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You are here: Home / Permitting / Air Permits / PermitByRule / Historical Rules / old117 / 1199 / Title 30 TAC 117.101 - 121, November 21, 1999

Title 30 TAC 117.101 - 121, November 21, 1999

Outdated 30 TAC 117 and 31 TAC 117 rules, 31 TAC 117 date from 1972 and the rule changed to 30 TAC 117 in September 1993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

Division 1: 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 division (relating to Utility Electric Generation) shall apply to the following units 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 Beaumont/Port Arthur, Houston/Galveston, or Dallas/Fort Worth ozone nonattainment areas:

(1) utility boilers;

(2) steam generators;

(3) auxiliary steam boilers; and

(4) gas turbines.

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power generating system or until this division or sections of this title which are applicable to an affected unit are rescinded.

117.103 Exemptions

(a) Units exempted from the provisions of this division (relating to Utility Electric Generation), except as may be specified in § 117.109(b)(1) of this title (relating to Initial Control Plan Procedures) and § 117.113(i) 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.

(b) The fuel oil firing emission limitation of § 117.105(c) or § 117.107(b) of this title (relating to Emissions Specifications and Alternative System-wide Emission Specifications) 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:

(1) 42 parts per million by volume (ppmv) at 15% oxygen (O2), dry basis, while firing natural gas; and

(2) 65 ppmv at 15% O2, dry basis, while firing fuel oil.

(g) 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:

(1) 0.20 pound per MMBtu heat input while firing natural gas; and

(2) 0.30 pound per MMBtu heat input while firing fuel oil.

(h) No person shall allow the discharge into the atmosphere from any utility boiler, steam generator, or auxiliary steam boiler subject to the NOx emission limits specified in subsections (a) - (e) of this section, carbon monoxide (CO) emissions in excess of 400 ppmv, based on a one-hour average for units not equipped with continuous emissions monitoring systems (CEMS) or predictive emissions monitoring systems (PEMS) for CO, or on a rolling 24-hour averaging period for units equipped with CEMS or PEMS for CO.

(i) 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.

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

(k) 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)-(g) 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 the final compliance date as specified in § 117.510 of this title (relating to Compliance Schedule for Utility Electric Generation) or 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, 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)-(g) 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. 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).

(1) The following units shall comply with the individual emission specifications of § 117.105 of this title and shall not be included in the system-wide emission specification:

(A) gas turbines subject to the emission limits of § 117.105(h) or (i) of this title;

(B) auxiliary steam boilers subject to the emission limits of § 117.105(a), (c), (d), or (e) of this title.

(2) Coal-fired utility boilers or steam generators shall have a separate system average under this section, limited to those units.

(3) Oil-fired utility boilers or steam generators shall have a separate system average under this section, limited to those units. 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.

(b) The owner or operator shall establish enforceable emission limits for each affected unit in the system calculated in accordance with the maximum rated capacity averaging in this section as follows:

(1) for each gas-fired unit in the system, in pound per million (MM) Btu:

(A) on a rolling 24-hour averaging period; and

(B) on a rolling 30-day averaging period;

(2) for each coal-fired unit in the system, in pound per MMBtu on a rolling 24-hour averaging period;

(3) for stationary gas turbines, in the units of the appropriate emission limitation of § 117.105 of this title; and

(4) for each fuel oil-fired unit in the system, in pound per MMBtu on a rolling 24-hour averaging period.

(c) An owner or operator of any gaseous and liquid fuel-fired utility boiler, steam generator, or gas turbine shall:

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

(2) comply with the assigned maximum allowable emission rate 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, 24-hour average, allowable emission limit and the assigned liquid-firing allowable emission limit while operating on liquid and gaseous fuel concurrently.

(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 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) located in the Beaumont/Port Arthur or Houston/Galveston ozone nonattainment area 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.

(1) This section applies only to sources which were major for NOx emissions before November 15, 1992.

(2) The executive director shall approve the plan if it contains all the information specified in this section.

(3) 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) The owner or operator of all units which are subject to the emission limitations of this division (relating to Utility Electric Generation) must be tested as follows.

(1) Test for nitrogen oxides (NOx), carbon monoxide (CO), and oxygen (O2) emissions.

(2) Units which inject urea or ammonia into the exhaust stream for NOx control shall be tested for ammonia emissions.

(3) Testing 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 the emission limits of this division. Test results shall be reported in the units of the applicable emission limits and averaging periods. If compliance testing is based on 40 Code of Federal Regulations, Part 60, Appendix A reference methods, the report must contain the information specified in § 117.211(g) of this title (relating to Initial Demonstration of Compliance).

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

(d) Initial compliance with the emission specifications of this division for units operating with CEMS or PEMS in accordance with § 117.113 of this title shall be demonstrated after monitor certification testing 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 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 or PEMS certification testing required in § 117.113 of this title 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) NOx monitoring. The owner or operator of each unit subject to the emission specifications of this division (relating to Utility Electric Generation), shall install, calibrate, maintain, and operate a continuous emissions monitoring system (CEMS), predictive emissions monitoring system (PEMS), or other system specified in this section to measure nitrogen oxides (NOx) on an individual basis.

(b) Carbon monoxide (CO) monitoring. The owner or operator shall monitor CO exhaust emissions from each unit subject to the emission specifications of this division using one or more of the following methods:

(1) install, calibrate, maintain, and operate a:

(A) CEMS in accordance with subsection (c) of this section; or

(B) PEMS in accordance with subsection (f) of this section; or

(2) sample CO as follows:

(A) with a portable analyzer (or 40 CFR 60, Appendix A reference method test apparatus) after manual combustion tuning or manual burner adjustments conducted for the purpose of minimizing NOx emissions whenever, following such manual changes, either:

(i) NOx emissions are sampled with a portable analyzer or 40 CFR 60, Appendix A reference method test apparatus; or

(ii) the resulting NOx emissions measured by CEMS or predicted by PEMS are lower than levels for which CO emissions data was previously gathered; and

(B) sample CO emissions using the test methods and procedures of 40 CFR 60 in conjunction with the annual relative accuracy test audit of the NOx and diluent analyzer.

(c) CEMS requirements.

(1) Any CEMS required by this section shall be installed, calibrated, maintained, and operated in accordance with 40 CFR, Part 75 or 40 CFR, Part 60, as applicable.

(2) One CEMS may be shared among units, provided:

(A) the exhaust stream of each unit is analyzed separately; and

(B) the CEMS meets the applicable certification requirements of paragraph (1) of this subsection for each exhaust stream.

(d) Acid rain peaking units. The owner or operator of each peaking unit as defined in 40 CFR Part 72.2, may:

(1) monitor operating parameters for each unit in accordance with 40 CFR Part 75, Appendix E § 1.1 or § 1.2 and calculate NOx emission rates based on those procedures; or

(2) use CEMS or PEMS in accordance with this section to monitor NOx emission rates.

(e) Auxiliary boilers. The owner or operator of each auxiliary boiler as defined in § 117.10 of this title (relating to Definitions) shall:

(1) install, calibrate, maintain, and operate a CEMS in accordance with this section; or

(2) 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).

(f) PEMS requirements. The owner or operator of any PEMS used to meet a pollutant monitoring requirement of this section must comply with the following. The required PEMS and fuel flow meters shall be used to demonstrate continuous compliance with the emission limitations of § 117.105 or § 117.107 of this title (relating to Emission Specifications and Alternative System-wide Emission Specifications).

(1) The PEMS must predict the pollutant emissions in the units of the applicable emission limitations of this division.

(2) Monitor diluent, either oxygen or carbon dioxide:

(A) using a CEMS

(i) in accordance with subsection (b) of this section; or

(ii) with a similar alternative method approved by the executive director and the United States Environmental Protection Agency; or

(B) using a PEMS.

(3) Any PEMS for units subject to the requirements of 40 CFR 75 shall meet the requirements of 40 CFR 75 Subpart E, § § 75.40 - 75.48.

(4) Any PEMS for units not subject to the requirements of 40 CFR 75 shall meet the requirements of either:

(A) 40 CFR 75, Subpart E, § § 75.40 - 75.48; or

(B) § 117.213(f) of this title.

(g) Gas turbine monitoring. The owner or operator of each gas turbine subject to the emission specifications of § 117.105 of this title, instead of monitoring emissions in accordance with the monitoring requirements of 40 CFR 75, may 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(g) of this title:

(A) install, calibrate, maintain and operate a CEMS or PEMS in compliance with 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) of this title, install, calibrate, maintain and operate a CEMS or PEMS in compliance with this section.

(h) Totalizing fuel flow meters. The owner or operator of units listed in this subsection shall install, calibrate, maintain, and operate totalizing fuel flow meters to individually and continuously measure the gas and liquid fuel usage. A computer which collects, sums, and stores electronic data from continuous fuel flow meters is an acceptable totalizer. The units are:

(1) any unit subject to the emission specifications of this division;

(2) any stationary gas turbine with an MW rating greater than or equal to 1.0 MW operated more than 850 hours per year (hr/yr); and

(3) any unit claimed exempt from the emission specifications of this division using the low annual capacity factor exemption of § 117.103(a)(2) of this title (relating to Exemptions).

(i) Run time meters. The owner or operator of any stationary gas turbine using the exemption of § 117.103(a)(3) of this title shall record the operating time with an elapsed run time meter approved by the executive director.

(j) Loss of exemption. The owner or operator of any unit claimed exempt from the emission specifications of this division using the low annual capacity factor exemptions of § 117.103(a)(2) or (3) of this title, shall notify the executive director within seven days if the applicable limit is exceeded.

(1) If the limit is exceeded, the exemption from the emission specifications of § 117.105 of this title shall be permanently withdrawn.

(2) 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 limit. The plan shall include a schedule of increments of progress for the installation of the required control equipment.

(3) The schedule shall be subject to the review and approval of the executive director.

(k) Data used for compliance. After the initial demonstration of compliance required by § 117.111 of this title (relating to Initial Demonstration of Compliance) the methods required in this section shall be used to determine compliance with the emission specifications of this division. Compliance with the emission limitations may also be determined at the discretion of the executive director using any commission compliance method.

(l) Enforcement of NOx limits. 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) of this title (relating to Final Control Plan Procedures).

117.115 Final Control Plan Procedures

(a) The owner or operator of units listed in § 117.101 of this title (relating to Applicability) at a major source of nitrogen oxides (NOx) shall submit a final control report to show compliance with the requirements of this division. The report must include a list of all units listed in § 117.101 of this title, showing:

(1) the NOx emission specification resulting from application of § 117.105 of this title (relating to Emission Specifications) for each non-exempt unit;

(2) the section under which NOx compliance is being established for units specified in paragraph (1) of this subsection, either:

(A) § 117.105 of this title;

(B) § 117.107 of this title (relating to Alternative Plant-wide Emission Specifications);

(C) § 117.121 of this title (relating to Alternative Case Specific Specifications); or

(D) § 117.570 (relating to Trading);

(3) the method of control of NOx emissions for each unit;

(4) the emissions measured by testing required in § 117.111 of this title (relating to Initial Demonstration of Compliance);

(5) the submittal date, and whether sent to the Austin or the regional office (or both), of any compliance stack test report or relative accuracy test audit report required by § 117.111 of this title which is not being submitted concurrently with the final compliance report; and

(6) the specific rule citation for any unit with a claimed exemption from the emission specifications of this division.

(b) For sources complying with § 117.107 of this title, in addition to the requirements of subsection (a) of this section, 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) a rolling 24-hour average and rolling 30-day average for gaseous fuel firing, and

(B) a rolling 24-hour average for oil or coal firing;

(2) submit a list to the executive director for approval of:

(A) the maximum allowable NOx emission rates identified in paragraph (1) of this subsection; and

(B) the maximum rated capacity for each unit;

(3) submit calculations used to calculate the system-wide average in accordance with § 117.107(e) of this title; and

(4) maintain a copy of the approved list of emission limits for verification of continued compliance with the requirements of § 117.107 of this title.

(c) The lists of information required in this section must be submitted electronically and on hard copy using forms provided by the executive director. This requirement does not apply to calculations or other explanatory information.

(d) The report must be submitted by the applicable date specified for final control plans in § 117.510 of this title (relating to Compliance Schedule For Utility Electric Generation). The plan must be updated with any emission compliance measurements submitted for units using continuous emissions monitoring system or predictive emissions monitoring system and complying with an emission limit on a rolling 30-day average, according to the applicable schedule given in § 117.510 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 division (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) Start-up and shutdown records. For units subject to the start-up and/or shutdown exemptions allowed under § 101.11 of this title (relating to Exemptions from Rules and Regulations), 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 executive director, 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) Notification. The owner or operator of a unit subject to the emission specifications of this division (relating to Utility Electric Generation) 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) Reporting of test results. 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:

(1) within 60 days after completion of such testing or evaluation; and

(2) not later than the appropriate compliance schedules specified in § 117.510 of this title (relating to Compliance Schedule for Utility Electric Generation).

(d) Semiannual reports. 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 semiannual basis any exceedance of the applicable emission limitations in this division and the monitoring system performance. All reports shall be postmarked or received by the 30th day following the end of each calendar semiannual period. Written reports shall include the following information:

(1) the magnitude of excess emissions computed in accordance with 40 Code of Federal Regulations (CFR), 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 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 commission's "Guidance for Preparation of Summary, Excess Emission, and Continuous Monitoring System Reports") shall be submitted, unless otherwise requested by the executive director. 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) Recordkeeping. The owner or operator of a unit subject to the requirements of this division shall maintain records of the data specified in this subsection. Records shall be kept for a period of at least five years and made available for inspection by the executive director, 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 for units claimed exempt from the emission specifications based on low annual capacity factor, monthly. Records 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) emission monitoring data, pursuant to § 117.113 of this title, including:

(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 operating parameter 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; and

(7) records of hours of operation.

117.121 Alternative Case Specific Specifications

(a) Where a person can demonstrate that an affected unit cannot attain the applicable requirements of § 117.105 of this title (relating to Emission Specifications), the executive director may approve emission specifications different from § 117.105 of this title for that unit. The executive director:

(1) shall consider on a case-by-case basis the technological and economic circumstances of the individual unit;

(2) must determine 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; and

(3) in determining whether to approve alternative emission specifications, 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.

(b) Any person affected by the executive director's decision to deny an alternative case specific emission specification may file a motion for reconsideration. The requirements of § 50.39 of this title (relating to Motion for Reconsideration) apply. However, only a person affected may file a motion for reconsideration. Executive director approval does not necessarily constitute satisfaction of all federal requirements nor eliminate the need for approval by the United States Environmental Protection Agency in cases where specified criteria for determining equivalency have not been clearly identified in applicable sections of this division (relating to Utility Electric Generation).


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