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You are here: Home / Permitting / Air Permits / PermitByRule / Historical Rules / old117 / 693 / Outdated Title 30 TAC 117.101 - 121 Subchapter B, June 9, 1993

Outdated Title 30 TAC 117.101 - 121 Subchapter B, June 9, 1993

Outdated 30 TAC 117 and 31 TAC 117 rules, 31 TAC 117 date from 1972 and the rule changed to 30 TAC 117 in September 1993

Subchapter B Combustion at Existing Major Sources - Utility Electric Generation

117.101 Applicability
117.103 Exemptions
117.105 Emission Specifications
117.107 Alternative System-Wide Emission Specifications
117.109 Initial Control Plan Procedures
117.111 Initial Demonstration of Compliance
117.113 Continuous Demonstration of Compliance
117.115 Final Control Plan Procedures
117.117 Revision of Final Control Plan
117.119 Notification, Recordkeeping, and Reporting Requirements
117.121 Alternative Case Specific Specifications

117.101 Applicability

(a) The provisions of this undesignated head (relating to Utility Electric Generation) shall apply to utility boilers, steam generators, auxiliary steam boilers, and gas turbines used in an electric power generating system owned or operated by a municipality or a Public Utility Commission of Texas regulated utility located within the Houston/Galveston and Beaumont/ Port Arthur ozone nonattainment areas.

(b) The provisions of this undesignated head are applicable for the life of each affected unit within an electric power generating system or until this undesignated head or sections of this title which are applicable to an affected unit are rescinded.

117.103 Exemptions

(a) The provisions of § 117.105 of this title (relating to Emission Specifications) or § 117.107 of this title (relating to Alternative System-Wide Emission Specifications) shall not apply during periods of major upset or maintenance under the requirements of § 101.6 of this title (relating to Notification Requirements for Major Upset), § 101.7 of this title (relating to Notification Requirements for Maintenance), and § 101.11 of this title (relating to Exemptions from Rules and Regulations).

(b) Units exempted from the provisions of this undesignated head (relating to Utility Electric Generation), include the following:

(1) any new units placed into service after November 15, 1992;

(2) any utility boiler, steam generator, or auxiliary steam boiler with an annual heat input less than or equal to 2.2(10^11) Btu per year; or

(3) stationary gas turbines, which are:

(A) used solely to power other engines or gas turbines during start-ups; or

(B) used as emergency standby gas turbines or engines and demonstrated to operate less than 850 hours per year; or

(C) peaking gas turbines and operated less than 850 hours per calendar year.

(c) The owner or operator of any utility boiler, steam generator or auziliary steam boiler using the exemption of subsection (b)(2) or this section shall install and maintain totalizing fuel meters for each individula unit, as approved by the executive director and record the fuel input for each unit on a calendar year basis. The owner or operator of any engine or turbine using the exemption of subsection (b)(3) of this section shall record the operating time with instrumentation approved by the executive director. The owner or operator of any utility boiler, steam generator, auziliary steam boiler or stationary gas turbine or engine exempt under the exemptions of subsection (b)(2) and (3) of this section must notify the executive director within seven days if the applicable Btu per year (Btu/yr) or hour per year (hr/yr) limit is exceeded. If the Btu/yr or hr/yr limit is exceeded, the exemption shall be permanently withdrawn. Within 90 days after loss of the exemption, the owner or operator must submit a compliance plan detailing a plan to meet the applicable compliance limit as soon as possible but no later than 24 months after exceeding the hr/yr limit. Included with this compliance plan, the owner or operator must submit a schedule of increments of progress for hte installation of the required control equipment. This schedule shall be subject to the review and approval of the Executive Director.

117.105 Emission Specifications

(a) No person shall allow the discharge into the atmosphere from any utility boiler, steam generator, or auxiliary steam boiler, emissions of nitrogen oxides (NOx) in excess of 0.26 pound per million (MM) Btu heat input on a rolling 24-hour average and 0.20 pound per MMBtu heat input on a 30-day rolling average while firing natural gas or a combination of natural gas and waste oil.

(b) No person shall allow the discharge into the atmosphere from any utility boiler or steam generator, NOx emissions in excess of 0.38 pound per MMBtu heat input for tangentially-fired units on a rolling 24-hour averaging period or 0.43 pound per MMBtu heat input for wall-fired units on a rolling 24-hour averaging period while firing coal.

(c) No person shall allow the discharge into the atmosphere from any utility boiler, steam generator, or auxiliary steam boiler, NOx emissions in excess of 0.30 pound per MMBtu heat input on a rolling 24-hour averaging period while firing fuel oil only.

(d) No person shall allow the discharge into the atmosphere from any utility boiler, steam generator, or auxiliary steam boiler, NOx emissions in excess of the heat input weighted average of the applicable emission limits specified in subsections (a)-(c) of this section on a rolling 24-hour averaging period while firing a mixture of natural gas and fuel oil, as follows: Emission Limit = [a(0.26) + b(0.30)]/(a + b)

Where:

a = the percentage of total heat input from natural gas.
b = the percentage of total heat input from fuel oil.

(e) Each auxiliary steam boiler which is an affected facility as defined by New Source Performance Standards (NSPS) 40 Code of Federal Regulations (CFR), Part 60, Subparts D, Db, or Dc shall be limited to the applicable NSPS NOx emission limit, unless the boiler is also subject to a more stringent permit emission limit, in which case the more stringent emission limit applies. Each auxiliary boiler subject to an emission specification under this subsection is not subject to the emission specifications of subsection (a) or (c) of this section.

(f) No person shall allow the discharge into the atmosphere from any stationary gas turbine with a megawatt (MW) rating greater than or equal to 30 MW and an annual electric output in MW-hours (MW-hr) of greater than or equal to the product of 2,500 hours and the MW rating of the unit, NOx emissions in excess of a block one-hour average of 42 parts per million by volume (ppmv) at 15% oxygen (O2), dry basis, while firing natural gas.

(g) No person shall allow the discharge into the atmosphere from any stationary gas turbine with a MW rating greater than or equal to 30 MW and an annual electric output in MW-hr of greater than or equal to the product of 2,500 hours and the MW rating of the unit, NOx emissions in excess of a block one-hour average of 65 ppmv at 15% O2, dry basis, while firing fuel oil.

(h) No person shall allow the discharge into the atmosphere from any stationary gas turbine used for peaking service with an annual electric output in MW-hr of less than the product of 2,500 hours and the MW rating of the unit, NOx emissions in excess of a block one-hour average of 0.20 pound per MMBtu heat input while firing natural gas.

(i) No person shall allow the discharge into the atmosphere from any stationary gas turbine used for peaking service with an annual electric output in MW-hr of less than the product of 2,500 hours and the MW rating of the unit, NOx emissions in excess of a block one-hour average of 0.30 pound per MMBtu heat input while firing fuel oil.

(j) No person shall allow the discharge into the atmosphere from any unit subject to this undesignated head (relating to Utility Electric Generation), carbon monoxide (CO) emissions in excess of 400 ppmv, based on a rolling 24-hour averaging period.

(k) No person shall allow the discharge into the atmosphere from any unit subject to this undesignated head, ammonia emissions in excess of 20 ppmv based on a block one-hour averaging period.

(l) The NOx emission limits specified in subsections (a)-(i) of this section shall apply at all times, except as specified in § 117.103 of this title (relating to Exemptions) and § 117.107 of this title (relating to Alternative System-Wide Emission Specifications). The emission limits specified in subsections (j) and (k) of this section shall apply at all times, except as specified in § 117.103 of this title.

117.107 Alternative System-Wide Emission Specifications

(a) An owner or operator may achieve compliance with the nitrogen oxides (NOx) emission limits of § 117.105 of this title (relating to Emission Specifications) by achieving compliance with a system-wide emission limitation. Any owner or operator who elects to comply with system-wide emission limits shall reduce emissions of NOx from affected units so that, if all such units were operated at their maximum rated capacity, the system-wide emission rate from all units in the system would not exceed the system-wide emission limit as defined in § 117.010 of this title (relating to Definitions), and shall establish enforceable emission limits for each affected unit in the system. A pound per million (MM) Btu emission limit based on a rolling 24-hour averaging period and a pound per MMBtu emission limit based on a 30-day averaging period shall apply to each gas-fired unit in the system. A pound per MMBtu emission limit based on a rolling 24-hour averaging period shall apply to each gas-fired unit in the system. A pound per MMBtu emission limit based on a rolling 24-hour averaging period shall apply to each coal-fired unit in the system.

(b) An owner or operator of any gaseous and liquid fuel-fired utility boiler, steam generator, auxiliary steam boiler or gas turbine which derives more than 50% of its annual heat input from gaseous fuel shall use only the appropriate gaseous fuel emission limit of &#167117.105 of this title at maximum rated capacity in calculating the system-wide emission limit and shall assign to the unit the maximum allowable NOx emission rate while firing gas, calculated in accordance with subsection (a) of this section. The owner or operator shall also:

(1) comply with the assigned maximum allowable emission rate while firing natural gas only;

(2) comply with the liquid fuel emission limit of § 117.105 of this title while firing liquid fuel only;

(3) comply with a limit calculated as the actual heat input weighted sum of the assigned gas-firing allowable emission rate and the liquid fuel emission limit of § 117.105 of this title while operating on liquid and gaseous fuel concurrently.

(c) Peaking gas turbines subject to the emission limits of § 117.105(h) or (i) of this title and auxiliary steam boilers subject to the emission limits of § 117.105(a), (c), (d), or (e) of this title shall comply with those individual emission specifications under this section and shall not be included in the system-wide emission specification. Coal-fired utility boilers or steam generators shall be treated as a separate system, and system averaging for coal-fired utility boilers or steam generators shall be limited to those units under this section.

(d) Solely for purposes of calculating the system-wide emission limit, the allowable mass emission rate for each affected unit shall be calculated from the emission specifications of § 117.105 of this title, as follows.

(1) The NOx emissions rate (in pounds per hour) for each affected utility boiler, steam generator, or auxiliary steam boiler is the product of its maximum rated capacity and its NOx emission specification of § 117.105 of this title.

(2) The NOx emissions rate (in pounds per hour) for each affected stationary gas turbine is the product of the in-stack NOx, the turbine manufacturer's rated exhaust flow rate (expressed in pounds per hour at megawatt (MW) rating and International Standards Organization (ISO) flow conditions), and (46/28)(10^-6);

Where:

In-stack NOx = NOx (allowable) x (1 - %h3O/100) x [20.9 - %O2/(1 - %h3O/100)]/5.9

NOx (allowable) = the applicable NOx emission specification of § 117.105(f) or (g) of this title (expressed in parts per million by volume NOx at 15% oxygen (O2) dry basis)

%h3O = the volume percent water in the stack gases, as calculated at MW rating and ISO flow conditions

%O2 = the volume percent O2 in the stack gases on a wet basis, as calculated at the MW rating and ISO flow conditions.

117.109 Initial Control Plan Procedures

The owner or operator of any major source which has units subject to § 117.105 of this title (relating to Emission Specifications) or § 117.107 of this title (relating to Alternative System-Wide Emission Specifications) shall submit for the approval of the executive director, an initial control plan for installation of NOx emissions control equipment to meet the requirements of § 117.105 of this title or § 117.107 of this title. The executive director shall approve the plan if it contains all the information specified in this section. Revisions to the initial control plan shall be submitted with the final control plan. The initial control plan shall be submitted in accordance with the schedule specified in § 117.510 of this title (relating to Compliance Schedule for Utility Electric Generation) and shall contain the following:

(1) a list of all combustion units at the source with a maximum rated capacity greater than 5.0 million Btu per hour; all stationary, reciprocating internal combustion which are located in the Houston/Galveston ozone nonattainment area and rated 150 horsepower (hp) or greater, or located in the Beaumont/Port Arthur ozone nonattainment area and rated 300 hp or greater; all stationary gas turbines with a megawatt (MW) rating of greater than or equal to 1.0 MW; to include the maximum rated capacity, anticipated annual heat input capacity factor, the facility identification numbers as submitted to the Emissions Inventory Section of the Texas Air Control Board (TACB), and the emission point numbers as listed on the Maximum Allowable Emissions Rate Table of any applicable TNRCC permit for each unit;

(2) identification of all units subject to the emission specifications of § 117.105 or § 117.107 of this title;

(3) identification of all boilers and stationary gas turbines with a claimed exemption from the emission specifications of § 117.105 of this title or § 117.107 of this title and the rule basis for the claimed exemption;

(4) identification of the election to use individual emission limits as specified in § 117.105 of this title or the system-wide emission limit specified in § 117.107 of this title to achieve compliance with this rule;

(5) a list of units to be controlled and the type of control to be applied for all such units, including an anticipated construction schedule;

(6) a list of any units retired, decommissioned, or shutdown and rendered inoperable, as a result of compliance with this regulation; and

(7) the basis for calculation of the mass rate of NOx emissions for each unit to demonstrate that each unit will achieve the NOx emission rates specified in § 117.105 of this title or § 117.107 of this title.

117.111 Initial Demonstration of Compliance

(a) All units which are identified in the control plan required by § 117.109 of this title (relating to Initial Control Plan Procedures) and are subject to the emission limitations of § 117.105 of this title (relating to Emission Specifications) or § 117.107 of this title (relating to Alternative Plant-Wide Emission Specifications), shall be tested for nitrogen oxides (NOx), carbon monoxide (CO), and oxygen (O2) emissions. Units which inject urea or ammonia into the exhaust stream for NOx control shall be tested for ammonia emissions. Such tests shall be performed in accordance with the schedule specified in § 117.510(3) of this title (relating to Compliance Schedule For Utility Electric Generation).

(b) The tests required by subsection (a) of this section shall be used for determination of initial compliance with either the emission limits of § 117.105 of this title or the assigned emission limits of § 117.107 of this title, as applicable. Test results shall be reported in the units of the applicable emission limits and averaging periods.

(c) Continuous emissions monitoring systems (CEMS) required by § 117.113(a) of this title (relating to Continuous Demonstration of Compliance) shall be installed and operational prior to conducting performance testing under subsection (a) of this section. Verification of operational status shall, as a minimum, include completion of the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device.

(d) Initial compliance with the emission specifications of § 117.105 of this title or § 117.107 of this title for units operating with CEMS in accordance with § 117.113(a) of this title shall be demonstrated using the NOx CEMS as follows:

(1) To comply with the NOx emission limit in pound per million (MM) Btu on a rolling 30-day average, NOx emissions from a unit are monitored for 30 successive unit operating days and the 30-day average emission rate is used to determine compliance with the NOx emission limit. The 30-day average emission rate is calculated as the average of all hourly emissions data recorded by the monitoring system during the 30-day test period.

(2) To comply with the NOx emission limit in pound per MMBtu on a rolling 24-hour average, NOx emissions from a unit are monitored for 24 consecutive operating hours and the 24-hour average emission rate is used to determine compliance with the NOx emission limit. The 24-hour average emission rate is calculated as the average of all hourly emissions data recorded by the monitoring system during the 24-hour test period.

(3) To comply with the CO emission limit in parts per million by volume on a rolling 24-hour average, CO emissions from a unit are monitored for 24 consecutive hours and the rolling 24-hour average emission rate is used to determine compliance with the CO emission limit. The rolling 24-hour average emission rate is calculated as the average of all hourly emissions data recorded by the monitoring system during the 24-hour test period.

117.113 Continuous Demonstration of Compliance

(a) The owner or operator of each affected unit, as defined in § 117.101 of this title (relating to Applicability), except for exempted units listed in § 117.103 of this title (relating to Exemptions); peaking units as defined in § 1.1 or § 1.2 of Appendix E of 40 Code of Federal Regulations (CFR) Part 75, subject to the monitoring requirements of Appendix E; gas turbines monitored in accordance with subsection (e) of this section; and auxiliary boilers as defined in § 117.010 of this title (relating to Definitions), monitored in accordance with subsection (d) of this section, shall install, calibrate, maintain, and operate an in-stack continuous emissions monitoring systems (CEMS) to measure nitrogen oxides (NOx) on an individual basis. The CEMS shall be installed and operating by the time of compliance with the emission limits specified in § 117.105 of this title (relating to Emission Specifications) or § 117.107 of this title (relating to Alternative System-Wide Emission Specifications). Each CEMS shall be capable of measuring the following:

(1) NOx;

(2) carbon monoxide (CO); and

(3) oxygen (O2) or carbon dioxide (CO2) as a diluent.

(4) exhaust or fuel flow rate.

(b) Any CEMS required by subsection (a) of this section shall be installed, calibrated, maintained, and operated in accordance with 40 CFR, Part 75 or 40 CFR, Part 60, as applicable. The Texas Air Control Board (TACB) executive director may approve alternative locations to in-stack monitoring for any affected unit subject to this section.

(c) The owner or operator of each peaking unit as defined in 40 CFR Part 75, Appendix E § 1.1 or § 1.2, may monitor operating parameters for each unit in accordance with Appendix E and calculate NOx emission rates based on those procedures or use CEMS in accordance with subsection (a) of this section to monitor NOx emission rates.

(d) The owner or operator of each auxiliary boiler as defined in § 117.010 of this title shall install, calibrate, maintain, and operate a CEMS in accordance with subsection (a) of this section or comply with the appropriate (considering boiler maximum rated capacity and annual heat input) industrial boiler monitoring requirements of § 117.213 of this title (relating to Continuous Demonstration of Compliance).

(e) The owner or operator of each gas turbine subject to the emission specifications of § 117.105 of this title, in lieu of monitoring emissions in accordance with the monitoring requirements of 40 CFR 75, may elect to comply with the following monitoring requirements:

(1) for gas turbines rated less than 30 megawatt (MW) or peaking gas turbines (as defined in § 117.10 of this title) which use steam or water injection to comply with the emission specifications of § 117.105(h) or (i) of this title:

(A) install, calibrate, maintain and operate a CEMS in compliance with subsection (b) of this section; or

(B) install, calibrate, maintain, and operate a continuous monitoring system to monitor and record the average hourly fuel and steam or water consumption. The system shall be accurate to within +/- 5.0%. The steam-to-fuel or water-to-fuel ratio monitoring data shall constitute the method for demonstrating continuous compliance with the applicable emission specification of § 117.105 of this title.

(2) for gas turbines subject to the emission specifications of § 117.105(f) or (g) of this title, install, calibrate, maintain and operate a CEMS in compliance with subsection (b) of this title.

(f) After the initial demonstration of compliance required by § 117.111 of this title (relating to Initial Demonstration of Compliance), compliance with either § 117.105 or § 117.107 of this title, as applicable, shall be determined by the methods required in this section. Compliance with the emission limitations may also be determined at the discretion of the executive director using any TACB compliance method. If compliance with § 117.105 of this title is selected, no unit subject to § 117.105 of this title shall be operated at an emission rate higher than that allowed by the emission specifications of § 117.105 of this title. If compliance with § 117.107 of this title is selected, no unit subject to § 117.107 of this title shall be operated at an emission rate higher than that approved by the executive director pursuant to § 117.115(b)(2) of this title (relating to Final Control Plan Procedures).

117.115 Final Control Plan Procedures

(a) For sources complying with § 117.105 of this title (relating to Emission Specifications), the owner or operator of an affected source shall submit a final control report to show compliance with the requirements of § 117.105 of this title by the date specified in § 117.510(4) of this title (relating to Compliance Schedule For Utility Electric Generation). The report shall include a list of all affected units showing the method of control of nitrogen oxides (NOx) emissions for each unit and the results of testing required in § 117.111 of this title (relating to Initial Demonstration of Compliance).

(b) For sources complying with § 117.107 of this title (relating to Alternative System-Wide Emission Specifications), the owner or operator of an affected source shall submit a final control plan to show attainment of the requirements of § 117.107 of this title by the date specified in § 117.510(4) of this title. The owner or operator shall:

(1) assign to each affected unit the maximum NOx emission rate, expressed in units of pound per million (MM) Btu heat input on a rolling 24-hour average and rolling 30-day average for gaseous fuel firing, and a rolling 24-hour average for oil or coal firing, which are allowable for that unit under the requirements of § 117.107 of this title;

(2) submit a list to the executive director for approval of the maximum allowable NOx emission rates identified in paragraph (1) of this subsection and maintain a copy of the approved list for verification of continued compliance with the requirements of § 117.107 of this title; and

(3) submit a list summarizing the results of testing each unit in accordance with the requirements of § 117.111 of this title.

117.117 Revision of Final Control Plan

A revised final control plan may be submitted by the owner or operator, along with any required permit applications. Such a plan shall adhere to the emission limits and the final compliance dates of this undesignated head (relating to Utility Electric Generation). The revision of the final control plan shall be subject to the review and approval of the executive director.

117.119 Notification, Record keeping, and Reporting Requirements

(a) For units subject to the exemptions allowed under § 117.103(a) of this title (relating to Exemptions), hourly records shall be made of start-up and/or shutdown events and maintained for a period of at least two years. Records shall be available for inspection by the Texas Air Control Board (TACB), the Unites States Environmental Protection Agency (EPA), and any local air pollution control agency having jurisdiction upon request. These records shall include, but are not limited to: type of fuel burned; quantity of each type fuel burned; gross and net energy production in megawatt-hours (MW-hr); and the date, time, and duration of the procedure.

(b) The owner or operator of a unit subject to the provisions of § 117.105 of this title (relating to Emission Specifications) or § 117.107 of this title (relating to Alternative System-wide Emission Specifications) shall submit to the executive director written notification as follows:

(1) verbal notification of the date of any performance testing conducted under § 117.111 of this title (relating to Initial Demonstration of Compliance) at least 15 days prior to such date followed by written notification within 15 days after testing is completed; and

(2) verbal notification of the date of any continuous emissions monitoring systems (CEMS) performance evaluation conducted under § 117.113 of this title (relating to Continuous Demonstration of Compliance) at least 15 days prior to such date followed by written notification within 15 days after testing is completed.

(c) The owner or operator of an affected unit shall furnish the executive director and any local air pollution control agency having jurisdiction a copy of any performance testing conducted under § 117.111 of this title or any CEMS performance evaluation conducted under § 117.113 of this title within 60 days after completion of such testing or evaluation.

(d) The owner or operator of a unit required to install a CEMS continuous operating parameter monitoring system or steam-to-fuel or water-to-fuel ratio monitoring system under § 117.113 of this title shall report in writing to the executive director on a quarterly basis any exceedance of the applicable emission limitations in § 117.105 of this title or § 117.107 of this title and the monitoring system performance. All reports shall be postmarked or received by the 30th day following the end of each calendar quarter. Written reports shall include the following information:

(1) the magnitude of excess emissions computed in accordance with 40 Code of Federal Regulations, Part 60, § 60.13(h), any conversion factors used, the date and time of commencement and completion of each time period of excess emissions, and the unit operating time during the reporting period. For gas turbines using steam-to-fuel or water-to-fuel ratio monitoring to demonstrate compliance in accordance with § 117.113(e)(1)(B) of this title, excess emissions are computed as each one-hour period during which the hourly steam-to-fuel or water-to-fuel ratio is less than the ratio determined to result in compliance during the initial performance test required by § 117.111 of this title.

(2) specific identification of each period of excess emissions that occurs during start-ups, shutdowns, and malfunctions of the affected unit. The nature and cause of any malfunction (if known) and the corrective action taken or preventative measures adopted;

(3) the date and time identifying each period during which the continuous monitoring system was inoperative, except for zero and span checks and the nature of the system repairs or adjustments;

(4) when no excess emissions have occurred or the continuous monitoring system has not been inoperative, repaired, or adjusted, such information shall be stated in the report;

(5) if the total duration of excess emissions for the reporting period is less than 1.0% of the total unit operating time for the reporting period and the CEMS or steam-to-fuel or water-to-fuel ratio monitoring system downtime for the reporting period is less than 5.0% of the total unit operating time for the reporting period, only a summary report form (as outlined in the latest edition of the TACB "Guidance for Preparation of Summary, Excess Emission, and Continuous Monitoring System Reports") shall be submitted, unless otherwise requested by the executive director of the TACB. If the total duration of excess emissions for the reporting period is greater than or equal to 1.0% of the total operating time for the reporting period or the CEMS or steam-to-fuel or water-to-fuel ratio monitoring system downtime for the reporting period is greater than or equal to 5.0% of the total operating time for the reporting period, a summary report and an excess emission report shall both be submitted.

(e) For units subject to the provisions of § 117.105 of this title or § 117.107 of this title, records of hours of operation and other operating records shall be made and maintained for a period of at least two years. Records shall be available for inspection by the TACB, EPA, or local air pollution control agencies having jurisdiction upon request. Operating records for each unit shall be recorded and maintained at a frequency equal to the applicable emission specification averaging period, or monthly for units exempt from the emission specifications based on annual heat input, or hours of operation per calendar year, and shall include:

(1) emission rates in units of the applicable standards;

(2) gross energy production in MW-hr (not applicable to auxiliary boilers);

(3) quantity and type of fuel burned;

(4) the injection rate of reactant chemicals (if applicable); and

(5) CEMS, continuous operating parameter monitoring system or steam-to-fuel or water-to-fuel ratio monitoring system data, as applicable, pursuant to § 117.113 of this title. The records shall include:

(A) the date, time, and duration of any malfunction in the operation of the monitoring system, except for zero and span checks, if applicable, and a description of system repairs and adjustments undertaken during each period;

(B) the results of performance testing, evaluations, calibrations, checks, adjustments, and maintenance of CEMS, continuous operating parameter monitoring system, or steam-to-fuel or water-to-fuel ratio monitoring systems; and

(C) actual emissions or operating parameter measurements, as applicable.

117.121 Alternative Case Specific Specifications

Where a person can demonstrate that an affected unit cannot attain the requirements of § 117.105 of this title (relating to Emission Specifications), as applicable, the executive director, on a case-by-case basis after considering the technological and economic circumstances of the individual unit, may approve emission specifications different from § 117.105 of this title for that unit based on the determination that such specifications are the result of the lowest emission limitation the unit is capable of meeting after the application of reasonably available control technology. In determining whether to approve alternative emission specifications, the executive director may take into consideration the ability of the plant at which the unit is located to meet emission specifications through system-wide averaging at maximum capacity. Any person affected by the decision of the executive director may appeal to the Board by filing written notice of appeal with the executive director within 30 days after the decision. Such appeal is to be taken by written notification to the executive director. Section 103.71 of this title (relating to Request for Action by the Board) should be consulted for the method of requesting Board action on the appeal. Executive director approval does not necessarily constitute satisfaction of all federal requirements nor eliminate the need for approval by EPA in cases where specified criteria for determining equivalency have not been clearly identified in applicable sections of this undesignated head (relating to Utility Electric Generation).


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