 15A of appendix A-5 to part 60 or EPA Method 16 of appendix A-6 to part 60 for determining the H2S concentration for affected facilities using an H2S monitor as specified in § 60.107a(a)(2). The method ANSI/ASME PTC 19.10-1981 (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60. The owner or operator may demonstrate compliance based on the mixture used in the fuel gas combustion device or flare or for each individual fuel gas stream used in the fuel gas combustion device or flare.

(i) For Method 11 of appendix A-5 to part 60, the sampling time and sample volume must be at least 10 minutes and 0.010 dscm (0.35 dscf). Two samples of equal sampling times must be taken at about 1-hour intervals. The arithmetic average of these two samples constitutes a run. For most fuel gases, sampling times exceeding 20 minutes may result in depletion of the collection solution, although fuel gases containing low concentrations of H2S may necessitate sampling for longer periods of time.

(ii) For Method 15 of appendix A-5 to part 60, at least three injects over a 1-hour period constitutes a run.

(iii) For Method 15A of appendix A-5 to part 60, a 1-hour sample constitutes a run. The method ANSI/ASME PTC 19.10-1981, “Flue and Exhaust Gas Analyses,” (incorporated by reference - see § 60.17) is an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.

(iv) If monitoring is conducted at a single point in a common source of fuel gas as allowed under § 60.107a(a)(2)(iv), only one performance test is required. That is, performance tests are not required when a new affected fuel gas combustion device or flare is added to a common source of fuel gas that previously demonstrated compliance.

[73 FR 35867, June 24, 2008, as amended at 77 FR 56470, Sep. 12, 2012]

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. Pub. L. 101–549, title VI, § 601, Nov. 15, 1990, 104 Stat. 2648

§ 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 - NOx and VOC study

§ 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 2015-07-01

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

  • 2015-12-01; vol. 80 # 230 - Tuesday, December 1, 2015
    1. 80 FR 75178 - Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards
      GPO FDSys XML | Text
      ENVIRONMENTAL PROTECTION AGENCY, 40 CFR Parts 60 and 63
      Final rule.
      This final action is effective on February 1, 2016. The incorporation by reference of certain publications for part 63 listed in the rule is approved by the Director of the Federal Register as of February 1, 2016. The incorporation by reference of certain publications for part 60 listed in the rule were approved by the Director of the Federal Register as of June 24, 2008.
      40 CFR Part 60