Current through Reg. 50, No. 13; March 28, 2025
(a) Nitrogen oxides (NOX) monitoring. The owner or operator of each unit subject to this division (relating to Houston-Galveston-Brazoria Ozone Nonattainment Area Utility Electric Generation Sources), shall install, calibrate, maintain, and operate a continuous emissions monitoring system (CEMS), predictive emissions monitoring system (PEMS), or other system specified in this section to measure NOX on an individual basis. Each NOX monitor (CEMS or PEMS) is subject to the relative accuracy test audit relative accuracy requirements of 40 Code of Federal Regulations (CFR) Part 75, Appendix B, Figure 2, except the concentration options (parts per million by volume (ppmv) and pounds per million British thermal units) therein do not apply. Each NOX monitor must meet either the relative accuracy percent requirement of 40 CFR Part 75, Appendix B, Figure 2, or an alternative relative accuracy requirement of ± 2.0 ppmv from the reference method mean value.
(b) Carbon monoxide (CO) monitoring. The owner or operator shall monitor CO exhaust emissions from each unit subject to this division using one or more of the methods in §
117.8120 of this title (relating to Carbon Monoxide (CO) Monitoring).
(c) Ammonia monitoring requirements. The owner or operator of units that are subject to the ammonia emission specification in §
117.1210(b)(2) of this title (relating to Emission Specifications for Attainment Demonstration) shall comply with the ammonia monitoring requirements of §
117.8130 of this title (relating to Ammonia Monitoring).
(d) CEMS requirements.
(1) For units subject to §
117.1205 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)), any CEMS required by this section must comply with the requirements of §
117.8110(a) of this title (relating to Emission Monitoring System Requirements for Utility Electric Generation Sources).
(2) The owner or operator of any unit subject to §
117.1210 of this title shall comply with the following:
(A) any CEMS required by this section must comply with the requirements of §
117.8110(a)(1) of this title;
(B) all bypass stacks must be monitored in order to quantify emissions directed through the bypass stack;
(C) one CEMS may be shared among units, provided:
(i) the exhaust stream of each stack is analyzed separately; and
(ii) the CEMS meets the certification requirements of §
117.8110(a)(1) of this title for each stack while the CEMS is operating in the time-shared mode; and
(D) exhaust streams of units that vent to a common stack do not need to be analyzed separately.
(e) Acid rain peaking units. The owner or operator of each peaking unit as defined in 40 CFR §72.2, may:
(1) monitor operating parameters for each unit in accordance with 40 CFR Part 75, Appendix E, §1.1 or §1.2 and calculate NOX emission rates based on those procedures; or
(2) use CEMS or PEMS in accordance with this section to monitor NOX emission rates.
(f) Auxiliary steam boilers. The owner or operator of each auxiliary steam boiler as defined in §
117.10 of this title (relating to Definitions) shall:
(1) install, calibrate, maintain, and operate a CEMS in accordance with this section; or
(2) comply with the appropriate (considering boiler maximum rated capacity and annual heat input) industrial boiler monitoring requirements of §
117.340 of this title (relating to Continuous Demonstration of Compliance).
(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. The required PEMS and fuel flow meters must be used to demonstrate continuous compliance with the requirements of this division.
(1) The PEMS must predict the pollutant emissions in the units of the applicable emission limitations of this division.
(2) The PEMS must meet the requirements of §
117.8110(b) of this title.
(h) Stationary gas turbine monitoring for NO X RACT. The owner or operator of each stationary gas turbine subject to the emission specifications of §
117.1205 of this title, instead of monitoring emissions in accordance with the monitoring requirements of 40 CFR Part 75, may comply with the following monitoring requirements:
(1) for stationary gas turbines rated less than 30 megawatts or peaking gas turbines (as defined in §
117.10 of this title) that use steam or water injection to comply with the emission specifications of §
117.1205(g) of this title:
(A) install, calibrate, maintain and operate a CEMS or PEMS in compliance with this section; or
(B) install, calibrate, maintain, and operate a continuous monitoring system to monitor and record the average hourly fuel and steam or water consumption. The system must be accurate to within ± 5.0%. The steam-to-fuel or water-to-fuel ratio monitoring data must be used for demonstrating continuous compliance with the applicable emission specification of §
117.1205 of this title; and
(2) for stationary gas turbines subject to the emission specifications of §
117.1205(f) of this title, install, calibrate, maintain and operate a CEMS or PEMS in compliance with this section.
(i) Totalizing fuel flow meters. The owner or operator of units listed in this subsection shall install, calibrate, maintain, and operate totalizing fuel flow meters to individually and continuously measure the gas and liquid fuel usage. A computer that collects, sums, and stores electronic data from continuous fuel flow meters is an acceptable totalizer. In lieu of installing a totalizing fuel flow meter on a unit, an owner or operator may opt to assume fuel consumption at maximum design fuel flow rates during hours of the unit's operation. The units are:
(1) for units subject to §
117.1205 of this title:
(A) any unit subject to the emission specifications of this division;
(B) any stationary gas turbine with an MW rating greater than or equal to 1.0 MW operated more than 850 hours per year; and
(C) any unit claimed exempt from the emission specifications of this division using the low annual capacity factor exemption of §
117.1203(a)(2) of this title (relating to Exemptions); and
(2) for units subject to §
117.1210 of this title:
(B) auxiliary steam boilers; and
(C) stationary gas turbines.
(j) Run time meters. The owner or operator of any stationary gas turbine using the exemption of §
117.1203(a)(3) or (b) of this title shall record the operating time with an elapsed run time meter approved by the executive director.
(k) Loss of exemption. The owner or operator of any unit claimed exempt from the emission specifications of this division using the low annual capacity factor exemptions of §
117.1203(a)(2) or (3) of this title, shall notify the executive director within seven days if the applicable limit is exceeded.
(1) If the limit is exceeded, the exemption from the emission specifications of 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.
(l) Data used for compliance.
(1) After the initial demonstration of compliance required by §
117.1235 of this title (relating to Initial Demonstration of Compliance), the methods required in this section must be used to determine compliance with the emission specifications of §
117.1205 of this title. Compliance with the emission specification may also be determined at the discretion of the executive director using any commission compliance method.
(2) For units subject to §
117.1210(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 requirements.
(m) Enforcement of NOX RACT limits. If compliance with §
117.1205 of this title is selected, no unit subject to §
117.1205 of this title may be operated at an emission rate higher than that allowed by the emission specifications of §
117.1205 of this title. If compliance with §
117.1215 of this title (relating to Alternative System-Wide Emission Specifications) is selected, no unit subject to §
117.1215 of this title may be operated at an emission rate higher than that approved by the executive director in accordance with §
117.1252(b) of this title (relating to Final Control Plan Procedures for Reasonably Available Control Technology).
(n) Testing requirements. The owner or operator of units subject to §
117.1210(a) of this title must test the units as specified in §
117.1235 of this title in accordance with the schedule specified in §
117.9120(2) of this title (relating to Compliance Schedule for Houston-Galveston-Brazoria Ozone Nonattainment Area Utility Electric Generation Sources).
(o) Emission allowances. The owner or operator of units subject to §
117.1210(a) of this title shall comply with the following.
(1) The NOX testing and monitoring data of subsections (a), (i), and (n) 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.
(2) For units not operating with a CEMS or PEMS, the following apply.
(A) Retesting as specified in subsection (n) 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 (n) 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 NO X 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 establish a new emission factor to be used 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.
