Section 117.340 - 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, with an accuracy of ± 5%, to individually and continuously measure the gas and liquid fuel usage. A computer that collects, sums, and stores electronic data from continuous fuel flow meters is an acceptable totalizer. The owner or operator of units with totalizing fuel flow meters installed prior to March 31, 2005, that do not meet the accuracy requirements of this subsection shall either recertify or replace existing meters to meet the ± 5% accuracy required as soon as practicable but no later than March 31, 2007. For the purpose of compliance with this subsection for units having pilot fuel supplied by a separate fuel system or from an unmonitored portion of the same fuel system, the fuel flow to pilots may be calculated using the manufacturer's design flow rates rather than measured with a fuel flow meter. The calculated pilot fuel flow rate must be added to the monitored fuel flow when fuel flow is totaled. (1) The units are the following: (A) for units that are subject to § 117.305 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)), for stationary gas turbines that are exempt under § 117.303(b)(7) of this title (relating to Exemptions):(i) if individually rated more than 40 million British thermal units per hour (MMBtu/hr):(III) boilers and industrial furnaces that were regulated as existing facilities by 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;(ii) stationary reciprocating internal combustion engines not exempt by §117.303(a)(6), (a)(8), (b)(9), or (b)(10) of this title;(iii) stationary gas turbines with a megawatt (MW) rating greater than or equal to 1.0 MW operated more than 850 hours per year; and(iv) fluid catalytic cracking unit boilers using supplemental fuel; and(B) for units subject to § 117.310 of this title (relating to Emission Specifications for Attainment Demonstration): (i) boilers (excluding wood-fired boilers that must comply by maintaining records of fuel usage as required in § 117.345(f) of this title (relating to Notification, Recordkeeping, and Reporting Requirements) or monitoring in accordance with paragraph (2)(A) of this subsection);(iii) boilers and industrial furnaces that were regulated as existing facilities by 40 CFR Part 266, Subpart H, as was in effect on June 9, 1993;(iv) duct burners used in turbine exhaust ducts;(v) stationary, reciprocating internal combustion engines;(vi) stationary gas turbines;(vii) fluid catalytic cracking unit boilers and furnaces using supplemental fuel;(ix) lightweight aggregate kilns;(x) heat treating furnaces;(xii) magnesium chloride fluidized bed dryers; and(xiii) incinerators (excluding vapor streams resulting from vessel cleaning routed to an incinerator, provided that fuel usage is quantified using good engineering practices, including calculation methods in general use and accepted in new source review permitting in Texas. All other fuel and vapor streams must be monitored in accordance with this subsection.)(2) The following are alternatives to the fuel flow monitoring requirements of paragraph (1) of this subsection. (A) Units operating with a nitrogen oxides (NOX) and diluent continuous emissions monitoring system (CEMS) under subsection (f) of this section may monitor stack exhaust flow using the flow monitoring specifications of 40 CFR Part 60, Appendix B, Performance Specification 6 or 40 CFR Part 75, Appendix A.(B) Units that vent to a common stack with a NOX and diluent CEMS under subsection (f) of this section may use a single totalizing fuel flow meter.(C) Diesel engines operating with run time meters may meet the fuel flow monitoring requirements of this subsection through monthly fuel use records maintained for each engine.(D) Stationary reciprocating internal combustion engines and stationary gas turbines equipped with a continuous monitoring system that continuously monitors horsepower and hours of operation are not required to install totalizing fuel flow meters. The continuous monitoring system must be installed, calibrated, maintained, and operated according to manufacturers' recommended procedures.(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) British thermal units 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 greater than or equal to 100 MMBtu/hr, except as provided in subsection (g) of this section.(2) The following are not subject to this subsection: (A) units listed in §117.303(b)(3) - (5) and (8) - (10) of this title;(B) process heaters operating with a carbon dioxide CEMS for diluent monitoring under subsection (g) of this section; and(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 (f) of this section if O2 is the monitored diluent under that subsection. However, if new O2 monitors are required as a result of this subsection, the criteria in subsection (f) 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 that use a chemical reagent for reduction of NOX;(E) units that the owner or operator elects to comply with the NOX emission specifications of § 117.305 of this title using a pound per MMBtu (lb/MMBtu) limit on a 30-day rolling average;(F) lime kilns and lightweight aggregate kilns;(G) units with a rated heat input greater than or equal to 100 MMBtu/hr that are subject to § 117.310(a) of this title; and(H) fluid catalytic cracking units (including carbon monoxide (CO) boilers, CO furnaces, and catalyst regenerator vents). In addition, the owner or operator shall monitor the stack exhaust flow rate with a flow meter using the flow monitoring specifications of 40 CFR Part 60, Appendix B, Performance Specification 6 or 40 CFR Part 75, Appendix A.(2) The following are not required to install CEMS or PEMS under this subsection:(A) for purposes of § 117.305 of this title, units listed §117.303(b)(3) - (5) and (8) - (10) of this title; and(B) units subject to the NOX CEMS requirements of 40 CFR Part 75.(3) The owner or operator shall use one of the following methods to provide substitute emissions compliance data during periods when the NOX monitor is off-line: (A) if the NOX monitor is a CEMS:(i) subject to 40 CFR Part 75, use the missing data procedures specified in 40 CFR Part 75, Subpart D (Missing Data Substitution Procedures); or(ii) subject to 40 CFR Part 75, Appendix E, use the missing data procedures specified in 40 CFR Part 75, Appendix E, §2.5 (Missing Data Procedures);(B) use 40 CFR Part 75, Appendix E monitoring in accordance with § 117.1240(e) of this title (relating to Continuous Demonstration of Compliance);(C) if the NOX monitor is a PEMS:(i) use the methods specified in 40 CFR Part 75, Subpart D; or(ii) use calculations in accordance with § 117.8110(b) of this title (relating to Emission Monitoring System Requirements for Utility Electric Generation Sources); or(D) use the maximum block one-hour emission rate as measured during the initial demonstration of compliance required in § 117.335(f) of this title (relating to Initial Demonstration of Compliance); or(E) use the following procedures: (i) for NOX monitor downtime periods less than 24 consecutive hours, use the maximum block one-hour NOX emission rate, in lb/MMBtu, from the previous 24 operational hours of the unit;(ii) for NOX monitor downtime periods equal to or greater than 24 consecutive hours, use the maximum block one-hour NOX emission rate, in lb/MMBtu, from the previous 720 operational hours of the unit; and(iii) if the fuel flow or stack exhaust flow monitor required by subsection (a) of this section is off-line simultaneous with the NOX monitor downtime, the owner or operator shall use the maximum block one-hour NO X pound per hour emission rate for the substitute data under clause (i) or (ii) of this subparagraph in lieu of the lb/MMBtu emission rate.(d) Ammonia monitoring requirements. The owner or operator of units that are subject to the ammonia emission specifications of § 117.310(c)(2) of this title shall comply with the ammonia monitoring requirements of § 117.8130 of this title (relating to Ammonia Monitoring).(e) 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 methods specified in § 117.8120 of this title (relating to Carbon Monoxide (CO) Monitoring).(f) CEMS requirements. The owner or operator of any CEMS used to meet a pollutant monitoring requirement of this section shall comply with the following.(1) The CEMS must meet the requirements of § 117.8100(a) of this title (relating to Emission Monitoring System Requirements for Industrial, Commercial, and Institutional Sources).(2) For units subject to § 117.310 of this title: (A) all bypass stacks must be monitored, in order to quantify emissions directed through the bypass stack: (i) if the CEMS is located upstream of the bypass stack, then:(I) no effluent streams from other potential sources of NOX emissions may be introduced between the CEMS and the bypass stack; and(II) the owner or operator shall install, operate, and maintain a continuous monitoring system to automatically record the date, time, and duration of each event when the bypass stack is open; and(ii) process knowledge and engineering calculations may be used to determine volumetric flow rate for purposes of calculating mass emissions for each event when the bypass stack is open, provided that:(I) the maximum potential calculated flow rate is used for emission calculations; and(II) the owner or operator maintains, and makes available upon request by the executive director, records of all process information and calculations used for this determination; and(B) exhaust streams of units that vent to a common stack do not need to be analyzed separately.(g) PEMS requirements. The owner or operator of any PEMS used to meet a pollutant monitoring requirement of this section shall comply with the following.(1) The PEMS must predict the pollutant emissions in the units of the applicable emission specifications of this division (relating to Houston-Galveston-Brazoria Ozone Nonattainment Area Major Sources).(2) The PEMS must meet the requirements of § 117.8100(b) of this title.(h) Engine monitoring. The owner or operator of any stationary gas engine subject to § 117.305 of this title that is not equipped with NOX CEMS or PEMS shall stack test engine NOX and CO emissions as specified in § 117.8140(a) of this title (relating to Emission Monitoring for Engines). The owner or operator of any stationary internal combustion engine subject to § 117.310 of this title that is not equipped with NOX CEMS or PEMS shall stack test engine NOX and CO emissions as specified in § 117.8140(a) and (b) of this title.(i) Monitoring for stationary 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 § 117.305 or § 117.315 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT) and 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 (e) 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 must be accurate to within ± 5.0%;(B) the steam-to-fuel or water-to-fuel ratio monitoring data must constitute the method for demonstrating continuous compliance with the applicable emission specification of § 117.305 or § 117.315 of this title; and(C) steam or water injection control algorithms are subject to executive director approval.(j) Run time meters. The owner or operator of any stationary gas turbine or stationary internal combustion engine claimed exempt using the exemption of §117.303(a)(6)(D), (a)(10), (a)(11), (b)(2) or (b)(9) of this title shall record the operating time with an elapsed run time meter. Any run time meter installed on or after October 1, 2001, must be non-resettable.(k) Hydrogen (H2) monitoring. The owner or operator claiming the H2 multiplier of §117.305(b)(6) or § 117.315(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 must 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 must be tested according to American Society for Testing and Materials (ASTM) Method D1945-81 or ASTM Method D2650-83, or other methods that are demonstrated to the satisfaction of the executive director and the United States Environmental Protection Agency 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 must 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 that is the source of the H2 must 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.(l) Data used for compliance. (1) After the initial demonstration of compliance required by § 117.335 of this title, the methods required in this section must be used to determine compliance with the emission specifications of § 117.305 of this title. 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.(2) For units subject to § 117.310(a) of this title, the methods required in this section must be used in conjunction with the requirements of Chapter 101, Subchapter H, Division 3 of this title (relating to Mass Emissions Cap and Trade Program) to determine compliance. 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.(m) Enforcement of NOX RACT limits. If compliance with § 117.305 of this title is selected, no unit subject to § 117.305 of this title may be operated at an emission rate higher than that allowed by the emission specifications of § 117.305 of this title. If compliance with § 117.315 of this title is selected, no unit subject to § 117.315 of this title may be operated at an emission rate higher than that approved by the executive director under § 117.352(b) of this title (relating to Final Control Plan Procedures for Reasonably Available Control Technology).(n) Loss of NOX RACT 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 § 117.303(b)(2) of this title shall notify the executive director within seven days if the Btu/yr or hour-per-year limit specified in § 117.10 of this title (relating to Definitions), as appropriate, is exceeded. (1) If the limit is exceeded, the exemption from the emission specifications of this division is 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 must include a schedule of increments of progress for the installation of the required control equipment.(3) The schedule is subject to the review and approval of the executive director.(o) Testing and operating requirements. The owner or operator of units that are subject to § 117.310(a) of this title shall comply with the following. (1) The owner or operator of units that are subject to § 117.310(a) of this title shall test the units as specified in § 117.335 of this title in accordance with the schedule specified in § 117.9020(2) of this title (relating to Compliance Schedule for Houston-Galveston-Brazoria Ozone Nonattainment Area Major Sources).(2) Each stationary internal combustion engine controlled with nonselective catalytic reduction must be equipped with an automatic air-fuel ratio (AFR) controller that operates on exhaust O2 or CO control and maintains AFR in the range required to meet the engine's applicable emission limits.(p) Emission allowances. The owner or operator of units that are subject to § 117.310(a) of this title shall comply with the following. (1) The NOX testing and monitoring data of subsections (a), (c), (f), (g), and (o) of this section, together with the level of activity, as defined in § 101.350 of this title (relating to Definitions), must be used to establish the emission factor for calculating actual emissions for compliance with Chapter 101, Subchapter H, Division 3 of this title (relating to Mass Emissions Cap and Trade Program.(2) For units not operating with CEMS or PEMS, the following apply. (A) Retesting as specified in subsection (o)(1) of this section is required within 60 days after any modification that could reasonably be expected to increase the NOX emission rate.(B) Retesting as specified in subsection (o)(1) of this section may be conducted at the discretion of the owner or operator after any modification that could reasonably be expected to decrease the NOX emission rate, including, but not limited to, installation of post-combustion controls, low-NOX burners, low excess air operation, staged combustion (for example, overfire air), flue gas recirculation, and fuel-lean and conventional (fuel-rich) reburn.(C) The NOX emission rate determined by the retesting must be used to establish a new emission factor to calculate actual emissions from the date of the retesting forward. Until the date of the retesting, the previously determined emission factor must be used to calculate actual emissions for compliance with Chapter 101, Subchapter H, Division 3 of this title.(D) All test reports must be submitted to the executive director for review and approval within 60 days after completion of the testing.(3) The emission factor in paragraph (1) or (2) of this subsection is multiplied by the unit's level of activity to determine the unit's actual emissions for compliance with Chapter 101, Subchapter H, Division 3 of this title.30 Tex. Admin. Code § 117.340
The provisions of this §117.340 adopted to be effective June 14, 2007, 32 TexReg 3206; amended to be effective March 4, 2009, 34 TexReg 1445