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HomeMy WebLinkAboutAQC_08Jan2025_Approved Meeting Minutes1 ENVIRONMENTAL MANAGEMENT COMMISSION AIR QUALITY COMMITTEE MEETING SUMMARY January 8, 2025 Ground Floor Hearing Room of the Archdale Building 10:15 A.M. – 11:15 A.M. AQC MEMBERS IN ATTENDANCE Chair Charles (Charlie) Carter Mr. Michael Ellison Vice-Chair H. Kim Lyerly Ms. Robin Smith Ms. Yvonne Bailey Ms. Elizabeth (Jill) Weese Mr. Chris Duggan, EMC Vice-Chair OTHERS IN ATTENDANCE During the January 8, 2025, meeting, the Air Quality Committee (AQC) of the Environmental Management Commission (EMC) heard: 1. Agenda Item V-1: Update on Rulemaking to Implement EPA’s Emission Guidelines for Greenhouse Gas Emissions from Fossil Fuel-Fired Steam Electric Generating Units (EGUs) pursuant to 40 CFR Part 60, Subpart UUUUb (566) (Katherine Quinlan, DAQ) 2 PRELIMINARY MATTERS Agenda Item I-1, Call to Order and the State Government Ethics Act, N.C.G.S. §138A-15 AQC Chair Carter 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 November 13, 2024, Meeting Minutes AQC Chair Carter deferred approval of the November 13, 2024, meeting minutes to the March meeting. RULEMAKING CONCEPTS Agenda Item V-1: Update on Rulemaking to Implement EPA’s Emission Guidelines for Greenhouse Gas Emissions from Fossil Fuel-Fired Steam Electric Generating Units (EGUs) pursuant to 40 CFR Part 60, Subpart UUUUb (566) (Katherine Quinlan, DAQ) Katherine Quinlan (DAQ): Good morning, Commissioners. I am Katherine Quinlan, I am with the Division of Air Quality in the Rule Development Branch, and I will be giving an update on where we are with this rulemaking. I’ll go over a little bit of the background that you’ve seen before and then go into where we are with our analysis and our development of the rules. (Slide 2) This is just a slide with a list of acronyms for reference as you go through, we use a lot of acronyms throughout these slides, so for reference here. (Slide 3) To recap the background behind this a little bit, there have been essentially three renditions of this rule. Back in 2015, U.S. Environmental Protection Agency (EPA) promulgated New Source Performance Standards (NSPS) for electric utility generating units, or EGUs, in 40 CFR Part 60, Subpart TTTT, and that was for control of greenhouse gas emissions from affected facilities. Those pertained to carbon dioxide (CO2) emissions standards for new, modified, and reconstructed steam generating units and stationary combustion turbines. There was a variety of best system of emission reduction (BSER) requirements that were established for those units depending on the type of unit, fuel usage, and the size of the unit. In that same action, EPA promulgated Emission Guidelines for existing EGUs, and that was under 40 CFR Part 60, Subpart UUUU, controlling greenhouse gas emissions from designated facilities, and that was known as the Clean Power Plan. This established guidelines for States to develop their standards of performance for existing steam generating units and stationary combustion turbines. BSER in the Clean Power Plan was state-specific goals for reducing CO2 emissions, and that also required States to develop a plan, including necessary rules, to meet those goals. However, the Clean Power Plan was stayed by the Court in 2016. (Slide 4) In 2019, the EPA finalized the repeal of the Clean Power Plan and revisions to the Emission Guidelines Implementing Regulations that are under 40 CFR Part 60, Subpart Ba. EPA also promulgated new Emission Guidelines for greenhouse gas emissions from existing EGUs under Subpart UUUUa, and that was known as the Affordable Clean Energy or ACE Rule. In the ACE Rule, EPA identified BSER as heat rate improvement through the application of seven specific heat rate improvement candidate technologies. However, the ACE Rule was stayed by the Court in January 2021. (Slide 5) This brings us to the third iteration of these rules. In May of 2023, the EPA proposed five separate actions for greenhouse gas emissions from fossil fuel-fired EGUs. They proposed the repeal of the ACE Rule and NSPS for new stationary combustion turbines and for fossil fuel-fired steam generating 3 units that are undertaking a large modification. They also proposed new Emission Guidelines for existing coal-fired and gas- and oil-fired steam generating units and Emission Guidelines for existing large combustion turbines. In May of 2024, four of those five proposed actions were finalized. While EPA finalized the Emission Guidelines for existing coal-fired, natural gas-fired, and oil-fired steam generating units, they intend to take final action on Emission Guidelines for existing combustion turbines at a later time. (Slide 6) Regarding North Carolina's Clean Air Act obligations in response to these EPA rules, the NSPS promulgated under Section 111(b) are directly applicable to facilities and automatically incorporated through Rule 02D .0524. Emission Guidelines, however, are under Clean Air Act Section 111(d), and those are not directly applicable to facilities. Instead, these specify requirements for states to develop standards that apply to the designated facilities in their jurisdiction. The Emission Guidelines for existing steam generating units give states two years from the effective date of the rule to develop and submit their plans to EPA for reducing greenhouse gas emissions from their existing sources. The state can take into account the remaining useful life and other factors, or what's often called RULOF, when applying standards of performance to individual existing sources. The states also must follow the requirements in the State Plan Implementing Regulations in Subpart Ba. (Slide 7) There are three main steps for Emission Guidelines. First, EPA identifies BSER for the existing sources in that source category. That's what they've done in these Emission Guidelines. Then the states establish their standards of performance for the designated facilities in their jurisdiction based on applying that BSER to those facilities. Here in North Carolina, we codify those standards in a State Rule, and then we incorporate those State Rules into a State Plan that we submit to EPA. Then the regulated sources comply with those standards using either BSER or non-BSER methods. The State Plan must demonstrate that the state's standards of performance meet the equivalency criteria specified in the Emission Guidelines when compared to what EPA has put forward as the presumptive standard of performance in the Emission Guidelines. (Slide 8) This chart is showing the final NSPS standards for the new stationary combustion turbines. These are the ones that are automatically adopted by the State through Rule 02D .0524, but it is relevant in the context of the Emission Guidelines and the whole system, so we'll go over it quickly here. Essentially, the final NSPS for combustion turbines separate the source category into three subcategories based on the annual average capacity factor of the unit. There are low-load units, intermediate-load and base-load units, with the cut offs for each subcategory based on the unit’s capacity factor. If the unit’s capacity factor is less than or equal to 20%, it is a low-load unit. If the capacity factor is between 20% and 40%, it is an intermediate-load unit, and if the capacity factor is greater than 40% capacity factor, it is a base-load unit. The standard that applies to the unit depends on which subcategory it falls within. You can also see there are two phases for implementation. Low-load and intermediate-load units only comply with Phase 1 beginning upon startup, and for the base-load units, Phase 1 BSER is highly efficient combined cycle generation. For Phase 1, upon startup, base-load units must meet a standard between 800 and 900 pounds of CO2 per megawatt-hour (lb CO2 /MWh), depending on the size of the unit. For Phase 2, which begins in 2032, BSER is established as carbon capture and storage (CCS) with 90% capture, and that standard is 100 lb CO2 /MWh. Chair Carter: Let me stop you right there and start and ask a couple questions. Number one, the 111(d) is a process that runs out a couple of years, but you said that these standards apply immediately to new sources, correct? Katherine Quinlan: That's correct. 4 Chair Carter: Do we have any new sources that these will apply to? Katherine Quinlan: Yes. Chair Carter: I saw recently the information about the permits for some Duke combustion turbines, those are the ones we'd expected it to apply to? Mike Abraczinskas (DAQ Director): Yes, Sir. Commissioner Ellison: Where are those, and how big are they? Director Abraczinskas: The two facilities that will have new units that this applies to are the Duke Energy Marshall gas turbines and then the Duke Energy Roxboro natural gas combined cycle units. The size of those I cannot recite off the top of my head. I'm looking at Taylor. Taylor Hartsfield (DAQ Deputy Director): Not off the top of my head. Director Abraczinskas: We could pull that up. It is substantial. Chair Carter: Yes, I assumed they were pretty good sized. Do you have any idea what the timeline is as far as when Duke is going to be starting construction on those? Director Abraczinskas: I can't provide an exact date. I think there was a proposed schedule in parts of their application, but that's probably a question better posed to Duke about their exact construction schedule. Chair Carter: Well, I'll tell you where I'm going with this because all you have to do is look back at the history, the three-prong history of this thing and particularly what happened in 2017 or actually ended up in 2019. I guess my thought on this whole thing is the likelihood that this going forward is not going to continue with some new folks coming in at EPA in a new administration. They changed the Clean Power Plan last time. I can't imagine there's any likelihood they're not going to do that this time or at least put these on hold would be my guess, and then take a look to decide whether they want to make modifications or not. I guess part of my concern here is that it seems like this is an area that I'm not sure it's worth spending a lot of time on right now, as far as you all developing rules, particularly for the 111(d), until we get some indication of what's going to happen with the new folks at EPA and where that may be going. Director Abraczinskas: Thank you, Mr. Chairman. I think we certainly acknowledge that there could be some regulatory whiplash that occurs in 2025. Chair Carter: That's a good way to describe it. Director Abraczinskas: But you know, at this point, as Ms. Quinlan will go through over the course of her presentation, the new source performance standards are on the books and adopted. Chair Carter: Yeah, I understand. Director Abraczinskas: If they change, then they change on our books as well, but for the existing source emission guidelines, the state has an obligation and a timeline that it must meet. Our proposal is to continue on a path to meeting that federal deadline until there is a change. If there is a change, then when it changes, we would adjust of course. Where we're headed, as Ms. Quinlan is going to share with you, we're putting ourselves in a position to successfully meet the federal requirement until that requirement is changed or eliminated. Chair Carter: And that deadline would be May of 2026, then? Katherine Quinlan: Yes, early May. I believe it's May 8th or 9th, 2026. 5 Chair Carter: Two years from the date of promulgation, which was last May? Katherine Quinlan: Yes. Director Abraczinskas: Again, Ms. Quinlan will show you that the difficulty here is that there's kind of a “two-prong” element to this. There's not only the rulemaking piece that this body would go through to adopt those existing source standards, but then we also go through a State Plan process, which is a separate public process altogether with a runway that is fairly long as well. That's why we need quite a bit of time to make sure that we're in a position to meet that May 2026 deadline. Chair Carter: Okay, we'll go ahead. I have more questions, but let's go ahead with the presentation now. Katherine Quinlan: (Slide 9) Okay. This slide gives an overview of the emission guidelines for existing coal steam generating units. This is for just the coal portion, and then the slide after this will show, in a similar format to the NSPS the flow chart, the different subcategories. For existing coal steam generating units, EPA finalized three subcategories, and those are based on the operating horizon of the unit. If the unit plans to permanently cease operations prior to January 1, 2032, then it's a “near-term” unit and there are no emission obligations under the rule. There are some reporting obligations for these units to ensure that they're achieving milestones and on track to meet that retirement date, but there are no emission control obligations under the rule. “Medium-term” EGUs are ones planning to operate on or after January 1, 2032, but retire permanently prior to January 1, 2039. BSER for those units is to meet a CO2 emission limit equivalent to 40% co-firing with natural gas and to do so by January 1, 2030. EGUs that plan to operate on or after January 1, 2039, are considered “long-term” units. BSER for those units is meeting a CO2 emission limit equivalent to 90% carbon capture and storage by January 1, 2032. (Slide 10) I know that the text here is a little small, but this is showing an overview of the emission guidelines with all of the covered subcategories. What I just covered is everything on the left for the coal- fired units. As I mentioned before, these emission guidelines also cover existing natural gas- and oil-fired steam generating units, which are divided into subcategories based on capacity factor, and the cutoffs are slightly different than what they are for the NSPS. Capacity factor of 8% is the cutoff between low-load and intermediate load units, 45% capacity factor is the cutoff between intermediate-load and base-load, and then anything operating above 45% capacity factor is a base-load unit. BSER for these existing natural gas and oil-fired steam generating units is routine methods of operation and maintenance and no increase in emission rates. EPA put forward some presumptive standards of performance for these units that you can see on the slide. The compliance date for those is January 1st, 2030. Pivoting back to the left side of this slide , we already covered (on the previous slide) the BSER for medium-term and long-term coal-fired units. EPA also established presumptively approvable standards of performance for these units: for medium-term units, the presumptive standard is 16% reduction in emission rate, and for long-term units, it would be an 88.4% reduction in emission rate. For the 16% reduction, the Federal Register and the EPA’s rule specify that any existing natural gas co-firing in the baseline should be accounted for when developing your standard of performance, so the 16% reduction would be adjusted if there's already natural gas co-firing in the baseline. (Slide 11) Now we've covered the NSPS under Section 111(b) of the Clean Air Act, and we've covered the emission guidelines under Section 111(d) of the Clean Air Act. Next, we'll go into another layer here in North Carolina, which is House Bill 951 and the Carolina Carbon Plan that is implemented by the North Carolina Utilities Commission (NCUC). These three layers overlap, there are sources that are covered by both the Carbon Plan and then also the rules under either Section 111(b) or 111(d) of the Clean Air Act. Figuring out the interaction between these is something that we're deciphering in our analysis, and it adds another level of complexity to this rulemaking. 6 (Slide 12) Several years ago, House Bill 951 required the NCUC to take all reasonable steps to achieve 70% carbon reductions from 2005 levels by 2030, which is called the interim target, and then to achieve carbon neutrality by 2050. That Plan gets reviewed by the NCUC every two years after adoption of the initial Carbon Plan. The portfolios are evaluated against four objectives: CO2 emission reduction, affordability, reliability, and executability of the Plan. The initial Carbon Plan order consolidated the existing Integrated Resource Plan, or IRP process, with the Carbon Planning process. Now we have a Carbon Plan and Integrated Resource Plan, or CPIRP, which is required to be filed by Duke Energy every two years beginning in 2023. (Slide 13) On this slide, I’ll cover the timeline of the latest CPIRP that was filed in 2023. There was an update in January of 2024 where Duke revised their CPIRP based on an updated 2023 Fall Load Forecast. This is what's called the “Supplemental Planning Analysis”. Then on July 1st of 2024, shortly after EPA finalized the NSPS and the emission guidelines, Duke Energy filed a Section 111 Sensitivity Analysis, which presents the impacts of EPA’s recently finalized rules for greenhouse gases from the power sector. On November 1st of 2024, the NCUC issued a decision on Duke Energy's 2023-2024 CPIRP. We've included an excerpt of just one sentence from that decision on this slide, which states that the NCUC concluded that the modeling presented in the CPIRP, as well as the Supplemental Portfolio Analysis and the Clean Air Act Section 111 Sensitivity Analysis, are reasonable for planning purposes. (Slide 14) That 111 Sensitivity Analysis evaluated the effects of both the Clean Air Act Section 111(b) NSPS and the Section 111(d) emission guidelines on Duke Energy's EGUs with respect to their trajectories under the CPIRP (i.e., without the Section 111 standards). One assumption in that modeling was that all new gas units would operate as intermediate-load units under the NSPS, so with a capacity factor less than or equal to 40%, beginning in 2032. This was on the basis that a 100 lb CO2/MWh emission rate would not be achievable, so the CCS is not feasible and no other technologies capable of meeting this standard are viable or cost-effective by 2032. Again, we've included an excerpt from that Section 111 Sensitivity which states that that modeling determined that the impacts of the “Final Rule” (which is the term used to cover both the Section 111(b) and 111(d) Rules in that Sensitivity Analysis) on the Pathway 3 (P3) Fall Load Forecast Base Portfolio is an increase in CO2 emissions of over 4 million tons in the year 2035, a likely delay in the Interim Target date to 2036 or later, and an increase in the total system cost of more than $600 million. Chair Carter: I'm curious, do you know what the basis is for that modeling determination there, that it’s going to increase CO2 emissions? Katherine Quinlan: Yes, so that's actually what the next bullet point is going over, and some of the following slides, which touch on some things that may be causing or driving that conclusion from the modeling, based on our review of the Sensitivity Analysis. One driver is that that the NSPS Section 111(b) rules, which of course are adopted automatically through our State Air Quality rules, cause the generation to shift away from the highly efficient new combined cycle units, which are already planned and in the baseline of the P3 Fall Load Base Case, since those units have to be restricted to a capacity factor of less than 40% annually beginning in 2032. That displaced generation appears to be shifting towards more gas units or higher utilization of the existing coal or existing gas units, which would cause an increase in CO2 emissions with respect to the baseline. That may be one driving factor here. It does not appear to be caused by the emission guidelines, which we're developing State rules for, but the interaction here is complex, and these impacts may be caused by the 111(b) NSPS rules. (Slide 15) This slide shows the units that we expect to be covered by the emission guidelines, so our State Plan and the rules that we're developing. These are all coal units. Some of them co-fire natural gas already in the baseline. What we're showing here in the three blue columns on the right, the far left column in the 7 lighter blue color is showing the baseline, or business-as-usual scenario implementing the Carbon Plan under the P3 Fall Load Forecast that was filed in January of last year. Then the middle column titled “Most Likely Subcategory” is showing the most likely subcategory that we think these units would fall within with the Clean Air Act Section 111 standards applied. As shown, we're not seeing a lot of change between the baseline and the Most Likely Subcategory for these coal units covered by the emission guidelines. There may be some change for the Cliffside units, where it looks like Cliffside Unit 6 (the newest unit) may become a base-load natural gas-fired unit. We're not seeing a lot of change from the Section 111(d) standards, in terms of the subcategory that the units would fall within. (Slide 16) This is a graph showing, from a high level, the CO2 emissions under the P3 Fall Baseline (purple line), and then the baseline with the Section 111 standards (blue line). You can see that up until 2031, the lines follow very closely together. We see some divergence beginning in 2031, where the Section 111 case shows higher emissions than the baseline, where the lines are diverging. Likely this is because those NSPS Phase 2 standards begin in 2032, so that's when those units would need to shift to less than 40% capacity factor, and that generation is displaced to other units. (Slide 17) I'll hover on this graph for just a little bit because I know there's a lot going on here. This shows the difference between the Section 111 Sensitivity Analysis and the baseline, and it's showing the generation by resource type. Everything above the zero line, so all the positive bars, are showing where there is more generation of that type in the Section 111 Sensitivity than there is in the baseline. For example, in 2033, the graph shows more coal and more natural gas from steam EGUs under the Section 111 Sensitivity Analysis than there is in the baseline. It is also showing less natural gas from combined cycle (CC) units and combustion turbines (CTs), and a little bit of some other resource types. So this graph shows the changes to the generation mix across the system between those two cases (the Sensitivity Analysis with Section 111 Rules, and the baseline without 111 Rules applied). Again, both the Clean Air Act Section 111(b) and 111(d) Rules are included in this Sensitivity Analysis. EMC Chair Solomon: Crazy slide. Commissioner Ellison: Can you go back just a second? Katherine Quinlan: Yes. Commissioner Ellison: Okay, thank you. Katherine Quinlan: (Slide 18) So now I'll go over a high-level outline of the draft rules that we're developing. We're looking at putting forward six new rules under a new section, 02D .2700. Overall, the outline is similar to what you would see in other sections of Air Quality rules, but there are a few rules that might be a little different than what we're used to seeing, so I'll talk about those just a little longer when we get to those slides. (Slide 19) The first rule is very standard and covers the purpose and applicability of the rules. I'll note one provision that we're looking at adding here is something we've used before for the draft Clean Power Plan rules, to provide a sort of “backstop,” such that if the federal rule Emission Guidelines are stayed, withdrawn, or otherwise rendered of no force at the federal level, whether it is all or only a portion, then that action would have the same effect on these state rules. (Slide 20) We’ll also have a rule with definitions, taking the same ones from the Emission Guidelines, and also defining the subcategories since we will use those terms throughout the State rules to make it clear where all of the units fall. (Slide 21) For the rule with the standards of performance, we are looking at providing the individual EGU emission limits in this rule. First, for each coal unit that we saw earlier in the table (on slide 15), we've 8 determined the baseline, and calculated what the unit’s medium-term limit would be, accounting for any co-firing in the baseline, and we've also calculated what the unit’s long-term limit would be. This rule would lay out the different possible standards for each unit, based on the unit’s potential subcategories. Also, we will put into this rule the natural gas-fired and oil-fired emission limits for all of the different load subcategories that we saw earlier (on slide 10), and as well as provisions allowing the EGUs to apply for alternative-form emission limits in lieu of the individual EGU limits for just coal-fired units. That includes an aggregate rate-based emission standard, which is essentially an average across multiple EGUs that are in the medium or long-term coal subcategories. This is allowed by the Emission Guidelines, and it would allow the EGUs to apply to the DAQ for an aggregate emission standard and propose an averaged rate, and we would review that proposal and gather any additional information we need to ensure that it complies with the requirements, and incorporate that aggregate emission standard into a State Plan or State Plan revision for approval by EPA. The Rule would also include a provision that allows the EGUs to apply for a less stringent standard of performance using the RULOF provisions that are in Subpart Ba and Subpart UUUUb. This would follow a similar process where the facility would apply for this alternate standard, and then the agency would need to review and approve that proposal and incorporate it into a State Plan or State Plan revision. (Slide 22) There are also some compliance flexibilities that are allowed under the Emission Guidelines that we are looking at incorporating into a rule titled “Compliance Flexibilities”. One is a short-term reliability mechanism. This provides that the coal-fired EGUs may exclude from their compliance calculation for a given year the CO2 emissions that occur during periods of operation that are used to maintain electric service reliability during a system emergency. I think of this mechanism as addressing an acute emergency, such as a storm event or something along those lines. The second bullet point outlines a reliability assurance mechanism. This allows for an extension of up to one year for operation of an affected EGU that is necessary for electric grid reliability. This is more of a planning reliability assurance mechanism. Then the third bullet point pertains to an EGU that needs to install add-on control technology and is unable to meet their control standard by their compliance date due to circumstances beyond the owner or operator’s control. This provision would allow this EGU to apply for up to one year of a compliance date extension to meet that standard. They must make a demonstration of the progress they've already achieved and identify those circumstances necessitating the additional time required. (Slide 23) The monitoring, recordkeeping, and reporting is fairly standard. I'll note there are some milestone reports that are required from the medium-term EGUs, including an initial milestone report no less than five years before the planned retirement date, then annual milestone reports each subsequent year, and a final milestone report no less than six months after the permanent retirement date. These are intended to essentially ensure that the facilities are completing milestones towards achieving the retirement dates for each EGU. Additionally, there is a requirement in the Emission Guidelines that we are proposing to incorporate into our rules, where the EGUs must maintain a publicly accessible Carbon Pollution Standards for EGUs website and post, for example, these reports, and other information needed for the public to see how they are achieving progress towards and compliance with these rules. There is also a requirement for the DAQ to have their own website that points to the EGUs’ website(s), which we can do. (Slide 24) The last rule of this Section is a little bit different from what we would normally put in a set of rules for Emission Guidelines. This rule would require the EGUs to submit information needed by the DAQ to prepare our State Plan. The last few slides have laid out the various options for different standards that would apply to the EGUs, depending on which subcategory the EGU falls within; however, the Emission Guidelines require that the State be more specific in their State Plan, actually choosing a specific subcategory and certain compliance pathway for each EGU. This rule would essentially have the 9 owners and operators of those EGUs narrow in on that specific information and submit it to the DAQ. We would review it, look at which subcategory they're proposing for each EGU, what the retirement date is, whether they plan to install any add-on control technology or change the fuel type, and other things of that nature. We will review that information, ensure that it complies with the rules, and then incorporate those materials into a State Plan and submit it to EPA for review and approval. Upon EPA approval, those resulting provisions of the State Plan would be binding upon the affected EGUs. (Slide 25) Now I'll cover a few slides with an overview of the approach for the fiscal analysis that we're developing right now. The objective is, as always, to identify the potential effects of this set of rules, (i.e., the Clean Air Act Section 111(d) rules), on the regulated EGUs, including any costs and changes in emissions. Our approach is to review Duke Energy’s Section 111 Sensitivity Analysis that was filed as part of the CPIRP and determine the most likely compliance pathway for each EGU. Our baseline, as I covered before, is the CPIRP P3 Fall Load Forecasts, and then the “policy” scenario is that Section 111 Sensitivity Analysis layered on top of that P3 Fall Base Case. As best as we can, we are trying to distinguish the impacts that are likely resulting from the Section 111(d) Rules from those that are more likely attributable to the Section 111(b) Rules. It's a very difficult thing to do, but we are reviewing that data and making those distinctions as best we can while noting all of the uncertainties and caveats to any of those conclusions. Then we'll summarize the estimated impacts on the mix of electricity generation, fuel usage, emissions, and the present value of revenue requirements that was presented in the CPIRP 111 Sensitivity Analysis. Then as usual, we'll estimate the climate and health benefits using the social cost of carbon and EPA’s Co-Benefits Risk Assessment (COBRA) tool for any collateral emission impacts. (Slide 26) There will likely be some additional cost to both the private sector and state government for tasks such as developing, submitting and reviewing those milestone reports, updating the EGUs’ Title V permits, and developing and maintaining EGU websites as necessary. (Slide 27) So as mentioned, we're still reviewing the CPIRP 111 Sensitivity Analysis, drafting the rules which are under review right now, and working on the fiscal analysis. We're also planning our outreach and meaningful engagement. We plan to finalize the rules and the fiscal note and conduct that outreach to stakeholders in the coming months. (Slide 28) Here's an updated timeline for this rulemaking. At this point, we are planning to bring the draft rules and the fiscal analysis back before the AQC for an action in March. If we received that approval, we would proceed to the EMC in May. All of this has us on track to have a rule effective possibly in either November of this year or January of next year. As mentioned earlier, the State Plan is due to EPA by early May of 2026. Once the rules are effective, we would then need to incorporate those State Plan materials into the State Plan, which has its own comment period. Then, we must address those comments and submit it to EPA by May of 2026. (Slide 29) There's our contact information, and with that, I can take any questions. Chair Carter: Anyone? Go ahead. Commissioner Ellison: Yeah, I have a couple questions. The reliability assurance mechanism, who set that one year as the extension period? Katherine Quinlan: That is specified in the Emission Guidelines. The State can allow up to one year under that specific mechanism. Commissioner Ellison: That's a maximum set by EPA that the State is allowed to take advantage of? Katherine Quinlan: Yes. 10 Commissioner Ellison: Okay. You mentioned that Duke said in their Utilities Commission documents that that CCS is not feasible in North Carolina. What was that based on? Katherine Quinlan: I'm not sure that I can speak to the basis of Duke’s conclusion, but I know that we have also conducted some research into the feasibility of CCS. Although I am not a geologist, my understanding is that the geology of North Carolina doesn't support the storage component of CCS. Looking at whether there are other potential options for transporting the CO2 or anything along those lines leads us into a large discussion about feasibility. These are large quantities of CO2. So it’s something we're continuing to look at, but that is the understanding that I've come to have. Commissioner Ellison: Okay. Where is North Carolina on the Carbon Plan reductions? Are we on track with all that in general? Katherine Quinlan: I'm not sure that I have that in front of me. I know that emissions have been decreasing as we move towards other fuels and more renewables. I believe that they are continuing to decrease, but I don't have that in front of me. Commissioner Ellison: Okay, that's fine. You had indicated, I think it was $600 million in costs to Duke. Was that all just compliance costs or was that capital investments, and do you know what was in that amount? Katherine Quinlan: Let me go back to that slide referring to this $600 million at the end of that blue quote there. Commissioner Ellison: I'm looking for it. Yes. Katherine Quinlan: It mentions the total system cost of more than $600 million. I haven't pulled apart what might be included in that, but I would imagine it's everything needed to operate the system under that scenario versus the baseline. Commissioner Ellison: Okay, so then do you know if that would be passed on to the rate base? Katherine Quinlan: Not sure that I can speak on rate cases or how those costs are recovered. Commissioner Ellison: What happens if you don't meet EPA’s deadline for the State Plan? Katherine Quinlan: Under the State Plan implementing regulations under Subpart Ba, which were revised back in November of 2023, EPA has 12 months from the date that either a state fails to submit a State Plan, which would be that May 2026 deadline, or if EPA makes a finding that the State Plan is not adequate, they are on a 12-month clock to develop a Federal Plan. If EPA develops a Federal Plan, then that essentially is similar to a State Plan, but it's developed by EPA. It goes into 40 CFR Part 62, and the EPA develops their own standards under that Federal Plan, and the sources have to comply with that once that's finalized. The State can also take delegation of that Federal Plan if they choose to do so. Essentially, that Federal Plan would then apply to the EGUs until the State gets an approved State Plan in place. Commissioner Ellison: Okay, so back to the reliability assurance. I'm sure Duke has thought this through in their submittals to the NCUC, but there’s a concern with the increase in the data centers, increased demand, and issues of reliability. I'm just wondering how the rule you're working towards is going to potentially decrease reliability. Is that a consideration? Is that something you're looking at or the regulatory impact analysis (RIA) would address? Katherine Quinlan: We certainly are cognizant of reliability, as it's very important. Reliability is one of the main things that the Utilities Commission is looking at when reviewing the CPIRP and making decisions at that level regarding what types of resources should be planned for and built. I believe that is one of the main concerns of the NCUC and the NCUC Public Staff. I can't speak to whether these rules 11 would change that, but there are some mechanisms in the Emission Guidelines intended to add some flexibility where it's needed for reliability. Ultimately, the NCUC still has purview over what resources get built and planned for in the future. Commissioner Ellison: Understood, but would your RIA analyze reliability issues that could be challenged by these regulations? Katherine Quinlan: My best understanding at this point is I think it will certainly acknowledge the trade- offs of different resource types in terms of how they may impact reliability. But I don't believe that my first thought is that these 111(d) rules would not necessarily impact reliability. As we saw in the Sensitivity Analysis modeling, the 111(d) Emission Guidelines are not having much of an impact on the retirement schedule of the coal units, at least in terms of what subcategories they fall within. If there is an impact from the NSPS, that's already being implemented directly through EPA. Those wouldn't necessarily be in our RIA, but we can certainly acknowledge them and then talk about them to the extent that they affect or are part of this analysis. Commissioner Ellison: I think they should be mentioned to some extent, and as I mentioned when this was first brought up and the Chair mentioned, this is EPA’s third or fourth bite of the apple and they've been shot down every time. I'm not really expecting a lot of this to go through and I don't think it's a good idea to be as aggressive as you seem to be. I know you're trying to comply with EPA requirements and all that, but no matter what the new Administration does, this is going to end up in court. That's just my opinion. Thank you. Katherine Quinlan: Thank you. Chair Carter: Commissioner Bailey. Commissioner Bailey: Excuse me for being late, but I'm driving up from Carolina Beach, so sometimes I get into traffic jams. Anyway, so with the Utilities Commission, there's goals set for 2030 and 2050, and Duke has to meet those no matter what, as long as the law stays the way it is. Is this just telling them how they can meet those goals? I'm just trying to get a big picture because we're talking about reliability, how are they going to do it, and we're putting all these rules in place, but they still have to get it done even if these don't get passed is how I'm seeing it. Katherine Quinlan: Good question. One thing I will point out is that House Bill 951 required the Utilities Commission to take all reasonable steps towards achieving the 70% emission reduction levels by 2030. My understanding is that there were some provisions allowing for delays in that 2030 date if needed to achieve any of the other objectives on the screen there (slide 12), so affordability, reliability, and/or executability. My understanding is that it's not an absolute that they must meet 70% Interim Target by 2030, and in fact, I believe that the Interim Target date has been pushed out in the latest CPIRP to a later date. My understanding is that the current trajectory of the P3 Fall Base is achieving that 70% reduction by 2035. You're right that there's already something in place, or rather that this CPIRP is already identifying pathways towards achieving that Interim Target by 2035 now, and then also carbon neutrality by 2050. The CPIRP is meant to identify the pathway towards getting there, so yes, the CPIRP is already putting them on a pathway towards achieving these goals. Because these rules have come out, the NSPS must be implemented on those new units that it applies to, and then we have to develop a State Plan, or EPA develops a Federal Plan. These 111 rules are adding another layer on top of that. Commissioner Bailey: Is the other layer, I mean, it's a layer, but how much is it changing what they need to do? Every year they must file annual reports to the Securities and Exchange Commission basically saying this is how much it's going to cost to comply with these laws that are in place in North Carolina. 12 They're already predicting costs, which you can probably put into the RIA. How much of a layer is this actually? Katherine Quinlan: That's what we're trying to figure out in our analysis, and that's what our analysis is looking at, to determine the effects of this layer. There is already a trajectory in the baseline towards achieving reductions. So, is this having little effect, or is it having a lot of effect? That's what we're trying to decipher, and that's what the 111 Sensitivity is also looking at, to determine if there is an effect, or if these reductions are largely already being achieved by the CPIRP because that's in the baseline and our business-as-usual scenario. We are trying to figure out which it is, and that's actually why we are looking at the Section 111 Sensitivity as compared to the P3 Fall Base, in order to have that as our baseline so we can look at the difference between those two scenarios. Some of these graphs show preliminary results of that analysis. Commissioner Bailey: Well, there is a lot of information out there because they're publicly traded. Katherine Quinlan: Okay. Commissioner Bailey: It should help with the RIA. Thank you. Katherine Quinlan: Thank you. Commissioner Smith: A couple of things. I think one is related to that one graph that shows the baseline and then the baseline with 111, if you could go back to that. Katherine Quinlan: This one? (slide 16) Commissioner Smith: Yes, thank you. Essentially, you come out at the same place in the long-term, and the question is whether there is inevitably some “bump up” in that one period between 2030 and 2035/2036 because they're having to adjust their sources to comply with Section 111. We're not talking about an ultimate difference. We're talking about what's happening in that interim period. I will say with respect to that interim period, I have some questions about Duke Energy's assumptions too. First, the assumption that capture, sequestration, and storage is not feasible, but also, we've seen this throughout the planning process between Duke Energy and the Utilities Commission under House Bill 951. Duke Energy has put forward a very specific vision of their own of what types of sources they want or need to rely on at certain periods of time. Their selection was not inevitable, and there has been a lot of pushback on the degree to which Duke actually chose to rely on additional natural gas units. I think in looking at the RIA and how these two things fit together, I think it's important to take a really hard look at what those assumptions are. In terms of the relationship between the federal legislation and the activities of the Utilities Commission under House Bill 951, clearly, the Utilities Commission has a responsibility under state law, and they are carrying out that responsibility, which directs them in part to take reliability and cost into consideration. You've got a lot of moving parts here, but the federal rule does not dictate a certain outcome in this situation. There are other adjustments that can be made, both at the Utilities Commission and at Duke Energy, in terms of how the two plans fit together. I think we need to be really careful about taking some of the assumptions at face value. I guess my bias would certainly be in favor of at least getting ourselves in the position to implement the federal requirement. There are other mechanisms at the state level to take the impact of that federal requirement into consideration through the planning process at the Utilities Commission. It's complicated because you've got state and federal laws that weren't developed to mesh particularly well with each other, but you've got flexibility, certainly under the state law, and responsibilities at the Utilities Commission that allow them to take into consideration some things that this Commission typically doesn't have to take under consideration in implementing a federal requirement, that's sort of presumed to have been dealt with at the federal level. My feeling would be there's no downside to getting ourselves in a position to comply with the federal standard and that we 13 need to take a hard look at what the assumptions are about what happens in that discrete period. That really is the only question here. Katherine Quinlan: Okay. Thank you. Chair Carter: Any other of you have something you want to add? Director Abraczinskas: Mr. Chairman, if I may, just to kind of wrap it up because I think we've heard some good comments here. Chair Carter: I've definitely got some comments. I'm in agreement with Commissioner Ellison over here. I don't understand this aggressive schedule, Mike. You got the State Plan effectively in place six months ahead of the due date to EPA and coming back in here with draft rules in March when we know that EPA is going to be taking a hard look at this. I don't think we're going to be anywhere close to being ready to act on draft rules in March, so I think at a minimum that needs to be backed up to May or maybe even July. I think we need to make a significant adjustment, and it looks like you're pouring resources at a rulemaking that's probably not going to go forward for the reasons we know from past history with this whole thing and with the new Administration coming in. I have a real problem with this schedule, and I'm sorry that Chair Solomon is not here because I want to talk to him about this as well. I feel like there's better things you guys could be spending your time on than trying to push this kind of an aggressive schedule. Commissioner Ellison: Regarding CCS and Duke's assumption on that, having evaluated four or five sites and other states, there's really nothing in close proximity to where Duke's generating carbon, where geological storage would be a viable alternative without some sort of massive pipeline. Commissioner Smith: That may or may not be the case, but I think it's worth taking a hard look at for two reasons, not just whether carbon sequestration and storage is a practical possibility for Duke's facilities, which I think is still an open question. There has been a lot of work done in North Carolina by North Carolina universities and other institutions looking at that issue, but also because that is not the only option here. The interplay between House Bill 951 and these federal rules also relies on decisions that Duke makes about what types of sources it chooses to rely on during this period of time, and that is not written in stone. It was not handed down on the mountaintop. In addition to carbon sequestration and storage, there are also decisions to be made about whether they rely more or less on other types of renewables. To make the assumption that inevitably going forward with these 111 standards would require Duke to rely more on existing coal-fired plants, that's just not an assumption I'm prepared to accept at this point. I think there are a lot of decisions to be made by different actors in all this. As far as the aggressiveness of the rulemaking schedule, I'd like to remember the last time we stayed on a rulemaking schedule that the staff put forward. I don't think that's a great risk actually, but it's not aggressive in terms of what the EPA expectation is of the State. I think inevitably we will probably fall off that schedule. We generally do for a variety of reasons and that's fine. I'm not terribly worried about that, but I just think there are assumptions in this process that need to be really examined before we decide to completely abandon or put on hold our obligation to comply with a federal air quality standard. Chair Carter: Well, let me let me be clear. I'm not suggesting we abandon anything, but I am suggesting that we take a more realistic approach on schedule here because even if we move this thing back like I said, even to May or even July, you're still well ahead of the EPA deadline here. I don't disagree with your point that things do slip, but it'd still be several months ahead of that deadline. I don't see any risk in that respect, in coming up with a more realistic schedule for this rulemaking. I'm glad you at least touched on the point about carbon capture, which is that the geology is not the only issue here, it is whether there is technology too. I take your point that the mix of generation obviously has a lot to do with how this whole 14 process moves forward, both for House Bill 951, and ultimately, if there's a Carbon Plan here out of EPA, whatever it takes to meet the obligations there. Anybody else have any further questions? Commissioner Deerhake. Commissioner Deerhake: I just wanted to make sure I understood something in Slide 21, and I know I'm not a committee member, but I appreciate the opportunity to ask. On Slide 21, the bullet stating that an aggregate rate-based emission standard, that is alternative forms of emission limits averaged emission limits across multiple units - are those units within a particular site or statewide units? Katherine Quinlan: The Emission Guideline requires it to be within the same company, and in our case they're all across the Duke system, so it could be any of them. Commissioner Deerhake: Statewide - that to me brings to thought similarity to the approach that we've used for nitrogen oxides (NOx) in the past where we give them a cumulative target for the State, and they have the flexibility across all of the facilities in the State to reach that. Is that correct? Katherine Quinlan: Are you referring to more of an emission cap? Commissioner Deerhake: Right, but it's a similar approach, in that you're able to work across all of your units to achieve your goal, you don't have to do it on a unit-by-unit basis. Katherine Quinlan: Right. In this case, it would not be a mass-based standard or certain amount of emissions; instead, it would be a rate. Of course, it's a weighted average across the units, depending on how much each unit is contributing towards that. It does allow for flexibility to operate units as it is most efficient in order to collectively achieve that rate. Commissioner Deerhake: Right. That type of statewide flexibility proves successful for the NOx standards. To me, it appears that there's adequate flexibility here to achieve the goal of the federal standard but also at the same time, integrate it with the House Bill approach and the House Bill goals. It's not that we're imposing standards on each and every unit necessarily, correct? Katherine Quinlan: They could be individual, but you're right, it could be an average across them. Then of course, the near-term units don't have any emission obligations under the rule at all, just those medium and long-term and then the natural gas and oil-fired units. Commissioner Deerhake: I personally believe that the staff should continue to proceed on the schedule they are because of the amount of time it takes to work through all of these details. We can anticipate what changes might be coming out of this politically, but I would be doubtful that it would be a complete stay on the standards, once again. We had stays with each Presidential change/Administration change, but to me, this particular package seems to be much more accommodating to what they've learned from lessons in the past two Administrations. Katherine Quinlan: Thank you. Chair Carter: Is there anything you want to add because I want to get this last item up as soon as we can. Director Abraczinskas: Sure. Thank you, Mr. Chairman. Great discussion, comments, and points made here. I think that emphasizes our motivation here today to bring this information item and not just jump straight to an action item when we're ready with draft rules and a fiscal note because this is a complex matter. I appreciate Ms. Quinlan for pulling together this summary here today to stimulate some discussion on the complex interactions between two federal programs and the state law, recognizing that we're presenting modeling scenarios with lots of uncertainty in predicting the future 8 to 10 to 12 years out, right? We need to recognize that uncertainty here. The statement was made and it's true that these are moving targets. These are moving baselines. We're going to take a quick snapshot, a picture of the 15 baseline and apply a policy to it to do an analysis, but recognizing as soon as we do that, the picture may change as well. It is very complex, and some great points have been made here. Katie, if you could forward to Slide 28 as we talk about the schedule for just a moment, I'll also just note that we want to acknowledge that most air quality experts in the air quality community would not be surprised if there's some changes made to this federal regulatory framework at some point in 2025. We don't know how, we don't know what might change, and we don't know when. We know that for EPA’s pathways to change, the most firm pathway would be going through the Administrative Procedures Act. That takes time. We just don't have any information at this point to share, and so we want to acknowledge that. That's part of our presentation here today, and some of the remarks that I wanted to make. Great questions about assumptions, reliability, and averaging. These are all great points that we have been discussing for many months internally. Then on the timeline, I want to explain the difference between the last two lines here on this slide, Mr. Chairman, that shows the gap between when a rule might be completed and when the State Plan is due. We did not include all the different milestones and tasks that the Division must take to get us to that deadline by May 2026. The rule is simply a piece of the State Plan. We have to do meaningful engagement. That's an important new piece to this overall exercise that EPA put on the states in this framework, so that must be conducted during that period. A whole additional public process above and beyond what we would do through the rulemaking process has to occur between that November and May time frame as well, so that's why you see a little bit of a longer runway there between November 2025 and May 2026. We just didn't bullet all that out for you all because that's more of a Division action rather than a Commission action. I just wanted to give you a further explanation on that. We'll certainly take all the comments into consideration about schedule, timeline, and who knows what might happen on the federal stage between now and when we next meet as well. We promise to keep you informed and keep the dialogue going with the Chairman and Vice-Chair. Chair Carter: Okay. Thank you, Ms. Quinlan. I don't know what we're going to do about this next agenda item. We don't have time for 38 slides. I know that. Director Abraczinskas: Do you want to defer it to the next meeting? Chair Carter: Yeah, I think we better do that, unless there's some urgent need to do it today. I don't think there is. As I'm just discussing with the Director, we're going to defer the presentation on the PM2.5 Exceptional Events Demonstration. We'll have to do that next time given our timing here. I guess the only other question is did you have anything else you wanted to mention today? Director Abraczinskas: No, Sir. Just want to say Happy New Year, and I'll reserve my remarks for the full Commission tomorrow. Thank you. CLOSING REMARKS AND MEETING ADJOURNMENT Chair Carter: That's fine. Anything else that anybody wants to bring up right now? Otherwise, I'm going to declare this meeting closed, and I guess the Steering Committee will start in 15 minutes. Thank you very much.