Approved AQC Meeting Summary_11May2022

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ENVIRONMENTAL MANAGEMENT COMMISSION
AIR QUALITY COMMITTEE MEETING SUMMARY May 11, 2022 Archdale Building-Ground Floor Hearing Room 11:30 A.M. – 1:00 P.M.

AQC MEMBERS IN ATTENDANCE
Ms. Shannon M. Arata, AQC Chair Ms. Donna Davis Mr. Charlie S. Carter, AQC Vice-Chair Ms. Marion Deerhake
Ms. Yvonne Bailey Ms. Maggie C. Monast OTHERS IN ATTENDANCE
Ms. Robin Smith, EMC Chair Mr. Mike Abraczinskas, DAQ Director
Ms. Pat Harris, EMC Ms. Christina Cress, Bailey & Dixon, LLP
Mr. Chris Duggan, EMC Mr. Peter Ledford, NCSEA
Mr. Phillip Reynolds, EMC Counsel DEQ Staff Mr. John McAdams Members of the public PRELIMINARY MATTERS
Agenda Item I-1, Call to Order and the State Government Ethics Act, N.C.G.S. §138A-15 AQC Chair Arata 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 stated.
MEETING BRIEF
During the May 11, 2022 meeting, the Air Quality Committee (AQC) of the Environmental Management
Commission (EMC) heard:
• Concept: Proposed rule revisions to 15A NCAC 02D .0516, Sulfur Dioxide Emissions.
• Action Item: None.
• Informational Item: Two summaries of House Bill 951. Supplementing Existing Regulatory
Processes and Establishing the Carbon Plan to Reduce Carbon Emissions in North Carolina’s Electric
Power Sector, and the Impact on Long-Range Utility Planning.

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Agenda Item I-2, Review and Approval of the March 9, 2022 Meeting Minutes Chair Arata requested approval of the March 9, 2022 Meeting Minutes. Commissioner Bailey made the
motion and Commissioner Monast seconded the motion. The minutes were approved without a discussion by unanimous roll call vote. RULEMAKING CONCEPTS Agenda Item II-1, Revisions to Rule 02D .0516 (557) Chair Arata introduced the presenter, Mr. Bradley Nelson Description:
Mr. Nelson stated that the DAQ is proposing to amend 15A NCAC 02D .0516 to clarify the agency’s position that the use of supplemental fuel to increase the heating value beyond what is needed for
combustion is not a means for compliance with the 2.3 lb/MMBtu sulfur dioxide (SO2) standard. He stated that this rule was adopted in 1976 to attain and maintain the National Ambient Air Quality Standard for SO2. He added that the Environmental Management Commission requested the change to the
rule after the Commission concluded that the plain language of the Rule does not prohibit the use of supplemental fuels, including natural gas purchased from a utility, to increase the heating value of flared waste biogas to enhance oxidation and to endeavor compliance with the standard in a declaratory ruling in November of 2021. Mr. Nelson stated that a work group was assembled from the various branches of the DAQ to discuss potential revisions and to propose a draft rule. In addition, a Regulatory Impact Analysis will be developed and submitted to the Office of State Budget and Management for approval. The DAQ plans to present the proposed rule and Regulatory Impact Analysis at the July AQC meeting. Discussion: Commissioner Monast asked if it was acceptable to use supplemental fuel to increase the heating value, but not more than enough to dilute the sulfur in the gas stream. Mr. Nelson answered that a flare typically
needs 200-300 MMBtu/scf of heat input to achieve proper combustion, however the facility in question is increasing the heat input beyond that to increase the denominator of the SO2 emission rate to meet the SO2 standard. He noted that some supplemental fuel is needed to increase the heat input of the gas that is
being flared. Commissioner Monast asked if there were any other facilities or businesses that would be affected by this proposed change to the rule. Mr. Nelson answered that the DAQ was only aware of one facility that was using excess supplemental fuel. He noted that a similar facility used a control device to
remove sulfur from the waste gas before it is sent to the flare. ACTION ITEMS No action items were presented during this AQC meeting. INFORMATIONAL ITEMS
Agenda Item V-1, House Bill 951. Supplementing Existing Regulatory Processes and Establishing the Carbon Plan to Reduce Carbon Emissions in North Carolina’s Electric Power Sector (Christina
Cress, Bailey & Dixon, LLP) and Impact on Long-Range Utility Planning (Peter Ledford, North Carolina Sustainable Energy Association)

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Description:
House Bill 951. Supplementing Existing Regulatory Processes and Establishing the Carbon Plan to Reduce Carbon Emissions in North Carolina’s Electric Power Sector (Christina Cress, Bailey & Dixon, LLP)
Ms. Christina Cress practices energy law, here representing her client, The Carolina Industrial Group for Fair Utility Rates. Session Law 2021-165 was signed into law on October 13, 2021, better known as House Bill 951 (HB 951). This bill created a 70% carbon reduction goal by 2030 and carbon neutral goal by year 2050. Most utility reductions will come from carbon emissions originating from Duke Energy-owned power generating facilities across the state. The Utilities Commission has already started a robust stakeholder process, holding meetings to achieve the goals set out by this legislation. Duke Energy is submitting a proposal on May 16, 2022 filed with the Utilities Commission. This proposed plan will include four possible portfolio options for the commission’s review. This proposal will be open to stakeholder comments due by mid-July. The Carbon Plan which results from this stakeholder process will
then be approved by the Commission in December this year.
The Utilities Commission will approve a plan which meets the goals of this legislative action and will not diminish the capacity or reliability of the energy grid for North Carolina residents. Ms. Cress summed up
HB 951’s impact on power utilities saying, “the legislation provided the ‘what’, the carbon plan itself will give us the ‘how’.” The Carbon Plan will be reviewed every two years to adjust for changing technologies and other factors.
Ms. Cress received some questions from AQC Commissioners ahead of the meeting today via email. Specifically, Ms. Cress wanted to express her desire to be responsive to the questions and addressed the first concern about the interrelationship with existing utility regulatory processes. Integrated Resource
Plans (IRP) filed by facilities are required by Statute1 for submission to the Utilities Commission for review. The analysis process2 included in the IRP filings will be integral to the iterative process of the new Carbon Plan the Utilities Commission will undertake.
Regarding the enforceability of an IRP filing, the Commission determines if the IRP is acceptable “for planning purposes”, and this decision is judicially reviewable pursuant to NC G.S. 62-5.3 The IRP undergoes two primary regulatory processes to test it; (1) Certificates of Public Convenience and
Necessity (CPCN), and (2) Cost of Service Recovery pursued through a general rate case.
The Utilities Commission recognizes the overlapping nature of the Carbon Plan framework and the IRP process; they have decided to sync these two requirements. Therefore, the year 2022 is devoted to developing the initial Carbon Plan. Additionally, the comprehensive IRP filings4 for Duke Energy has been delayed until September 2023. Lastly, the Utilities Commission will revise Commission Rule R8-60
to reflect the approach of syncing the Carbon Plan with the IRP proceedings.

1 G.S. 62-110.1(c) requires the Commission to develop an analysis of the long-range needs for expansion of electric generation facilities in North Carolina, and Commission Rule R8-60 requires all electric public utilities develop an
Integrated Resource Plan (IRP) and provide details of that IRP to the Commission by way of a biennial report filed in even-numbered years.
2 See slide #8 of the presentation located at: https://edocs.deq.nc.gov/WaterResources/DocView.aspx?id=2309060&dbid=0&repo=WaterResources
3 Law: https://www.ncleg.gov/Laws/GeneralStatuteSections/Chapter62 4 Required under Commission Rule R8-60(h)(1)

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The Utilities Commission has at its disposal Performance Incentive Mechanisms (PIMs) to encourage regulated facilities to take action for carbon reduction among other considerations.5 This is under the
Commission’s performance based regulatory authority.
The rulemaking authority of the Commission will allow them to implement HB 951. An example includes 50% of the remaining net book value of subcritical coal-fired units retired early to achieve the carbon reduction goals of the Carbon Plan. Also, a “on-utility-bill” repayment program for energy efficiency to assist low-income customers. To this point Ms. Cress’s client is concerned about the impact to rate increases to customers which may result from the Carbon Plan’s implementation. Ms. Cress points to the
graph on slide #18 of her presentation to show some cost projections from Duke Energy.
Historically North Carolina has been a leader in the Southeast and was the first to adopt the Renewable Energy & Energy Efficiency Portfolio Standard (REPS). This was passed into law in North Carolina on August 20, 2007, setting out a percent minimum6 for energy utilities to generate electricity from renewable sources (or energy efficiency measures). The Utilities Commission oversees compliance with
REPS and all of the state remains compliant with this legislation. North Carolina will remain ahead of the curve for leading carbon reductions now that HB 951 is law.
Ms. Cress ends her presentation discussing leakages regarding the Regional Greenhous Gas Initiative
(RGGI) rulemaking under consideration in North Carolina. Ms. Cress expressed concern on behalf of her client regarding the leakages, as they expect RGGI will have a net opposite effect in reducing carbon emissions within the state. Ms. Cress contends the HB 951 will be more effective in achieving the carbon
reductions within North Carolina as opposed to RGGI. The goal remains a 70% reduction target by 2030 in the near future. Ms. Cress’s client wishes to express great concern for the broad scope of RGGI impacting industrial co-generators. These sources will be hit twice with the costs of RGGI; (1) significant increase in operational costs as industrial rate payers, and (2) the cost of being an emitter without exemption.
Impact on Long-Range Utility Planning (Peter Ledford, North Carolina Sustainable Energy Association)
Mr. Peter Ledford, General Counsel & Director of Policy of NC Sustainable Energy Association (NCSEA) started his presentation giving an overview of NCSEA’s mission. NCSEA is a 501(c)(3) nonprofit organization that works to drive policy and market development to create clean energy jobs, economic opportunities, and affordable energy for the benefit of all North Carolinians.
Mr. Ledford thanked Ms. Cress for giving an excellent rundown of everything that is in HB 951, and the impacts of the NC Utilities Commission.
He started his presentation indicating that wanted to focus more narrowly on the differences between the
current planning process that we have, the integrated resource planning process, and how things look to be shaping up before the Commission moving forward with the new Carbon Plan. Initially, the Integrated Resource Plan has requirements that are codified in Statute at Chapter 62-110.1(c) In addition, because
this has been on the books for 40-odd years, the Utilities Commission has adopted rules to implement the Integrated Resource Plan Statute. The Carbon Plan, in contrast, was passed into law roughly nine months ago, and the Utilities Commission has not yet had the opportunity to adopt rules to implement it.
He added that the Commission has said this initial Carbon Plan is going to be guided by the existing rules that it has in place for the Integrated Resource Plans, however, they are not going to strictly adhere to those rules. The Commission also said in this order that opened the Carbon Plan proceeding that in 2023, it will do a rulemaking proceeding to examine how the Carbon Plan and the Integrated Resource Plan

5 See presentation slide #16 “Encourage energy efficiency, carbon reduction, beneficial electrification” 6 For coops the minimum is 10% and 12.5% for all other power utility suppliers.

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should be melded together. So, in a lot of ways right now, Duke Energy, interveners, and other Carbon Plan proceeding participants are largely winging it because there are not rules and this has never been
done before.
Also, he indicated that he wanted to highlight that the two planning proceedings really have very big different overall goals. The Carbon Plan is directed at accomplishing these carbon emissions. In contrast, the Integrated Resource Plan, looks into the future to develop and keep a long-range plan for the expansion of generating facilities. By rule, it looks 15 years into the future, examining aspects such as planned plant retirements, how North Carolina will grow, how to meet the load, how the load will change, potential for a hot summer that leads to peaks in the summer afternoon, or cold winters that lead to peaks in winter mornings.
In a lot of ways, they are two fundamentally different planning proceedings. That said, they are not mutually exclusive because you really cannot factor the carbon emission reductions required by the Carbon Plan without looking at those generating facilities and how those will evolve into the future. So,
that brings one of the other major differences, which is that the IRP is completely silent to emissions reductions. The Carbon Plan does put forward the 70 percent reduction by 2030, and the carbon neutrality by 2050, about which the Integrated Resource Plans are silent.
One thing that he also wanted to highlight is the differences in reliability requirements. HB 951 is explicit that the Utilities Commission needs to ensure that any generation changes maintain or improve the adequacy and reliability of the grid, an issue on which the Integrated Resource Plan is largely silent.
However, there are some broader statutes applicable to the Utilities Commission that set reliability as a priority. For example, the Utilities Commission’s Declaration Policy states that we need to have a reliable electric system. In addition, regulated utilities must show reliability when they come in for CPCN to build
new generation facilities. So, there is a slightly different relationship between the two planning processes.
In terms of technologies, the Carbon Plan is very explicit that pretty much everything needs to be considered in the planning process, from generation, the grid, transmission and distribution, grid modernization, energy storage, energy efficiency, and demand side management. The Integrated Resource Planning Statute is broader, only focusing on the need for generation, such as including reserves. The
Rule goes into more detail, requiring the utility to consider both supply-side resources, such as generation and demand-side resources, such as energy efficiency and demand-side management. The Carbon Plan Statute also explicitly calls out for those to be considered.
He highlighted another major difference, which is an issue of purchased or imported power. Obviously, North Carolina has different utilities, with the two Duke Energy service territories, Dominion, and the various cooperatives and municipalities that provide power. However, they are all part of a much broader
grid, the Eastern Interconnect that covers roughly the eastern half of the country. They are interconnected, at times transferring power to neighboring states and utilities, such as the TVA in Tennessee, Santee Cooper in South Carolina, or PJM in Virginia and up north.
The Carbon Plan has no explicit requirements that the Commission consider imported and purchased power. However, the Integrated Resource Plan Statute and Rule both require the Commission to consider pooling power and purchasing power from out state or other utilities in determining the most reasonable
and prudent way forward to obtain the capacity necessary to serve the state.
He ended his presentation by indicating that there are some differences in stakeholder input. The Session Law that adopts the Carbon Plan is vague, but it tells the Utilities Commission that the Plan development must include stakeholder input. The Commission issued a series of orders directing Duke to hold stakeholder meetings and technical working groups. Also, the Commission has held multiple conferences to hear from those associated with the proceeding and participating in those meetings. However, the Integrated Resource Planning proceeding is lighter on stakeholder input. Parties such as Ms. Cress’s

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clients and Mr. Ledford’s organization can intervene and participate as legal participants, but otherwise there is only a single public hearing to solicit the feedback from interested stakeholders.
Discussion: Chair Arata opened discussion section asking Commissioner Carter if he would like to make any
comments since this Committee topic was his idea.
Commissioner Carter asked Director Abraczinskas to confirm his recollection of their short discussion at CAPCA about the set of sources subject to the RGGI Petition. He recalled that Director Abraczinskas indicated that about 95 or 96 percent of CO2 emissions would be from Duke, with the remaining 4 or 5 percent from the other sources listed in the RGGI Petition Appendix. Director Abraczinskas confirmed that about 96 to 97 of the emissions come from investor-owned utilities, and in the RGGI Petition there are other subject facilities, including four industrial, one institutional, two cooperatives, one municipal facility. The investor-owned utilities represent approximately 97 percent of the total emissions profile.
Commissioner Carter recalled that when counting the sources listed in the appendix, the majority listed are in fact the non-Duke facilities of which none are subject to the Utilities Commission jurisdiction. He asked if that is correct. Director Abraczinskas confirmed.
Commissioner Carter stated that it was helpful to see the Carbon Plan and the IRP side-by-side. He asked Mr. Ledford if it’s fair to say that, while there are some differences, they are similar, and the Utilities Commission is positioned to make any adjustments that are needed such that both plans work in a common basis going forward. Mr. Ledford noted that the Commission would be the best one to answer that question, but they have forecasted that they plan to combine the two planning processes into a single proceeding that is done every two years. Mr. Ledford expects that their rulemaking proceeding in 2023
will try to melt the requirements of the two Statutes into a single rule set and proceeding.
Commissioner Carter stated that, unless the Commission adopted some aspect of RGGI, the EMC imposing RGGI adds a third layer, and now all three must work symmetry. He asked for confirmation.
Mr. Ledford stated that he believes that is fair.
Commissioner Monast thanked both presenters and stated that, even though there is not yet a Carbon Plan to talk about, it sounds like the presenters may have an idea about what is coming. She asked if the presenters know if Duke is assuming a carbon price as they think about how to meet the 2030 and 2050 targets in the context of achieving the least-cost resource mix. Mr. Ledford indicated we may know on Monday exactly what and how they are doing the modeling, but he understands they are treating it as a carbon cap as opposed to having a carbon price adder. Ms. Cress indicated that it can’t be answered definitively until the proposal from Duke is seen, and we won’t have clarity until December 31 when the
Utilities Commission makes the ultimate decision in the design and approval of the initial Carbon Plan.
Commissioner Monast asked how compliance with the Carbon Plan will affect the co-pollutants from energy production that are within DEQ’s jurisdiction. Mr. Ledford responded that he is a utilities lawyer and not an environmental attorney, so while he suspects some impact because both are being emitted from the same source, he is not knowledgeable on that issue. Commissioner Monast added that this is obviously an issue that falls within the jurisdiction of several different agencies, and she is struggling to
see the connection, which points to the need for hearing from the relevant agencies and understanding how these things are woven together.
Chair Arata directed the conversation towards Director Abraczinskas.
Director Abraczinskas responded that he thinks it very much depends on the makeup of Carbon Plan and the four potential pathways included in the draft submitted to the Utilities Commission on Monday. The details of those four pathways, such as the mix of coal retirements, new renewables, new wind or modular

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nuclear, or anything else in that new mix, will determine the total amount of co-benefits from pollutants other than carbon dioxide.
Commissioner Monast confirmed that the response was helpful, adding that she would like an update when there is more information. She also added that during the EMC’s RGGI deliberations, one main area of concern was uncertainty around how the Utilities Commission makes decisions. She stated
appreciation for the context on their decision-making process, which gives a fuller picture.
Chair Arata added that when the Commissioners were debating the rulemaking petition, they realized areas of potential overlap and a lot of details that will need to be worked out. Ms. Cress added that Duke Energy might be well-positioned to provide insight on the answer to those questions once a Carbon Plan is filed. This Committee or the Commission may wish to invite folks from the utilities to brief the Commissioners on the Carbon Plan portfolios they will propose on May 16th.
Chair Arata directed to Commissioner Deerhake.
Commissioner Deerhake asked Director Abraczinskas about the interface between the Division and the Utilities Commission as all of this is developing, and if there is a designated contact person for the Utilities Commission conversations. Director Abraczinskas responded that DAQ is already interacting with the Public Staff on all these matters. For example, recent discussions related to HB 951 have been
aimed at getting agreement on the 2005 baseline from which the 70 percent needs to be achieved. Good, productive discussions have occurred between DEQ technical staff and the Public Staff. Similarly, as we have been discussing pathways and different elements of the fiscal note for the RGGI Petition, DAQ will need some assistance from the Public Staff, as briefly mentioned before. There are open lines of communication between DAQ and the Public Staff.
Commissioner Deerhake asked if there is one person as the point of contact or if it will all come to Director Abraczinskas. Director Abraczinskas responded that it does not all come to him. Randy Strait and the DAQ team in the Planning Section are interacting with the Public Staff. Commissioner Deerhake asked if Director Abraczinskas believes DAQ is being included in the conversation well enough at this stage to have an active role in the HB 951 and Utilities Commission planning process. Director Abraczinskas confirmed, indicating that DAQ serves as technical resource for all these efforts, with some unique skillsets that lend itself to these processes.
EMC Chair Smith asked a couple of questions about implementation and enforcement, with the first question for Director Abraczinskas, and then a follow-up question for the presenters.
EMC Chair Smith asked for confirmation from Director Abraczinskas that the DAQ would have to come into the process to revise any permit to reflect different emission limits or other resulting changes, depending on the Plan and the extent to which there are changes in sources that affect air quality
permitting. Director Abraczinskas confirmed that as a reasonable anticipated outcome of the HB 951 process.
EMC Chair Smith then directed a question to the presenters. She stated her understanding that,
previously the Utilities Commission focused on the need for generating facilities, and then reasonable costs (i.e., rates). Environmental standards were built into the background but not part of the Utilities Commission process. Therefore, to the extent that utilities had to comply with environmental standards, that was built into the reasonable rate evaluation. She asked for confirmation. Ms. Cress added one nuance. The beginning of Chapter 62 of the General Statutes contains policy goals and overarching policy considerations that the Utilities Commission is to consider, and there are environmental concerns that the Utilities Commission considers based on the policy delineations therein. Ms. Cress largely agreed with that the focus is primarily on the need for that new increment of generating plant, and then the least-cost resource to fill that need.

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EMC Chair Smith asked how there will be adequate tracking and enforcement of these goals, recalling that there are not new enforcement mechanisms on a year-by-year or every-two-year basis. There is an
ultimate deadline, with some discretions on the part of the Utilities Commission to extend that deadline for certain reasons, but nothing that would provide clarity about holding to specific interim goals or enforcement mechanisms. She asked if the method of getting from point A to point B, and how those
reductions are implemented, is still vague.
Ms. Cress stated that she believes the Legislature intended the Utilities Commission to figure out those details, with the goal of giving the Utilities Commission as much discretion as possible to develop and approve its own Carbon Plan this year. She expects that the Utilities Commission will have various means of tracking compliance, possibly taking the effect of a reporting requirement in addition to the two-year
review proceeding at the Utilities Commission, and certainly that those details will be worked out by the Utilities Commission in their order adopting a Carbon Plan.
Mr. Ledford noted that there are no interim requirements, only the 70 percent for 2030 and carbon
neutrality for 2050 goals. Conceivably, we could see emissions increase in the next couple of years, as long as they come back down to meet the 2030 goal. There are off-ramps and extensions available to the Commission. The Commission has broad authority to compel efficient service from the utilities, but he
agreed that a lot of the reporting and tracking metrics will need to be figured out moving forward.
Chair Arata asked whether there were any other questions.
Commissioner Carter asked Ms. Cress if both RGGI and HB 951 have the same goal or end point, 70 percent reduction by 2030. Ms. Cress stated her understanding that the RGGI states have recently agreed to reduce emissions by an additional 30 percent from 2020 levels by 2030. The target that HB 951 sets out actually go much higher than that, requiring a 52 percent reduction from 2020 levels by 2030. Commissioner Carter recalled that the petition that came before the EMC was set at the same 70 percent by 2030 goal. Ms. Cress confirmed and directed to one of her slides, stating that there should be third column because it does not necessarily show what the petitioners have requested in their rulemaking
petition.
Commissioner Carter agreed with Ms. Cress and directed a question to Mr. Ledford, asking if his mention of off-ramps is suggesting that the Commission could design a plan that would not meet the 70 percent goal by 2030, and if there were an off-ramp that would allow them to go beyond.
Mr. Ledford confirmed that the Commission has significant discretion. Some things are set forth in Statute, such as extension of compliance deadlines if there is an offshore wind project or a small modular reactor that requires additional time for permitting. They also have other abilities to extend or delay the compliance deadlines based on reliability, costs, or other factors. Ms. Cress expressed a different
interpretation, which that the Utilities Commission has the authority to extend the 2030 compliance date for any reason up to 2032. It can extend beyond that if small modular nuclear reactors, or new nuclear, or new wind is selected by the Carbon Plan as a least-cost resource for meeting those carbon reduction goals.
The reason for that is quite simply that Duke Energy wouldn’t be able to construct those facilities and the needed transmission to interconnect those facilities with enough time to get them online and placed into service by the end of the decade.
Chair Arata asked if they have any sense of how this planning process might affect the forecast demands that you might see in the regular planning process, in terms of customer load. She added that she is an environmental attorney, not a utilities attorney, but her understanding of the forecasted demand is that it’s not only a matter of how many more people might live in the state, but also dependent on other factor such as conservation and energy efficiency. Ms. Cress responded that, although this might be better addressed by Duke Energy, she believes they are seeing trending load growth and increased load over

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time, and this is going to be even more true as electric vehicles continue to grow in terms of market share. She believes projections for the rest of the decade are showing continued increased load growth.
Mr. Ledford responded that the Commission is required to consider energy efficiency, which can reduce load, and demand side management, which would be things like a switch that turns off your air conditioner for 10 minutes on a very hot day, which can reduce that absolute peak load. Load is growing in North Carolina, due to the State’s growth and vehicle electrification, as examples. Mr. Ledford stated that the question is, will that natural growth and the electrification of various things outweigh what we could save through efficiency and demand-side management, and to what extent? The Commission is going to need to consider both. We do have things that are pushing load to increase, but there are also ways of pushing load down, and it will be a matter of how it falls out.
Chair Arata asked if there is any sense of how much the already-planned coal-fired utility retirements will factor into meeting the goals under the Plan?
Ms. Cress stated her understanding that the HB 951 retirements will be clarified as retirements that are
accelerated ahead of their economic retirement dates for the purpose of meeting HB 951 goals. The two will be clearly delineated as to whether a retirement is happening at its economic retirement date, regardless of what carbon emissions targets were in HB 951, or retirements that were fast-tracked and
moved ahead to a non-economic retirement date to comply with the Carbon Plan.
Chair Arata asked for any further questions. None were raised. Chair Arata thanked the presenters for summarizing the process of the Utilities Commission.
Agenda Item V-2, Director’s Remarks (Mike Abraczinskas, DAQ)
The Director indicated that Deputy Director, Michael Pjetraj will be covering his duties, and giving Division
updates during the EMC meeting.
CLOSING REMARKS AND MEETING ADJOURNMENT Chair Arata noted the next meeting of the AQC is scheduled for July 13, 2022 and adjourned the meeting.