N.M. Code R. § 20.2.101.113

Current through Register Vol. 35, No. 11, June 11, 2024

Section 20.2.101.113 - MONITORING REQUIREMENTS

A. Owners or operators of an affected EGF shall prepare a monitoring plan to quantify the hourly CO₂ mass emission rate in tons per hour (tph) in accordance with the applicable provisions of this Section and 40 CFR Part 75.53(g). The monitoring plan shall be submitted to the Department and in place prior to reporting emission data and the results of the monitoring system certification test under Subsection A of 20.2.101.113 NMAC. The monitoring plan shall be updated as appropriate.

B. Owners or operators shall determine the hourly CO₂ mass emissions in pounds or tons from each affected electric generating unit (EGU) according to paragraphs (1) through (5) of Subsection B of 20.2.101.113 NMAC.

(1) Owners or operators shall install, certify, operate, maintain, and calibrate a CO₂ continuous emission monitoring system (CEMS) to directly measure and record the hourly average CO₂ concentration in the affected EGU exhaust gas emitted to the atmosphere, and a flow monitoring system to measure hourly average stack gas flow rates, in accordance with 40 CFR Part 75.10(a)(3)(i). As an alternative to direct measurement of the CO₂ concentration, provided that the affected EGU does not employ carbon separation (e.g., carbon capture and storage), owners or operators may use data from a certified oxygen (O₂) monitor to calculate the hourly average CO₂ concentration in accordance with 40 CFR Part 75.10(a)(3)(iii) . If the CO₂ concentration is measured on a dry basis, owners or operators shall also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, in accordance with 40 CFR Part 75.11(b) . Alternatively, owners or operators may either use an appropriate fuel-specific default moisture value from 40 CFR Part 75.11(b) or submit a petition to the Department for a site-specific default moisture value.

(2) For each CEMS used to comply with this Part, owners or operators shall meet the applicable certification and quality assurance procedures in 40 CFR Part 75.20 and Appendices A and B of 40 CFR Part 75.

(3) Owners or operators shall use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO₂ mass emission rate from each affected EGU. Owners or operators shall not apply the bias adjustment factors described in Section 7.6.5 of Appendix A to 40 CFR Part 75 to the exhaust gas flow rate data.

(4) Owners or operators shall select an appropriate reference method to set up the flow monitor and perform the ongoing Relative Accuracy Test Audit (RATA), in accordance with 40 CFR Part 75. If owners or operators use a Type-S pitot tube or a pitot tube assembly for the flow RATA, owners or operators shall calibrate the pitot tube or pitot tube assembly. Owners or operators may not use the 0.84 default Type-S pitot tube coefficient specified in Method 2.

(5) Owners or operators shall calculate the hourly CO₂ mass emissions (in tons) as described in Subparagraphs (a) through (c) of Paragraph (5) of Subsection B of 20.2.101.113 NMAC. Owners and operators shall only perform this calculation for valid operating hours, as defined in 40 CFR Part 60.5540(a)(1) .

(a) Begin with the hourly CO₂ mass emission rate (tons/hour), obtained either from Equation F-11 of Appendix F of 40 CFR Part 75 (if the CO₂ concentration is measured on a wet basis), or by following the procedure in section 4.2 of Appendix F of 40 CFR Part 75 (if the CO₂ concentration is measured on a dry basis).

(b) Next, multiply each hourly CO₂ mass emission rate by the EGU or stack operating time in hours (as defined in 40 CFR Part 72.2), to calculate the tons of CO₂).

(c) The hourly CO₂ emission rate and the EGU (or stack) operating hours used to calculate the CO₂ emission rate shall be recorded under 20.2.101.114 NMAC and shall be reported as required under 20.2.101.115 NMAC.

C. Owners or operators shall install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the hourly net electric output from each affected EGU. These measurements shall be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI Standards No. C12.20 (see 40 CFR Part 60.17 ).

D. Consistent with 40 CFR Part 60. 5520, if two or more affected EGUs serve a common electric generator, the owners or operators shall apportion the combined hourly net energy output to the individual affected EGU according to the fraction of the total steam load contributed by each EGU. Alternatively, if the EGUs are identical, owners or operators may apportion the combined hourly net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU.

E. In accordance with 40 CFR Part 60.13(g) and 40 CFR Part 60.5520 , if an owner or operator of two or more affected EGUs that utilize the CEMS provisions in Subsection B of 20.2.101.113 NMAC share a common exhaust stack, the owners or operators may monitor the hourly CO₂ mass emissions at the common stack, in lieu of monitoring each EGU separately. If an owner or operator chooses this option, the hourly net generation shall be the sum of the hourly net generation for each individual affected EGU, and the owner or operator shall express the operating time as "stack operating hours" (as defined in 40 CFR Part 72.2 ). If an owner or operator demonstrates compliance with the emission standard of this Part at the common exhaust stack, each affected EGU utilizing the stack shall be determined to be in compliance.

F. In accordance with 40 CFR Part 60.13(g) and 40 CFR Part 60.5520 , if an owner or operator of an affected EGU utilizing the CEMS provisions in Subsection B of 20.2.101.113 NMAC has exhaust gas that is emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and owners or operators elect to monitor the ducts), the owner or operator shall monitor the hourly CO₂ mass emissions and the "stack operating time" (as defined in 40 CFR Part 72.2 ) at each stack or duct separately. Owners or operators shall determine compliance with the emission standard of this Part by summing the CO₂ mass emissions measured at the individual stacks or ducts and dividing by the total net generation for the affected EGU.

G. Operating hours in which CO₂ mass emission rates are calculated using maximum potential values are not "valid operating hours" (as defined in 40 CFR Part 60.5540 (a)(1) ) and shall not be used in the compliance determinations under 40 CFR Part 60.5540.

N.M. Code R. § 20.2.101.113

Adopted by New Mexico Register, Volume XXXIII, Issue 22, November 29, 2022, eff. 1/1/2023