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You are here: Home / Permitting / Air Permits / PermitByRule / Historical Rules / old117 / 1297 / Title 30 TAC 117.101 - 121 Subchapter B, December 23, 1997

Title 30 TAC 117.101 - 121 Subchapter B, December 23, 1997

Outdated 30 TAC 117 and 31 TAC 117 rules, 31 TAC 117 date from 1972 and the rule changed to 30 TAC 117 in September 1993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

Adopted date: December 3, 1997
Effective date: December 23, 1997

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system or until this undesignated head or sections of this title which are applicable to an affected unit are rescinded.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), except for § 117.109(b)(1) of this title (relating to Initial Control Plan Procedures) and § 117.113(h) of this title (relating to Continuous Demonstration of Compliance), 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 and engines, which are:

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

(B) demonstrated to operate less than 850 hours per year, based on a rolling 12-month average.

(c) The fuel oil firing emission limitation of § 117.105(c) or § 117.107(b) of this title shall not apply during an emergency operating condition declared by the Electric Reliability Council of Texas or the Southwest Power Pool, or any other emergency operating condition which necessitates oil firing. All findings that emergency operating conditions exist are subject to the approval of the executive director. The owner or operator of an affected unit shall give the executive director and any local air pollution control agency having jurisdiction verbal notification as soon as possible but no later than 48 hours after declaration of the emergency. Verbal notification shall identify the anticipated date and time oil firing will begin, duration of the emergency period, affected oil-fired equipment, and quantity of oil to be fired in each unit, and shall be followed by written notification containing this information no later than five days after declaration of the emergency. The owner or operator of an affected unit shall give the executive director and any local air pollution control agency having jurisdiction final written notification as soon as possible but no later than two weeks after the termination of emergency fuel oil firing. Final written notification shall identify the actual dates and times that oil firing began and ended, duration of the emergency period, affected oil-fired equipment, and quantity of oil fired in each unit.

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 utility boiler, steam generator, or auxiliary steam boiler 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 stationary gas turbine with a MW rating greater than or equal to 10 MW, CO emissions in excess of a block one-hour average of 132 ppmv at 15% O2, dry basis.

(l) 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.

(m) 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), (k), and (l) of this section shall apply at all times, except as specified in § 117.103 of this title.

(n) For purposes of this subchapter, the following shall apply:

(1) The lower of any permit NOx emission limit in effect on June 9, 1993 under a permit issued pursuant to Chapter 116 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification) and the NOx emission limits of subsections (a)-(i) of this section shall apply, except that gas-fired boilers operating under a permit issued after March 3, 1982, with an emission limit of 0.12 pound NOx per MMBtu heat input, shall be limited to that rate for the purposes of this subchapter.

(2) For any unit placed into service after June 9, 1993 and prior to May 31, 1995 or the final compliance date as approved under the provisions of § 117.540 of this title (relating to Phased Reasonably Available Control Technology (RACT)), as functionally identical replacement for an existing unit or group of units subject to the provisions of this chapter and limited to the cumulative maximum rated capacity of the units replaced, the higher of any permit NOx emission limit under a permit issued after June 9, 1993 pursuant to Chapter 116 of this title and the emission limits of subsections (a)-(i) of this section shall apply. Any emission credits resulting from the operation of such replacement units shall be limited to the cumulative maximum rated capacity of the units replaced. The inclusion of such new units is an optional method for complying with the emission limitations of § 117.107 of this title. Compliance with this paragraph does not eliminate the requirement for new units to comply with Chapter 116 of this title.

117.107 Alternative System-wide Emission Specifications

(a) An owner or operator of any gaseous- or coal-fired utility boiler or stationary gas turbine 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, except as provided for in subsection (d) of this section. 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 § 117.10 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 rolling 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 coal-fired unit in the system. For stationary gas turbines, the emission limits shall be assigned in the units given by the appropriate emission limitation of § 117.105 of this title.

(b) An owner or operator of any fuel oil-fired utility boiler may achieve compliance with the NOx emission limits of § 117.105 of this title by achieving compliance with a system-wide emission limitation. Any owner or operator who elects to comply with system-wide emission limits for oil firing shall reduce emissions of NOx from affected units so that, if all such units were operated at their average activity level for fuel oil firing as defined in § 117.10 of this title, the system-wide emission rate from all oil-fired units in the system would not exceed the system-wide emission limit as defined in § 117.10 of this title, and shall establish enforceable emission limits for oil firing for each affected unit in the system. A pound per MMBtu emission limit based on a rolling 24-hour averaging period shall apply to each oil-fired unit in the system. The emission limit assigned to each oil-fired unit in the system shall not exceed 0.5 pound NOx per MMBtu based on a rolling 24-hour average.

(c) An owner or operator of any gaseous and liquid fuel-fired utility boiler, steam generator, or gas turbine shall calculate the gaseous and liquid fuel-fired system-wide emission limits of subsections (a) and (b) of this section separately. The owner or operator shall also:

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

(2) comply with the assigned maximum allowable emission rates for liquid fuel while firing liquid fuel only; and

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

(d) 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.

(e) 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 average activity level for fuel oil firing or maximum rated capacity for gas firing 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 - %H2O/100) x [20.9 - %O2/(1 - %H2O/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)

%H2O = the volume percent water in the stack gases, as calculated from the manufacturer's data, or other data as approved by the executive director, at MW rating and ISO flow conditions

%O2 = the volume percent O2 in the stack gases on a wet basis, as calculated from the manufacturer's data, or other data as approved by the executive director, at the MW rating and ISO flow conditions.

117.109 Initial Control Plan Procedures

(a) The owner or operator of any major source of nitrogen oxides (NOx) shall submit, for the approval of the executive director, an initial control plan for installation of NOx emissions control equipment and demonstration of anticipated compliance with other applicable requirements of this subchapter. 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.

(b) The initial control plan shall be submitted in accordance with the schedule specified in § 117.510(1) 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 and emission point numbers as submitted to the Emissions Inventory Section of the Texas Natural Resource Conservation Commission (TNRCC), 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 (relating to Emission Specifications and Alternative System-Wide Emission Specifications);

(3) identification of all boilers and stationary gas turbines with a claimed exemption from the emission specifications of § 117.105 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 which have been or will be retired, decommissioned, or shutdown and rendered inoperable, indicating the date of occurrence and whether these actions are a result of compliance with this regulation;

(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 or § 117.107 of this title. Emissions from stationary gas turbines shall be represented in the units given by the appropriate emission limitation of § 117.105 of this title; and

(8) for units required to install totalizing fuel flow meters in accordance with § 117.113(e), (g), or (h) of this title (relating to Continuous Demonstration of Compliance), indication of whether the devices have been placed in operation by April 1, 1994.

117.111 Initial Demonstration of Compliance

(a) All units which 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 System-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 schedules specified in § 117.510(4) and (5) 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) or predictive emissions monitoring systems (PEMS) required by § 117.113(e) of this title shall be installed and operational prior to conducting initial demonstration of compliance 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 or § 117.107 of this title for units operating with CEMS in accordance with § 117.113(a) of this title or with PEMS in accordance with § 117.113(e) of this title shall be demonstrated using the NOx CEMS or PEMS 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. Compliance with the NOx emission limit for fuel oil firing shall be determined based on the first 24 consecutive operating hours a unit fires fuel oil.

(3) To comply with the NOx emission limit in pounds per hour or parts per million by volume (ppmv) at 15% O2 dry basis, on a block one-hour average, any one-hour period while operating at the maximum rated capacity, or as near thereto as practicable, after CEMS certification testing required in § 117.113(b) of this title or PEMS certification testing required in § 117.213(c) of this title (relating to Continuous Demonstration of Compliance) is used to determine compliance with the NOx emission limit.

(4) To comply with the CO emission limit in ppmv 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 (f) of this section; and auxiliary boilers as defined in § 117.10 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 able to use measured exhaust or fuel flow rate data obtained by a certified flow meter and be capable of measuring the following:

(1) NOx;

(2) carbon monoxide (CO); and

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

(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 executive director of the Texas Natural Resource Conservation Commission (TNRCC) 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 § 117.10 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) As an alternative to CEMS, the owner or operator of units subject to continuous monitoring requirements under this undesignated head (relating to Utility Electric Generation) may, with the approval of the executive director, elect to install, calibrate, maintain, and operate predictive emissions monitoring systems (PEMS) and totalizing fuel flow meters. The required PEMS and fuel flow meters shall be used to measure NOx, CO, and O2 (or CO2) emissions and fuel flow for each affected unit and shall be used to demonstrate continuous compliance with the emission limitations of § 117.105 or § 117.107 of this title. As an alternative to using PEMS to monitor O2 (or CO2), subsection (a) of this section or similar alternative method approved by the executive director and the United States Environmental Protection Agency may be used. Any PEMS for units subject to the requirements of 40 CFR 75 shall meet the requirements of § 117.119 of this title (relating to Notification, Recordkeeping, and Reporting Requirements) and 40 CFR 75 Subpart E, § § 75.40 - 75.48. Any PEMS for units not subject to the requirements of 40 CFR 75 shall meet the requirements of § 117.119 of this title and either 40 CFR 75, Subpart E, § § 75.40 - 75.48 or § 117.213(c)(1)-(3) of this title.

(f) 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 or PEMS 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 or PEMS in compliance with subsection (b) of this section.

(g) The owner or operator of any stationary gas turbine with a MW rating greater than or equal to 1.0 MW operated more than 850 hours per year (hr/yr) shall install and maintain totalizing fuel flow meters on an individual unit basis.

(h) The owner or operator of any utility boiler, steam generator, or auxiliary steam boiler using the exemption of § 117.103(b)(2) of this title shall install and maintain totalizing fuel meters for each individual unit, as approved by the executive director, and record the annual fuel input for each unit, based on a rolling monthly average. The owner or operator of any stationary gas turbine using the exemption of § 117.103(b)(3) of this title shall record the operating time with an elapsed run time meter approved by the executive director.

(i) The owner or operator of any utility boiler, steam generator, or auxiliary steam boiler using the exemption of § 117.103(b)(2) of this title, or any stationary gas turbine using the exemption of § 117.103(b)(3) of this title, shall notify the executive director within seven days if the Btu/yr or hr/yr limit specified in § 117.103(b)(2) or § 117.103(b)(3) of this title, as appropriate, is exceeded. If the Btu/yr or hr/yr limit, as appropriate, is exceeded, the exemption from the emission specifications of § 117.105 of this title shall be permanently withdrawn. Within 90 days after loss of the exemption, the owner or operator shall 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 Btu/yr or hr/yr limit, as appropriate. Included with this compliance plan, the owner or operator shall submit a schedule of increments of progress for the installation of the required control equipment. This schedule shall be subject to the review and approval of the executive director.

(j) 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 TNRCC 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(6) 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(6) 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 description of the NOx control method used to achieve compliance with § 117.107 of this title, and the results of testing for each unit in accordance with the requirements of § 117.111 of this title. For units complying with a pound per MMBtu emission limit on a rolling 30-day average, this information may be submitted according to the schedule given in § 117.510(4) of this title.

(4) submit a list summarizing the results of testing for 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). For sources complying with § 117.105 of this title (relating to Emission Specifications), or § 117.107 of this title (relating to Alternative System-Wide Emission Specifications), replacement new units may be included in the control plan. 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 Natural Resource Conservation Commission (TNRCC), 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 event.

(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 notification to the executive director as follows:

(1) verbal notification of the date of any initial demonstration of compliance 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) or predictive emissions monitoring systems (PEMS) 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 initial demonstration of compliance testing conducted under § 117.111 of this title or any CEMS or PEMS performance evaluation conducted under § 117.113 of this title within 60 days after completion of such testing or evaluation. Such results shall be submitted in accordance with the appropriate compliance schedules specified in § 117.510(3) and (4) of this title (relating to Compliance Schedule for Utility Electric Generation).

(d) The owner or operator of a unit required to install a CEMS, PEMS, 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 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(f)(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 demonstration of compliance 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, PEMS, 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 TNRCC "Guidance for Preparation of Summary, Excess Emission, and Continuous Monitoring System Reports") shall be submitted, unless otherwise requested by the executive director of the TNRCC. 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 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 TNRCC, 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, PEMS, 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 initial certification testing, evaluations, calibrations, checks, adjustments, and maintenance of CEMS, PEMS, or steam-to-fuel or water-to-fuel ratio monitoring systems; and

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

(6) the results of performance testing, including initial demonstration of compliance testing conducted in accordance with § 117.111 of this title.

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 Commission 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 Commission) should be consulted for the method of requesting Commission 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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