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You are here: Home / Permitting / Air Permits / PermitByRule / Historical Rules / old117 / 1199 / Title 30 TAC 117.201 - 223, November 21, 1999

Title 30 TAC 117.201 - 223, November 21, 1999

Agency rules, policies and procedures; Reference materials

Subchapter B Combustion at Existing Major Sources

Division 2: Commercial, Institutional and Industrial Sources

117.201 Applicability
117.203 Exemptions
117.205 Emission Specifications
117.207 Alternative Plant-Wide Emission Specifications
117.208 Operating Requirements
117.209 Initial Control Plan Procedures
117.211 Initial Demonstration of Compliance
117.213 Continuous Demonstration of Compliance
117.215 Final Control Plan Procedures
117.217 Revision of Final Control Plan
117.219 Notification, Recordkeeping, and Reporting Requirements
117.221 Alternative Case Specific Specifications
117.223 Source Cap

117.201 Applicability

The provisions of this division (relating to Commercial, Institutional, and Industrial Sources) shall apply to the following units located at any major stationary source of nitrogen oxides located within the Beaumont/Port Arthur, Dallas/Fort Worth, or Houston/Galveston ozone nonattainment areas:

(1) commercial, institutional, or industrial boilers and process heaters with a maximum rated capacity of 40 million Btu per hour or greater;

(2) stationary gas turbines with a megawatt (MW) rating of 1.0 MW or greater; and

(3) stationary internal combustion engines which are:

(A) located in the Houston/Galveston ozone nonattainment area with a horsepower (hp) rating of 150 hp or greater; or

(B) located in the Beaumont/Port Arthur or Dallas/Fort Worth ozone nonattainment area with a horsepower rating of 300 hp or greater.

117.203 Exemptions

Units exempted from the provisions of this division (relating to Commercial, Institutional, and Industrial Sources), except as may be specified in § 117.209(c)(1) of this title (relating to Initial Control Plan Procedures) and § 117.213(a) and (i) of this title (relating to Continuous Demonstration of Compliance), include the following:

(1) any new units placed into service after November 15, 1992, except for new units which were placed into service as functionally identical replacement for existing units subject to the provisions of this division as of June 9, 1993. Any emission credits resulting from the operation of such replacement units shall be limited to the cumulative maximum rated capacity of the units replaced;

(2) any commercial, institutional, or industrial boiler or process heater with a maximum rated capacity of less than 40 million Btu per hour;

(3) any electric utility power generating boiler;

(4) flares, incinerators, fume abaters, pulping liquor recovery furnaces, sulfur recovery units, sulfuric acid regeneration units, and sulfur plant reaction boilers;

(5) dryers, kilns, or ovens used for drying, baking, cooking, calcining, and vitrifying;

(6) stationary gas turbines and engines, which are:

(A) used in research and testing, or used for purposes of performance verification and testing, or used solely to power other engines or gas turbines during start-ups, or operated exclusively for firefighting and/or flood control, or used in response to and during the existence of any officially declared disaster or state of emergency, or used directly and exclusively by the owner or operator for agricultural operations necessary for the growing of crops or raising of fowl or animals, or used as chemical processing gas turbines; or

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

(7) stationary gas turbines with a megawatt (MW) rating of less than 1.0 MW; and

(8) stationary internal combustion engines which are:

(A) located in the Houston/Galveston ozone nonattainment area with a horsepower (hp) rating of less than 150 hp; or

(B) located in the Beaumont/Port Arthur or Dallas/Fort Worth ozone nonattainment area with a hp rating of less than 300 hp.

117.205 Emission Specifications

(a) No person shall allow the discharge of air contaminants into the atmosphere to exceed the emission limits of this section, except as provided in § 117.207 of this title (relating to Alternative Plant- Wide Emission Specifications), or § 117.223 of this title (relating to Source Cap).

(1) For purposes of this subchapter, the lower of any permit nitrogen oxides (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 emission limits of subsections (b)-(d) of this section shall apply, except that:

(A) gas-fired boilers and process heaters operating under a permit issued after March 3, 1982, with an emission limit of 0.12 pound NOx per million British thermal units (Btu) heat input, shall be limited to that rate for the purposes of this subchapter; and

(B) gas-fired boilers and process heaters which have had NOx reduction projects permitted since November 15, 1990 and prior to June 9, 1993 that were solely for the purpose of making early NOx reductions, shall be subject to the appropriate emission limit of subsection (b) of this section. The affected person shall document that the NOx reduction project was solely for the purpose of obtaining early reductions, and include this documentation in the initial control plan required in § 117.209 of this title (relating to Initial Control Plan Procedures).

(2) For purposes of calculating NOx emission limitations under this section from existing permit limits, the following procedure shall be used:

(A) the limit explicitly stated in pound NOx per million Btu (MMBtu) of heat input by permit provision (converted from low heating value to high heating value, as necessary); or

(B) the NOx emission limit is the limit calculated as the permit Maximum Allowable Emission Rate Table emission limit in pounds per hour, divided by the maximum heat input to the unit in MMBtu per hour (MMBtu/hr), as represented in the permit application. In the event the maximum heat input to the unit is not explicitly stated in the permit application, the rate shall be calculated from Table 6 of the permit application, using the design maximum fuel flow rate and higher heating value of the fuel, or, if neither of the above are available, the unit's nameplate heat input.

(3) For any unit placed into service after June 9, 1993 and before the final compliance date as specified in § 117.520 of this title (relating to Compliance Schedule for Commercial, Institutional, and Industrial Combustion Sources 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, 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 (b)-(d) 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 § 117.207 or § 117.223 of this title. Compliance with this paragraph does not eliminate the requirement for new units to comply with Chapter 116 of this title.

(b) For each boiler and process heater with a maximum rated capacity greater than or equal to 100.0 MMBtu/hr of heat input, the applicable emission limit is as follows:

(1) gas-fired boilers, as follows:

(A) low heat release boilers with no preheated air or preheated air less than 200 degrees Fahrenheit, 0.10 pound (lb) NOx/MMBtu of heat input;

(B) low heat release boilers with preheated air greater than or equal to 200 degrees Fahrenheit and less than 400 degrees Fahrenheit, 0.15 lb NOx/MMBtu of heat input;

(C) low heat release boilers with preheated air greater than or equal to 400 degrees Fahrenheit, 0.20 lb NOx/MMBtu of heat input;

(D) high heat release boilers with no preheated air or preheated air less than 250 degrees Fahrenheit, 0.20 lb NOx/MMBtu of heat input;

(E) high heat release boilers with preheated air greater than or equal to 250 degrees Fahrenheit and less than 500 degrees Fahrenheit, 0.24 lb NOx/MMBtu of heat input; or

(F) high heat release boilers with preheated air greater than or equal to 500 degrees Fahrenheit, 0.28 lb NOx/MMBtu of heat input.

(2) gas-fired process heaters, based on either air preheat temperature or firebox temperature, as follows:

(A) based on air preheat temperature:

(i) process heaters with preheated air less than 200 degrees Fahrenheit, 0.10 lb NOx/MMBtu of heat input;

(ii) process heaters with preheated air greater than or equal to 200 degrees Fahrenheit and less than 400 degrees Fahrenheit, 0.13 lb NOx/MMBtu of heat input; or

(iii) process heaters with preheated air greater than or equal to 400 degrees Fahrenheit, 0.18 lb NOx/MMBtu of heat input.

(B) based on firebox temperature:

(i) process heaters with a firebox temperature less than 1,400 degrees Fahrenheit, 0.10 lb NOx/MMBtu of heat input;

(ii) process heaters with a firebox temperature greater than or equal to 1,400 degrees Fahrenheit and less than 1,800 degrees Fahrenheit, 0.125 lb NOx/MMBtu of heat input; or

(iii) process heaters with a firebox temperature greater than or equal to 1,800 degrees Fahrenheit, 0.15 lb NOx/MMBtu of heat input;

(3) liquid fuel-fired boilers and process heaters, 0.30 lb NOx/MMBtu of heat input;

(4) wood fuel-fired boilers and process heaters, 0.30 lb NOx/MMBtu of heat input;

(5) any unit operated with a combination of gaseous, liquid, or wood fuel, a variable emission limit calculated as the heat input weighted sum of the applicable emission limits of this subsection;

(6) for any gas-fired boiler or process heater firing gaseous fuel which contains more than 50% hydrogen by volume, over an eight-hour period, in which the fuel gas composition is sampled and analyzed every three hours, a multiplier of up to 1.25 times the appropriate emission limit in this subsection may be used for that eight-hour period. The total hydrogen volume in all gaseous fuel streams will be divided by the total gaseous fuel flow volume to determine the volume percent of hydrogen in the fuel supply. The multiplier may not be used to increase limits set by permit;

(7) for units which operate with a NOx continuous emission monitors (CEMS) or predictive emission monitors (PEMS) under § 117.213 of this title (relating to Continuous Demonstration of Compliance), the emission limits shall apply as:

(A) the mass of NOx emitted per unit of energy input (pound NOx per MMBtu), on a rolling 30-day average period; or

(B) the mass of NOx emitted per hour (pounds per hour), on a block one-hour average, calculated as the product of the boiler's or process heater's maximum rated capacity and its applicable limit in pound NOx per MMBtu; and

(8) for units which do not operate with a NOx CEMS or PEMS under § 117.213 of this title, the emission limits shall apply in pounds per hour, as specified in paragraph (7)(B) of this subsection.

(c) No person shall allow the discharge into the atmosphere from any stationary gas turbine with a MW rating greater than or equal to 10.0 MW, emissions in excess of a block one-hour average concentration of 42 parts per million by volume (ppmv) NOx and 132 ppmv carbon monoxide (CO) at 15% oxygen (O2), dry basis.

(d) No person shall allow the discharge into the atmosphere from any gas-fired, rich-burn, stationary, reciprocating internal combustion engine, emissions in excess of a block one-hour average of 2.0 grams NOx per horsepower hour (g NOx/hp-hr) and 3.0 g CO/hp-hr for engines which are:

(1) rated 150 hp or greater and located in the Houston/Galveston ozone nonattainment area; or

(2) rated 300 hp or greater and located in the Beaumont/Port Arthur or Dallas/Fort Worth ozone nonattainment area

(e) No person shall allow the discharge into the atmosphere from any gas-fired, lean-burn, stationary, reciprocating internal combustion engine rated 300 hp or greater and located in the Beaumont/Port Arthur ozone nonattainment area, emissions in excess of 3.0 g NOx/hp-hr and 3.0 g CO/hp-hr, either as:

(1) a block one-hour average limit; or

(2) a thirty-day rolling average limit. The owner or operator must ensure compliance with a 30-day rolling average using:

(A) a PEMS or CEMS under § 117.213 of this title; or

(B) a monitoring system which

(i) computes predicted emissions as a function of engine speed and torque using curves or equations supplied by the engine manufacturer or developed through engine testing, which

(I) may be adjusted by engine testing; and

(II) must be shown to be consistent with the required initial and biennial compliance testing; and

(ii) monitors and records data representative of engine torque and speed at sufficient frequency to accurately compute the 30-day average NOx.

(f) No person shall allow the discharge into the atmosphere from any boiler or process heater subject to NOx emission specifications in subsection (a) or (b) of this section, CO emissions in excess of the following limitations:

(1) for gas or liquid fuel-fired boilers or process heaters, 400 ppmv at 3.0% O2, dry basis;

(2) for wood fuel-fired boilers or process heaters, 775 ppmv at 7.0% O2, dry basis; and

(3) for units equipped with CEMS or PEMS for CO, the limits of paragraphs (1) and (2) of this subsection shall apply on a rolling 24-hour averaging period. For units not equipped with CEMS or PEMS for CO, the limits shall apply on a one-hour average.

(g) No person shall allow the discharge into the atmosphere from any unit subject to a NOx emission limit in this division (relating to Commercial, Institutional, and Industrial Sources), ammonia emissions in excess of 20 ppmv based on a block one-hour averaging period.

(h) Units exempted from the emissions specifications of this section include the following:

(1) any commercial, institutional, or industrial boiler or process heater with a maximum rated capacity less than 100 MMBtu/hr;

(2) any low annual capacity factor boiler, process heater, stationary gas turbine, or stationary internal combustion engine as defined in § 117.10 of this title (relating to Definitions);

(3) boilers and industrial furnaces which were regulated as existing facilities by the United States Environmental Protection Agency at 40 Code of Federal Regulations Part 266, Subpart H, as was in effect on June 9, 1993;

(4) fluid catalytic cracking units (including CO boilers);

(5) supplemental waste heat recovery units used in turbine exhaust ducts;

(6) any lean-burn, stationary, reciprocating internal combustion engine located in the Houston/Galveston or Dallas/Fort Worth ozone nonattainment area; and

(7) any stationary gas turbine with an MW rating less than 10.0 MW.

117.207 Alternative Plant-wide Emission Specifications

(a) An owner or operator may achieve compliance with the nitrogen oxides (NOx) emission limits of § 117.205 of this title (relating to Emission Specifications) by achieving equivalent NOx emission reductions obtained by compliance with a plant-wide emission limitation. Any owner or operator who elects to comply with a plant-wide emission limit shall reduce emissions of NOx from affected units so that if all such units were operated at their maximum rated capacity, the plant-wide emission rate of NOx from these units would not exceed the plant-wide emission limit as defined in § 117.10 of this title (relating to Definitions).

(b) The owner or operator shall establish an enforceable (NOx) emission limit for each affected unit at the source as follows.

(1) For boilers and process heaters which operate with continuous emission monitors (CEMS) or predictive emission monitors (PEMS) in accordance with § 117.213 of this title (relating to Continuous Demonstration of Compliance), the emission limits shall apply as:

(A) the mass of NOx emitted per unit of energy input (pound NOx per million (MM) Btu), on a rolling 30-day average period; or

(B) as the mass of NOx emitted per hour (pounds per hour), on a block one-hour average.

(2) For boilers and process heaters which do not operate with CEMS or PEMS, the emission limits shall apply as the mass of NOx emitted per hour (pounds NOx per hour), on a block one-hour average.

(3) For stationary gas turbines, the emission limits shall apply as the NOx concentration in parts per million by volume (ppmv) at 15% oxygen (O2), dry basis on a block one-hour average.

(4) For stationary internal combustion engines, the emission limits shall apply in units of grams NOx per horsepower-hour (g NOx/hp-hr) on a block one-hour average.

(c) An owner or operator of any gaseous and liquid fuel-fired unit which derives more than 50% of its annual heat input from gaseous fuel shall use only the appropriate gaseous fuel emission limit of § 117.205 of this title at maximum rated capacity in calculating the plant-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 gas only;

(2) comply with the liquid fuel emission limit of § 117.205 of this title 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 rate and the liquid fuel emission limit of § 117.205 of this title while operating on liquid and gaseous fuel concurrently.

(d) An owner or operator of any gaseous and liquid fuel-fired unit which derives more than 50% of its annual heat input from liquid fuel shall use a heat input weighted sum of the appropriate gaseous and liquid fuel emission specifications of § 117.205 of this title in calculating the plant-wide emission limit and shall assign to the unit the maximum allowable NOx emission rate, calculated in accordance with subsection (a) of this section.

(e) An owner or operator of any unit operated with a combination of gaseous (or liquid) and solid fuels shall use a heat input weighted sum of the appropriate emission specifications of § 117.205 of this title in calculating the plant-wide emission limit and shall assign to the unit the maximum allowable NOx emission rate, calculated in accordance with subsection (a) of this section.

(f) Units exempted from emission specifications in accordance with § 117.205(h) of this title are also exempt under this section and shall not be included in the plant-wide emission limit, except as follows. The owner or operator of exempted units as defined in § 117.205(h) of this title may opt to include one or more of an entire equipment class of exempted units into the alternative plant-wide emission specifications.

(1) Low annual capacity factor boilers, process heaters, gas turbines, or engines as defined in § 117.10 of this title are not to be considered as part of the opt-in class of equipment.

(2) The ammonia and carbon monoxide emission specifications of § 117.205 of this title apply to the opt-in units.

(3) The individual NOx emission limit that is to be used in calculating the alternative plant-wide emission specifications is the lower of any applicable permit emission specification determined in accordance with § 117.205(a) of this title and the specification of paragraph (4) of this subsection.

(4) The equipment classes which may be included in the alternative plant-wide emission specifications and the NOx emission rates that are to be used in calculating the alternative plant-wide emission specifications are listed in the following table, § 117.207(f) OPT-IN UNITS:

§ 117.207(f) OPT-IN UNITS

Equipment Class/Description Emission Specification
fluid catalytic cracking unit carbon monoxide (CO) boilers 50% NOx reduction across the inlet of the CO boiler to the outlet of the CO boiler, with the outlet concentration in ppmv converted into lb NOx/MMBtu of heat input
lean-burn, gas-fired, stationary, reciprocating internal combustion engines rated 150 hp or greater 5.0 g NOx/hp-hr under all operating conditions
boilers, steam generators, or process heaters with a maximum rated capacity (MRC): 40 MMBtu/hr <= MRC < 100 MMBtu/hr the emission specifications in § 117.205(a) of this title for the applicable type of unit
stationary gas turbines with a MW rating: 1.0 MW <= MW rating < 10.0 MW 42 ppmv NOx at 15% O2, dry basis
boilers and industrial furnaces which are regulated as existing facilities by the United States Environmental Protection Agency (EPA) at 40 Code of Federal Regulations (CFR) Part 266, Subpart H the appropriate emission limitation in § 117.205(b) of this title

(g) Solely for the purposes of calculating the plant-wide emission limit, the allowable NOx emission rate (in pounds per hour) for each affected unit shall be calculated from the emission specifications of § 117.205 of this title, as follows.

(1) For each affected boiler and process heater, the rate is the product of its maximum rated capacity and its NOx emission specification of § 117.205 of this title.

(2) For each affected stationary internal combustion engine, the rate is the product of the applicable NOx emission specification of § 117.205 of this title (expressed in g/hp-hr) and the engine manufacturer's rated heat input (expressed in MMBtu/hr) at the engine's hp rating; divided by the product of the engine manufacturer's rated heat rate (expressed in Btu/hp-hr) at the engine's hp rating and 454(106).

(3) For each affected stationary gas turbine, the rate is the product of the in-stack NOx, the turbine manufacturer's rated exhaust flow rate (expressed in pounds per hour at 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 § 117.205(c) of this title (expressed in ppmv NOx at 15% O2, dry basis).

%H2O = the volume percent of 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 of 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 MW rating and ISO flow conditions.

(4) Each affected gas-fired boiler and process heater firing gaseous fuel which contains more than 50% hydrogen (H2) by volume, over an annual basis, may be adjusted with a multiplier of up to 1.25 times the product of its maximum rated capacity and its NOx emission specification of § 117.205 of this title.

(A) Double application of the H2 content multiplier using this paragraph and § 117.205(b)(6) of this title is not allowed.

(B) The multiplier may not be used to increase a limit set by permit.

(C) The fuel gas composition must be sampled and analyzed every three hours.

(h) The owner or operator of any gas-fired boiler or process heater firing gaseous fuel which contains more than 50% H2 by volume, over an eight-hour period, in which the fuel gas composition is sampled and analyzed every three hours, may use a multiplier of up to 1.25 times the emission limit assigned to the unit in this section for that eight-hour period, not applicable to units under subsection (g)(4) of this section or to increase limits set by permit. The total H2 volume in all gaseous fuel streams will be divided by the total gaseous fuel flow volume to determine the volume percent of H2 in the fuel supply.

117.208 Operating Requirements

(a) The owner or operator shall operate any unit subject to the emission limitations of § 117.205 of this title (relating to Emission Specifications) in compliance with those limitations.

(b) The owner or operator shall operate any unit subject to the plant-wide emission limit of § 117.207 of this title (relating to Alternative Plant-wide Emission Specifications) such that the assigned maximum nitrogen oxides (NOx) emission rate for each unit expressed in units of the applicable emission limit and averaging period, is in accordance with the list approved by the executive director pursuant to § 117.215 of this title (relating to Final Control Plan Procedures).

(c) The owner or operator shall operate any unit subject to the source cap emission limits of § 117.223 of this title (relating to Source Cap) in compliance with those limitations.

(d) All units subject to the emission limitations of § § 117.205, 117.207, or 117.223 of this title shall be operated so as to minimize NOx emissions, consistent with the emission control techniques selected, over the unit's operating or load range during normal operations. Such operational requirements include the following.

(1) Each boiler, except for wood-fired boilers, shall be operated with oxygen (O2) or carbon monoxide (CO) trim (or both).

(2) Each boiler and process heater controlled with forced flue gas recirculation (FGR) to reduce NOx emissions shall be operated such that the proportional design rate of FGR is maintained, consistent with combustion stability, over the operating range.

(3) Each boiler and process heater controlled with induced draft FGR to reduce NOx emissions shall be operated such that the operation of FGR over the operating range is not restricted by artificial means.

(4) Each unit controlled with steam or water injection shall be operated such that injection rates are maintained to limit NOx concentrations to less than or equal to the NOx concentrations achieved at maximum rated capacity (corrected to 15% O2 on a dry basis for gas turbines).

(5) Each unit controlled with post combustion control techniques shall be operated such that the reducing agent injection rate is maintained to limit NOx concentrations to less than or equal to the NOx concentrations achieved at maximum rated capacity.

(6) Each stationary internal combustion engine controlled with nonselective catalytic reduction shall be equipped with an automatic air-fuel ratio (AFR) controller which operates on exhaust O2 or CO control and maintains AFR in the range required to meet the engine's applicable emission limits.

(7) Each stationary internal combustion engine shall be checked for proper operation of the engine by recorded measurements of NOx and CO emissions at least quarterly and as soon as practicable after each occurrence of engine maintenance which may reasonably be expected to increase emissions, O2 sensor replacement, or catalyst cleaning or catalyst replacement. Stain tube indicators specifically designed to measure NOx concentrations shall be acceptable for this documentation, provided a hot air probe or equivalent device is used to prevent error due to high stack temperature, and three sets of concentration measurements are made and averaged. Portable NOx analyzers shall also be acceptable for this documentation.

117.209 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 (if required in order to comply with the emission specifications of this subchapter) and demonstration of anticipated compliance with the 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 owner or operator shall provide results of emissions testing using portable or reference method analyzers or, as available, initial demonstration of compliance testing conducted in accordance with § 117.211(e) or (f) of this title (relating to Initial Demonstration of Compliance) for NOx, carbon monoxide (CO), and oxygen emissions while firing gaseous fuel (and as applicable, hydrogen (H2) fuel for units which may fire more than 50% H2 by volume) and liquid and/or solid fuel at the maximum rated capacity or as near thereto as practicable, for the units listed in this subsection. Previous testing documentation for any claimed test waiver as allowed by § 117.211(d) of this title shall be submitted with the initial control plan. Any units which were not operated between June 9, 1993 and April 1, 1994 and do not have earlier representative emission test results available shall be tested and the results submitted to the executive director, with certification of the equipment's shutdown period, within 90 days after the date such equipment is returned to operation. Test results are required for the following units:

(1) boilers and process heaters with a maximum rated capacity greater than or equal to 40 million British thermal units per hour (MMBtu/hr), except for low annual capacity factor boilers and process heaters as defined in § 117.10 of this title (relating to Definitions);

(2) boilers and industrial furnaces with a maximum rated capacity greater than or equal to 40 MMBtu/hr which were regulated as existing facilities by EPA at 40 Code of Federal Regulations, Part 266, Subpart H, as was in effect on June 9, 1993, except for low annual capacity factor boilers and process heaters as defined in § 117.10 of this title;

(3) fluid catalytic cracking units with a maximum rated capacity greater than or equal to 40 MMBtu/hr;

(4) gas turbine supplemental waste heat recovery units with a maximum rated fired capacity greater than or equal to 40 MMBtu/hr, except for low annual capacity factor gas turbine supplemental waste heat recovery units as defined in § 117.10 of this title;

(5) stationary gas turbines with a megawatt (MW) rating of greater than or equal to 1.0 MW, except for low annual capacity factor gas turbines or peaking gas turbines as defined in § 117.10 of this title; and

(6) gas-fired, stationary, reciprocating internal combustion engines 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, except for low annual capacity factor engines or peaking engines as defined in § 117.10 of this title.

(c) The initial control plan shall be submitted in accordance with the schedule specified in § 117.520 of this title (relating to Compliance Schedule For Commercial, Institutional, and Industrial Combustion Sources) 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 engines which are located in the Houston/Galveston ozone nonattainment area and rated 150 hp or greater, or located in the Beaumont/Port Arthur ozone nonattainment area and rated 300 hp or greater; all stationary gas turbines with an MW rating of greater than or equal to 1.0 MW; to include the maximum rated capacity, anticipated annual capacity factor, the facility identification numbers and emission point numbers as submitted to the Area and Mobile Emissions Assessment and Industrial Emissions Assessment Sections of the commission, and the emission point numbers as listed on the Maximum Allowable Emissions Rate Table of any applicable commission permit for each unit;

(2) identification of all units subject to the emission specifications of § 117.205 of this title (relating to Emission Specifications), § 117.207 of this title (relating to Alternative Plant-Wide Emission Specifications), or § 117.223 of this title (relating to Source Cap);

(3) identification of all boilers, process heaters, stationary gas turbines, or engines with a claimed exemption from the emission specifications of § 117.205 or § 117.207 of this title and the rule basis for the claimed exemption;

(4) identification of the election to use individual emission limits as specified in § 117.205 of this title, the plant-wide emission limit as specified in § 117.207 of this title, or the source cap emission limit as specified in § 117.223 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 units requiring operating modifications to comply with § 117.208(d) of this title (relating to Operating Requirements) and the type of modification to be applied for all such units, including an anticipated construction schedule;

(7) a list of any units which have been or will be retired, decommissioned, or shutdown and rendered inoperable after November 15, 1990 as a result of compliance with this regulation, indicating the date of occurrence or anticipated date of occurrence;

(8) the basis for calculation of the rate of NOx emissions for each unit to demonstrate that each unit will achieve the NOx emission rates specified in this division. For fluid catalytic cracking unit CO boilers, the basis for calculation of the pound NOx per million Btu (lb NOx/MMBtu) rate for each unit shall include the following:

(A) the calculation of the CO boiler heat input;

(B) the calculation of the appropriate CO boiler volumetric inlet and exhaust flowrates; and

(C) the calculation of the CO boiler lb NOx/MMBtu emission rate;

(9) for units required to install totalizing fuel flow meters in accordance with § 117.213(a) of this title (relating to Continuous Demonstration of Compliance), indication of whether the devices are currently in operation, and if so, whether they have been installed as a result of the requirements of this chapter;

(10) for units which have had NOx reduction projects as specified in § 117.205(a)(1)(B) of this title, documentation that such projects were undertaken solely for the purpose of obtaining early NOx reductions; and

(11) test results in accordance with subsection (b) of this section.

117.211 Initial Demonstration of Compliance

(a) The owner or operator of all units which are subject to the emission limitations of this division (relating to Commercial, Institutional, and Industrial Sources) must test the units as follows.

(1) Test for nitrogen oxides (NOx), carbon monoxide (CO), and oxygen (O2) emissions while firing gaseous fuel or, as applicable:

(A) hydrogen (H2) fuel for units which may fire more than 50% H2 by volume; and

(B) liquid and solid fuel.

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

(3) Test all units belonging to equipment classes which are elected to be included in

(A) the alternative plant-wide emission specifications as defined in § 117.207(f) of this title (relating to Alternative Plant-Wide Emission Specifications); or

(B) the source cap as defined in § 117.223(b)(4) of this title (relating to Source Cap).

(4) Initial demonstration of compliance testing shall be performed in accordance with the schedule specified in § 117.520 of this title (relating to Compliance Schedule For Commercial, Institutional, and Industrial Combustion Sources).

(b) The initial demonstration of compliance tests required by subsection (a) of this section shall use the test methods referenced in subsection (e) or (f) of this section and 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.

(c) Any continuous emissions monitoring system (CEMS) or any predictive emissions monitoring system (PEMS) required by § 117.213 of this title (relating to Continuous Demonstration of Compliance) shall be installed and operational before conducting testing under subsection (a) of this section. Verification of operational status shall, as a minimum, include completion of the initial relative accuracy test audit and the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device or system.

(d) Early testing conducted before March 21, 1999 may be used to demonstrate compliance with the standards specified in this division, if the owner or operator of an affected facility demonstrates to the executive director that the prior compliance testing at least meets the requirements of subsections (a), (b), (c), (e), and (f) of this section. For early testing, the compliance stack test report required by subsection (g) shall be as complete as necessary to demonstrate to the executive director that the stack test was valid and the source has complied with the rule. The executive director reserves the right to request compliance testing or CEMS or PEMS performance evaluation at any time.

(e) Compliance with the emission specifications of this division for units operating without CEMS or PEMS shall be demonstrated while operating at the maximum rated capacity, or as near thereto as practicable. Compliance shall be determined by the average of three one-hour emission test runs, using the following test methods:

(1) Test Method 7E or 20 (40 Code of Federal Regulations (CFR), Part 60, Appendix A) for NOx;

(2) Test Method 10, 10A, or 10B (40 CFR 60, Appendix A) for CO;

(3) Test Method 3A or 20 (40 CFR 60, Appendix A) for O2;

(4) Test Method 2 (40 CFR 60, Appendix A) for exhaust gas flow and following the measurement site criteria of Test Method 1, Section 2.1 (40 CFR 60, Appendix A), or Test Method 19 (40 CFR 60, Appendix A) for exhaust gas flow in conjunction with the measurement site criteria of Performance Specification 2, Section 3.2 (40 CFR 60, Appendix B);

(5) American Society of Testing and Materials (ASTM) Method D1945-91 or ASTM Method D3588-93 for fuel composition; ASTM Method D1826-88 or ASTM Method D3588-91 for calorific value; or alternate methods as approved by the executive director and the United States Environmental Protection Agency (EPA); or

(6) EPA-approved alternate test methods or minor modifications to these test methods as approved by the executive director, as long as the minor modifications meet the following conditions:

(A) the change does not affect the stringency of the applicable emission limitation; and

(B) the change affects only a single source or facility application.

(f) Initial compliance with the emission specifications of this division for units operating with CEMS or PEMS in accordance with § 117.213 of this title, shall be demonstrated after monitor certification testing using the CEMS or PEMS as follows.

(1) For boilers and process heaters complying with a NOx emission limit in pound per million British thermal units (MMBtu) on a rolling 30-day average, NOx emissions from the 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) For units complying with a NOx emission limit on a block one-hour average, any one-hour period while operating at the maximum rated capacity, or as near thereto as practicable is used to determine compliance with the NOx emission limit.

(3) For units complying with a CO emission limit, on a rolling 24-hour average, any 24-hour period is used to determine compliance with the CO emission limit.

(4) For units complying with § 117.223 of this title, a rolling 30-day average of total daily pounds of NOx emissions from the units are monitored (or calculated in accordance with § 117.223(c) of this title) for 30 successive source 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 daily emissions data recorded by the monitoring and recording system during the 30-day test period. There must be no exceedances of the maximum daily cap during the 30- day test period.

(g) Compliance stack test reports must include the following minimum contents.

(1) Introductory information. Provide background information pertinent to the test, including:

(A) company name, address, and name of company official responsible for submitting report;

(B) name and address of testing organization;

(C) names of persons present, dates and location of test;

(D) schematic drawings of the unit being tested, showing emission points, sampling sites, and stack cross section with the sampling points labeled and dimensions indicated;

(E) description of the process being sampled; and

(F) facility identification number (FIN) used to identify the unit in the final control plan.

(2) Summary information. Provide summary information, including:

(A) a summary of emission rates found, reported in the units of the applicable emission limits and averaging periods, and compared with the applicable emission limit;

(B) the maximum rated capacity, normal maximum capacity, and actual operating level of the unit during the test (in MMBtu/hr, horsepower (hp), or megawatts (MW), as applicable), and description of the method used to determine such operating level;

(C) the operating parameters of any active NOx control equipment during the test, (for example, percent flue gas recirculation, ammonia flow rate, etc); and

(D) documentation that no changes to the unit have occurred since the compliance test was conducted that could result in a significant change in NOx emissions.

(3) Procedure. Describe the procedures used and operation of the sampling train and process during the test, including:

(A) a schematic drawing of the sampling devices used with each component designated and explained in a legend;

(B) a brief description of the method used to operate the sampling train and procedure used to recover samples; and

(C) deviation from reference methods, if any.

(4) Analytical technique. Provide a brief description of all analytical techniques used to determine the emissions from the source.

(5) Data and calculations. Include all data and calculations, of:

(A) field data collected on raw data sheets;

(B) log of process operating levels, including fuel data;

(C) laboratory data, including blanks, tare weights, and results of analysis; and

(D) emission calculations.

(6) Chain of custody. Include a listing of the chain of custody of the emission or fuel test samples, as applicable.

(7) Appendix. Provide:

(A) calibration work sheets for sampling equipment;

(B) collection of process logs of process parameters;

(C) brief resume/qualifications of test personnel; and

(D) description of applicable continuous monitoring system, as applicable.

(8) Monitor certification reports. Monitor certification reports must contain:

(A) information which demonstrates compliance with the certification requirements of § 117.213(e) or (f) of this title for CEMS or PEMS, as applicable; and

(B) the relative accuracy test audit information specified in 40 CFR 60, Appendix B, Performance Specification 2, Section 9.

117.213 Continuous Demonstration of Compliance

(a) Totalizing fuel flow meters. The owner or operator of units listed in this subsection shall install, calibrate, maintain, and operate a totalizing fuel flow meter 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.

(1) The units are the following:

(A) if individually rated more than 40 million British thermal units (Btu) per hour (MMBtu/hr):

(i) boilers;

(ii) process heaters;

(iii) boilers and industrial furnaces which were regulated as existing facilities by EPA at 40 Code of Federal Regulations (CFR) Part 266, Subpart H, as was in effect on June 9, 1993; and

(iv) gas turbine supplemental-fired waste heat recovery units;

(B) stationary, reciprocating internal combustion engines not exempt by § 117.203(6) or (8) of this title (relating to Exemptions);

(C) stationary gas turbines with a megawatt (MW) rating greater than or equal to 1.0 MW operated more than 850 hours per year; and

(D) fluid catalytic cracking unit boilers using supplemental fuel.

(2) As an alternative to the fuel flow monitoring requirements of this subsection, units operating with a nitrogen oxides (NOx) and diluent continuous emission monitoring system (CEMS) under subsection (e) of this section may monitor stack exhaust flow using the flow monitoring specifications of 40 CFR 75, Appendix A.

(b) Oxygen (O2) monitors.

(1) The owner or operator shall install, calibrate, maintain, and operate an O2 monitor to measure exhaust O2 concentration on the following units operated with an annual heat input greater than 2.2(1011) Btu per year (Btu/yr):

(A) boilers with a rated heat input greater than or equal to 100 MMBtu/hr; and

(B) process heaters with a rated heat input:

(i) greater than or equal to 100 MMBtu/hr and less than 200 MMBtu/hr; and

(ii) greater than or equal to 200 MMBtu/hr, except as provided in subsection (f) of this section.

(2) The following are not subject to this subsection:

(A) units listed in § 117.205(h)(3)-(5) of this title (relating to Emission Specifications);

(B) process heaters operating with a carbon dioxide (CO2) CEMS for diluent monitoring under subsection (e) of this section; and

(C) wood-fired boilers.

(3) The O2 monitors required by this subsection are for process monitoring (predictive monitoring inputs, boiler trim, or process control) and are only required to meet the location specifications and quality assurance procedures referenced in subsection (e) of this section if O2 is the monitored diluent under that subsection. However, if new O2 monitors are necessitated as a result of this subsection, the criteria in subsection (e) of this section should be considered the appropriate guidance for the location and calibration of the monitors.

(c) NOx monitors.

(1) The owner or operator of units listed in this paragraph shall install, calibrate, maintain, and operate a CEMS or predictive emissions monitoring system (PEMS) to monitor exhaust NOx. The units are:

(A) boilers with a rated heat input greater than or equal to 250 MMBtu/hr and an annual heat input greater than 2.2(1011) Btu/yr;

(B) process heaters with a rated heat input greater than or equal to 200 MMBtu/hr and an annual heat input greater than 2.2(1011) Btu/yr;

(C) stationary gas turbines with an MW rating greater than or equal to 30 MW operated more than 850 hours per year;

(D) units which use a chemical reagent for reduction of NOx; and

(E) units for which the owner or operator elects to comply with the NOx emission specifications of this division using a pound per MMBtu limit on a 30-day rolling average.

(2) The following are not required to install CEMS or PEMS under this subsection:

(A) units listed in § 117.205(h)(3)-(5) of this title (relating to Emission Specifications); and

(B) units subject to the NOx CEMS requirements of 40 CFR 75.

(d) Carbon monoxide (CO) monitoring. The owner or operator shall monitor CO exhaust emissions from each unit listed in subsection (c)(1) of this section using one or more of the following methods:

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

(A) CEMS in accordance with subsection (e) 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 of the following occur:

(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 any relative accuracy test audit of the NOx and diluent analyzer.

(e) CEMS requirements. The owner or operator of any CEMS used to meet a pollutant monitoring requirement of this section must comply with the following.

(1) The CEMS shall meet the requirements of 40 CFR, Part 60 as follows:

(A) Section 60.13;

(B) Appendix B:

(i) Performance Specification 2, for NOx;

(ii) Performance Specification 3, for diluent; and

(iii) Performance Specification 4, for CO, for owners or operators electing to use a CO CEMS; and

(C) After the final compliance date, audits in accordance with Section 5.1 of Appendix F, quality assurance procedures, except that a cylinder gas audit or relative accuracy audit may be performed in lieu of the annual relative accuracy test audit (RATA) required in Section 5.1.1.

(2) Monitor diluent, either O2 or CO2.

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

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

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

(4) The CEMS shall be subject to the approval of the executive director.

(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.

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

(2) Monitor diluent, either O2 or CO2:

(A) using a CEMS

(i) in accordance with subsection (e)(1)(B)(ii) of this section; or

(ii) with a similar alternative method approved by the executive director and EPA; or

(B) using a PEMS.

(3) Any PEMS shall meet the requirements of 40 CFR 75, Subpart E, except as provided in paragraphs (4)-(5) of this subsection.

(4) The owner or operator may vary from 40 CFR 75, Subpart E if the owner or operator:

(A) demonstrates to the satisfaction of the executive director and EPA that the alternative is substantially equivalent to the requirements of 40 CFR 75, Subpart E; or

(B) demonstrates to the satisfaction of the executive director that the requirement is not applicable.

(5) The owner or operator may substitute the following as an alternative to the test procedure of Subpart E for any unit:

(A) perform the following alternative initial certification tests:

(i) conduct initial RATA at low, medium, and high levels of the key operating parameter affecting NOx using 40 CFR Part 60, Appendix B:

(I) Performance Specification 2, subsection 4.3 (pertaining to NOx);

(II) Performance Specification 3, subsection 2.3 (pertaining to O2 or CO2); and

(III) Performance Specification 4, subsection 2.3 (pertaining to CO), for owners or operators electing to use a CO PEMS; and

(ii) conduct an F-test, a t-test, and a correlation analysis using 40 CFR 75, Subpart E at low, medium, and high levels of the key operating parameter affecting NOx.

(I) Calculations shall be based on a minimum of 30 successive emission data points at each tested level which are either 15-minute, 20-minute, or hourly averages.

(II) The F-test shall be performed separately at each tested level.

(III) The t-test and the correlation analysis shall be performed using all data collected at the three tested levels;

(B) further demonstrate PEMS accuracy and precision for at least one unit of a category of equipment by performing RATA and statistical testing in accordance with subparagraph (A) of this paragraph for each of three successive quarters, beginning:

(i) no sooner than the quarter immediately following initial certification; and

(ii) no later than the first quarter following the final compliance date; and

(C) after the final compliance date, perform RATA for each unit:

(i) at normal load operations;

(ii) using the Performance Specifications of paragraph (5)(A)(i)(I)-(III) of this subsection; and

(iii) at the following frequency:

(I) semiannually; or

(II) annually, if following the first semiannual RATA, the relative accuracy during the previous audit for each compound monitored by PEMS is less than or equal to 7.5 % of the mean value of the reference method test data at normal load operation; or alternatively,

(-a-) for diluent, is no greater than 1.0 % O2 or CO2, for diluent measured by reference method at less than 5% by volume; or

(-b-) for CO, is no greater than 5 parts per million by volume.

(6) The owner or operator shall, for each alternative fuel fired in a unit, certify the PEMS in accordance with paragraph (5)(A) of this subsection unless the alternative fuel effects on NOx, CO, and O2 (or CO2) emissions were addressed in the model training process.

(7) The PEMS shall be subject to the approval of the executive director.

(g) Engine monitoring. The owner or operator of any stationary gas engine subject to the emission specifications of this division shall stack test engine NOx and CO emissions as follows.

(1) Use the methods specified in § 117.211(e) of this title (relating to Initial Demonstration of Compliance).

(2) Sample:

(A) on a biennial calendar basis; or

(B) within 15,000 hours of engine operation after the previous emission test, under the following conditions:

(i) install and operate an elapsed operating time meter; and

(ii) submit, in writing, to the executive director and any local air pollution agency having jurisdiction, biennially after the initial demonstration of compliance:

(I) documentation of the actual recorded hours of engine operation since the previous emission test; and

(II) an estimate of the date of the next required sampling.

(h) Monitoring for gas turbines less than 30 MW. The owner or operator of any stationary gas turbine rated less than 30 MW using steam or water injection to comply with the emission specifications of § 117.205 or § 117.207 of this title (relating to Alternative Plant-wide Emission Specifications) shall either:

(1) install, calibrate, maintain, and operate a NOx CEMS or PEMS in compliance with this section and monitor CO in compliance with subsection (d) of this section; or

(2) install, calibrate, maintain, and operate a continuous monitoring system to monitor and record the average hourly fuel and steam or water consumption.

(A) The system shall be accurate to within ñ 5.0%.

(B) 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 § 117.205 or § 117.207 of this title.

(C) Steam or water injection control algorithms are subject to executive director approval.

(i) Run time meters. The owner or operator of any stationary gas turbine or stationary internal combustion engine claimed exempt using the 850 hours per year exemption of § 117.203(6)(B) of this title shall record the operating time with an elapsed run time meter.

(j) Hydrogen (H2) monitoring. The owner or operator claiming the H2 multiplier of § 117.205(b)(6), § 117.207(g)(4), or (h) of this title shall sample, analyze, and record every three hours the fuel gas composition to determine the volume percent H2.

(1) The total H2 volume flow in all gaseous fuel streams to the unit will be divided by the total gaseous volume flow to determine the volume percent of H2 in the fuel supply to the unit.

(2) Fuel gas analysis shall be tested according to American Society of Testing and Materials (ASTM) Method D1945-81 or ASTM Method D2650-83, or other methods which are demonstrated to the satisfaction of the executive director and the EPA to be equivalent.

(3) A gaseous fuel stream containing 99% H2 by volume or greater may use the following procedure to be exempted from the sampling and analysis requirements of this subsection.

(A) A fuel gas analysis shall be performed initially using one of the test methods in this subsection to demonstrate that the gaseous fuel stream is 99% H2 by volume or greater.

(B) The process flow diagram of the process unit which is the source of the H2 shall be supplied to the executive director to illustrate the source and supply of the hydrogen stream.

(C) The owner or operator shall certify that the gaseous fuel stream containing H2 will continuously remain, as a minimum, at 99% H2 by volume or greater during its use as a fuel to the combustion unit.

(k) Data used for compliance. After the initial demonstration of compliance required by § 117.211 of this title, the methods required in this section shall be used to determine compliance with the emission specifications of this division. For enforcement purposes, the executive director may also use other commission compliance methods to determine whether the source is in compliance with applicable emission limitations.

(l) Enforcement of NOx limits. If compliance with § 117.205 of this title is selected, no unit subject to § 117.205 of this title shall be operated at an emission rate higher than that allowed by the emission specifications of § 117.205 of this title. If compliance with § 117.207 of this title is selected, no unit subject to § 117.207 of this title shall be operated at an emission rate higher than that approved by the executive director pursuant to § 117.215(b) of this title (relating to Final Control Plan Procedures).

(m) 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 exemption of § 117.205(h)(2) of this title (relating to Definitions), shall notify the executive director within seven days if the Btu/yr or hour- per-year limit specified in § 117.10 of this title, as appropriate, is exceeded.

(1) If the limit is exceeded, the exemption from the emission specifications of § 117.205 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.

117.215 Final Control Plan Procedures

(a) The owner or operator of units listed in § 117.201 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 (relating to Commercial, Institutional, and Industrial Sources). The report must include a list of the units listed in § 117.201 of this title, showing:

(1) the NOx emission specification resulting from application of § 117.205 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) § 117.205 of this title;

(B) § 117.207 of this title (relating to Alternative Plant-wide Emission Specifications);

(C) § 117.221 of this title (relating to Alternative Case Specific Specifications);

(D) § 117.223 (relating to Source Cap); or

(E) § 117.570 (relating to Trading);

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

(4) the emissions measured by testing required in § 117.211 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 § 117.211 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, for:

(A) boilers and heaters with a maximum rated capacity greater than or equal to 100.0 million Btu per hour;

(B) gas turbines with a megawatt (MW) rating greater than or equal to 10 MW; and

(C) gas-fired internal combustion engines rated greater than or equal to:

(i) 150 horsepower (hp) in the Houston/Galveston ozone nonattainment area; and

(ii) 300 hp in the Beaumont/Port Arthur or Dallas/Fort Worth ozone nonattainment area.

(b) For sources complying with § 117.207 of this title, in addition to the requirements of subsection (a) of this section, the owner or operator shall:

(1) assign to each affected:

(A) boiler or process heater, the maximum allowable NOx emission rate in pound per million (MM) Btu (rolling 30-day average), or in pounds per hour (block one-hour average) indicating whether the fuel is gas, high-hydrogen gas, solid, or liquid;

(B) stationary gas turbine, the maximum allowable NOx emission in parts per million by volume at 15% oxygen, dry basis on a block one-hour average; and

(C) stationary internal combustion engine, the maximum allowable NOx emission rate in grams per horsepower-hour on a block one-hour average;

(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 plant-wide average in accordance with § 117.207(g) of this title; and

(4) maintain a copy of the approved list of emission limits for verification of continued compliance with the requirements of § 117.207 of this title.

(c) For sources complying with § 117.223 of this title (relating to Source Cap), in addition to the requirements of subsection (a) of this section, the owner or operator shall submit:

(1) the calculations used to calculate the 30-day average and maximum daily source cap allowable emission rates; and

(2) a list containing, for each unit in the cap:

(A) the historical average daily heat input information Hi;

(B) the maximum daily heat input, Hmi;

(C) the applicable restriction, Ri;

(D) the method of monitoring emissions; and

(3) an explanation of the basis of the values of Hi, Hmi, and Ri; and

(4) the information applicable to shutdown units, specified in § 117.223(g) and (h) of this title.

(d) 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.

(e) The report must be submitted by the applicable date specified for final control plans in § 117.520 of this title (relating to Compliance Schedule for Commercial, Institutional, and Industrial Sources). 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 § 117.520 of this title.

117.217 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 Commercial, Institutional, and Industrial Sources). For sources complying with § 117.205 of this title (relating to Emission Specifications), or § 117.207 of this title (relating to Alternative Plant-wide Emission Specifications), replacement new units may be included in the control plan. For sources complying with § 117.223 of this title (relating to Source Cap), any new unit shall be included in the source cap, if the unit belongs to an equipment category which is included in the source cap. The revision of the final control plan shall be subject to the review and approval of the executive director.

117.219 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, 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 of fuel burned; and the date, time, and duration of the procedure.

(b) Notification. The owner or operator of an affected source shall submit notification to the executive director, as follows:

(1) verbal notification of the date of any initial demonstration of compliance testing conducted under § 117.211 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 system (CEMS) or predictive emissions monitoring system (PEMS) performance evaluation conducted under § 117.213 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 § 117.211 of this title and any CEMS or PEMS relative accuracy test audit (RATA) conducted under § 117.213 of this title:

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

(2) not later than the compliance schedule specified in § 117.520 of this title (relating to Compliance Schedule For Commercial, Institutional, and Industrial Combustion Sources).

(d) Semiannual reports. The owner or operator of a unit required to install a CEMS, PEMS, or water-to-fuel or steam-to-fuel ratio monitoring system under § 117.213 of this title shall report in writing to the executive director on a semiannual basis any exceedance of the applicable emission limitations of this division (relating to Commercial, Institutional, and Industrial Sources) 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, 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.

(A) For gas turbines using steam-to-fuel or water-to-fuel ratio monitoring to demonstrate compliance in accordance with § 117.213(h)(2) of this title, excess emissions are computed as each one-hour period during which the average steam or water injection rate is below the level defined by the control algorithm as necessary to achieve compliance with the applicable emission limitations in § 117.205 of this title (relating to Emission Specifications).

(B) For units complying with § 117.223 of this title (relating to Source Cap), excess emissions are each daily period for which the total nitrogen oxides (NOx) emissions exceed the rolling 30-day average or the maximum daily NOx cap.

(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 water-to-fuel or steam-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, PEMS, or water-to-fuel or steam-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) Reporting for engines. The owner or operator of any rich-burn engine subject to the emission limitations in § 117.205 or § 117.207 of this title (relating to Alternative Plant-wide Emission Specifications) shall report in writing to the executive director on a quarterly basis any excess emissions and the air-fuel ratio 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 (based on the quarterly emission checks of § 117.208(d)(7) of this title (relating to Operating Requirements) and the biennial emission testing required for demonstration of emissions compliance in accordance with § 117.213(g) of this title, computed in pounds per hour and grams per horsepower-hour, any conversion factors used, the date and time of commencement and completion of each time period of excess emissions, and the engine operating time during the reporting period;

(2) specific identification, to the extent feasible, of each period of excess emissions that occurs during start-ups, shutdowns, and malfunctions of the engine or emission control system, the nature and cause of any malfunction (if known), and the corrective action taken or preventative measures adopted.

(f) Recordkeeping. The owner or operator of a unit subject to the requirements of this division shall maintain written or electronic records of the data specified in this subsection. Such records shall be kept for a period of at least five years and shall be made available upon request by authorized representatives of the executive director, EPA, or local air pollution control agencies having jurisdiction. The records shall include:

(1) For each unit using a CEMS or PEMS in accordance with § 117.213 of this title, monitoring records of:

(A) hourly emissions and fuel usage (or stack exhaust flow) for units complying with an emission limit enforced on a block one-hour average; and

(B) daily emissions and fuel usage (or stack exhaust flow) for units complying with an emission limit enforced on a rolling 30-day average. Emissions must be recorded in units of:

(i) pound per million British thermal units (Btu) heat input; and

(ii) pounds or tons per day.

(2) for each internal combustion engine subject to the emission specifications of this division, records of:

(A) emissions measurements required by:

(i) § 117.208(7) of this title (relating to Operating Requirements); and

(ii) § 117.213(g) of this title; and

(B) catalytic converter, air-fuel ratio controller, or other emissions-related control system maintenance, including the date and nature of corrective actions taken.

(3) for each gas turbine monitored by steam-to-fuel or water-to-fuel ratio in accordance with § 117.213(h) of this title, records of hourly:

(A) pounds of steam or water injected;

(B) pounds of fuel consumed; and

(C) the steam-to-fuel or water-to-fuel ratio.

(4) for hydrogen (H2) fuel monitoring in accordance with § 117.213(j) of this title, records of the volume percent H2 every three hours.

(5) for units claimed exempt from the emission specifications of this division using the low annual capacity factor exemption of § 117.205(h)(2), either records of monthly:

(A) fuel usage, for exemptions based on heat input; or

(B) hours of operation, for exemptions based on hours per year of operation.

(6) Records of carbon monoxide measurements specified in § 117.213(d)(2) of this title.

(7) records of 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.

(8) records of the results of performance testing, including initial demonstration of compliance testing conducted in accordance with § 117.211 of this title.

117.221 Alternative Case Specific Specifications

(a) Where a person can demonstrate that an affected unit cannot attain the applicable requirements of § 117.205 of this title (relating to Emission Specifications), the executive director may approve emission specifications different from § 117.205 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 plant-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 Commercial, Institutional, and Industrial Sources).

117.223 Source Cap

(a) An owner or operator may achieve compliance with the nitrogen oxides (NOx) emission limits of § 117.205 of this title (relating to Emission Specifications) by achieving equivalent NOx emission reductions obtained by compliance with a source cap emission limitation in accordance with the requirements of this section. Each equipment category at a source whose individual emission units would otherwise be subject to the NOx emission limits of § 117.205 of this title may be included in the source cap. Any equipment category included in the source cap shall include all emission units belonging to that category. Equipment categories include, but are not limited to, the following: steam generation, electrical generation, and units with the same product outputs, such as ethylene cracking furnaces. All emission units not included in the source cap shall comply with the requirements of § 117.205 or § 117.207 (relating to Alternative Plant-wide Emission Specifications) of this title.

(b) The source cap allowable mass emission rate shall be calculated as follows.

(1) A rolling 30-day average emission cap shall be calculated for all emission units included in the source cap using the following equation:

NOx 30-day rolling average emission cap (lb/day) = (Summation of i=1 to N (Hi X Ri))

Where:

I = each emission unit in the emission cap

N = the total number of emission units in the emission cap

Hi = The actual historical average of the daily heat input for each unit included in the source cap, in million (MM) Btu per day, as certified to the executive director, for a 24 consecutive month period between January 1, 1990 and June 9, 1993, plus one standard deviation of the average daily heat input for that period. All sources included in the source cap shall use the same 24 consecutive month period. If sufficient historical data are not available for this calculation, the executive director may approve another method for calculating Hi.

Ri = (A) For emission units subject to the federal New Source Review (NSR) requirements of 40 Code of Federal Regulations (CFR) 51.165(a), 40 CFR 51.166, or 40 CFR 52.21, or to the requirements of Chapter 116 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification) which implements these federal requirements, or emission units that have been subject to a New Source Performance Standard requirement of 40 CFR 60 prior to June 9, 1993, Ri is the lowest of the actual emission rate or all applicable federally enforceable emission limitations as of June 9, 1993, in pounds (lb) NOx per MMBtu, that apply to emission unit I in the absence of trading. All calculations of emission rates shall presume that emission controls in effect on June 9, 1993 are in effect for the two-year period used in calculating the actual heat input.

(B) For all other emission units, Ri is the lowest of the reasonably available control technology (RACT) limit of § 117.205(b)-(d) or § 117.207(f) of this title or the best available control technology limit for any unit subject to a permit issued pursuant to Chapter 116 of this title, in lb NOx/MMBtu, that applies to emission unit I in the absence of trading.

(2) A maximum daily cap shall be calculated for all emission units included in the source cap using the following equation:

NOx maximum daily cap (lb/day) = (Summation of i=1 to N (Hmi X Ri))

Where:

I, N, and Ri are defined as in paragraph (1) of this subsection.

Hmi = The maximum daily heat input, as certified to the executive director, allowed or possible (whichever is lower) in a 24-hour period.

(3) Each emission unit included in the source cap shall be subject to the requirements of both paragraphs (1) and (2) of this subsection at all times.

(4) The owner or operator at its option may include any of the entire classes of exempted units listed in § 117.207(f) of this title in a source cap. Such units shall be required to reduce emissions available for use in the cap by an additional amount calculated in accordance with the United States Environmental Protection Agency's proposed Economic Incentive Program rules for offset ratios for trades between RACT and non-RACT sources, as published in the February 23, 1993, Federal Register (58 FR 11110).

(5) For stationary internal combustion engines, the source cap allowable emission rate shall be calculated in lbs per hour using the procedures specified in § 117.207(g)(2) of this title.

(6) For stationary gas turbines, the source cap allowable emission rate shall be calculated in lbs per hour using the procedures specified in § 117.207(g)(3) of this title.

(c) The owner or operator who elects to comply with this section shall:

(1) for each unit included in the source cap, either:

(A) install, calibrate, maintain, and operate a continuous exhaust NOx monitor, carbon monoxide (CO) monitor, an oxygen (O2) (or carbon dioxide (CO2)) diluent monitor, and a totalizing fuel flow meter in accordance with the requirements of § 117.213 of this title (relating to Continuous Demonstration of Compliance). The required continuous emissions monitoring systems (CEMS) and fuel flow meters shall be used to measure NOx, CO, and O2 (or CO2) emissions and fuel use for each affected unit and shall be used to demonstrate continuous compliance with the source cap;

(B) install, calibrate, maintain, and operate a predictive emissions monitoring system (PEMS) and a totalizing fuel flow meter in accordance with the requirements of § 117.213 of this title. 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 source cap; or

(C) for units not subject to continuous monitoring requirements and units belonging to the equipment classes listed in § 117.207(f) of this title, the owner or operator may use the maximum emission rate as measured by hourly emission rate testing conducted in accordance with § 117.211(e) of this title (relating to Initial Demonstration of Compliance) in lieu of CEMS or PEMS. Emission rates for these units shall be limited to the maximum emission rates obtained from testing conducted under § 117.211(e) of this title.

(2) For each operating unit equipped with CEMS, the owner or operator shall either use a PEMS pursuant to § 117.213 of this title, or the maximum emission rate as measured by hourly emission rate testing conducted in accordance with § 117.211(e) of this title, to provide emissions compliance data during periods when the CEMS is off-line. The methods specified in 40 CFR 75.46 shall be used to provide emissions substitution data for units equipped with PEMS.

(d) The owner or operator of any units subject to a source cap shall maintain daily records indicating the NOx emissions from each source and the total fuel usage for each unit and include a total NOx emissions summation and total fuel usage for all units under the source cap on a daily basis. Records shall also be retained in accordance with § 117.219 of this title (relating to Notification, Record keeping, and Reporting Requirements).

(e) The owner or operator of any units operating under this provision shall report any exceedance of the source cap emission limit within 48 hours to the appropriate regional office. The owner or operator shall then follow up within 21 days of the exceedance with a written report which includes an analysis of the cause for the exceedance with appropriate data to demonstrate the amount of emissions in excess of the applicable limit and the necessary corrective actions taken by the company to assure future compliance. Additionally, the owner or operator shall submit semiannual reports for the monitoring systems in accordance with § 117.219 of this title.

(f) The owner or operator shall demonstrate initial compliance with the source cap in accordance with the schedule specified in § 117.520 of this title (relating to Compliance Schedule for Commercial, Institutional, and Industrial Combustion Sources).

(g) A unit which has operated since November 15, 1990, and has since been permanently retired or decommissioned and rendered inoperable prior to June 9, 1993, may be included in the source cap emission limit under the following conditions.

(1) the unit shall have actually operated since November 15, 1990;

(2) for purposes of calculating the source cap emission limit, the applicable emission limit for retired units shall be calculated in accordance with subsection (b) of this section;

(3) The actual heat input shall be calculated according to subsection (b)(1) of this section. If the unit was not in service 24 consecutive months between January 1, 1990, and June 9, 1993, the actual heat input shall be the average daily heat input for the continuous time period that the unit was in service, plus one standard deviation of the average daily heat input for that period. The maximum heat input shall be the maximum heat input, as certified to the executive director, allowed or possible (whichever is lower) in a 24-hour period.

(4) the owner or operator shall certify the unit's operational level and maximum rated capacity; and

(5) emission reductions from shutdowns or curtailments which have not been used for netting or offset purposes under the requirements of Chapter 116 of this title or have not resulted from any other state or federal requirement may be included in the baseline for establishing the cap.

(6) Shutdowns which occurred before September 10, 1993, may not be used for compliance with the lean-burn engine specification of § 117.205(e) of this title.

(h) A unit which has been shut down and rendered inoperable after June 9, 1993, but not permanently retired, should be identified in the initial control plan and may be included in the source cap to comply with the NOx emission specifications of this division:

(1) applicable in the Houston/Galveston or Beaumont/Port Arthur ozone nonattainment areas, required by November 15, 1999; or

(2) applicable in the Dallas/Fort Worth ozone nonattainment area, required by March 31, 2001.

(i) An owner or operator who chooses to use the source cap option shall include in the initial control plan, if required to be filed under § 117.209 of this title (relating to Initial Control Plan Procedures), a plan for initial compliance. The owner or operator shall include in the initial control plan the identification of the election to use the source cap procedure as specified in this section to achieve compliance with this section and shall specifically identify all sources that will be included in the source cap. The owner or operator shall also include in the initial control plan the method of calculating the actual heat input for each unit included in the source cap, as specified in subsection (b)(1) of this section. An owner or operator who chooses to use the source cap option shall include in the final control plan procedures of § 117.215 of this title (relating to Final Control Plan Procedures) the information necessary under this section to demonstrate initial compliance with the source cap.

(j) For the purposes of determining compliance with the source cap emission limit, the contribution of each affected unit that is operating during a startup, shutdown, or upset period shall be calculated from the NOx emission rate, as measured by the initial demonstration of compliance, for that unit, unless the owner or operator provides data demonstrating to the satisfaction of the executive director that actual emissions were less than maximum emissions during such periods.

(k) The modified requirements of this subsection are necessary for an owner or operator to use the source cap requirements of this section to achieve compliance with the lean-burn engine NOx emission specification of § 117.205(e) of this title.

(1) In subsection (b) of this section, the dates are modified in the definitions as follows:

(A) Hi, the actual historical average daily heat input, the time period between January 1, 1997, and December 31, 1999, replaces the time period between January 1, 1990, and June 9, 1993; and

(B) Ri, December 31, 1999, replaces June 9, 1993, throughout.

(2) In subsection (g) of this section, the dates are modified as follows:

(A) September 10, 1993, replaces November 15, 1990, throughout;

(B) December 31, 1999, replaces June 9, 1993, throughout; and

(C) January 1, 1997, replaces January 1, 1990.

(3) The actual heat input identified in subsection (g)(3) of this section must be consistent with the heat input used to represent the unit's emissions in the attainment demonstration modeling inventory.

(4) A source which used a source cap to comply with the NOx emission specifications of this division required by November 15, 1999, must either:

(A) maintain a separate source cap for the lean-burn engines; or

(B) revise an existing source cap to include the lean-burn engines, recalculating the allowable mass emission rates for all units in the cap based on the conditions in paragraphs (1)-(3) of this subsection.


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