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You are here: Home / Permitting / Air Permits / PermitByRule / Historical Rules / old117 / 693 / Outdated Title 30 TAC 117.201 - 221 Subchapter B, June 9, 1993

Outdated Title 30 TAC 117.201 - 221 Subchapter B, June 9, 1993

Outdated 30 TAC 117 and 31 TAC 117 rules, 31 TAC 117 date from 1972 and the rule changed to 30 TAC 117 in September 1993

Subchapter B Combustion at Existing Major Sources -- 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

117.201 Applicability

The provisions of this undesignated head (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 Houston/Galveston or Beaumont/Port Arthur 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 ozone nonattainment area with a horsepower rating of 300 hp or greater.

117.203 Exemptions

(a) The provisions of § 117.205 of this title (relating to Emission Specifications) or § 117.207 of this title (relating to Alternative Plant-wide Emission Specifications) shall not apply during periods of major upset or maintenance under the requirements of § 101.6 of this title (relating to Notification Requirements for Major Upset), § 101.7 of this title (relating to Notification Requirements for Maintenance), and § 101.11 of this title (relating to Exemptions from Rules and Regulations).

(b) Units exempted from the provisions of this undesignated head (relating to Commercial, Institutional, and Industrial Sources) include the following:

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

(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, sulfur recovery 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;

(B) used as emergency standby gas turbines which are demonstrated to operate less than 850 hours per calendar year, (low annual capacity factor gas turbines) or engines which are demonstrated to operate less than 850 hours per calendar year (low annual capacity factor engines). The owner or operator of any engine or turbine using this exemption shall record the operating time with an elapsed run time meter; or

(C) used as peaking gas turbines or engines and operated less than 850 hours per calendar year. The owner or operator of any engine or turbine using this exemption shall record the operating time with instrumentation approved by the executive director. The owner or operator of any stationary gas turbine or engine exempt under this exemption must notify the executive director within seven days if the hour per year limit is exceeded. If the hour per year limit is exceeded, the exemption shall be permanently withdrawn. Within 90 days after loss of the exemption, the owner or operator must submit a compliance plan detailing a plan to meet the applicable compliance limit as soon as possible but no later than 24 months after exceeding the hour per year limit. Included with this compliance plan, the owner or operator must submit a schedule of increments of progress for the installation of the required control equipment. This schedule shall be subject to the review and approval of the executive director;

(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 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). For units which operate with continuous emission monitors in accordance with § 117.213(b) of this title (relating to Continuous Demonstration of Compliance), the emission limits shall apply as the mass of nitrogen oxides (NOx) emitted per unit of energy input (pound NOx per million (MM) Btu), on a rolling 30-day average period or as the mass of NOx emitted per hour (pounds per hour), on a block one-hour average. For units which do not operate with continuous emission monitors, the emission limits shall apply as the mass of NOx emitted per hour (pounds NOx per hour), on a block one-hour average. The mass of NOx emitted per hour shall be calculated as the product of the unit's maximum rated capacity and its applicable limit (in pound NOx per MMBtu), as follows.

(1) Each commercial, institutional or industrial boiler which is an affected facility as defined by New Source Performance Standards (NSPS) 40 Code of Federal Regulations (CFR), Part 60, Subparts D or Db, shall be limited to the applicable NSPS NOx emission limit, unless the boiler is also subject to a more stringent permit emission limit as identified in paragraph (2) of this subsection, in which case the more stringent emission limit applies.

(2) Each commercial, institutional, or industrial boiler or process heater operating under a permit issued after March 3, 1982, pursuant to Chapter 116 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification) and placed into service prior to November 15, 1992, and subject to a NOx best available control technology review shall be subject to the permitted NOx limitation, as follows:

(A) the limit explicitly stated in pound NOx per 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 no 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) Each commercial, institutional or industrial boiler and process heater with a maximum rated capacity greater than or equal to 100.0 MMBtu/hr of heat input, not subject to paragraphs (1) or (2) of this subsection, shall meet the applicable emission limit, as follows:

(A) gas-fired boilers, as follows:

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

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

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

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

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

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

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

(i) based on air preheat temperature:

(I) process heaters with preheated air less than 200 degrees Fahrenheit of air preheat, 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 of air preheat, 0.13 lb NOx/MMBtu of heat input; or

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

(ii) 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;

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

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

(E) any unit operated with a combination of gaseous, liquid, or wood fuel, a variable emission limit calculated as the heat input weighted average of the applicable emission limits of this paragraph.

(4) 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 1.25 times the appropriate emission limit in this subsection, 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.

(b) 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.

(c) 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 ozone nonattainment area.

(d) No person shall allow the discharge into the atmosphere from any boiler or process heater subject to NOx emission specifications in subsection (a) of this section, CO emissions in excess of 400 ppmv based on a block one-hour average.

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

(f) 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 or process heater as defined in § 117.010 of this title (relating to Definitions);

(3) boilers and industrial furnaces which are regulated as existing facilities by the United States Environmental Protection Agency at 40 Code of Federal Regulations Part 266, Subpart H;

(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; and

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

(g) The NOx emission limits specified in subsections (a)-(c) of this section shall apply at all times except as specified in § 117.203 of this title (relating to Exemptions), § 117.207 of this title (relating to Alternative Plant-Wide Emission Specifications). The CO emission limits specified in subsections (b), (c), and (d) of this section and the ammonia emission limits specified in subsection (e) of this section shall apply at all times, except as specified in § 117.203 of this title.

117.207 Alternative Plant-wide Emission Specifications

(a) An owner or operator may achieve compliance with the emission limits of § 117.205 of this title (relating to Emission Specifications) by achieving equivalent nitrogen oxides (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 § 117.010 of this title (relating to Definitions) and shall establish an enforceable emission limit for each affected unit at the source. For boilers and process heaters which operate with continuous emission monitors in accordance with § 117.213(b) of this title (relating to Continuous Demonstration of Compliance), the emission limits shall apply as the mass of NOx emitted per unit of energy input (pound NOx per million (MM) Btu), on a rolling 30-day average period, or as the mass of NOx emitted per hour (pounds per hour), on a block one-hour average. For units which do not operate with continuous emission monitors, the emission limits shall apply as the mass of NOx emitted per hour (pounds NOx per hour), on a block one-hour average.

(b) Units exempted from emission specifications in accordance with § 117.205(f) of this title are also exempt under this section and shall not be included in the plant-wide emission limit, except as provided in subsection (f) of this section.

(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 average 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 average 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) The owner or operator of exempted units as defined in § 117.205(f) of this title may elect to include one or more of an entire equipment class of exempted units into the alternative plant-wide emission specifications as defined in this section. The equipment classes which may be included in the alternative plant-wide emission specifications as an entire population of units at the major source include the following: fluid catalytic cracking unit carbon monoxide (CO) boilers; lean-burn, gas-fired, stationary, reciprocating internal combustion engines rated 150 hp or greater; boilers, steam generators, or process heaters with a maximum rated capacity of greater than or equal to 40 MMBtu per hour (MMBtu/hr) and less than 100 MMBtu/hr; and stationary gas turbines with a megawatt (MW) rating of greater than or equal to 1.0 MW and less than 10.0 MW. Low annual capacity factor boilers or process heaters and low annual capacity factor gas turbines or engines as defined in § 117.010 of this title and § 117.203(b)(6)(B) of this title are not to be considered as part of that class of equipment. The individual emission limits that are to be used in calculating the alternative plant-wide emission specifications are as follows:

(1) fluid catalytic cracking unit CO boilers, 50% NOx reduction across the inlet of the CO boiler to the outlet of the CO boiler, with the outlet concentration in parts per million by volume converted into a pound (lb) NOx/MMBtu of heat input;

(2) lean-burn, gas-fired, stationary, reciprocating internal combustion engines rated 150 hp or greater, 5.0 grams NOx hp-hr (g NOx/hp-hr) under all operating conditions;

(3) boilers, steam generators, or process heaters with a maximum rated capacity of greater than or equal to 40 MMBtu/hr and less than 100 MMBtu/hr, the emission specifications in § 117.205(a) of this title for the applicable type of unit; and

(4) stationary gas turbines with a MW rating of greater than or equal to 1.0 MW and less than 10.0 MW, 42 ppmv NOx at 15% O2, dry basis.

(g) Solely for the purposes of calculating the plant-wide emission limit, the allowable mass emission rate for each affected unit shall be calculated from the emission specifications of § 117.205 of this title, as follows:

(1) The NOx emission rate (in pounds per hour) for each affected boiler and process heater is the product of its maximum rated capacity and its NOx emission specification of § 117.205 of this title.

(2) The NOx emission rate (in pounds per hour) for each affected stationary internal combustion engine 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(10^6).

(3) The NOx emission 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 MW rating and International Standards Organization (ISO) flow conditions) and (46/28)(10^-6);

Where:

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

NOx (allowable) = the applicable NOx emission specification of § 117.205 of this title (expressed in ppmv NOx at 15% O2, dry basis).

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

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

(4) The NOx emission rate (in pounds per hour) for each affected gas-fired boiler and process heater firing gaseous fuel which contains more than 50% hydrogen (h3) by volume, over an annual basis, in which the fuel gas composition is sampled and analyzed every three hours, may use a multiplier of 1.25 times the product of its maximum rated capacity and its NOx emission specification of § 117.205 of this title. Double application of the h3 content multiplier using this paragraph and § 117.205(a)(4) of this title is not allowed.

(h) The owner or operator of any gas-fired boiler or process heater firing gaseous fuel which contains more than 50% h3 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 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. The total h3 volume in all gaseous fuel streams will be divided by the total gaseous fuel flow volume to determine the volume percent of h3 in the fuel supply.

117.208 Operating Requirements

(a) Except during major upset or maintenance as referenced in § 101.6 of this title (relating to Notification Requirements for Major Upset), § 101.7 of this title (relating to Notification Requirements for Maintenance), and § 101.11 of this title (relating to Exemptions from Rules and Regulations), 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) All units subject to the emission limitations of § 117.205 of this title or § 117.207 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 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 which has units subject to § 117.205 of this title (relating to Emission Specifications) or § 117.207 of this title (relating to Alternative Plant-Wide Emission Specifications) shall submit, for the approval of the executive director, an initial control plan for installation of NOx emissions control equipment to meet the requirements of § 117.205 of this title or § 117.207 of this title. The executive director shall approve the plan if it contains all the information specified in this section. Revisions to the initial control plan shall be submitted with the final control plan. The initial control plan shall be submitted in accordance with the schedule specified in § 117.520 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 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 capacity factor, the facility identification numbers as submitted to the Emissions Inventory Division of the Texas Air Control Board (TACB) and the emission point numbers as listed on the Maximum Allowable Emissions Rate Table of any applicable TACB permit for each unit;

(2) identification of all units subject to the emission specifications of § 117.205 of this title or § 117.207 of this title;

(3) identification of all boilers, process heaters, stationary gas turbines, or engines with a claimed exemption from the emission specifications of § 117.205 of this title 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 or the plant-wide emission limit as specified in § 117.207 of this title to achieve compliance with this rule;

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

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

(7) 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 § 117.205 of this title or § 117.207 of this title. 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;

(8) previous testing documentation for any claimed test waiver as allowed by § 117.211(e) of this title (relating to Initial Demonstration of Compliance); and

(9) results of emission testing using portable analyzers or, as available, performance testing conducted in accordance with § 117.211(f) or (g) of this title for each unit subject to the testing requirements of § 117.211 of this title.

117.211 Initial Demonstration of Compliance

(a) All units which are identified in the control plan required by § 117.209 of this title (relating to Initial Control Plan Procedures) and are subject to the emission limitations of § 117.205 of this title (relating to Emission Specifications) or § 117.207 of this title (relating to Alternative Plant-Wide Emission Specifications), shall be tested for nitrogen oxides (NOx), carbon monoxide (CO), and oxygen (O2) emissions while firing gaseous fuel (and as applicable, hydrogen (h3) fuel for units which may fire more than 50% h3 by volume and liquid fuel). Units which inject urea or ammonia into the exhaust stream for NOx control shall be tested for ammonia emissions. Performance testing of these units shall be performed in accordance with the schedule specified in § 117.520(2) of this title (relating to Compliance Schedule For Commercial, Institutional, and Industrial Combustion Sources).

(b) The performance tests required by subsection (a) of this section shall use the test methods referenced in subsection (f) or (g) of this section and shall be used for determination of initial compliance with either the emission limits of § 117.205 of this title or the assigned emission limits of § 117.207 of this title, as applicable. Test results shall be reported in the units of the applicable emission limits and averaging periods.

(c) The units listed in this subsection shall be tested for NOx, CO and O2 emissions while firing gaseous fuel (and as applicable, h3 fuel for units which may fire more than 50% h3 by volume) and/or liquid fuel at the maximum rated capacity or as near thereto as practicable. Testing using portable analyzers is acceptable for the units listed in this subsection. The testing shall be performed in accordance with the schedule specified in § 117.520(1) of this title. The units listed are as follows:

(1) process heaters and boilers with a maximum rated capacity greater than or equal to 40.0 million Btu per hour (MMBtu/hr) and less than 100.0 MMBtu/hr, except for low annual capacity factor boilers and process heaters as defined in § 117.010 of this title (relating to Definitions);

(2) boilers and industrial furnaces with a maximum rated capacity greater than or equal to 40.0 MMBtu/hr which are regulated as existing facilities by the US EPA at 40 Code of Federal Regulations (CFR), Part 266, Subpart H, except for low annual capacity factor boilers and process heaters as defined in § 1170.01 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 § 117.010 of this title.

(5) stationary gas turbines with a megawatt (MW) rating of greater than or equal to 1.0 MW and less than 10.0 MW, except for low annual capacity factor gas turbines as defined in § 117.203(b)(6)(B) of this title (relating to Exemptions) or peaking gas turbines as defined in § 117.203(b)(6)(C) of this title; and

(6) lean burn, 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 as defined in § 117.203(b)(6)(B) of this title or peaking engines as defined in § 117.203(b)(6)(C) of this title.

(d) Any continuous emissions monitoring system (CEMS) required by § 117.213(b) of this title (relating to Continuous Demonstration of Compliance) shall be installed and operational prior to conducting performance testing under subsection (a) of this section. Verification of operational status shall, as a minimum, include completion of the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device.

(e) Testing conducted prior to the effective date of this rule may be used to demonstrate compliance with the standards specified in § 117.205 of this title or § 117.207 of this title or to satisfy the additional testing requirements of subsection (c) of this section, if the owner or operator of an affected facility demonstrates to the executive director that the prior performance testing at least meets the requirements of subsections (a), (b), (c), (f), and (g) of this section. The executive director reserves the right to request performance testing or CEMS performance evaluation at any time.

(f) Compliance with the emission specifications of § 117.205 of this title or § 117.207 of this title for units operating without CEMS shall be demonstrated while operating at the maximum rated capacity, or as near thereto as practicable, by application of 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 or 19 (40 CFR 60, Appendix A) for exhaust gas flow; and

(5) American Society of Testing and Materials (ASTM) Method D1945-91, ASTM Method D-3588-81 or ASTM Method D-2650-83 for fuel composition; or

(6) EPA-approved alternate test methods or minor modifications to these test methods as approved by the executive director

(f) Initial compliance with the emission specifications of § 117.205 of this title or § 117.207 of this title for units operating with CEMS in accordance with § 117.213(b) of this title shall be demonstrated using the CEMS as follows.

(1) For units complying with a NOx emission limit in pound per million Btu 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 in pounds per hour block one-hour average, any one-hour period after CEMS certification testing required in § 117.213(b) of this title is used to determine compliance with the NOx emission limit.

(3) For units complying with a CO emission limit, block one-hour average, any one-hour period after CEMS certification testing required in § 117.213(b) of this title is used to determine compliance with the CO emission limit.

(h) Testing with portable analyzers may be used to satisfy the emission test requirements for units listed in subsection (c) of this section and for providing initial compliance plan information for all units which are subject to emission limits. This information shall be provided in accordance with the schedule specified for submission of the initial control plan in § 117.520 of this title.

117.213 Continuous Demonstration of Compliance

(a) The owner or operator of units listed in this subsection and subject to the provisions of this undesignated head (relating to Commercial, Institutional, and Industrial Sources) shall install, calibrate, maintain, and operate an oxygen (O2) monitor to measure exhaust O2 concentration and a totalizing fuel flow meter to measure the fuel usage. The O2 monitors and totalizing fuel flow meters shall be installed by the time of compliance with the emission limits specified in § 117.205 of this title (relating to Emission Specifications) or § 117.207 of this title (relating to Alternative Plant-wide Emission Specifications) for the following units:

(1) each commercial, institutional, and industrial boiler with a rated heat input greater than or equal to 100 million Btu per hour (MMBtu/hr) and less than 250 MMBtu/hr and an annual heat input greater than 2.2(10^11) Btu per year (Btu/yr); and

(2) each process heater with a rated heat input greater than or equal to 100 MMBtu/hr and less than 200 MMBtu/hr and an annual heat input greater than 2.2(10^11) Btu/yr.

(b) The owner or operator of units listed in this subsection and subject to the provisions of this undesignated head shall install, calibrate, maintain, and operate a continuous exhaust nitrogen oxides (NOx) monitor, a carbon monoxide (CO) monitor, an O2 (or carbon dioxide (CO2)) diluent monitor, and a totalizing fuel flow meter. The required continuous emissions monitoring systems (CEMS) will be used to measure NOx, CO, and O2 emissions for each affected unit. One CEMS may be used to monitor up to three units. Any CEMS shall meet all the requirements of 40 Code of Federal Regulations (CFR), Part 60, § 60.13; 40 CFR 60, Appendix B, Performance Specifications 2 and 3; and quality assurance procedures of 40 CFR 60, Appendix F, Procedure 1, Section 5.1.2, except that a cylinder gas audit may be performed in lieu of the annual relative accuracy test audit required in Section 5.1.2. The CEMS shall be subject to the approval of the executive director under any permit issued pursuant to Title V of the 1990 Federal Clean Air Act Amendments.

(1) The CEMS shall be installed by the time of compliance with the emission limits specified in § 117.205 of this title or § 117.207 of this title for the following units:

(A) each commercial, institutional, and industrial boiler with a rated heat input greater than or equal to 250 MMBtu/hr and an annual heat input greater than 2.2(10^11) Btu/yr;

(B) each process heater with a rated heat input greater than or equal to 200 MMBtu/hr and an annual heat input greater than 2.2(10^11) Btu/yr;

(C) each stationary gas turbine with a megawatt (MW) rating greater than or equal to 30 MW operated more than 850 hours per year;

(D) each unit which uses a chemical reagent for reduction of NOx; and

(E) each unit for which the owner or operator elects to comply with the NOx emission specifications of § 117.205 of this title or § 117.207 of this title using a pound per MMBtu limit on a 30-day rolling average.

(2) The units listed in § 117.205(f)(3)-(5) of this title are not required to install CEMS under this subsection.

(c) In addition to the totalizing fuel flow meters specified in subsections (a) and (b) of this section, the owner or operator shall install and maintain totalizing fuel flow meters on an individual unit basis on the following units:

(1) process heaters and commercial, institutional, and industrial boilers with a rated heat input greater than or equal to 40.0 MMBtu/hr and less than 100.0 MMBtu/hr;

(2) low annual capacity factor boilers and process heaters as defined in § 117.010 of this title (relating to Definitions);

(3) lean-burn, 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; and

(4) stationary gas turbines with a MW rating greater than or equal to 1.0 MW and less than 10.0 MW.

(d) The owner or operator of any stationary gas engine subject to the emission specifications of § 117.205 of this title or § 117.207 of this title shall install and maintain a totalizing fuel flow meter and perform biennial stack testing of engine emissions of NOx and CO, measured in accordance with the methods specified in § 117.211(f) of this title (relating to Initial Demonstration of Compliance). In lieu of performing stack sampling on a biennial calendar basis, an owner or operator may elect to install and operate an elapsed operating time meter and shall test the engine within 15,000 hours of engine operation after the previous emission test. The owner or operator who elects to test on an operating hour schedule shall submit, in writing, to the TACB and any local air pollution agency having jurisdiction, biennially after the initial demonstration of compliance, documentation of the actual recorded hours of engine operation since the previous emission test, and an estimate of the date of the next required sampling.

(e) 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 of this title or § 117.207 of this title shall either:

(1) install, calibrate, maintain, and operate a CEMS in compliance with subsection (b) 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. 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 § 117.205 of this title or § 117.207 of this title.

(f) The owner or operator of any gas-fired boiler or process heater firing gaseous fuel which contains more than 50% hydrogen (h3) by volume, shall sample, analyze, and record every three hours the fuel gas composition to comply with the emission specifications of § 117.205 of this title or § 117.207 of this title. The total h3 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 h3 in the fuel supply to the unit. 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 to be equivalent. A gaseous fuel stream containing 99% h3 by volume or greater may use the following procedure to be exempted from the sampling and analysis requirements of this subsection.

(1) 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% h3 by volume or greater.

(2) The process flow diagram of the process unit which is the source of the h3 shall be supplied to the TACB to illustrate the source and supply of the hydrogen stream.

(3) The owner or operator shall certify that the gaseous fuel stream containing h3 will continuously remain, as a minimum, at 99% h3 by volume or greater during its use as a fuel to the combustion unit.

(g) After the initial demonstration of compliance required by § 117.211 of this title, compliance with either § 117.205 of this title or § 117.207 of this title, as applicable, shall be determined by the methods required in this section. Compliance with the emission limitations may also be determined at teh discretion of the executive director using any TACB compliance method.

(h) 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)(2) of this title (relating to Final Control Plan Procedures).

(i) The owner or operator of any low annual capacity factor boiler or process heater as defined in § 117.010 of this title must notify the executive director within seven days if the Btu/yr limit is exceeded. If the Btu/yr limit is exceeded, the exemption from the emission specifications of § 117.205 (a)(3) of this title shall be permanently withdrawn. Within 30 days after loss of the exemption, the owner or operator must submit a compliance plan detailing a plan to meet the applicable compliance limit as soon as possible, but no later than 24 months after exceeding the Btu/yr limit. Included with this compliance plan, the owner or operator must submit a schedule of increments of progress for the installation of the required control equipment. This schedule shall be subject to the review and approval of the executive director.

117.215 Final Control Plan Procedures

(a) For sources complying with § 117.205 of this title (relating to Emission Specifications), the owner or operator of an affected source shall submit a final control report to show compliance with the requirements of § 117.205 of this title by the date specified in § 117.520(4) of this title (relating to Compliance Schedule For Commercial, Institutional, and Industrial Combustion Sources). The report shall include a list of all affected units showing the method of control of nitrogen oxides (NOx) emissions for each unit and the results of testing required in § 117.211 of this title (relating to Initial Demonstration of Compliance).

(b) For sources complying with § 117.207 of this title (relating to Alternative Plant-wide Emission Specifications), the owner or operator of an affected source shall submit a final control plan to show attainment of the requirements of § 117.207 of this title by the date specified in § 117.520(4) of this title. The owner or operator shall:

(1) assign to each unit 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) while firing gaseous or liquid fuel, which are allowable for that unit under the requirements of § 117.207 of this title;

(2) submit a list to the executive director for approval of the maximum allowable NOx emission rates identified in paragraph (1) of this subsection and maintain a copy of the approved list for verification of continued compliance with the requirements of § 117.207 of this title; and

(3) submit a list summarizing the results of testing of each unit at maximum rated capacity, in accordance with the requirements of § 117.211 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 undesignated head (relating to Commercial, Institutional, and Industrial Sources). New units, including functionally identical replacement units shall not be incorporated into the plan. 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) For units subject to the exemptions allowed under § 117.203(a) of this title (relating to Exemptions), hourly records shall be made of start-up and/or shutdown events and maintained for a period of at least two years. Records shall be available for inspection by the Texas Air Control Board (TACB), United 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; and the date, time, and duration of the procedure.

(b) The owner or operator of an affected source shall submit to the executive director written notification, 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) 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) The owner or operator of an affected unit shall furnish the executive director and any local air pollution control agency having jurisdiction a copy of any performance testing conducted under § 117.211 of this title or any CEMS performance evaluation conducted under § 117.213 of this title, within 60 days after completion of such testing or evaluation. For purposes of demonstrating compliance with § 117.520 of this title (relating to Compliance Schedule For Commercial, Institutional, and Industrial Combustion Sources), such results shall be submitted no later than 30 days before the final compliance date specified in § 117.520 of this title .

(d) The owner or operator of a unit required to install a CEMS 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 quarterly basis any exceedance of the applicable emission limitations in § 117.205 of this title (relating to Emission Specifications) or § 117.207 of this title (relating to Alternative Plant-Wide Emission Specifications) and the monitoring system performance. All reports shall be postmarked or received by the 30th day following the end of each calendar quarter. Written reports shall include the following information:

(1) the magnitude of excess emissions computed in accordance with 40 Code of Federal Regulations, Part 60, § 60.13(h), any conversion factors used, the date and time of commencement and completion of each time period of excess emissions, and the unit operating time during the reporting period. For gas turbines using steam-to-fuel or water-to-fuel ratio monitoring to demonstrate compliance in accordance with § 117.213(e)(2) of this title, excess emissions are computed as each one-hour period during which the hourly steam-to-fuel or water-to-fuel ratio is less than the ratio determined to result in compliance during the initial performance test required by § 117.211 of this title.

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

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

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

(5) if the total duration of excess emissions for the reporting period is less than 1.0% of the total unit operating time for the reporting period and the CEMS or 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 TACB "Guidance for Preparation of Summary, Excess Emission, and Continuous Monitoring System Reports") shall be submitted, unless otherwise requested by the executive director of the TACB. If the total duration of excess emissions for the reporting period is greater than or equal to 1.0% of the total operating time for the reporting period or the CEMS or 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) The owner or operator of any rich-burn engine subject to the emission limitations in § 117.205 of this title or § 117.207 of this title 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 quarter. Written reports shall include the following information:

(1) the magnitude of excess emissions (based on the quarterly emission checks of § 117.208(c)(7) of this title (relating to Operating Requirements) and the biennial emission testing required for demonstration of emissions compliance in accordance with § 117.213(d) 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, catalytic converter, or air-fuel ratio controller, the nature and cause of any malfunction (if known), and the corrective action taken or preventative measures adopted.

(f) The owner or operator of an affected unit shall maintain written records of all continuous emissions monitoring and performance test results, hours of operation, and fuel usage rates. Such records shall be kept for a period of at least two years and shall be made available upon request by authorized representatives of the TACB, EPA, or local air pollution control agencies having jurisdiction. The emission monitoring (as applicable) and fuel usage records for each unit shall be recorded and maintained:

(1) on an hourly basis for units complying with an emission limit enforced on a block one-hour average;

(2) on a daily basis for units complying with an emission limit enforced on a rolling 30-day basis; and

(3) on a monthly basis for units exempt from the emission specifications based on annual heat input or hours of operation per calendar year.

117.221 Alternative Case Specific Specifications

Where a person can demonstrate that an affected unit cannot attain the requirements of § 117.205 of this title (relating to Emission Specifications), as applicable, the executive director, on a case-by-case basis after considering the technological and economic circumstances of the individual unit, may approve emission specifications different from § 117.205 of this title for that unit based on the determination that such specifications are the result of the lowest emission limitation the unit is capable of meeting after the application of reasonably available control technology. In determining whether to approve alternative emission specifications, the executive director may take into consideration the ability of the plant at which the unit is located to meet emission specifications through plant-wide averaging at maximum capacity. Any person affected by the decision of the executive director may appeal to the board by filing written notice of appeal with the executive director within 30 days after the decision. Such appeal is to be taken by written notification to the executive director. Section 103.71 of this title (relating to Request for Action by the Board) should be consulted for the method of requesting board action on the appeal. Executive director approval does not necessarily constitute satisfaction of all federal requirements nor eliminate the need for approval by the United States Environmental Protection Agency in cases where specified criteria for determining equivalency have not been clearly identified in applicable sections of this undesignated head (relating to Commercial, Institutional, and Industrial Sources).


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