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HomeMy WebLinkAboutApproved July 2024 AQC Meeting Minutes_Amended1 ENVIRONMENTAL MANAGEMENT COMMISSION AIR QUALITY COMMITTEE MEETING SUMMARY July 10, 2024 Ground Floor Hearing Room of the Archdale Building 10:15 A.M. – 11:15 A.M. AQC MEMBERS IN ATTENDANCE Mr. Chris Duggan, Acting AQC Chair Mr. Michael Ellison Ms. Elizabeth (Jill) Weese Ms. Robin Smith *Commissioner H. Kim Lyerly observed the meeting as a guest on WebEx. OTHERS IN ATTENDANCE During the July 10, 2024, meeting, the Air Quality Committee (AQC) of the Environmental Management Commission (EMC) heard: 1. Agenda Item II-1: Concept for Emission Guidelines for Greenhouse Gas Emissions from Coal-Fired Electric Generating Units (Katherine Quinlan, DAQ) 2. Agenda Item II-2: Concept for Revisions to Permit Rules to incorporate Pre-Permitting Activities Provisions of Session Law 2023-134, Section 12.11(e) (Joelle Burleson, DAQ) 3. Agenda Item V-1: (Katherine Quinlan, DAQ) 4. Agenda Item V-2: Director’s Remarks (Mike Abraczinskas, DAQ) 2 PRELIMINARY MATTERS Agenda Item I-1, Call to Order and the State Government Ethics Act, N.C.G.S. §138A-15 AQC Acting Chair Duggan called the meeting to order and inquired, per General Statute §138A-15, as to whether any member knows of any known conflict of interest or appearance of conflict with respect to matters before the EMC’s AQC. None were stated. Agenda Item I-2, Review and Approval of the May 8, 2024, Meeting Minutes AQC Acting Chair Duggan requested approval of the May 8, 2024, Meeting Minutes. Commissioner Weese made the motion for approval of the minutes, and Commissioner Ellison seconded the motion. The minutes were approved unanimously. RULEMAKING CONCEPTS Agenda Item II-1, Emission Guidelines for Control of Greenhouse Gas Emissions from Coal-Fired Electric Generating Units (566) (Katherine Quinlan, DAQ) Ms. Katherine Quinlan, DAQ Rule Development Branch Supervisor, presented a concept for adoption of rules to implement the U.S. Environmental Protection Agency’s (EPA’s) Emissions Guidelines (EGs) for Control of Greenhouse Gas (GHG) Emissions from Existing Fossil Fuel-Fired Electric Generating Units (EGUs) under 40 CFR Part 60, Subpart UUUUb. She provided an overview of the history of EPA’s New Source Performance Standards (NSPS) and EGs to reduce GHG emissions, in the form of carbon dioxide (CO2), from the fossil fuel-fired electric generation sector. The most recent promulgation was on May 9, 2024, when the EPA finalized NSPS for new stationary combustion turbines and coal-fired steam EGUs undertaking large modifications, finalized EGs for existing coal-fired and oil/gas-fired steam EGUs, and the repeal of the Affordable Clean Energy rule. The EPA intends to take final action on EGs for existing combustion turbines at a later date. The EGs finalized three subcategories for existing coal-fired steam EGUs based on the operating horizon of the unit. These subcategories include “near-term” EGUs that cease operations prior to January 1, 2032. These EGUs will have no emission control obligations under the rule. The second subcategory is “medium-term” EGUs that cease operations prior to January 1, 2039. The EPA’s best system of emission reduction (BSER) for medium-term EGUs is a CO2 emission limit equivalent to 40% co-firing with natural gas and meeting that emission limit by January 1, 2030. The third subcategory is “long-term” EGUs that plan to operate past January 1, 2039. The BSER for these EGUs is a CO2 emission limit equivalent to 90% carbon capture and sequestration (CCS) and meeting that emission limit by January 1, 2032. For natural gas- and oil-fired EGUs, the BSER is routine operation and maintenance with no increase in CO2 emissions by January 1, 2030. North Carolina has a carbon emission reduction plan in place for investor-owned EGUs pursuant to House Bill 951 (commonly referred to as the Carbon Plan), that requires the North Carolina Utilities Commission (NCUC) to take “all reasonable steps” to achieve 70% carbon emission reduction from 2005 levels by 2030 and achieve carbon neutrality by 2050. Duke Energy has submitted a Carbon Plan and Integrated Resource Plan (CPIRP) pursuant to the Carbon Plan requirements, which contained three potential pathways towards achieving carbon reductions from their fleet. However, the NCUC has not yet made a final determination on which pathway will be implemented by Duke Energy to achieve this goal. Since this State law is existing, it is part of the business-as-usual scenario that DAQ will use as a baseline against which to calculate the impact of the EGs for the fiscal note. While NSPS requirements apply directly to affected facilities and are 3 incorporated by reference under 15A NCAC 02D .0524, EG requirements apply to States, who must establish standards of performance consistent with the EG for designated facilities in their jurisdiction. The States then submit a Clean Air Act (CAA) Section 111(d) State Plan to the EPA within two years after the effective date of the rule, specifying how their standards of performance meet the requirements of the EG and the State Plan Implementing Regulations under 40 CFR Part 60, Subpart Ba. Pursuant to the State Plan Implementing Regulations, the DAQ will conduct meaningful engagement with stakeholders during the rulemaking and state plan development process. Next steps include continuing to review the scope of the EPA’s rule, determining data needs to begin the analysis, drafting a rule(s), creating the fiscal note or regulatory impact analysis (RIA), and developing a community outreach plan to identify stakeholders that are most affected by the rulemaking. The DAQ is aiming to bring draft rules and a fiscal analysis to the AQC in November 2024 for approval to proceed to the full EMC and is aiming for a public comment period spanning February through April 2025. If EMC-adoption of the rules is granted in July 2025, the tentative effective date for the rules would fall in September 2025. Discussion Commissioner Duggan asked during the presentation how many EGUs in the State fall into the subcategories listed in the presentation. Ms. Quinlan presented a slide that listed the tentative retirement dates for the affected EGUs for the three pathways that were submitted in Duke Energy’s CPIRP. Commissioner Ellison asked about the likelihood that these EPA rules will be litigated. Director Abraczinskas stated that a stay by the courts would halt the rulemaking process and the State would remain on hold until the litigation is resolved. Commissioner Ellison asked about CCS and heat rate improvement for reducing GHG emissions. Ms. Quinlan stated that CCS is a control technology, whereas heat rate improvements can be compared to a work practice standard. She added that CCS is expected to reduce more GHG emissions in comparison to heat rate improvements, however the technology is impacted by geology in the area. Only one facility, Cliffside 6 located near Charlotte, is expected to be in the long-term subcategory and therefore would be subject to the CCS BSER requirements. Commissioner Ellison asked where in North Carolina CCS would be a viable practice. Ms. Quinlan responded that more studies would need to be done to determine that. Commissioner Ellison asked if complying with the EGs would be more challenging for Duke Energy than the CO2 reduction requirements in State statutes. Ms. Quinlan stated that the carbon plan that Duke Energy is developing puts them on a pathway to achieving the CO2 reduction goals in the State statutes. The EPA requirements are intended to work in unison with those carbon plans, but there may be instances when the requirements may differ, and the DAQ is working to determine those differences and estimate the impacts. Commissioner Ellison asked if there might be potential conflict between what the NCUC approves by State statute versus what EMC might approve to comply with EPA’s requirements. Ms. Quinlan responded that the EPA EGs does not specify that they must install any certain technology or operate in any certain way. The EGs do allow for extension of retirement dates to meet reliability concerns and we are continuing to review what those requirements are and how they can be utilized. Commissioner Smith asked if the Cliffside facility was the only long-term EGU and therefore would need to achieve a level of reduction represented by CCS. Ms. Quinlan confirmed that one of the Cliffside units has a retirement date in Duke’s CPIRP that would place it in the long-term subcategory. However, while the emission limitation for any long-term units would need to represent an emission reduction equivalent to using CCS, the units do not have to actually use CCS to comply. Facilities can choose another method of reducing emissions, as long as they comply with the emission limitation that the State establishes pursuant to the Emission Guidelines. Commissioner Smith noted that the State legislation mirrors the 4 approach used in the Clean Power Plan, in which GHG emissions are reduced by broadening the use of renewables. She added that one potential way for Duke Energy to comply with the EGs is through the processes they are going through with the NCUC to reduce CO2 emissions from their coal-fired EGUs through renewables or conservation measures. Ms. Quinlan agreed with the assessment and added that the CPIRP provides plans for retirements, increased generation from other sources, or construction of new generation. Director Abraczinskas added that Duke Energy is fully aware of the EGs and State law and is working on the optimal pathway to comply with both. The DAQ is in discussions with Duke Energy to obtain data to determine the impacts of the EGs on the State for the Fiscal Note analysis. Commissioner Deerhake noted that Cliffside is the newest EGU in the State and Duke Energy would like to recover their investment in the project. She asked if many of the coal-fired EGUs that were retiring were being replaced with natural gas-fired turbines. Ms. Quinlan stated that some of the coal-fired EGUs were being replaced by gas combustion turbines. Commissioner Deerhake followed up by asking how natural gas-fired turbines are regulated in the rule. Ms. Quinlan stated that new gas turbines are regulated by the NSPS and not the EGs, however some of the affected EGUs under the EGs can potentially burn up to 100% natural gas. Commissioner Deerhake asked if the NSPS includes major modifications to existing units and whether conversion of a unit from coal to natural gas would fall under a “major modification,” making the unit subject to the NSPS. Ms. Quinlan stated that the DAQ was working on trying to answer that question. It may come down to whether retrofit is needed or whether the retrofit has already been installed. Commissioner Deerhake asked when the NSPS major modifications rule becomes effective, and what date triggers a new source to be subject to the NSPS instead of the EG. Ms. Quinlan stated that NSPS rules generally become effective 60 days after publication in the Federal Register, and that typically the proposal date of the NSPS and EG rules serves as the cutoff date for new/modified sources versus existing sources (i.e., sources constructed or modified after the EPA proposal date are considered “new sources” and subject to the NSPS, whereas sources constructed before the EPA’s proposal date are considered “existing sources” and subject to the EG). These EPA rules were proposed on May 23, 2023. Agenda Item II-2, Revisions to Permit Rules to Incorporate Pre-Permitting Activities Provision of Session Law 2023-134, Section 12.11(e) (565) (Joelle Burleson, DAQ) Mrs. Joelle Burleson, DAQ Planning Section, presented a concept on a potential rulemaking to incorporate the pre-permitting activities provisions of Session Law 2023-134, Section 12.11(e). S.L. 2023-134 became effective in October 2023 and Section 12.11(e) (Pre-Permitting Activities) specifies changes to General Statute (G.S.) 143-215.108A, which deals with the control of sources of air pollution, construction of new sources, new facilities, and alteration or expansion of existing facilities. The S.L. changes the types of site activities that a permit applicant can undertake before receiving an air quality permit from the Division. In May of 2024, Governor Cooper signed S.L. 2024-1, which included technical corrections to last October’s S.L. 2023-134. S.L. 2024-1, Section 4.13(a), adds Section 12.11(f) to S.L. 2023-134, requiring that the Department of Environmental Quality (DEQ) submit a State Implementation Plan (SIP) revision by July 1, 2025 for EPA approval of the changes to the air quality permitting program resulting from Section 12.11. It also added a new Section 12.11(g) to S.L. 2023-134 that established the effective date for Section 12.11 as the first of a month that is 60 days after the DEQ Secretary certifies to the Revisor of Statutes that the EPA has approved a SIP amendment with these air quality permitting program changes. Section 4.13(b) of S.L. 2024-1 made the effective date for the provisions of S.L. 2023-134, Section 12.11 retroactive back to July of 2023. 5 Section 12.11(e) of S.L. 2023-134 modified G.S. 143-215.108A by adding new subsection (b1) that applies to both new and permitted facilities and contains a list of activities that are allowed prior to obtaining a permit. Some of these activities were previously in subdivisions (a)(1)-(4) of G.S.143- 215.108A, including clearing and grading, construction of access roads and driveways and parking lots, installation of underground utilities and pipe work, and construction of things that are not a necessary component of an air contaminant source or associated control device, such as office buildings and fences. S.L. 2013-134, Section 12.11(e) expands upon this list by adding new subdivision (b1)(5) to G.S. 143- 215.108A to allow construction, but not operation of a new air contaminant source, equipment, or associated air cleaning or emissions control device if an application for a permit or permit modification has been submitted to the DAQ and determined administratively complete. This new subdivision (b1)(5) of the statute does not apply to emission sources subject to: (1) permit limits set pursuant to programs for the Prevention of Significant Deterioration (PSD) and for attainment of air quality standards in nonattainment areas; (2) a residual risk-based hazardous air pollutant (HAP) standard under CAA Section 112(f); or (3) a case-by-case maximum achievable control technology (MACT) permit requirement that are issued by the Department under CAA Section 112(j). DAQ is beginning rulemaking to incorporate the Pre-Permitting provisions of the Session Law to comply with the July 1, 2025 SIP amendment submittal deadline of Section 12.11(f), and the Division is working to minimize the number of rules that need to be revised to effectively meet the statutory requirements. The presentation concluded with an overview of the tentative rulemaking timeline, which indicates that the timeline of this rulemaking is anticipated to correspond to that of another DAQ rulemaking to implement some of the other permitting changes proposed in response to the Session Law. Discussion Commissioner Smith asked for confirmation that the state would need to submit the actual language of the statute along with any rules in its SIP revision because the policy changes, in this case, are in the statute. Mrs. Burleson said clarified that DAQ can provide the statute to EPA as background information and explanatory material, but EPA would typically not approve incorporation of a session law or statutes into the SIP because CAA Section 110(a)(2)(C) and 40 CFR Part 51 implementing regulations require that SIP changes undergo a public review and comment process, which is not provided through the legislative process in and of itself. Commissioner Smith asked how DAQ would then get to a SIP amendment because the actual policy changes here are in the statute, noting that the Administrative Procedures Act (APA) prohibits adopting statute language directly into a rule and this rulemaking would simply consist of whatever minor amendments to the rules would be necessary to conform to this statutory language. Noting that she understands the need for public notice, she indicated that state programs under both the CAA and Clean Water Act consist of a combination of the state laws and the state regulations. She noted that the SIP may be the complicating factor here, because North Carolina’s overall air program consists of both statutes and rules since some of the substantive requirements are in the statute and not in EMC regulation. Director Abraczinskas clarified that the DAQ’s vision here is to change the rules where necessary, such as modifying the definition of construction in North Carolina’s SIP-approved rules, which can then be submitted as a SIP revision by the statute deadline for EPA’s review and consideration. He added that the complexity arises where, as the AQC has heard from the DAQ in previous presentations on this topic, there is concern about this provision not being consistent with the CAA or the federal implementing regulations of the CAA. Therefore, the DAQ intends to pose the approvability question EPA prior to coming back to the AQC with an action item. While the DAQ has already had discussions with EPA about these concerns, we do not yet have anything in writing to provide the Commission. Commissioner 6 Smith commented to the Chairman that it would be wise to get EPA’s reaction to the statute language before launching an EMC rulemaking process for policy changes that are already suspected to be problematic under the CAA. Commissioner Deerhake asked that the regulatory impact analysis include a list of all existing PSD permitted facilities that could potentially construct a new unit or undergo a major modification of an existing unit, but because they are in PSD areas, would not fall under this statute. She asked for confirmation that the Duke Energy Cliffside plant has a PSD Class I permit. Director Abraczinskas indicated that the facility is definitely a Title V facility but would need to verify if the facility is a PSD major source; however, this particular provision does not apply to PSD facilities. Commissioner Deerhake indicated that she wants to ensure that the Commissioners are informed and assured about which PSD permitted facilities choosing to go through a major modification would still be covered due to that statement in the statute about the PSD facilities. ACTION ITEMS None EMC AGENDA ITEMS Acting Chair Duggan noted that there is one Air Quality action items on the following day’s EMC agenda. INFORMATION ITEMS Agenda Item V-1, Update on Rulemaking to Implement EPA’s Emission Guidelines for Control of Greenhouse Gas Emissions from the Oil and Gas Sector (563) (Katherine Quinlan, DAQ) Ms. Katherine Quinlan, DAQ Rule Development Branch Supervisor, presented an update on the rulemaking to implement EPA’s EGs for Control of GHG Emissions from the Crude Oil and Natural Gas Sector. She outlined the pertinent NSPS and EGs, including their 40 CFR Part 60 subparts, source type, applicable dates, and designated pollutants. This rulemaking is focused on the EGs in Subpart OOOOc (“EG OOOOc”). CAA Section 111(d) requires states to submit plans for these sources containing standards consistent with federal EGs, and these state plans are due by March 8, 2026. The procedure for EGs involves the state identifying the BSER and establishing standards of performance based on the application of the BSER. Regulated sources must then comply with the standards using either BSER or non-BSER methods. EG OOOOc applies to the production and processing of crude oil and natural gas as well as the transmission and storage of natural gas; however, this rulemaking is limited to natural gas compressor stations. The DAQ has currently identified 11 natural gas compressor stations that will be affected, spanning across 5 regions and 11 counties of the state. The stations belong to 5 different entities. The EPA specifies different sources and their corresponding BSERs and presumptive standards of performance. The BSER for emissions from fugitive emissions/equipment leaks is monthly audio, visual, and olfactory (AVO) monitoring surveys as well as monitoring and repair based on quarterly monitoring using optical gas imaging (OGI). The presumptive standard of performance allows for EPA Method 21 monitoring instead of OGI and establishes required time frames for repairs. The other sources are types of equipment that may be present at the sites. The BSERs and presumptive standards of performance for reciprocating compressors, dry-seal centrifugal compressors, and wet-seal centrifugal compressors are monitoring and repair to maintain volumetric flow rates at or below 2 standard cubic feet per minute (scfm), 10 scfm, and 3 scfm, respectively. For reciprocating compressors, the EPA’s BSER also includes an option for periodic replacement of the 7 compressor rod packing in lieu of the periodic volumetric monitoring. The BSER for pneumatic controllers is the use of zero-emissions controllers, and the presumptive standard of performance is a GHG emission rate of zero methane emissions to the atmosphere. Additionally, EG OOOOc includes the Super Emitter Program. The EG defines a super-emitter event as a quantified emission rate of 100 kilograms per hour of methane or greater. This program allows EPA-certified third-parties to remotely detect super-emitter events at sites and notify the EPA. The EPA will then alert the facility, which must conduct an investigation of the event. As part of the investigation, owners and operators must report all sources, including non-NSPS/EG sources, that they suspect may have caused or contributed to the super-emitter event. Meaningful engagement must be documented in the state plan, including a list of pertinent stakeholders. The DEQ Public Affairs Office is working on an Outreach Assessment that will help inform the outreach for the rulemaking and state plan development process. The Outreach Assessment will analyze community characteristics within a 3-mile radius of affected facilities and the presence of Tribal Organizations within a 50-mile radius. The DAQ is developing outreach plans based on this information as well as assessing data needs for conducting fiscal analysis and drafting rule(s). They will continue to finalize the draft rule(s), perform a cost/benefit analysis for the fiscal note/RIA, and conduct outreach to stakeholders affected by the rulemaking. The tentative effective date of the rule(s) is expected to be September 1, 2025. Discussion Commissioner Ellison asked if the certified third-parties are contracted by the EPA. Ms. Quinlan stated that she does not believe that the third-parties are contracted by the EPA and that any person or entity could become certified if their technologies and methodologies are approved under the advanced methane detection technology program. Commissioner Duggan asked how difficult it is to become certified. Ms. Quinlan responded that she would have to read more about the program but expects that there are specific requirements set forth in federal rule for those seeking to become a certified third party under the super emitter program. Commissioner Ellison asked if permits after September 2025 would have to comply with the EG. Ms. Quinlan answered that the applicability date of which facilities are covered by the EG has passed. If the facility was existing and not modified after that date, it is covered by the EG. Permits that come to the DAQ after the new rule(s) are effective may contain reference to these new rule(s), or the DAQ may not incorporate those requirements into the permits until after the state plan is submitted and approved by EPA. Commissioner Ellison asked if permits that come to the DAQ between now and September 2025 will incorporate the requirements of EG OOOOc. Ms. Quinlan stated that these permits would not incorporate EG OOOOc requirements, and permit applications for new facilities would be covered by NSPS. Agenda Item V-2, Director’s Remarks (Mike Abraczinskas, DAQ) DAQ Director Abraczinskas had no further remarks. CLOSING REMARKS AND MEETING ADJOURNMENT Acting Chair Duggan noted the next meeting of the AQC is scheduled for September 11, 2024, and adjourned the meeting.