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2023-04-11 AEA Agenda and docs
813 West Northern Lights Boulevard, Anchorage, Alaska 99503 T 907.771.3000 Toll Free 888.300.8534 F 907.771.3044 REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG Alaska Energy Authority Board Meeting Tuesday, April 11, 2023 8:30 AM AGENDA Dial 1 (888) 585-9008 and enter code 212-753-619# Public comment guidelines are below. 1. CALL TO ORDER 2. ROLL CALL BOARD MEMBERS 3. AGENDA APPROVAL 4. PRIOR MINUTES – March 1, 2023 5. PUBLIC COMMENTS (2 minutes per person) see call in number above 6. NEW BUSINESS A. AEA Cash and Investments 7. OLD BUSINESS A. SSQ Line Update 8. DIRECTOR COMMENTS A. IIJA Update i. Grid Resiliency and Innovation Partnerships (GRIP) Update ii. National Electric Vehicle Infrastructure (NEVI) – Presentation B. FY24 Budget Update i. CASR Report C. Governor’s State Energy Security Task Force D. Rural Update E. Denali Commission Update F. Power Project Loan (PPF) Update G. Renewable Energy Fund (REF) Program Update H. Update on Trip to Unalaska and Project I. Legislative Update J. Cook Inlet Gas Supply K. Community Outreach L. Articles of Interest M. Next Regularly Scheduled AEA Board Meeting Wednesday, May 24, 2023 9. BOARD COMMENTS 10. ADJOURNMENT Public Comment Guidelines Members of the public who wish to provide written comments, please email your comments to publiccomment@akenergyauthority.org by no later than 4 p.m. on the day before the meeting, so they can be shared with board members prior to the meeting. On the meeting day, callers will enter the teleconference muted. After board roll call and agenda approval, we will ask callers to press *9 on their phones if they wish to make a public comment. This will initiate the hand-raising function. Alaska Energy Authority Page 2 of 2 We will unmute callers individually in the order the calls were received. When an individual is unmuted, you will hear, “It is now your turn to speak.” Please identify yourself and make your public comments. 813 W Northern Lights Blvd, Anchorage, AK 99503 Phone: (907) 771-3000 Fax: (907) 771-3044 Email: info@akenergyauthority.org REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG Alaska Energy Authority DRAFT BOARD MEETING MINUTES Wednesday, March 1, 2023 Anchorage, Alaska 1. CALL TO ORDER Chair Pruhs called the meeting of the Alaska Energy Authority to order on March 1, 2023, at 8:31 am. A quorum was established. 2. ROLL CALL BOARD MEMBERS Members present: Chair Dana Pruhs (Public Member); Vice-Chair Bill Kendig (Public Member); Albert Fogle (Public Member); Adam Crum (Commissioner DOR); Julie Sande (Commissioner DCCED); Bill Vivlamore (Public Member); and Randy Eledge (Public Member). 3. AGENDA APPROVAL MOTION: A motion was made by Vice-Chair Kendig to approve the agenda, as presented. Motion seconded Mr. Fogle. The motion to approve the agenda passed without objection. 4. PRIOR MINUTES – January 18, 2023 MOTION: A motion was made by Mr. Fogle to approve the prior minutes of January 18, 2023, as presented. Motion seconded by Vice-Chair Kendig. The motion to approve the minutes of January 18, 2023, passed without objection. 5. PUBLIC COMMENTS (2 minutes per person) There were no members of the public online or in-person who requested to comment. 6. NEW BUSINESS A. Cook Inlet Gas Supply Challenges – Overview and Discussion i. 2022 Cook Inlet Gas Forecast Presentation to Senate Resources Committee ii. DNR 2022 Cook Inlet Gas Forecast Alaska Energy Authority Page 2 of 10 iii. Railbelt Electric Energy System and Energy Transition Presentation Curtis Thayer, Executive Director and Secretary-Treasurer, informed that the Board packets under 6A. contain three documents: the Alaska Department of Natural Resources (DNR) 2022 Cook Inlet Gas Forecast presentation to the Senate Resources Committee, the DNR Cook Inlet Forecast, and the Railbelt Electric Energy System and Energy Transition presentation to the Senate Resources Committee. Mr. Thayer commented that the Gordian knot challenges of not having enough gas supply or potentially not having enough gas supply under contract in the Cook Inlet have occurred over the past 15 to 20 years. Mr. Thayer explained that the State has pulled many different levers, including incentives. The gas purchase contract is between the producer and the gas company on the Railbelt. The Regulatory Commission of Alaska (RCA) approves the contract. AEA does not have statutory or regulatory ability regarding the gas supply issue in Cook Inlet. Mr. Thayer discussed that AEA has become a more active observer, as he has been working with the utilities, the Governor’s Office, DNR, and RCA in understanding the challenges. Mr. Thayer noted that DNR says that there is gas in the Cook Inlet, but there are not producers to produce the gas. He gave a brief overview that for seven years in the early 2000’s, the RCA never approved a gas contract. The result of this was that the big producers left Cook Inlet, and the plant and export facility closed. This greatly impacted the utilities. Mr. Thayer discussed that there are currently three producers in Cook Inlet: Hilcorp Alaska, Hex LLC, and BlueCrest. These companies are very small compared to the large companies, such as Marathon and Conoco, that previously operated in Cook Inlet. Mr. Thayer explained an aspect of pricing. He noted that the State entered into an agreement with BlueCrest regarding their base contract, which was higher than it was in the past. The utilities requested Henry Hub pricing from RCA, and RCA rejected the request, which put into question the value of Cook Inlet gas and investment returns. The State stepped in and spent a billion dollars in tax credits. Subsequently, the State vetoed the tax credits. This changed the economics of pending gas supply contracts between utilities and producers. As a result, the pending contracts dissolved. Mr. Thayer informed that Homer Electric Association (HEA) is in the most immediate need within two years. Enstar’s need is the furthest out, due to their gas storage ability. Mr. Thayer discussed his understanding is that the utilities are working with the producers in Cook Inlet to extend gas production beyond 2030. This plan would have to be approved by RCA. Mr. Thayer commented that any type of progression into renewables would include the transitional fuel of natural gas for the next 20 years. He discussed the need for transmission line upgrades in order to access additional renewable energy. Mr. Thayer continued the discussion noting that the Fairbanks gas utility is currently reviewing contracts to ship liquefied natural gas (LNG) directly from the North Slope to Fairbanks, thus bypassing Cook Inlet. He commented on discussions by the four utilities regarding solutions that Alaska Energy Authority Page 3 of 10 include a natural gas pipeline off the North Slope. These types of discussion have occurred for years, but no decisions regarding projects have been made. The utilities are also discussing the possibility of using the Marathon plant as an import facility for Cook Inlet. The cost would be borne by consumers. Mr. Thayer noted that he will keep the Board informed regarding the continued discussions among DNR, RCA, and the utilities. He believes that utilities may soon announce small contract extensions. Commissioner Crum commented that the presentation to the Senate Resources Committee on January 30th is worthwhile following. DNR has been tasked to put forward the current tax regime of Cook Inlet compared to other fiduciaries around the state. He noted that the Legislature is evaluating the tax regime within the review of the overall need of getting energy to the Railbelt. Chair Pruhs expressed appreciation to Mr. Thayer for the presentation. He discussed his understanding of the Cook Inlet issue with supply and demand, and that one company is controlling 80% to 90% of the gas supply. Chair Pruhs commented that he would like to focus on the future to support that the money spent by the State and the money spent on required projects ties into the maximum benefit for the rate payer. He discussed the recent $160 million of bonding for upgrades between Anchorage and Homer. Chair Pruhs reiterated that he wants to ensure that the money spent to develop the Intertie system is spent efficiently. He requested that AEA is kept apprised of the utilities’ plans and how it connects to the capital project plan to help the Railbelt utilities. Mr. Thayer explained that AEA’s ownership of the Alaska Intertie’s 170 miles from Willow to Healy saves the Fairbanks community $35 million to $40 million a year, which exceeds PCE. This means that it is cheaper for the community to buy power on the Railbelt than it would be for Fairbanks to produce power. Chair Pruhs discussed the single line to Fairbanks from a dynasty standpoint. The single line becomes increasingly critical as Fairbanks continues to rely on Southcentral gas and power supply, and at some point, will determine whether or not there should be a second line or redundancy for long-term planning. Chair Pruhs opined the scenario of what would happen if the single line became inoperable. Mr. Thayer commented on AEA’s mission to lower the cost of energy. He suggested that the mission going forward could include having safe, reliable, and redundant power at a low cost. Mr. Thayer discussed that redundancy is necessary and costs are incurred when lines are added. Vice-Chair Kendig commented that reliability is just as important as affordability. Chair Pruhs expressed his hope that the cost of utility bills do not double in five years. He noted that the mission statement and the valuable suggestions to revise the mission statement could be reviewed during the August strategic planning retreat. Chair Pruhs requested that AEA is kept apprised of the ongoing discussions and asked Commissioner Crum to provide Mr. Thayer with any pertinent information. Commissioner Crum agreed, and explained that the Cook Inlet gas Alaska Energy Authority Page 4 of 10 supply issues and challenges are complex. There were no additional questions. 7. OLD BUSINESS - None 8. DIRECTOR COMMENTS A. Annual Report Mr. Thayer noted that included in the Board packet is the 2022 Annual Report that was produced entirely in-house. It was sent to the Legislature yesterday. Chair Pruhs commented that the Annual Report is very nice. Mr. Thayer informed that the front picture is the South Fork Hydroelectric Plant, a small hydro project in Eagle River owned by a husband-and-wife team. AEA financed the hydro expansion, which provides power for 800 homes. The power is sold through MEA. Mr. Thayer noted that he could schedule a field trip to tour the facility. Chair Pruhs expressed support. B. PCE Report Mr. Thayer discussed that even though there is not a statutory deadline for the Power Cost Equalization (PCE) Reports, the target date is March 1st. The information in the report is structured by community and includes the average annual PCE payment per customer. The report is provided to the Legislature and to rural Alaskan communities. Mr. Thayer expressed appreciation to Tim Sandstrom, AEA, for his efforts in developing the report while short a staff member. Chair Pruhs asked how the PCE rate is calculated. Mr. Thayer explained that the RCA establishes the PCE rate. It is based on the cost of electricity in Anchorage, Fairbanks, and Juneau. The PCE floor rate this year was approximately 19 cents. The rate is capped in statute at 75 cents for a maximum of 750 kilowatts. The difference between the rate and the cap is what the State subsidizes in rural Alaska. Mr. Thayer complimented the PCE team on the reformat of the payment structure within the organization. The new process controls eliminated the backlog and brought the 300 past due payments current to-date. Mr. Thayer explained that RCA determines which communities are eligible for PCE and AEA follows their direction. Chair Pruhs asked if Southeast Alaska has the least expensive cost of power. Mr. Thayer agreed that Juneau is the least expensive, followed by Anchorage, and Fairbanks. He explained that lowering the cost of energy on the Railbelt lowers the floor rate, which increases the payments to rural Alaska. The current formula is established in statute. There were no additional questions or comments. C. Owned Assets Update Mr. Thayer discussed that the Owned Assets Update includes information about the Alaska Intertie and the Bradley Lake Hydroelectric Project. Removal of the 69 kV Sterling to Quartz Line has begun. The bid came in on budget and remains within budget. Mr. Thayer informed that AEA Alaska Energy Authority Page 5 of 10 bonded $166 million of required project work in December, and 65% of the proceeds are dedicated to transmission work and 35% of the proceeds are dedicated to battery energy systems. Chair Pruhs inquired as to the specifics regarding a target for a reserve amount or for battery hours. Mr. Thayer explained that the Department of Law determined that the battery energy systems are required project work. AEA will provide funding for a certain parameter of the battery system, a base model, and the community must pay for any upgrades or enhancements. AEA will own the base model and the utility will own any upgrades. Mr. Thayer noted that a Tesla system was installed in Kenai. He discussed the possibility of taking a field trip to walk through their battery storage area. This is one of the areas that the Bradley Project Management Committee (BPMC) is reviewing to possibly purchase. Commissioner Crum asked how the minimum aspect and need is determined among the communities and if the negotiation is amicable. Mr. Thayer informed that these types of conversations are new. He commented that the utilities are working well together. Chugach (CEA) and Matanuska Electric Association (MEA) are even discussing the possibility and plausibility of sharing a battery. Mr. Thayer informed that AEA will consider working with Department of Law during the negotiation stage of the arrangements. He reported that the cost of the batteries has continued to increase from the budgeted amount. This is a major cause of concern. Chair Pruhs asked if the rate payers pay for both the base model battery system and any upgrades the utilities select. Mr. Thayer agreed. He explained that each utility has different specifications for their system operations. Mr. Thayer commented that staff is pursuing funding within the Federal Infrastructure Bill to help offset the battery costs for the rate payers. There were no additional questions or comments. D. Railbelt Reliability Council (RRC) Update Mr. Thayer invited Bryan Carey, Director of Owned Assets, to provide the RRC update. Mr. Carey discussed that the RRC is currently undergoing the process with RCA to transition from organizational development to mission work. He informed that the web page contains information and helpful links regarding the RRC. Mr. Carey reviewed the general timeline for activities. Staff is currently seeking initial office space to house the Chief Executive Officer (CEO), who will be hired later this year. The CEO will then hire additional staffing. Next year, the first order of business is the Integrated Resource Plan. The Plan will take approximately two years to complete and will examine all future Railbelt projects and transmission capability. The data will be available to be organized based on different parameters and variables entered. This will provide relevant information regarding different scenarios and combinations of projects. Mr. Eledge asked if AEA developed the algorithms for the Integrated Resource Plan. Mr. Carey informed that in 2010, AEA developed an Integrated Resource Plan in connection to the Susitna Project. The new Integrated Resource Plan will be developed by the RRC, which has 13 Board members. AEA holds one seat on the Board and will be able to provide input regarding what scenarios the Plan will be able to produce. Alaska Energy Authority Page 6 of 10 Mr. Thayer explained that the RRC was established in State statute about three years ago. Its structure and governance has been in development since then. Mr. Carey explained the background of the development of the RRC. He noted that individual utilities build different plants with different generation sources. The intent of the RRC is to provide effective planning and savings for the Railbelt utilities as a whole. The total savings are expected to exceed the cost of the RRC. There were no other questions. E. Renewable Energy Fund (REF) Program Update Mr. Thayer discussed that the REF is in Round 15. There were 33 applicants totaling $31 million. AEA is currently evaluating the applications and will make recommendations to the nine-member Renewable Energy Fund Advisory Committee (REFAC). The REFAC guidelines are set within statute. Within the Governor’s Budget, there is a placeholder of approximately $7.5 million. The final number will not be known until REFAC makes their recommendations to the Governor and to Legislature, who will then make the appropriations. Chair Pruhs asked if there is an average appropriation amount based on the prior rounds. Mr. Thayer discussed that there is not an average. He explained that when the program began in 2010, the goal was $50 million a year for five years, for a total of $250 million. That amount of funding was never achieved and for several years, and during the previous Administration, no funding was given to the REF Program. Two years ago, the round was conducted and utilized $4.7 million of remaining program funds. Last year, the round was conducted with a total of $15 million. Mr. Thayer stated that the application is organized by technology and by region. One of the weighted criteria factors for evaluation is the cost of energy for the applicant community. Approximately 80% of approvals are within rural Alaska. Mr. Thayer discussed that a prior report of the program revealed that the program has saved 30 million gallons of diesel fuel in rural Alaska. AEA has recently contracted with a third-party to conduct an updated evaluation of the program since inception to better identify the success of the program. Results are expected within a few months and will be shared with the Board and with the Legislature. There were no other questions. F. Electric Vehicle Update Mr. Thayer noted that AEA is operating off of the State’s Vehicle Infrastructure Implementation Plan that has been approved by the Federal Department of Energy. A round of requests for applications (RFA) is out for identifying charging station sites along the alternative fuel corridor from Anchorage to Fairbanks. In the future, the rounds will be expanded to include the Kenai Peninsula and the Marine Highway System. A 20% match is required per applicant. Chair Pruhs asked which department identified the corridor from Anchorage to Fairbanks. Mr. Thayer explained that the corridor was determined by the Federal Department of Transportation (DOT) and in coalition with the Federal Department of Energy (DOE). Chair Pruhs asked if it would be advantageous to have electrification in communities that do not have access to a transportation infrastructure. He gave examples of charging sites in Cordova or Valdez. Mr. Thayer Alaska Energy Authority Page 7 of 10 indicated AEA has raised those concerns and other concerns with DOE and with the congressional delegation because the parameters disqualify rural Alaska, including hub communities. The sites for this particular program must be on a federally recognized highway corridor. The phased sections are Anchorage to Fairbanks, Homer to Anchorage, Tok to Glennallen, and the Marine Highway System. Mr. Thayer explained that grants for rural Alaska could be sought via a competitive process with other states. He commented that the size of the electrical chargers for the grants total 600 kV, which is more than some of the rural communities’ power can accommodate. Mr. Fogle expressed appreciation for the update. He asked for information on who will monitor the charging stations to ensure they are active and operational, similar to the inspectors who survey gas stations. Mr. Thayer discussed that the grant agreement contains a requirement that the charging stations are maintained at a 97% operational standard and include a warranty. That information is shared with AEA to include in the grant monitoring that is submitted back to the federal government. Mr. Thayer noted the increase in electric vehicle registration from June 2022 to January 2023, as shown in the included chart. A member asked if the registration information could be delineated by community. Mr. Thayer stated that staff could try to obtain that information from Department of Motor Vehicles (DMV). He commented that it took a very long time to obtain the current information. Mr. Eledge asked if staff has reviewed the potential increases of power generation from charging stations within the hub communities and rural communities that are not connected by the road system. Mr. Thayer agreed that staff is considering those power source issues and concerns, as well as the equipment size requirements versus the community need. Mr. Eledge contemplated the additional amount of power that would need to be produced in the villages to electrify vehicles and to provide charging station services. Mr. Thayer discussed that there are different types of electric vehicle charging station types and technologies that could accommodate locations that do not have three-phased power. However, in the federal program discussed today, those types of chargers are not allowed. Mr. Thayer informed that Alaska is not the only state that has raised these types of issues. Wyoming has similar concerns, and conversations with DOE are ongoing. Commissioner Sande expressed appreciation to Mr. Thayer for proactively sending articles that address these issues. She particularly noted the article about Wyoming and the potential implications for Alaska. Commissioner Sande asked if Mr. Thayer will make suggestions to the Board regarding whether or not Alaska should provide the same response to DOE as Wyoming provided, that the model does not work for Alaska. Additionally, she asked Mr. Thayer to explain the role of AEA within the Governor’s Energy Security Task Force in terms of evaluating information and the strategic plan. Mr. Thayer discussed that the Governor’s Administrative Order (AO) No. 344 establishes the Alaska Energy Security Task Force. Membership will include the Commissioner of DNR, the Commissioner of DEC, the Executive Director of AEA, a representative from the University of Alaska, and nine public members, and five ex officio members. The Governor has not yet named all of the participants and no meetings have occurred. The goal of the Task Force is to develop a statewide and comprehensive policy on energy. Mr. Thayer assumes that Alaska Energy Authority Page 8 of 10 AEA’s role will be to implement the policy as it pertains to AEA. Deliverables are due to the Governor in May and a final report is due in October. The plan will include both short-term options and long-term options that extend out 20 years. Commissioner Sande expressed appreciation to Mr. Thayer for his willingness to participate in that important conversation, as well as AEA’s participation in the subcabinet. She believes that larger conversations regarding PCE are valuable. PCE has been powerful and has helped serve Alaskans well. At the time PCE was created, there were no discussions about renewable energy. One question to consider is if PCE is causing an unintended disincentive to investment and economic development. Additionally, PCE does not serve commercial businesses. She noted that these questions have not been addressed by AEA, and perhaps the Task Force can provide recommendations. Mr. Thayer noted that the Task Force also wants to utilize involvement from the 17 available National Labs for the analysis. There is also a potential role for AIDEA regarding the financing of upgrades. Mr. Thayer commented that it will be a herculean effort. Commissioner Sande discussed AEA’s mission of reducing the cost of energy as it relates to a comment by a representative from DOE regarding the role of proper insulation in rural Alaska to reduce the consumption of energy. Mr. Thayer believes that AEA may host many of the Task Force meetings, and he will keep the Board informed as the process moves forward. He commented that the Governor is currently at Westinghouse reviewing nuclear reactors. Mr. Thayer indicated that no matter what source of power is determined, transmission lines are needed to transmit the power. Chair Pruhs commented that the electric vehicle industry is a new business line in which the State needs to heed caution. The trend indicates there will be additional electric cars, which puts pressure on a different infrastructure that will need possibly substantial investment. He noted that unfortunately, Alaska’s situation is that there is not typically the volume to pay for the infrastructure that is needed. Chair Pruhs supports the creation of an energy policy. He discussed the possibility that on a short-term basis, more electric vehicles on the road will be at the expense of buying less fuel, thus increasing the fuel price for existing cars, as well as stressing the existing electrical infrastructure and increasing the cost of electricity. Chair Pruhs stated this is a balancing act and he wished Mr. Thayer luck. There were no additional questions. G. Bradley Lake Audit Mr. Thayer discussed that the annual Bradley Lake Audit has been completed, which included the SSQ Line and Intertie. The clean audit was presented to the BPMC. Mr. Thayer complimented the Finance Team and Controller. There were no questions. H. FY24 Budget Update Mr. Thayer advised that the information listed in blue within the FY24 Budget was discussed at the January Board meeting as part of the Governor’s $74 million submitted budget. Supplemental Alaska Energy Authority Page 9 of 10 projects are listed in green and include a lump sum for the IIJA State Energy Plan and the Black Rapids Training Site funds, adding $15.6 million to AEA’s budget. The Governor’s Amended Budget listed in orange includes additional funding of $7.5 million for the Renewable Energy Grant Round 15, $74.5 million from the Inflation Reduction Act for home energy performance and weatherization program in concert with Alaska Housing Authority, and $3.7 million for the IIJA Efficiency Revolving Loan Fund Capitalization. The total budget amount is $175.8 million dollars. Mr. Thayer noted this is AEA’s largest budget. He discussed that at the time that the budget was $74 million, AEA requested five new employee positions: two project managers, an accounting position, a procurement position, and a grants administrator. The Governor’s Office is moving forward with those positions on a temporary basis for up to five years. Since the January Board meeting, however, the AEA Budget has accumulated an additional $100 million of responsibility, and does not include the $166 million in bonding responsibility and the $40 million operating budget. Mr. Thayer believes that employee staffing positions will be an ongoing conversation. He gave the perspective that there are State agency departments that do not have this level of budget responsibility. Mr. Eledge commented that the additional responsibility impacts staffing tremendously. He asked how AEA is responding to staffing. Mr. Thayer reiterated that the Governor’s Office is hiring for the five, five-year positions, and that further conversations will occur regarding increased staffing needs going forward, including back-office positions for the accounting and compliance requirements. He showed members a physical copy of the IIJA bill that includes all the funding opportunities available. The Governor’s Office has an IIJA coordinator and applications are submitted to administer the funds available for Alaska. If the funds are competitive, then AEA or a different State agency is selected to complete the application as the lead agency based on time and efficiency. Mr. Thayer reported that of the four Grid Resilience and Innovation Partnerships (GRIP) Concept Papers that were discussed at the previous Board meeting, two of the Concept Papers, GRIP 1 and GRIP 2, totaling $600 million, were asked to advance to the application stage. Only about a third of the submittals were asked to advance. The status of GRIP 3, totaling $500 million, is unknown. These potential funding amounts add another layer to the staffing conversation. There were no additional questions. I. Legislative Update Mr. Thayer announced that he is traveling to Juneau tomorrow at the request of the House and Senate Co-Chairs. He noted that the Legislature has been very supportive. The legislative presentations are included in the packet, along with the summary of conversations engaged with legislative offices. J. IIJA Update Mr. Thayer indicated that the IIJA Update was discussed earlier in the meeting. Alaska Energy Authority Page 10 of 10 K. Community Outreach Mr. Thayer reviewed the Community Outreach report and highlighted the diversified team that has been traveling to different areas of the state is due to the nature of the workload. L. Articles of Interest Mr. Thayer indicated that he sent another article of interest not included in the packet, in which Bill Gates discusses that transmission is key to clean energy. M. Next Regularly Scheduled AEA Board Meeting Tuesday, April 11, 2023 9. BOARD COMMENTS Chair Pruhs thanked Mr. Thayer for his overview and comments. He expressed appreciation to staff for their efforts. Chair Pruhs asked Mr. Thayer if he is aware of any of the specifics regarding the timeline, location, support, and facilitation for the Governor’s AO. Mr. Thayer responded that he does not have any of those specifics. Chair Pruhs commented that AEA is currently short-handed on staff, and he assumes that Mr. Thayer will communicate the lack of resources available. Chair Pruhs thanked the Board members for their attendance and their input. 10. ADJOURNMENT There being no further business of the Board, the AEA meeting adjourned at 9:43 am. __________________________________________________ Curtis W. Thayer, Executive Director / Secretary From: Zrust, Thomas S <thomas.zrust@usbank.com> Sent: Friday, March 24, 2023 9:19:03 AM To: Amy Adler Subject: RE: RE: AIDEA and AEA Bond Funds held at USBank - Assurance letter CAUTION: This email originated from outside of AIDEA / AEA. Do not click Hyper Links or open attachments unless you recognize the sender and know the content is safe. Hi Amy, Attached is the information that the bank has put together for clients. Also, according to federal banking law, the securities U.S. Bank Trust Company, National Association holds in a trust account are not commingled with the assets of U.S. Bank. The securities are the sole property of the client and are kept segregated from other assets. This means the securities do not appear on the U.S. Bank balance sheet and are not subject to claims made by U.S. Bank creditors. Additionally, the securities cannot be used for securities lending without the client’s consent. In addition, as the funds in the trust account are held in a Treasury Obligation Money market fund they are collateralized by the assets of the fund. I am also attaching a list of the holdings that are backing the fund as of March 16, 2023. I hope this information answers some of your questions. Tom Thomas S Zrust Vice President | Corp Trust Relationship Manager | Global Corporate Trust p.206.344.4687 | m. 206.390.8510 | thomas.zrust@usbank.com U.S. Bank Global Corporate Trust Seattle Tower 1420 Fifth Ave, 7th Floor, Seattle, WA 98101 U.S. Bank 1U.S. Bank U.S. Bank strength and stability U.S. Bancorp, U.S. Bank National Association, and MUFG Union Bank, National Association Key USB = U.S. Bancorp, on a consolidated basis including with U.S. Bank and MUB U.S. Bank = U.S. Bank National Association MUB = MUFG Union Bank, National Association U.S. Bank 2 USB overview Union Bank added:Consumer accounts ~1 Million Business Banking clients ~190,000 Commercial relationships ~700 High Net Worth / Affluent households ~50,000 Branches 296 $ in billions 1 End of period balances as of Dec. 31, 2022 2 2022 Full Year taxable-equivalent basis; business line revenue percentages exclude Treasury and Corporate Support Payment Services 27% Wealth Management and Investment Services 18% Corporate and Commercial Banking 19% Consumer and Business Banking 36% $675B assets $525B deposits $388B loans Highly diversified business mix 2Strong balance sheet1 Our highly diversified business mix and scale creates sustainable earnings U.S. Bank 3 Solid financial performance (4Q22*) Return on Average Common Equity Return on Average Assets Efficiency Ratio Source: company reports; Peer banks include:BAC, CFG, FITB, JPM, KEY, PNC, RF, TFC and WFC 1 Non-GAAP; USB ratios adjusted for notable items. See slide 29 of Exhibit 99.2 of Form 8K filed 1/25/23 for calculation. 16.8%1 13.7% USB MedianPeer median 1.20%1 1.16% USB Median 58.4%1 58.9% USB Median Our highly diversified business mix and scale create sustainable earnings Peer median Peer median U.S. Bank 4 Strong capital management •USB is well capitalized with a Common Equity Tier 1 capital ratio (“CET1”) ratio of 8.4% and total risk-based capital ratio of 11.9% at December 31, 2022 •Capital stack reflects lower risk profile and financial discipline of the business •USB’s strong credit quality and ability to generate sustainable earnings during economic stress results in lowest stress decline (or largest buffer to minimum Stress Capital Buffer in peer group) Minimum Capital Requirement Stress Capital Buffer (SCB) Capital Volatility Buffer 8.5% Capital stack 2022 CCAR results Our financial discipline and credit profile help ensure performance under stress 0.7 1.8 1.9 1.8 2.2 2.8 2.9 3.0 3.0 3.3 4.1 0.7 0.6 0.5 0.7 0.6 0.4 0.3 0.5 0.5 0.8 0.8 1.2 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.5 2.5 2.5 2.5 2.8 3.2 3.2 3.5 3.5 4.1 4.9 0 1 2 3 4 5 6 2022 2022 2022 2022 2022 2022 2022 2022 2022 2022 2022 USB RF KEY TFC PNC WFC COF BAC CFG JPM MTB Stress Decline Dividend Add-On Buffer to 2.5%YoY Chg (Total SCB) +0.0 +0.0 +0.0 +0.0 +0.3 +0.1 +0.7 +1.0 +0.1 +0.9 +2.4 CET1 U.S. Bank 5 World -class debt ratings •Provides pricing power, flight-to-quality, customer confidence op=outlook positive on=outlook negative s=outlook stable wn=watch negative wp=watch positive NR = not ratedDebt ratings: holding company as of 1/23/2023 Rating Outlook Rating Outlook Rating Outlook Rating Outlook USB A2 on A+on A+s AA s JPM A1 s A-op AA-s AA (low)s BAC A2 op A-op AA-s AA (low)s WFC A1 s BBB+s A+s AA (low)s TFC A3 s A-op A s AA (low)s PNC A3 s A-op A s A (high)s FITB Baa1 s BBB+s A-s A s KEY Baa1 s BBB+s A-s A s RF Baa1 s BBB+s A-s A s CFG NR NR BBB+s BBB+op A (low)s Moody's S&P Fitch DBRS USB is among the highest rated bank holding companies in the world U.S. Bank 6 Resilient liquidity 143% 123%122%122% 118%118% 112%112%112% 107%106% 80% 90% 100% 110% 120% 130% 140% 150% Capital One Schwab Wells USB BoNY Citi JP Morgan BofA TFC PNC STT 118% Avg Liquidity Coverage Ratio (LCR) is above peer average reflecting strong balance sheet Source: Company filings U.S. Bank 7 Deposit profile 63% 55%54%54%53%51% 48%45%3 45% 6% 0% 10% 20% 30% 40% 50% 60% 70% RF JPM TFC PNC BAC CFG WFC USB FITB SIVB FDIC insured as a % of deposits1 U.S. Bank’s access to diversified funding sources •Significant core deposits •Partner alliances (e.g., State Farm deposit generation) •On-balance sheet (e.g., cash + AFS securities) •FHLB advances •Asset securitizations •Debt capital markets for term funding •FRB discount window We maintain a diversified funding profile with ample alternative funding sources 0 20 40 60 80 100 120 140 USB PNC FRC FITB SIVB TFC RF CFG KEY Secured borrowing capacity ($Bn) –4Q221,2 USB deposit profile ($Bn) USB has significant capacity to support liquidity requirements 1 Goldman Sachs Global Investment Research 2 BAC, PNC, USB, FITB include borrowing capacity from FHLB and FRB 3 USB Form 10K filed 2/27/23. Sterling to Quartz Cr eek Transmission Line Rebuild: Board update April 11, 2023 SSQ Rebuild Agenda Public 2 •Introduction: Informational Update •Project Phasing •Progress Update –Land Rights •Progress Update –Design & Procurement •Schedule •Project Risks •Next Steps SSQ Rebuild •The Sterling to Quartz Creek line is the approximately 40 mile transmission line between the Sterling Substation and Quartz Creek substation. •Owned by Alaska Energy Authority (AEA) •Identified for Replacement by the Bradley Lake Project Management Committee (BPMC) •Chugach Electric was selected by the BPMC as the utility to manage design and procurement for the project per BPMC resolution. •Design criteria established in recent replacement for segments of the Quartz Creek to University Substation transmission line •Wood and steel structures designed to accommodate 230 kV insulation, clearances, and specifications •Utilizes the same alignment in its entirety within the existing 100‐foot ROW •Procurement and construction delineated into phases based on land use requirements 3 Introduction SSQ Rebuild 4 Project Phasing SSQ Rebuild Phase 1 8 Miles Sterling Substation to KNWR boundary. Phase 2 17 Miles Kenai National Wildlife Refuge Phase 3 14 Miles Russian River to Quartz Creek Substation Work completed •Identified landowners along entire route •Established database of cultural and historical resources •Field Assessment to be conducted •Identifying wildlife resources and habitat •Delineating wetlands •Establishing permitted access points •Held preliminary meetings with KNWR, USFS, Kenai Peninsula Borough •Three follow up meetings have been conducted with KNWR 5 Progress Update –Land Rights SSQ Rebuild Permitting discussions with KNWR Concerns from KNWR •Access –Wilderness area north of the Sterling Highway between Jean Lake and Russian River •Access points need to be mapped. •Wood pole treat contaminating the surface water, KNWR prefers steel poles •Coordination with other agencies at change of ownership (Russian River) KNWR would like a detailed ROW management plan. •Vegetation, Maintenance, Operating plans. •Eliminates the need for a special use permit for routine maintenance and replacement. •Access points and routes will be documented. 6 Progress Update –Land Rights Cont’ SSQ Rebuild Work completed •Aerial and ground reconnaissance •Established Basis of Design •Framing types, foundation design, structure material, ruling span, clearances, etc. •Evaluated communication cable OPGW vs. ADSS (OPGW selected) •Phase 1; 65% design complete •Pole locations to be reviewed the week of April 10 •Geotech work will be completed in Early April to finalize foundation design 7 Progress Update –Design & Procurement SSQ Rebuild 8 Schedule SSQ Rebuild PH 1 Design PH 1 Procurement PH 1 Construction PH 2 Design PH 2 Procurement PH 2 Construction PH 3 Design PH 3 Procurement PH 3 Construction Project Initiation Phase 1 Completion Phase 2 Completion Phase 3 Completion 10/31/2021 3/15/2023 7/27/2024 12/9/2025 4/23/2027 9/4/2028 1/17/2030 SSQ Project Timeline 9 Costs and TIC Estimate SSQ Rebuild Category Actuals Committed ETC ECAC Labor $9,626 $2,103,306 $2,112,932 Professional/Contract Services $247,635 $1,475,000 $5,641,547 $5,889,182 Materials $4,310 $11,473,105 $11,477,415 Field Contractual Services $10,469 $42,010,002 $42,020,471 Totals $272,040 $1,475,000 $61,227,960 $61,500,000 ETC: Estimate To Completion ECAC: Estimated Cost at Completion •Projecting the estimated Total Installed Cost •Construction schedule competes with other Railbelt projects •Adding to Railbelt Maintenance Schedule •Construction window limited due to high demand for hydroelectric energy •Mitigation: Assess methods to extend outage window. •Kenai Wildlife Refuge permitting requirements •Underground (option) •Steel poles •Access restrictions •Restrictions due to wildlife and habitat •OPGW vs. ADSS communication fiber •Assessed: cost of taller structures for ADSS is greater than cost of OPGW 10 Project Risks SSQ Rebuild 11 Next Steps SSQ Rebuild •Continue Permitting for Phase 1 construction •US Army Corps of Engineers (several agencies under this umbrella) •Start procurement of Phase 1 materials (October of 2023) •Establish Basis of Design for Phase 2 and 3 pending permitting guidelines •Continue to meet with agencies and stakeholders to progress (Phase 2 and 3) permitting 12 Questions SSQ Rebuild Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 1 ii. SF-424: Application for Federal Assistance iii. Project/Performance Site Locations The project covers a vast area of Alaska from the Kenai Borough to Anchorage and the Matanuska Susitna Borough. Transmission Lines and stations are in the vicinity of the following Alaska communities. • Homer • Soldotna • Kenai • Sterling • Cooper Landing • Anchorage • Eagle River • Eklutna • Palmer • Wasilla Alaska is an at-large Congressional District, therefore the Site Congressional District for all areas is AK-001. iv. Technical Volume Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 2 A. Cover Page • Project Title: Railbelt Backbone Reconstruction Project (RBR) • FOA Topic Area 1: Grid Resilience Grants • Applicant: Matanuska Electric Association representing The Bradley Lake Project Management Committee (BPMC) • Technical and Business Point of Contact: Brian Hickey, P.E. • The BPMC is a collaborative group of decision makers that represents all the primary transmission owners and operators of Alaska’s largest electrical grid (the Railbelt). The BPMC consists of the following organizations: 1. The State of Alaska dba The Alaska Energy Authority (AEA) - Curtis W. Thayer, Executive Director 2. Chugach Electric Association Inc, a Central Region cooperative (CEA) – Arthur Miller, Chief Executive Officer 3. Golden Valley Electric Association Inc., a Northern Region Cooperative (GVEA) – John Burns, President & CEO 4. Homer Electric Association inc., a Southern Region Cooperative (HEA) – Brad Janorschke, General Manager 5. Matanuska Electric Association inc., a Central Region Cooperative (MEA) – Tony Izzo, Chief Executive Officer 6. The City of Seward Ak. dba Seward Electric System (SES) – Rob Montgomery, General Manager 7. Although not part of the BPMC The Regulatory Commission of Alaska (RCA) is participating as a team member in an advisory and regulatory role, as permitted by their statutory authority.1 • Project Location: The Central region of the Alaska Railbelt 1 On January 4, 2023, the RCA unanimously passed the following motion “I (Commissioner Pickett) will make a motion that the RCA be considered as a [Alaska Railbelt GRIP] team member subject to any legal restrictions we may have and to consider probably in the format of an I docket, uncommon or innovative regulatory structures [to incentivize transmission investment].” Area served by the Railbelt Grid Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 3 B. Project Overview B.1 Background History The Railbelt electric grid is unique in North America as it is technically a fully functioning long- distance electrical grid on a very small scale. The Railbelt is characterized by three load- generation regions with four load-balancing areas. These load-balancing areas do not coincide precisely with the load-generation regions. These load-generation concentrations, known as the Northern Region (Fairbanks-Delta Junction), the Central Region (Anchorage-MatSu), and Southern Region (the Kenai Peninsula), are tied together with two long transmission lines operating at 115kV and 138KV. The grid provides electricity to approximately 75% of the state's residents and generates 80% of the electricity in Alaska. It extends over 700 miles from the Bradley Lake Project, located at the head of Kachemak bay near Homer, Alaska, in the Southern Region, to Delta Junction in Interior Alaska, roughly the distance from Washington, DC to Atlanta, GA as depicted in figure 1. The grid traverses inhospitable subarctic mountainous terrain. The region is laced with highly active seismic zones and is subject to volcanic eruptions, forest fires, flooding, and fierce annual winter storms. The grid's assets vary from high voltage (138 kV and 230 kV) submarine cable crossings in Cook Inlet 2 to remote "helicopter/riverboat - access-only" river crossings and numerous transmission structures well above 2000 feet (sub- arctic). Figure 1: Alaska’s Relative Size Unlike numerous areas in the contiguous lower forty-eight states, the Railbelt has received minimal federal investment in grid development. The Eklutna Hydroelectric Project, initially constructed in the 1950s, was the last major federal project in the Railbelt that included a 2 Cook inlet is a silt laden 180-mile inlet reaching from Knik Arm to the Gulf of Alaska. The Inlet has the fourth highest tidal range in the world at 30.3 feet and contains an endangered subspecies of the Beluga Whale. Railbelt Grid Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 4 transmission line component. This project was rebuilt by the Bureau of Reclamation's Alaska Power Administration after the 1964 "Good Friday” Earthquake and sold by the Federal government to Central Region utilities in the early 1990s. Due to limited investment, the Northern Region is moderately interconnected, primarily at 69kv and 138kV. The Central Region is reasonably well interconnected with multiple 230, 138, and 115 kV lines. The Southern Region is also reasonably well interconnected at 115 kV. A tight power pool operates in the Central Region, and an active economy energy market exists but is severely limited by transmission constraints. A reserve-sharing pool exists between all three regions. Due to the relatively feeble regional interconnections, the Railbelt Grid is technically characterized as "transient stability limited," with machines under dynamic stress swinging against other machines within the region; and with regions swinging against each other across the light interregional interconnections. The grid is susceptible to and has experienced large- scale 3 small-signal instability oscillations during the annual nexus of low lake elevations at Bradley Lake, summer valley load conditions, and faults on the Alaska Intertie nearly 300 miles north of the Bradley Lake Project. Voltage stability, which varies from marginal to good depending on the specific area, has been improved with the addition of six static VAR compensators at critical locations. The Railbelt Grid operates under a subset of North American Electric Reliability Corporation (NERC) standards modified to account for the scale and nature of the interconnection (the grid's system bias is variable and ranges from 3-10 Mw/.1 hertz). In 2024 these standards will become mandatory and enforceable under a recently formed and certificated Electric Reliability Organization, as developed through the Railbelt Reliability Council. The grid has a sophisticated under-frequency load shed scheme which sheds load to match generation in four stages with varying time delays and, in some cases considering frequency rate-of-change. Traditional day-ahead and real-time security constrained economic dispatch are run in each LBA with net interchange, and frequency monitored and managed to NERC CPS 1 and 2. Dynamic events on the grid occur and resolve very quickly (2-10 seconds) when compared with the much larger North American grids (the Eastern Interconnection, the Western Interconnection, and ERCOT), which resolve in tens of minutes. The grid's peak demand is roughly 750 MW compared to ERCOT's (by far the smallest of the North American interconnections) peak demand of 85,000 MW. The grid's annual energy consumption is approximately 4,800 GWH compared to ERCOT at 339,000 GWH. The Railbelt’s Grid Modernization Resiliency Plan (GMRP) Today, the broader energy landscape in Alaska and across the world is being reshaped by multiple change drivers. Geopolitical shifts are dramatically altering global energy markets. Decarbonization policies and technological advancements, shaped by increasingly dramatic climate change, are both the result of and contributing to a shift in focus on energy and the 3 Oscillations have been measured with a peak of 275MW, a 1.1 sec period and sustained for over 90 seconds on a grid with a summer valley peak load of approximately 500MW. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 5 environment. Regionally, uncertainty around Cook Inlet Natural gas and broader fuel supply issues for the utilities is a critical – and shared – challenge looming on the near-term horizon. The Railbelt’s weakly interconnected grid is inadequate to meet the challenges of a sustainable, fuel diverse, decarbonized future. In response to this shared challenge, the BPMC has come together to develop a broad-based, long-term plan to ensure the future energy viability of the Railbelt from a social, economic, and technical perspective. The technical aspect of that Plan is the GMRP, of which the RBR is a component. The BPMC will propose that the GMRP be incorporated into Alaska’s broader State Energy Security Plan as that document is developed in the coming months. Figure Two is a graphic representation of the Southern, Central and Northern regions of the Railbelt grid with the current system and the proposed Southern and Central Region GMRP components overlayed. The components of the GMRP in these regions that make up the 22-23 funding cycle RBR are highlighted in yellow. A more detailed listing of the Plan’s component projects (transmission line segments and substations), and estimated costs is outlined in the workplan. This effort has been slightly modified from that presented in the Topic 1 Concept paper. The Lorraine station and Lorraine-Douglas line were removed. It is a new station and line and would parallel the Teeland-Douglas line. We believe it may not meet the prohibition against new lines over 69 kV. This project has been moved to our GRIP Topic 3 proposal and funding will be sought in funding cycle two. This project was replaced with an upgrade of the Teeland- Figure 2: RBR Components in current funding cycle Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 6 Douglas line and Douglas station. Due to constraints on matching funds, the Western loop between Bradley and Soldotna (estimated at $172M) has been moved to Topic 1- funding cycle 2 and funding for it will be sought at that time. Figure 3: Railbelt Grid Modernization and Resiliency Plan (GMRP) Figure Three is a graphic representation of the entire Railbelt with the full GMRP overlayed on the existing system. On this diagram yellow highlights indicate GRIP topic 3 Railbelt Innovative Resiliency (RIR) projects, rust and red Highlights indicate Topic 1 (RBR) projects and the blue “C” indicated GRIP Topic 2 Smart Grid projects. This Plan is transformational and highly innovative. The Plan is transformationl n that it will reshape the Railbelt in a way that will usher in a sustainable fule Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 7 diverse low carbon future. As we describe below it is innovative technically, financially, and from, both a teaming and regulatory perspective. Given the operational nature of the Railbelt and the disparate socioeconomic status and vast diversity of its communities as described below, learnings from this undertaking will be broadly applicable to the larger grids of the contiguous lower forty-eight states and North America. The BPMC intends to apply for federal funding assistance for specific GMRP components in each of the five funding-year periods of the GRIP, IRA, and USDA RUS loan programs. In addition to our federal funding requests, we are seeking State assistance. As member-owned cooperatives, we hope that Federal and State will be sufficient t o fund this effort; however, subject to governing board approval we will seek the unfunded balance from the five cooperative and the municipal utility that make up the Railbelt. . Our estimated total cost for the GMRP is $2.87B over fifteen years. Without significant Federal and State investment, the GMRP and this Project are beyond the capabilities of the Railbelt utilities.. Uniquely, the team assembled for this Project as shown below consists of stakeholder outreach experts, engineers, project managers, and all the executive-level decision-makers in the Railbelt. The Team will work diligently to integrate other regional stakeholders into the process. Given DOE and State support, this Team has the authority, strength, and experience to see this ambitious project successfully through to completion. The priority in diversifying the Railbelt fuel supply and decarbonizing the Railbelt Grid must be stabilizing its primary control variable frequency and decongesting the transmission system. These improvements are required irrespective of the nature of fuel supply diversity and decarbonization solutions. For example, in 2010 the Railbelt's frequency was equal to 60 Hz. approximately 44 % of the time. By 2021, the grid operated at 60 Hertz about 17% of the time. The primary causes of this deterioration of frequency control are the introduction of lighter, more efficient aero-derivative turbines, efficiency-driven (as opposed to response-driven) plant control systems, and the introduction of non-dispatchable renewables in the form of solar and wind generators. Decongesting the grid will require the installation of battery energy storage BESS in each region (with coordinated interregional control), upgrading existing transmission lines and building a new transmission interconnection from the Kenai to the Central Region and on to Healy in the Northern region. A subsequent phase will include a transmission interconnection from Wasilla to Glenallen and north to interconnect with the GVEA system at Fort Greely and the Ground- Based Mid-Course Missile Defense system. It is important to note that, the priority and timing of these projects will be dynamic and may vary given the outcome of NEPA processes, the evolving nature of low carbon generation development, and Cook Inlet fuel supply changes. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 8 B.2 Background: The reconstruction of the Railbelt Backbone Transmission System is made up of a series of transmission line segments that stretch from the Bradley Lake Hydro Electric Project to Fairbanks and Delta Junction, 700 miles to the north. The newest of these transmission line segments was constructed in 2006, with most constructed in the 1970s and 1980s and some as early as the 1950s and 1960s. For this application we have selected segments of the RBR which have the highest value in terms of reliability, resiliency, or efficiency and have received formal or informal regional or interregional approval allowing them to be fast-tracked to design, permitting, and construction in this funding cycle. In GRIP Topic 2 of this funding cycle, we will be seeking federal assistance for design and procurement of an interregional coordinated battery/HVDC control system. Furthermore, in GRIP Topic 3 we will be seeking federal assistance for the interregional ties and potentially Grid Stabilization batteries. The total estimated cost for the reconstruction of the line segments and associated station facilities, proposed in this funding cycle, is approximately $402MM. On December 2, 2022, the BPMC, through AEA, closed on a bond package for $166M, 65% of which will be dedicated to this project and 35% to three regional grid stabilization battery energy storage systems (BESS). This will begin work on the GMRP but without Federal and State assistance it will not be completed in a reasonable time frame. In later funding cycles, we will include other segments of the RBR as study work is completed and once regional approval is obtained. Finally, we are also seeking State funding assistance 4 to help close the gap between utility funding and federal assistance. Project Goals: The RBR project will simultaneously reduce losses and increase transfer capability both within and between regions. Although these transfers lack the resiliency that would be provided by second ties between the three regions 5 the newly constructed lines will increase resiliency, and transfers will be less susceptible to wildfires, avalanches, earthquakes, and other disruptions. Increased transfer capability reduces security constrained economic dispatch (SCED) constraints resulting in a more efficient generation dispatch. Increased transfer capability combined with reduced losses will reduce overall fuel burn and reduce carbon emissions. For example, the Bradley Lake Hydro Electric Project, one of the lowest-cost resources in the Railbelt, is a 120 MW plant that is limited to operation at or below 90MW 6 maximum capacity due to transient stability limitations and unacceptable transmission losses. Losses on energy delivered to Quartz Creek with Bradley Lake at 90MW (2020 Winter Peak case) are roughly 8%; losses at 120MW (same case) are nearly 11%. When increasing Bradley output from 110 MW to 120 MW losses increase by 5.6 MW, an incremental 56% increase. Thus, the RBR will result in lowering fuel burn and reduce carbon emissions both from reduced losses and the more efficient SCED for all BPMC participants. 4The October 26 letter from Railbelt Utility Managers to Alaska Governor Michael Dunleavy is available for review. 5Resiliency in terms of additional ties will be addressed Topic 3 of our GRIP application 6 Except in periods of imminent spill Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 9 Ultimately the RBR project, acting as a component of the larger GMRP, will improve resiliency, reliability and efficiency and help facilitate the integration of additional non-dispatchable renewables whether they are in the Southern, Central or Northern regions. Goal 1: Technology Adoption The following design concepts and new technological systems will aid in the achievement of the stated goals and will result in critical success of improving resiliency within the Railbelt. Fire-resistant technologies and fire prevention systems Reconstructing the towers to 230kV standards using metal and wood structures with elevated conductor height that lessen the likelihood of tree contacts and where possible increased ROW widths that lessen the likelihood of fire impact and tree contact from uphill slopes. Monitoring and control technologies State of the art protection, control and monitoring using dual, line current differential, time-domain line protection with precise fault location using traveling wave reflectometry, and fiber and digital microwave communications assisted distance protection schemes. Increased situation awareness from real-time supervisory control and data acquisition with synchro-phasor power angle and voltage magnitude at all appropriate busses. Additionally real-time fault location data telemetered to the control centers. In areas where possible low-sag conditions may occur under certain conditions and cannot be mitigated by reduced spans or taller structures, remote reporting line conductor tension and insulator string angle monitoring may be used to indicated potential low sag conditions. Utility pole management Replacement of existing poles which have exceeded their useful life, as well as, if possible, relocation of structures out of known avalanche paths and powder blast paths. If relocation is not possible, the use of breakaway conductor attachments, and pole in driven- pile-caisson construction for ease of replacement where avalanche danger cannot be mitigated. The relocation of power lines or the reconductoring of power lines with low sag, advanced conductors All circuits are re-framed at 230 kV and reconductored for maximum transfer capability. Adaptive protection technologies Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 10 Given the speed with which the events occur and resolve- (electric sub-cycle to single seconds), the protection systems will include remedial action schemes such as undersea cable load control and rate of change supervised underfrequency load shed. The integrated BESS systems will provide adaptive increased transfer capability based on load and generation scenarios. Hardening of power lines, facilities, substations, of other systems Facilities including communications, substation constructed to current Critical Infrastructure Protection (CIP) standards and specifically with respect to this Topic in terms of security and fire resistance. Advanced modeling technologies Advanced Eigenvector/Eigenvalue modeling and analysis will be required to tune the control, protection, and adaptive control systems for small- signal instability. The replacement of old overhead conductors and underground cables Virtually all conductors being replaced are between 40 and 75 years of age. A proven technology that can be expanded throughout the Railbelt is what is referred to in the Railbelt as the Snow Loading Monitoring System that warns system operators if snow and ice build-up on transmission lines becomes dangerously low to the ground. Of course, this same system could detect highly loaded lines in hot weather that could sag into trees. The system uses both load cells and inclinometers that signal the operator if conditions exist that are outside of the norm. The operator can choose to deenergize the line and dispatch a crew to remove the hazard. This unique technology has been invaluable in avoiding potentially hazardous conditions. Goal 2: Regulatory Framework The project will assist in achieving the recently adopted reliability standards approved by the Regulatory Commission of Alaska and guided by the certificated Electric Reliability Organization (ERO), the Railbelt Reliability Council (RRC). In Alaska the ERO is responsible for both planning and reliability. The framework of the GRIP will be the backbone of a much-needed Railbelt Integrated Resource Plan that will improve resiliency for electric consumers. Further the Regulatory Commission of Alaska had agreed to consider innovative rate-making strategies that will incent transmission construction. For example, currently in Alaska construction costs must be held and financed until a project is used and useful e.g., energized and in service. With transmission projects this can be a number of years and the carrying costs on these held funds can be very large. Allowing recovery of these costs in rates as they are incurred would eliminate the carrying costs on transmission projects, reducing their overall cost and incentivizing construction. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 11 Goal 3: Skilled Workforce The stakeholders in this project have the requisite skills necessary to carry out this plan. The funding opportunity provided will strengthen and expand the workforce for decades to come. Alaska has experienced and outward migration of people for several years, believed to be in part due to the high cost of living and lack of good paying jobs. This project will help to lower the cost of living and provide opportunities for high paying skilled jobs which will be critical for the growth and prosperity of Alaska and its future economy. This grant will provide opportunities for the BPMC utilities to partner with existing programs such as Science Technology Engineering and Mathematics (STEM), energy literacy programs, the IBEW, and other institutions throughout the state as an investment in the future pool of critical energy- related jobs. Goal 4: Community Benefits The project will provide long-term benefits to the community (job opportunity, business growth, and stable energy cost) and achieve the project goals of improved resiliency. It is truly a win-win situation. B. 3 DOE Impact DOE investment in RBR will unlock State 7 and local Cooperative funding for this Project and subsequent GMRP components. By advancing the GMRP’s cumulative broader impact this investment will transform the Railbelt transmission grid. This transformation will provide adequate transmission capability for broad regional participation in renewable and low carbon generation projects. Broad participation will drive economies of scale, lowering the per-unit cost of project electricity, and improving the cost profile of these projects. This improvement in project cost profile effectively eases rate burden of the Green Premium8. The burden of such rate impacts falls disproportionately on low income and underserved communities. Thus, the GMRP will facilitate the integration of renewable and low carbon generation technologies from Homer to Fairbanks through the unrestricted electron freeway. In the current business environment, expansion of the transmission backbone has not occurred and without the backbone, renewable energy opportunities have been constrained in the most part to projects that are sized meet local regional loads . Without federal or state assistance, utilities will focus on local rather than regional or Railbelt-wide opportunities. The development of ERO was a direct result of the utilities working in their individual best interest, rather than regional benefits. There needs to be a financial incentive to move forward, and the DOE grant is the tool to make this happen. 7 See October 26th letter from the Railbelt Electric Utility managers to Governor Dunleavy. 8 https://breakthroughenergy.org/our-approach/the-green-premium. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 12 B.4 Community Benefit Plan The Railbelt Backbone Reconstruction project presents a unique opportunity to increase reliability, provide clean energy options, and reduce electricity rates for a 700-mile-long stretch of Alaska that serves as the state’s economic backbone and is home to approximately two- thirds of the state’s population. The same Railbelt region includes, several disadvantaged communities, extensive veteran, Pacific Islander, and Alaska Native populations, and some of the most diverse neighborhoods in the nation. Furthermore, the State of Alaska’s Power Cost Equalization program extends the financial benefits of lower Railbelt electric rates to positively impact hundreds of remote communities statewide; even populations not connected to the Railbelt’s electric network benefit from reduced Railbelt rates. Having missed out on the federal government’s transformational infrastructure investments before Alaska statehood, residents of Alaska have long borne outsized infrastructure costs spread across relatively few homes, businesses, and industries. Alaskans have experienced a lack of redundancy and infrastructure that would be considered unacceptable in other parts of the Federal support would be a step closer to providing parity to Alaskans, including numerous Disadvantaged Communities (DACs) as well as tribal entities and rural communities. BPMC intends to identify project benefits, the anticipated recipients, and metrics to track and measure the benefits in its Community Benefits Plan (CBP) to meet the federal government’s four target goals. BPMC’s approach to this plan will be stakeholder driven, involving communities and entities anticipated to become partners through the project planning, execution, and operations stages. CBP development will benefit from early engagement with potential partners and stakeholders to define measurable project benefits, set workforce goals, and advance formal partnerships for inclusion in the CBP. Individuals in impacted communities and local institutions can provide invaluable insight into potential project benefits and outcomes that will inform the project development and execution. This stakeholder participation is critical up-front to ensure the project delivers expected benefits that reach the intended communities, while reducing possible adverse impacts. Defining the affected stakeholders early, establishing clear, durable communication channels, receiving their concerns, and crafting measures to address those concerns is critical to managing project risks and ensuring desired objectives. Clear communication and collaboration during development of the project application and the CBP will set a foundation for implementing the CBP during project development, construction, and operations. This engagement should be a continuous loop through the project design and execution. Stakeholder engagement is central to the BPMC partners’ regular businesses, with four member-owned electric cooperatives, a municipally owned utility, and a state entity. BPMC believes this extensive experience will provide key support in the CBP development and execution. Early engagement with stakeholders is also expected to further the ability of Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 13 communities, individuals and local governments and tribal entities to unlock additional funding opportunities tied to the project. To that end, BPMC will develop a robust community benefit plan around the four FOA elements. Across all elements, BPMC’s approach is founded on the belief that direct, early communication and a meaningful exchange with other entities and communities will inform CBP development. B.6 Long-Term Constraints Given that this project reconstructs existing lines and Substations. we do not believe it will have any long-term constraints on community’s access to natural resources and Tribal culture resources. B.7 Resilience Strategy BPMC believes significant benefits can be realized in energy resiliency, reduction of energy and pollution poverty as well clean energy opportunities throughout the region and state and will coordinate with partners and stakeholders to quantify these broader benefits within the CBP. Communities in the project region currently face potentially severe health, safety, and economic consequences resulting from grid threats such as earthquakes, severe cold weather events, and large-scale forest fires often in remote areas. Projects are also anticipated to increase clean energy options throughout the region, including DACs and other rural communities, many of whom are currently powered through coal or diesel-fired generation. The project is expected to reduce the potential consequences posed by these risks. The CBP will also capture the potential benefits of increased opportunities for tying new, clean-energy projects to the grid, especially smaller-scale projects. Project benefits are anticipated to include improvements to air quality across the project regions, especially in the Northern Region and other locations where particulate matter (PM2.5) have risen to non-attainment levels high enough to trigger remediation efforts through the EPA and concerns are adversely impacting the economy and health. C. Technical Description, Innovation, and Impact C.1 Relevance and Outcomes Relevance: Funding cycle 1 of the Railbelt Backbone Reconstruction (RBR) Project is comprised reconstruction of 7 individual line segments totaling over 180 miles of high voltage transmission. To interconnect these lines to the backbone, the reconstruction of 8 substations and switchyards are incorporated. Outcome: The overall outcome will be an increase in the line voltage from 115kV to 230kV and provide normalized transfer capability between existing parallel transmission paths within regions, as well as the ultimate goal of interregional parallel ties (GRIP Topic 3 projects). In addition, parallel paths with normalized transfer capability will increase both reliability and resiliency. Future phases and funding cycles will be necessary to accomplish this in its entirety. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 14 Technology: By increasing the voltage, line losses will be reduced and transfer capacity between regions will increase as discussed in the goals section. By incorporating future parallel paths, energy transfers can be improved on an improved transient stability basis and firm (multi-path) access to each region will increase participation in renewable projects, increasing economies of scale and driving per unit costs lower thereby make more projects cost effective. In a single line scenario, if you lose the interconnection, you lose all power transfers between the adjoining systems and cause a power swing equivalent to the transfer loss. If you have a parallel line, you maintain a majority of the power transfer and avoid the large power swing between these adjoining systems. The ultimate benefit is improved resiliency and reliability and lower operating costs. In the instance of a fire or other hazard, the parallel line (given its not within the same hazard zone9) will carry the load and avoid a costly outage. As discussed in our goals section, other technologies used on a single line will aid in avoiding outages. Grid Outcome: Creating a strong backbone transmission system will allow more independent generators to interconnect renewable energy projects to the grid and move power from points South to North. Currently we do not have adequate transfer capacity to provide firm delivery for large scale renewable projects. Performance Targets: Completion of the RBR will increase transfer capacity incrementally as line segments are upgraded. As design and modeling is completed we will establish smart targets to measure this progress. Moving to clean energy is key to maintaining local control and diversifying supply. The Railbelt region is strongly dependent on natural gas in Southcentral and fuel oil in the Fairbanks region. Fuel availability is of concern in Cook Inlet as the fields continue their natural decline and fuel oil and potential gas imports are costly. Although renewable energy projects are being implemented regionally, implementing the RBR is crucial to adoption of larger-scale lower-cost renewable energy, improvements in grid stability and avoidance of costly outages due to natural disasters such as fire, avalanche, floods, earthquakes and volcanic events. Alaska’s history has shown that these natural occurring events are not just possibilities but occur frequently and negatively impact all Alaskan’s. C.2 Feasibility Previous Work: The applicants have used the technologies described with excellent results. Adding avalanche barriers, breakaway conductors, driven caisson and pea gravel foundations and strategically placed structures has almost eliminated avalanche related outages on the Anchorage to Daves Creek 115 kV line and significantly reduced restoration times when outages do occur. Insulator string angle and conductors load cells have allowed immediate response to low-sag conditions resulting from unbalanced snow loading on the Alaska Intertie between Willow and Healy. The use of automated field switching has aided in restoration and has aided 9 We will employ path diversity as a design criterion, wherever practical. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 15 remote communities maintain power in the severe winter weather. Application of these technologies broadly across the three regions will significantly improve reliability and resiliency. Access to Infrastructure: In the late 80’s and early 90”s, parallel transmission lines were added from Anchorage to Beluga (major load and generation locales). Since completion, several events have occurred that proved their value. From floods that washed out major structures across the Big Susitna River to black bears and large birds of prey who frequent the towers during fish season. Bird biological waste coats insulator strings and degrading the Insulation and causing short circuits. Curious bears have also short-circuited lines in the past. Redundancy has saved the day numerous times. Skilled Workforce: The applicants have access to a skilled workforce; both engineering and construction wise, but will be challenged with the scope of this effort. The applicants have a strong working relationship with both the IBEW and NECA through the local Joint Apprenticeship Program. This program is a federally certificated apprenticeship program that produces skilled Journeymen lineman, wireman and other credentialed trades. It will be incumbent upon the parties to ramp up the workforce development, and encourage minorities, women, and indigenous peoples to take advantage of this opportunity. C.3 Innovation and Impacts Innovative partnerships: In the Railbelt the status quo for transmission construction has been for each utility to only construct the minimum transmission needed to serve its certificated loads. Using the BPMC model as an integrated wholistic teaming arrangement to modernize the grid is innovative in the Railbelt, and will be a game changer for the transmission grid. What is the BPMC? Through the BPMC the utilities enjoy an innovative private-public partnership with the state of Alaska. The BPMC is a leadership and governance team that, under its bylaws and the requirements of the Bradley Lake Power Sales Agreement, manages the Bradley Lake Hydroelectric Project and associated facilities ranging from the Project’s transmission lines and state-of-the-art Static Var Compensators (SVC’s) to the proposed Battery Energy Storage Systems (BESS). Extending this successful, unique, and innovative partnership between the State of Alaska (through the Alaska Energy Authority (AEA)) and the Railbelt utilities to the broader transmission system will result in significant improvements to Railbelt’s resiliency which will in turn aid in the technical advancement of renewable energy projects and decarbonization of the electric grid. Proof of the success of this model is that the Bradley Lake Project delivers some of the lowest cost energy from any source to the Railbelt’s population. BPMC improvement projects such as the Battle Creek diversion have increased its energy content by more than 10%. The DOE grant funding will incentivize the utilities to expand this successful model to upgrade the regional and interregional transmission grid. Teaming with the Regulatory Commission of Alaska (RCA) will result in the RCA’s evaluation of the ability to forward fund or at a minimum immediately recover transmission costs in rates, thus reducing carrying costs and pushing down the Benefit/Cost ratio bar. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 16 The AEA also manages the State’s Renewable Energy Fund (REF) and the Power Cost Equalization (PCE) program. This unique partnership assists remote native communities with adopting renewable energy projects. The PCE formula for providing energy assistance to rural Alaska is tied to the Railbelt energy rates, so when technology and renewable energy in the Railbelt reduces costs, it eventually benefits rural native Alaska residents many of which are tribal and DAC’s. New Financial Arrangement: The Railbelt Utilities and AEA have worked together under the auspices of the BPMC for over 30 years. From constructing the project, which was commissioned in 1992 at a cost of approximately $350M in 1990 dollars, to the most recent addition to the Project the Sterling to Quartz 115 kV line. The Project added the Battle Creek Diversion in 2018, a $45M diversion structure that increased the lake’s energy capacity water by approximately 10 percent. On November 30, 2022, AEA on behalf of the BPMC closed on a $166M bond package which will be used to begin the RBR project by upgrading the Soldotna to Quartz section of the 115 kV Southern Region to Central region Transmission line (aka the Anchorage to Kenai 115kV line). Thirty-five percent of the bond issue will be used to partially fund three regional grid stabilization batteries, one of which has been constructed by HEA and is currently operational. It is this innovative partnership that includes financial arrangements, broad application of unique technologies like the snow load monitoring system, and successful project deployment that will make this project successful. C.4 State, Local, Tribal, and Regional Resilience It is this unique relationship between the Railbelt utilities and rural Alaska through the AEA and the PCE and REF programs that will directly spread the benefits of the RBR project. Given the key part the Railbelt plays in the State’s economy, the growth and adoption of technologies, advancement of renewable energy and strength of an expanded energy industry will service all Alaska. The project will fully support the newly adopted ERO and its Regional Integrated Resource Plan. With a strong transmission backbone, the opportunities for expanding renewable energy throughout the grid are made possible. The renewable energy sector through the Renewable Energy Alaska Project (REAP) is a strong supporter of the ERO and have stated that “Alaskans can make smart energy choices, powering local clean energy growth, and positioning the state as a global energy powerhouse”. It is relationships within the industry that will assure the State’s energy goals are achieved. C.5 Risk Avoidance and Private Sector Investment Project deployment will be critical to achieve the goals of the RBR. The risks of this project are typical to most transmission projects and include financial, supply chain, resources, and workforce availability, as well as operational flexibility. Since the cost of the project is Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 17 substantial, both state funding support and federal grants will reduce the risk to the utilities unleash cooperative (private sector), and state funding of these projects. Resources will be stretched, but excellent relations with labor and state-wide training and education programs will help reduce the risk. Operational flexibility will improve over time as each project is completed. Partnership with State and local entities will assist in securing the required permits and approvals in a timely manner. A complete and comprehensive project management plan with ongoing risk evaluation and mitigation, as well as strong change, scheduling, and cost control components will be critical to risk management. Early stakeholder engagement will also be key in this effort. As stated, this is a long-term 15-year effort. As each project is incrementally completed the industry will grow and the expertise, technology and processes will mature. A whole new industry will be developed over time. The private sector will meet the need and will expand as necessary. C.6 Topic Area 1 Requirement Disruptive Events: Alaska has no shortage of disruptive events. Railbelt utility mitigation plans take into consideration, among other things: avalanches, earthquakes, wildfires, and severe winds events. With single transmission lines connecting the three Railbelt regions, single events can leave communities isolated and/or without power. A combination of events can result in prolonged disruptions. A good example is the community of Girdwood which was once out of power for over a week when separate avalanches destroyed structures both North and South of the community. Should such an event have occurred during spring break the resort communities most lucrative week of the year the results could have been financially devastating to Alyeska Resort, which would have then rippled through the remainder of the States tourism industry. Other events can lead to a substantial increase in cost to operate. In 2019, a fire on the Kenai Peninsula shut down power transfer between the Bradley Lake Hydroelectric project and Anchorage for several months. Replacing hydroelectric power with natural gas and oil increased carbon emissions and cost utilities millions of dollars until the lines could be energized. These are just a few examples where a completed RBR would mitigate impacts; whether it be loss of power or increased operating costs. Mitigates Hazards: The design criteria of the new RBR facilities will mitigate the chance that electric lines can cause a wildfire to the community. Wildfires can be caused in many ways, one of which is fires caused by trees encountering electric lines. This can occur by trees growing into the lines from beneath the structures and can occur from tall trees falling into the lines adjacent to the lines. Recent Spruce bark beetle infestations have left many trees tall enough to reach the electric lines standing as deadfall well outside traditional ROW widths. The new criteria will raise the structures and/or widen the ROW so the tallest tree could not impact the lines. In addition, advanced technology wire and monitoring will be used to reduce mid-span Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 18 conductor sag. The utilities will continue to adhere to prudent line clearing programs to minimize tree growth within and adjacent to power lines. Other design criteria for known hazards such as avalanche danger and seismic risk will be designed into the RBR facilities. An Avalanche Atlas that identifies all known avalanche paths along the transmission line between Anchorage and the Kenai Peninsula transmission route was established in the 1990’s when several avalanches impacted the transmission line. This atlas has been invaluable in the design of new line segments and reducing avalanche related outages on this line section. Expanding this atlas to other regions of the Railbelt will be a key part of the RBR. New designs will locate structures outside of avalanche or powder blast zones, or create special designs if relocating is not possible. Raising conductors above the snow blast zone, spanning towers to avoid slide paths, and incorporating protection/diversion structures if other methods can’t be deployed. Another key design feature is designing breakaway conductor systems and special foundations that will accommodate quick restoration after a slide. Lessons learned from prior events is that it is far better to lose a single structure than have a cascade of structures fail after impact. Grant Funding: Absent this grant funding, these projects would not be undertaken, or might be taken on over an extended period. The primary cause for this avoidance or delay is that, without unacceptable rate impacts, the cost of these projects is beyond the financial capabilities of Railbelt. As noted, all the above-mentioned techniques have been successfully adopted and put into place in prior resilience efforts in limited areas. This grant will expand these initial efforts to the entire Railbelt. D. Workplan D.1 Project Objectives Objective 1: Increase grid reliability, resiliency and transfer capability for the existing Railbelt grid by rebuilding existing lines and stations to hardened and more resilient standards. Expected Outcome: A reconstructed Railbelt backbone operating at 230 kV that has enhanced resiliency to avalanches, earthquakes, wildfires, and other disruptive events. This improved Railbelt Backbone system will improve economic dispatch, increase efficiency and system reliability, and reduce carbon emissions. Converting from 115kV to 230 kV will reduce losses and increase transfer capability significantly. Objective 2: Broad application of the technological advancements used in the Railbelt will be shared with rural Alaska communities outside the Railbelt and serve as a model for other communities in the rest of the US and world. Expected Outcome: Application of Railbelt technological advancements, such as avalanche path mapping and conductor tension monitoring of sag and others, when shared with non-Railbelt utilities will result in more reliable and resilient rural Alaskan electrical Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 19 systems. In addition, the efficiencies gained in the Railbelt will lower Railbelt costs and through the Power Cost Equalization program lower the costs to rural Alaskan often tribal DACs. Objective 3: The RBR project will provide cost-effective grid modernization and decarbonization lessons for the US and world. Expected Outcome: These learnings will be applicable to and shared with the Grids of the contiguous lower forty-eight states and in many regions of the world by DOE and their network of national Labs. D.2 Technical Scope Summary The RBR project is part of a multifaceted project to rebuild the existing transmission system from Fairbanks to Homer. Funding cycle 1 RBR line segments are combined in 3 phases. Phase Description Timing Outcome 1 Transmission rebuilds from the Bradley Lake project to Daves Creek near Cooper Landing improve resiliency and reduce losses. 4 years Decrease Line Loss Increase reliability and resiliency 2 Mat-su upgrade parallel transmission path, Eklutna Hydro to Lucas rebuild the original Eklutna line constructed in the late 1950s 1.5 years Decrease Line Loss Increase reliability and resiliency 3 Loraine to Douglas rebuild reconstruct a line insulated at 115 kV and operated a 138 kV 1.5 years Decrease Line Loss Increase reliability and resiliency Phase1 Phase 1 Transmission rebuild from the Bradley Lake project to Daves Creek near Cooper Landing. Expected Results: Upon completion of this line losses will be substantially reduced, and reliability and resiliency will improve with taller and more resilient structures. Furthermore, increased voltage levels will increase transfer capabilities from Bradley Lake, the largest renewable energy source I the Railbelt to Soldotna and other larger populations centers north. Phase 2 Phase 2 Upgrade a portion of one of the parallel transmission paths from Anchorage to Teeland Substation (Eklutna to Lucas), the southern terminus of the Alaska Intertie between the Central and northern region. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 20 Expected Results: This upgrade will reduce losses and provide resiliency to the heart of the Matanuska Susitna Borough (Mat-Su) including Wasilla, Palmer, Big Lake, Houston and Willow. Once completed entirely this multiple transmission line path will provide an alternative to the East Terminal to West Terminal 230 kV submarine cable (a 40 year old oil-filled submarine cable crossing Knik arm) that has had numerous mechanical challenges over its life. Phase 3 Phase 3 will upgrade the Teeland to Doulas line (the southern terminus of the Alaska Intertie). This section of the Alaska Intertie was cobbled together with a few new structures and an old 115 kV line. Currently this line section is framed at 115 kV and operated at 138kV. The Mat-Su is the fastest growing region of the state. These sections are slated for construction over roughly a three-year period and will overlap the Bradley Lake to Daves Creek segment construction. Expected Results: Reinsulating and converting to 230 kV will lower losses and eliminate nuisance flashovers that trip the Alaska Intertie, islanding Fairbanks, and during Summer Valley setting off the small signal instability oscillations noted in the history section. D.3 WBS and Task Description Summary The overall scope of the project will include 7 individual line segments and 8 substations/switchyards. Individual WBS and milestones are discussed below and will be developed once design is completed. Estimated completion schedules for each project are indicated here and graphically in the Project Schedule. The following objectives will be accomplished by the Execution of the WBS below. Objective 1: Increase Grid reliability, resiliency, and transfer capability for the existing Railbelt grid by rebuilding existing lines and stations to hardened and more resilient standards. Objective 2: New electric industry and technological advancement will be shared with rural Alaska and serve as a model for other communities. Objective 3: The RBR project will provide cost-effective grid modernization and decarbonization lessons to the US and world. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 21 Each transmission line segment has the following sub tasks, Go/No-Go decision points and milestones (only printed once here to save space) Major Segment Description Duration Start End 1.0 Bradley Lake to Daves Creek Transmission Lines Wed 3/14/29 1.1 New Bradley Lk. to Bradley Jct. DC 230 486.2 7/1/2024 Tue 5/12/26 1.2 Bradley Jct. to Soldotna 115 kV to 230kV 632.7 2/4/2026 Fri 7/7/28 1.3 Soldotna-Sterling 115 kV to DC 115kV/230kV 289.2 2/3/2028 Wed 3/14/29 1.4 Sterling-Quartz Cr. 115 kV to 230kV 654.4 3/1/2025 Thu 9/2/27 1.5 Quartz Cr. - Daves Cr. 115 kV to 230kV 98.2 3/22/2027 Thu 8/5/27 2.0 Eklutna to Douglas Transmission Lines Thu 3/8/29 2.1 Teeland to Douglas 230kV 345.3 7/5/2027 Mon 10/30/28 2.2 Eklutna Hydro - Lucas 115kV to 230kV 186.4 6/21/2028 Thu 3/8/29 4.0 Substation and Switchyards Segments Thu 11/16/28 4.1 Bradley Lake 230kV Station 617 7/1/2024 Tue 11/10/26 4.2 Soldotna 230kV Station 488 3/17/2026 Thu 1/27/28 4.3 Sterling 230kV Station 128 7/25/2027 Tue 1/18/28 4.4 Quartz Creek 230kV Station 248 12/7/2027 Thu 11/16/28 4.5 Daves Creek 230kV Station 496 7/1/2024 Mon 5/25/26 4.6 Douglas 230kV Station 304 11/15/2025 Wed 1/13/27 4.7 Lucas 230kV Station 537 9/22/2026 Wed 10/11/28 4.8 Eklutna Hydro Substation 126 3/19/2028 Fri 9/8/28 Task No.For Transmission lines Duration X.X.1 Project Management and Planning (PMP)* X.X.2 National Environmental Policy Act (NEPA) Compliance * X.X.3 Cybersecurity Plan (CSP)- If Required * X.X.4 Continuation Briefing(s)* X.X.5 Avalanche, sesmic, wildfire, and special foundation risk evaluation * X.X.6 Develop Tailored Design Criteria and mititgation based on X.X. 1 * X.X.7 Preliminary Design & Engineering * X.X.8 Public Notice * X.X.9 Go/No-Go Design and Permiting 1 X.X.10 Final Design & Engineering * X.X.11 Permiting * X.X.12 Design and Permitting complete Milestone 0 X.X.13 Go/No-Go Procurement 1 X.X.14 Procurement * X.X.15 Long Lead Procurement Complete milestone 0 X.X.16 Go/No-Go Construction 1 X.X.17 Construction * X.X.18 Construction complete milestone 0 X.X.19 Testing and Commissioning * X.X.20 Go/No-go Energize line 1 X.X.21 Line in service milestone 0 * Actual duration dependent on line segment Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 22 Each Station and switchyard have the following sub tasks, Go/No-Go decision points, and milestones (only printed once here to save space) D.4 Milestone Summary The minimum milestones for typical line and station switch yard construction projects are listed below and are designed to demonstrate progress throughout the entire project. Task No.For Stations and Swtichyards Duration X.X.1 Project Management and Planning (PMP)* X.X.2 National Environmental Policy Act (NEPA) Compliance * X.X.3 Cybersecurity Plan (CSP)* X.X.4 Continuation Briefing(s)* X.X.5 Avalanche, sesmic, wildfire, and special foundation risk evaluation * X.X.6 Develop Tailored Design Criteria and mititgation based on X.X. 4 * X.X.7 Preliminary Design & Engineering * X.X.8 Public Notice * X.X.9 Go/No-Go Design and Permiting 1 X.X.10 Final Design & Engineering * X.X.11 Permiting * X.X.12 Design and Permitting complete Milestone 0 X.X.13 Go/No-Go Procurement 1 X.X.14 Procurement * X.X.15 Long Lead Procurement Complete milestone 0 X.X.16 Go/No-Go Construction 1 X.X.17 Construction * X.X.18 Construction complete milestone 0 X.X.19 Testing and Commissioning * X.X.20 Go/No-go Energize line 1 X.X.21 Line in service milestone 0 * Actual duration dependent on line segment Station and Switchyard Milestone Table Design and Permitting complete Milestone Long Lead Procurement Complete milestone Construction complete milestone Line in service milestone Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 23 The above milestones are reported monthly and quarterly as appropriate. Technical Milestones are SMART milestones and will be reported on an annual basis as major line segments are completed. The two most applicable technical milestones include Reduced Line Loss and Reduced Service Interruptions. After the completion of a line segment, the increased voltage (115kV to 230kV) and increased conductor size, will reduce losses. These losses can be measured using control systems and metering at the appropriate station termination point. Resilience will be improved through taller structures that will limit tree contact and avoid avalanche damage. The redundancy of having parallel lines will also reduce system outages. These system improvements will be measured on an annual basis and will compare the previous 5-year average of line outages with the current year. D.5 Go/No-Go Decision Points The minimum milestones for typical line and station switch yard construction projects are listed below and are designed to demonstrate progress throughout the entire project. Go/No-Go decision points are primarily attributed to the design and permit phase but occur throughout the project. Once the permit is issued, the owner can issue a construction RFP or RFQ and begin the solicitation stage. After receiving bids, the owner will evaluate the proposals and recommend award to Transmission Line Milestone Table Design and Permitting complete Milestone Long Lead Procurement Complete milestone Construction complete milestone Line in service milestone Transmission Line Go/No-Go Table Go/No-Go Design and Permiting Go/No-Go Procurement Go/No-Go Construction Go/No-go Energize line Station and Switchyards Go/No-Go Table Go/No-Go Design and Permiting Go/No-Go Procurement Go/No-Go Construction Go/No-go Energize line Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 24 its governing body. Once approved, the contracts can be awarded. Materials can either be ordered by the owner or included in the bid package for construction, Generally, long lead items are secured ahead of time by the owner. A Go/No-Go decision can also take place in the permitting stage if the regulating entity does not approve the permit. This may require a change in design, routing, or use of materials. In that case, the design is modified and resubmitted for approval. Other Go/No-Go scenarios which proceed construction such as procurement. It may be necessary to add Go/No-Go points items like financing, board governance or legislative approval, or stakeholder approval. In these cases, the owner must address the issue, potentially go back for permit review, and approve once the issues are resolved. Other No-Go decisions can also occur during construction dependent on the line segment. An example may arise due to an environmental issue such as bird migration, discovered contamination, or sensitive or cultural site findings. In these cases, the conflicts must be addressed, and the project continues with some delay. In addition, generation unavailability may impact the construction schedule. Generation resources have both scheduled and forced outages. If taking a line out of service creates a single contingency situation, the utility likely will not allow an outage on that segment until the situation is resolved. Go/No-Go scenarios generally extend the timeline of the project, but seldom result in a No-Go for the entire project. As this project contains a considerable number of line segments and individual station locations, some No-Go scenarios are possible. ERO Go/No-Go Technical Milestones for the Substations provide state of the art protection, control and monitoring that provide the data to assure electrical systems are efficient (line loss, voltage stability, maximum energy transfer, minimum trip times and tune control systems etc.) Go/No Go Milestones for substations are much the same as for line segments but have greater impact to public neighborhoods. Sound and visual issues with large transformers, communication towers and fence construction add to list of potential issues that can delay a project. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 25 D.6 End of Project Goal The end of project goal has three components. • Successful completion of the construction projects at or below budget • Higher reliability, increased transfer capability and reduced losses • Documented leanings that can be shared throughout Alaska, the nation, and the world D.7 Project Schedule D.8 Buy America Requirements for Infrastructure Projects We do not believe this project contains any applicable infrastructure work. D.9 Project Management Overall Approach The project will use traditional project management techniques and controls e.g., change management, budget and cost control, scope management etc. as identified in the Project Management Body of Knowledge (PMBOK) to ensure project success. A risk log will be Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 26 developed and maintained by the project manager. All risks and mitigation strategies will be updated at least every milestone. The project will be managed by an overall project lead under the guidance of the Bradley Lake project Management Committee’s (BPMC’s) Technical Coordinating Committee (TCC). The TCC is comprised of Railbelt utility engineers, system operators and managers. Acting as the project steering committee, the TCC will guide the project leads efforts and provide access to resources and data. Having ready access to resources and data from all regions will be key to ensuring successful project execution. Further, the TCC and DOE will validate and verify the performance of the systems at each milestone and go/no go point. The overall project will contain multiple engineering and design teams and construction contracts. Each entity will be responsible to submit a Quality Planning (QP)/Quality Assurance (QA)/Quality Control (QC) plan that will outline the procedures used to detect quality issues and control quality throughout the project. Develop Management Team – Team Liaison may take on multiple tasks as time allows. • Project Lead - manages overall project. • Engineering Liaison - evaluates process to secure needed design & engineering expertise. • Lands Liaison – evaluates process to secure land acquisition, easements, and permits. • Construction Liaison – evaluates the best method to secure construction contracts. • Labor Liaison – works with labor unions and workforce development, universities and trade schools to arrange for needed labor. • Project Management Lead – manage overall schedule and coordinate individual projects. • Finance & Grant Management Lead – coordinates work with AEA, utilities, DOE, RUS and private lenders. • Government Relations Lead – communicates project details with local, state and federal entities. • Purchasing & Materials Lead – Assures key materials are available and monitors and works with vendors on unforeseen Buy America goals. • Public Relations Lead – communicates with key stakeholders and the general public. • Legal & Contracts Lead – develops contracts and provides guidance with appropriate terms and conditions. • Accounting and Closeout Coordinator – coordinates with project leads to assure all proper documentation is secured to timely close out projects. Coordinates with Finance and Grant Management Lead. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 27 Project Value and Change Management Projects will be competitively bid whenever practical and cost effective, and traditional project change control methods will be used. The Project manager will maintain and up-to-date project change control log with all material changes being formally approved the TCC. Quality Assurance/Control QA/QC will be performed by the project management team. Strict check-out and commissioning procedures will be developed in the Factory Acceptance (FAT)and Site Acceptance test (SAT) plans. Adherence to test and commissioning plans will ensure quality system check out. Project Communication The Project initiation documents, and Project Management Plan (PMP) will contain a project communications plan detailing chain of command and appropriate communication meeting cadence and tempo. E. Technical Qualifications and Resources E.1 Quality Assurance/Control The project team (the BPMC and the TCC designated by the BPMC) combined have two hundred years of Railbelt system operations and engineering experience. The team is experienced and well versed in executing complex transmission line and substation projects in Alaska’s challenging environment. The Railbelt utilities have skilled engineers and designers, and the local work force includes IBEW journeymen technicians and linemen who have built the electrical system we have today. Engineering and design firms are available locally and in the Pacific Northwest who routinely propose on projects as envisioned in the application. Alaska has multiple highly skilled electrical contractors through the National Electrical Contractor Association (NECA) who employee workers from IBEW local 1547. They are versed in both high voltage transmission and substation construction. The IBEW has out-of-state traveler availability and a state-of-the-art apprenticeship school that can ramp up to meet demand. The NECA contractors have the specialized tools and equipment to undertake remote offroad transmission construction. Multiple projects have been completed over the years from Fairbanks to the Kenai Peninsula. Contractors have the expertise to use helicopter construction in remote areas to set transmission towers and string conductor. These specialized techniques have expedited construction and minimized environmental damage. Key members will be assigned to this project as necessary to ensure successful completion. E.2 Existing Equipment and Facilities The utilities have complex state of the art SCADA/EMS systems with an interregional ICCP link for data transfer. A complex network of ringed SONET compatible digital microwave and fiber assets and hardened stations at each of the BESS sites. The microwave and fiber systems are currently used for SEL high speed mirrored bit communications to enable high speed transfer tripping. Mirrored bits or an equivalent system is a likely candidate for interregional BESS and HVDC communications. As noted Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 28 above, dedicated, utility owned fiber and digital microwave does not currently exist between the northern and central regions however there may be dark fiber that could be acquired for this purpose. E.3 Relevant Previous Work Efforts, Demonstrated Innovations Numerous complex systems have been studied and successfully put into place in the Railbelt by this team. Installation of SCADA and EMS systems at all five utilities, installation of interregional digital microwave and fiber optic systems, and high-speed communication assisted transfer trip and line current differential protection on all Railbelt transmission lines, eigenvector/value analysis that defined and mitigated, the small signal instability points between the weak summer valley Railbelt grid and the Bradley Lake Hydroelectric project. The study of development and installation of the Railbelt’s multi- stage, multi-delayed under frequency load shed scheme is another example of a complex real-time control system developed and installed by members of the project team. E.4 Time Commitment of Key Members Key members will by assigned to this project as necessary to ensure successful completion. E.5 DOE Technical Services None BIL-GRID RESILIENCE AND INNOVATION PARTNERSHIPS (GRIP) Funding Opportunity Announcement: DE-FOA-0002742 Table of Contents A. Cover Page.........................................................................................................................1 B. Project Overview..........................................................................................................2-10 C. Technical Description, Innovation, and Impact.........................................................10-16 D. Workplan………………………………………………….................................................................16-24 E. Technical Qualifications and Resources ....................................................................24 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 1 A. Cover Page ● Battery Energy Storage/HVDC Coordinated Control ● Smart Grid ● Applicant – Matanuska Electric Association representing The Bradley Lake Project Management Committee (BPMC) ● The BPMC consists of the following organizations: i. The State of Alaska dba The Alaska Energy Authority (AEA) ii. Chugach Electric Association Inc., a Central Region cooperative (CEA) iii. Golden Valley Electric Association Inc., a Northern Region Cooperative (GVEA) iv. Homer Electric Association Inc., a Southern Region Cooperative (HEA) v. Matanuska Electric Association Inc., a Central Region Cooperative (MEA) vi. The City of Seward Alaska dba Seward Electric System (SES) ● Project Team Key Personnel i. David Burlingame P.E; Principal Electric Power Systems ii. Brian Hickey P.E.; Executive Director Railbelt Regional Coordination BPMC iii. Dustin Highers; Chugach Electric Association Inc. iv. Dan Bishop P.E.; Golden Valley Electric Association Inc. v. Ed Jenkin P.E.; Matanuska Electric Association Inc. vi. Larry Jorgensen; Homer Electric Association Inc. vii. Rob Montgomery; Seward Electric System viii. Bryan Carey P.E.; Alaska Energy Authority ● Project Location: Central Northern and Southern regions of the Alaska Railbelt electrical system Railbelt Militar Bases Area served by the Railbelt Grid Area served by the Railbelt Grid Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 2 B. Project Overview B. 1 Background Vision Alaska and the United States are at a crossroads. A nexus now exists with the need to develop a fuel-diverse low-carbon economy and a once in a generation opportunity to invest in infrastructure. At this intersection, the Railbelt utilities and the State developed the collective mission to build a resilient, clean, smart, and low-cost electrical grid. The grid of the future supports a fuel-diverse energy landscape that drives sustainable economic development in the state and ensures the cost-effective delivery of energy to the consumers of the Railbelt and beyond. The Railbelt utilities, acting together through the Bradley Lake Project Management Committee (BPMC) have a shared vision: a collaborative future in the Railbelt in which our communities come together and share resources to strengthen and build a smart, clean electrical grid that allows our members, our national defense infrastructure, and the communities adjacent to the Railbelt access to clean low-cost energy resources. The Battery Energy Storage/HVDC Coordinated Control (BES) Project, the subject of this GRIP Topic Area 2 application, is one of a series of projects that constitute the BPMC’s Grid Modernization and Resiliency Plan (GMRP or Plan). Through the GMRP, there exists an opportunity for a transformational series of transmission infrastructure improvements estimated to cost ~$2.9 B. Successful implementation of the GMRP will prepare the Railbelt grid in terms of resiliency and reliability necessary for the development of a more fuel diverse low carbon reality in Alaska that can serve as a model for the United States and the world. Opportunities Modernization: As described throughout this application, the Railbelt grid is an isolated, long- distance, fully functioning, electric grid built on a relatively small scale that serves nearly three quarters of Alaska’s population with aging infrastructure, inadequate by traditional industry standards. Through the GRIP, the BPMC recognizes that there is an opportunity for a successful modernization of the Railbelt grid primed to facilitate decarbonization of the broader Alaska economy. Due to the diversity within the Railbelt and scale of the infrastructure, the federal government has an opportunity to utilize the Railbelt grid as a model to demonstrate both the objectives and vision of the bipartisan Infrastructure Investment and Jobs Act (IIJA) and other initiatives. The lessons learned from this prototype will have broad applicability to the larger grids of the contiguous lower forty-eight states. Equity: As discussed more fully in the Community Benefits Plan, the Railbelt region is home to numerous federally recognized tribes and disadvantaged and underserved communities. There are over 200 federally recognized tribes in Alaska, many in the Railbelt region, and based on the 2010 census Anchorage was home to the three most culturally diverse census tracts in the US (followed closely by Queens, New York). More than 100 languages are spoken in the Anchorage School District alone. With this socially and economically diverse makeup, the Railbelt is the ideal area for the federal government to demonstrate how the benefits of the IIJA can be maximized. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 3 National Defense: The Railbelt serves five military bases, as depicted in figure 1, each of which has a vital strategic importance to national security. These critical bases contribute to the national defense from a broad range of perspectives including missile defense, global telecommunications downlink infrastructure, and F-22 high-speed intercept capability. As noted in the White House’s release of the Indo-Pacific Strategy in February 2022, these defense capabilities are vital to our national security and prosperity. The GMRP will support the transition of Alaska-based US DoD assets to a low carbon future. Economic Strategy: The Railbelt is essential to the broader state economy. The Port of Alaska, a federally designated Strategic Seaport, serves as the primary point of entry for virtually all cargo, food, building materials, and fuel for most of Alaska’s population. Additionally, Anchorage International Airport is the fourth busiest international airport in the world in terms of cargo throughput. The Railbelt is home to significant mining operations, including that of rare earth minerals critical to the US national security and other strategic imperatives. These assets are vital to the economy and security of both Alaska and the Nation. Benefits Through the BES Project, the Railbelt and the State will experience broad and substantial benefits. Those benefits include increased transmission capacity, enhanced interregional transfer capability, optimized network topology, improved system efficiency and reliability, increased operator situational awareness, reduction in carbon emissions, integration of renewables and other low carbon generation sources, facilitation of decarbonized beneficial electrification, and the eventual decarbonization of the electric grid. More significantly, this Project and the broader Plan will help keep electric rates lower, longer throughout the State. Alaskans pay some of the highest electric rates in the country, which disproportionately impact the disadvantaged and underserved. Keeping rates lower on the Railbelt will in turn help address the high cost of energy in rural Alaska not served by the Railbelt, close to 30% of the state’s population. This cost is mitigated through the State’s Power Cost Equalization Program, based in part on the price of Railbelt electricity. The GRIP Program’s objectives are met and complemented by the BPMC’s goal of a resilient, clean, and low-cost electrical network that supports sustainable economic development in the region, decarbonization, and cost-effective delivery of energy. Figure 1: Military Assets Served by The Railbelt Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 4 Effectively, the Railbelt is a proving ground where US DOE and other federal agencies can evaluate and successfully demonstrate transmission resiliency improvements in preparation for electric decarbonization both technically and on a community basis. All the electric utilities in the Railbelt are electric cooperatives. Thus, virtually all benefits from this grid modernization effort flow directly to the member-owners, the residents of the Railbelt. The BES project will have full support and collaborative cooperation of the BPMC project team. This team consists of representatives of each of the five Railbelt electric utilities and the State of Alaska, dba, AEA. The BPMC team members are committed to the GMRP, subject to governance board approval and vetting through the National Environmental Policy Act (NEPA) process. The team plans to apply for all IIJA and Inflation Reduction Act (IRA) applicable federal assistance for GMRP projects. In addition, the team is seeking State appropriations to augment these federal funds. The GMRP upgraded grid will create an unrestricted electron freeway and prepare the Railbelt to optimize the use of cost-effective, low-carbon energy technologies by eliminating current technical and geographic constraints. The Railbelt Grid The Railbelt electric grid is unique in North America as it is technically a fully functioning long- distance electrical grid on a very small scale. The Railbelt is characterized by three load- generation regions with four load-balancing areas. These load-balancing areas do not coincide precisely with the load-generation regions. These load-generation concentrations, known as the Northern Region (Fairbanks-Delta Junction), the Central Region (Anchorage-MatSu), and Southern Region (the Kenai Peninsula), are tied together with two long transmission lines operating at 115kV and 138KV. The grid provides electricity to approximately 70% of the state's residents and generates 80% of the electricity in Alaska. It extends over 700 miles from the Bradley Lake Project, located at the head of Kachemak bay near Homer, Alaska, in the Southern Region, to Delta Junction in Interior Alaska, roughly the distance from Washington, DC to Atlanta, GA as depicted in figure 2. The grid traverses inhospitable mountainous subarctic terrain. The region is laced with highly active seismic zones and is subject to volcanic eruptions, forest fires, flooding, and fierce annual winter storms. The grid's assets vary from high voltage (138 kV and 230 kV) submarine cable crossings in Cook Inlet to remote "helicopter/riverboat - access-only" river crossings and numerous transmission structures well above 2000 feet. Unlike many areas in the contiguous lower forty-eight states, the Railbelt has received minimal federal investment in grid development. The Eklutna Hydroelectric Project, initially constructed in the 1950s, was the last major federal project in the Railbelt that included a transmission line component. This project was rebuilt by the Bureau of Reclamation's Alaska Power Administration after the 1964 "Good Friday” Earthquake and sold by the Federal government to Central Region utilities in the early 1990s. The Northern Region is marginally interconnected, primarily at 69kv and 138kV. The Central Region is moderately well interconnected with multiple 230, 138, and 115 kV lines. The Southern Region is also interconnected at 115 kV but includes a radial feed to the SES system. A tight power pool operates in the Central Region, and an active economy energy market exists but is severely limited by transmission constraints. A reserve-sharing pool exists between all three regions. Due to the relatively feeble regional interconnections, the Railbelt Grid is Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 5 technically characterized as "transient stability limited," with machines under dynamic stress swinging against other machines within the region; and with regions swinging against each other across the light interregional interconnections. The grid is susceptible to and has experienced large-scale small-signal instability oscillations during the annual nexus of low lake elevations at Bradley Lake, summer valley load conditions, and faults on the Alaska Intertie nearly 300 miles north of the Bradley Lake Project. Voltage stability, which varies from marginal to good depending on the specific area, has been improved with the addition of six static VAR compensators at critical locations. The Railbelt Grid operates under a subset of North American Electric Reliability Corporation (NERC) standards modified to account for the scale and nature of the interconnection (the grid's system bias is variable and ranges from 3-10 Mw/.1 hertz). In 2024 these standards will become mandatory and enforceable under a recently formed and certificated Electric Reliability Organization, as developed through the Railbelt Reliability Council. The grid has a sophisticated under-frequency load shed scheme which sheds load to match generation in four stages with varying time delays and, in some cases considering frequency rate-of-change. Traditional day-ahead and real-time security constrained economic dispatch are run in each LBA with net interchange, and frequency monitored and managed to NERC CPS 1 and 2. Dynamic events on the grid occur and resolve very quickly (2-10 seconds) when compared with the much larger North American grids (the Eastern Interconnection, the Western Interconnection, and ERCOT), which resolve in tens of minutes. The grid's peak demand is roughly 750 MW compared to ERCOT's (by far the smallest of the North American interconnections) peak demand of 85,000 MW. The grid's annual energy consumption is approximately 4,800 GWH compared to ERCOT at 339,000 GWH. The Railbelt’s Grid Modernization Resiliency Plan (GMRP) Today, multiple change drivers are reshaping the broader energy landscape in Alaska and across the world. Geopolitical shifts are dramatically altering global energy markets. Decarbonization policies and technological advancements, shaped by increasingly dramatic climate change, are both the result of and contributing to a shift in popular sentiment about energy and the environment. Regionally, uncertainty around Cook Inlet natural gas and broader fuel supply issues for the utilities is a critical – and shared – challenge looming on the near-term horizon. In response to this shared challenge, the BPMC has come together to develop a broad-based, long-term plan to ensure the future energy viability of the Railbelt from a social, economic, and technical perspective. Figure 2: Grid Modernization Resiliency Plan Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 6 The technical aspect of that Plan is the GMRP, of which the Battery Energy Storage/HVDC Coordinated Control Project is a component. This Plan will be incorporated into Alaska’s broader State Energy Security Plan as that document is developed in the coming months. We intend to apply for federal funding assistance for specific GMRP components in each of the five funding-year periods of the GRIP, IRA, and USDA RUS loan programs. In addition to our federal funding requests, we are seeking State assistance and the remainder of the total plan costs will be funded by Railbelt utilities. Our estimated total cost for the GMRP is $2.87B over fifteen years. Without significant Federal and State investment, the GMRP plan and this Project are beyond the capabilities of the Railbelt utilities and AEA. The team assembled for this Project as shown below consists of stakeholder outreach experts, engineers, project managers, and all the executive-level decision-makers in the Railbelt. The Team will work diligently to integrate other regional stakeholders into the process. The priority in diversifying the Railbelt fuel supply and decarbonizing the Railbelt Grid must be stabilizing its primary control variable frequency and decongesting the transmission system. These improvements are required irrespective of the nature of fuel supply diversity and decarbonization solutions. In 2010 the Railbelt's frequency was equal to 60Hertz approximately 44 % of the time. By 2021, the grid operated at 60Hertz about 17% of the time. The primary causes of this deterioration of frequency control are the introduction of lighter, more efficient aero-derivative turbines, efficiency-driven (as opposed to response-driven) plant control systems, and non-dispatchable renewables in the form of solar and wind generators. Decongesting the grid will require upgrading existing transmission lines and building a new transmission interconnection from the Kenai to the Central Region and on to Healy in the Northern Region. A subsequent phase will include a transmission interconnection from Wasilla to Glenallen and north to interconnect with the GVEA system at Fort Greely and the Ground- Based Mid-Course Missile Defense system. The Alaska Railbelt grid was not established until 1985 with the completion of the Anchorage- Fairbanks Intertie, connecting Golden Valley Electric Association (GVEA) to the southcentral utilities, concurrently with the strengthening of the tie between Chugach Electric Association (CEA), Matanuska Electric Association (MEA) and Municipal Light & Power (ML&P, subsequently acquired by CEA) in the Southcentral region. In 1991, the Bradley Hydroelectric project, including a new 115 kV transmission line completing a 115 kV loop to the Bradley projects was completed by the five interconnected utilities (Chugach, GVEA, ML&P, MEA, Homer Electric Association (HEA) and the City of Seward (SES)) in partnership with the State of Alaska’s Alaska Energy Authority (AEA). Together, these entities constitute the Bradley Lake Project Management Committee (BPMC). In 1992, the BPMC identified stability constraints on the single 115 kV transmission line between the Bradley Lake/HEA area and the southcentral region and installed two Static VAR Compensation systems coupled with power oscillation damping to substantially increase the transfer limits between the southern and south-central portions of the system. These two southern SVCs were in addition to three additional SVCs located on the Anchorage – Fairbanks Intertie required for increased power transfer across the interconnected system. This increase in transfer limits allowed more efficient use of generation throughout the Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 7 entire Railbelt region, allowing increased flexibility and use of existing hydro resources in the southern portion of the system. The Railbelt utilities have been actively investing in energy infrastructure and storage projects since 1985. Their efforts have resulted in the successful installation of more than $1 billion worth of natural gas-fired combustion turbine and reciprocating engine-driven electric generators since 2007. In addition to this, the Battle Creek Diversion project completed by BPMC members in 2020 is estimated to add around 37 GWH of hydroelectric energy to the 400 GWH Bradley Lake reservoir, which will significantly increase grid efficiency and resiliency. To further enhance grid resiliency and efficiency, the Railbelt utilities are pursuing state of the art energy storage systems. Homer Electric's 46.5 MW- 93 MWh battery in the Southern Region and the Chugach-Matanuska Electric tight pool’s procurement of a 40 MW- 80Mwh battery in the Central region will bolster the Railbelt’s energy storage capabilities. Furthermore, Golden Valley Electric's study on the replacement of the Northern region's 46 MW-10 MWh battery, which has almost reached the end of its useful life, will be completed by mid-2023 and all BESS systems under this project application are expected in place by fourth quarter 2025. The Railbelt system is constrained by stability limits to values considerably less than the thermal capabilities of the single interconnecting transmission lines. Current transmission constraints, depending on direction, limit the transfers of energy between regions to less than 10% of the combined system’s peak demand of approximately 750 MW. Because of the constrained transfers and single transmission interconnections, generation within the Railbelt has historically been regionalized, with each region forced to provide its own generation and reserves required to operate islanded for extended periods of time. The transmission deficiencies and stability limits have constricted the use of renewables on the system as each region is required to provide balancing services for its own generation and load. To kick off the Railbelt Backbone Reconstruction project1, and to enhance the energy storage effort, the BPMC issued $166.5 million in bonds in 2022. Sixty-five percent of this bond package is dedicated to transmission line construction, and 35% to energy storage, and additional funding is being sought from the State of Alaska. With DOE funding, the successful completion of the BESS/ HVDC2 coordinated control project is expected to unlock the full potential of the Railbelt utilities' investment in battery energy storage for enhanced grid resiliency, transfer capability, reduced carbon emissions through lower reserve requirements, more efficient use of the electrical system, and lowering impediments to renewable development. In conclusion, using DOE funding to unlock the full potential of State of Alaska and Railbelt funding, the Railbelt utilities' investment in energy infrastructure and storage projects will form a significant step towards achieving greater grid efficiency and resiliency, lower carbon emissions and an increased ability to integrate variable generation renewables. 1 The Railbelt Back Bone (RBR) Reconstruction project is the subject of the project team’ Topic 1 GRIP application. 2 The HVDC Submarine cable is a part of the State of Alaska’s funding cycle 1 GRIP Topic 3 assistance request Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 8 B. 2 Project Goals The goal of the project is to increase the transfer limits of the existing transmission interconnections between each of the three regions using a coordinated control system. Thus, coordinating the actions of three battery energy storage systems in each of the areas in conjunction with a planned HVDC cable between the southern and central region. The predominant goal is to optimize the use and capability of every resource that constitutes our transmission grid and increase the capabilities of the grid by control or other non-wire alternatives to the greatest extent possible. The project will result in high-speed data transfers and status reports to system operators and provide resiliency to all areas of the grid by allowing operators to immediately identify which resources can be used for service restoration. The project will use real time automation controllers (RTAC)3 to monitor variable generation and spinning and operating reserves in each area and automatically schedule battery regulation and contingency reserves in the optimum manner to maximize the use of renewables across the system, while increasing the reliability of the grid through reserve optimization. The project will significantly reduce the use of thermal generation for regulation and contingency reserves - effectively increasing the efficiency of the security constrained economic dispatch, conserving fuel, and consequently reducing carbon emissions. Critical to achieving this goal will be the real time monitoring and gathering of data over a Wide Area Network. Identifying and managing acceptable communications latency will be key to successful real-time control of a high-speed device like a BESS. At a less technical and more holistic level, execution of this project will require a highly skilled workforce and the project will provide on-the-job training to the engineers and technicians essential for implementation. Our established relationships with the building trades, primarily the AFL-CIO and International Brotherhood of Electrical Workers (IBEW), will enable good paying union jobs during the installation, commissioning, and maintenance of this system. B. 3 DOE Impact The DOE funded BESS Project will increase transfer capability between regions, decrease fossil fuel-based reserve requirements, thereby, reducing operating costs and carbon emissions, and improving resiliency for the entire Railbelt. Commercially, the Railbelt regions are composed of small businesses and, except for the Northern region served by GVEA, very few industrial loads or sources of revenue other than residential customers. DOE funding will catalyze investment in the grid, enabling both State and utility investment dollars. Without DOE and State funding, this transformative transmission improvement is beyond the financial capabilities of the Railbelt utilities absent increasing rates to our member-consumers to undesirable levels. B. 4 Community Benefits Plan The improvements proposed by BESS will have minimal visual/physical impact on stakeholders, have minimal anticipated negative environmental consequences, take place largely on utility owned property, have already been publicly vetted by 3 of the 5 participating utility 3 SEL 3530 RTAC with imbedded IEC 61131 logic engine or equivalent. These devices have integrated cyber security features which meet or exceed AK-CIP compliance. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 9 cooperatives via inclusion in their Capital Improvement Plans (Homer, Chugach, and Golden Valley), and have no anticipated negative impacts on vulnerable populations. Therefore, to ensure that this “Community and Labor Engagement” section is both useful and practical, BPMC is taking this opportunity to initiate public participation planning not only for BES but for the larger GMRP, of which BESS is one part. B. 5 Disadvantaged Communities This project is anticipated to provide significant benefits to Alaska’s DACs both on and off the Railbelt. There are 22 census tracts that qualify as disadvantaged4 (median DAC score=18) on the Railbelt, with a combined population of 81,921.5 There are a further 17 Alaska Native Village Statistical Areas (ANVSA) on the Railbelt6, with a combined population of 160,486.7 These communities will receive direct benefits from BESS via reduction of their energy burdens. BESS will decrease line losses, resulting in reduced thermal spending of 10-15%, and increase economic dispatch by increasing transmission capacity.8 Four of the five Railbelt utilities are member-owned, while the fifth is City-owned, so these expense reductions should transfer to reduced consumer costs. B. 6 Long-term Constraints The project will not impose long-term constraints on any resources of communities, boroughs, tribes or other entities or agencies. In fact, the project will relax constraints on existing facilities and resources. Additionally, the installation of this control scheme will reduce the use of Cook Inlet Natural Gas extending the available transition period and reducing the long-term negative effects on communities’ access to natural gas resources for home heating and electricity. B. 7 Climate Resiliency Strategy The Railbelt region is laced with highly active seismic zones and is subject to volcanic eruptions, forest fires, flooding, and fierce annual winter storms. Looking forward, warming permafrost will increase tower foundation challenges across the region. In the summer of 2019, one of the hottest summers on record, the Swan Lake fire islanded the southern region from the rest of the grid for several weeks. This separation of the southern and central-northern regions cost millions of dollars in additional fuel. The result was many tons of additional carbon emissions as the central-northern regions ran thermal generation to make up for their isolation from the Bradley Lake hydroelectric project. From a resiliency perspective, both the islanded southern region and the central-northern region were more susceptible to system disturbances and the negative effects of high ambient temperatures on available generation capacity. The grid's assets vary from high voltage (138 kV and 230 kV) submarine cable crossings in Cook Inlet5 to remote "helicopter/riverboat -access-only" river crossings and numerous transmission 4 DOE Disadvantaged Communities Reporter 5 American Community Survey 2021 5 Year Population Estimates 6 2020 U.S. Census, DOE Disadvantaged Communities Reporter 7 American Community Survey 2021 5 Year Population Estimates 8 Brian Hickey, Project Lead, P.E., PMP., Brian.Hickey@mea.coop, conversation with Curtis Fincher via Zoom, 8:00- 8:30 am, March 1st, 2023. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 10 structures well above two thousand feet located at high northern latitudes. All BESS and BESS control facilities will be designed to perform at or in excess of specification in this harsh climate. For example, due to the extreme cold temperatures in Fairbanks, the GVEA BESS will likely be located entirely within a seismically designed, climate-controlled structure of 74,0000 SQ FT. Significant lessons regarding climate and earthquake resilience will be realized from this project which can be disseminated to other regions in the contiguous lower forty-eight states. C. Technical Description, Innovation, and Impact C. 1 Relevance and Outcomes The project consists of developing an intelligent controller deployed in each of the region’s Battery Energy Storage Systems (BESS) and the HVDC submarine cable terminals, installing high- speed communications from system protective relays and frequency sensors to each of the region’s BESS, future HVDC controller, and to control rooms for system operators. Importantly this coordinated control will operate over a large geographic footprint with the BESSs located hundreds of miles apart. The integrated high-speed communications enable coordinated BESS/HVDC response to contingencies that limit the transient stability of the system. The high- speed control allows differences in transient frequencies between each of the areas to be minimized, decreasing the magnitude of the system’s first swing stability response to the contingency, and increasing the transfer capability between regions. The BESS controllers also utilize synchro-phasor technology to detect changes in the transmission system topology that does not result in islanding between regions. The change in phase angle between regions will be used to control BESS output to manage the transfer between regions until automatic AGC or operator intervention can make long-term corrections or adjustments. Communications will also allow the coordinated scheduling of each of the BESS/HVDC controllers for regulation to meet line contingency and generation contingency requirements. The coordinated scheduling allows the BESS systems to increase the total amount of BESS supplied reserves and limit additional reserves from other fossil fuel generation to less than 10-15% of total required reserves, conserving expensive natural gas and reducing carbon emissions. The primary outcomes of the project are initially to increase transfer capacity over the single transmission lines connecting the southern and central and central and northern regions of the Railbelt. The increased transfers are expected to result in 1) more efficient operation of the Railbelt power system by increasing transfer limits based on real-time assessment and positive control action of battery and system regulation and the state of battery energy storage systems, 2) increased transfer of renewable energy between the various regions, 3) real-time coordination and optimization of BESS reserve contributions for generation/transmission contingencies and variable generation regulation, 4) real-time indication of key transmission and generation assets for all system operators, 5) real-time analysis and annunciation to system operators of generation or transmission outages that require operator action or that trigger BESS reaction, and 6) real-time summation of variable generation regulation requirements from all three regions, providing a significant reduction in the total amount of regulation required over all three regions. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 11 The longer-term goals are to incorporate the future HVDC controller into the coordinated BESS scheduler, allowing additional flexibility and control of resource scheduling between the southern region and the central-northern regions. In an isolated grid such as the Railbelt, any change in renewable energy that is not countered by an equal change in controllable energy results in a noticeable frequency deviation. This frequency deviation can be severe in a system whose system frequency response is as low as 3 MW/ 0.1 Hz. The frequency nadir generally occurs within 2-3 seconds of the initiating event. As the grid evolves into less conventional thermal units and more inverter-based generation, the use of BESS/HVDC technologies will become more critical in controlling system frequencies during steady-state conditions to maintain the integrity of underfrequency load shedding programs. The first stage of these programs is set at 59.0 Hz with a time delay of only ten cycles. Second, third and fourth stages are staggered 0.3 – 0.5 Hz between stages with comparable time delays. As BESS/HVDC systems increase both the short-term (cycles-seconds) and longer-term (minutes) response to generation contingencies, the ability of the smart coordinated BESS/HVDC controller to monitor system conditions and allow operator discretion in the utilization of hydro resources to relieve BESS discharges during longer-term renewable energy changes will be essential to ensure that BESS capability is available for contingency and resiliency requirements as well as maximizing the system’s stored water resources. Due to the costs of developing a transmission grid within the Railbelt, the planning and operating criteria applicable to the Railbelt has been considerably different than the criteria used throughout the contiguous lower forty-eight states. Due to large development costs and a small customer base, the Railbelt has been forced to utilize innovative solutions and technologies to overcome the lack of financial base required to support a grid that would meet the planning criteria employed in the contiguous lower forty-eight electrical grids. However, as load has matured and more technical resources are deployed by consumers of the Railbelt, the requirement by its users for improved reliability and resiliency has increased as well as the desire and demand for the increased use of renewable energy within the grid. The expanded use of renewables within the grid is severely hamstrung by the limitations of the grid’s reliability and its inability to provide adequate transfers between regions or to allow regulation across the entire grid as opposed to by region. The implementation of the acclaimed Coordinated BESS Controller is an exclusive project that can improve transfers and increase renewable implementation within the Railbelt. The project’s goals are impeccably aligned with the goals of the FOA at it will increase the resiliency and reliability of the Railbelt grid as a whole and in each of the regions of the grid. Additionally, it will expand the supply of geographically and technically diverse resources by enabling increased transfers across all regions and performing regulation across the entire Railbelt as opposed to the current practice of independent regulation requirements with each LBA. This practice will allow geographically diverse resources to interact and reduce the regulation requirement of the Railbelt. Ultimately, the project will strengthen grid efficiency and streamline the grid’s acceptance of additional renewable energy while simultaneously allowing system operators more visibility and control across the entire grid. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 12 C. 2 Feasibility The members of the project group have completed feasibility studies9 that indicate the control of transient frequencies within each region can have measurable impacts on increasing the transient stability rating of each transmission path between the regions. The amount of positive impact depends on many factors, including the location and characteristics of renewable resources, the quantity and location of conventional generation units, and how those resources are coordinated with the Coordinated BESS Controller. As the system evolves and the new HVDC link is added, the possibility of using the simulated inertial response of inverter-based generation controlled by system triggers as opposed to solely from frequency response could provide significant transient frequency response. As such, lessons learned will be extremely useful in larger grids with substantial inverter-connected generation. Transient stability studies have been used for many years in the Railbelt to establish the transfer limits used for normal operating conditions as well as for future resource planning studies. Team members for this project recently simulated and determined the root cause of severe oscillations between the southern, central, and northern systems. These 250 MW oscillations are the result of weak transmission system characteristics and the interaction with a large hydro plant in the southern region. The oscillations can be controlled by coordinated BESS scheduling within the Railbelt as outlined in this document. The studies will determine the needs of each region during events that exceed the planning criteria, as described in the Railbelt Reliability standards, or that occur prior to the construction of facilities necessary to bring the region into compliance with the planning criteria. Additionally, to avoid complete collapse and provide restoration capability and increased resiliency, the needs of each region will be balanced against the needs of the entire Railbelt. Decisions will be made and confirmed with simulations on the prioritization of control sequences and the evolution of these sequences and control requirements as the system progresses toward planning and operating criteria closer to that of the contiguous lower forty- eight states. The team recognizes the complexity and quantity of simulations required to complete the design optimization. Although the exact simulations required to determine the actual control logic have not previously been completed, simulations involving complex sequences and cascading outages and control requirements have been completed for other purposes. The history and knowledge of over 30 years of simulation experience by key team members ensures the technical feasibility and enabled the team to assess the actual feasibility of key performance factors. The BES project will require the ability to schedule and coordinate the BESS controls in all three regions of the system. BESS systems currently exist or are being constructed in the southern and central regions and the northern region has an existing BESS that is being studied for replacement. The BESS will require additional control and communication upgrades. Final studies will indicate which BESS units may require incremental sizing upgrades as part of this 9 No studies specific to this application have been completed; however, the relative percentage of reserve reduction has been inferred from study work completed for other purposes. Studies to validate this value will be completed in phase one study work, as a part of the first go/no-go milestone. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 13 new task requirement to provide the ability to meet the overall grid requirements as well as those of the individual region. The first phase of the project will be completion of system-wide transient stability simulations to determine the maximum allowable BESS control times for each of the various contingencies within the system. The control time will include the BESS/HVDC control latency plus the communication delays between each of the critical system monitoring points and the BESS/HVDC controllers. These transient stability simulations will also provide specific metrics in terms of increased transfer capability and reduced thermal spinning reserve which will be incorporated into our SMART metrics. Development of these metrics will be a key Go/No-Go milestone for the project. High-speed communication paths exist throughout most of the Railbelt. A key missing communication link is the path required between the northern and central regions. A survey and test of existing communication paths will be required to ascertain bandwidth and latency capability to determine the required communication upgrades along each communication path. Due to the age of the existing communication system, it is assumed that there will be communication paths that will require upgrade. A new communication path will need to be established and integrated into the existing infrastructure to tie the northern BESS and northern system operator into the central and southern regions. C. 3 Innovation & Impacts Current Standards There are several methods to determine the actual transfer limit of transmission paths in use throughout the US electrical grid. These methods are primarily based on power flow and transient stability modeling techniques. These modeling techniques produce static transfer limits for system operators to observe. Project Improvement and Innovation The proposed project is innovative because rather than using model transfer capability limits it will use real-time control action to improve system performance, increase transfer limits, and optimize power transfer ability between regions as opposed to a determination of static limits for system operators. The proposed control system will assess the actual capacity of each BESS, actual power flows on each interconnecting transmission system, reserves required for generation contingencies in each area, reserves required for transmission contingencies, actual power angle between each region and reserves required by area to control inter-area oscillations. The control strategy will monitor and determine the net variable generation regulation requirement and forecast the regulation requirement in terms of system-wide BESS regulation requirements in coordination with other scheduled generation available for regulation in accordance with system operator limitations and system reliability standards. Advantages As opposed to just monitoring real-time power angles, inferring stability limits between regions, and passing this information on to operators, the controller will assess natural power angles Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 14 and actively change the power angle during steady-state conditions or react and control transient frequency oscillations immediately following a contingency. This positive control action will mitigate transient changes in power angle across the regions, increasing the transfer capability of the transmission path. As variable generation becomes a larger percentage of the overall grid generation mix, the ability to ascertain transfer limits between regions as well as coordinate contingency and regulation reserves between various grid resources will become more important and have a larger impact on the efficient use of those resources. Additionally, the economics of non- optimized use of system resources across regions or load-balancing areas could result in significant opportunities for reduced operating costs, carbon emissions and increased use of renewables. There are potentially large wind resources available in the northern and southern extremes of the Railbelt. Currently, these projects are not economically feasible due to the limited ability to transfer energy between regions and the requirement to provide regulation for the entire project in only the region it is located. In addition, there are potentially large hydro resources in the southern and central regions of the Railbelt as well as in the Copper Valley region10. These hydro resources also compete with the limited transfer capability between regions as well as the existing and planned hydro resources located in the southern region. The coordinated BESS/HVDC controls will mitigate the regulation requirement of individual regions, lowering the financial barriers to these variable energy resources. Furthermore, the coordinated controls will optimize the use of hydro resources to provide secondary regulation resources in conjunction with the BESS regulation, providing more regulation capability for wind and solar generation. The reduced regulation requirements are expected to decrease the financial barriers of renewable projects in the Railbelt and bolster projects across the entire length of the Railbelt, providing more reliable renewable energy through geographic diversity. C. 4 State, Local, Tribal, Regional, and National Resilience, Decarbonization In essence, reducing the dependency on natural gas to produce electricity will increase the length of time allowed for the transition away from Cook Inlet Natural gas for non-utility users. The State of Alaska has endorsed a forthcoming State Energy Plan. Furthermore, Cook Inlet natural gas suppliers have also announced limitations on the availability of natural gas for electric and gas utility use beginning in 2024. The expanded transition period will enable more time to move heating systems away from this fuel source and development of non-gas alternatives. The limitation on the availability of Cook Inlet natural gas further underscores the need for transitioning towards alternative energy sources. This transition period will provide a prime opportunity for stakeholders to explore and develop alternative energy solutions for heating and additional purposes. Fundamentally, all alternatives for replacement of both electrical production and heating require an expanded electrical grid. 10 A tie to Cooper Valley may be included in a late funding cycle of the State of Alaska’s application for GRIP topic 3 assistance Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 15 Clean Energy goals are widely supported by team members within the Railbelt and are consistent with the present Administration's decarbonization strategies. It is also in alignment with other goals adopted by Alaska organizations and communities outside of the Railbelt. The project empowers the Railbelt to meet and follow national and statewide goals and plans adopted or being considered by Alaska government agencies, legislative or executive branches, tribal governments, cities, and boroughs. C. 5 Deployment Impacts; Further Deployment; Additional Private Sector Investment The deployment of the coordinated BESS control project, including the associated high-speed monitoring and operator notifications, will have a significant impact on the investment of the Railbelt’s private sector. The coordination of BESS and HVDC controls throughout the Railbelt will bolster the amount of renewable generation projects supportable by the system. Absent the coordinated scheduler, the amount of renewables supportable within the Railbelt would be limited to the regulation ability within each region; the summation of which would be much greater than the reserves required when considering the Railbelt as a whole; thus, increasing the investment required for the Railbelt in obtaining regulation reserves. The coordinated scheduler will allow renewables to be coordinated between regions, allowing geographic diversity for regulation requirements as well as capacity determination for project evaluation. The lower regulation requirements and increased transfer capability will allow or increase variable generation penetration, reduce electric rates, and reduce barriers to entry for independent power producers into the Railbelt generation market. C. 6 Smart Grid Development The coordinated BESS controllers’ future capabilities include battery systems utilization in residential or commercial customer facilities as well as grid edge EV charging capabilities to augment the storage capacity of the primary BESS installations. In addition, the ability to control and manage load resources could be utilized in the same manner as the load-side storage. The aptitude to utilize both resources as longer-term BESS response strategies allow incorporated grid security and resiliency requirements sans high-speed response. The flexibility offered by incorporating them into the coordinated control system of the BESS increases the use of distribution-located resources in future deployments. Preliminary studies have indicated that while coordinated control and response of utility sized systems improve the transfer capacity between regions, the uncoordinated control of load-side resources may impact transfer capacity between regions. Augmenting the BESS capacity with regional load side resources effectively increases the capacity. C. 7 System Flexibility The existing Railbelt system is severely constrained with little flexibility. The restrictions on the scheduling and use of the gas delivery system to serve the thermal generation coupled with the lack of transmission pathways has placed severe restrictions on the development of renewable energy systems. Current contractual natural gas scheduling requires a 24 hour-day advance schedule in four-hour blocks within the Cook Inlet basin. This limited transfer capability Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 16 between regions11 and severe gas scheduling restrictions increase the difficulty of incorporating variable generation resources into the system. The hydro resources can be utilized to provide long-term regulation requirements for the grid. However, all the hydro’s response characteristics are too slow to respond to the rapid changes experienced with variable generation. Efforts to regulate with hydro resources alone results in unacceptable frequency deviations across the entire grid. Furthermore, a combination of gas- fired resources and hydro resources regulations results in unacceptable fluctuations in gas delivery by the producers. The proposed project will allow all BESS systems throughout the Railbelt to be utilized in conjunction with the hydro resources to provide regulation for the renewable generation. Without coordinated response of the BESS across all regions, the system has limited ability to regulate variable generation. The lack of ties to other systems requires both fast/short-term response from the BESS as well as slower, long-term response from the hydros. The Coordinated BESS Control will interface with the renewable metering across the system and provide an AGC signal to each system operator, allowing the BESS response in each operator’s Load Balancing Area to be included in the bias calculation for each utility interchange. This coordination increases the amount of renewable energy supportable to the system by the entire grid as opposed to the limitations of each region. To reduce the total amount of regulation required for the system, the renewable generation must be treated as a system resource. To accomplish this and reduce the amount of regulation required, the spatial diversity of resources spread across the 700-mile transmission system must be utilized. The lack of transfer capability precludes the use of geographic diversity between regions in mitigating the overall regulation requirement of the system. Consequently, there is currently limited resource development in the northern and southern regions, the regions with the highest rated renewable energy projects. The project will increase transfer capacity between each of the regions and allow system operators to schedule more energy to and from each area as an entire Railbelt as opposed to relatively small system needs control areas. The high-speed control will allow coordinated frequency response from all system resources, regardless of location and allow all regions to benefit from using the slower responding regulation capability of the hydro units. This distributed control and monitoring ensures each area provides only its required regulation energy to increase the flexibility of scheduled generation and BESS reserves. D. Workplan D. 1 Project Objectives Objective 1: The project will develop and install high-speed controllers for each of the BESS/HVDC systems capable of controlling transient frequencies following contingency events and large system power swings caused by variable energy resources. 11 75 MW ~ 10% of peak system load between any two regions Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 17 Objective 2: The ability to control transient frequencies and hence phase angles will increase the transfer capacity between each of the regions. The increased transfer capacity will result in better use of variable renewable resources in all regions of the Railbelt. Objective 3: The high-speed controls will have the capability to determine instantaneous generation levels of all variable generation, and to ascertain the impact of frequency deviation to the entire grid and will optimally dispatch the BESS resources in each region and lower the total required regulation requirements for the Railbelt. Additionally, the lower regulation requirements will allow more renewable generation to be utilized without increasing the amount of regulating capacity required in any region or the entire grid. Finally, high-speed feedback to control systems and system operators following contingency events at a summary level, indicating the available resources and charge state of all systems will allow for increased situational awareness, provides greater response to resiliency conditions. Objective 4: The expected response is a coordinated response to regulation and contingency conditions within all regions of the Railbelt. The Railbelt will evolve from a system that has extreme difficulty operating with even small amounts of variable generation to a system that can accept larger amounts of variable generation while at the same time improving reliability and resiliency, at reduced operating costs and significantly less carbon emissions. Objective 5: During steady-state conditions, the primary change in the observable power system will be the three BESS units operating in conjunction with the hydro units to control system regulation requirements. The BESS units will be operating in a coordinated fashion without the tell-tale deviations in power system frequency. As the ability to regulate more renewable energy develops, coupled with increased transfer capability between regions, development of renewable resources with favorable diversity factors across the system will increase. D. 2 Technical Scope Summary Overall Work Scope The project will utilize SEL RTAC 3345 controllers at each BESS location and at critical transmission stations in the Railbelt. In addition, the project will utilize SEL RTAC 3345 controllers at all major renewable energy resources to incorporate the response of the renewable generation as well as the steady-state output of each renewable resource to the BESS controllers for compilation and computation of each BESS response for both regulation and contingency responses. Tertiary level control for the coordination of multiple microgrids and grid storage batteries requires high speed communication of time synced power system phasor data. The Railbelt regions have standardized on Schweitzer Engineering Laboratories (SEL) control and protection devices. Our market evaluation of suitable control systems favors a solution using a distributed network of dedicated Schweitzer Engineering Laboratories (SEL) 3555 Automation Controllers sharing Synchro-phasor data from SEL protective relays throughout existing substations. Figure 3 shows a conceptual block diagram of the proposed control system. Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 18 Real time processing and control of power system data requires that all data within a discrete sample time stays correlated as it is passed across the network and processed. The high-speed nature of power system control limits the available hardware options to manufacturers that support communications protocols with this functionality. The best suited and most widely used communications protocol for this is IEEE C37.118 Synchro-phasor. The IEC 61850-90-5 protocol can achieve a similar level of control however the existing install base of relays likely does not support this version of the protocol. The onboard logic engine and native protocol conversion make the SEL 3555 an ideal controller to both process synchro-phasor data and communicate with the third party microgrid controllers for communications. Other manufacturers offer Phasor controllers with similar processing ability but lack the communication flexibility needed to interface with the proprietary controllers used in microgrid installations. This flexibility along with the large existing install base of SEL equipment throughout the state makes the SEL-3555 the ideal control system solution for this application. The RTAC 3345 will monitor frequency, voltage, power flow and phase angles across these key points. The control system will need to consider the security of each region, the security of the entire grid, unit contingencies, tie-line contingencies and overall system regulation requirements, dispatch, and capacity of any other possible regulation resources as well as changes in unit commitments or line outages not associated with contingency events. Based on power flow, phase angles and the system topology, each BESS will be dispatched in accordance with the optimization algorithm. Following corrective action of the controller and the system has reached steady-state and both the BESS and AGC control transient actions have been completed, the system will re-evaluate control algorithms for the new system conditions. New protective relays utilizing traveling wave differential protection scheme such as the SEL- T400L Time Domain Line Protection will be utilized on each transmission line interconnecting two regions. These protective relays can provide extremely fast clearing and accurate fault locations typically within one tower location of the fault location. In these interconnecting transmission lines, the ability to accurately and automatically pinpoint fault locations for transmission lines that are not accessible via conventional methods is extremely importation for reliability and resiliency. The upgrades to communications system will allow data exchange between regions and improved situational awareness for system operators. Figure 3: Proposed Control System Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 19 In addition to the interconnecting transmission lines, all key 230 kV lines that define the critical clearing time of the system and transverse difficult regions or areas will be upgraded to SEL- T400L protection as defined during the transient stability analysis. It is anticipated that all lines within one bus of an interconnecting transmission line require upgrading. Rapid changes in system phase angles measured across the interties will indicate a change in the system topology. The BESS units will monitor changes in phase angle and take appropriate control action if the change in either absolute angle or a change in angle over time exceeds pre- determined limits. The controllers will react to decrease power flow across the correct tie-line to acceptable phase angle limits until system resources under AGC control can react to the coordinated controllers signal for longer term changes. The project will deliver high-speed topology changes to each system operator to augment the visual reports of the slower SCADA systems. The controllers will have the capability to discern system topology changes in an extremely rapid manner and take appropriate BESS actions to stabilize the system, while alerting system operators of the exact change in system topology and system resource availability. D. 3 WBS and Task Description Summary Performance Periods The project will have nine high level phases: (1) Project Management and Planning, (2) Design Parameters, (3) Project Validation, (4) Project Implementation, (5) Two-Battery Control System, (6) Project Build Out, (7) Bess Commissioning, (8) HDVC Control Design, (9) HVDC Control Installation/Project Closeout. D. 4 Milestone Summary Phase 1: Project Management & Planning (Total Duration = 780 Days) Phase 1 Milestones Description Timing Ownership Task 1.1 Project Management/Plan 3 Weeks EPS Task 1.2 NEPA Compliance 10 Weeks EPS Task 1.3 Cyber Security Plan 12 Weeks EPS Task 1.4 Continuation Briefing 156 Weeks EPS Task 1. 5 Milestone PMP Complete 0 EPS Task 1.6 Go/no-go PMP Approved by TCC/DOE 1 day DOE-TCC Phase 2: Design Parameters (Total Duration = 202 Days) Phase 2 Milestones Description Timing Ownership Task 2.1 Develop Preliminary Network Diagram 1 Week EPS Task 2.2 Develop Controller Design and Transfer Capability Involvement 6 Weeks EPS Task 2.3 Develop Controller Design Criteria for Variable Renewable Generation Regulation Optimization 8 Weeks EPS Task 2.4 De Develop Controller Design Criteria for Transmission/Generation Reserve Optimization 8 Weeks EPS Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 20 Task 2.5 Evaluate DCSS/Soldotna SVC POD Impacts 3 Weeks EPS Task 2.6 Establish Evaluation Cases and Dispatch 4 Weeks EPS Task 2.7 Select Pilot Project Buses and full integration busses for selected regions 6 Weeks EPS Task 2.8 Develop Points list and database (pilot and full integration busses for selected regions) 8 Weeks EPS Task 2.9 Validate latency on existing fiber and digital microwave 16 Weeks EPS Task 2.10 Perform PF,TS,VS w/o Integrated controls 8 Weeks EPS Task 2.11 Perform PF,TS,VS w/ Integrated controls 6 Weeks EPS Task 2.12 Perform EMTP and Eigen value analysis as required 8 Weeks EPS Task 2.13 Determine maximum acceptable communications latency 2 Weeks EPS Task 2.14 Milestone- Complete Parameterization 0 EPS Phase 3: Project Target Validation (Total Duration = 110 Days) Phase 3 Milestones Description Timing Ownership Task 3.1 Establish estimated target transfer capability increase 4 Weeks TCC/EPS Task 3.2 Establish estimated target reserve thermal req. reduction 4 Weeks TCC/EPS Task 3.3 Establish SMART targets Reserves reduction and Increased transfer capability 4 Weeks TCC/EPS Task 3.4 Perform production costs study to evaluate efficiency gains - model BESS coordination in prodsum 18 Weeks TCC/EPS Task 3.5 Milestone- Targets established 0 TCC/EPS Task 3. 6 Go/no go milestone-economic and reliability benefit calculated based on target? 1 Week DOE-TCC Phase 4: Project Implementation Guides (Total Duration = 190 Days) Phase 4 Milestones Description Timing Ownership Task 4.1 Design/Program Control system 16 Weeks EPS Task 4.2 Design Comm. Improvements 10 Weeks EPS Task 4.3 Construct Comm Improvements 24 Weeks EPS Task 4.4 Validate communications latency 4 Weeks EPS Task 4.5 Develop FAT test Plan 6 Weeks EPS Task 4.6 Develop SAT test plan 8 Weeks EPS Task 4.7 Develop operator training plan 4 Weeks EPS Task 4.8 Milestone- implementation guides complete 0 EPS Phase 5: Two Battery Install and Test (Total Duration = 220 Days) Phase 5 Milestones Description Timing Ownership Task 5.1 Develop southern or northern region intelligent controller 4 Weeks EPS Task 5.2 Test BESS control (FAT) 4 Weeks EPS Task 5.3 Develop Central region Intelligent controller 4 Weeks EPS Task 5.4 Test BESS control 4 Weeks EPS Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 21 Task 5.5 Test Integrated Control algorithm 4 Weeks EPS Task 5.6 Test coordinated (2) BESS control 4 Weeks EPS Task 5.7 Big board test (SAT) 6 Weeks EPS Task 5.8 Go/no go milestone successful big board test 2 Weeks EPS Task 5.9 Validate successful achievement of SMART Targets 6 Weeks EPS Task 5.10 Revise pilot- retest as required 6 Weeks EPS Task 5.11 Milestone- Two battery controller complete 0 EPS Task 5.12 Go/no go milestone-First controller in place and functioning 1 DOE-TCC Phase 6: Project Build Out (Total Duration = 280 Days) Phase 6 Milestones Description Timing Ownership Task 6.1 Develop remaining regional intelligent controller 4 Weeks EPS Task 6.2 Design Comm. Improvements 10 Weeks EPS Task 6.3 Construct Comm Improvements 12 Weeks EPS Task 6.4 Complete permanent communication interconnections 6 Weeks EPS Task 6.5 Test BESS control 4 Weeks EPS Task 6.6 Test Integrated Control algorithm 4 Weeks EPS Task 6.7 Test coordinated (2) BESS control - new region/central region 4 Weeks EPS Task 6.8 Big board test (SAT) new region/central region 6 Weeks EPS Task 6.9 Integrate three controllers 6 Weeks EPS Task 6.10 Milestone- Project build-out complete 0 EPS Phase 7: Three Region BESS Commissioning (Total Duration = 130 Days) Phase 7 Milestones Description Timing Ownership Task 7.1 Check out data inputs 4 Weeks EPS Task 7.2 Develop FAT three terminal procedures 4 Weeks EPS Task 7.3 Commission three terminal integrated operation 4 Weeks EPS Task 7.4 Big Board 3-terminal FAT 2 Weeks EPS Task 7.5 Validate successful achievement of SMART Targets 2 Weeks EPS Task 7.6 GO/ No go Milestone -sufficient economic or reliability benefit? 2 Weeks EPS Task 7.7 Operator training 2 Weeks EPS Task 7.8 Big board test - all three regions 4 Weeks EPS Task 7.9 Validate successful achievement of SMART Targets 2 Weeks EPS Task 7.10 Milestone- commissioning complete 0 EPS Task 7.11 Go/no go milestone-Battery control system success 1 DOE-TCC Phase 8: HVDC Control Design (Total Duration = 210 Days) Phase 8 Milestones Description Timing Ownership Task 8.1 Develop BESS-HVDC control algorithm 6 Weeks EPS Task 8.2 Establish estimated target transfer capability increase 6 Weeks EPS Task 8.3 Establish estimated target reserve thermal req. reduction 6 Weeks EPS Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 22 Task 8.4 Establish HVDC SMART targets Reserves reduction and Increased transfer capability 6 Weeks EPS Task 8.5 GO/ No-go Milestone -determine economic and reliability benefit? 6 Weeks EPS Task 8.6 Develop HVDC SAT test plan 4 Weeks EPS Task 8.7 Develop HVDC FAT test Plan 4 Weeks EPS Task 8.8 Develop operator training plan 4 Weeks EPS Task 8.9 Milestone- HVDC Control Design complete 0 EPS Task 8.10 Go no-go Design successful 1 DOE-TCC Phase 9: HVDC Control Installation/Project Closeout (Total Duration = 170 Days) Phase 9 Milestones Description Timing Ownership Task 9.1 Install HVDC Control Hardware and Comm circuits 10 Weeks EPS Task 9.2 Test BESS -HVDC control (FAT) 8 Weeks EPS Task 9.3 Update (3) BESS controllers to (3) BESS + HVDC 8 Weeks EPS Task 9.4 Big Board Test BESS -HVDC control (SAT) 6 Weeks EPS Task 9.5 Validate SMART target achievement 2 Weeks EPS Task 9.6 Project closeout 6 Weeks EPS Task 9.7 Project complete milestone 0 EPS D. 5 Go-No-Go Decision Points Phase Go/No-Go Decision Point Criteria to Evaluate Timing Phase 1 Begin project planning Phase 1 PMP Approved by TCC/DOE 780 days Prior to Phase 2 Phase 2 Complete Parameterization Project Target Validation 202 days Prior to Phase 3 Phase 3 Economic and Reliability Benefit Design of Program and Control System 110 days Prior to Phase 4 Phase 4 Implementation Guides Complete FAT Test Plan/SAT Test Plan 190 days Prior to Phase 5 Phase 5 Successful Big Board Test Big Board Test (SAT) 8 weeks Prior to Task 5.8 Phase 5 Controller Implementation First Controller In Place and Functioning 6 weeks Prior to Phase 6 Phase 6 Product Build Out Check Out Data Inputs from Integrated Three Controllers 280 Days Prior to Phase 7 Phase 7 Economic/Reliability Sufficient Economic and Reliability Benefits Based on SMART Targets 2 weeks Prior to Task 7.7 Phase 7 Battery Control System Success Validate Successful Achievement of SMART Targets Based on BESS-HVDC Algorithm 6 weeks Prior to Phase 8 Phase 8 Economic/Reliability HVDC SMART Targets 6 weeks Prior to Task 8.6 Phase 8 Design Success HVDC Installation of Hardware and Communication Systems 1 day Prior to Phase 9 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 23 D. 6 End of Project Goal The End of Project goal will be successful demonstration of multiple BESS/HVDC controls that optimize reserves and transfer capability in real-time and prove increased situation awareness to system operators of potential challenges related to energy transfer between regions and the regulation of variable generation sources. D. 7 Project Schedule D. 8 Buy America Requirements for Infrastructure Projects This project will not include applicable infrastructure work. D. 9 Project Management Overall Approach The Project will use traditional project management techniques and controls e.g., change management, budget and cost control, scope management etc. as identified in the Project management body of knowledge (PMBOK) to ensure project success. A risk log will be developed and maintained by the project manager. All risks and mitigation strategies will be updated at least at every milestone. The project will be managed by Electric Power Systems under the guidance of the Bradley Lake Project Management Committee’s (BPMC’s) Technical Coordinating Committee (TCC). The TCC is made up of Railbelt utility engineers, system operators and managers12. Acting as the Project steering committee, the TCC will guide EPS’s efforts, provide access to equipment and information to EPS. Access to information and equipment across the regions will be critical to successful and timely completion of the project having the operational decision makers from all regions on the Steering committee will be key to ensuring successful project execution. Further the TCC and DOE will validate and verify the performance of the systems at each milestone and go/no go point. EPS will be under task order contract to Matanuska Electric Association, the designated sub recipient of grant funds. Project Changes Traditional project change control will be used. The Project manager will maintain and up-to- date project change control log with all material changes being formally approved the TCC. Quality Assurance/Control QA/QC will be performed by the project management team. Strict check-out and commissioning procedures will be developed in the Factory Acceptance (FAT)and Site 12 The members of the TCC and EPS terms are listed in the resume section of the application Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 24 Acceptance test (SAT) plans. Adherence to test and commissioning plans will ensure quality system check out. Project Communication The Project initiation documents, and Project Management Plan (PMP) will contain a project communications plan detailing chain of command and appropriate communication meeting cadence and tempo. E. Technical Qualifications and Resources E.1 Quality Assurance/Control As noted above, the Project team (the BPMC and the Technical group designated by the BPMC combined with EPS) combined have two hundred years of Railbelt system operations and engineering experience. The Team is experienced and well versed in executing complex system operations control system projects spanning the length of the Railbelt. The utilities have skilled engineers and designers; and IBEW technical staff are competent in system control and communications construction and commissioning. E.2 Existing Equipment and Facilities The utilities have complex state of the art SCADA/EMS systems with an interregional ICCP link for data transfer. A complex network of ringed SONET compatible digital microwave and fiber assets and hardened stations at each of the BESS sites. The microwave and fiber systems are currently used for SEL high speed mirrored bit communications to enable high speed transfer tripping. Mirrored bits or an equivalent system is a likely candidate for interregional BESS and HVDC communications. As noted above, dedicated, utility owned fiber and digital microwave does not currently exist between the northern and central regions however there may be dark fiber that could be acquired for this purpose. E.3 Relevant Previous Work Efforts, Demonstrated Innovations Numerous complex systems have been studied and successfully put into place in the Railbelt by this team. Installation of SCADA and EMS systems at all five utilities, installation of interregional digital microwave and fiber optic systems, and high-speed communication assisted transfer trip and line current differential protection on all Railbelt transmission lines, eigenvector/value analysis that defined and mitigated, the small signal instability points between the weak summer valley Railbelt grid and the Bradley Lake Hydroelectric project. The study of development and installation of the Railbelt’s multi-stage, multi-delayed under frequency load shed scheme is another example of a complex real-time control system developed and installed by members of the project team. E.4 Time Commitment of Key Members Key members will by assigned to this project as necessary to ensure successful completion. E.5 DOE Technical Services: None March 10, 2023 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 2: Smart Grid Grants; Concept Paper – Battery Energy Storage / HVDC Coordinated Control To the U. S. Department of Energy, Golden Valley Electric Association, Inc. (GVEA) is pleased to team with the State of Alaska, d/b/a the Alaska Energy Authority, and the other Railbelt electric utilities 1 to partner in the funding opportunity for Battery Energy Storage / HVDC Coordinated Control (DE-FOA-0002740). GVEA is a not-for-profit, member owned, electric cooperative that serves nearly 100,000 residents in Interior Alaska. We operate and maintain nearly 3,300 miles of power lines, 35 substations and nine generating facilities. GVEA’s electric system is interconnected with, and has the ability to serve, four critical military installations - Fort Wainwright, Eielson AFB, Fort Greely, and Clear AFS. GVEA is also interconnected to the other Railbelt electric utilities via a single transmission line, the majority of which is the Alaska Intertie – a 170 mile long, 345 kilovolt (kV) transmission line between Willow and Healy that operates at 138 kV. Together GVEA and the other Railbelt electric utilities comprise what is commonly referred to as the Alaska Railbelt Electric System and provide electric service to approximately 75% of Alaska’s population. GVEA is supportive of the Battery Energy Storage/HVDC Coordinated Control proposal and hopes that the proposal receives DOE approval. As a not-for-profit, member owned cooperative, GVEA has a fiduciary responsibility to our member-consumers, to ensure that GVEA’s resources are used wisely and prudently. As essential as the Energy Storage/HVDC proposal is to achieve meaningful, transformative, long-term benefits on the Railbelt Electric System, the cost of achieving those benefits cannot, from a practical perspective, be borne solely by Railbelt Ratepayers. Financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) is critically necessary. For 1 Chugach Electric Association, Inc., Homer Electric Association, Inc., Matanuska Electric Association, Inc., and the City of Seward d/b/a Seward Electric System. DOE Letter of Commitment (GVEA) – FOA-0002740 Page 2 of 2 that reason, GVEA supports the cost allocation methodology outlined in this and other applications being submitted by this project team to the DOE’s Grid Resilience and Innovation Partnerships (GRIP) Program that prioritizes securing Federal IIJA/IRA funds with State of Alaska matching funds for the “non-federal cost share requirement.” If necessary, additional funding will also come from GVEA and the other Railbelt electric utilities, subject to successful negotiation of the grant contract and receipt of Board of Directors, regulatory, and/or third-party approvals required to ensure that costs incurred by the utilities can appropriately be recovered from the Railbelt’s member-consumers. GVEA has been diligently working with the other Railbelt electric utilities and with the Alaska Energy Authority to ensure that the opportunities afforded by the DOE IIJA and IRA funding grants, once received, will meaningfully and positively transform the Alaska Railbelt electric system. GVEA fully supports the Battery Energy Storage/HVDC Coordinated Control proposal, as well as other aspects of the broader Grid Modernization and Resiliency Plan that will be submitted to the DOE under separate applications. As the application reflects, there exists unprecedented alignment amongst the Railbelt utilities and the Alaska Energy Authority to materially transform the Railbelt electric system. We are committed to work collaboratively in order to strengthen and build a smart, clean electrical grid that ensures residents, communities, and the military bases served by the Railbelt electric utilities have access to clean, reliable, low-cost energy. Sincerely, John J. Burns President & Chief Executive Officer Corporate Office Central Peninsula Service Center 3977 Lake Street 280 Airport Way Homer, Alaska 99603-7680 Kenai, Alaska 99611-5280 Phone (907) 235-8551 Phone (907) 283-5831 FAX (907) 235-3313 FAX (907) 283-7122 March 13, 2023 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 2: Smart Grid Grants; Concept Paper – Battery Energy Storage / HVDC Coordinated Control Dear Grid Deployment Office: Homer Electric Association, Inc. (HEA) is pleased to submit this letter expressing its support for the funding proposal for the Battery Energy Storage / HVDC Coordinated Control (DE-FOA- 0002740). HEA is a not-for-profit, member owned, electric cooperative that serves the residents, businesses, and industrial facilities of the entire western Kenai Peninsula in the state of Alaska. HEA’s electric system is interconnected with the other Alaska Railbelt electric utilities via a single transmission line between the HEA and Chugach Electric systems. Together HEA and the other Railbelt electric utilities comprise what is commonly referred to as the Alaska Railbelt Electric System and provide electric service to approximately 75% of Alaska’s population. HEA supports the Battery Energy Storage/HVDC Coordinated Control proposal and hopes that the proposal receives DOE approval. As a not-for-profit, member owned cooperative, HEA has a fiduciary responsibility to its member-consumers, to ensure that HEA’s resources are used wisely and prudently. As essential as the Energy Storage/HVDC proposal is to achieve meaningful, transformative, long-term benefits on the Railbelt Electric System, the cost to HEA’s members of secure those benefits must be understood before HEA can make a financial commitment to participate in funding the project. For that reason, HEA expects financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) to be critically necessary. Accordingly, HEA commits to work with the other utilities and the State of Alaska to develop a firm cost allocation methodology for funding the “non-federal cost share requirement” of the initiatives as described in the applications being submitted by the Railbelt Utilities’ project team to the DOE’s Grid Resilience and Innovation Partnerships (GRIP) Program. HEA’s funding obligation in this regard will be subject to HEA’s final approval of the terms of the grant agreement and any necessary or appropriate Board of Directors, regulatory, and/or third-party approvals. HEA fully supports the Battery Energy Storage/HVDC Coordinated Control proposal, as well as other aspects of the broader Grid Modernization and Resiliency Plan that will be submitted to the DOE under separate applications. As the application reflects, there exists unprecedented alignment U.S. Department of Energy Grid Deployment Office March 13, 2023 Page 2 among the Railbelt utilities and the Alaska Energy Authority to create a resilient, reliable Railbelt electric system that would be on a par with the systems currently enjoyed by the rest of the country. HEA is committed to work collaboratively in order to achieve that end. Sincerely, Bradley P. Janorschke General Manager MATANUSKA ELECTRIC ASSOCIATION, INC. • P.O. Box 2929 • Palmer, Alaska 99645 • t 907.745.3231 • f 907.761.9368 • www.mea.coop March 10, 2023 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 2: Smart Grid Grants; Concept Paper – Battery Energy Storage / HVDC Coordinated Control Dear Application Review Committee: Matanuska Electric Association, Inc. (MEA) is pleased to team with the State of Alaska, d/b/a the Alaska Energy Authority, and the other Railbelt electric utilities1 to partner in the funding opportunity for Battery Energy Storage / HVDC Coordinated Control (DE-FOA-0002740). MEA is a not-for-profit, member owned, electric cooperative that serves almost 65,000 meters in the fastest-growing area of Alaska. We operate and maintain nearly 4,700 miles of power lines, 26 substations and self-generate the majority of our power. MEA is interconnected to the other Railbelt electric utilities via a single transmission line, the majority of which is the Alaska Intertie – a 170 mile long, 345 kilovolt (kV) transmission line between Willow and Healy that operates at 138 kV. Together, MEA and the other Railbelt electric utilities comprise what is commonly referred to as the Alaska Railbelt Electric System and provide electric service to approximately 75% of Alaska’s population. MEA is supportive of the Battery Energy Storage/HVDC Coordinated Control proposal and hopes that the proposal receives DOE approval. As a not-for-profit, member-owned cooperative, MEA has a fiduciary responsibility to our member-consumers, to ensure that MEA’s resources are used wisely and prudently. As essential as the Energy Storage/HVDC proposal is to achieve meaningful, transformative, long-term benefits on the Railbelt Electric System, the cost of achieving those benefits cannot, from a practical perspective, be borne solely by Railbelt Ratepayers. Financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) is critically necessary. For that reason, MEA supports the cost allocation methodology outlined in this and other applications being submitted by this project team to the DOE’s Grid Resilience and Innovation Partnerships (GRIP) Program that prioritizes securing Federal IIJA/IRA funds with State of Alaska matching funds for the “non-federal cost share requirement.” If necessary, additional funding will also come from MEA and the other Railbelt electric utilities, subject to successful negotiation of the grant contract and receipt of any necessary Board of Directors, regulatory, and/or third-party approvals required to ensure that costs incurred by the utilities can appropriately be recovered from the Railbelt’s member-consumers. MEA has been diligently working with the other Railbelt electric utilities and with the Alaska Energy Authority to ensure that the opportunities afforded by the DOE IIJA and IRA funding grants, once received, will meaningfully and positively transform the Alaska Railbelt electric system. 1 Chugach Electric Association, Inc., Homer Electric Association, Inc., Golden Valley Electric Association, Inc., and the City of Seward d/b/a Seward Electric System. US Department of Energy, Grid Deployment Office Letter of Commitment, MEA – FOA-0002740 March 10, 2023 Page 2 MEA fully supports the Battery Energy Storage/HVDC Coordinated Control proposal, as well as other aspects of the broader Grid Modernization and Resiliency Plan that will be submitted to the DOE under separate applications. As the application reflects, there exists unprecedented alignment amongst the Railbelt utilities and the Alaska Energy Authority to materially transform the Railbelt electric system. We are committed to work collaboratively in order to strengthen and build a smart, clean electrical grid that ensures residents, communities, and the military bases served by the Railbelt electric utilities have access to clean, reliable, low-cost energy. Sincerely, Anthony M. Izzo Chief Executive Officer Community Benefits Plan: Job Quality and Equity The Bradley Lake Hydroelectric Project, completed in 1991, brought together the State of Alaska (dba Alaska Energy Authority) and the Railbelt’s five utility providers. Those Railbelt utilities are: 1) Chugach Electric Association, 2) Golden Valley Electric Association, 3) Homer Electric Association, 4) Matanuska Electric Association, and 5) Seward Electric System. The first four are member-owned cooperatives while Seward Electric System is owned and operated by City of Seward. Together they provide 79% of Alaska’s electrical energy.1 These utilities have developed an efficient partnership with each other as well as with the Alaska Energy Authority through management, operation, and maintenance of the Bradley Lake Project. Acting jointly as the Bradley Lake Project Management Committee (BPMC) they have assembled a Grid Modernization and Resiliency Plan (GMRP), which seeks to modernize Railbelt grid infrastructure to improve reliability, resiliency, carbon impact, and energy burden for over three quarters of the state’s population. Included in GMRP is the Battery Energy Storage Systems/High Voltage Direct Current Coordinated Control Project (BESS). BESS includes new battery control systems, software, and transmission cables to stabilize and improve efficiency of power transfers between Railbelt regions. This will reduce the risk of blackouts for individual regions, increase economic dispatch, and incentivize development of clean energy solutions by increasing the customer base from individual regions to the entire Railbelt grid. 1. Community and Labor Engagement The improvements proposed by BESS will have minimal visual/physical impact on stakeholders, have minimal anticipated negative environmental consequences, take place largely on utility owned property, have already been publicly vetted by 3 of the 5 participating utility cooperatives via inclusion in their Capital Improvement Plans (Homer, Chugach, and Golden Valley), and have no anticipated negative impacts on vulnerable populations. Therefore, to ensure that this “Community and Labor Engagement” section is both useful and practical, BPMC is taking this opportunity to initiate public participation planning not only for BESS but for the larger GMRP, of which BESS is one part. Public Participation Plan BPMC recognizes that broad support for GMRP is necessary for successful project implementation. An effective public participation process draws out diverse perspectives from a broad cross-section of stakeholders, and BPMC looks forward to incorporating this public knowledge into GMRP, including BESS. The five Railbelt utility providers will form “hubs” for 1Alaska’s Energy Infrastructure | REAP (https://alaskarenewableenergy.org/ppf/alaskas-energy-infrastructure) 2 this process, since their properties will host the majority of physical improvements in GMRP and they already possess communication channels with many of the relevant stakeholders. Phase 1: Draft GMRP public participation plan (Present-December 2023). BPMC intends to have the following deliverables complete by Fall 2023: • Define purpose and goals of GMRP public participation plan. • Select BPMC core team for implementing GMRP public participation plan. • Select consulting firm to assist BPMC with GMRP public participation plan. • Identify various stakeholder groups affected by GMRP. • Draft stakeholder engagement strategies and outreach media. Special attention will be paid to soliciting participation from disadvantaged communities affected by the project. ○ Outreach media to include: public notices, social media posts, newspaper advertisements, radio advertisements, email, mailers, and e-newsletters. • Draft sample graphics and key messages. • Draft SMART (specific, measurable, achievable, relevant, and time-bound) DEIA (diversity, equity, inclusion, and accessibility) goals, including support for creation of minority business enterprises in disadvantaged communities; and SMART commitments to workers, stakeholders, and those vulnerable to project activities. • Finalize public participation plan schedule. • Launch GMRP website with public meeting schedule, GMRP description, and public comment section. This website will remain live until at least January 2028. Phase 2: Implement GMRP public participation plan (January 2024-November 2024). The Phase 2 timeline will be constructed to allow for sufficient public participation in individual projects represented in GMRP (such as BESS) that are ready for construction spring 2024. This means that certain local meeting series may be accelerated as needed. The BPMC core team will work closely with each utility provider to determine the appropriate time and setting for each community visit, taking care to avoid conflicts with other events. When possible, they will use existing community events and meetings to gather input on the plan. The core team will devote special attention to ensuring diverse demographic participation at all meetings. Task 1: Introductory Work Sessions (February 2024). Each of the five utility providers in BPMC will host an introductory public work session. These work sessions will be advertised at least two weeks in advance via social media, public postings, utility cooperative mailers, and the GMRP website. Topics will include: 3 • Review the GMRP. Communicate what it encompasses, what it costs, its projected timeline, and its potential positive and negative effects. ○ Provide extra detail about projects in GMRP that are shovel ready such as BESS. – BESS includes a new underwater high voltage direct current transmission line from the southern Railbelt region to the central Railbelt region. This project component may require additional public meetings. • Communicate how the public can learn more, track project progress, and how their feedback will be used. • Share success stories as well as lessons learned from other electrical infrastructure upgrades conducted on the Railbelt. • Discuss structure of BPMC and roles and responsibilities of the six parties that constitute it. • Discuss measures of success for GMRP. • Share proposed list of relevant community organizations with which to conduct one-on-one outreach meetings, with an emphasis on organizations that serve disadvantaged populations. • Present and solicit feedback on SMART DEIA goals, including support for creation of minority business enterprises in disadvantaged communities; and SMART commitments to workers, stakeholders, and those vulnerable to project activities. • Identify areas where stakeholders wish they had more data or information via questions such as: ○ What should the BPMC consider that we haven't covered today? ○ What information would you like to see at a future meeting? ○ What additional questions do you have? Task 2: Data Collection and Materials Refinement (March-May 2024) A series of core team meetings will be held to refine the GMRP public participation plan in light of feedback gathered during initial work sessions. At this point, a timeline as well as core team leads will be established for the following deliverables: • Using feedback from initial work sessions, conduct data collection/research as needed (including surveys) to address data gaps identified by the public and/or BPMC core team. ○ A simple survey can be an effective way to collect feedback on key issues, priorities, and projects. The survey could be distributed electronically or made available at key community locations. BPMC would not expect to get a statistically valid sample of the entire Railbelt population, but enough feedback to assess community perspectives from a cross-section of residents. 4 • Develop ArcGIS Online mapping tool for GMRP website. ○ By hosting an interactive map of the project, BPMC can solicit public comments that are geocoded by location, allowing identification of site-specific issues, needs, and themes. • Minutes from intro work sessions as well as public comments from GMRP website coalesced to capture key themes and messages and posted to website. • Refine communication materials based on public feedback. • Finalize list of organizations with which to conduct one-on-one work sessions, including organizations serving disadvantaged populations and relevant labor unions (IBEW Local 1547 and IUOE Local 302, among potential others); SMART DEIA goals; and SMART commitments. As part of this task, the core team will continue to use various stakeholder engagement tools to share project information, promote opportunities to get involved, and invite public input. Task 3: One-on-One Organizational Work Sessions (April-June 2024) A series of work sessions with focus-area-specific representatives will be conducted. Early engagement with these groups will provide important input to guide GMRP revisions. It will also establish constructive relationships and shared interest in creating a successful plan, as many of these groups will be critical partners throughout GMRP implementation. Possible topics include: environmental impacts, subsistence impacts, state and federal land management, Power Cost Equalization, workforce development and training including apprenticeships, ways to support minority business enterprises through the project, DEIA recruitment, DEIA workplace policies, and state legislation. Members of the BPMC core team will meet (virtually or physically) with the finalized list of relevant organizations. These meetings will follow the same template as the intro public work sessions (Task 1), communicating an overview of the GMRP and inviting these organizations to provide feedback on their specific focus areas. Minutes will be recorded. Examples of relevant organizations and Minority Serving Institutions with whom meetings will be sought include: Alaska Federation of Natives*, Alaska Village Electric Cooperative*, University of Alaska, Alaska Pacific University, Alaska Black Caucus, Alaska Municipal League*, IBEW Local 1547*, IUOE Local 302*, Alaska Chapter of the National Electrical Contractors Association, Alaska Operating Engineers Training Trust*, Alaska Joint Electrical Apprenticeship & Training Trust*, and Railbelt Tribal councils.2 Task 4: Public Feedback Sharing (June 2024) 2 Asterisked organizations are those with whom preliminary contact about both BESS and GMRP have already been made. 5 A second round of public meetings will be hosted by each of the five utility providers. Topics will include: • Brief recap of project purpose, goals, and timeline. • Themes and key takeaways from intro work sessions, one-on-one org meetings (those organizations will be encouraged to participate in this round of public meetings to ensure their positions are accurately represented), public comments, and survey results. • Share SMART DEIA goal revisions, and SMART commitments revisions. • Have stations set up around different topics - people can walk from station to station, learn about different elements of the project (timeline, DEIA goals, labor commitments, environmental impacts, employment opportunities, homeowner impacts, etc.), and ask questions of project staff. • Request for additional feedback or alternative viewpoints not captured thus far. • Demonstration/launch of ArcGIS mapping tool on GMRP website. • Minutes from this meeting will be posted to GMRP website. Task 5: Internal GMRP and SMART Commitments Finalization (July-August 2024) The BPMC core team will meet to discuss the Public Feedback Sharing and assign task leads to the following deliverables: • Create GMRP final draft with incorporated stakeholder feedback to present to utility boards. • Create final draft SMART DEIA goals and SMART commitments to present to utility boards. Task 6: Board Presentations (September 2024) Final draft GMRP, SMART DEIA goals, and SMART commitments will be presented to each utility board by BPMC core team. Requested changes will be catalogued in detail. Task 7: Incorporation of Board Edits (October 2024) BPMC core team meetings conducted to incorporate requested changes from utility boards. If funded through this application, these changes will be considered only when doing so allows GMRP to remain in compliance with Department of Energy Grid Deployment Office DE-FOA- 0002740 job equality and equity, community and labor engagement, quality jobs, and DEIA requirements. Task 8: Revised Board Presentations (November 2024) Revised final draft GMRP, SMART DEIA goals, and SMART commitments presented to each utility board by BPMC core team. This presentation will focus on the requested changes by the boards from the previous meeting, whether those changes were implemented, and if not, why not. Each board will asked to ratify these documents. If they do not approve the revised final drafts, a second round of edits and board presentations will be scheduled. 6 Task 9: Finalized GMRP Overview (November 2024) The board-ratified GMRP, SMART DEIA goals, and SMART commitments will be posted to GMRP website. Outreach media—including emails to those who attended the previous two public meetings—will direct the public to these finalized documents. 2. Quality Jobs Alaska’s Economy Relies on the Railbelt Both BESS and GMRP will provide significant secondary benefits to nearly all sectors of Alaska’s economy. In addition to serving as home to three quarters of Alaska’s population, the Railbelt, and particularly Anchorage, is the economic heart of Alaska, shunting labor, supplies, and goods to and from all corners of the state. While a quantitative analysis of the impact of the Railbelt on Alaska’s broader state economy lies outside the scope of this Community Benefits Plan, the magnitude of its import can be quickly illustrated through an overview of the Port of Alaska, a potential beneficiary of this project as a customer of Chugach Electric Association. The Port of Alaska, located in Anchorage, is a federally designated Strategic Seaport, and serves 90% of Alaska’s population. It receives 50% of all freight shipped into Alaska by all modes (marine, truck, and air), and supports $14 billion of commercial activity in Alaska.3 Seventy-four percent of all waterborne freight and ninety-five percent of refined petroleum products entering the state are shipped through the Port of Alaska. This includes 100 percent of the jet fuel supplied to Joint Base Elmendorf-Richardson and 66 percent of the jet fuel for Ted Stevens Anchorage International Airport4, which is the fourth busiest cargo airport in the world.5 Despite its importance to the statewide economy, the Port of Alaska, like the rest of the Railbelt, is served by inadequate electrical infrastructure. Tony Izzo, general manager of Matanuska Electrical Authority, said: “We have one of the most fragile systems in the United States. I don’t refer to the Alaska Railbelt as first-world, because it’s not.”6 Unlike the contiguous lower forty-eight states, Alaska has received minimal federal investment in grid development. The Eklutna Hydroelectric Project, constructed in the 1950s, was the last major federal project in the Railbelt that included a transmission line component. According to the North American Electric Reliability Corporation, the leading cause of electric transmission outages in Alaska is “Transmission Line Faults and Overloads”. On average, the number of people affected annually by electric outages in Alaska is 39,282, and the average 3 Port of Alaska in Anchorage, The Logistical and Economic Advantages of Alaska's Primary Inbound Port, McDowell Group, October 2020. 4 Ten Year Tonnage Summary | Port of Alaska in Anchorage 5 Ted Stevens Anchorage International Airport (alaska.gov) 6 Anchorage Daily News, 03/12/23, "Railbelt utilities again scramble to fill expected Cook Inlet gas shortages" 7 duration of these outages is 31 hours a year.7 While no available data on the economic impact of these outages exists for the Railbelt’s 36,000 commercial accounts8, Alaska was rated the 49th worst state to start a business by a 2022 report whose weighted criteria included “Infrastructure” (50th) and “Cost of Doing Business” (46th).9 Reducing the cost of energy and increasing energy reliability via BESS will be a step toward national parity for Alaskans and a boon for Alaska’s struggling economy. Employment at Chugach Electric Association, Golden Valley Electric Association, Homer Electric Association, Matanuska Electric Association, and Seward Electric System More granularly, investment in BESS and GMRP will create and retain high-quality jobs with employer sponsored benefits at all five Railbelt utility providers. 659 of the 1,071 total employees who work at these utilities belong to labor unions; each utility allows their employees to organize, bargain collectively, and participate in labor organizations of their choosing.10 These are highly skilled and highly paid positions: the average wage of a journeyman lineman at these utilities ranges from $54.40 to $58.00 an hour.11 The following employer sponsored benefits are provided, varying by employee group: medical, dental, vision, life insurance, defined contribution retirement plans, 401(k), pension, short-term disability, long/short-term disability, tuition reimbursement, paid time off, and paid holidays.12 BESS will retain jobs by replacing outdated infrastructure that is at the end of its usable lifespan. Improving transmission efficiency will also allow utilities to spread their costs over a larger customer base. This places less pressure on reducing staff, because asset costs are fixed, and boards are typically reluctant to raise rates, which means that when employees retire their positions are often not replaced since payroll is one of the few variables utilities can use to balance expenses. BESS will also create new jobs by installing new systems that will require operations and maintenance for the next 25 years. Job positions related to and affected by BESS are: safety personnel; field operations management; field operations: linemen, wiremen, relay technicians; substation technicians; powerplant operations management; powerplant operations: heavy mechanics, instrument control technicians; power system technicians, system operations engineers; environmental engineers and environmental technicians; 7 AK-Energy Sector Risk Profile.pdf (energy.gov) 8 Summed from: Homer Electric Association, Golden Valley Electric Association, Chugach Electric Association Inc., Matanuska Electric Association, Inc. 9 America's Top States for Business 2022: The full rankings (cnbc.com) 10 Email correspondence with Reagan M. Russel (see footnote 12); Justin Patterson (see footnote 13); phone correspondence with Charlene Flyum, (907)235-3369, Human Resources, Homer Electric Association, Friday, March 10, 2023 9:26 AM; Candice Strandberg, Human Resources, Chugach Electric Association, (907)762-4788, Friday, March 10, 2023, 9:16 AM; and Rob Montgomery, General Manager, Seward Electric System, (907)224-4073, Wednesday, March 8, 2023, 3:10 PM. 11 See footnote 10. 12 See footnote 10. 8 administrative and procurement; information technology; operations technology; telecommunications engineering; and telecommunications technicians. The 659 unionized workers these utilities employ suggests they possess access to sufficient supplies of skilled labor, while their longstanding track records of providing power to Alaska residents in a remote and difficult environment demonstrates that they are responsible employers. For perspective, each of these utilities is significantly older than the State of Alaska itself (which became a state in 1959). Their years of founding are as follows: Chugach Electric Association: 1948, Golden Valley Electric Association: 1947, Homer Electric Association: 1945, Matanuska Electric Association: 1941, and Seward Electric System: 1921.13 HR directors at these utilities confirmed that their organizations possess plans to minimize the risk of labor disputes via contracts that have “appropriate grievance resolution stipulations”14 and the filled position of “dedicated Labor Relations Program Manager”15 Meanwhile, Melinda Taylor, Director of Communications at IBEW 1547 wrote, “we would generally consider our relationship with each utility to be positive. We work well with each of these utilities and understand that the success of our membership is tied to the success of each utility. Because of the fact that we have separate collective bargaining agreements with each utility (some of these utilities have multiple CBAs), the applicable work rules and expectations are much clearer than if there were no CBA in place. For these reasons, we believe that the IBEW is well- positioned to maintain strong labor relations with our partner utilities throughout any Railbelt grid modernization and revitalization projects.”16 As noted in Section 1: “Community and Labor Engagement”, during the GMRP public participation plan implementation one-on-one work sessions will be conducted with labor unions and other relevant organizations, and SMART commitments to workers will be ratified by each utility board as part of the adoption of a revised GMRP. Task 1: To engage with organized labor to accomplish the projects making up the GMRP. 3. Diversity, Equity, Inclusion, and Accessibility (DEIA) It is a fundamental policy of all five Railbelt utilities and Alaska Energy Authority to assure equal opportunity in employment to all individuals regardless of race, color, gender, religion, national 13 Homer Electric Association, Golden Valley Electric Association, Chugach Electric Association Inc., Matanuska Electric Association, Inc., and phone call with Rob Montgomery, General Manager, Seward Electric System, (907)224-4073, Wednesday, March 8, 2023, 3:10 PM 14 Email correspondence between Reagan M. Russell, RMRussel@gvea.com, Human Resources at Golden Valley Electric Association, and Clare Boersma, clareboersma@northerncompassgroup.com, Monday, March 6, 2023, 10:39 AM. 15 Email correspondence between Justin Patterson, justin.patterson@mea.coop, Human Resources at Matanuska Electric Association, and Clare Boersma, clareboersma@northerncompassgroup.com, Monday, March 9, 2023, 3:27 PM. 16 Email correspondence between Melinda Taylor, mtaylor@ibew1547.org, Communications Director IBEW 1547, and Clare Boersma, clareboersma@northerncompassgroup.com, Tuesday, March 7, 2023, 6:00 PM. 9 origin, age, genetic information, veteran status, or disability. Each utility provides reasonable accommodations to applicants and employees who need them because of a disability or to practice or observe their religion absent undue hardships. All hiring practices and standard operating procedures comply with all Local, State, and Federal laws. GMRP will measure DEIA goals. These goals will be SMART, shared publicly during the GMRP public participation plan, and ratified by each utility board as part of the adoption of a revised GMRP. These goals will include support for minority business enterprises in disadvantaged communities and will be informed by BPMC core team meetings with organizations that represent disadvantaged communities. Potential goals include equal opportunity employment programs, affirmative action programs, scholarships, anti-bias trainings for hirers, and inter- organizational data collection re: percentage female and minority participation in each trade. Final goals will depend largely on needs expressed by organizations representing DACs during one-on-one meetings. Chugach Electric Association, Matanuska Electric Association, Homer Electric Association and Golden Valley Electric Association are federal contractors. The lone utility which is not—Seward Electric System—only has 10 employees. As federal contractors these four utilities are subject to the Office of Federal Contract Compliance Programs’ requirements for hiring practices, and adherence to an Affirmative Action Plan.17 As part of the GMRP public participation plan, meetings will be held between the BPMC core team and the Alaska Operating Engineers/Employers Training Trust, and Alaska Joint Electrical Apprenticeship & Training Trust. A focus of these meetings will be to assess how the apprenticeship programs these organizations offer serve workers facing systematic barriers to employment, and whether those programs can be improved to reduce those barriers further through GMRP project implementation. Cumulative annual benefits from the project in the form of reduced energy burdens of $18,215,330 will flow to DACs or Tribal lands. For more detail on these benefits, see Section 4: “Project Benefits for Disadvantaged Communities”. 4. Justice40 Initiative “America’s First Climate Refugees” Nowhere is climate change more visible--or occurring faster--than in the far north. Driven by a shift in popular sentiment about the environment, decarbonization policies and technological advancements are reshaping Alaska’s energy landscape. Uncertainty around Cook Inlet natural gas, which provides 73% of the power generated across the Railbelt, is a major challenge looming on the near-term horizon.18 The Alaska Department of Natural Resources forecasts 17 See footnote 10. 18 Alaska’s Energy Infrastructure | REAP (https://alaskarenewableenergy.org/ppf/alaskas-energy-infrastructure) 10 there will be supply shortfalls of Cook Inlet gas starting around 2027, and no alternative supply exists in-state.19 Rob Montgomery, General Manager of Seward Electrical System, writes: “the Railbelt’s electric utilities all agree that a large-scale hydro-electric project or projects would best serve the state’s power needs while also putting downward pressure on rates once the plant is in service.”20 This economic reality exists alongside complex moral and social issues: a thawing arctic disproportionately affects disadvantaged and predominantly Alaska Native communities. For instance, Newtok Village, located on the Ninglick River, and the Native Village of Napakiak, located on the Kuskokwim river, are both currently being relocated to higher ground with over $60 million of Federal aid; they are considered “America’s first climate change refugees.”21 Alaska Governor Michael J. Dunleavy recently introduced legislation that would require 80% of the Railbelt’s electricity to come from renewable sources by 2040, with penalties for electric companies that fail to meet the requirement.22 Rob Montgomery writes: “the biggest obstacle Railbelt utilities face in putting more renewable or carbon-free energy on the grid is the limited capacity of existing transmission infrastructure. The Railbelt’s transmission system simply is not robust enough to move electricity in large capacities that would ultimately drive down costs. A good example of this is the Bradley Lake Hydro Project, which today can only provide 20 percent of its capacity to customers in a given moment because of transmission limitations.” BESS would increase the transfer capacity between the three Railbelt regions, paving the way for development of increased hydro-electric power generation and other clean energy solutions. In doing so, it would mitigate negative environmental impacts to communities such as Newtok and Napakiak from the 3,218 natural-gas-produced GWh on the Railbelt each year, resulting in an annual 1.61 billion kilograms of carbon dioxide equivalent.23 Additionally, BESS is projected to result in a 10-15% reduction in thermal spending due to decreased line losses, representing a non-cumulative decrease of over 200 million kilograms carbon dioxide equivalent per year.24 BESS is not anticipated to cause any negative environmental impacts for disadvantaged or non- disadvantaged communities. Project Benefits for Disadvantaged Communities This project is anticipated to provide significant benefits to Alaska’s DACs both on and off the Railbelt. There are 22 census tracts that qualify as disadvantaged25 (median DAC score=18) on 19 State of Alaska, Department of Natural Resources, Division of Oil and Gas 2022-cook-inlet-gas-forecast-report.pdf 20 Rob Montgomery, April 26, 2022: Railbelt utilities united on a more diversified energy mix | Editorials | sewardjournal.com 21 See: Alaska on the edge: Newtok's residents race to stop village falling into sea | The Guardian; Impossible Choice Faces America's First 'Climate Refugees' : NPR; Alaska’s Climate Refugees - The Atlantic 22 Alaska State Legislature, House Bill 301 23 Life Cycle Greenhouse Gas Emissions of Electricity Generated from Conventionally Produced Natural Gas - O'Donoughue - 2014 - Journal of Industrial Ecology - Wiley Online Library 24 Life Cycle Greenhouse Gas Emissions of Electricity Generated from Conventionally Produced Natural Gas - O'Donoughue - 2014 - Journal of Industrial Ecology - Wiley Online Library 25 DOE Disadvantaged Communities Reporter 11 the Railbelt, with a combined population of 81,921.26 There are a further 17 Alaska Native Village Statistical Areas (ANVSA) on the Railbelt27, with a combined population of 160,486.28 These communities will receive direct benefits from BESS via reduction of their energy burdens. BESS will decrease line losses, resulting in reduced thermal spending of 10-15%, and increase economic dispatch by increasing transmission capacity.29 Four of the five Railbelt utilities are member-owned, while the fifth is City-owned, so these expense reductions should transfer to reduced consumer costs. The Railbelt’s 260,00030 residential utility accounts serve 623,916 individuals31, 242,407 of whom live in a DAC or on Tribal Land. BPMC project engineers project savings of .5 cents/kWh to 1.5 cents/kWh.32 The Railbelt sold 4,408 GWh (Gigawatt-Hours) in 202033, suggesting total savings of $44,080,000 at a 1 cent cost reduction per kWh. Again, much of these $44 million in annual savings should pass through to member-owners; as a percentage of total population served, 39% of savings will flow to those who either live in a DAC or on Tribal Land. BESS will also result in a reduction of energy burden for DACs off the Railbelt through Alaska’s Power Cost Equalization program. In rural areas of Alaska, electricity rates can be two to five times higher than in more urban areas due to the limited resource options (usually diesel) and high transportation costs. In order to provide economic assistance to residents and community facilities in rural Alaska, the PCE program was established in 1985 as part of a statewide energy plan. PCE was devised at the same time that state funds were used to construct major energy projects such as the Four Dam Pool, Bradley Lake, and the Alaska Intertie, which helped provide energy for urban Alaska communities. The primary beneficiaries of PCE are residential customers, who are eligible for subsidy of actual consumption up to the first 500 kWh per month. If a household uses more than 500 kWh of electricity in a given month, the amount used above 500 kWh is not subsidized. Community facilities are also eligible for actual consumption of up to 70 kWh per month per community resident. Community facilities must be nonprofit organizations that do not receive the majority of their funding from state and federal sources. For-profit businesses do not receive PCE. A unique feature of BESS is that it will have significant economic impacts outside of the Railbelt due to PCE. All 86 rural utilities that participate in PCE are required to submit annual reports to the Alaska Energy Authority (AEA) of total kWh sold and produced, amount of diesel purchased 26 American Community Survey 2021 5 Year Population Estimates 27 2020 U.S. Census, DOE Disadvantaged Communities Reporter 28 American Community Survey 2021 5 Year Population Estimates 29 Brian Hickey, Project Lead, P.E., PMP., Brian.Hickey@mea.coop, conversation with Curtis Fincher via Zoom, 8:00-8:30 am, March 1st, 2023. 30 Summed from: Homer Electric Association, Golden Valley Electric Association, Chugach Electric Association Inc., Matanuska Electric Association, Inc. 31 Alaska Department of Labor and Workforce Development, Research and Analysis Section. 32 Brian Hickey, Project Lead, P.E., PMP., Brian.Hickey@mea.coop, conversation with Curtis Fincher via Zoom, 8:00-8:30 am, March 1st, 2023. 33 U.S. Energy Information Administration, 2020 12 and at what price, total cost to provide electricity, and after-PCE cost to ratepayers. AEA administers the PCE program by making payments directly to individual utilities based on a formula. The PCE program is funded by earnings of the PCE Endowment Fund. Alaska Statute 42.45.085 provides that five percent of the PCE Endowment Fund’s three-year monthly average market value may be appropriated to the PCE Program. In recent years the five percent draw on the endowment has been sufficient to fully fund PCE payments. PCE is determined for a utility as 95 percent of eligible power costs above the “Average Class Rate” (which is the urban average electricity costs of Anchorage, Juneau, and Fairbanks; it was 20.03 cents per kWh for FY 2022) and below $1.00 per kWh. Eligible costs are fuel expenses (including transportation), and non-fuel expenses such as: salaries, insurance, taxes, parts, supplies, and interest. In addition, a utility must meet required efficiency and line loss standards, or the PCE payment is reduced to reflect those standards. By decreasing or keeping lower for longer electricity rates in Anchorage and Fairbanks, BESS may decrease the Average Class Rate AEA uses to calculate PCE for rural utilities. This will, in turn, increase the PCE subsidy for eligible communities and residents. In FY22 PCE served 188 communities, 15434 of whom qualify as DACs or Tribal lands. Approximately 108,914,53035 of PCE-eligible kWh were produced between residential and community facilities for those 154 DACs. At a one cent decrease in the average class rate, 2022 PCE payments to DACs would increase by $1,089,145. (That said, actual savings would be slightly less than this, since Juneau, which is outside the Railbelt, is included in the “Average Class Rate”, and their rates would not be affected by BESS.) In sum: BESS will cause 38.9% of a projected $44,080,000 in reduced energy burdens to flow to on-Railbelt DACs or Tribal lands; and 81.9% of additional PCE subsidies ($1,329,60636) to flow to off-Railbelt DACs or Tribal lands. Together, this represents cumulative benefits to DACs or Tribal lands of $18,215,330, or 40.1% of a projected total $45,409,606 in annual benefits. 34 https://www.energy.gov/diversity/justice40-initiative 35 FY22 PCE Community Report.pdf (akenergyauthority.org) 36 FY22 PCE Community Report.pdf (akenergyauthority.org) March 10, 2023 U.S. Department of Energy Grid Deployment Office Office of Clean Energy Demonstrations Re: FOA DE-FOA-0002740 Subject: Letter of Support for Alaska Railbelt GRIP Applications To Whom it May Concern: This letter expresses support for the applications submitted by the members of Alaska’s Bradley Lake Project Management Committee to Topic Areas 1, 2 and 3 of the Grid Resilience and Innovation Partnerships (GRIP) Program. The five railbelt electric utilities and the State of Alaska’s Alaska Energy Authority are working in unison to design, fund and implement a program of grid modernization that will directly benefit over 70% of the state’s population connected to the grid and indirectly benefit rural Alaskans who are geographically isolated from the railbelt. This is a once-in-a-generation opportunity for Alaskans to stabilize an aging grid, bringing it up to modern standards and improving its resiliency against future natural disasters, climate change, and the ongoing challenges wrought by our rugged geographic terrain. Perhaps most importantly, these improvements are critical to preparing Alaska for a fuel-diverse clean energy future so new sources of energy can be fully integrated, whatever and wherever they may be. The Railbelt Reliability Council (RRC) is a non-profit corporation certificated by the Regulatory Commission of Alaska (RCA) as the Electric Reliability Organization (ERO) responsible for performing Integrated Resource Planning and developing and enforcing Reliability, Security, and Non- Discriminatory Open Access Transmission and Interconnection Standards for the railbelt bulk energy system. The capital projects proposed in the GRIP applications will directly impact the system under the RRC’s ERO jurisdiction. The RRC was certificated less than six months ago, and is still in the process of staffing and organizing. As such, the RRC cannot at this time render opinions on the specific projects included within the GRIP applications. The RRC can affirm that the existing Railbelt grid has multiple single contingency elements, capacity bottlenecks, and technical and operational constraints that prevent optimal dispatch of the region’s existing and potential future suite of generation resources. The RRC can also confirm that the existing Railbelt grid leaves some regions isolated for up to several months every year during periods of annual maintenance and, at times, for even longer due to natural disasters such as wildland fires. The projects within the GRIP applications will address these long-standing limitations, and the parties involved in developing the GRIP applications are the best-available team to advance current proposals GRIP Application Support letter March 10, 2023 Page 2 of 2 for railbelt system improvements to address these limitations. Over the timeframe that these capital projects would unfold, the RRC will become fully functional, implementing standards and integrated resource plans that will in time directly influence the refinement, execution, and operation of the capital upgrades proposed in the GRIP applications. The RRC Board of Directors is a balanced independent and stakeholder board whose directors represent the stakeholder interests of railbelt utilities, independent power producers, residential, industrial, and environmental consumers, and state agencies. The stakeholder interests represented on the RRC’s board individually and collectively rely on the railbelt electric grid to power homes and businesses, drive manufacturing, support resource development, and bolster community services that make Alaska a place where current and future generations will thrive. The RRC looks forward to continuing engagement with the utilities and the State in partnership to ensure the benefits of this historic federal investment reach a wide and diverse group of Alaskans. Thank you for your time and attention to Alaska’s infrastructure needs. You may reach me via e-mail with any questions or requests for information. Sincerely, RAILBELT RELIABILITY COUNCIL Joel D. Groves. P.E. President and Board Chair joel@polarconsult.net Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 RE: Alaska’s Railbelt Grid Modernization and Resiliency Plan To Whom It May Concern, The Alaska Municipal League (AML) is a voluntary, nonprofit, nonpartisan, statewide organization of 165 cities, boroughs, and unified municipalities, wherein over 97 percent of Alaskans reside. Since the passage of the Bipartisan Infrastructure Law, AML has focused its efforts to support strategic regional projects that address the long-standing inadequacy of Alaska’s infrastructure. As part of this effort, we are proud to support projects that improve the condition of communities and intersect with Alaska’s municipalities. We are excited to see the proposed project for the Alaska Railbelt’s Grid Modernization and Resiliency Plan (GMRP) move forward. Working to decarbonize Alaska’s Railbelt grid is a particularly timely endeavor – state regulators have recently indicated that the natural gas supply that both power generation and other users rely on may not meet current demand within the next decade. This looming shortage puts economic activity throughout the state at risk by introducing long-term uncertainty to the key services that local governments and other organizations rely on from the Railbelt. With some of the highest energy prices in the country, solutions to control cost are a critical economic challenge facing Alaska’s communities and economic development. It’s important to note that in addressing costs on the Railbelt, these projects also stand to benefit communities across the state via the Power Cost Equalization program. The formula for this critical program ties subsidies for energy across the state to Railbelt prices – thus, if the cost of electricity on the Railbelt is lowered, it provides a greater subsidy to those communities who are experiencing high costs, and in effect lowering the cost to consumers. The GRMP is a strategic and collaborative effort that would go beyond the Railbelt to help make energy and the rural economies that depend on it more affordable and resilient. We fully support the GRMP and its associated projects. Sincerely, Nils Andreassen Executive Director 510 L Street, Suite 603, Anchorage, AK 99501 • 907-258-3700 • www.AEDCweb.com March 10, 2023 U.S. Department of Energy Grid Deployment Office Office of Clean Energy Demonstrations Re: FOA DE-FOA-0002740 To Whom it May Concern: I’m writing today in support of the applications submitted by the members of Alaska’s Bradley Lake Project Management Committee to Topic Areas 1,2 and 3 of the Grid Resilience and Innovation Partnerships (GRIP) Program. The five Railbelt electric utilities and the State of Alaska’s Alaska Energy Authority are working in unison to design, fund and implement a program of grid modernization that will directly benefit over 70% of the state’s population connected to the grid and indirectly benefit rural Alaskans who are geographically isolated from the Railbelt. This is a once-in-a-generation opportunity for Alaskans to stabilize an aging grid, bringing it up to modern standards and bringing resiliency in the face of unprecedented natural disaster, climate change and rugged geographic terrain. Perhaps most importantly, these improvements are critical to preparing Alaska for a fuel-diverse clean energy future and integrating new sources of energy, whatever they may be and wherever they are created. Anchorage Economic Development Corporation’s mission is to grow and diversify the economy of Anchorage and Alaska. The health and future success of the local economy relies on the Railbelt electric grid to power homes and businesses, drive manufacturing, support resource development and bolster community services that make Alaska a place where current and future generations will thrive. Going forward, we look forward to engaging with the utilities and the State and partnering to make sure the benefits of this historic federal investment reach a wide and diverse group of Alaskans. Thank you for your time and attention to Alaska’s infrastructure needs. You may reach me at 907-334-1206 or wpopp@aedcweb.com with any questions or requests for information. Sincerely, Bill Popp President & CEO Josi HartleyProgram Manager Board MeetingApril 11, 2023 ALASKA ENERGY AUTHORITY Electric Vehicle (EV) Program Update AEA EV Mission Statement Lead the effort to minimize barriers to EV adoption in Alaska. Dimond Center EV Car Show and Ride & Drive, Anchorage, AK 03 Sites Open Now Anchorage;Dimond Center Homer;AJ’s Old Town Steakhouse & Tavern Seward;Seward Chamber of Commerce Soldotna;Custom Seafoods Cantwell;Jack River Inn Cooper Landing; Grizzly Ridge Sites Under Construction Chugiak;Three Bears Alaska Healy;Three Bears Alaska Trapper Creek;Three Bears Alaska *AEA is working with the VW Trustee to obligate $125,000 to Southeast Alaska for Level Two community charging projects Volkswagen Settlement Update 3 EV Adoption in Alaska 04 EV Ownership: Geographic Distribution 05 5 174 7 122 258 922 783 Create an interconnected network Designated Alternative Fuel Corridors (AFC’s) New FHWA Federal Aid program apportioned to state DOT’s Annual Implementation Plan Required National Electric Vehicle Infrastructure (NEVI) Program The National Electric Vehicle Infrastructure (NEVI) Formula Program is a $5 billion program established by the Bipartisan Infrastructure Law (BIL) to build a national network of 500,000 electric vehicle (EV) charging stations by 2030 along federally designated Alternative Fuel Corridors (AFCs). 06 Alaska NEVI Plan AEA and the Alaska Department of Transportation & Public Facilities (DOT&PF), submitted their State of Alaska EV Infrastructure Implementation Plan (The Plan) to the United States Joint Office of Energy and Transportation, as required by the Infrastructure Investment and Jobs Act’s (IIJA) NEVI Formula Program. On September 27, 2022, AEA and DOT&PF securedapproval of The Plan. The announcement unlocks $19 million to expand EV charging infrastructure in Alaska. Over the next five years, AEA anticipates receiving $52 million. Funds will be received by DOT&PF and administered by AEA. FY24 NEVI Plan due on August 1, 2023 07 Funding must be used to build outAlternative Fuel Corridors (AFCs) first Alaska currently has one AFC After AFC buildout, funding can be used elsewhere Charging stations must be located no more than50 miles apart along designated AFC Chargers must be located no more than 1 driving mile from AFC Charging infrastructure must be DC fast-charging ⁻4 Combined Charging System Connectors ⁻>150 kW each Justice 40 80% Federal Share, 20% Match Title 23 Program National Electric Vehicle Infrastructure Standards and Requirements, Buy America Waiver NEVI Requirements 08 09 010 Priority AFC Areas 11 Eligible Applicants Open to a wide range of applicants Public, Private, Non-Profit, Tribal, utilities, etc. Eligible Projects Projects directly related to EV charging Publicly available Charging network provider Eligibility and Funding 12 13 Technical Scoring Element Max Points % of Total Understanding of Program and Project Methodology 100 10% Management Plan, Schedule, Development and Operation 200 20% Experience and Qualifications 200 20% Site Proposal 300 30% Maximum Technical Application Score 800 80% Pricing Scoring Element Max Points % of Total Site Pricing Application Cost 100 10% Site Pricing Application Narrative 100 10% Maximum Pricing Application Score 200 20% Overall Maximum Application Score 1000 100% Scoring Elements 14 015 Deploy publicly accessible EV charging and other alternative fueling infrastructure in communities and along AFCs Applications Due May 30 Eligible Infrastructure: EV Charging Hydrogen Fueling Natural Gas Fueling Propane Fueling FY22/23 Funding, up to $700 million Two funding Categories: Community Program ($350 million) Corridor Program ($350 million) Charging and Fueling Infrastructure (CFI) Program 15 May be located on any public road or other publicly accessible locations Minimum award: $500,000Maximum award: $15M20% Match Requirement CFI Community Grant Program Community Program Focus-Area Categories: •Multimodal Hubs and Shared Fleets •Urban/Suburban Area Charging •Rural Area Charging •Fleet Vehicles that Serve and Operate in Communities DOT&PF, AEA, AML and Launch Alaska developing an application concept to the Community Grant Program. Charging station deployment at state-owned facilities. Dual purpose to support community charging and state fleet electrification. 016 017 Past Events: RFA Release, March 1, 2023 DBE Conference Presentation, March 3, 2023 Quarterly AKEVWG Meeting, March 10, 2023 NEVI Pre-Application Meeting, March 15, 2023 IBEW and NECA Presentation, March 28, 2023 ITE California Presentation, March 28, 2023 AKEVWG Technical Session, April 3, 2023 Upcoming Events: Mat-Su NEVI Workshop, April 18, 2023 NEVI Applications Due, May 15, 2023 NEVI Evaluation Committee Meeting, May 22, 2023 AKEVWG Quarterly Meeting, May 22, 2023 Alaska SEC Presentation, May 23, 2023 CFI Applications Due, May 30, 2023 Anchorage NEVI Plan Workshop, June 12, 2023 Mat-Su NEVI Plan Workshop, June 13, 2023 Juneau NEVI Plan Workshop, June 14, 2023 Fairbanks NEVI Plan Workshop, June 15, 2023 Community Outreach 17 Alaska Energy Authority (AEA)Capital Appropriation Status Report FY231 of 6 PagesAs Of 3/14/2023Alaska Energy Authority (AEA) - Capital Appropriation Status Report(REF and PCE)EFFECTIVEDATEFund Source #ORIG YEARTERM YEARIRIS AR TYPE DESCRIPTION STATUS ORIGINALCURRENT BUDGET EXPENDED ENCUMBERED UNOBLIGATEDUGF UNOBLIGATEDDGF UNOBLIGATEDOTHER UNOBLIGATEDFED UNOBLIGATEDBULK FUEL UPGRADE PROGRAM 111/21/202210042002 2025 D321Language Section: Trans-Alaska Pipeline Liability FundThis project is on-going. Grants are in place for active bulk fuel upgrade projects to communities. Funds are a mix of federal Denali Commission funds and state/TAPL match. The appropriation's term year will be extended. The remaining authorization is needed for project completion.26,758,055.51 26,758,055.51 25,934,667.38 750,170.26 73,217.87 0.00 0.00 0.00 73,217.87211/21/20221140/11022011 2024 D241Bulk Fuel UpgradesThis project is on-going. Grants are in place for active bulk fuel upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The appropriation's term year will be extended. The remaining authorization is needed for project completion.5,000,000.00 5,000,000.00 3,487,176.22 494,824.87 1,017,998.91 0.00 0.00 0.00 1,017,998.91311/21/20221004/10022012 2024 D122Bulk Fuel UpgradesThis project is on-going. Grants are in place for active bulk fuel upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The appropriation's term year will be extended. The remaining authorization is needed for project completion.5,000,000.00 5,000,000.00 4,777,984.22 147,282.05 74,733.73 73,291.42 0.00 0.00 1,442.31411/21/20221004/10022013 2024 D065Bulk Fuel Upgrades This project is on-going. Grants are in place for active bulk fuel upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The appropriation's term year will be extended. The remaining authorization is needed for project completion.7,000,000.00 7,000,000.00 6,915,719.14 2,104.52 82,176.34 82,176.34 0.00 0.00 0.00511/21/20221004/10022014 2024 D006Bulk Fuel Upgrades This project is on-going. Grants are in place for active bulk fuel upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The appropriation's term year will be extended to FY2024. The remaining authorization is needed for project completion.6,000,000.00 6,000,000.00 5,885,129.76 89,221.30 25,648.94 0.00 0.00 0.00 25,648.94611/21/202211692017 2024 DH05Alaska Energy Authority - Bulk Fuel Upgrades This project is on-going. Grants are in place for active bulk fuel upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The appropriation's term year will be extended. The remaining authorization is needed for project completion.1,300,000.00 1,300,000.00 1,153,657.79 104,954.41 41,387.80 0.00 41,387.80 0.00 0.00711/21/202212432018 2024 DG10Alaska Energy Authority - Bulk Fuel Upgrades This project is on-going. Grants are in place for active bulk fuel upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The appropriation's term year will be extended. The remaining authorization is needed for project completion.2,420,000.00 2,420,000.00 2,115,208.37 101,671.26 203,120.37 203,120.37 0.00 0.00 0.00811/21/20221140/1102/10032019 2024 DF01Alaska Energy Authority - Bulk Fuel Upgrades This project is on-going. Grants are in place for active bulk fuel upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The appropriation's term year will be extended. The remaining authorization is needed for project completion.17,000,000.00 17,000,000.00 4,209,504.19 3,904,147.67 8,886,348.14 587,944.26 0.00 0.00 8,298,403.88911/21/20221140/11022022 2026 DF0MAlaska Energy Authority - Bulk Fuel UpgradesThis project is on-going. Grants are in place for active bulk fuel upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The appropriation's term year will be extended. The remaining authorization is needed for project completion.13,000,000.00 13,000,000.00 394,457.87 251,206.30 12,354,335.83 4,854,335.83 0.00 0.00 7,500,000.001011/21/20221002/100320232027 DW01Alaska Energy Authority - Bulk Fuel UpgradesThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.13,000,000.00 13,000,000.00 5,949.13 255,320.48 12,738,730.39 5,494,679.52 7,244,050.87TOTAL BULK FUEL PROGRAMS96,478,055.51 96,478,055.51 54,879,454.07 6,100,903.12 35,497,698.32 11,295,547.7441,387.80 0.00 24,160,762.78Active Projects: Beaver; Rampart, Tatitlek, Kasaan, Chalkytsik, Nunapitchuk, Shaktoolik, Scammon Bay, Shungnak, Venetie, Shageluk, Nondalton; M&I Projects (Akiak, Tuluksak, Kwigillingok, Port Graham, Nikolai, Atka, Diomede); Barge Header & Fill Lines; Dispensers. Alaska Energy Authority (AEA)Capital Appropriation Status Report FY232 of 6 PagesAs Of 3/14/2023EFFECTIVEDATEFund Source #ORIG YEARTERM YEARIRIS AR TYPE DESCRIPTION STATUS ORIGINALCURRENT BUDGET EXPENDED ENCUMBERED UNOBLIGATEDUGF UNOBLIGATEDDGF UNOBLIGATEDOTHER UNOBLIGATEDFED UNOBLIGATEDRURAL POWER SYSTEM UPGRADE PROGRAM1111/21/20221140/11022011 2024 D242Rural Power System UpgradesThis project is on-going. Grants are in place for active rural power systems upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The remaining authorization is needed for project completion.7,000,000.00 7,000,000.00 6,593,667.59 255,209.18 151,123.23 0.00 0.00 0.00 151,123.231211/21/20221004/10022012 2024 D124Rural Power System UpgradesThis project is on-going. Funding supports several rural power systems projects to communities. The appropriation's term year will be extended. Funds are a mix of federal Denali Commission funds and state match. The remaining authorization is needed for project completion.10,000,000.00 10,000,000.00 9,982,624.95 0.00 17,375.05 0.00 0.00 0.00 17,375.051311/21/20221004/10022013 2024 D067Rural Power Systems UpgradeThis project is on-going. Grants are in place for active rural power systems upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The remaining authorization is needed for project completion.13,000,000.00 13,000,000.00 12,120,645.59 701,995.71 177,358.70 0.00 0.00 0.00 177,358.701411/21/20221004/10022014 2024 D008Rural Power Systems UpgradeThis project is on-going. Grants are in place for active rural power systems upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The remaining authorization is needed for project completion.10,800,000.00 10,800,000.00 10,659,086.44 51,476.82 89,436.74 1,471.28 0.00 0.00 87,965.461511/21/2022 2015 2023 DN06Nunam Iqua Rural Power System UpgradeThis project is complete. The remaining authorization will lapse at the close of the current fiscal year.760,000.00 760,000.00 745,000.00 0.00 15,000.00 0.00 0.00 0.00 15,000.001611/21/20221004/11672016 2024 DH88Reapprop to Department of Commerce, Community, and Economic Development, AEA, for Rural Power Systems Upgrades - Est $1,053,858This project is on-going. Grants are in place for active rural power systems upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The remaining authorization is needed for project completion.1,053,858.00 1,053,858.00 1,000,823.26 31,632.46 21,402.28 0.00 0.00 21,402.28 0.001711/21/202212102017 2024 DG64Reapprop for Alaska Energy Authority - Rural Power Systems Upgrades - NTE $3,156,000This project is on-going. Grants are in place for active rural power systems upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The remaining authorization is needed for project completion.3,156,000.00 3,156,000.00 3,142,741.43 2,599.00 10,659.57 0.00 10,659.570.00 0.001811/21/202211692017 2024 DH10Alaska Energy Authority - Rural Power Systems UpgradesThis project is on-going. Grants are in place for active rural power systems upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The remaining authorization is needed for project completion.1,446,142.00 1,446,142.00 1,407,722.99 0.00 38,419.01 0.00 38,419.01 0.00 0.001911/21/20221169/10022019 2024 DF03Alaska Energy Authority - Rural Power Systems UpgradesThis project is on-going. Grants are in place for active rural power systems upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The remaining authorization is needed for project completion.21,900,000.00 21,900,000.00 10,860,019.83 7,936,945.83 3,103,034.34 0.00 746,392.45 0.00 2,356,641.892011/21/202210042021 2025 DF83Alaska Energy Authority - Rural Power Systems UpgradesThis project is on-going. Grants are in place for active rural power systems upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The remaining authorization is needed for project completion.17,500,000.00 17,500,000.00 592,861.80 2,636,968.92 14,270,169.28 1,770,169.28 0.00 0.00 12,500,000.002111/21/202210042022 2026 DF0NAlaska Energy Authority - Rural Power Systems UpgradesThis project is on-going. Grants are in place for active rural power systems upgrade projects to communities. Funds are a mix of federal, Denali Commission funds, and state match. The remaining authorization is needed for project completion.17,500,000.00 17,500,000.00 2,324,826.11 1,859,552.35 13,315,621.54 815,621.54 0.00 0.00 12,500,000.002211/21/20221169/100220232027 DW04Alaska Energy Authority - Rural Power Systems UpgradesThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.20,000,000.00 20,000,000.00 11,435.25 639,033.00 19,349,531.75 0.00 9,358,027.28 0.00 9,991,504.47TOTAL RURAL POWER SYSTEMS UPGRADE PROGRAM124,116,000.00 124,116,000.00 59,441,455.24 14,115,413.27 50,559,131.49 2,587,262.10 10,153,498.31 21,402.28 37,796,968.80 Active Projects: Nikolai, Akhiok, Venetie, Napaskiak, Nelson Lagoon, Rampart, Manokotak, Minto; Port Heiden Phase 1 Distribution Upgrades; Maintenance and Improvement Projects (Stevens Village, Arctic Village, Atka, Koyukuk, Akiachak, Beaver, Chefornak, Diomede, Atka, Koyukuk, Akiachak, Beaver, Chefornak, Diomede, Galena, Karluk, Quzinkie, Tenakee Springs, Angoon, Chignik Bay, Chitina, Pilot Point, Kwethluk, Levelock, Unalakleet, Hoonah, Igiugig,Kwigillingok); DERA (TCC, Circle, Chignik Lake, Arctic Village, Grayling, Platinum, Ruby, Akiachak). Alaska Energy Authority (AEA)Capital Appropriation Status Report FY233 of 6 PagesAs Of 3/14/2023EFFECTIVEDATEFund Source #ORIG YEARTERM YEARIRIS AR TYPE DESCRIPTION STATUS ORIGINALCURRENT BUDGET EXPENDED ENCUMBERED UNOBLIGATEDUGF UNOBLIGATEDDGF UNOBLIGATEDOTHER UNOBLIGATEDFED UNOBLIGATEDELECTRICAL EMERGENCIES2311/21/2022 2019 2024 DF02Alaska Energy Authority - Electrical Emergencies ProgramThis project is on-going. This appropriation funds electrical emergencies. These funds are anticipated to be depleted during FY2024. 330,000.00 330,000.00 175,984.77 999.00 153,016.23 153,016.23 0.00 0.00 0.002411/21/2022 2021 2026 DF0AAlaska Energy Authority - Electrical Emergencies ProgramThis project is on-going. This appropriation funds electrical emergencies. Remaining funds are needed.200,000.00 200,000.00 0.00 99,000.00 101,000.00 101,000.00 0.00 0.00 0.002511/21/2022 2023 2027 DW02Alaska Energy Authority - Electrical Emergencies ProgramThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.200,000.00 200,000.00 0.00 0.00 200,000.00 200,000.00 0.00 0.00 0.00TOTAL ELECTRICAL EMERGENCIES730,000.00 730,000.00 175,984.77 99,999.00 454,016.23 454,016.23 0.00 0.00 0.00RAILBELT2611/21/202210122008 2024 D283Alaska Energy Authority - ALCAN IntertieFunds used for repair of Static VAR Compensators and tower foundation repair on the Alaska Intertie. Remaining funds are encumbered for warranty and maintenance contract for these improvements. The remaining balance is needed for project completion.10,000,000.00 10,000,000.00 8,241,764.05 378,568.00 1,379,667.95 1,379,667.95 0.00 0.00 0.002711/21/202210122012 2024 D097Reapprop to Alaska Energy Authority for Railbelt-wide Detailed Transmission Line Plan and Extension of Intertie to Point MacKenzieThis project is complete. The remaining authorization will lapse at the close of the next fiscal year.1,000,000.00 1,000,000.00 986,372.64 0.00 13,627.36 13,627.36 0.00 0.00 0.002811/21/202210122012 2024 D098Reapprop to Alaska Energy Authority for Railbelt-wide Detailed Transmission Line Plan and Extension of Intertie to Point MacKenzieAlaska Energy Authority is working with the Railbelt utilities to scope the Intertie extension projects. Energy Plan efforts are underway. The appropriations term year will be extended to FY2024.4,527,406.92 4,527,406.92 1,483,268.11 0.00 3,044,138.81 3,044,138.81 0.00 0.00 0.002911/21/2022100420232027 DW05Alaska Energy Authority - Strategic Plan for Railbelt AssetsThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.2,500,000.00 2,500,000.00 737.42 0.00 2,499,262.58 2,499,262.58 0.00 0.00 0.00TOTAL RAILBELT18,027,406.92 18,027,406.92 10,712,142.22 378,568.00 6,936,696.70 6,936,696.70 0.00 0.00 0.00ENERGY PLANNING3011/21/202210042012 2024 D121Alaska Energy Plan ImplementationThis project is ongoing. Activities are ongoing, and the remaining authorization is needed for project completion.1,000,000.00 1,000,000.00 967,485.77 12,249.00 20,265.23 20,265.23 0.00 0.00 0.003111/21/202210042013 2024 D062Alaska Energy Plan ImplementationThis project is active and on-going. Planning funds support technical assistance to community local energy planning and to advancing projects and priorities identified in local and regional plans. The remaining authorization is needed for project completion. The Alaska Energy Authority continues to work on State Energy Planning initiatives as the State's Energy Office.1,000,000.00 1,000,000.00 975,733.24 0.00 24,266.76 24,266.76 0.00 0.00 0.00TOTAL ENERGY PLANNING2,000,000.00 2,000,000.00 1,943,219.01 12,249.00 44,531.99 44,531.99 0.00 0.00 0.00 Alaska Energy Authority (AEA)Capital Appropriation Status Report FY234 of 6 PagesAs Of 3/14/2023EFFECTIVEDATEFund Source #ORIG YEARTERM YEARIRIS AR TYPE DESCRIPTION STATUS ORIGINALCURRENT BUDGET EXPENDED ENCUMBERED UNOBLIGATEDUGF UNOBLIGATEDDGF UNOBLIGATEDOTHER UNOBLIGATEDFED UNOBLIGATEDALTERNATIVE ENERGY & ENERGY EFFICIENCY PROGRAMS3211/21/20221140/11022011 2024 D240Alternative Energy and Energy EfficiencyThis project is on-going. Funds support Alternative Energy and Energy Efficiency programs and provide state match to federal dollars. The appropriation's term year will be extended to FY2024. The remaining authorization is needed for project completion and for matching federal funds.8,000,000.00 8,000,000.00 5,713,758.98 1,319,815.53 966,425.49 153,666.98 0.00 0.00 812,758.513311/21/20221004/1002/1108/10072013 2024 D063Alternative Energy and Energy Efficiency (AEEE) ProgramsThis project is on-going. Funds support Alternative Energy and Energy Efficiency programs and provide state match to federal dollars. Remaining authorization is needed for project completion and for matching federal funds. The appropriation's term year will be extended. 4,800,000.00 7,800,000.00 2,110,195.69 68,151.11 5,621,653.20 272,420.57 0.00 785,687.50 4,563,545.133411/21/202210042014 2024 D005Alternative Energy and Energy Efficiency ProgramsThis project is on-going. Funds support Alternative Energy and Energy Efficiency programs and provide state match to federal dollars. Remaining authorization is needed for project completion and for matching federal funds. The appropriation's term year will be extended to FY2024. 2,000,000.00 2,000,000.00 1,101,010.43 165,768.37 733,221.20 733,221.20 0.00 0.00 0.003511/21/202211082020 2024 DF40Alaska Energy Authority - Rural Outdoor Lighting Efficiency RetrofitThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The remaining authorization is needed for project completion.1,000,000.00 1,000,000.00 811,286.11 107,700.65 81,013.24 0.00 0.00 81,013.24 0.003611/21/202210042022 2027 DF0KAlaska Energy Authority - Alaska Cargo and Cold StorageAlaska Energy Authority is working with its project partners to clarify and satisfy Federal Highway Administration pre-award conditions. Grant award is pending. 21,000,000.00 21,000,000.00 0.00 0.00 21,000,000.00 0.00 0.00 0.00 21,000,000.003711/21/202210042022 2026 DF0LAlaska Energy Authority - Alternative Energy and Energy Efficiency ProgramsThis project is on-going. Funds support Alternative Energy and Energy Efficiency programs and provide state match to federal dollars. Remaining authorization is needed for project completion and for matching federal funds. 5,000,000.00 5,000,000.00 1,385.98 74,347.00 4,924,267.02 0.00 0.00 0.00 4,924,267.023811/21/2022100220232027 DW26Alaska Energy Authority - Energy Efficiency Conservation Block GrantsThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.2,000,000.00 2,000,000.00 0.00 0.00 2,000,000.00 0.00 0.00 0.00 2,000,000.003911/21/2022100220232027 DW23Alaska Energy Authority - New Energy Auditor Training Grant ProgramThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.63,600.00 63,600.00 0.00 0.00 63,600.00 0.00 0.00 0.00 63,600.004011/21/2022100220232027 DW24Alaska Energy Authority - New Energy Efficiency Revolving Loan Fund Capitalization ProgramThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.796,000.00 796,000.00 0.00 0.00 796,000.00 0.00 0.00 0.00 796,000.004111/21/2022100220232027 DW25Alaska Energy Authority - State Energy ProgramThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.796,000.00 796,000.00 6,264.71 150,000.00 639,735.29 0.00 0.00 0.00 639,735.29TOTAL ALTERNATIVE ENERGY & ENERGY EFFICIENCY PROGRAMS45,455,600.00 48,455,600.00 9,743,901.90 1,885,782.66 36,825,915.44 1,159,308.75 - 866,700.74 34,799,905.95 VOLKSWAGON SETTLEMENT4211/21/202211082018 2024 DG74Alaska Energy Authority - Volkswagen SettlementGrant documents are in place and in process for Volkswagen Settlement Environmental Mitigation Trust grants. This appropriation's term year will be extended. The remaining authorization is needed for project completion.8,125,000.00 8,125,000.00 6,432,159.55 653,965.44 1,038,875.01 0.00 0.00 1,038,875.01 0.004311/21/2022110820232027 DW85Alaska Energy Authority - Volkswagen SettlementThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.400,000.00 400,000.00 0.00 0.00 400,000.00 0.00 0.00 400,000.00 0.00TOTAL VOLKSWAGON SETTLEMENT8,525,000.00 8,525,000.00 6,432,159.55 653,965.44 1,438,875.01 0.00 0.001,438,875.01 0.00Programs: Village Energy Efficiency Programs, State Energy Program Formula (SEP); Electric Vehicle, State Energy Security Plan, State‐wide energy planning, Hydroelectric Development, Wind, Solar, Biomass, Data Library, Data Management) Alaska Energy Authority (AEA)Capital Appropriation Status Report FY235 of 6 PagesAs Of 3/14/2023EFFECTIVEDATEFund Source #ORIG YEARTERM YEARIRIS AR TYPE DESCRIPTION STATUS ORIGINALCURRENT BUDGET EXPENDED ENCUMBERED UNOBLIGATEDUGF UNOBLIGATEDDGF UNOBLIGATEDOTHER UNOBLIGATEDFED UNOBLIGATEDRENEWABLE ENERGY GRANTS4411/21/202212102010 2024 D262Alaska Energy Authority - Renewable Energy Project Grants (AS 42.45.045)This project is complete and being reviewed for close-out and final payment, estimated to be final by 06/30/2024. The remaining authorization will lapse to the Renewable Energy Fund upon close-out and final payment.21,080,339.02 21,080,339.02 20,988,776.32 91,562.70 0.00 0.00 0.00 0.00 0.004511/21/202212102013 2024 D073Thayer Lake Hydropower Transmission/Generation Project is on-going as permits are finalized (USFS signed Change Analysis for modified road routing and overhead transmission lines from 2009 Special Use Permit) and the grantee works on construction funding package for estimated construction cost exceeding REF grant. The Period of Performance was extended to 2024.7,000,000.00 7,000,000.00 1,539,519.20 605,163.80 4,855,317.00 0.00 4,855,317.00 0.00 0.004611/21/202212102019 2024 DF04Fivemile Creek Hydroelectric ProjectThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The project is anticipated to be complete by 12/31/2023. Funding from the Denali Commission was awarded in December 2020 to complete the construction of the project. The remaining authorization is needed for project completion.3,516,240.00 3,516,240.00 488,241.92 187,410.08 2,840,588.00 0.00 2,840,588.00 0.00 0.004711/21/202212102019 2023 DF05Wales Water System Heat Recovery This project is complete. 69,905.00 69,905.00 69,905.00 0.00 0.00 0.00 0.00 0.00 0.004811/21/202212102019 2023 DF07Koyuk Water System Heat Recovery This project is complete. 90,922.00 90,922.00 90,922.00 0.00 0.00 0.00 0.00 0.00 0.004911/21/202212102019 2024 DF08Shishmaref Wind Feasibility and Conceptual DesignThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The remaining authorization is needed for project completion. This project's estimated completion date is March 31, 2024. 152,000.00 152,000.00 79,727.00 72,273.00 0.00 0.00 0.00 0.00 0.005011/21/202212102019 2024 DF09Heat Pump System for City of SewardThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The remaining authorization is needed for project completion. This project's estimated completion date is March 31, 2024.725,000.00 725,000.00 88,000.00 637,000.00 0.00 0.00 0.00 0.00 0.005111/21/202212102022 2026 DF2ACity of Unalaska Wind Power Feasibility and Conceptual DesignThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The project is anticipated to be complete by 06/30/2023. The remaining authorization is needed for project completion.139,000.00 139,000.00 13,450.28 125,549.72 0.00 0.00 0.00 0.00 0.005211/21/202212102022 2026 DF2BKotzebue Community-Scale Energy Storage SystemThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The project is anticipated to be complete by 09/30/2023. The remaining authorization is needed for project completion.325,000.00 325,000.00 0.00 325,000.00 0.00 0.00 0.00 0.00 0.005311/21/202212102022 2026 DF2CNaknek Service Area Wind and Solar Power Feasibility and Conceptual DesignThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The project is anticipated to be complete by 06/30/23. The remaining authorization is needed for project completion.103,500.00 103,500.00 3,720.00 99,780.00 0.00 0.00 0.00 0.00 0.005411/21/202212102022 2026 DF2DKotlik Wind Energy Feasibility and Conceptual Design ProjectThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The project is anticipated to be complete by 09/30/2024. The remaining authorization is needed for project completion.237,500.00 237,500.00 63,389.00 174,111.00 0.00 0.00 0.00 0.00 0.005511/21/202212102022 2026 DF2EDillingham Nuyakuk River Hydroelectric ProjectThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The project is anticipated to be complete by 12/31/2025. The remaining authorization is needed for project completion.1,000,000.00 1,000,000.00 871,238.20 128,761.80 0.00 0.00 0.00 0.00 0.005611/21/202212102022 2026 DF2FGoodnews Bay Wind Energy Feasibility and Conceptual Design ProjectThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The project is anticipated to be complete by 07/23/2023. The remaining authorization is needed for project completion.128,250.00 128,250.00 12,758.00 115,492.00 0.00 0.00 0.00 0.00 0.005711/21/202212102022 2026 DF2GShungnak Heat Recovery ExpansionThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The project is anticipated to be complete by 12/31/2023. The remaining authorization is needed for project completion.1,303,607.00 1,303,607.00 69,308.81 1,234,298.19 0.00 0.00 0.00 0.00 0.00 Alaska Energy Authority (AEA)Capital Appropriation Status Report FY236 of 6 PagesAs Of 3/14/2023EFFECTIVEDATEFund Source #ORIG YEARTERM YEARIRIS AR TYPE DESCRIPTION STATUS ORIGINALCURRENT BUDGET EXPENDED ENCUMBERED UNOBLIGATEDUGF UNOBLIGATEDDGF UNOBLIGATEDOTHER UNOBLIGATEDFED UNOBLIGATED5811/21/202212102022 2026 DF2HKongiganak Improved Airfoil for Wind TurbinesGrant/contract documents are in process. The project is anticipated to be complete by 06/30/2024.108,000.00 108,000.00 0.00 0.00 108,000.00 0.00 108,000.00 0.00 0.005911/21/202212102022 2026 DF2IWalter Northway School Wood Chip Heating SystemThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The project is anticipated to be complete by 06/30/2023. The remaining authorization is needed for project completion.650,000.00 650,000.00 0.00 650,000.00 0.00 0.00 0.00 0.00 0.006011/21/202212102022 2026 DF2JHoonah Water Supply Creek Hydro Final DesignThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The project is anticipated to be complete by 06/30/2023. The remaining authorization is needed for project completion.461,474.00 461,474.00 186,368.88 275,105.12 0.00 0.00 0.00 0.00 0.006111/21/202212102022 2026 DF2KCordova Hydro Storage Assessment ProjectThis project contains grant funds that are encumbered and will be expended upon receipt of billings from the recipient. The project is anticipated to be complete by 03/31/2024. The remaining authorization is needed for project completion.294,642.00 294,642.00 0.00 294,642.00 0.00 0.00 0.00 0.00 0.006211/21/2022121020232027 DW03Alaska Energy Authority - Round XIV Renewable Energy Project Grants (AS 42.45.045)This authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.15,000,000.00 15,000,000.00 247,166.73 8,817,138.27 5,935,695.00 0.00 5,935,695.00 0.00 0.00TOTAL RENEWABLE ENERGY GRANTS52,385,379.02 52,385,379.02 24,812,491.34 13,833,287.68 13,739,600.00 0.0013,739,600.00 0.00 0.00ELECTRIC UTILITY RELIEF PROGRAM (EURP)6311/21/202210042021 2024 DF0GGrants to Electric Utilities to Address Delinquent PaymentsThis project is completed and in close-out. Remaining federal authorization will lapse.7,000,000.00 7,000,000.00 3,358,814.19 0.00 3,641,185.81 0.00 0.00 0.00 3,641,185.81TOTAL ELECTRIC UTILITY RELIEF (EURP) PROGRAM7,000,000.00 7,000,000.00 3,358,814.19 0.003,641,185.81 0.00 0.00 0.003,641,185.81 GRID MODERNIZATION6411/21/202210042022 2026 DW29Grid Modernization, Reliability, Resiliency and Transmission ProjectsThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.250,000.00 250,000.00 82,738.27 97,065.43 70,196.30 70,196.30 0.00 0.00 0.006511/21/202210042022 2024 DW87Reappropriate NTE $3,633,158 to AEA for Statewide Grid Resilience and Reliability for FY ending 6/30/2023 and 6/30/2024This authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.3,633,158.00 3,633,158.00 0.00 0.00 3,633,158.00 3,633,158.00 0.00 0.00 0.006611/21/2022100220232027 DW00Alaska Energy Authority - Alaska Grid Resilience and Reliability - FormulaThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.12,110,523.00 12,110,523.00 0.00 0.00 12,110,523.00 0.00 0.00 0.00 12,110,523.00TOTAL GRID MODERNIZATION15,993,681.00 15,993,681.00 82,738.27 97,065.43 15,813,877.30 3,703,354.30 0.00 0.00 12,110,523.00ELECTRIC VEHICLE (EV) INFRASTRUCTURE PROGRAM6711/21/202210042022 2026 DW27Alaska Energy Authority - Electrical Vehicle Infrastructure PlanThis authorization became effective in the current fiscal year. Significant, on-going project activity is estimated to begin by 06/30/2024.1,500,000.00 1,500,000.00 15,948.35 0.00 1,484,051.65 1,484,051.65TOTAL ELECTRIC VEHICLE (EV) INFRASTRUCTURE PROGRAM1,500,000.00 1,500,000.00 15,948.35 0.00 1,484,051.65 1,484,051.65 0.00 0.00 0.00DCCED GRANT TO DENALI COMMISSION FOR SUPPORT OF RURAL ROADS/WATERFRONT DEVELOPMENT 6811/21/2022 2016 2024 DH92Reapprop to DCCED for a Grant to the Denali Commission for State Support of Rural Roads and Waterfront Development- Est $3,000,000This project is complete. The remaining authorization will lapse at the close of the current fiscal year.5,565,645.00 5,565,645.00 5,525,594.96 39,809.71 240.33 240.33 0.00 0.00 0.00TOTAL DCCED GRANT TO DENALI COMMISSION FOR SUPPORT OF RURAL ROADS/WATERFRONT DEVELOPMENT5,565,645.00 5,565,645.00 5,525,594.96 39,809.71 240.33 240.33 0.00 0.00 0.00GRAND TOTAL377,776,767.45 380,776,767.45 177,123,903.87 37,217,043.31 166,435,820.27 27,665,009.79 23,934,486.11 2,326,978.03 112,509,346.34 Governor Dunleavy Announces Energy Security Task Force Members Mar 22, 2023 Today, Alaska Governor Mike Dunleavy revised the Alaska Energy Security Task Force and announced its members. The Governor issued Administrative Order 344 on February 23, 2023, establishing the task force. The task force has been revised to include the Lieutenant Governor as the Chair and add an additional public seat, increasing the number of voting members from 13 to 15. The Energy Security Task Force, as revised in Administrative Order 345, focuses on Alaska’s efforts to reduce the cost of energy for Alaskans. “Alaska is an oil and gas giant, but we are all in for every form of energy – wind, solar, hydro, tidal, geothermal, micronuclear, and hydrogen,” said Governor Dunleavy. “I have full confidence in these members of the Energy Security Task Force to identify tactics to reduce the cost of energy for Alaskans during this exciting time of energy innovation in Alaska. “I am honored to sit as the Governor’s Energy Security Task Force chair,” said Lt. Governor Dahlstrom. “Together, we will work on a plan to reduce Alaska’s vulnerability to fluctuating energy markets by securing dependable and affordable energy for Alaskan residents.” The Alaska Energy Security Task Force will consist of 15 voting members and three ex officio members appointed by and serving at the pleasure of the Governor. The voting members are as follows: • Lieutenant Governor Dahlstrom (Chair of the Task Force) • Commissioner Jason Brune (Commissioner of the Department of Environmental Conservation) • Commissioner John Boyle (Commissioner of the Department of Natural Resources) • Curtis Thayer (Vice Chair of the Task Force) (The Executive Director of the Alaska Energy Authority) • Gwen Holdman (Vice Chair of the Task Force) (Member from the University of Alaska with a background in energy) • Clay Koplin, Cordova Electric Cooperative (Member from a utility that represents rural Alaska or a community receiving power cost equalization) • Nils Andreassen, Alaska Municipal League (Member who represents a city, borough, or municipality) • Tony Izzo, Matanuska Electric Association (Member with a Railbelt utility background) • John Simms, Enstar (Member from the oil and gas industry) • Karl Hanneman, International Tower Hill Mines (Member from the mining industry) • Robert Venables, Southeast Conference (Member with a background in economic development) • Andrew Guy, Calista Corporation (Member from the business community) • Jenn Miller, Renewable Independent Power Producers (Member from any segment of the Alaskan energy industry) • Duff Mitchell, Juneau Hydropower (Member of the general public) • Isaac Vandenburg, Launch Alaska (Member of the general public) “We are committed to making sure Alaskans have access to energy that is affordable, reliable, and redundant,” said AEA Executive Director Curtis W. Thayer. “The members of this task force cover a wide array of knowledge and perspectives. Together, we will provide an effective platform for ensuring that a statewide energy plan is comprehensive with a focus on long-term solutions. “Addressing the challenge of providing affordable, reliable energy to our communities is vital to Alaska’s long-term economic and social well-being,” said Gwen Holdmann, Associate Vice Chancellor for Research, Innovation & Industry Partnerships; University of Alaska Fairbanks. “I am honored to work with this diverse group of Alaskans to develop a sustainable path toward energy independence for the state. Alaskans are innovators, and I believe that in working together, we can come up with creative strategies to meet our energy needs for today, and for the future.” The ex officio members are as follows (plus the two seats from the legislature): • Commissioner Keith Kurber (Member of the Regulatory Commission of Alaska) • Garrett Boyle (Representative from the Denali Commission) • Erin Whitney (From the U.S. Department of Energy, Arctic Energy Office) • Senator Click Bishop (District R) • Representative George Rauscher (District 29) The Task Force shall deliver an initial report to the Governor by May 19, 2023, and the Task Force will sunset on October 31, 2023. 813 West Northern Lights Boulevard, Anchorage, Alaska 99503 T 907.771.3000 Toll Free 888.300.8534 F 907.771.3044 REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG TO: Curtis Thayer, Executive Director FROM: Rebecca Garrett, Rural Programs Manager DATE: March 15, 2023 SUBJECT: AEA Rural Programs & Projects Highlights Training Highlight AEA, with funding partner the Denali Commission, provided training at the Seward AVTEC facility for 213 power plant, bulk fuel operators, and person in charge (PIC) over the last five years. This training is fundamental to maximizing the useful life of rural energy infrastructure. It also develops well-paying local jobs in rural communities. There are seven training programs for power plant operators, bulk fuel operators, utility management, the Circuit Rider program and emergency response, with a total budget of over $9m. Rural Power System Upgrades (RPSU) The new power house in Nikolai is operational, punch list items remain. The Venetie power system upgrade will pick back up in May and is expected to go on-line in September. This project has been expanded to include the distribution portion of the project and will be completed in 2024. Powerhouse modules for Rampart, Napaskiak, and Nelson Lagoon will be assembled in southcentral Alaska over the winter, with the goal of installation in 2024. Local operators will be invited to Anchorage to participate in the testing of the module before it is moved on site. Once there, extensive onsite training is conducted with the local operators and utility managers before turning the project over to the community. The estimated cost is $16 million for the Napaskiak, Rampart, and Nelson Lagoon projects. This reflects a price increase of approximately 43% over the course of design for these powerhouse upgrades. The cost increase can be directly linked to inflation, logistics delays, and work force shortages. In total there are fifty-two rural power system upgrade projects - from system replacement to maintenance and improvement, with a total budget of over $46m. Bulk Fuel Upgrades (BFU) Alaska’s approximately 400 eligible bulk fuel facilities face mounting challenges from aging infrastructure and increased ocean and river erosion. The inventory and assessment program has started with a few test sites. This will be a multi-year effort and provide accurate information regarding the condition of bulk fuel facilities which will enable the same benefits realized from the power systems inventory and assessment. Alaska Energy Authority Page 2 of 2 New bulk fuel tank farms cost $5-8 million. With limited funding, the BFU program has moved heavily to maintenance and improvement type projects that require local matching funds to ensure a complete project. Under this program, each community has a list of maintenance projects, approximate cost, and priority for each project. There are currently 11 M&I projects in various stages. There are thirty-two active bulk fuel upgrade projects, with a total budget of over $29m and one shovel ready BFU projects waiting for funding, Ekwok. Award No Project Name DC Funding Perf. Period Beg Perf. Period Thru Actions Since Last Report Estimated Jobs Created Permanent Jobs Created Internal Use Only 01432-12 Tatitlek BFU 1,472,000 6/1/2013 6/30/2023 None 15 2 01474-09 Chalkytsik BFU (2)517,500 6/16/2015 6/30/2023 None 15 2 01485-05 START Communities Technical Assistance 375,000 11/1/2015 3/31/2023 None 2 0 01492-10 Beaver BFU 608,000 7/6/2016 9/30/2023 None 5 2 01500-08 Bulk Fuel Operator Training 1,610,000 9/1/2016 6/30/2023 None 3 0 01515-09 Circuit Rider Program 1,350,000 1/1/2017 12/31/2023 None 3 0 01516-08 RPSU - Maintenance & Improvement 748,776 10/1/2016 12/31/2024 None 20 0 01523-08 Miscellaneious Small M&I Projects 1,920,000 6/1/2017 12/31/2024 None 20 0 01525-07 Training - Advanced Power Plant Operators 872,514 8/15/2017 6/30/2023 None 3 0 01544-06 Training - Itinerant Electric Utility 500,000 3/1/2018 12/31/2023 None 3 0 01548-07 RPS Maintenance & Improvement Program-Statewide 3,090,000 5/1/2018 9/30/2023 None 20 0 01549-06 RPS Inventory & Assessment-Statewide 300,000 5/1/2018 9/30/2022 None 01551-07 Venetie RPSU 2,250,000 5/1/2018 12/31/2025 Extend Period of Performance & Funding 5 2 01557-03 Barge Headers and Fill Lines 3,976,820 10/1/2018 12/31/2024 None 60 0 01571-02 Nunapitchuk BF 3,522,546 8/15/2019 12/31/2023 None 30 2 01574-02 Nikolai RPSU 1,733,740 8/1/2019 3/31/2023 None 5 2 01575-06 Nelson Lagoon - RPSU 1,585,455 8/1/2019 12/31/2025 Extend Period of Performance & Funding 5 2 01576-04 Rampart - RPSU 1,733,740 8/1/2019 12/31/2024 None 5 2 01577-05 Napaskiak - RPSU 335,455 8/1/2019 12/31/2024 None 26 2 01600-02 AEEE - Village Energy Efficiency Program - State 875,000 6/15/2020 12/31/2023 None 3 0 01611-02 AEA Data Library 100,000 9/1/2020 6/30/2023 None 1 0 01618-01 Fivemile Creek Hydroelectric Project R2,R4 2,880,000 9/1/2020 6/30/2024 None 65 2 01628-02 DC Craig High School Biomass Project 440,417 11/1/2020 12/31/2023 None 0 2 01645-01 O&M Manual Conversion & Training 75,000 4/1/2021 9/30/2023 None 4 0 01646-00 Bulk Fuel Inventory and Assessment 480,000 4/1/2021 12/31/2023 None 20 0 01647-01 Port Heiden Phase 1 Distribution Upgrades 1,905,600 4/1/2021 12/31/2024 None 8 0 01666-01 Littoral Power Systems Hydrokinetic Project 80,642 11/15/2021 3/31/2023 None 1 0 01704-00 Chalkyitsik RPSU 200,000 10/1/2022 3/31/2024 None 5 2 01705-01 Middle Kuskokwim Electric Cooperative FMAP 200,000 10/1/2022 3/31/2024 Change Project name to MKEC & FMAP 5 2 01731-00 Shungnak BFU 3,296,032.04 1/1/2023 3/31/2024 New award 30 2 Total Funding for Active DC Awards:39,034,237 Less Total Spending on Active DC Awards:(18,883,763) Total Funding Remaining on Active DC Awards:20,150,474 Active Denali Commission Awards As of 03/16/2023 PAYMENTS RECEIVED LATE FEES RECEIVED INTEREST + LATE FEES ($453,720)$3,039 $190,892 18 TOTAL # OF PPF LOANS LOAN DASHBOARD REPORT For Board Meeting on 4/11/2023 AEA POWER PROJECT LOAN FUND FISCAL YEAR-TO-DATE LOAN PORTFOLIO ACTIVITY (07/01/2022 - 2/28/2023) LOAN ACTIVITY EARNINGS LOAN CATEGORY STARTING BALANCE FUNDS DISBURSED ENDING BALANCE INTEREST RECEIVED AEA Power Project Fund $27,534,898 $54,486 $27,135,664 $187,853 LOAN PROGRAM SUMMARY Outstanding Loans $27,135,663.98 Uncommitted Cash Balance $6,759,864.52 Loan Commitments $5,592,482.76 Total Loan Program $39,488,011.26 0 $0 0.000% TOTAL # OF DELINQUENT LOANS LOANS DELINQUENT AMOUNT ($) % OF DELINQUENT LOANS ($) Page 1 TOTAL ($) $2,346,815 $929,068 $849,631 $8,317,916 $18,695,792 $4,362,254 $35,501,476 AEA POWER PROJECT FUND LOANS BY ENERGY REGION & PROJECT TYPE OUTSTANDING BALANCES & NEW ACTIVITY ENERGY REGION AEA PPF LOAN BALANCE REMAINING LOAN COMMITMENTS NEW APPLICATIONS IN PROCESS # OF AEA PPF LOANS ALEUTIANS $2,346,815 --3 BRISTOL BAY $414,568 -$514,500 2 LOWER YUKO- KUSKOKWIM $849,631 --2 RAILBELT $3,323,416 -$4,994,500 4 SOUTHEAST $18,695,792 --2 YUKON-KOYUKUK/U TANA $1,505,442 $597,983 $2,258,829 5 TOTAL $27,135,664 $597,983 $7,767,829 18 AEA PPF LOANS BY PROJECT TYPE AEA PPF LOANS BY PROJECT TYPE - BALANCE (NEW & OUTSTANDING) PROJECT TYPE # OF PROJECTS PROJECT TYPE BALANCE HYDRO 5 HYDRO $22,301,759.06 DIESEL 5 SOLAR $5,510,799.35 WIND 3 TANK FARM $2,258,829.00 SOLAR 2 WIND $2,062,464.41 BIOMASS 1 TRANSMISSION $1,966,667.00 TANK FARM 1 DIESEL $1,326,334.04 TRANSMISSION 1 BIOMASS $74,622.88 Page 2 REDUCING THE COST OF ENERGY IN ALASKARenewable Energy Fund Advisory Committee (REFAC)Alaska Energy Authority —Renewable Energy Fund – Round XVREDUCING THE COST OF ENERGY IN ALASKASAFE, RELIABLE, & AFFORDABLE ENERGY SOLUTIONSApril 5, 2023 REDUCING THE COST OF ENERGY IN ALASKA2Welcome and IntroductionsSAFE, RELIABLE, & AFFORDABLE ENERGY SOLUTIONS REDUCING THE COST OF ENERGY IN ALASKA3Meeting Agenda•11:30am-11:40am Welcome and Introductions •11:40am-12:00pm REFAC Overview•REF evaluation process•REF eligible projects•REF project funding limits•REFAC advisory role•12:00pm-12:30pm Informational Items•Round XV request for application schedule•Anticipated FY2024 REF fund capitalization•Review of received applications•Review of non-recommended applications•Review of recommended applications•Review of partial funding recommendations•12:30pm-12:45pm Solicitation of advice from committee members concerning Round XV REF application recommendations to the Legislature•12:45pm-1:00pm Member comments / questions•Adjourn REDUCING THE COST OF ENERGY IN ALASKAREFAC Overview4•REF Evaluation Process•REF Eligible Projects•REF Project Funding Limits•REFAC Advisory Role REDUCING THE COST OF ENERGY IN ALASKAREFAC Advisory Committee5NAMETITLE SECTOR APPOINTED BYVACANT VACANT Small rural electric utility Governor (pending)Rose, Chris Founder / Executive Director, RenewableEnergy Alaska Project (REAP)Business/organization involved in renewable energyGovernorVACANT VACANT Representative of an Alaska Native OrganizationGovernor (pending)Amberg, Alicia Member, Denali Commission; Exec Dir, Associated General Contractors of AlaskaDenali Commission GovernorJanorschke, Bradley General Manager, Homer Electric AssociationLarge urban electric utility GovernorStedman, Bert Senator Senate Member 2 Senate PresidentWilson, David Senator Senate Member 1 Senate PresidentCarpenter, Ben Representative House Member 2 Speaker of the HouseCronk, Mike Representative House Member 1 Speaker of the House REDUCING THE COST OF ENERGY IN ALASKAREF Statutory Guidance (AS 42.45.045)Eligible projects must:Be a new project not in operation in 2008, and•be a hydroelectric facility; •direct use of renewable energy resources;•a facility that generates electricity from fuel cells that use hydrogen from renewable energy sources or natural gas (subject to additional conditions); or•be a facility that generates electricity using renewable energy. •natural gas applications must also benefit a community that:•Has a population of 10,000 or less, and•does not have economically viable renewable energy resources it can develop.Evaluation processDevelop a methodology for determining the order of projects that may receive assistance, •most weight being given to projects that serve any area in which the average cost of energy to each resident of the area exceeds the average cost to each resident of other areas of the state, •significant weight given to a statewide balance of grant funds and to the amount of matching funds an applicant is able to make available•The REF evaluation process is comprised of four stages.6 REDUCING THE COST OF ENERGY IN ALASKAREF Evaluation Process: Stage 1 Eligibility and CompletenessThe REF evaluation process is comprised of four stages. Stage 1 is an evaluation of the applicant, project eligibility and, completeness of the application, as per 3 AAC 107.635. This portion of the evaluation process is conducted by AEA staff. •Applicant eligibility is defined as per AS 42.45.045 (l).•“electric utility holding a certificate of public convenience and necessity under AS 42.05, independent power producer, local government, or other governmental utility, including a tribal council and housing authority;”•Project eligibility is defined as per AS 42.45.045 (f)-(h) and is provided on the preceding page.•Project completeness:•An application is complete in that the information provided is sufficiently responsive to the RFA to allow AEA to consider the application in the next stage (Stage 2) of the evaluation. •The application must provide a detailed description of the phase(s) of project proposed.Applications that failed to meet the requirements of Stage 1 were rejected by the authority. Each applicant whose application was rejected was notified of the authority’s decision. 7STAGE 1 CRITERIA PASS/FAILApplicant eligibility, including formal authorization and ownership, site control, and operationPASS/FAILProject Eligibility PASS/FAILComplete application, including Phase description(s)PASS/FAIL REDUCING THE COST OF ENERGY IN ALASKAREF Evaluation Process: Stage 2 Technical and Economic FeasibilityStage 2 is an evaluation concerning technical and economic feasibility. This portion of the evaluation process is conducted by AEA staff, Alaska Department of Natural Resources, and contracted third-party economists. The following items are evaluated as part of the Stage 2evaluation, as required per 3 AAC 107.645:•Project management, development, and operations;•Qualifications and experience of project management team, including on-going maintenance and operation;•Technical feasibility – including but not limited to sustainable current and future availability of renewable resource, site availability and suitability, technical and environmental risks, and reasonableness of proposed energy system; and, •Economic feasibility and benefits – including but not limited to project benefit-cost ratio, project financing plan, and other public benefits owing to the project.All Stage 2 criteria are weighted as follows as part of the evaluation process. Applications that score below 40 points in this stage are automatically rejected by the authority, however, those projects scoring above 40 may also be rejected as under 3 AAC 107.645(b) has the authority to reject applications that it determines to be not technically and economically feasible, or do not provide sufficient public benefit.8CRITERIA CRITERIA DESCRIPTION WEIGHT1 Project management, development, and operation25%2 Qualifications and experience 20%3 Technical feasibility 20%4.a Economic benefit-cost ratio 25%4.b Financing plan 5%4.c Other public benefit 5% REDUCING THE COST OF ENERGY IN ALASKAREF Evaluation Process: Stage 3 Project RankingStage 3 is an evaluation concerning the ranking of eligible projects. This portion of the evaluation process is conducted by AEA staff in conjunction with solicitation from the Renewable Energy Fund Advisory Committee (REFAC) . The following items are evaluated as part of the stage three evaluation, as required per 3 AAC 107.655-660:•Cost of energy•Applicant matching funds•Project feasibility (levelized score from stage 2)•Project readiness•Public benefits (evaluated through stage 2 benefits)•Sustainability•Local Support•Regional Balance•ComplianceAll Stage 3 criteria are weighted as follows as part of the evaluation process. The Stage 3 scoring is used to determine the ranking score. 9CRITERIA CRITERIA DESCRIPTION WEIGHT1 Cost of Energy 30%2 Matching Funds 15%3 Project Feasibility (levelized score from Stage 2)25%4 Project Readiness 5%5 Public Benefits 10%6 Sustainability 10%7 Local Support 5%8 Regional Balance Pass/Fail9 Compliance Pass/Fail REDUCING THE COST OF ENERGY IN ALASKAREF Evaluation Process: Stage 4 Regional SpreadingStage 4 is a final ranking of eligible projects, as required per 3 AAC 107.660, which gives “significant weight to providing a statewide balance of grant money, taking into consideration the amount of money available, number and types of projects within each region, regional rank, and statewide rank.” This portion of the evaluation process is conducted by AEA staff in conjunction with solicitation from the Renewable Energy Fund Advisory Committee (REFAC) . The following items are evaluated as part of the stage four evaluation, as required per 3 AAC 107.660:•Cost of energy burden = [HH cost of electric + HH heat cost] ÷[HH income] – this is used to determine target funding allocation by region – for regional spreadingStage 4 cost of energy burden given below. The below table indicates target funding, as has been allocated, by region, this will be applied to Stage 3 statewide ranking to determine the regionally-spread rank.10 REDUCING THE COST OF ENERGY IN ALASKAREF Round XV funding limits are limited by the requested phase(s) in the application and the technology type applied.Low vs High Cost Energy Areas:•Low Energy Cost Areas are defined as communities with a residential retail electric rate of below $0.20 per kWh, before Power Cost Equalization (PCE) reimbursement is applied. For heat projects, low energy cost areas are communities with natural gas available as a heating fuel to at least 50% of residences, or availability expected by the time the proposed project is constructed.•High Energy Cost Areasare defined as communities with a residential retail electric rate of $0.20 per kWh or higher, before PCE funding is applied. For heat projects, high energy cost areas are communities that do not have natural gas available as a heating fuel.REF Round XV Funding LimitsREF Round XV Grant Funding Limits11 REDUCING THE COST OF ENERGY IN ALASKAREFAC RolesStatutes (AS 42.45.045)•AEA “in consultation with the advisory committee…develop a methodology for determining the order of projects that may receive assistance….”•AEA “shall, at least once each year, solicit from the advisory committee funding recommendations for all grants.”Regulations (3 AAC 107.660)(a) To establish a statewide balance of recommended projects, the authority will provide to the advisory committee established inAS 42.45.045(i) a statewide and regional ranking of all applications recommended for grants.(b) In consultation with the advisory committee established in AS 42.45.045 (i), the authority will(1) make a final prioritized list of all recommended projects, giving significant weight to providing a statewide balance of grant money, and taking into consideration the amount of money that may be available, number and types of projects within each region, regional rank, and statewide rank12 REDUCING THE COST OF ENERGY IN ALASKADATE / ANTICIPATED DATE ACTIONOctober 4, 2022 Request for Applications postedDecember 5, 2022 Application submission deadlineDecember 2022 - March 2023 Evaluation of ApplicationsApril 5, 2023 REFAC MeetingApril 7, 2023 Submission of recommendations to LegislatureJuly 1, 2023 If capital funds are appropriated by the Alaska Legislature – Grants could beginRequest for Applications Schedule – REF Round XV13 REDUCING THE COST OF ENERGY IN ALASKAProposed REF Capitalization for FY2024 / Rd 15The State of Alaska FY2024 proposed capital budget allocates $7.5 million for REF Round 15 grant funding of recommended projects. The current list of 27 recommended applications yields a total grant request of $25.25 million. With the proposed REF budget of $7.5 million, there would be insufficient funding to cover the current Round 15 recommendations. Additional funding of $17.75 million would need to be allocated to fund all of the current Round 15 recommendations or some of the Round 15 recommendations will not be funded. The table to the right indicates historical REF program funding from the inception of the REF program to the proposed $7.5 million for FY2024.$15M was approved in the FY2023 capital budget for REF Round 14, the largest REF capitalization since FY2014.14Fiscal YearLegislative Appropriation /AwardFY2008 $ 100,000,000 FY2009 $ 25,013,014 FY2010 $ 25,000,000 FY2011 $ 26,620,231 FY2012 $ 25,870,659 FY2013 $ 25,000,000 FY2014 $ 22,843,900 FY2015 $ 11,512,659 FY2016 - FY2018 $ -FY2019 $ 11,000,000 FY2020 - FY2021 $ -FY2022 $ 4,750,973 FY2023 $ 15,000,000 FY2024 (proposed) $ 7,500,000 Total (excl. FY2024) $ 292,611,436 Total$ 300,111,436 REDUCING THE COST OF ENERGY IN ALASKAFor REF Round 15, AEA received 31 applications, with a corresponding total grant request of $33.0 million. Round XV – Received Applications Summary15Round 15 Summary of Received Applications - by Energy RegionEnergy Region No. of Applications REF Funding Requested ($)Aleutians 2 4,497,650$ Bristol Bay 5 6,692,378$ Copper River Chugach 1 500,000$ Lower Yukon Kuskokwim 7 3,806,068$ Northwest Arctic 1 1,134,500$ Railbelt 12 9,788,733$ Southeast 2 4,538,526$ Yukon-Koyukuk Upper Tanana 1 2,082,000$ Total 31 33,039,855$ Round 15 Summary of Received Applications - by TechnologyTechnology No. of Applications REF Funding Requested ($)Biomass 1 500,000$ Geothermal 2 113,500$ Heat Recovery 1 1,000,000$ Hydro 6 8,967,570$ Solar 6 8,586,768$ Storage 1 2,172,984$ Wind 14 11,699,033$ Total 31 33,039,855$ $- $2,000,000 $4,000,000 $6,000,000 $8,000,000 $10,000,000 $12,000,000Round 15 Grant Funds Requested by Energy Region $- $2,000,000 $4,000,000 $6,000,000 $8,000,000 $10,000,000 $12,000,000 $14,000,000Biomass Geothermal HeatRecoveryHydro Solar Storage WindRound 15 Grant Funds Requested by Technology REDUCING THE COST OF ENERGY IN ALASKARound XV – Received Applications SummaryThe table to the right indicates the number of applications received by requested phase, along with the corresponding grant request totals. Per the current RFA, there are four phases, listed below in chronological order, for which an applicant may request funding: (1) Reconnaissance(2) Feasibility and Conceptual Design(3) Final Design and Permitting(4) ConstructionSeveral applications received in Round 15 requested funding for more than one phase. 16 $- $2,000,000 $4,000,000 $6,000,000 $8,000,000 $10,000,000 $12,000,000 $14,000,000 $16,000,000Round 15 Grant Funds Requested by Phase REDUCING THE COST OF ENERGY IN ALASKAStage 1 Non-Recommended Applications Summary17In AEA’s Stage 1 evaluation, as per 3 AAC 107.635, it was determined by AEA evaluation staff that 4applications did not meet the eligibility and/or completeness requirements and were rejected. Two applicants appealed their rejections as per 3 AAC 107.650 – “Requests for reconsideration”. Upon AEA’s due consideration and review of the appeals, both rejections were upheld, and final written notices were issued to those applicants.No additional applications were rejected as per 3 AAC 107.645, Stage 2 evaluations.With an initial receipt of 31 applications and 4 being rejected during Stage 1, there are 27 remaining applications which are recommended. With respect to grant funding requests, a total of $3.1 million was rejected in Stage 1. AEA received 31 initial applications. Owing to AEA’s Stage 1 review, 4 applications were rejected, reducing the total grant funds requested by $3.1 million. The remaining 27 applications, totaling a grant request of $29.9 million, were then evaluated according to Stage 2, Stage 3, and Stage 4 criteria. With the current proposed REF fund allocation of $7.5 million for FY2023, there are insufficient REF funds to cover one-hundred percent of the Round 15 requests. Partial funding recommendations, which are discussed further along in the presentation, were made in full consideration of project phases applied for, application scoring, project scope eligibility, and household cost of energy. REDUCING THE COST OF ENERGY IN ALASKAStage 1 Non-Recommended Applications18Below are the 4 identified applications that were rejected during the Stage 1 evaluation:Application Number ApplicantApplication Name Technology Phase CommunityFunds RequestedElection District Rejection Reason15002Nushagak Electric & Telephone CooperativeNuyakuk Hydroelectric Project HydroFeasibility and Conceptual Design Dillingham $1,000,000 37-SProject received maximum funding for requested phase in previous REF Rounds 15015 Beric Alaska EnergyBeric Alaska Energy Solar One SolarReconnaissance; Feasibility and Conceptual Design Railbelt $ 52,500 30-O Application was not signed15019 City of AkiakAkiak Reconnaissance and Wind Assessment Wind; SolarReconnaissance; Feasibility and Conceptual Design Akiak $ 446,500 38-S Application was not signed15030 City of FairbanksPublic Works Solar Panel Array SolarFinal Design and Permitting; Construction Fairbanks $1,600,000 31-P Incomplete application REDUCING THE COST OF ENERGY IN ALASKAThere are 27 recommended applications, totaling a request of $25.25 million. Round XV – Recommended Applications Summary19 $- $1,000,000 $2,000,000 $3,000,000 $4,000,000 $5,000,000 $6,000,000 $7,000,000 $8,000,000Round 15 Grant Funds Recommended by Energy Region $- $1,000,000 $2,000,000 $3,000,000 $4,000,000 $5,000,000 $6,000,000 $7,000,000 $8,000,000Biomass Geothermal HeatRecoveryHydro Solar Storage WindRound 15 Grant Funds Recommended by Technology REDUCING THE COST OF ENERGY IN ALASKARound XV Geographical Distribution of Recommended Applications20 REDUCING THE COST OF ENERGY IN ALASKAAEA Recommended Applications Overview: #1-921Please see related summary report for details concerning the evaluation and description of the individual applications.Recommended ProjectsRecommendationApp. # Applicant Project Title PhaseEnergy RegionElection District Tech CommunityGrant Funds RequestedMatching FundsStage 3 ScoreBenefit / Cost Ratio HECRegional RankState RankFunding LevelFunding Amount15001Native Village of Kluti-KaahWoodchip Heating Project ConstructionCopper River Chugach 36-R BiomassCooper Center $ 500,000 $ 403,400 81.84 1.04 $10,138 1 6 Full $ 500,000 15003Northwest Arctic Borough Selawik Solar PV ConstructionNorthwest Arctic 40-T Solar Selawik $ 1,134,500 $ 251,500 72.86 0.88 $ 8,448 1 15 Full $1,134,500 15004Cook Inlet Region Inc(CIRI) EnergyHealy Renewable Resource AssessmentFeasibility Conceptual Design Railbelt 30-O Wind Healy $ 298,000 $ 54,000 78.36 2.59 $ 9,425 5 11 Full $ 298,000 15005Cook Inlet Region Inc(CIRI) EnergyBeluga Renewable Resource AssessmentFeasibility Conceptual Design Railbelt 37-S Wind Beluga $ 298,000 $ 54,000 79.99 0.91 $13,101 4 9 Full $ 298,000 15006Tanana Chiefs ConferenceHusliaCommunity-Scale Solar PV and Battery ProjectFinal Design,Permitting; ConstructionYukon-Koyukuk Upper Tanana 36-R Solar Huslia $ 2,082,000 $ 110,000 74.77 1.00 $11,090 1 13 Full $2,082,000 15007TDX Adak Generating, LLCHydroelectric Power Adak -Feasibility DesignFeasibility and Conceptual Design Aleutians 37-S Hydro Adak $ 497,650 $ 247,075 91.66 1.26 $12,265 1 1 Full $ 497,650 15008Turnagain Arm Tidal Energy CorpTurnagain Arm Tidal Electricity Generation Project Reconnaissance Railbelt16-H; 15-H; 8-D Hydro Railbelt $ 1,400,000 $ 280,000 56.41 1.07 $ 5,792 10 23Partial w/ Special Provision $ 400,000 15009Matanuska Electric AssociationRailbelt Wind Feasbility Study Conceptual DesignFeasibility and Conceptual Design Railbelt Various Wind Railbelt $ 1,833,333 $ 550,000 73.83 1.10 $ 5,792 7 14 Full $1,833,333 15010City of NapaskiakNapaskiakReconnaissance and Wind AssessmentReconnaissance; Feasibility,Conceptual DesignLower Yukon Kuskokwim 38-S Wind Napaskiak $ 446,500 $ 3,000 53.66 0.33 $10,069 6 26 Partial $ 337,500 REDUCING THE COST OF ENERGY IN ALASKAAEA Recommended Applications Overview: #10-1822Recommended ProjectsRecommendationApp. # Applicant Project Title PhaseEnergy RegionElection District Tech CommunityFunds RequestedMatching FundsStage 3 ScoreBenefit / Cost HECRegional RankState RankFunding LevelFunding Amount15011Naterkaq Light PlantChefornak Battery Installation, Integration, and Commissioning ConstructionLower Yukon Kuskokwim 38-S Wind Chefornak $ 437,000 $ 859,000 78.91 1.72 $ 8,946 2 10 Full $ 437,000 15012Atmautluak Tribal UtilitiesAtmautluak Battery &Thermal Stove Installation, Integration and Commissioning ConstructionLower Yukon Kuskokwim 38-S Wind Atmautluak $ 577,000 $ 81,000 59.18 0.77 $ 9,546 4 21 Full $ 577,000 15013Kipnuk Light PlantKipnuk Battery Installation, Integration and Commissioning ConstructionLower Yukon Kuskokwim 38-S Wind Kipnuk $ 434,000 $ 859,000 80.53 5.00 $ 9,624 1 7 Full $ 434,000 15014 City of ChignikHydroelectric Power SystemFinal Design PermittingBristol Bay 37-S Hydro Chignik $ 802,394 $ 43,767 61.47 0.67 $ 6,780 3 20 Full $ 802,394 15016Alaska Village Electric CoopKalskag Wind Feasibility and Conceptual DesignFeasibility Conceptual DesignLower Yukon Kuskokwim 37-S Wind Kalskag $ 267,300 $ 29,700 72.10 0.30 $ 9,022 3 17 Full $ 267,300 15017Alaska Village Electric CoopNew Stuyahok Solar Energy and Battery Storage ProjectFinal Design and Permitting; ConstructionBristol Bay 37-S SolarNew Stuyahok, Ekwok $ 2,520,000 $ 280,000 64.670.07 $ 9,273 2 19 Full $2,520,000 15018Golden Valley Electric AssociationLIDAR Improvement Interior Wind AssessmentsFeasibility and Conceptual Design Railbelt 36-R Wind Railbelt $ 250,000 $ 125,000 90.78 2.46 $ 9,943 1 2 Full $ 250,000 15020Levelock Village CouncilLevelock Feasibility and Conceptual DesignFeasibility and Conceptual DesignBristol Bay 37-S Wind Levelock $ 197,000 $ 9,000 53.35 0.04 $10,171 4 27Full w/ special provision $ 197,000 15021Alaska Renewables Utility-Scale Railbelt WindFinal Design and Permitting Railbelt30-O; 36-R Wind Railbelt $ 2,000,000 $3,546,500 71.64 0.68 $ 5,791 8 18 Full $2,000,000 Please see related summary report for details concerning the evaluation and description of the individual applications. REDUCING THE COST OF ENERGY IN ALASKAAEA Recommended Applications Overview: #19-2723Please see related summary report for details concerning the evaluation and description of the individual applications.Recommended ProjectsRecommendationApp. # Applicant Project Title PhaseEnergy RegionElection District Tech CommunityGrant Funds RequestedMatching FundsStage 3 ScoreBenefit / Cost Ratio HECRegional RankState RankFunding LevelFunding Amount15022NaknekElectircAssociation Naknek Electric Battery Energy Storage SystemFinal Design Permitting; Construction Bristol Bay 37-S StorageNaknek, S.Naknek, King Salmon $ 2,172,984 $1,950,000 83.47 1.07 $10,532 1 5 Full $2,172,984 15023Alaska Electric & Energy CooperativeCook Inlet Oil Platform Wind ProjectReconnaissance; Feasibility,Conceptual Design Railbelt 8-D WindHEA Serving Area $ 214,400 $ 97,448 77.64 1.15 $ 7,523 6 12 Full $ 214,400 15024Alaska Electric & Energy Coop, Augustine Island GeothermalFeasibility and Conceptual Design Railbelt 37-SGeothermal Railbelt $ 68,000 $ 42,140 87.76 1.83 $ 7,523 3 4 Full $ 68,000 15025Alaska Electric & Energy Coop, Mount SpurrGeothermalFeasibility and Conceptual Design Railbelt 37-SGeothermal Railbelt $ 45,500 $ 30,940 88.06 1.83 $ 7,523 2 3 Full $ 42,500 15026Yakutat Health CenterYakutat Community Health Center Heat Recovery ProjectFinal Design,Permitting; Construction Southeast 2-AHeat Recovery Yakutat $ 1,000,000 $ 273,000 72.19 1.24 $ 7,957 2 16Full w/ special provision $1,000,000 15027TuntutuliakCommunity AssociationCommunity Services Association Solar Energy ProjectFinal Design,Permitting; ConstructionLower Yukon Kuskokwim 38-S Solar Tuntutuliak $ 1,197,768 $ 14,000 55.57 0.00 $10,426 5 24Full w/ special provision $1,197,768 15028Inside Passage Electric CoopWater Supply Creek Hydro Construction Construction Southeast 2-A Hydro Hoonah $ 3,538,526 $6,853,474 80.42 0.38 $ 9,663 1 8 Full $3,538,526 15029Chugach Electric AssociationGodwin Creek Hydroelectric ProjectFeasibility and Conceptual Design Railbelt 5-C HydroCEA Serving Area $ 1,729,000 $ 306,117 58.530.40 $ 3,613 9 22 Full $1,729,000 15031City of UnalaskaCity of Unalaska Wind Power Design/ConstructionFinal Design Permitting; Construction Aleutians 37-S Wind Unalaska $ 4,000,000 $8,790,000 54.05 0.90 $ 8,418 2 25 Partial $ 420,000 REDUCING THE COST OF ENERGY IN ALASKARound XV –Partial Funding RecommendationsAs part of the evaluation process and pursuant to 3 AAC 170.655(b), 3 applications, as provided below, have been recommended for partial funding. If these partial funding recommendations are reversed and full funding recommended, this would raise the total grant request amount for all remaining 27 recommended applications to $29.9 million. Reasoning for recommendations of partial funding are provided on the following page. Partial funding recommendations have been made in full consideration of additional due diligence and information needed from preliminary project phases prior to funding for final design and/or construction; eligibility of items comprising project scope; and statewide balance of grant money, taking into consideration the amount of money available, number and types of projects within each region, regional rank, and statewide rank (as per 3 AAC 107.660).24Application NumberApplicant Name Project Title Project PhaseEnergy RegionElection District TechGrant Funds RequestedMatching FundsMatch TypeStage 3 ScoreBenefit/Cost RatioHousehold Energy Cost Regional RankStatewide RankRecommended Funding Amount15008Turnagain Arm Tidal Energy CorpTurnagain Arm Tidal Electricity Generation Reconnaissance Railbelt16-H; 15-H; 8-D Hydro $1,400,000 $ 280,000 In Kind 60.35 1.07 $7,504 10 23 $ 400,000 15010City of NapaskiakNapaskiak Reconnaissance and Wind Assessment ReconnaissanceLower Yukon Kuskokwim 38-S Wind$ 446,500 $ 3,000 In Kind 52.85 0.33 $9,709 6 26 $ 337,500 15031City of UnalaskaCity of Unalaska Wind Power Design/ConstructionFinal Design and Permitting; Construction Aleutians 37-S Wind $4,000,000 $8,790,000 Cash 51.56 0.9 $7,315 2 25 $ 420,000 REDUCING THE COST OF ENERGY IN ALASKARound XV –Partial Funding Reasoning25Application Number Applicant Name Project Title Partial Funding Reasoning15008Turnagain Arm Tidal Energy CorpTurnagain Arm Tidal Electricity Generation The requested funding amount was to fund two studies, one study for regulatory requirements and permitting and one study for bathymetry for the site. AEA recommends funding only the study for regulatory requirements and permitting in Round 15. Reconnaissance studies are a desktop study and the analysis should use resource, economic, and operational data that is readily and/or publicly available. There are also many stakeholders on a project such as TATEG, and it is imperative for project planners to conduct extensive stakeholder outreach prior to any feasibility study work, such as bathymetric mapping, to determine the extent of stakeholder approval. Additionally, the TATEG project’s permitting and regulatory requirements must be known before the project team can sufficiently define the scope of work, and subsequently estimate the project cost and schedule.15010 City of NapaskiakNapaskiak Reconnaissance and Wind AssessmentCosts proposed for equipment and monitoring in the application appear high when compared to similar projects. AEA recommends partial funding for the met tower to bring the cost in line with similar projects; requested funding for this line item was $194k and AEA recommends $97k. AEA recommends partial funding for monitoring costs; requested funding for this line item was $2,000 a month and AEA recommends $1,000.15031 City of UnalaskaCity of Unalaska Wind Power Design/ConstructionThe requested phases were Final Design & Permitting and Construction. AEA recommends funding only the Final Design & Permitting Phase in Round 15. Partial funding will allow for more refined cost estimates for the Construction Phase in future REF rounds, as well as, provides additional time to determine if other energy projects will be moving forward in the region. REDUCING THE COST OF ENERGY IN ALASKASolicitation of Advice from REFACAs statutorily required per AS 42.45.045 and set forth in 3 AAC 107.660, the authority is to solicit advice from the REFAC concerning making a final list / ranking of eligible projects, which gives “significant weight to providing a statewide balance of grant money, taking into consideration the amount of money available, number and types of projects within each region, regional rank, and statewide rank.” This finalized list will be provided to the legislature for recommendation in accordance with AS 42.45.045(d)(3). Any grant awards are subject to legislative approval and appropriation.The right-hand table is provided to assess the “regional spreading” of REF funding. As indicated, both the Railbelt and the Southeast energy regions currently exceed 200% of their target allocation based on their cost of energy burden. Bristol Bay and Yukon-Koyukuk/Upper Tanana energy regions are the remaining regions where the allocation, based on the cost of energy burden, has not met 50% of their potential allocation, categorizing these regions as “under-served”. The authority solicits advice from the REFAC relating to any recommendations in changes to funding level, ranking, and/or total amount of funding and number of projects. 26 REDUCING THE COST OF ENERGY IN ALASKAMember comments27 REDUCING THE COST OF ENERGY IN ALASKA28SAFE, RELIABLE, & AFFORDABLE ENERGY SOLUTIONSALASKA ENERGY AUTHORITY813 West Northern Lights Blvd.Anchorage, Alaska 99503Phone: (907) 771‐3000Fax: (907) 771‐3044Toll Free (Alaska Only) 888‐300‐8534 Makushin Geothermal Project Site Visit March 28-30, 2023 “Man Camp Group Photo” “Makushin Valley” “Curtis in Helicopter near proposed site.” “Trident Site” Page 1 of 2 Legislative Requests Date Request Who Assigned to Date answered 3/31/2023 Power Cost Equaliztion (PCE) – SB98 questions Tim from Senator Hoffman’s Office Curtis 3/31/2023 (by phone) 3/30/2023 Inquiries of Tesla EV Warranties Representative Sarah Vance Curtis / Audrey 3/21/2023 REF Project List inquiry Representative Zack Fields Curtis / Conner 3/24/2023 (email) 3/20/2023 AEA – PCE Inquiry Dawson Verley – Representative Armstrong’s Office Curtis / Tim 3/20/2023 (email) 3/20/2023 Hydroelectric budget appropriation – Dixon and Godwin Cody Grussendorf - Senator Click Bishop’s Office Curtis / Bryan 3/20/2023 (email) 3/16/2023 Banner Peak Wind Farm kilowatt per hour cost House Finance Committee Curtis / Karen/ Josi 3/14/2023 HB62 Renewable Energy Grant Fund – Rep Ortiz follow up on personnel Laib Allensworth – on behalf of Representative Ortiz Curtis 3/15/2023 (email) 3/13/2023 HB62 Renewable Energy Grant Fund – Rep Cronk, Rep Stapp and Rep Edgmon Laib Allensworth – Representative Edgmon’s Office Curtis / Conner 3/14/2023 (email) 3/9/2023 Renewable Energy Fund balance Edra Morledge – Representative Coulombe’s Office Curtis/Conner 3/15/2023 (email) 3/8/2023 Bulk Fuel Upgrade / Power Project questions from Senator Click Bishop Senator Click Bishop’s Office (Cody Grussendorf) Curtis / Tim 3/10/2023 (email) 3/7/2023 AEA Vacancies Senator Hoffman Curtis / Megan 3/14/2023 (email) 3/6/2023 Renewable Energy or Alternative Energy Inventory / opportunities Representative Dan Saddler Curtis / Audrey 3/8/2023 (email) 3/2/2023 Questions from meeting with Senator Stedman in Juneau on 3/2/23 Senator Stedman Curtis / Tim 3/8/2023 (email) Page 2 of 2 2/16/2023 Bristol Bay Communities considered for Renewable Energy Grants Dillingham Legislative information Office (Valerie Burgess) Conner / Curtis 2/16/2023 (email) 2/13/2023 SB33 – Renewable Energy Grant Fund – follow up questions Emma Torkelson – Senator Kaufman’s Office Conner 2/13/2023 (email) 2/10/2023 City of Pelican – increase in cost of Hydro Mayor of Pelican / Rep Himschoot / Senator Stedman / John Espindola Curtis / Tim 2/14/2023 (email) 2/6/2023 SB33 – Renewable Energy Grant Fund – REF Projects by Region and REF Fact Sheet Emma Torkelson – Senator Kaufman’s Office Conner 2/8/2023 (email) 2/6/2023 PCE Electrical Data - follow up Senator Bert Stedman office (Rose Foley) Tim 2/6/2023 (email) 1/27/2023 Community of Pelican – power challenges Thatcher Brown – Representative Himschoot’s office Tim 1/27/2023 (email) 1/26/2023 Su-Wa Historical Funding (2009 forward) House Energy Committee Pam Ellis 2/3/2023 (email) 1/25/2023 DOR on PCE re: Senate Finance Committee questions Senate Finance Committee through DOR Curtis 1/26/2023 (email) April 5, 2023 (Wednesday) Legislative Meeting in Juneau Time Curtis /Tim Senator /Representative / Other Committee Location Phone 8:30 am Curtis/Tim Representative Josephson House Finance Room 432 907-465-4939 8:30 am Curtis / Tim Representative Calvin Schrage House Energy Room 404 907-465-4931 9:30 am Curtis / Tim Representative Frank Tomaszewski House Finance Room 501 907-465-4457 9:30 am Curtis / Tim Representative Sara Hannan House Finance Room 400 907-465-4766 10:00 am Curtis / Tim Representative Stanley Wright House Energy Room 412 907-465-2095 10:00 am Curtis / Tim Representative Dan Ortiz House Finance Room 500 907-465-3824 10:30 am Curtis / Tim Representative Will Stapp House Finance Room 513 907-465-3004 11:30 am- 1:00 pm Curtis and Tim Renewable Energy Fund Advisory Committee REFAC Teams Link or Call in 1:00 pm Curtis / Tim Representative Mike Cronk House Finance Room 418 907-465-4527 1:30 pm Curtis / Tim Speaker Cathy Tilton Speaker Room 208 907-465-2199 2:00 pm Curtis / Tim Representative Mike Prax House Energy Room 108 907-465-4797 2:30 pm Curtis / Tim Senator Bill Wielchowski Senate Resources Room 103 907-465-2435 2:30 pm Curtis / Tim Senator Scott Kawaski (may be w/ staff) Senate Resources Room 119 907-465-3466 3:00 pm 3:30 pm – 4:30 pm Senate Resource Committee – Senator Click Bishop (Presentation) Senate Resource 4:30 pm Curtis / Tim Representative Alyse Galvin House Finance Room 405 907-465-3875 Cancelled March 20, 2023 (Monday) Legislative Meeting in Juneau Time Senator /Representative / Other Committee Location Phone 2:00 pm Speaker Cathy Tilton Speaker Room 208 907-465-2199 2:30 pm Meeting with Governor’s Office N/A Gov’s Office 4:00 pm Senator Kelly Merrick Senate Finance Room 510 907-465-3777 6:00 pm Legislative Dinner March 21, 2023 (Tuesday) Legislative Meetings in Juneau Time Senator /Representative / Other Committee Location Phone 10:15 am- 11:15 am House Energy Committee – AEA Overview Presentation House Energy Capitol Room 124 11:30 am Representative Julie Coulombe House Finance Room 502 907-465-3879 12:00 pm DEPART TO AIRPORT Thursday March 9, 2023 Legislative Meetings in Juneau Time Senator /Representative/Other Committee Location Phone # 11:00 – 12:00 pm Commissioner Sande Economic Sub Cabinet meeting Teams Meeting or call in # 907-202-7104. Code 794-563-956# 11:45 – 12:30 FY24 Capital Budget / CASR Meeting Legislative Office Building Room Legislative Office Building Room 103 12:30 – 1:30 pm LUNCH LUNCH 1:30 HB62, REF *** House Finance Adams 519 2:00 – 2:30 PM Senator Lyman Hoffman Senate Finance Co-Chair Room 516 907-465-4453 3:00 – 3:30 PM Rep George Rauscher House Resources Room 409 907-465-4859 3:30 -4:00 pm Rep Bryce Edgmon House Finance Co-Chair Room 410 800-898-4451 4:30 -5:00 PM Senator Olson Senate Finance Co Chair Room 508 907-465-3707 5:30 -6:00 PM Senator Jesse Kiehl Senate Finance Room 514 907-465-4947 *** Conner will be calling into HB62, REF, House Finance Committee Hearing as well. Cancelled Cancelled Cancelled Thursday, March 2, 2023 Legislative Meetings in Juneau Time Senator / Representative Committee Location Phone # 8:00 -8:30 am Senator Giessel Senate Resource Co chair Room 427 907-465-4843 9:00 -9:30 am Senator Kaufman Senate Resources Room 115 907-465-4949 9:45 - 10:15 am Rep. DeLena Johnson House Finance Co-Chair Room 505 907-465-4958 10:30 - 11:00 am Rep Bryce Edgmon House Finance Co-Chair Room 410 800-898-4451 10:30 – 11:00 Representative Foster’s Office House Finance co-Chair Room 511 907-465-3542 12:00-12:30 Representative Tom McKay House Resource Chair Room 128 907-465-4993 12:30 - 2:15 pm 2:15 - 2:45 pm Senator David Wilson Senate Finance Room 121 907-465-3878 3:00 - 3:30 pm Senator Bert Stedman Senate Finance Co-Chair Room 518 907-465-3873 4:00 - 4:30 pm Senator Donald Olson (per his office, please come prepared to talk about PCE) Senate Finance Co-Chair Room 508 907-465-3707 5:00 -5:30 pm Representative McCabe House Resources Room 102 907-465-2679 MODERNIZING ALASKA’S LARGEST ELECTRIC SYSTEM Curtis W. Thayer, Executive Director Bryan Carey, PE, Director of Owned Assets Senate Resources Committee April 5, 2023 ALASKA ENERGY AUTHORITY Railbelt Energy –AEA owns the Bradley Lake Hydroelectric Project, the Alaska Intertie, and the Sterling to Quartz Creek Transmission Line —all of which benefit Railbelt consumers by reducing the cost of power. Power Cost Equalization (PCE) –PCE reduces the cost of electricity in rural Alaska for residential customers and community facilities, which helps ensure the sustainability of centralized power. Rural Energy –AEA constructs bulk fuel tank farms, diesel powerhouses, and electrical distribution grids in rural villages. AEA supports the operation of these facilities through circuit rider and emergency response programs. Renewable Energy and Energy Efficiency –AEA provides funding, technical assistance, and analysis on alternative energy technologies to benefit Alaskans. These include biomass, hydro, solar, wind, and others. Grants and Loans –AEA provides loans to local utilities, local governments, and independent power producers for the construction or upgrade of power generation and other energy facilities. Energy Planning –In collaboration with local and regional partners, AEA provides economic and engineering analysis to plan the development of cost-effective energy infrastructure. About AEA AEA’s mission is to reduce the cost of energy in Alaska. To achieve this mission, AEA strives to diversify Alaska's energy portfolio — increasing resiliency, reliability, and redundancy. AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 02 AEA Active Projects and Services AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 03 Foundation of a Dependable Transmission System Resiliency Grid resiliency is defined as the ability to withstand, manage, and respond quickly to disruptions such as severe weather events, equipment failures, or cyberattacks. Reliability Reliability defines standards and system performance such that the system is designed to withstand sudden events. Redundancy An important aspect of grid resiliency and reliability, redundancy is the existence of more than one means for performing a given function. AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 04 Soldotna Homer Seward Owned by AEA, the Bradley Lake Hydroelectric Project was energized in 1991 and is Alaska’s largest source of renewable energy. Location –The project is located 27‐air miles northeast of Homer on the Kenai Peninsula. Benefits –Provides low cost energy to 550,000+ members of Chugach Electric Association, Golden Valley Electric Association, Homer Electric Association, Matanuska Electric Association, and the City of Seward. Annual Energy Production –~10% of Railbelt electricity at 4.5 cents/kWh (or ~54,400 homes/year) and over $16 million in savings per year to Railbelt utilities from Bradley Lake versus natural gas. Status –In 2020, AEA completed the West Fork Upper Battle Creek Diversion project, which increased Bradley Lake’s annual energy production by about 10%. Dam Height –125 feet Dam Elevation –1,190 Feet Reservoir Length –4 miles Reservoir Width –1.3 miles Installed Capacity –120 MW Annual Energy –400,000 MWh Cost –~$400 Million Bradley Lake Hydroelectric Project AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 05 BPMC BPMC The Bradley Lake Hydroelectric Project is owned by AEA and managed by the Bradley Lake Project Management Committee (BPMC), which is comprised of a member from each of the five participating Railbelt utilities: Chugach Electric Association, Golden Valley Electric Association, Homer Electric Association, Matanuska Electric Association, and City of Seward. (56.3%)(1.0%) (16.9%)(13.8%) (12.0%) 06 Installed Capacity –≤ 180 MW Annual Energy –100,000- 500,000 MWh Cost –~$160-500 Million The proposed Dixon Diversion Project would increase energy from Bradley Lake Hydroelectric Project potentially up to 50%. Location –The Dixon Diversion Project is located five miles southwest of Bradley Lake Components – -Diversion dam and intake below Dixon Glacier -Five mile tunnel to Bradley Lake -Raise dam elevation to store more water for critical periods Benefits –Could provide annual electric energy for up to 28,000 homes on the Railbelt. (Bradley Lake Hydroelectric Project: 54,000 homes) Status –Feasibility (verifying energy and cost) Dixon Diversion Project Capital Request: General Fund -$5 Million 07 Possible Economic Feasibility $0 $50 $100 $150 $200 $250 AEA Chugach/NERA Scenario 2 Scenario 350-Year Levelized Cost of Energy ($/MWh)LCOE of Dixon Economic Evaluations Compared to Possible Chugach Short-Run Avoided Costs Dixon Economic Evaluations Chugach Avoided Cost ($18 gas, 2.5% escalation) Chugach Avoided Cost ($12 gas, 2.5% escalation) Chugach Avoided Cost (2.5% annual escalation) The Dixon Diversion economic evaluations indicate a levelized cost of energy (LCOE) that is competitive with some of the possible future Chugach short-run avoided cost 50-year LCOEs, depending upon the future cost of natural gas. This indicates that further feasibility assessment is warranted to refine the projected cost and energy production estimates until or unless a determination is made that the project is not economically viable. AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 08 Energy Generation Comparison - 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 Daily Acre-Feet of WaterModeled Dixon Diversion Annual Water FlowsProjectMWh/yr Bradley Lake Hydro ~400,000 MWh/yr Dixon Diversion ~160,000 MWh/yr Fire Island Wind ~49,000 MWh/yr Battle Creek Diversion ~37,000 MWh/yr Net Metered Solar ~3,500 MWh/yr AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 09 BRADLEY LAKE REQUIRED PROJECT WORK 10 Installed Capacity –≤ 180 MW Annual Energy –100,000- 500,000 MWh Cost –~$160-500 Million In 2020, AEA acquired the SSQ Transmission Line a critical component of the interconnected Railbelt transmission system located on the Kenai Peninsula, as part of the Bradley Lake Hydroelectric Project. Location –39.4 miles of 115 kilovolt (kV) transmission and out of use 69 kV transmission from Sterling to Quartz substation (Kenai Lake) Benefits –AEA ownership ensures better cost alignment, increase reliability, and more timely repairs and upgrades. Status –Removal of decommissioned 69 kV line on SSQ. Engineers are designing the upgrade of the existing 115 kV line to 230 kV to reduce line losses, increase line reliability and system resiliency. Cost –Estimated cost to upgrade line to 230 kV standards is $62 million. Sterling to Quartz (SSQ) Transmission Line 11 Project Name Scope Schedule Budget Upgrade Transmission Line from Bradley to Soldotna Upgrade of the transmission line between the Bradley Substation and Soldotna Substation from with additional 115 kV line or convert to 230 kV By 2033* Upgrade Transmission Line from Soldotna to Sterling Upgrade of the transmission line from 115 kV to 230 kV from the Soldotna Substation to the Sterling Substation By 2030* Upgrade Transmission Line from Sterling to Quartz Creek Upgrade of the transmission line between the Sterling Substation and Quartz Creek Substation (SSQ Line) from 115 kV to 230 kV By 2028* Battery Energy Storage Systems (BESS) for Grid Stabilization Upgrade to existing BESS system in Homer, and also new BESS systems in the Central, and Northern regions of the grid By 2025* Required Project Work Summary *Subject to supply chain logistics and permitting. Total $379 Million* AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 12 BPMC Required Project Work Upgrade Transmission Line from Bradley Lake to Soldotna Scope –This project will allow for increased power flow from the Bradley Project through the upgrade of this 67.8 mile segment to 230 kilovolt (kV) or a second 115 kV transmission line from the Bradley Lake power plant to the Soldotna Substation. This transmission line will become part of the Bradley Lake Hydroelectric Project. Schedule –Estimated completion date is 2033 Budget –Estimated cost is $96 million Benefits –Reduce energy losses and increase resiliency to unplanned events AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 14 Upgrade Transmission Line from Soldotna to Sterling Scope –This project will allow for increased power flow and reduced line losses from the Bradley Project through the construction of an upgrade of the transmission line from 115 kilovolt (kV) to 230 kV from the Soldotna Substation to the Sterling Substation. The SSQ Line (as well as the transmission line between the Sterling Substation and Quartz Creek Substation) are the sections of the Bradley Project to Anchorage interconnection that incur the most significant energy losses. This additional transmission capacity will become part of the Bradley Project. Schedule –Estimated completion date is 2030 Budget –Estimated cost is $27 million Benefits –Reduce energy losses and increase resiliency to unplanned events AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 15 Upgrade Transmission Line from Sterling to Quartz Creek Scope –This project involves the upgrade of the 39 miles of transmission line between the Sterling Substation and Quartz Creek Substation (SSQ Line) from 115 kilovolt (kV) to 230 kV. The SSQ Line is part of the Bradley Project. All property rights and obligations in the SSQ Line were purchased by AEA in 2020 and made part of the Bradley Project. Bradley Lake output is significantly reduced as it transitions these line sections. Schedule –Estimated completion date by 2028 Budget –Estimated cost is $62 million Benefits –Reduce energy losses and increase resiliency to unplanned events AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 16 Battery Energy Storage Systems for Grid Stabilization Scope –The BESS projects consist of an upgrade to the existing BESS system in North, and also new BESS systems in the Southern, and Central regions of the grid. The Northern BESS is located at Fairbanks, the Southern BESS is located in Kenai, the Central Region BESS will be located at Anchorage. BESS will be needed to fully realize the benefits of a 230 kV bulk power supply system, regulate energy from various generation, and increase resilience. Schedule –Estimated completion date is 2025 Budget –Estimated cost is up to $194 million (depending on technology choices and capacity) Benefits –Increase system resilience, transfer capability, more efficient use of system and lowering impediments to additional renewable generation development Fairbanks AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 17 ALASKA INTERTIE 18 Alaska Intertie AEA owns the 170-mile Alaska Intertie transmission line that runs between Willow and Healy. The line operates at 138 kV (it was designed to operate at 345 kV) and includes 850 structures. A vital section of the Railbelt transmission system, the Intertie is the only link for transferring power between northern and southern utilities. The Intertie transmits power north into the Golden Valley Electric Association (GVEA)system and provides Interior customers with low-cost, reliable power —between 2008 and 2021, the Intertie saved GVEA customers an average of $37 million annually. The Intertie provides benefits to Southcentral customers as well through cost savings and resilience to unexpected events. Constructed in the mid‐1980s with $124 million in State of Alaska appropriations, there is no debt associated with the Alaska Intertie. AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 19 Alaska Intertie 20 MODERNIZING THE RAILBELT GRID 21 Railbelt Transmission System Urgently Needs Modernization Grid Forming A grid with alternate paths will increase reliability, resiliency, and fuel diversification. Fuel Savings Upgrades and alternate paths will reduce line losses. Energy Security Natural or other events can isolate cities or regions from energy. The majority of the Railbelt transmission system was constructed 40 years ago (older than average age of population). A resilient and redundant Railbelt transmission system is not only achievable but also necessary to create the needed capacity to integrate additional renewable energy in the future. Generation Changes New renewable energy projects are not located in existing cities. New transmission to connect new renewable projects to existing transmission paid for by projects. However, existing transmission must be upgraded to transmit energy to and between the Railbelt regions. AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 22 AEA and the Railbelt utilities submitted for the following IIJA: Grid Resilience and Innovation Partnerships (GRIP) competitive grants: GRIP Application Topic 1 –Application for upgrading existing transmission Bradley Lake to Susitna Valley. Request: $100 million; Required Match: $100 million GRIP Application Topic 2 –Application for Battery Energy Storage System/High Voltage Direct Current coordinated control system. Would coordinate actions of batteries in the South (Kenai), Central (Anchorage, and North (Fairbanks). Request: $15 million; Required Match: $15 million GRIP Application Topic 3 –Application for transmission upgrades to connect Kenai (new submersible line), northern (Susitna Valley Line), and Copper Valley with central and northern. Request: $299 million; Required Match: $299 million Infrastructure Investment and Jobs Act (IIJA) Railbelt Transmission Funding Opportunities 23 C C C Upgrades to Railbelt transmission line are needed to increase resiliency, reliability, and redundancy, and decrease line losses. Modernization Work Phases Work Phase 1 –Upgrade existing southern transmission backbone first which will reduce losses from Bradley Lake and allow new Renewable Energy Projects. Work Phase 2 –New lines to add reliability, resilience, and redundancy. Additional time for upfront activities required. Battery Energy Storage System (BESS)/High Voltage Direct Current Controls (HDVC) –Increase resilience, transfer capability, and efficient use of electrical system. 2 1 24 C These federal formula grant funds will provide $60 million to Alaska over five years, including $22.2 Million for the first two years allocation, to catalyze projects that increase grid resilience against disruptive events. Resilience measures include but are not limited to: -Relocating or reconductoring powerlines -Improvements to make the grid resistant to extreme weather -Increasing fire resistant components -Integrating distributed energy resources like microgrids and energy storage Formula-based funding requires a 15% state match and a 33% small utility match. Statewide Grid Resilience and Reliability IIJA Formula Grant Program, 40101(d) Per IIJA section 40101(a)(1),8 a disruptive event is defined as “an event in which operations of the electric grid are disrupted, preventively shut off, or cannot operate safely due to extreme weather, wildfire, or a natural disaster.” 25 Susitna -Watana Hydroelectric Project 26 Susitna-Watana At-A -Glance The proposed Susitna-Watana Hydroelectric Project is a large hydro project that would provide long-term stable power for generations of Alaskans. The project would result in approximately 70% of the power generated in the Railbelt originating from renewable sources, up from the current 15% —a nearly four-fold increase. Dam Height –705 feet Dam Elevation –2,065 Feet Reservoir Length –~42 miles Reservoir Width –~1.25 miles Installed Capacity –618 MW Annual Energy –2,800,000 MWh Cost –~$5.6 billion (2014$) AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 27 percent estimated supply of current Railbelt energy demand 50 100+ years is the project life providing long- term, stable rates billion estimated energy cost savings ($2014) over first 50 years $11.2 CO The reduction of carbon dioxide emissions from displaced coal and natural gas-fired generation would amount to 1.3 million tons a year, which equates to removing approximately 250,000 cars from the road.2 Why Susitna-Watana? AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 28 2019 Abeyance Rescinded 2017 Licensing Abeyance Susitna-Watana History AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 29 Susitna-Watana Employment Opportunities Pre-Construction Employment ~5,000 direct jobs ~3,870 indirect jobs Construction Employment ~12,000 direct jobs ~11,305 indirect jobs Operations Employment (Life of Project) ~24-28 direct jobs ~105 indirect jobs 32,308 Total Jobs 17,028 Direct jobs 15,280 Indirect jobs AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 30 Susitna-Watana Timeline AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 31 813 W Northern Lights Blvd. Anchorage, AK 99503 Main: (907) 771-3000 Fax: (907) 771-3044 akenergyauthority.org @alaskaenergyauthority @alaskaenergyauthority Alaska Energy Authority AEA provides energy solutions to meet the unique needs and opportunities of Alaska’s rural and urban communities. APPENDIX 33 Bradley Lake Required Project Work Definition “…repairs, maintenance, renewals, replacements, improvements or betterments required by federal or state law, a licensing or regulatory agency with jurisdiction over the [Bradley] Project, or this Agreement, or otherwise necessary to keep the [Bradley] Project in good and efficient operating condition, consistent with (1) sound economics for the [Bradley] Project and the Purchasers and (2) national standards for the industry.” Required Project Work is defined in the Power Sales Agreement (PSA) to mean: In other words, for the proposed projects to be considered “Required Work” under the PSA, the work must be intended to keep the project in good and efficient operating condition. The measures of this work must: (1) be based on sound economics for the Project and the Purchasers, and (2) be consistent with national standards for the industry. AEA Modernizing Alaska’s Largest Electric System | Senate Resources Committee | April 5, 2023 34 AEA OVERVIEW PRESENTATION Curtis W. Thayer Executive Director House Energy Committee March 21, 2023 ALASKA ENERGY AUTHORITY Who We Are Created in 1976 by the Alaska State Legislature, the Alaska Energy Authority (AEA) is a public corporation of the State of Alaska governed by a board of directors with the mission to “reduce the cost of energy in Alaska.” AEA is the state's energy office and lead agency for statewide energy policy and program development. Our Mission Reduce the cost of energy in Alaska. AEA Overview Presentation | House Energy Committee | March 21, 2023 02 Railbelt Energy –AEA owns the Bradley Lake Hydroelectric Project, the Alaska Intertie, and the Sterling to Quartz Creek Transmission Line —all of which benefit Railbelt consumers by reducing the cost of power. Power Cost Equalization (PCE) –PCE reduces the cost of electricity in rural Alaska for residential customers and community facilities, which helps ensure the sustainability of centralized power. Rural Energy –AEA constructs bulk fuel tank farms, diesel powerhouses, and electrical distribution grids in rural villages. AEA supports the operation of these facilities through circuit rider and emergency response programs. Renewable Energy and Energy Efficiency –AEA provides funding, technical assistance, and analysis on alternative energy technologies to benefit Alaskans. These include biomass, hydro, solar, wind, and others. Grants and Loans –AEA provides loans to local utilities, local governments, and independent power producers for the construction or upgrade of power generation and other energy facilities. Energy Planning –In collaboration with local and regional partners, AEA provides economic and engineering analysis to plan the development of cost-effective energy infrastructure. What We Do AEA’s mission is to reduce the cost of energy in Alaska. To achieve this mission, AEA strives to diversify Alaska's energy portfolio to increase reliability, resiliency, and redundancy. AEA Overview Presentation | House Energy Committee | March 21, 2023 03 Active Projects and Services AEA Overview Presentation | House Energy Committee | March 21, 2023 04 URBAN ENERGY 05 Bradley Lake is Alaska’s largest source of renewable energy. Energized in 1991, the project is situated 27‐air miles northeast of Homer on the Kenai Peninsula. The 120 MW facility provides low-cost energy to 550,000+ members on the Railbelt. Bradley Lake’s annual energy production is ~10% of Railbelt electricity at 4.5 cents/kWh (or ~54,400 homes/year) and over $20 million in savings per year to Railbelt utilities from Bradley Lake versus natural gas. AEA, in partnership with the Railbelt utilities, is studying the Dixon Diversion Project which would increase the annual energy production of Bradley Lake by 50% —or the equivalent of 14,000-28,000 homes. Bradley Lake Hydroelectric Project 06 BPMC BPMC The Bradley Lake Hydroelectric Project is owned by AEA and managed by the Bradley Lake Project Management Committee (BPMC), which is comprised of a member from each of the five participating Railbelt utilities: Chugach Electric Association, Golden Valley Electric Association, Homer Electric Association, Matanuska Electric Association, and Seward Electric System. (56.3%)(1.0%) (16.9%)(13.8%) (12.0%) 07 Transmission Upgrades and Battery Storage AEA and the Railbelt utilities closed on $166 million in bond financing to improve the efficiency and deliverable capacity of power from the Bradley Lake Hydroelectric Project. The bonding comes at no additional cost to ratepayers or burden on the State treasury. Upgrade transmission line between Bradley Lake and Soldotna Substation Upgrade transmission line between Soldotna Substation and Sterling Substation Upgrade transmission line between Sterling Substation and Quartz Creek Substation Battery Energy Storage Systems for Grid Stabilization These projects will reduce constraints on the Railbelt by improving the Kenai Peninsula’s transmission capacity to export power from Bradley Lake —and allow for the integration of additional renewable energy generation. 08 Railbelt Upgrades 09 Completed in 1986, the Alaska Intertie is a 170 mile-long, 345 kilovolt (kV) transmission line from Willow to Healy and operates at 138 kV. Owned by AEA and operated by the Railbelt utilities,the Intertie transmission line improves reliability. The Intertie allows Golden Valley Electric Association (GVEA) to connect to and benefit from lower cost power. Between 2008 and 2021, the Intertie provided an average annual cost savings of $37 million to GVEA customers. Alaska Intertie 10 RURAL ENERGY 11 St. George Island, Pribilof Islands, AK Power Cost Equalization (PCE) AEA, along with the Regulatory Commission of Alaska, administers the PCE program, which serves remote communities that are largely reliant on diesel fuel for power generation. AEA Overview Presentation | House Energy Committee | March 21, 2023 12 193 91 82,000 Who is Eligible to Participate in PCE? PCE eligibility is determined by the Regulatory Commission of Alaska in accordance with Alaska Statutes 42.45.100-170. Eligible customers include: Residential and community facilities (water, sewer, public lighting, and clinics, etc.) Non-eligible customers include: State and federal facilities and commercial customers Any community with rates lower than the urban average (the PCE floor) AEA Overview Presentation | House Energy Committee | March 21, 2023 13 Rural Power System Upgrades BeforeAfter14 ~197 communities eligible for Rural Power System Upgrade Goal —improve power system efficiency, safety, and reliability Aging infrastructure and Operation and Maintenance Active projects —7 full and 16 Maintenance and Improvement/Diesel Emissions Reduction Act Deferred maintenance is $300 million Capital Request: State Match –$7.5 Million Federal Receipt Authority –$25 Million ~400 rural bulk fuel facilities Goal —code compliant fuel storage facilities and prevention of spills and contamination Aging infrastructure, erosion, and catastrophic failure Active projects —8 full and 18 Maintenance and Improvement; no funding for two years Leveraging Coast Guard regulatory efforts to capture BFU assessments to prioritize projects Deferred maintenance is $800 million Bulk Fuel UpgradesBefore After15 Capital Request: State Match –$5.5 Million Federal Receipt Authority –$7.5 Million FINANCING TOOLS 16 The PPF loan program qualifies applicants seeking low-interest loans for eligible power projects. PPF provides local utilities, local governments, or independent power producers an avenue to seek funding for the development, expansion, or upgrade of electric power facilities. Power Project Fund (PPF) Loan Program FLEXIBLE FINANCING Low-Cost Financing Tailored to Project and Borrower COMMUNITY BORROWING $27.2 Million in Outstanding Loans COMPETITIVE RATES Current PPF Interest Rate 4.86% as of March 6, 2023 AVAILABLE CAPITAL $6.7 Million Available for Lending AEA Overview Presentation | House Energy Committee | March 21, 2023 17 SUCCESS STORY Location: Hydaburg, Prince of Wales Island Total Project Cost: $31,300,000 REF: $4,000,000 PPF Loan: $19,130,000 Capacity: 5 MW Borrower : Haida Energy Hiilangaay Hydroelectric Project Financed by REF and PPF, the Hiilangaay Hydroelectric Project is a small dam constructed on Melon Lake near Hydaburg on Prince of Wales Island. Commissioned in January 2020, Hiilangaay is providing 100% clean renewable energy and has already displaced more than 110,000 gallons of costly imported diesel the isolated communities use for electrical generation. Haida Energy sells the output from its 5-megawatt (MW) turbines to Alaska Power & Telephone for distribution across Prince of Wales Island. AEA Overview Presentation | House Energy Committee | March 21, 2023 18 Location: Eagle River Total Project Cost: $4,320,000 PPF Loan: $2,070,000 Capacity: 1.2 MW Borrower : South Fork Hydro, LLC South Fork Hydroelectric Project Financed by PPF, the South Fork Hydroelectric Plant is a run-of-the-river hydro facility that produces power equivalent to that consumed by approximately 800 homes. The plant has been transmitting power to the Matanuska Electric Association (MEA) grid since August 2013 at a price of $0.07 kilowatt hour, cost competitive with MEA generation. In 2022, AEA approved South Fork’s request to refinance the PPF loan and utilize the savings to purchase a third turbine, increasing the nameplate capacity of the facility to 1.76 megawatt (MW), an increase of 47%. SUCCESS STORY AEA Overview Presentation | House Energy Committee | March 21, 2023 19 SUCCESS STORY Location: Willow Total Project Cost: $1,577,000 PPF Loan: $814,000 Capacity: 1.2 MW Borrower : AK Renewable Energy Partners / Renewable IPP Willow Solar Farm Expansion Project Through a PPF loan, AEA provided additional capital needed to expand a 140-kilowatt pilot project to a 1.2 megawatt (MW) facility —making it Alaska’s largest solar project at that point in time. The Willow Solar Farm Expansion project, which began operations in December 2019, went from 408 solar panels to 3,240 solar panels capable of producing enough power for 200 homes and offsetting 2 million pounds of carbon dioxide annually. Power is sold to Matanuska Electric Association at its avoided energy cost, which are $0.07681 per kilowatt-hour as of January 1, 2023. AEA Overview Presentation | House Energy Committee | March 21, 2023 20 Established in 2008, REF provides grant funding (subject to Legislative approval) incentivizing the development of qualifying and competitively selected renewable energy projects. The program is designed to produce cost-effective renewable energy for heat and power to benefit Alaskans statewide. Renewable Energy Fund (REF) Grant Program STATEWIDE INVESTMENT 271 Grants Awarded Totaling $300 Million ACTIVE PROJECTS 100 Projects in Operation 44 in Development ROUND 13 AWARDS 11 Projects Awarded $4.75 Million Appropriated ROUND 14 AWARDS 27 Applications $15 Million Appropriated ROUND 15: 31 applications totaling request of $33 Million AEA Overview Presentation | House Energy Committee | March 21, 2023 21 SUCCESS STORY Location: Nome, Alaska REF Funding: $8,870,000 Total Project Cost: $10,100,000 Total Capacity: 1.8 MW Borrower : Nome Joint Utilities Banner Peak Wind Farm Expansion REF funded the Banner Peak Wind Farm expansion and related transmission infrastructure for the City of Nome. The project expanded Nome Joint Utilities’ (NJUS) wind generation capacity by 1.8 megawatt (MW), with the addition of two, 900 kilowatt EWT Turbines. Since its launch in August 2013, the project has reduced diesel fuel costs for NJUS, resulting in lower electric rates for Nome ratepayers. The Banner Peak Wind Farm currently generates about 2,160 megawatt hours of energy per year, or about 7% of NJUS total annual power generation. AEA Overview Presentation | House Energy Committee | March 21, 2023 22 Location: Ketchikan, Alaska REF Funding: $10,025,000 Total Project Cost: $28,200,000 Total Capacity: 4.6 MW Borrower : Ketchikan Public Utilities SUCCESS STORY Whitman Lake Hydroelectric Project In 2015, the Whitman Lake Hydroelectric Project became operational generating an estimated 16,000 megawatt hours annually, displacing approximately 1.1 million gallons of diesel. Together with Ketchikan Public Utilities' (KPU) other hydroelectric generation facilities, the project provides about 50% of Ketchikan's power needs, with the remaining 50% coming from Southeast Alaska Power Agency (SEAPA). The project allows KPU to continue using its diesel generators only for backup power in the event of low hydro levels and non-availability of SEAPA purchases. AEA Overview Presentation | House Energy Committee | March 21, 2023 23 SUCCESS STORY Location: Kodiak Island REF Funding: $4,000,000 Total Project Cost: $22,600,000 Total Capacity: 11.25 MW Borrower : Kodiak Electric Association Terror Lake Hydroelectric Expansion Project AEA financed the addition of a third turbine to the existing Terror Lake Hydroelectric Project on Kodiak Island, which provides an additional 11.25 megawatts (MW) of power, for a total power plant capacity of 31 MW. The project helped Kodiak reach its goal to have 95% of their electrical needs supplied by renewable energy by 2020. The project benefits the City of Kodiak, the United States Coast Guard Support Center, and the communities of Chiniak, Pasagshak, and Port Lions. AEA Overview Presentation | House Energy Committee | March 21, 2023 24 INFRASTRUCTUREINVESTMENTAND JOBS ACT 25 These federal formula grant funds will provide $60 million to Alaska over five years, including $22.2 Million for the first two years allocation, to catalyze projects that increase grid resilience against disruptive events. Resilience measures include but are not limited to: -Relocating or reconductoring powerlines -Improvements to make the grid resistant to extreme weather -Increasing fire resistant components -Integrating distributed energy resources like microgrids and energy storage Formula-based funding requires a 15% state match and a 33% small utility match. Statewide Grid Resilience and Reliability IIJA Formula Grant Program, 40101(d) Per IIJA section 40101(a)(1),8 a disruptive event is defined as “an event in which operations of the electric grid are disrupted, preventively shut off, or cannot operate safely due to extreme weather, wildfire, or a natural disaster.” 26 State of Alaska Electric Vehicle (EV) Infrastructure Implementation Plan AEA and the Alaska Department of Transportation & Public Facilities (DOT&PF), submitted their State of Alaska EV Infrastructure Implementation Plan (The Plan) to the United States Joint Office of Energy and Transportation, as required by the Infrastructure Investment and Jobs Act’s (IIJA) NEVI Formula Program. On September 27, 2022, The Plan was approved.The announcement unlocks $19 million to expand EV charging infrastructure in Alaska. Over the next five years, AEA anticipates receiving $52 million. Funds will be received by DOT&PF and administered by AEA. On March 1, 2023, AEA issued a Request for Applications for to site hosts compete for a share of Alaska's NEVI program funding. Applications are due by 4 p.m. on May 1, 2023. 27 Funding must be used to build out Alternative Fuel Corridors (AFCs) first Alaska currently has one AFC (pending) After AFC buildout, funding can be used elsewhere Charging infrastructure must be DC fast-charging ⁻4 Combined Charging System Connectors ⁻>150 kW each Chargers must be located no more than 1 driving mile from AFC Charging stations must be located no more than 50 miles apart along designated AFC Match Requirements Federal share: 80% Private entity or other: 20% Justice40 Requirements NEVI Requirements AEA Overview Presentation | House Energy Committee | March 21, 2023 28 IIJA Energy Opportunities — Need Federal Receipt Authority IIJA: Statewide Grid Resilience and Reliability Formula Grant Program, 40101(d) –$12 Million (requires $1.8 Million Federal Match) IIJA Competitive: Energy Efficiency Revolving Loan Fund –$3.7 Million IIJA: State Energy Program –$2.9 Million IIJA Competitive: Alaska Rural EVSE Deployment –$2 Million IIJA: Energy Auditor Training –$315,000 (Over Five Years) Alaska High Efficiency Home Rebate Program –$37 Million Inflation Reduction Act Alaska Hope for Homes –$37 Million Defense Community Infrastructure Pilot Program: Black Rapids Training Site – $12.8 Million AEA Overview Presentation | House Energy Committee | March 21, 2023 29 To enhance the power system's resilience to extreme weather and climate change, the Grid Deployment Office is administering a $10.5 billion GRIP program under the Bipartisan Infrastructure Law. IIJA Competitive: Grid Resilience and Innovation Partnerships (GRIP) 1) Railbelt Backbone Reconstruction Project $100 Million (Application Phase) 2) Battery Energy Storage/HVDC Coordinated Control $15 Million (Application Phase) 3) Railbelt Innovation Resiliency Project) $299 Million (Application Phase) 3) Rural Alaska Microgrid Transformation $250 Million (Application Phase) AEA Overview Presentation | House Energy Committee | March 21, 2023 30 Infrastructure Investment and Jobs Act (IIJA) Staffing Needs Managing and deploying millions of federal IIJA funds in compliance with federal requirements requires adequate technical and administrative support. Five (5) key positions, funded by federal IIJA receipts, are needed to carry out IIJA projects: Power Cost Equalization (PCE) Staffing Needs $233.9 increment for technical and administrative support. This includes one (1) PCE Technician needed for training, inventory, and technical assistance. Fund source is PCE Endowment Earnings. -PCE Technician R14 –$106.8 -PCE Salary Adjustment, Rural Assistance, Shared Services -$127.1 -Project Manager R24 $160.1 -Project Manager R24 $160.1 -Contracting Officer R20 $127.6 -Senior Accountant R18 $114.4 -Grant Coordinator R18 $114.4 Total $676.6 Staffing Needs AEA Overview Presentation | House Energy Committee | March 21, 2023 31 813 W Northern Lights Blvd. Anchorage, AK 99503 Main: (907) 771-3000 Fax: (907) 771-3044 akenergyauthority.org @alaskaenergyauthority @alaskaenergyauthority Alaska Energy Authority AEA provides energy solutions to meet the unique needs of Alaska’s rural and urban communities. 32 APPENDIX Operating Budget Overview (In Thousands) Operating Budget -All Components FY2017 Authorized FY2018 Authorized FY2019 Authorized FY2020 Authorized FY2021 Authorized FY2022 Authorized FY2023 Management Plan FY2024 Authorized Expenditure Categories: Travel 162.0 162.0 162.0 134.8 134.8 134.8 196.1 196.1 Services (includes personal services paid to AIDEA)9,662.0 8,948.2 9698.2 9698.2 8,548.2 8,548.2 8,503.8 10,008.8 Commodities 56.0 56.0 56.0 56.0 56.0 56.0 56.0 106.0 Capital Outlay/Equipment 15.0 15.0 15.0 15.0 15.0 15.0 15.0 15.0 Grants 40,100.0 37,600.0 32,100.0 32,100.0 29,600.0 32,100.0 47,794.8 47,794.8 Totals 49,995.0 46781.2 42,031.2 42,004.0 38,354.0 40,854.0 56,565.7 58,120.7 Funding Sources: Unrestricted GF (undesignated)2,276.1 874.5 874.5 874.3 874.3 874.3 852.2 1,215.3 Power Project Fund (designated)995.5 995.5 995.5 995.5 995.5 995.5 996.4 996.4 Renewable Energy Fund (designated)2,000.0 2,000.0 2,000.0 2,000.0 1,400.0 1,400.0 1,401.2 1,401.2 Power Cost Equalization Endowment (designated)40,335.0 38,236.8 32,736.8 32,736.8 30,236.8 32,736.8 48,431.6 48,665.5 GF Program Receipts (designated)100.0 100.0 100.0 100.0 50.0 50.0 50.0 50.0 Subtotal (Undesignated and Designated)45,726.6 42,206.8 38,706.8 36,769.6 33,529.6 39,029.6 51,731.4 52,328.4 CIP Receipts 2,567.8 2,567.8 2,567.8 2,567.8 2,567.8 2,567.8 2,570.1 3,528.1 Federal Receipts 445.0 752.0 1,502.0 1,502.0 1,202.0 1,202.0 1,208.6 1,208.6 AEA Receipts 981.7 980.7 980.7 980.7 780.7 780.7 781.3 781.3 I/A Receipts 123.9 123.9 123.9 123.9 123.9 123.9 124.3 124.3 Statutory Designated Program Receipts 150.0 150.0 150.0 150.0 150.0 150.0 150.0 150.0 Subtotal (Receipts)4,268.4 4,574.4 5,324.4 5324.4 4,824.4 4,824.4 4,834.3 5,792.3 Totals 49,995.0 46,781.2 42,031.2 42,004.0 38,354.0 40,854.0 56,565.7 58,120.7 AEA Overview Presentation | House Energy Committee | March 21, 2023 34 AEA Receipts, $781.3 , 8% Federal Receipts, $1,208.6 , 12% General Fund, $1,215.3 , 12% I/A Receipts, $124.3 , 1% CIP Receipts, $3,380.6 , 33% Power Project Fund, $996.4 , 10% Statutory Designated, $150.0 , 1% PCE Endowment, $970.7 , 9% GF Program Receipts Designated, $50.0 , 0% Renewable Energy Fund, $1,401.2 , 14% FY2024 Proposed Operating Budget $3,528.1, 33% AEA Overview Presentation | House Energy Committee | March 21, 2023 35 Project/Program Budget Year Federal State UGF Total IIJA -Statewide Grid Resilience and Reliability Formula FY 24 12,110,523 1,816,579 13,927,102 IIJA -New Energy Efficiency Revolving Loan Fund Capitalization FY 24 3,773,780 -3,773,780 IIJA -State Energy Program FY 23 Suppl.*2,865,930 -2,865,930 IIJA -EV Charging Equipment Competitive FY 24*1,670,000 -1,670,000 IIJA -Energy Auditor Training FY 24 63,600 -63,600 IRA -Home Energy and High Efficiency Rebate Allocations FY 24 74,519,420 -74,519,420 Black Rapids Training Site -Defense Community Infrastructure Pilot Program FY 23 Suppl.*12,752,540 -12,752,540 Rural Power Systems Upgrades FY 24 25,000,000 7,500,000 32,500,000 Renewable Energy Fund Round 15 FY 24 -7,500,000 7,500,000 Bulk Fuel Upgrades FY 24 7,500,000 5,500,000 13,000,000 Hydroelectric Development -Dixon &Godwin Creek Studies FY 24 -5,000,000 5,000,000 Renewable Energy &Efficiency Programs FY 24 -5,000,000 5,000,000 Delta Phase 3 Power FY 24 3,000,000 3,000,000 Electrical Emergencies FY 24 -200,000 200,000 TOTAL 140,255,793 35,516,579 175,772,372 FY2024 Capital Budget Overview •Statewide Grid Resilience and Reliability Formula -$60 million over five years •National Electric Vehicle Infrastructure Formula Program (funds from Department of Transportation RSA) -$52 million over five years AEA Overview Presentation | House Energy Committee | March 21, 2023 36 Renewable Energy & Efficiency Programs BIOMASS ENERGY EFFICIENCY ELECTRIC VEHICLES ENERGY STORAGE GEOTHERMAL HEAT RECOVERY HYDROELECTRIC NUCLEAR SOLAR WIND AEA’s renewable energy and efficiency programs provide critical technical support for communities interested in developing renewable energy programs in with the aim of growing Alaska's clean economy. Funds would be used for: reconnaissance level studies and feasibility analysis to identify project locations, and technical assistance and support for utilities and communities interested in developing cost-effective renewable energy and energy efficiency projects. Funds would help AEA leverage: federal funding from federal partners such as, but no limited to the Denali Commission, USDOE, and USDA —and is imperative for continued renewable development in Alaska. Capital Request: General Fund -$5 Million AEA Overview Presentation | House Energy Committee | March 21, 2023 37 AEA OVERVIEW PRESENTATION Curtis W. Thayer Executive Director House Finance Committee March 16, 2023 ALASKA ENERGY AUTHORITY Who We Are Created in 1976 by the Alaska Legislature, the Alaska Energy Authority (AEA) is a public corporation of the State of Alaska governed by a board of directors with the mission to “reduce the cost of energy in Alaska.” AEA is the state's energy office and lead agency for statewide energy policy and program development. Our Mission Reduce the cost of energy in Alaska. AEA Overview Presentation | House Finance Committee | March 16, 2023 02 Railbelt Energy –AEA owns the Bradley Lake Hydroelectric Project, the Alaska Intertie, and the Sterling to Quartz Creek Transmission Line —all of which benefit Railbelt consumers by reducing the cost of power. Power Cost Equalization (PCE) –PCE reduces the cost of electricity in rural Alaska for residential customers and community facilities, which helps ensure the sustainability of centralized power. Rural Energy –AEA constructs bulk fuel tank farms, diesel powerhouses, and electrical distribution grids in rural villages. AEA supports the operation of these facilities through circuit rider and emergency response programs. Renewable Energy and Energy Efficiency –AEA provides funding, technical assistance, and analysis on alternative energy technologies to benefit Alaskans. These include biomass, hydro, solar, wind, and others. Grants and Loans –AEA provides loans to local utilities, local governments, and independent power producers for the construction or upgrade of power generation and other energy facilities. Energy Planning –In collaboration with local and regional partners, AEA provides economic and engineering analysis to plan the development of cost-effective energy infrastructure. What We Do AEA’s mission is to reduce the cost of energy in Alaska. To achieve this mission, AEA works to diversify Alaska's energy portfolio. AEA Overview Presentation | House Finance Committee | March 16, 2023 03 Active Projects and Services AEA Overview Presentation | House Finance Committee | March 16, 2023 04 URBAN ENERGY 05 Bradley Lake is Alaska’s largest source of renewable energy. Energized in 1991, the project is situated 27‐air miles northeast of Homer on the Kenai Peninsula. The 120 MW facility provides low-cost energy to 550,000+ members on the Railbelt. Bradley Lake’s annual energy production is ~10% of Railbelt electricity at 4.5 cents/kWh (or ~54,400 homes/year) and over $20 million in savings per year to Railbelt utilities from Bradley Lake versus natural gas. The Dixon Diversion Project would expand Bradley Lake and generate electricity for 14,000-28,000 homes on the Railbelt every year. Bradley Lake Hydroelectric Project 06 BPMC BPMC The Bradley Lake Hydroelectric Project is owned by AEA and managed by the Bradley Lake Project Management Committee (BPMC), which is comprised of a member from each of the five participating Railbelt utilities: Chugach Electric Association, Golden Valley Electric Association, Homer Electric Association, Matanuska Electric Association, and Seward Electric System. (56.3%)(1.0%) (16.9%)(13.8%) (12.0%) 07 Transmission Upgrades and Battery Storage AEA and the Railbelt utilities closed on $166 million in bond financing to improve the efficiency and deliverable capacity of power from the Bradley Lake Hydroelectric Project. The bonding comes at no additional cost to ratepayers or burden on the State treasury. Upgrade transmission line between Bradley Lake and Soldotna Substation Upgrade transmission line between Soldotna Substation and Sterling Substation Upgrade transmission line between Sterling Substation and Quartz Creek Substation Battery Energy Storage Systems for Grid Stabilization These projects will reduce constraints on the Railbelt by improving the Kenai Peninsula’s transmission capacity to export power from Bradley Lake —and allow for the integration of additional renewable energy generation. 08 Railbelt Upgrades 9 Constructed in the mid-1980s, the Alaska Intertie is a 170 mile-long, 345 kilovolt (kV) transmission line from Willow to Healy. Operated by AEA and Railbelt utilities, within Railbelt system the transmission line improves reliability. Allows Golden Valley Electric Association (GVEA) to connect to and benefit from lower cost power. Between 2008 and 2021, the Intertie provided an average annual cost savings of $37 million to GVEA customers. Alaska Intertie 010 RURAL ENERGY 11 St. George Island, Pribilof Islands, AK PCE by the Numbers AEA, along with the Regulatory Commission of Alaska, administers the program that serves remote communities that are largely reliant on diesel fuel for power generation. AEA Overview Presentation | House Finance Committee | March 16, 2023 12 193 91 82,000 Who is Eligible to Participate in PCE? PCE eligibility is determined by the Regulatory Commission of Alaska in accordance with Alaska Statutes 42.45.100-170. Eligible customers include: Residential and community facilities (water, sewer, public lighting, and clinics, etc.) Non-eligible customers include: State and federal facilities and commercial customers Any community with rates lower than the urban average (the PCE floor) AEA Overview Presentation | House Finance Committee | March 16, 2023 13 Rural Power System Upgrades BeforeAfter14 ~197 communities eligible for Rural Power System Upgrade Goal —improve power system efficiency, safety, and reliability Aging infrastructure and Operation and Maintenance Active projects —7 full and 16 Maintenance and Improvement/Diesel Emissions Reduction Act Deferred maintenance $300 million Capital Request: State Match –$7.5 Million Federal Receipt Authority –$25 Million ~400 rural bulk fuel facilities Goal —code compliant fuel storage facilities and prevention of spills and contamination Aging infrastructure, erosion, and catastrophic failure Active projects —8 full and 18 Maintenance and Improvement; no funding for two years Leveraging Coast Guard regulatory efforts to capture BFU assessments to prioritize projects Deferred maintenance $800 million Bulk Fuel UpgradesBefore After15 Capital Request: State Match –$5.5 Million Federal Receipt Authority –$7.5 Million FINANCING TOOLS 16 The PPF loan program qualifies applicants seeking low-interest loans for eligible power projects. PPF provides local utilities, local governments, or independent power producers an avenue to seek funding for the development, expansion, or upgrade of electric power facilities. Power Project Fund (PPF) Loan Program FLEXIBLE FINANCING Low-Cost Financing Tailored to Project and Borrower COMMUNITY BORROWING $27.2 Million in Outstanding Loans COMPETITIVE RATES Current PPF Interest Rate 4.86% as of March 6, 2023 AVAILABLE CAPITAL $6.7 Million Available for Lending AEA Overview Presentation | House Finance Committee | March 16, 2023 17 SUCCESS STORY Location: Hydaburg, Prince of Wales Island Total Project Cost: $31,300,000 REF: $4,000,000 PPF Loan: $19,130,000 Capacity: 5 MW Borrower : Haida Energy Hiilangaay Hydroelectric Project Financed by REF and PPF, the Hiilangaay Hydroelectric Project is a small dam constructed on Melon Lake near Hydaburg on Prince of Wales Island. Commissioned in January 2020, Hiilangaay is providing 100% clean renewable energy and has already displaced more than 110,000 gallons of costly imported diesel the isolated communities use for electrical generation. Haida Energy sells the output from its 5-megawatt (MW) turbines to Alaska Power & Telephone for distribution across Prince of Wales Island. AEA Overview Presentation | House Finance Committee | March 16, 2023 18 Location: Eagle River Total Project Cost: $4,320,000 PPF Loan: $2,070,000 Capacity: 1.2 MW Borrower : South Fork Hydro, LLC South Fork Hydroelectric Project Financed by PPF, the South Fork Hydroelectric Plant is a run-of-the-river hydro facility that produces power equivalent to that consumed by approximately 800 homes. The plant has been transmitting power to the Matanuska Electric Association (MEA) grid since August 2013 at a price of $0.07 kilowatt hour, cost competitive with MEA generation. In 2022, AEA approved South Fork’s request to refinance the PPF loan and utilize the savings to purchase a third turbine, increasing the nameplate capacity of the facility to 1.76 megawatt (MW), an increase of 47%. SUCCESS STORY AEA Overview Presentation | House Finance Committee | March 16, 2023 19 SUCCESS STORY Location: Willow Total Project Cost: $1,577,000 PPF Loan: $814,000 Capacity: 1.2 MW Borrower : AK Renewable Energy Partners / Renewable IPP Willow Solar Farm Expansion Project Through a PPF loan, AEA provided additional capital needed to expand a 140-kilowatt pilot project to a 1.2 megawatt (MW) facility —making it Alaska’s largest solar project at that point in time. The Willow Solar Farm Expansion project, which began operations in December 2019, went from 408 solar panels to 3,240 solar panels capable of producing enough power for 200 homes and offsetting 2 million pounds of carbon dioxide annually. Power generated will be sold to Matanuska Electric Association under a 30-year contract with the utility. AEA Overview Presentation | House Finance Committee | March 16, 2023 20 Established in 2008, REF provides grant funding (subject to Legislative approval) incentivizing the development of qualifying and competitively selected renewable energy projects. The program is designed to produce cost-effective renewable energy for heat and power to benefit Alaskans statewide. Renewable Energy Fund (REF) Grant Program STATEWIDE INVESTMENT 271 Grants Awarded Totaling $300 Million ACTIVE PROJECTS 100 Projects in Operation 44 in Development ROUND 13 AWARDS 11 Projects Awarded $4.75 Million Appropriated ROUND 14 AWARDS 27 Applications $15 Million Appropriated ROUND 15: 31 applications totaling request of $33 Million AEA Overview Presentation | House Finance Committee | March 16, 2023 21 SUCCESS STORY Location: Nome, Alaska REF Funding: $8,870,000 Total Project Cost: $10,100,000 Total Capacity: 1.8 MW Borrower : Nome Joint Utilities Banner Peak Wind Farm Expansion REF funded the Banner Peak Wind Farm expansion and related transmission infrastructure for the City of Nome. The project expanded Nome Joint Utilities’ (NJUS) wind generation capacity by 1.8 megawatt (MW), with the addition of two, 900 kilowatt EWT Turbines. Since its launch in August 2013, the project has reduced diesel fuel costs for NJUS, resulting in lower electric rates for Nome ratepayers. The Banner Peak Wind Farm currently generates about 2,160 megawatt hours of energy per year, or about 7% of NJUS total annual power generation. AEA Overview Presentation | House Finance Committee | March 16, 2023 22 Location: Ketchikan, Alaska REF Funding: $10,025,000 Total Project Cost: $28,200,000 Total Capacity: 4.6 MW Borrower : Ketchikan Public Utilities SUCCESS STORY Whitman Lake Hydroelectric Project In 2015, the Whitman Lake Hydroelectric Project became operational generating an estimated 16,000 megawatt hours annually, displacing approximately 1.1 million gallons of diesel. Together with Ketchikan Public Utilities' (KPU) other hydroelectric generation facilities, the project provides about 50% of Ketchikan's power needs, with the remaining 50% coming from Southeast Alaska Power Agency (SEAPA). The project allows KPU to continue using its diesel generators only for backup power in the event of low hydro levels and non-availability of SEAPA purchases. AEA Overview Presentation | House Finance Committee | March 16, 2023 23 SUCCESS STORY Location: Kodiak Island REF Funding: $4,000,000 Total Project Cost: $22,600,000 Total Capacity: 11.25 MW Borrower : Kodiak Electric Association Terror Lake Hydroelectric Expansion Project AEA financed the addition of a third turbine to the existing Terror Lake Hydroelectric Project on Kodiak Island, which provides an additional 11.25 megawatts (MW) of power, for a total power plant capacity of 31 MW. The project helped Kodiak reach its goal to have 95% of their electrical needs supplied by renewable energy by 2020. The project benefits the City of Kodiak, the United States Coast Guard Support Center, and the communities of Chiniak, Pasagshak, and Port Lions. AEA Overview Presentation | House Finance Committee | March 16, 2023 24 INFRASTRUCTUREINVESTMENTAND JOBS ACT 25 These federal formula grant funds will provide $60 million to Alaska over five years, including $22.2 Million for the first two years allocation, to catalyze projects that increase grid resilience against disruptive events. Resilience measures include but are not limited to: -Relocating or reconductoring powerlines -Improvements to make the grid resistant to extreme weather -Increasing fire resistant components -Integrating distributed energy resources like microgrids and energy storage Formula-based funding requires a 15% state match and a 33% small utility match. Statewide Grid Resilience and Reliability IIJA Formula Grant Program, 40101(d) Per IIJA section 40101(a)(1),8 a disruptive event is defined as “an event in which operations of the electric grid are disrupted, preventively shut off, or cannot operate safely due to extreme weather, wildfire, or a natural disaster.” 26 State of Alaska Electric Vehicle (EV) Infrastructure Implementation Plan AEA and the Alaska Department of Transportation & Public Facilities (DOT&PF), submitted their State of Alaska EV Infrastructure Implementation Plan (The Plan) to the United States Joint Office of Energy and Transportation, as required by the Infrastructure Investment and Jobs Act’s (IIJA) NEVI Formula Program. On September 27, 2022, The Plan was approved. The announcement unlocks $19 million to expand EV charging infrastructure in Alaska. Over the next five years, AEA anticipates receiving $52 million. Funds will be received by DOT&PF and administered by AEA. On March 1, 2023, AEA issued a Request for Applications for to site hosts compete for a share of Alaska's NEVI program funding. Applications are due by 4 p.m. on May 1, 2023.27 Funding must be used to build out Alternative Fuel Corridors (AFCs) first Alaska currently has one AFC (pending) After AFC buildout, funding can be used elsewhere Charging infrastructure must be DC fast-charging ⁻4 Combined Charging System Connectors ⁻>150 kW each Chargers must be located no more than 1 driving mile from AFC Charging stations must be located no more than 50 miles apart along designated AFC Match Requirements Federal share: 80% Private entity or other: 20% Justice40 Requirements NEVI Requirements AEA Overview Presentation | House Finance Committee | March 16, 2023 28 IIJA Energy Opportunities — Need Federal Receipt Authority IIJA: Statewide Grid Resilience and Reliability Formula Grant Program, 40101(d) –$12.1 Million (requires $1.8 Million Federal Match) IIJA Competitive: Energy Efficiency Revolving Loan Fund –$3.8 Million IIJA: State Energy Program –$2.9 Million IIJA Competitive: Alaska Rural EVSE Deployment –$1.67 Million IIJA: Energy Auditor Training –$318,000 (Over Five Years) Alaska High Efficiency Home Rebate Program –$37.2 Million Inflation Reduction Act Alaska Hope for Homes –$37.4 Million Department of Defense Community Infrastructure Pilot Program: Black Rapids Training Site –$12.8 Million AEA Overview Presentation | House Finance Committee | March 16, 2023 29 To enhance the power system's resilience to extreme weather and climate change, the Grid Deployment Office is administering a $10.5 billion GRIP program under the Bipartisan Infrastructure Law. IIJA Competitive: Grid Resilience and Innovation Partnerships (GRIP) 1) Railbelt Backbone Reconstruction Project $100 Million (Application Phase) 2) Battery Energy Storage/HVDC Coordinated Control $15 Million (Application Phase) 3) Railbelt Innovation Resiliency Project) $299 Million (Application Phase) 3) Rural Alaska Microgrid Transformation $250 Million (Application Phase) AEA Overview Presentation | House Finance Committee | March 16, 2023 30 Infrastructure Investment and Jobs Act (IIJA) Staffing Needs Managing and deploying millions of federal IIJA funds in compliance with federal requirements requires adequate technical and administrative support. Five (5) key positions, funded by federal IIJA receipts, are needed to carry out IIJA projects: Power Cost Equalization (PCE) Staffing Needs $233.9 increment for technical and administrative support. This includes one (1) PCE Technician needed for training, inventory, and technical assistance. Fund source is PCE Endowment Earnings. -PCE Technician R14 –$106.8 -PCE Salary Adjustment, Rural Assistance, Shared Services -$127.1 -Project Manager R24 $160.1 -Project Manager R24 $160.1 -Contracting Officer R20 $127.6 -Senior Accountant R18 $114.4 -Grant Coordinator R18 $114.4 Total $676.6 Staffing Needs AEA Overview Presentation | House Finance Committee | March 16, 2023 31 813 W Northern Lights Blvd. Anchorage, AK 99503 Main: (907) 771-3000 Fax: (907) 771-3044 info@akenergyauthority.org akenergyauthority.org @alaskaenergyauthority @alaskaenergyauthority Alaska Energy Authority AEA provides energy solutions to meet the unique needs of Alaska’s rural and urban communities. 32 By KRISTEN NELSON Petroleum News The Baker Hughes’ U.S. rotary drilling rig count was down by three for the week ending March 9 to 746, and up 83 from a count of 663 for the same period a year ago. The count has dropped for four weeks in a row, and for six of the past eight weeks, down from 771 rigs Jan. 20 after reaching a high for 2022 of 784 at the beginning of December. When the count dropped to 244 in mid- August 2020, it was the lowest the domestic rotary rig count had been since the Houston based oilfield services company began issu- ing weekly U.S. numbers in 1944. Prior to 2020, the low was 404 rigs in May 2016. The count peaked at 4,530 in 1981. The count was in the low 790s at the beginning of 2020 prior to the COVID-19 pandemic, where it remained through mid- March, when it began to fall, dropping below what had been the historic low in early May with a count of 374 and continu- ing to drop through the third week of August 2020 when it gained back 10 rigs. The March 9 count includes 590 rigs tar- geting oil, down two from the previous week and up 63 from 527 a year ago, with 153 rigs targeting natural gas, down one from the previous week and up 18 from 136 a year ago, and three miscellaneous rigs, unchanged from the previous week and up by two from a year ago. Forty-two of the rigs reported March 9 were drilling directional wells, 692 were drilling horizontal wells and 12 were drilling vertical wells. Alaska (10) was up by three rigs from the previous week. West Virginia (14) was up by two rigs week over week and Colorado (18) was up by a single rig. Louisiana (59), New Mexico (103) and Pennsylvania (22) were each down by three rigs. Rig counts in other states were unchanged from the previous week: California (2), North Dakota (41), Ohio (14), Oklahoma (61), Texas (366), Utah (11) and Wyoming (20). Baker Hughes shows Alaska with 10 rotary rigs active March 9, up by three from the previous week and up by two from a year ago, when the state’s rig count stood at eight. All 10 of the Alaska rigs were onshore, an increase of three from the pre- vious week. There were no offshore rigs active in the state. The rig count in the Permian, the most active basin in the country, was down by six from the previous week at 343 and up by 27 from 316 a year ago. l PETROLEUM NEWS • WEEK OF MARCH 19, 2023 5 TNERS ARAP ROWING TGROGETHER IN QUALITY T ying • EevSurngineering • GIS l • Oil & Gas ib.lounwww omyinc.cnsbur l EXPLORATION & PRODUCTION Hilcorp submits 48th plan for Lewis River POD for Cook Inlet west side field includes 1 well, spudding as early as June 30, targeting Sterling, Beluga, and/or Tyonek sands By KAY CASHMAN Petroleum News Hilcorp Alaska operates four natural gas fields on the west side of Cook Inlet, including the tiny Lewis River unit for which the company recently sub- mitted its 48th annual plan of development, or POD. Referred to as the 2023 POD, the 48th plan runs from June 1 through May 31, 2024. Hilcorp became 100% working interest owner and operator at Lewis River on Jan. 1, 2012, as part of its 2011 acquisition of Chevron’s Cook Inlet assets. The 620-acre onshore unit was formed by Cities Service Oil Co. in 1977 and went online in 1984. In its report on work done during the 2018 POD at Lewis River Hilcorp said it “worked on a comprehen- sive field study,” evaluating the Sterling, Beluga and Tyonek reservoirs for further development, including study of what efficiencies would be pursued. Lewis River averaged 374 mcf per day in January, down 62.7% from a January 2022 average of 1,003 mcf per day. Recent POD activity Under the Lewis River unit’s 2021 POD Hilcorp perforated Sterling A sands in the Lewis River A1 well but reported the work was unsuccessful. Under the 2022 plan from June 1, 2022, through May 31, 2023, Hilcorp said it would continue to evalu- ate delineation drilling opportunities with the Sterling- Beluga and Tyonek participating areas, with various non-rig well projects planned. As with the previous POD, throughout the 2022 POD period, Hilcorp continued to produce from the Lewis River Gas Pool #2 participating area, or PA. Also, as with the 2021 POD, there was no production from the Lewis River Gas Pool #1 PA. 2023 plan activities The long-range proposed development activities for the unit include plans to delineate all underlying oil or gas reservoirs and get them into production and main- tain and enhance production once established. However, the company does not have any long- range proposed development activities for the unit dur- ing the 2023 POD period. Hilcorp also does not have any exploration plans for the 2023 POD. The company does plan to maintain production from the Lewis River Gas Pool #2 PA throughout the 2023 POD period. In what it calls its drill well program, Hilcorp plans to drill the LRU C-02 well spudding as early as June 30, and targeting Sterling, Beluga, and/or Tyonek sands. In Hilcorp’s wellwork and workover program, it plans to “perform various non-rig well projects” during the 2023 POD period. These projects may include: • Coil cleanout operations. • Adding (or isolating) Sterling or Beluga sand per- foration. At this time, Hilcorp said no major facility upgrades are planned during the 2023 POD. Finally, Hilcorp does not have any exploration or delineation activities planned in the 2023 POD. l l EXPLORATION & PRODUCTION US rotary drill rig count down 3 to 746 ESOR UNCO OPT 15 June 2023 • C–13 CE PLAOUR O NVENTION IMIZE YOU ention Center • Dado ConvColor A YS N AL U R ado, Colorerenv entionado Conv ), 13–15 JuneCTR(U echnoloechnoloTTcescesResour o attend t Color Resour Plan now t er e 2023 at the enceence ererConfConfogy entional n Center in Denv ogy the Unconv SiOiSponsoring Organizat essional disciplines.of ppr ation of the technical/ integr ces, with special emphasis on esourr entionalelopment of unconvvde ation and o explorchnology applied tte focused on the latest science and entvemier eeC is a prTado. URColor ,ention Center in Denvado ConvColor p er tions: ncoegrated event for uThe inteC.orgeURT ional resource teamsonvent PETROLEUM NEWS • WEEK OF MARCH 12, 2023 5 The Alaska Railroad has kept vital industries on track for 100 years. Freight moving by rail isn’t subject to seasonal weight restrictions like those on the road system, making the Alaska Railroad an efficient choice. Less hassle getting materials to the job site means you can focus on your project. FOR A CENTURY SEAMLESS LOGISTICS Full-service logistics. Get a free quote: 800.321.6518 AlaskaRailroad.com/freight l EXPLORATION & PRODUCTION Hilcorp gets approval to expand Pearl Pad Company also gets OK to drill 3 new wells at pad, 2 development gas wells and 1 O&G well; currently no oil production at Ninilchik By KRISTEN NELSON Petroleum News The Alaska Division of Oil and Gas has approved an application by Hilcorp Alaska to expand the Pearl Pad at the company’s Ninilchik unit on the Kenai Peninsula, and to drill three new wells from the pad — two development natural gas wells and one development gas well which will be extended to explore for oil. The approval of the unit plan of operations amendment is dated March 3. The division said the pad would be expanded by some 1.62 acres using approximately 13,120 cubic yards of grav- el fill. The two grass roots natural gas wells are the Pearl 10 and Pearl 11; the third well, Pearl 12, is a combination gas development and oil exploration well. The division said gas in the primary objective of Pearl 12, but it “will ultimately extend beyond anticipated gas zones to explore for oil.” The division said the bottomhole locations for Pearl 10 and Pearl 11 are in ADL 384372, which is offshore north- west of the Pearl Pad. A bottomhole location for Pearl 12 was not given in the decision. Hilcorp said it currently has no plans to produce oil from the Pearl Pad, but if oil is found at the Pearl 12 in commer- cial quantities, “potential methods for oil production and subsequent transport from Pearl Pad will be evaluated.” The project also involves infrastructure: gas flowlines, electrical instrumentation, a line heater and a separator. Pad on private land The pad is on private land south of the Ninilchik unit with the bottomhole locations for the new wells in the Ninilchik unit. The division said the pad expansion would provide space necessary for drilling of production wells and for increased gas production from the Ninilchik unit. In January, the most recent month for which production data is available from the Alaska Oil and Gas Conservation Commission, Ninilchik was the most productive Cook Inlet gas field, averaging 50,155 thousand cubic feet per day, 22.3% of Cook Inlet gas production, a 4.2% increase from the field’s December production and an increase of 69.7% from January 2022 production. The company also has drilling planned at the nearby Paxton Pad and offered an expected timeline for work on the two pads. Pre-rig construction activities at the Pearl Pad will occur during March, with drilling at the Paxton Pad expected from March 10 through April 10 and drilling at Pearl Pad from April 10 through June 1. l ! ! ! ! ! ! ! ! !! ! ! !. !. !H Pearl Pad LAT: 60.081799 LON:-151.627545 NAD 1983 S002N013WS002N012WS002N013W S001N013W S002N012W S001N012W S001N013WS001N012WS001N013W S001S013W S001N012W S001S012W S001S014WS001S013WS001S013WS001S012WNINILCHIK UNIT STERLINGH W Y Sec. 15Sec. 16Sec. 17Sec. 18Sec. 13Sec. 14Sec. 15Sec. 16Sec. 17Sec. 18 Sec. 22Sec. 21Sec. 20Sec. 19Sec. 24 Sec. 23Sec. 22Sec. 21Sec. 20Sec. 19 Sec. 27Sec. 28Sec. 29Sec. 30Sec. 25Sec. 26Sec. 27Sec. 28Sec. 29Sec. 30 Sec. 34Sec. 33Sec. 32Sec. 31Sec. 36Sec. 35Sec. 34Sec. 33Sec. 32Sec. 31 Sec. 3Sec. 4Sec. 5Sec. 6Sec. 1 Sec. 2Sec. 3Sec. 4Sec. 5Sec. 6Sec. 1 Sec. 10Sec. 9Sec. 8Sec. 7Sec. 12Sec. 11Sec. 10Sec. 9Sec. 8Sec. 7 Sec. 15Sec. 16Sec. 17Sec. 18Sec. 13Sec. 14Sec. 15Sec. 16Sec. 17Sec. 18 Sec. 22Sec. 21Sec. 20Sec. 19Sec. 24Sec. 23 Sec. 22Sec. 21 Sec. 20Sec. 19 Sec. 27Sec. 28Sec. 29Sec. 30Sec. 25Sec. 26Sec. 27Sec. 28Sec. 29Sec. 30 Sec. 34Sec. 33Sec. 32Sec. 31Sec. 36Sec. 35Sec. 34Sec. 33Sec. 32Sec. 31Sec. 36Sec. 35Sec. 34 Sec 3 Sec. 4Sec. 5Sec. 6 Sec. 1Sec. 2Sec. 3Sec. 4Sec. 5Sec. 6Sec. 1Sec. 2Sec. 3Sec. 4 Sec. 10 Sec. 9 Sec. 8Sec. 7Sec. 12Sec. 11Sec. 10Sec. 9Sec. 8Sec. 7Sec. 12Sec. 11Sec. 10Sec. 9 Sec 15 Sec. 16Sec. 17Sec. 18Sec. 13Sec. 14Sec. 15Sec. 16Sec. 17Sec. 18Sec. 13Sec. 14Sec. 15Sec. 16 Sec. 22 Sec. 21Sec. 20Sec. 19Sec. 24Sec. 23Sec. 22 Sec. 21 Sec. 20 Sec. 19Sec. 24Sec. 23Sec. 22Sec. 21 Sec. 27 Sec. 28Sec. 29Sec. 30Sec. 25Sec. 26Sec. 27Sec. 28Sec. 29Sec. 30Sec. 25Sec. 26Sec. 27Sec. 28 Sec. 34Sec. 33Sec. 32Sec. 31Sec. 36Sec. 35Sec. 34Sec. 33Sec. 32Sec. 31Sec. 36Sec. 35Sec. 34Sec. 33 )LJXUH Pearl Pad 9LFLQLW\ 012 Miles Alaska State Plane Zone 4, NAD83 ¯Pipelines !!!! !!!!Well Pads Oil and Gas Unit Boundaries Map Date: 5/20/2022 ! ! ! !! Alaska Canada Area of Detail Nome Juneau Fairbanks Anchorage Utqiagvik (Barrow) 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Murkowski slams Interior for deliberately cutting Cook Inlet gas production https://www.kinyradio.com/news/news-of-the-north/murkowski-slams-interior-for-deliberately-cutting-cook-inlet-gas-production/ 1/3 Murkowski slams Interior for deliberately cutting Cook Inlet gas production Saturday, March 4th, 2023 11:03am Cook Inlet (NOAA photo) Anchorage, Alaska (KINY) - Senator Lisa Murkowski issued the following statement Friday after reviewing an internal memo on Cook Inlet Lease Sale 258 that the Department of the Interior briefly posted online before quickly removing it from public view. The memo, which was obtained by the office of Senator Joe Manchin (D-West Virginia), outlines the administration’s efforts to undermine recent federal law and reduce natural gas production in Cook Inlet, Alaska. Murkowski slams Interior for deliberately cutting Cook Inlet gas production https://www.kinyradio.com/news/news-of-the-north/murkowski-slams-interior-for-deliberately-cutting-cook-inlet-gas-production/ 2/3 “This is a stunning document, and it details how the administration explicitly sought to reduce natural gas production in Cook Inlet. The administration did this despite rising regional electricity prices, despite producers warning local utilities not to count on continued gas delivery at the end of current contracts, and despite the likelihood of energy shortages that force us to import LNG. Despite being fully aware of all of that, Interior imposed conditions on a statutorily mandated lease sale that they knew would result in fewer bids and less production,” Murkowski said. “This document helps explain why the administration initially canceled this lease sale, and why they have resisted the development of a new Five-Year Plan. It shows a policy of working against domestic production, rather than promoting it. This administration may never feel the consequences, but Alaskans sure will, and that is completely unacceptable.” Clean-burning natural gas from Cook Inlet provides power generation for Southcentral Alaska, home to over half the state’s population. Joint Base Elmendorf Richardson (JBER), which hosts the Alaska NORAD Region, F-22s, AWACS, C-17s, and the 11th Airborne, relies on Cook Inlet gas for heat and power. “The Department is also weakening our nation’s defense posture in the Arctic and the Pacific by intentionally cutting Cook Inlet gas production,” Murkowski said. The administration abruptly canceled Lease Sale 258 in May 2022 despite industry’s expressed interest in new leases. Senator Manchin restored it through the Inflation Reduction Act, which required Interior to reschedule and hold the lease sale by the end of last year. Interior’s memo features a series of recommendations that were ultimately included in Lease Sale 258, including a maximum royalty of 18.75%. The memo notes that, “A lower royalty of 16 2⁄3 would also be expected to incentivize additional blocks receiving bids, increase bonus bids, and increase Murkowski slams Interior for deliberately cutting Cook Inlet gas production https://www.kinyradio.com/news/news-of-the-north/murkowski-slams-interior-for-deliberately-cutting-cook-inlet-gas-production/ 3/3 the chances of a discovery being developed. If a Cook Inlet prospect would be developed, there would be additional government revenues and greater energy security for the State of Alaska, especially if development of natural gas resources in the Cook Inlet ameliorated the long-term supply challenges facing the Anchorage area. Nevertheless, because of the serious challenges facing the Nation from climate change and the impact of GHGs from fossil fuels, BOEM is not recommending this option since it would not include an appropriate surcharge to account for those impacts.” 3/28/23, 9:50 AM Natural gas shortage in Cook Inlet? Not really. What’s short are investors | Local News Stories | frontiersman.com https://www.frontiersman.com/news/natural-gas-shortage-in-cook-inlet-not-really-what-s-short-are-investors/article_6c51ffb8-b986-11ed-bfef-2387a5e5…1/4 https://www.frontiersman.com/news/natural-gas-shortage-in-cook-inlet-not-really-what-s-short-are- investors/article_6c51 8-b986-11ed-bfef-2387a5e5128d.html Natural gas shortage in Cook Inlet? Not really. What’s short are investors By Tim Bradner For the Frontiersman Mar 2, 2023 Hilcorp Energy gas production platform, Cook Inlet. Courtesy photo Cook Inlet natural gas producers say they’re doing everything they can to get more gas into the Southcentral Alaska energy market to stave o possible shortages that could begin as early as 2027, according to a state study. Privacy - Terms 3/28/23, 9:50 AM Natural gas shortage in Cook Inlet? Not really. What’s short are investors | Local News Stories | frontiersman.com https://www.frontiersman.com/news/natural-gas-shortage-in-cook-inlet-not-really-what-s-short-are-investors/article_6c51ffb8-b986-11ed-bfef-2387a5e5…2/4 Hilcorp Energy, the region’s main oil and gas producer,has told state legislators in Juneau that it plans more drilling of gas wells. The company expects to spend $1 billion or more over the next 10 years to nd more gas, Luke Saugier, Hilcorp’s senior vice president for Alaska, told the Energy Committee of the state House Feb. 21. That won’t be enough. State Rep. Tom McKay, R-Anchorage, who chairs the Committee in the state House and who formerly worked in the industry, said 15 new gas wells per year are needed to stem the shortfall. That’s according to the state Department of Natural Resources, MacKay said. Hilcorp’s plan would drill about half the number needed, MacKay said in a discussion in the committee. Meanwhile, BlueCrest Energy, which is now producing oil from its Cosmopolitan eld just o shore Anchor Point, on the southern Kenai Peninsula, says it has a con rmed gas discovery in a separate reservoir overlaying the oil reservoir but is unable to secure , at least so far, a substantial investment needed to develop the gas. Benji Johnson, CEO at BlueCrest, told the state House committee that an o shore platform is needed to produce the gas because the deposit is too shallow to drill and produce with long extended-reach horizontal wells, as BlueCrest is doing with the oil reservoir at Cosmopolitan, which is deeper. The gas deposit has 234 billion cubic feet of proven reserves, Johnson said. If it could be developed it would supply the 70 billion cubic feet yearly demand in Southcentral Alaska for eight to 10 years, Johnson told the legislators. Another company hobbled by an investment need is Furie Alaska Operating LLC at its Kitchen Lights eld. HEX is currently producing gas from its one o shore platform and hopes to increase production with well workovers this year, but also wants to drill more producing wells. The problem for Furie is that it is challenged to fund the new work because of costs imposed by the state of Alaska, an unusual twist because the state is broadly encouraging new oil and gas development in Cook Inlet . 3/28/23, 9:50 AM Natural gas shortage in Cook Inlet? Not really. What’s short are investors | Local News Stories | frontiersman.com https://www.frontiersman.com/news/natural-gas-shortage-in-cook-inlet-not-really-what-s-short-are-investors/article_6c51ffb8-b986-11ed-bfef-2387a5e5…3/4 Furie CEO John Hendrix told legislators that a particular problem is the imposition of the state’s oil and gas property tax on the company’s facilities, and which is being interpreted in a way that impedes new development. Basically, the state is assessing the property based on estimated replacement cost minus depreciation. HEX argues the property should be valued on the basis of its original investment. Furie has sued the state Department of Revenue on its assessment and the issue is now in court. Meanwhile, the funds that could be used for new gas development at Kitchen Lights is instead going to the state of Alaska, Hendrix told the legislators. The property tax is only one problem. The state should be doing more to help smaller companies nd and develop more gas in the Inlet with other steps like reducing duplicative bonding requirements and considering relief from the state’s 12.5 percent gross royalty and 17.7 cents-per- mcf gas production tax. The state has done both royalty and tax relief in Cook Inlet before. If new gas cannot be developed in Cook Inlet in the next three to four years the only choice for regional utilities like Enstar Natural Gas, Chugach Electtric Association and Matanuska Electric Association, is to import lique ed natural gas, or LNG, most likely from British Columbia. The basic infrastructure to do that is in place at the mothballed former ConocoPhillips LNG export plant at Nikiski, which is now owned by Marathon Petroleum. Work would be required on the marine terminal at the plant to enable LNG to be o oaded rather than loaded, but most important the large LNG storage tanks at the plant have been maintained and kept in good condition. 3/28/23, 9:50 AM Natural gas shortage in Cook Inlet? Not really. What’s short are investors | Local News Stories | frontiersman.com https://www.frontiersman.com/news/natural-gas-shortage-in-cook-inlet-not-really-what-s-short-are-investors/article_6c51ffb8-b986-11ed-bfef-2387a5e5…4/4 A faster pace in developing renewable energy like new hydro, wind and solar would also help, although it would reduce gas demand for power generation but not space heating, which is soley dependent on gas. 3/28/23, 9:54 AM Kenai Peninsula analysts say looking to renewable energy options is crucial amid Cook Inlet natural gas decline https://www.kdll.org/2023-02-27/kenai-peninsula-analysts-say-looking-to-renewable-energy-options-is-crucial-amid-cook-inlet-natural-gas-decline 1/6 Support KDLL, make a donation today! Kenai Peninsula analysts say looking to renewable energy options is crucial amid Cook Inlet natural gas decline KBBI | By Simon Lopez Published February 27, 2023 at 1:40 PM AKST Sabine Poux /KDLL Previous Cook Inlet lease sales have been canceled due to lack of industry interest. The available gas supply from Cook Inlet — which electri es and heats Alaska’s Railbelt — is declining. Scott Waterman is a retired energy specialist who currently serves on the board of the Renewable Energy Alaska Project — a nonpro t aimed at increasing “clean energy” across the state. Donate 3/28/23, 9:54 AM Kenai Peninsula analysts say looking to renewable energy options is crucial amid Cook Inlet natural gas decline https://www.kdll.org/2023-02-27/kenai-peninsula-analysts-say-looking-to-renewable-energy-options-is-crucial-amid-cook-inlet-natural-gas-decline 2/6 “The Division of Oil and Gas Department of Natural Resources and the Oil and Gas [Conservation] Commission released a report just a couple of weeks ago that says that demand may exceed supplies as soon as 2027,” he said, during a roundtable on the state of Cook Inlet’s natural gas production on KBBI’s Coffee Table on Wednesday. Waterman said once the most easily accessible gas reserves in Cook Inlet are depleted, Alaska won’t have enough alternatives readily available to replace them in a short period of time. Erin McKittrick is a Seldovia-based writer and former scientist, who’s been analyzing energy and gas issues for years. She also is a member of the Homer Electric Association board of directors, but was not participating on behalf of the board. She said the state made an effort to boost natural gas production the last time there was a gas crisis imminent, in 2010, through the Cook Inlet Recovery Act. “The state basically paid about one-and-a-half-billion dollars of credits to Cook Inlet producers over the time period. I think it ended in 2016. And we've been paying back and still owe over $200 million on those credits,” she said. A 2015 report from the Alaska Oil and Gas Association said after the legislature took action, oil production increased by 80% across its 16 platforms. At that time, the report said, “The substantial increase in investment and economic growth on the Kenai Peninsula shows no signs of slowing down.” However, last month, the Alaska Division of Oil and Gas presented an updated forecast to the Alaska House Finance Committee that tells a different story. According to the 2022 Cook Inlet Gas Forecast Report, by the state’s Department of Natural Resources, gas production in Cook Inlet is predicted to fall below demand by 2027, assuming demand for that gas stays the same and that there’s no production from currently undeveloped gas prospects. Geologist and citizen scientist Bretwood Higman of Seldovia said the new report emphasizes the fact that Alaska is only a few years away from needing decisive and effective action — an action that could take many forms. 3/28/23, 9:54 AM Kenai Peninsula analysts say looking to renewable energy options is crucial amid Cook Inlet natural gas decline https://www.kdll.org/2023-02-27/kenai-peninsula-analysts-say-looking-to-renewable-energy-options-is-crucial-amid-cook-inlet-natural-gas-decline 3/6 “Either nding some way to increase supply so that there could be some new source within Cook Inlet, it could be natural gas imports, or we need to reduce our demand," Higman said. "That could be replacing natural gas with other renewable energy. It could also be just improving e ciency and how we use the natural gas we have.” McKittrick said there would be pros and cons to each solution. For example, relying on other states to accommodate the demand will increase household heating expenses. “If that price increases, as our gas supply dwindles, and we potentially bring in imported gas, then that's just going to directly pass through onto your bill in that line item and be substantially bigger,” she said. Higman said utilities like Homer Electric Association and private companies like Renewable IPP are exploring renewable options that could potentially become active producers of energy in a short amount of time. “That's what I really hope we'll see: that wind and solar being operational soon," he said. "And in the meantime, we need to be exploring geothermal and tidal, we could also talk about things like pumped hydro storage.” To listen to the full discussion on the state of Cook Inlet’s natural gas production, or read the forecast report, check out KBBI’s Coffee Table discussion from Feb. 22. The available gas supply from Cook Inlet — which electri es and heats Alaska’s Railbelt — is declining. “The Division of Oil and Gas Department of Natural Resources and the Oil and Gas [Conservation] Commission released a report just a couple of weeks ago that says that demand may exceed supplies as soon as 2027,” said Scott Waterman, a retired energy specialist. Waterman currently serves on the board of the Renewable Energy Alaska Project — a nonpro t aimed at increasing “clean energy” across the state. During a roundtable on Cook Inlet’s natural gas production on KBBI’s Coffee Table on Wednesday, he said once the most easily accessible gas reserves in Cook Inlet are depleted, Alaska won’t have enough alternatives readily available to replace them in a short period of time. 3/28/23, 9:54 AM Kenai Peninsula analysts say looking to renewable energy options is crucial amid Cook Inlet natural gas decline https://www.kdll.org/2023-02-27/kenai-peninsula-analysts-say-looking-to-renewable-energy-options-is-crucial-amid-cook-inlet-natural-gas-decline 4/6 Erin McKittrick, a Seldovia-based writer and former scientist, who’s been analyzing energy and gas issues for years. She also is a member of the Homer Electric Association board of directors, but was not participating on behalf of the board. She said the state made an effort to boost natural gas production the last time there was a gas crisis imminent, in 2010, through the Cook Inlet Recovery Act. “The state basically paid about one-and-a-half-billion dollars of credits to Cook Inlet producers over the time period. I think it ended in 2016,” McKittrick said. “And we've been paying back and still owe over $200 million on those credits.” A 2015 report from the Alaska Oil and Gas Association says after the legislature took action, boosted oil production by 80% across its 16 platforms. “The substantial increase in investment and economic growth on the Kenai Peninsula shows no signs of slowing down,” the nearly decade-old report says. However, last month, the Alaska Division of Oil and Gas presented an updated forecast to the Alaska House Finance Committee that tells a different story. According to the 2022 Cook Inlet Gas Forecast Report, gas production in Cook Inlet will fall below demand by 2027, assuming demand for that gas stays the same and that there’s no production from currently undeveloped gas prospects. Geologist and citizen scientist Bretwood Higman of Seldovia said the new report emphasizes the fact that Alaska is only a few years away from needing decisive and effective action — an action that could take many forms. “Either nding some way to increase supply so that there could be some new source within Cook Inlet, it could be natural gas imports, or we need to reduce our demand," Higman said. "That could be replacing natural gas with other renewable energy. It could also be just improving e ciency and how we use the natural gas we have.” McKittrick, a retired scientist, said there would be pros and cons to each solution. For example, relying on other states to accommodate the demand will increase household heating expenses. 3/28/23, 9:54 AM Kenai Peninsula analysts say looking to renewable energy options is crucial amid Cook Inlet natural gas decline https://www.kdll.org/2023-02-27/kenai-peninsula-analysts-say-looking-to-renewable-energy-options-is-crucial-amid-cook-inlet-natural-gas-decline 5/6 © 2023 KDLL Contact Us FCC Public Inspection File “So if that price increases, as our gas supply dwindles, and we potentially bring in impor ted gas, then that's just going to directly pass through onto your bill in that line item and be substantially bigger,” she said. Utilities like Homer Electric Association and private companies like Renewable IPP are exploring renewable options that could potentially become active producers of energy in a short amount of time, according to Higman. “That's what I really hope we'll see: that wind and solar being operational soon,” he said. “And in the meantime, we need to be exploring geothermal and tidal, we could also talk about things like pumped hydro storage.” Tags K e n a i P e n i n s u l a N e w s Simon Lopez Simon Lopez is a long time listener of KBBI Homer. He values Kachemak Bay’s beauty and its overall health. Simon is community oriented and enjoys being involved in building and maintaining an informed and proactive community. See stories by Simon Lopez On Point KDLL State sues feds over critical habitat designation for seals along Slope page 3 l FINANCE & ECONOMY l EXPLORATION & PRODUCTIONsee INSIDER page 8 Willow gathers support; AK House, defense experts tout production ON FEB. 20, THE ALASKA HOUSE voted unanimously in favor of House Joint Resolution 6 in support of the development of the Willow project in the National Petroleum Reserve in Alaska. HJR 6 by Rep. Josiah Patkotak, I- Utqiaġvik, urges the U.S. Department of the Interior to support the responsible develop- ment of resources in the petroleum reserve and issue a positive final record of decision for the Willow project, recognizing that responsible resource development today equips Alaska’s communities to make investments in technology and infrastructure to support the use of renewable sources creating a balanced and affordable energy outlook for Alaskans. “The unanimous passage of this resolution highlights the House’s acknowledgment of the importance of responsible resource development in Alaska,” said Rep. Calvin Schrage, NP-Anchorage. “This project will help ensure we have the resources needed to make critical investments to diversify our energy portfolio and expand renewable energy access.” see ALKAID 2 WELL page 11 see ANWR RESPONSE page 10 Biden administration responds on ANWR, says no laws contravened In a federal District Court in Alaska case, in which the Alaska Industrial Development and Export Agency is chal- lenging a Department of the Interior decision to suspend oil and gas lease related activities in the Arctic National Wildlife Refuge, the Biden administration has responded to a request for summary judgement by the plaintiffs in the case. The administration argues that the suspension does not infringe any laws and reflects a need to rework the evaluation of the potential environmental impacts of the lease related activities. The Tax Cuts and Jobs Act, passed by Congress in 2017, required the Department of the Interior to conduct oil and gas lease sales for the ANWR coastal plain. And in August 2020 DOI issued an environmental impact statement for the lease sale program, under the terms of the National Environmental Policy Act. The Bureau of Land Management subsequently conducted the first lease sale for the coastal plain in January 2021. AIDEA, Knik Arm Services LLC and Regenerate Vol. 28, No. 9 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of February 26, 2023 • $2.50 l EXPLORATION & PRODUCTION ANS below $80 ANS at discount to Brent; Chinese demand could drive prices up in 2023 By STEVE SUTHERLIN Petroleum News Alaska North Slope crude plunged $2.24 Feb. 22 to close at $77.48 per barrel, while West Texas Intermediate dropped $2.21 to close at $73.95 and Brent plummeted $2.45 to close at $80.60. In a trading week that saw ANS slide out of the low $80s range it has enjoyed most days of February, Feb. 22 marked its low for the week, and was its second lowest close for the month, follow- ing its close of $76.90 Feb. 3. ANS ended January above $80, but dropped into the upper $70s Feb. 1, following a price pat- tern that has been in place since late 2022 that has seen ANS displaying relative stability — trading in a range within several dollars of $80. Brent closed above $80 for the entire month of February, save for a close of $79.94 Feb. 3. Brent has maintained a premium of some $3.00 over ANS in 2023, at a time when Russian oil trad- ing has been constrained due to its invasion of Ukraine, and a formal G7 coalition price cap on Russian seaborne crudes became effective Feb. 5. China and India have been eagerly buying up dis- counted Russian crude as a result. Even as China has stepped up crude purchases Mustang start September? Spill plan app hints at AIDEA sale of Southern Miluveach assets to Finnex By KAY CASHMAN Petroleum News It appears the deal between Finnex Operating LLC, or FOLLC, and the Alaska Industrial Development and Export Authority, or AIDEA, may soon close, with operations on the Mustang Pad in the Southern Miluveach unit scheduled to begin in September 2023. The start date comes from FOLLC’s recent application for a new Southern Miluveach Oil Discharge Prevention and Contingency Plan, which it filed with the Alaska Department of Environmental Conservation, or DEC. The FOLLC deal with AIDEA, which seeming- ly fell apart once, was to purchase the assets of the five-lease Southern Miluveach unit, including its Mustang drilling and production pad, the Mustang Road and the 1,050-foot Mustang Pipeline which ties into the Alpine Pipeline just southeast of the Mustang Pad. The unit lies between the Kuparuk River and Colville River units on the North Slope and is adjacent to Oil Search (Alaska)’s Quokka unit. The Mustang Pad’s loca- tion was listed in the application as: Latitude/Longitude: 70 2486 / 150 2806. The application for a new spill plan for the Producing inlet gas Cook Inlet natural gas producers describe issues, production, plans for future By KRISTEN NELSON Petroleum News What is being done to offset declin- ing natural gas production in Alaska’s Cook Inlet? Three Cook Inlet operators, including the two largest and a company with a significant but undevel- oped natural gas field, talked to the Alaska House Special Committee on Energy on Feb. 21. Hilcorp Alaska is Cook Inlet’s major natural gas producer, operating more than 90% of Cook Inlet gas by volume in December; Furie Operating Alaska operated some 5% of inlet natural gas pro- duction in that month, the most recent for which Alaska Oil and Gas Conservation Commission data by field is available; and BlueCrest, primarily an oil producer with associated gas, accounted for less than 1% of inlet gas production. Hilcorp Asked about Hilcorp’s warning to Cook Inlet utilities about long-term con- tracts, Luke Saugier, Hilcorp’s senior vice president Alaska, said the utilities are Hilcorp’s customers and the company wants to give them as much transparency as possible. All fields decline, he said, and over the past 5 years, see OIL PRICES page 9 see MUSTANG START page 9 see INLET GAS page 8 Drill, test, build in a single season on Alaska’s North Slope In recent releases of information about Alkaid 2 well test- ing Pantheon Resources has talked about its nearby produc- tion facility which took only a year to build. The modular facility, which is on skids, can handle multi- ple wells. It appears to be a balancing act for Pantheon between the Alaska Oil and Gas Conservation Commission and the com- pany’s desire to have a facility in place that will allow its oper- ator Great Bear Pantheon to move quickly into production should the Alkaid 2 exploration well’s long-term production test be successful. AOGCC approved flaring in association with a long-term production test of the well, but in three-month increments, not the nine months requested by the company. A Pantheon spokesman told Petroleum News in a Feb. 17 email that “the facility was designed in-house, with the pri- mary components assembled in Ft Nelson Canada and then GORDON POSPISIL LUKE SAUGIER Hilcorp has been the only company drilling wells in Cook Inlet. Hilcorp is maintaining its supplies, he said, but hasn’t seen other companies drilling, which is not an ideal situation, because without drilling the gas supply will decline. Hilcorp is doing everything it can, he said, but if the market needs more, there isn’t an infinite supply and Hilcorp has contracted for all the gas it has. Redundancy is important for deliver- ability of gas, Saugier said, and Hilcorp maintains three of the four gas storage operations in the inlet. The Kenai gas field is the company’s largest storage facility, with one reservoir dedicated to storage with 540 billion cubic feet of storage available and 12 bcf in storage today, stored at low pressure and sent through compressors when the company wants to remove it. At Swanson River, Hilcorp maintains high-pressure gas storage, with a 3 bcf capacity. Think of this, Saugier said, as an emergency supply which would flow nat- urally even if there was no power. The smallest, and the only storage on the west side, is Pretty Creek. He said this is very small, almost 1 bcf, and typically empties every winter. The company also has redundant com- pressors and multiple delivery points to pipelines, Saugier said. Hilcorp in Alaska Hilcorp began operating in Cook Inlet in 2012 and has spent more than $750 mil- lion on capital projects in the inlet since then, with those projects directed to pro- duction of natural gas, Saugier said. Over the next 10 years the company plans to spend that much or more, he said. In addition to drilling and doing workovers, Saugier said Hilcorp has brought new and innovative technologies to the inlet, including new drilling rigs, new offshore and onshore pulling units and new vendors. It has also applied mod- ern technology, 3D seismic, improved stimulation and horizontal drilling. The company owns two rigs, he said, one working on the west side and one working on the Kenai Peninsula, rigs which have been used by other operators. Looking ahead, Saugier said the com- pany is investing in new wells, wellwork to add production rates and exploration and drilling, and plans to invest hundreds of millions of dollars per year in Kenai and Cook Inlet, with four rigs operating in 2023, 18 wells planned and 41 wells to be plugged and abandoned. Furie John Hendrix, president and CEO of Furie Operating Alaska, said the compa- ny’s goal is to increase its gas production. Furie produces natural gas only from its platform in Cook Inlet at the Kitchen Lights unit. Hendrix told the committee HEX Cook Inlet purchased Furie in July 2020. Since then, he said, they have stabilized pro- duction, providing natural gas to Enstar, Marathon Petroleum, Matanuska Electric Association, Homer Electric Association, Chugach Electric Association and the Interior Gas Utility. In 2023, he said, the company plans to finalize re-processing of 3D seismic and well data and mobilize a new workover rig to Alaska to work over and repair two wells, 50% of the unit’s four producing wells. Hendrix said the goal is to increase production for the winter of 2023-24. But there is uncertainty, he said, over the cost and the duration of the work, with issues including mobilization of the new rig to Cook Inlet, potential difficulties in performing the work and the impacts of weather, especially later in the season. Hendrix urged the state to reduce roy- alties and provide production tax relief, as well as releasing seismic data, providing a just and fair property tax, reducing bond- ing obligations and eliminating duplica- tive bonding requirements. BlueCrest BlueCrest President and CEO Benjamin Johnson told the committee that BlueCrest, which produces oil with asso- ciated gas at its Cosmopolitan field on the Kenai Peninsula, has a separate gas field. The Tyonek gas sands, which lie above the oil reservoirs the company is currently producing, are too shallow to be reached from onshore wells, he said. Multiple wells have been drilled through the gas zones, which have a proved but undeveloped volume of 234 billion cubic feet with flow tests con- firming high produc- tivity, and the size and shape of the structure document- ed by 3D seismic. Johnson said the gas zones are similar to the Ninilchik field, some 15 miles to the north and currently the largest Cook Inlet gas producer. The gas at Tyonek was discovered in the Starichkof State 1 drilled in 1967 and confirmed in the Cosmopolitan State 1 drilled in 2013, both drilled by jack-up rigs, with flow tests done at the 2013 well. Johnson said there are 12 gas sands at the Cosmopolitan Tyonek gas field, which is “proved” but undeveloped. Because of the requirement for a plat- form, it will cost hundreds of millions to develop that resource, Johnson said, but it could produce up to 50 million cubic feet per day. Johnson said this is dry gas, with no liquid hydrocarbons. It would require a 3- mile subsea pipeline to the company’s onshore facility, and he said recent seafloor surveys confirm a safe pipeline route, while the onshore facility is already connected to the Enstar pipeline system. The design of platform and facilities and cost estimates are largely completed, he said, with the platform gas wells to be done with standard Cook Inlet drilling and completion. From funding to first gas would be 30 to 40 months, Johnson said. He said the critical path is finding investors. l 8 PETROLEUM NEWS • WEEK OF FEBRUARY 26, 2023 Alaska’s Marine Transpo Compan cookinlettug.comon #1 rtatio ny. We take pride in p excellent services and challenging ewww.cproviding s in a very environmen “I’m grateful for the amendment supported in the resources commit- tee to include a broader context embracing the development and implementation of renewable energy here in Alaska,” said Rep. Donna Mears, D-Anchorage. “Renewable development in Alaska supports not only a future of lower and more stable energy prices, but a more diverse, stable economy over the long run as well.” “The benefits of the Willow project cannot be under- stated,” said Rep. Louise Stutes, R-Kodiak. “Whether we’re talking about job creation and workforce develop- ment, increased revenue to the state for essential services, or national security, I am happy to see that we all agree that this project will help build a brighter future for Alaskans.” Defense experts affirm importance IN A MID-FEBRUARY HEARING of the Senate Armed Services Committee, or SASC, several defense policy experts testified to the importance of domestic energy production as a critical strategic advantage for the United States relative to America’s main adversaries, China and Russia. The witnesses were responding to ques- tions posed by U.S. Sen. Dan Sullivan, R-Alaska, a senior SASC member, who asked whether it serves U.S. national security inter- ests to produce more oil and gas — such as the massive pending Willow project on the North Slope of Alaska — or to seek energy supplies from the regimes in Venezuela and Saudi Arabia. The witnesses testifying before the committee were Dr. Bonny Lin, senior fellow on Asian Security at the Center for Strategic & International Studies; Dr. Fiona Hill, senior fellow at the Brookings Institution; and Roger Zakheim, director at the Ronald Reagan Presidential Foundation and Institute. Below is a shortened transcript of the senator’s exchange with the witnesses. SULLIVAN: I’m going to turn to another topic that is all about American strategy. And that’s energy. I’m glad to see Senator Manchin, Senator Mullin, they’ve raised this. A very memorable meeting I had many years ago with our former chairman here, Senator McCain, and a Russian dissident, a very brave Russian dissident who’s now in jail, Vladimir Kara-Murza. I had asked him what more can we do to undermine the Putin regime? What more can we do to go after Putin and the oligarchs. He said, “It’s easy, Senator, number one thing you can do as a country is produce more American energy.” Number one. Do you agree with that, Dr. Hill, Mr. Zakheim? American energy is a really important tool of American power to deal with great powers like Russia and China? HILL: Well, I would say yes, writ large, together with our allies and rethinking our energy posture, so absolutely. ZAKHEIM: Yes. SULLIVAN: Thank you. Dr. Lin, someone else who’s very scared of American energy dominance is Xi Jinping. You read the reporting. It makes him very nervous. I was just in the Middle East. Sixty percent of China’s oil and gas goes through the Straits of Hormuz. If we’re in a con- flict with them, we could shut that down in 10 minutes. Is American energy dominance important for us — all the above, oil, gas, renewables, but certainly oil and gas —is that important for our competition with China? LIN: Absolutely. And China imports about 70% of its oil. So it is a huge dependency that China needs to work around. —Oil Patch Insider is compiled by Kay Cashman continued from page 1 INSIDER REP. JOSIAH PATKOTAK SEN. DAN SULLIVAN continued from page 1 INLET GAS JOHN HENDRIX BENJAMIN JOHNSON Homer Electric Association General Manager Brad Janorschke testifies before the Senate Resources Committee on Wednesday, Feb. 1, 2023, in Juneau, Alaska. (Screenshot via Gavel Alaska) Senate group briefed on future of Cook Inlet gas Demand for Cook Inlet gas could outpace supply as soon as 2027 By Ashlyn O'Hara Wednesday, February 1, 2023 9:46pm ❙NEWS ALASKA LEGISLATURE HOMER ELECTRIC ASSOCIATION LOCAL NEWS NEWS STATE NEWS News Sports Outdoors and Recreation Opinion Life Arts and Entertainment Jobs Obituaries Marketplace The heads of Alaska’s Railbelt utilities said Wednesday that clean energy projects and new natural gas solutions are among the ways they plan to ll the gap between demand and supply of Cook Inlet natural gas, which a new state report says is getting smaller. Homer Electric Association General Manager Brad Janorschke, Chugach Electric Association CEO Arthur Miller, Matanuska Electric Association CEO Tony Izzo, and Golden Valley Electric Association President and CEO John Burns presented Wednesday to the Alaska Senate Resources Committee. The City of Seward is also included in the Railbelt region, but did not have a representative in attendance. The 2022 Cook Inlet Gas Forecast, which was released last week by the Alaska Department of Natural Resources’ Division of Oil and Gas, found that demand for Cook Inlet gas could outpace supply as soon as 2027 without additional development and investment in the basin’s active elds. DNR Commissioner-Designee John Boyle, who presented the report to the same Senate committee on Monday, told committee members that the report is a “snapshot in time.” The report, he said, assumes demand for natural gas will remain at, at 70 billion cubic feet per year, and does not take into consideration potential increases in demand over time or the e ect of energy substitutes or e ciencies. “Fundamentally, we have to remember that, ultimately, oil and gas is a nite resource,” Boyle said Monday. “It doesn’t continue inde nitely and the Cook Inlet basin has been producing oil and natural gas now for more than 60 years.” Alaska’s Railbelt electric system spans 700 miles and provides power to more than 75% of the people in Alaska. Per the Alaska Department of Natural Resources, the Cook Inlet basin has been the “exclusive source of natural gas for over six decades,” for communities on the railbelt. Even though the report found that there are 820 billion cubic feet of proved gas reserves that would be “economic to develop,” key uncertainties include production costs and the rate of return companies require to invest in new projects. Jhonny Meza, a commercial analyst with the Alaska Department of Natural Resources, told committee members Monday that Hilcorp Alaska LLC accounts for about 85% of gas production and about 78% of oil production in Cook Inlet. Hilcorp was the sole bidder in separate state and federal oil and gas lease sales held in late 2022 and early 2023. The Railbelt utilities said Wednesday that they have a few things that can help “ ll the gap” between predicted supply and demand, such as by diversifying their energy portfolio. “Certainly a critical issue facing the Railbelt utilities is the continued decline of Cook Inlet gas reserves, and there’s no question utilities have bene ted signi cantly over the last 60 years of really a reliable, very a ordable supply of natural gas,” Miller said Wednesday. “But the situation is changing.” That may include pursuing clean energy projects and exploring solutions to natural gas. Clean energy projects could look like solar or hydro power, while natural gas solutions may include expanding gas lines from the North Slope and import opportunities. “That’s not the direction we want to take,” Miller said regarding the import of natural gas. “We think that … would be a very unfortunate situation, (for) a state as rich as Alaska is with natural gas to have to import LNG. However, we recognize we need gas, we want to have a competitive price for that gas, and, if that’s what it will take to get gas then we will pursue that.” HEA in November celebrated the completion of a battery energy storage system capable of storing 93 megawatt hours of power that can be used in the event of lost power generation. The Kenai Peninsula Borough also last year approved new tax exemptions for independent power producers after one expressed interest in building a solar farm near Sterling that would sell power to HEA. Alaska State Senate hearings can be streamed on the Alaska Legislature website at akleg.gov. Reach reporter Ashlyn O’Hara at ashlyn.ohara@peninsulaclarion.com. News Sports Outdoors and Recreation Opinion Life Arts and Entertainment Obituaries Search E-Edition Classi eds Weather Newsletters Media Solutions Subscribe About Us Contact Us Printer’s Ink Accessibility Bringing you the news, and views, of the Kenai since 1970 Subscribe Today DATE DESCRIPTION TOPIC AND AUDIENCELOCATION TEAM MEMBERMarch 22, 2023 Host/Presenter Alaska Rural Power Plant Operator Working Group Quarterly Meeting Virtual Justin TuomiMarch 21, 2023 Legislative Hearing AEA Overview Presentation to House Energy Committee Virtual Curtis W. ThayerMarch 16, 2023 Legislative Hearing AEA Overview Presentation to House Finance Committee Virtual Curtis W. ThayerMarch 15, 2023 Media Interview GRIP Grant Timeline, Brian Kassof, Alaska Energy Transparency Project Phone Curtis W. ThayerMarch 15, 2023 Host/Presenter Alaska NEVI Pre-Application Presentation to Public In-Person/Virtual Josi HartleyMarch 15, 2023 Host/Presenter Bulk Fuel Working Group with Multiple statewide Agencies In-Person/VirtualBill Price Khae PasaoMarch 10, 2023 Host/Presenter Alaska Electric Vehicle Working Group Technical Session: Uptime Requirements Presentation In-Person/Virtual Josi HartleyMarch 9, 2023 Host/Presenter Alaska Wind Working Group Quarterly Meeting In-Person/Virtual AEAMarch 8, 2023 Presenter AEA Hydropower Opportunities with Change to Alaska Section of the American Water Resources Association In-Person Bryan Carey, PEMarch 7, 2023 Host/Presenter State Energy Security Plan Advisory Group Meeting In-Person/Virtual Rebecca GarrettMarch 7, 2023 Brief Remarks2023 Alaska Sustainable Energy Conference: Pre-Event Workshop 1: Low Carbon Energy Transitions WorkshopVirtual Curtis W. ThayerMarch 3, 2023 Media Interview Solar Projects in Alaska, Alex Kay, Alaska Business Phone Curtis W. ThayerMarch 3, 2023 Media Interview Opportunities in the Latest Energy Infrastructure Bill, Sabine Poux, KDLL Phone Curtis W. ThayerFebruary 21, 2023 Presenter AEA Hydropower Opportunities Presentation to Alaska Dam Owners In-Person Bryan Carey, PEFebruary 9, 2023 Panelist Inflation Reduction Act to Alaska Forum on the Environment In-Person Conner EricksonFebruary 9, 2023 Presenter Alaska NEVI Plan Overview to Kenai Peninsula Workshop In-Person Taylor AsherFebruary 7-10, 2023 Attendee NASEO Energy Policy Outlook Conference In-Person Curtis W. ThayerFebruary 4-10, 2023 Meetings AEA Overview to Alaska Congressional Delegation, Washington, DC In-Person Curtis W. ThayerFebruary 1, 2023 Presenter AEA Update Alaska Power Association State Legislative Conference In-Person Curtis W. ThayerFebruary 1, 2023 Panelist Energy Committee Panel to Southeast Conference Mid-Session Summit and Transportation Symposium In-PersonCurtis W. ThayerAEA COMMUNITY OUTREACHLast Updated on March 28, 2023 (6-Month Look Back) 813 W Northern Lights Blvd, Anchorage, AK 99503 • Phone: (907) 771‐3000 Fax: (907) 771‐3044 • Email: info@akenergyauthority.org • Website: akenergyauthority.org DATE DESCRIPTION TOPIC AND AUDIENCELOCATION TEAM MEMBERJanuary 27, 2023 Media Interview AEA update, Tim Bradner, Alaska Economic Report Phone Curtis W. ThayerJanuary 26, 2023 Legislative Hearing AEA Susitna-Watana Presentation to House Energy Committee VirtualCurtis W. Thayer Bryan CareyJanuary 24, 2023 Attendee Idaho National Laboratory Alaska Visit In-Person Curtis W. ThayerJanuary 24, 2023 Presenter AEA State Energy Security Plan Presentation to SESP Committee Virtual Audrey Alstrom, PEJanuary 19, 2023 Presenter Alaska NEVI Plan Overview to Alaska EV Working Group In-Person/Virtual Josi HartleyJanuary 12, 2023 Exhibitor Alaska NEVI Plan to Anchorage Transportation Fair In-Person Taylor AsherJanuary 12, 2023 Presenter Alaska Draft Preventing Outages and Enhancing the Resilience of the Electric Grid In-Person/VirtualConner Erickson Daniel MillerDecember 15, 2022 Host/Presenter Bulk Fuel Working Group with Multiple statewide Agencies In-Person/VirtualBill Price Khae PasaoDecember 13, 2022 Presenter Grid Resiliency Program Presentation Public Meeting #3 In-Person/Virtual Conner EricksonDecember 12, 2022 Roundtable Northwest Arctic Leadership Team's Winter Summit In-Person Curtis W. ThayerDecember 9, 2022 Presenter State Energy Security Plan Presentation to the Bradley Lake Project Management Committee In-Person Rebecca GarrettDecember 8, 2022 Media Interview Alaska Electric Vehicle (EV) Infrastructure Plan, Jenny Willoughby, KTNA Virtual Curtis W. ThayerDecember 8, 2022 Presenter Alaska NEVI Plan Presentation to the Alaska Municipal League Annual Local Government Conference In-Person Josi HartleyDecember 7, 2022 Presenter Alaska EV Infrastructure Plan Presentation to All Hazards Planning Committee Virtual Dan AicherDecember 7, 2022 Panelist AEA Update to Alaska Municipal League Annual Local Government Conference In-Person Curtis W. ThayerDecember 7, 2022 Presentation AEA Update Presentation to Alaska Power Association Board of Directors Meeting In-Person Curtis W. ThayerDecember 6, 2022 Presentation AEA Overview Presentation to the General Consulate of Canada In-Person Curtis W. ThayerNovember 28, 2022 Presentation Alaska EV Infrastructure Plan Presentation to National Association of Women in Construction In-Person Josi HartleyNovember 23, 2022 Media Interview Renewable Energy Fund Round 15, Matt Wilson, KSRM Radio Kenai Phone Curtis W. ThayerNovember 17, 2022 Presentation Bradley Lake and Dixon Study Plan Presentation to Public Agencies In-Person/Virtual Bryan Carey, PENovember 15, 2022 Attendee/Presenter Financing Food Security in Alaska Presentation to Governor's Food Security Workshop In-PersonCurtis W. Thayer Tim SandstromNovember 9, 2022 Presenter Alaska EV Infrastructure Plan Presentation to Alaska Municipal Climate Network Virtual Taylor AsherNovember 3, 2022 Presenter Alaska EV Infrastructure Plan Presentation to Juneau Decision Makers In-Person Audrey Alstrom, PENovember 2, 2022 Meeting Alaska EV Infrastructure Plan Presentation Discussion with AELP & SE Conference In-Person Audrey Alstrom, PEOctober 27, 2022 Media Interview Approved Bonding for Transmission Upgrades and Battery Storage, Sabine Poux, KDLL Phone Curtis W. ThayerAEA Community OutreachPage 2 of 3 DATE DESCRIPTION TOPIC AND AUDIENCELOCATION TEAM MEMBEROctober 20-21, 2022 Table Alaska EV Infrastructure Plan Presentation to Alaska Federation of Natives Annual Convention In-Person Taylor AsherOctober 24, 2022 Presenter Alaska EV Infrastructure Plan Presentation to Wasilla City Council In-Person Taylor AsherOctober 20, 2022 Table Alaska EV Infrastructure Plan Presentation to Mat-Su Transportation Fair In-Person Dan AicherOctober 14, 2022 Media Interview Alaska’s EV Infrastructure Deployment Plan, Alex Bengel, KTVF 11 Phone Curtis W. ThayerOctober 11-14, 2022 Attendee National Association of State Energy Officials Annual Meeting In-Person Curtis W. ThayerOctober 13, 2022 Presenter Alaska EV Infrastructure Plan Presentation to The Alliance In Person Taylor AsherOctober 10, 2022 Public Comment Alaska EV Infrastructure Plan Presentation to Fairbanks City Council Phone Taylor AsherOctober 6, 2022 Presenter Energy and Infrastructure in Alaska Presentation to Seward Chamber of Commerce In Person Curtis W. ThayerSeptember 30, 2022 Press Conference Governor's Signs Administrative Order No. 340 Press Conference In Person Curtis W. ThayerSeptember 29, 2022 Media Interview Alaska’s EV Infrastructure Deployment Plan, Dan Bross, KUAC Radio Phone Curtis W. ThayerAEA Community OutreachPage 3 of 3 Meet Alaska hears CCUS details that could generate revenue for state page 5 l FINANCE & ECONOMY l EXPLORATION & PRODUCTION see PIKKA PROJECT page 11 Minor changes to Pikka project approved by state DO&G On March 16, Alaska’s Division of Oil and Gas approved Oil Search (Alaska)’s March 7 request to amend the Pikka Development Project Phase 1 plan of operations. Oil Search (Alaska), or OSA, a sub- sidiary of Santos Ltd., provided the divi- sion with a project update and associated figures that reflect current Phase 1 activi- ties in the Pikka unit. The project, which is located west of the central North Slope, was initially called the Nanushuk Development Project, which explains why each of the pad names begin with ND — ND-A, ND-B, and ND-C. Also, note that the Phase 1 pad ND-B is located approximately 12 miles north- east of the community of Nuiqsut. In its March 16 decision the division said the updates from OSA are a result of “incremental advancements in project design, construction methods, and operational requirements,” noting OSA has adopted a scaled, or phased, approach strategy to project development, in which the first phase would provide the cash needed for subsequent phases. Pikka Phase I has advanced through front end engineering and design, or FEED, and achieved a final investment decision for the project in August 2022. Plan of operations activities include the following: • Drill 43 horizontal wells at ND-B. —22 production wells —21 injector wells for enhanced oil recovery • Drill one disposal well at ND-B to accommodate the Grind and Inject facility • Install infield pipeline connecting ND-B to Nanushuk see SPRING FORECAST page 8 Oil prices, production down in state’s Spring Revenue Forecast Oil prices and oil production are both down, driving the Alaska Department of Revenue’s Spring Revenue Forecast down for fiscal year 2023 and FY 2024 and beyond, compared to the Fall Revenue Forecast released in mid- December. In December, unrestricted general rev- enue — before transfer from the Permanent Fund Earnings Reserve — for FY 2023 was forecast at $3.9 billion and $3.4 billion for FY 2024. The Spring Revenue Forecast, released March 23, forecasts unrestricted general revenue at $3.6 billion for FY 2023 and $2.7 billion for FY 2024, a drop of $0.3 bil- lion for FY 2023 and $0.7 billion for FY 2024. Both the ANS West Coast oil price and North Slope produc- tion are down from the fall forecast, and in that forecast they were down from the spring 2022 forecast. In the current spring forecast, the ANS West Coast price for FY 2023 is $85.25 per barrel, down $3.20 per barrel, 3.6%, from a fall ANS West Coast price of $88.45 per barrel. In FY 2022, the actual price averaged $91.41 per barrel. The FY 2024 price is now forecast at $73 per barrel, down $8, 9.9%, from a forecast of $81 per barrel in the fall. The forecast price is down from the spring forecast for the entire forecast period, through FY 2032. On the production side, Alaska North Slope volumes are fore- cast lower for every fiscal year except one, FY 2031, for the Vol. 28, No. 13 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of March 26, 2023 • $2.50 KEVIN GALLAGHER l ALTERNATIVE ENERGY Demand fears ease 6 million barrel US gasoline supply drop boosts rally off bank panic lows By STEVE SUTHERLIN Petroleum News Alaska North Slope crude gained ground March 22, up 95 cents to close at $74.13. West Texas Intermediate and Brent lofted sharply into the close on dovish Federal Reserve com- ments, following a widely expected quarter point jump in the benchmark federal funds rate from 4.75% to 5%. WTI leapt $1.57 to close at $70.90 and Brent popped $1.37 to close at $76.69. Prices were supported by a healthy, larger than expected draw on U.S gasoline and distillate fuel reserves. Total motor gasoline inventories for the week ending March 17 decreased by 6.4 million barrels from the previous week, standing 4% below the five-year average for the time of year, the U.S. Energy Information Administration said in its March 22 report. Distillate fuel inventories fell by 3.3 million barrels for the period, to a level 9% below the five-year average for the time of year. U.S. commercial crude inventories rose just 1.1 million barrels for the period to 481.2 million bar- rels, 8% above the five-year average for the time Another step forward Oil Search files Pikka Nanushuk pool rules, estimates 592-868 million barrels By KRISTEN NELSON Petroleum News As Oil Search continues to move toward pro- duction at its Pikka unit on the North Slope, the company has applied to the Alaska Oil and Gas Conservation Commission for pool rules for the Nanushuk oil pool at Pikka. Oil Search (Alaska) LLC, the Pikka unit opera- tor, a subsidiary of Santos Ltd., submitted the March 6 pool rules application on behalf of itself and Repsol E&P USA LLC, the other working interest owner. The company said that prior to beginning injec- tion it will apply to AOGCC for an area injection order to authorize water-alternating-gas, WAG, for the proposed Nanushuk oil pool. Oil Search said the area proposed for the Nanushuk pool rules coincides with the Pikka unit boundary. “The Nanushuk Oil Reservoir does extend out- side the unit boundary to the south and to the west of the Pikka Unit into leases operated by ConocoPhillips Alaska,” Oil Search said, with the extent of the Nanushuk “proven by recent delin- eation wells drilled in those areas as well as recent seismic interpretations.” The Nanushuk Oil Pool is the accumulation between measured depths of 3,892 and 5,166 feet REAP argues renewables With prospect of gas imports, should Railbelt transition to renewable energy? By ALAN BAILEY For Petroleum News As part of a continuing debate over the future of the Alaska Railbelt electrical system, in a March 16 meeting of the House Energy Committee Chris Rose, executive director of Renewable Energy Alaska Project, made the case for using renewable energy power generation and moving away from the current dependence on natural gas fueled power. Currently, much of the power generation in the southern sector of the Railbelt is provided by gas fueled generators, with the gas coming from oil and gas fields in the Cook Inlet. But, with uncer- tainty about the future availability of sufficient gas from the inlet, electric utilities are evaluating their future power supply options. In a Feb. 1 presenta- tion to the Senate Resources Committee, the CEOs of the utilities said that total supplies of natural gas will likely fall below demand after 2027 and, after that point, it will probably become necessary to import liquefied natural gas to bolster local gas supplies. High and volatile LNG pricing Rose expressed REAP’s disagreement with this position, saying that LNG in the Pacific market is much more expensive than Cook Inlet gas and that the LNG pricing is highly volatile. The result see OIL PRICES page 9 see POOL RULES page 10 see RENEWABLE ENERGY page 12 ADAM CRUM The bank panic oil price swoon not only is speculative, but oil will hit $140 a barrel by the end of the year, Andurand told the FT Commodities Global Summit in Lausanne, Switzerland. would be a sharp increase in the cost of Railbelt electricity coupled with volatile electricity pricing, Rose said. Moreover, with increasing prices for natural gas in Southcentral Alaska, the cost of using gas for heating buildings would also increase. Rising prices for electricity in the Railbelt would also adversely impact electricity costs in rural Alaska, given that the power cost equalization program that provides state funding assistance for rural energy is in part indexed to the cost of electricity in the Railbelt, Rose said. Rather than importing LNG, the Railbelt electrical system should move towards the use of renewable energy sources such as wind and solar energy, Rose said. The cost of renewable energy has dropped dramatically in recent years — wind and solar energy are now both cheaper than gas fueled power, even in the Lower 48, where gas prices are signif- icantly lower than in Southcentral Alaska, Rose said. Over the past 10 years the price of solar has dropped 90%, the cost of wind has come down 70% and the cost of batteries, used to regulate the varying renewable energy, has dropped 70%, he said. And renewable energy has stable and predictable pricing, given that much of the cost emanates from the amortization of construction costs. A renewable portfolio standard Rose favors the use of a renewable portfolio standard to drive the buildup of renewable energy deployment. An RPS sets targets for the increases in renewable energy use, with penalties for the utilities if those targets are not met. At this point 31 states have renewable portfolio stan- dards, Rose said. Last year Gov. Dunleavy introduced a bill to the state Legislature for creating an RPS, with a target of rais- ing renewable energy use from its current level of 15% of total generation to a level of 80% by 2040. Senate Bill 101, current- ly in the Legislature, proposes an RPS with a requirement for electricity utilities in the state to have at least 25% renewable power by Dec. 31, 2027; 55% renewable power by Dec. 31, 2035; and 80% renew- able power by Dec. 31, 2040. Rose said that the National Renewable Energy Laboratory has conducted a study into the practicalities of achieving the pro- posed Alaska RPS goals and has found that the goals are achievable. NREL is still conducting a study into the potential cost of meeting the goals. However, consulting company Analysis North has estimated a capital cost of $3.2 billion to achieve the 80% renewables target using the NREL model. That capital cost would potentially save around $6.7 billion in natural gas purchases, Rose said. However, NREL in its model assumed that transmission sys- tem upgrades and battery installations needed for the renewables would be required, regardless of whether the power generation moves away from natural gas. Renewable energy intermittency A critical issue for the widespread implementation of wind and solar energy is the intermittency of these energy sources — wind power, for example, varies in response to the fluctuating strength of the wind. Electricity utilities must have the means of compensating for these fluctuations, to maintain a stable voltage and frequency in the electrical system. And the possibility of drops in renewable power output raises questions over the risks of power outages. During the Senate Resources meeting, Tony Izzo, chief executive officer of Matanuska Electric Association, said that his utility would need to retain significant gas fired power generation to ensure elec- tricity supply reliability as the amount of renewable energy increases. In the House Energy meeting Rose argued that supply reliability can be main- tained through the use of industrial scale batteries to balance supply variations. Homer Electric recently installed a major new battery system in its network, while Chugach Electric Association and Golden Valley Electric Association are in the process of obtaining similar systems for their networks. It is also possible that more batteries will be needed within an RPS’s 17-year timeframe for achieving 80% renewable use, Rose commented. The other issue relating to power sup- ply reliability is a plan that the utilities are proposing for upgrading the Railbelt transmission system. The concept is to significantly increase the power carrying capacity of the system and to eliminate single points of failure in the system. As previously reported by Petroleum News, the utilities are applying to the Department of Energy for funding assis- tance for the upgrades, under the terms of the DOE’s Grid Resilience and Innovation Partnership. Upgrades to the transmission system could enable more sharing of power across the system, thus enabling more smoothing out of power generation varia- tions across the region, Rose said. For example, wind power from the Fairbanks region could help the Anchorage region when there is no wind in Anchorage, and vice versa, he said. The Railbelt Reliability Council Another significant factor feeding into the future of Railbelt electricity supplies is the recent RCA certification of the Railbelt Reliability Council as the electric reliability organization for the Railbelt high-voltage electrical system. The RRC is in the process of establishing its organi- zation and of seeking RCA approval for its initial budget and tariff. The RRC will maintain and mandate reliability standards for the Railbelt’s high voltage electrical system; administer rules for open access to the transmission grid; and conduct Railbelt-wide system planning. Clearly the future use of renewable energy will become a key factor in system planning. Moreover, open access to the grid will significantly improve the eco- nomics of the implementation of renew- able systems by independent power pro- ducers, Rose said. Under the current arrangements each utility owning some sector of the grid charges its own fees for transmitting power across its sector, thus resulting in the pancaking of transmission fees for power transmitted over long dis- tances across the system. Open access to the grid would probably involve a single “postage stamp” rate for any use of the transmission system. And while the utilities tend not to have room on their balance sheets for the con- struction of new power generation facili- ties, the independent power producers that typically build renewable energy systems can obtain the capital and take the associ- ated financial risks, Rose said. Moreover, the development of renew- able energy systems would use local resources and create local jobs, rather than exporting millions of dollars from the economy to pay for imported LNG. “The era of really affordable renew- ables is here,” Rose said. l continued from page 1 RENEWABLE ENERGY 12 PETROLEUM NEWS • WEEK OF MARCH 26, 2023 Harbo vvNa h ev pe O or Services that M vigating the W ur team o deliver ersonaliz very clie lf eedsour NYoMeet Y aters with EasWaW m of experts is committed ing quality service and zed attention to each an ent, ensuring a smooth a i se: d nd and Photo courtesy of N. Hamlin haassle-fre rn more e: (907) 24 ee experience. at wwww..cookinlettug.c 8-0179 | Email: info@cookinlettu com. ug.com sands are secondary targets. Net zero project In its Aug. 17 press release, Santos said Pikka Phase 1 has “strong funda- mentals, is located in a world-class oil producing province with significant existing infrastructure, has low unabat- ed emissions intensity and is supported by key stakeholders, including the State of Alaska, the North Slope Borough, the landowner company Kuukpik Corporation and the Arctic Slope Regional Corporation (ASRC).” Taking an FID, or final investment decision, on Pikka Phase 1 is “consis- tent with Santos’ goal of achieving net- zero (scope 1 and 2, equity share) by 2040,” Santos said in the Aug. 17 press release. Santos said it is “committed to deliv- ering a net-zero project (scope 1 and 2, equity share) and has entered into Memorandums of Understanding with Alaska Native corporations to deliver carbon offset projects, including a “strategic alliance with ASRC Energy Services, a wholly-owned subsidiary of ASRC, on leading technology develop- ment for carbon solutions in the Arctic.” “Santos has emission reduction plans to achieve scope 1 and 2 net-zero emissions by 2040 and in-line with that commitment, Pikka will be a net-zero project,” Santos Managing Director and Chief Executive Officer Kevin Gallagher said. —KAY CASHMAN continued from page 11 PIKKA PROJECT Today, Alaska Governor Mike Dunleavy revised the Alaska Energy Security Task Force and announced its members. The Governor issued Administrative Order 344 on February 23, 2023, establishing the task force. The task force has been revised to include the Lieutenant Governor as the Chair and add an additional public seat, increasing the number of voting members from 13 to 15. The Energy Security Task Force, as revised in Administrative Order 345, focuses on Alaska’s efforts to reduce the cost of energy for Alaskans. “Alaska is an oil and gas giant, but we are all in for every form of energy – wind, solar, hydro, tidal, geothermal, micronuclear, and hydrogen,” said Governor Dunleavy. “I have full confidence in these members of the Energy Security Task Force to identify tactics to reduce the cost of energy for Alaskans during this exciting time of energy innovation in Alaska. “I am honored to sit as the Governor ’s Energy Security Task Force chair,” said Lt. Governor Dahlstrom. “Together, we will work on a plan to reduce Alaska’s vulnerability to fluctuating energy markets by securing dependable and affordable energy for Alaskan residents.” The Alaska Energy Security Task Force will consist of 15 voting members and three ex officio members appointed by and serving at the pleasure of the Governor. The voting members are as follows: • Lieutenant Governor Dahlstrom (Chair of the Task Force) • Commissioner Jason Brune (Commissioner of the Department of Environmental Conservation) • Commissioner John Boyle (Commissioner of the Department of Natural Resources) • Curtis Thayer (Vice Chair of the Task Force) (The Executive Director of the Alaska Energy Authority) • Gwen Holdman (Vice Chair of the Task Force) (Member from the University of Alaska with a background in energy) • Clay Koplin, Cordova Electric Cooperative (Member from a utility that represents rural Alaska or a community receiving power cost equalization) • Nils Andreassen, Alaska Municipal League (Member who represents a city, borough, or municipality) • Tony Izzo, Matanuska Electric Association (Member with a Railbelt utility background) • John Simms, Enstar (Member from the oil and gas industry) • Karl Hanneman, International Tower Hill Mines (Member from the mining industry) • Robert Venables, Southeast Conference (Member with a background in economic development) • Andrew Guy, Calista Corporation (Member from the business community) • Jenn Miller, Renewable Independent Power Producers (Member from any segment of the Alaskan energy industry) Governor Dunleavy Announces Energy Security Task Force Members Mar 22, 2023 • Duff Mitchell, Juneau Hydropower (Member of the general public) • Isaac Vandenburg, Launch Alaska (Member of the general public) “We are committed to making sure Alaskans have access to energy that is affordable, reliable, and redundant,” said AEA Executive Director Curtis W. Thayer. “The members of this task force cover a wide array of knowledge and perspectives. Together, we will provide an effective platform for ensuring that a statewide energy plan is comprehensive with a focus on long- term solutions. “Addressing the challenge of providing affordable, reliable energy to our communities is vital to Alaska’s long-term economic and social well-being,” said Gwen Holdmann, Associate Vice Chancellor for Research, Innovation & Industry Partnerships; University of Alaska Fairbanks. “I am honored to work with this diverse group of Alaskans to develop a sustainable path toward energy independence for the state. Alaskans are innovators, and I believe that in working together, we can come up with creative strategies to meet our energy needs for today, and for the future.” The ex officio members are as follows (plus the two seats from the legislature): • Commissioner Keith Kurber (Member of the Regulatory Commission of Alaska) • Garrett Boyle (Representative from the Denali Commission) • Erin Whitney (From the U.S. Department of Energy, Arctic Energy Office) • Senator Click Bishop (District R) • Representative George Rauscher (District 29) The Task Force shall deliver an initial report to the Governor by May 19, 2023, and the Task Force will sunset on October 31, 2023. Administrative Order No. 345 I, Mike Dunleavy, Governor of the State of Alaska, under the authority of Article III, Sections 1 and 24 of the Alaska Constitution, and in accordance with AS 44.19.145(c), hereby revoke Administrative Order 344, establishing the Alaska Energy Security Task Force (“Task Force”), and issue this Administrative Order 345, reinstating the Task Force with a revised membership and reporting structure. BACKGROUND On September 30th, 2022, Governor Dunleavy established the Office of Energy Innovation to provide a central point of focus for Alaska’s efforts to reduce the cost of energy for residents. Alaskans suffer from exorbitantly high energy costs, restricted energy supply, and limited opportunities to drive down energy costs to consumers. Consequently, energy security and affordability are critical to Alaska’s prosperity going forward. The Task Force will provide recommendations on overall energy policy for the State of Alaska, as well as strategies and tactics to achieve its goal of reducing the cost of energy to Alaska residents. PURPOSE The purpose of the Task Force is to develop a comprehensive statewide energy plan that will evaluate energy generation, distribution, and transmission for the State of Alaska and its communities. The development of this plan will include collaboration with public and private stakeholders. The statewide energy plan, including proposed timelines and milestones, will be presented to the governor upon completion. MEMBERSHIP The Alaska Energy Security Task Force will consist of fifteen voting members and five ex officio members appointed by and serving at the pleasure of the governor. The governor shall select a Chair and two Vice- chairs from the voting members. The voting members are as follows: • Lieutenant Governor Dahlstrom. • The Commissioner of the Department of Environmental Conservation, or the Commissioner ’s designee. • The Commissioner of the Department of Natural Resources, or the Commissioner ’s designee. • The Executive Director of the Alaska Energy Authority, or the Executive Director ’s designee. • One member from the University of Alaska with a background in energy. • One member from a utility that represents rural Alaska or a community receiving power cost equalization. • One member who represents a city, borough, or municipality. • One member with a Railbelt utility background. • One member from the oil and gas industry. • One member from the mining industry. • One member with a background in economic development. • One member from the business community. • One member from any segment of the Alaskan energy industry. • Two members of the general public. The five ex officio members are as follows: • One member from the Regulatory Commission of Alaska. • One representative from the Denali Commission. • One representative from the U.S. Department of Energy, Arctic Energy Office. • One member of the Alaska State Senate, appointed by the Senate President, and one member of the Alaska House of Representatives, appointed by the Speaker of the House. DUTIES AND RESPONSIBILITIES The Task Force’s comprehensive energy plan shall include the following: • Establish a baseline energy portfolio for the State of Alaska. • Identify and evaluate potential future changes that could occur to energy supply and distribution in the state, the impacts of such changes, and the opportunity for mitigating impacts and leveraging opportunities associated with such change. • Identify solutions for meeting Alaska’s energy needs now and in the future with a focus on affordability, reliability, and security. • Identify policies, programs, regulatory changes, and funding that could accelerate adoption of these energy strategies. • Develop and maintain a public database of taskforce information and recommend strategies for sharing energy data and information through an energy data portal. • Recommend a statewide energy goal, a plan to achieve it, and identify additional work that may be required to refine this vision. The Task Force shall deliver an initial report to the Governor by May 19, 2023 . Once the report is received, further clarification and deliverables may be identified that would require additional work by the Task Force. The Chair of the Task Force shall report regularly to the Office of the Governor on activities conducted and issues that arise under this Order. ADMINISTRATIVE SUPPORT The Task Force is assigned to the Governor ’s Office of Energy Innovation for administrative purposes. GENERAL PROVISIONS Consistent with law and available appropriations, each designated state agency shall use existing personnel and monetary resources to comply with this Order. Task Force members receive no compensation or other remuneration from the state for their service as members; however, members of the Task Force who are not state or federal employees are entitled to per diem and travel expenses in the same manner permitted for members of state boards and commissions under AS 39.20.180. Per diem and travel expenses for members of the Task Force who are a representative of a state or federal agency are the responsibility of that agency. The Task Force may create advisory-only subcommittees. The Task Force will meet monthly, at a minimum. Additional meetings may be called by the Chair. The Task Force and its subcommittees will use teleconferencing and other electronic means, to the extent practicable, in order to gain maximum public participation at minimum cost. At times and locations to be determined by the Chair, the Task Force may convene public meetings to present information and receive comments. Meetings of the Task Force and any subcommittee shall be conducted in accordance with AS 44.62.310 – 44.62.319 (Open Meetings Act). Records of the Task Force and any subcommittee are subject to inspection and copying as public records under AS 40.25.100 – 40.25.295 (Alaska Public Records Act). EFFECTIVE DATE AND DURATION This Order takes effect immediately. The Task Force will sunset on October 31, 2023. DATED this 22nd day of March, 2023. 3/28/23, 12:21 PM States to receive $2.5B from feds for electric vehicle charging infrastructure - Alaska Beacon https://alaskabeacon.com/2023/03/14/states-to-receive-2-5b-from-feds-for-electric-vehicle-charging-infrastructure/1/4 D.C. BUREAU ECONOMY & ENVIRONMENT States to receive $2.5B from feds for electric vehicle charging infrastructure BY: JACOB FISCHLER - MARCH 14, 2023 11:20 AM Electric vehicles are displayed before a news conference with White House Climate Adviser Gina McCarthy and U.S. Secretary of Transportation Pete Buttigieg about the American Jobs Plan and to highlight electric vehicles at Union Station near Capitol Hill on April 22, 2021, in Washington, D.C. The federal government will send $2.5 billion over the next ve years to states, local governments and tribes to build electric vehicle charging infrastructure, Biden administration o cials said Tuesday. (Photo by Drew Angerer/Getty Images) The federal government will send $2.5 billion over the next ve years to states, local governments and tribes to build electric vehicle charging infrastructure, Biden administration o cials said Tuesday. 3/28/23, 12:21 PM States to receive $2.5B from feds for electric vehicle charging infrastructure - Alaska Beacon https://alaskabeacon.com/2023/03/14/states-to-receive-2-5b-from-feds-for-electric-vehicle-charging-infrastructure/2/4 The new Charging and Fueling Infrastructure grant program, which was authorized by the 2021 bipartisan infrastructure law, will spend $2.5 billion over ve years to build electric vehicle charging stations and refueling infrastructure for hydrogen, propane or natural-gas vehicles. Administration o cials told reporters in a press call Monday the program would help President Joe Biden meet his goal of 500,000 public charging stations by the end of the decade. O cials briefed reporters on the condition they would not be named. Biden has also set a goal of reducing national greenhouse gas emissions by at least half by 2030. Gas-powered vehicles account for about one-quarter of U.S. greenhouse gas emissions. The grant funding will be evenly split between designated alternative-fuel corridors and public facilities like parking lots, schools and parks. “With today’s announcement, we are taking another big step forward in creating an EV future that is convenient, a ordable, reliable, and accessible to all Americans,” U.S. Transportation Secretary Pete Buttigieg said in a written statement. Applications for the rst two years of funding, which will include $700 million in grants, opened Tuesday and are due by May 30. The grant program adds to other recent federal spending on electric vehicle charging stations. Each state will also receive a share of a separate $1.5 billion fund the federal government made available for charging stations last year. Each state developed a plan for building an electric vehicle charging network. The Federal Highway Administration, the Transportation Department agency that administers federal highway funding to states, approved each state plan last year. States will not have to apply for grants to receive funding under that program, instead receiving funding based on a predetermined formula that factors in things like population and miles of road. Last month, the administration nalized standards for charging stations, including a requirement that components will eventually have to be sourced in the United States. Most material needed for electric vehicle charging stations is not yet available domestically. SUPPORT NEWS YOU TRUST. D O N A T E 3/28/23, 10:46 AM In this issue: EV Infrastructure Standards, Buy America Waiver, and RFA Dates https://mailchi.mp/bfbbb954c915/aea-submits-ev-infrastructure-plan-to-joint-office-13511731?e=[UNIQID]1/8 View this email in your browser Alaska Electric Vehicle Working Group Newsletter, March 9, 2023 Standards Published for EV Infrastructure Imagine driving down the road without knowing where the next gas station will be, what type of fuel it will dispense, if it will be open, and what type of payment option it will accept. Sounds stressful, right? Luckily, gas stations are fairly standardized — we know that most pumps will be open even if the building is closed, we can pay with a credit card, gasoline and diesel will be available, and the pump will work — so we rarely worry about fueling up. The Joint Office of Energy and Transportation recently published the final National Electric Vehicle Infrastructure (NEVI) Minimum Standards and 3/28/23, 10:54 AM In this issue: EV Infrastructure Standards, Buy America Waiver, and RFA Dates https://mailchi.mp/bfbbb954c915/aea-submits-ev-infrastructure-plan-to-joint-office-13511731?e=[UNIQID]2/8 Requirements, which sets new national standards to make charging EVs convenient and reliable for all Americans, including when driving long distances. These final rules were published after taking into consideration public comments on the proposed rules that were released in the fall of 2022. All electric vehicle (EV) charging station sites constructed using NEVI program funds must adhere to them. The purpose of the rules is to increase public confidence in the reliability of EV charging sites by ensuring that any site funded with NEVI program funds is built to a high and reliable standard. The Alaska Energy Authority and the Alaska Department of Transportation and Public Facilities will distribute the first round of NEVI formula funding to Alaska with the March 1 release of the Request for Applications (RFA) soliciting EV charging station site hosts, so the release of these final rules comes at an opportune time. Final Rule Highlights The document that contains the final rules outlines the requirements for NEVI- funded charging sites to remain compliant with the program, as well as includes commentary on why certain decisions were made. On a broader level, the rules address these six specific areas: 1. Installation, operation, and maintenance by qualified technicians 2. Interoperability and standardization of the EV charging network 3. On-site traffic control devices and signs 4. Data submittal requirements 5. Network connectivity of EV chargers 6. Standard communication to consumers about the price and availability of EV chargers Rules Summarized: There must be public transparency in how the price is set for EV charging. In addition to traditional card payment options, users must also be able to pay via a toll-free phone number or SMS (text message), and not need to have any special apps or memberships to do so. Along the Alternative Fuel Corridor (AFC), which in Alaska is from Anchorage to Fairbanks, each station must have four network-connected Direct Current Fast Chargers (DCFC) that are available 24/7. Outside of AFCs, each station must still have four ports, but they can have a combination of DCFC and Level 2 chargers. 3/28/23, 10:46 AM In this issue: EV Infrastructure Standards, Buy America Waiver, and RFA Dates https://mailchi.mp/bfbbb954c915/aea-submits-ev-infrastructure-plan-to-joint-office-13511731?e=[UNIQID]3/8 Each port must have an annual uptime greater than 97 percent. Downtime due to vandalism, natural disasters, and other exclusions are not included in the uptime requirement calculation. Each station along the AFC must be able to supply at least 150 kW to each port simultaneously. Power sharing among ports is allowed, but only above the 150 kW level. Each DCFC must have a Combined Charging System (CCS) type 1 charger. Non-proprietary connectors (North American Charging Standard (NACS) and CHAdeMO) are also allowed so long as each port can charge a CCS-compliant vehicle. All electricians involved with installing, operating, or maintaining chargers must be certified by the Electric Vehicle Infrastructure Training Program (EVITP). If a project has more than one electrician working on it, at least one of the electricians must be in an apprenticeship program. Build America, Buy America Act Waiver The Joint Office also released guidance for final waivers to the Build America, Buy America Act. These waivers will temporarily allow exceptions to the Buy America Act, which was enacted as part of the Bipartisan Infrastructure Law and requires that all iron, steel, manufactured products, and construction materials used in infrastructure projects (like building and installing NEVI EV chargers) be produced in the United States. These waivers are intended to ease the transition into Buy America requirements and help get EV charging sites constructed quickly without overwhelming domestic manufacturers. 3/28/23, 10:46 AM In this issue: EV Infrastructure Standards, Buy America Waiver, and RFA Dates https://mailchi.mp/bfbbb954c915/aea-submits-ev-infrastructure-plan-to-joint-office-13511731?e=[UNIQID]4/8 Effective March 23, 2023, all EV chargers must undergo final assembly in the United States. Effective July 1, 2024, all EV chargers must undergo final assembly in the United States, AND over 55 percent of the cost of components must be manufactured in the United States. By October 1, 2024, all EV chargers manufactured prior to July 1, 2024, must be installed if they were paid for with NEVI funds. Throughout this process, all EV charger housing components that are primarily made of steel and iron do not fall under this waiver and must meet Buy America requirements, meaning they must be made and manufactured in the United States. So how will these final rules and Buy America waivers impact you? That depends! If you are a prospective site host, electric utility, EV supply equipment manufacturer, or someone else directly involved in the construction of charging stations, it will be important to thoroughly read through the final rules since they could impact your work. If you are an EV enthusiast, driver, or someone who plans on utilizing the newly constructed NEVI charging stations, get ready for reliable and consistent charging and a better consumer experience! 3/28/23, 10:46 AM In this issue: EV Infrastructure Standards, Buy America Waiver, and RFA Dates https://mailchi.mp/bfbbb954c915/aea-submits-ev-infrastructure-plan-to-joint-office-13511731?e=[UNIQID]5/8 Technical Session, March 10 AEA will hold a Technical Session on Friday, March 10, 2023, from noon-1 p.m. to discuss electric vehicle (EV) charging station uptime requirements. This is a hybrid meeting. You can attend in person at the AEA office in the Denali Room, located at 813 West Northern Lights, Anchorage Alaska, 99503, or participate virtually by using the link below. Join via Zoom by clicking here Meeting ID: 883 6578 4659 3/28/23, 10:46 AM In this issue: EV Infrastructure Standards, Buy America Waiver, and RFA Dates https://mailchi.mp/bfbbb954c915/aea-submits-ev-infrastructure-plan-to-joint-office-13511731?e=[UNIQID]6/8 Passcode: 419619 833 548 0282 US Toll-free 877 853 5257 US Toll-free 888 475 4499 US Toll-free 833 548 0276 US Toll-free Pre-Application Meeting, March 15 AEA will hold a Pre-Application meeting for the National Electric Vehicle Infrastructure (NEVI) Request for Applications (RFA) on Wednesday, March 15, 2023, from 11:30 to 1 p.m. This is a hybrid meeting. You can attend in person at the AEA office in the Board Room, located at 813 West Northern Lights, Anchorage Alaska, 99503, or participate virtually by using the link below. Join via Zoom by clicking here Meeting ID: 899 3521 4010 Passcode: 622255 877 853 5257 US Toll-free 888 475 4499 US Toll-free 3/28/23, 10:46 AM In this issue: EV Infrastructure Standards, Buy America Waiver, and RFA Dates https://mailchi.mp/bfbbb954c915/aea-submits-ev-infrastructure-plan-to-joint-office-13511731?e=[UNIQID]7/8 833 548 0276 US Toll-free 833 548 0282 US Toll-free Resources EV Charging Minimum Standards Rule as Submitted to Federal Register for Publication (Unofficial) (dot.gov) Federal Register: Waiver of Buy America Requirements for Electric Vehicle Chargers FACT SHEET: Biden-Harris Administration Announces New Standards and Major Progress for a Made-in-America National Network of Electric Vehicle Chargers - The White House Biden-Harris Administration Announces Latest Steps to Deliver a National Network of Convenient, Reliable, Made-in-America Electric Vehicle Chargers | FHWA (dot.gov) Alaska NEVI RFA | AEA (akenergyauthority.org) Important RFA Dates March 1, 2023 - Request for Applications (RFA) Release March 15, 2023 - Pre-Application Meeting from 11:30 a.m. to 1 p.m. March 23, 2023 - Pre-Application Questions Due May 1, 2023 - Applications Due by 4 p.m. Facebook LinkedIn Website The Alaska Energy Authority’s Alaska Electric Vehicle Working Group involves collaborative stakeholders focused on promoting the use of electric vehicles (EVs) in Alaska by removing barriers to EV adoption and increasing access to charging infrastructure. Stay up to date on AEA's EV efforts at our website here. Global race to boost electric vehicle range in cold weather https://apnews.com/article/electric-vehicles-cold-weather-battery-ev-6d86b7aa19e233d5dcc4d2c9abb193ed 1/7 Global race to boost electric vehicle range in cold weather By TOM KRISHER and MARK THIESSEN March 4, 2023 GMT TOK, Alaska (AP) — Alaska’s rugged and frigid interior, where it can get as cold as minus 50 Fahrenheit (minus 46 Celsius), is not the place you’d expect to find an electric school bus. But here is Bus No. 50, with a cartoon horse decal on its side, quietly traversing about 40 miles of snowy and icy roads each day in Tok, shuttling students to school not far from the Canadian border. Global race to boost electric vehicle range in cold weather https://apnews.com/article/electric-vehicles-cold-weather-battery-ev-6d86b7aa19e233d5dcc4d2c9abb193ed 2/7 It works OK on the daily route. But cold temperatures rob electric vehicle batteries of traveling range, so No. 50 can’t go on longer field trips, or to Anchorage or Fairbanks. It’s a problem that some owners of electric passenger vehicles and transit officials are finding in cold climates worldwide. At 20 degrees F (minus 7 C), electric vehicles just don’t go as far as they do at the ideal 70 degrees. Part of it is that keeping passengers warm using traditional technology drains the battery. So longer trips can be difficult in the coldest weather. Transit authorities like Chicago’s, which has pledged to convert its whole bus fleet to electricity by 2040, have to take extraordinary steps to keep electric buses charged and on schedule. Some automakers and drivers fear lower battery range in the cold could limit acceptance of electric cars, trucks and buses, at a time when emissions from transportation must go down sharply to address climate change. There is hope. Scientists are racing to perfect new battery chemistries that don’t lose as much energy in cold weather as today’s lithium-ion systems. Also, cars equipped with efficient heat pumps don’t lose as much range in the cold. “It is a problem to have batteries in cold weather, and we have a pretty cold climate, one of the coldest in North America,” said Stretch Blackard, owner of Tok Transportation, which contracts with the local schools. When the temperature hits zero, his cost to run Tok’s electric bus doubles. Tok has among the highest electricity prices in the nation. Global race to boost electric vehicle range in cold weather https://apnews.com/article/electric-vehicles-cold-weather-battery-ev-6d86b7aa19e233d5dcc4d2c9abb193ed 3/7 Stretch Blackard, owner of Tok, Transportation, poses with an electric school bus on Feb. 2, 2023, in Tok, Alaska. (AP Photo/Mark Thiessen) In the coldest weather, 0 down to minus 10 F (minus 18-23 C) the electric bus costs roughly $1.15 per mile, versus 40 cents per mile for a diesel bus, Blackard said. The cost of the electric bus drops to about 90 cents a mile when it’s warm, but he says the costs make it unworkable and he wouldn’t buy another one. Many owners of personal electric vehicles also are finding that long-distance wintertime travel can be hard. EVs can lose anywhere from 10% to 36% of their range as cold spells come at least a few times each winter in many U.S. states. Mark Gendregske of Alger, Michigan, said it starts to get serious when temperatures drop to the 10-20 F range (minus 7 to minus 12 C). “I see typically more than 20% degradation in range as well as charging time,” he Global race to boost electric vehicle range in cold weather https://apnews.com/article/electric-vehicles-cold-weather-battery-ev-6d86b7aa19e233d5dcc4d2c9abb193ed 4/7 said while recharging his Kia EV6 in a shopping center parking lot near Ypsilanti, Michigan. “I go from about 250 miles of range to about 200.” Gendregske, an engineer for an auto parts maker, knew the range would drop, so he said with planning, the Kia EV still gets him where he needs to go, even with a long commute. Mark Gendregske of Alger, Michigan, charges his Kia EV6, Friday, Feb. 10, 2023, in Ypsilanti, Mich. (AP Photo/Carlos Osorio) Some owners, though, didn’t anticipate such a big decline in the winter. Rushit Bhimani, who lives in a northern suburb of Detroit, said he sees about 30% lower range in his Tesla Model Y when the weather gets cold, from what’s supposed to be 330 miles per charge to as low as 230. “They should clarify that one,” he said while charging just south of Ann Arbor on a trip to Chicago. Around three-quarters of this EV range loss is due to keeping occupants warm, but speed and even freeway driving are factors. Some drivers go to Global race to boost electric vehicle range in cold weather https://apnews.com/article/electric-vehicles-cold-weather-battery-ev-6d86b7aa19e233d5dcc4d2c9abb193ed 5/7 great lengths not to use much heat so they can travel farther, wearing gloves or sitting on heated seats to save energy. And to be sure, gasoline engines also can lose around 15% of their range in the cold. The range loss has not slowed EV adoption in Norway, where nearly 80% of new vehicle sales were electric last year. An electric car charges in a parking lot of a shopping mall in Tallinn, Estonia, Feb. 11, 2023 (AP Photo/Pavel Golovkin) Recent tests by the Norwegian Automobile Federation found models really vary. The relatively affordable Maxus Euniq6 came the closest to its advertised range and was named the winner. It finished only about 10% short of its advertised 354 km (220 mile) range. The Tesla S was about 16% percent under its advertised range. At the bottom: Toyota’s BZ4X, which topped out at only 323 kilometers (200 miles), nearly 36% below its advertised range. Global race to boost electric vehicle range in cold weather https://apnews.com/article/electric-vehicles-cold-weather-battery-ev-6d86b7aa19e233d5dcc4d2c9abb193ed 6/7 Nils Soedal, from the Automobile Federation, calls the issue “unproblematic” as long as drivers take it into account when planning a trip. “The big issue really is to get enough charging stations along the road,” and better information on whether they’re working properly, he said. Temperatures ranged from just freezing to minus 2.2 F (0 to minus 19 C) during the test, over mountains and along snow-covered roads. The cars were driven until they ran out of juice and stopped. Recurrent, a U.S. company that measures battery life in used EVs, said it has run studies monitoring 7,000 vehicles remotely, and reached findings similar to the Norwegian test. CEO Scott Case said many EVs use resistance heating for the interior. The ones that do better are using heat pumps. Heat pumps draw heat from the outside air even in cold temperatures, and have been around for decades, but only recently have been developed for automobiles, Case said. “That is definitely what needs to be in all of these cars,” he said. Inside batteries, lithium ions flow through a liquid electrolyte, producing electricity. But they travel more slowly through the electrolyte when it gets cold and don’t release as much energy. The same happens in reverse, slowing down charging. Neil Dasgupta, associate professor of mechanical and materials science engineering at the University of Michigan, likens this to spreading cold butter on toast. “It just becomes more resistant at low temperatures,” Dasgupta said. Global race to boost electric vehicle range in cold weather https://apnews.com/article/electric-vehicles-cold-weather-battery-ev-6d86b7aa19e233d5dcc4d2c9abb193ed 7/7 Lawrence Ziehr, project manager for energy recovery on GM’s electric vehicles, connects to a Hummer EV to a charging station, Feb. 22, 2023, in Sault Ste. Marie, Mich. (AP Photo/Carlos Osorio) General Motors is among those working on solutions. By testing, engineers can make battery and heat management changes in existing cars and learn for future models, said Lawrence Ziehr, project manager for energy recovery on GM’s electric vehicles. Last week, GM sent a squadron of EVs from the Detroit area to Michigan’s chilly Upper Peninsula to test the impact of cold weather on battery range. Despite stopping to charge twice on the way, a GMC Hummer pickup, with around 329 miles of range per charge, made the 315 mile trip to Sault Ste. Marie with only about 35 miles left, barely enough to reach GM’s test facility. After finding a charging station out of order at a grocery store, engineers went to a nearby hotel to get enough juice to finish the trip. 3/28/23, 11:51 AM Alaska EV Tax Credits Guide | U.S. News https://cars.usnews.com/cars-trucks/advice/alaska-ev-tax-credits 1/5 Cars /Car Advice /Alaska EV Tax Credits Guide C A R S Alaska EV Tax Credits Guide Alaska's harsh climate and remote environment mean that it’s not an ideal place for EVs. Still, there are some incentives for Alaska residents who transition to EV ownership. Here’s what you need to know. By Cherise Threewitt Edited by Jill Leonard March 3, 2023 Save 3/28/23, 11:51 AM Alaska EV Tax Credits Guide | U.S. News https://cars.usnews.com/cars-trucks/advice/alaska-ev-tax-credits 2/5 The Alaska Highway Alaska isn’t known for being par ticularly sunny, and its harsh climate and remote environment mean that it’s not an ideal place for electric vehicles. Still, there are some incentives for Alaska residents who transition to EV ownership. Here’s what you need to know. As incentive programs shift over time, it is crucial that you research the most current incentives before you buy or consult a tax specialist to ensure that you qualify for a rebate or tax credit. A D V E R T I S E M E N T Does Alaska Have Tax Credits For Buying New EVs? Customers of Alaska Power and Telephone may be eligible for a rebate of $1,000 for buying a new or pre-owned EV with a minimum battery size of at least 16 kilowatts. Customers of Alaska Electric Light & Power who buy or lease an EV with a minimum battery size of at least 16 kilowatts are eligible for a time-of-use rate for charging during off-peak hours. Does Alaska Have Tax Credits For Buying Used EVs? Customers of Alaska Power and Telephone may be eligible for a rebate of $1,000 for buying a new or pre-owned EV with a minimum battery size of at least 16 kilowatts. Customers of Alaska Electric Light & Power who buy or lease an EV with a minimum battery size of at least 16 kilowatts are eligible for a time-of-use rate for charging during off-peak hours. G E T T Y I M A G E S /B R A D L E Y A T O M B E R S 3/28/23, 11:51 AM Alaska EV Tax Credits Guide | U.S. News https://cars.usnews.com/cars-trucks/advice/alaska-ev-tax-credits 3/5 Does Alaska Have Credits For Installing Home Charging Stations? Alaska residents who are customers of Chugach Electric Association may be eligible for a bill credit of up to $200 for installing a residential EV charging station and sharing charging station and EV use data. A D V E R T I S E M E N T Does Alaska Have Credits For Installing Solar Panels? There are no statewide incentives for residential solar installation in Alaska, though federal incentives may apply. Does Alaska Penalize EV Buyers? Alaska does not assess additional fees for electric vehicles. What Other EV Incentives Can I Get in Alaska? Alaska residents who purchase an EV may also qualify for the Federal Electric Car Tax Credit of up to $7,500. Alaska residents should also check with their local electric utilities for any additional credits or incentives. R E C O M M E N D E D A R T I C L E S Illinois EV Tax Credits Guide Indiana EV Tax Credits Guide Idaho EV Tax Credit SUVs With the Best Gas Mileage 3/28/23, 11:51 AM Alaska EV Tax Credits Guide | U.S. News https://cars.usnews.com/cars-trucks/advice/alaska-ev-tax-credits 4/5 The Most Reliable New Cars in 2023 Cars With the Fastest Depreciation See More » N E W C A R S U S E D C A R S I N S U R A N C E C A R R A N K I N G S A D V I C E B E S T C A R D E A L S H O W W E R A N K C A R S F O R S A L E Stock photography by izmostock. © 1986 - 2023 Autodata, Inc. dba Chrome Data About Contact Press Advertise Newsletters Jobs Site Map Store PRESS RELEASE Brandy M. Dixon Communications Director (907) 771-3078 FOR IMMEDIATE RELEASE March 1, 2023 AEA and DOT&PF Release Request for Applications for EV Charging Site Hosts Distributing millions in federal funds for local Alaskans to build EV charging infrastructure (Anchorage) — The Alaska Energy Authority (AEA) and the Department of Transportation & Public Facilities (DOT&PF) have released a Request for Applications (RFA) to solicit electric vehicle (EV) charging station site hosts as part of Alaska’s EV Infrastructure Deployment Plan (The Plan). The RFA is the first step in initiating Phase 1 of The Plan. Application packages are due back to AEA by May 1, 2023, at 4 p.m. Utilizing National Electric Vehicle Infrastructure (NEVI) formula funding, Phase 1 of The Plan focuses on building out EV charging infrastructure along Alaska’s Alternative Fuel Corridor (AFC), the 355-mile stretch of road that connects Fairbanks to Anchorage. NEVI program requirements state that charging sites be located every 50 miles along the AFC with four EV fast charging ports at each site. Alaska was granted an exception to the 50-mile requirement for the section of road between Denali State Park and Cantwell since there is no existing electric infrastructure there. “Releasing this RFA is a major step toward investing in the future of clean transportation in Alaska,” said AEA Executive Director Curtis W. Thayer. “The EV charging stations that will be built as a result of this funding will benefit all Alaskans, whether it be in the form of access to reliable charging infrastructure, the potential for increased tourism, or reducing greenhouse gas emissions.” Once EV chargers have been installed along the AFC and Phase 1 is complete, AEA and DOT&PF will move forward with implementing the remaining phases of The Plan: Phase 2: Build out Alaska’s Highway and Marine Highway System Phase 3: Install charging stations in hub communities, as funding allows Phase 4: Urban and “Destination” locations, as funding allows The NEVI program is funded through the Infrastructure Investment and Jobs Act, which was signed into law November 2021. The NEVI program will invest $5 billion across the nation over the course of five years, with Alaska receiving over $52 million between 2022-2027. For more information about the NEVI RFA and to apply, click here. If you have questions or need assistance, please email grants@akenergyauthority.org. ### The Alaska Energy Authority is a public corporation of the State of Alaska governed by a board of directors with the mission to “reduce the cost of energy in Alaska.” AEA is the state's energy office and lead agency for statewide energy policy and program development. The Alaska Department of Transportation and Public Facilities oversees 237 airports, 9 ferries serving 33 communities along 3,500 marine miles, over 5,600 miles of highway and 839 public facilities throughout the state of Alaska. The mission of the department is to “Keep Alaska Moving through service and infrastructure.” 3/28/23, 9:46 AM Governor Dunleavy Creates Alaska Energy Security Task Force to Create Comprehensive Statewide Energy Plan - Mike Dunleavy https://gov.alaska.gov/governor-dunleavy-creates-alaska-energy-security-task-force-to-create-comprehensive-statewide-energy-plan/1/2 Today Governor Mike Dunleavy issued Administrative Order 344, establishing the Alaska Energy Security Task Force. The purpose of the task force is to develop a comprehensive statewide energy plan that will evaluate the energy generation, distribution, and transmission for the State of Alaska and its communities. The development of the plan will include collaborating with both the public and private stakeholders. The statewide energy plan, including proposed timelines and milestones, will be presented to the Governor upon completion. “Despite Alaska’s position as a leading producer of energy, the cost of energy in Alaska, especially in our rural communities, is extremely high,” said Governor Mike Dunleavy. “As everyone has been reminded by the war in Ukraine, access to and cost of energy are influenced by global events. I’m establishing this task force to create a plan that will reduce Alaska’s vulnerability to fluctuating energy markets by securing dependable and affordable energy for Alaskan residents.” On September 30th, 2022, Governor Dunleavy established the Office of Energy Innovation to provide a central point of focus for Alaska’s efforts to reduce the cost of energy for residents. The Task Force will provide recommendations on overall energy policy for the State of Alaska, as well as strategies and tactics to achieve its goal of reducing the cost of energy for Alaskans. The task force’s initial report to the Governor shall be delivered by May 19, 2023. Once the report is received, further clarification and deliverables may be identified that would require additional work by the task force. The Alaska Energy Security Task Force will consist of thirteen voting members and five ex officio members appointed by the Governor. The voting members are as follows: The Commissioner of the Department of Environmental Conservation, or the Commissioner ’s designee. The Commissioner of the Department of Natural Resources, or the Commissioner ’s designee. The Executive Director of the Alaska Energy Authority, or the Executive Director ’s designee. One member from the University of Alaska with a background in energy. One member from a utility that represents rural Alaska or a community receiving power cost equalization. One member who represents a city, borough, or municipality. Governor Dunleavy Creates Alaska Energy Security Task Force to Create Comprehensive Statewide Energy Plan Feb 23, 2023 3/28/23, 9:46 AM Governor Dunleavy Creates Alaska Energy Security Task Force to Create Comprehensive Statewide Energy Plan - Mike Dunleavy https://gov.alaska.gov/governor-dunleavy-creates-alaska-energy-security-task-force-to-create-comprehensive-statewide-energy-plan/2/2 One member with a Railbelt utility background. One member from the oil and gas industry. One member from the mining industry. One member with a background in economic development. One member from the business community. One member from any segment of the Alaskan energy industry. One member of the general public. The five ex officio members of the task force are as follows: One member from the Regulatory Commission of Alaska. One representative from the Denali Commission. One representative from the U.S. Department of Energy, Arctic Energy Office. One member of the Alaska State Senate, appointed by the Senate President One member of the Alaska House of Representatives, appointed by the Speaker of the House. Alaskans interested in serving on the Alaska Energy Security Task Force may apply here: gov.alaska.gov/apply. Administrative Order No. 344 I, Mike Dunleavy, Governor of the State of Alaska, under the authority of Article III, Sections 1 and 24 of the Alaska Constitution, and in accordance with AS 44.19.145(c), hereby order the establishment of the Alaska Energy Security Task Force (“Task Force”). BACKGROUND On September 30th, 2022, Governor Dunleavy established the Office of Energy Innovation to provide a central point of focus for Alaska’s efforts to reduce the cost of energy for residents. Alaskans suffer from exorbitantly high energy costs, restricted energy supply, and limited opportunities to drive down energy costs to consumers. Consequently, energy security and affordability are critical to Alaska’s prosperity going forward. The Task Force will provide recommendations on overall energy policy for the State of Alaska, as well as strategies and tactics to achieve its goal of reducing the cost of energy to Alaska residents. PURPOSE The purpose of the Task Force is to develop a comprehensive statewide energy plan that will evaluate energy generation, distribution, and transmission for the State of Alaska and its communities. The development of this plan will include collaboration with public and private stakeholders. The statewide energy plan, including proposed timelines and milestones, will be presented to the governor upon completion. MEMBERSHIP The Alaska Energy Security Task Force will consist of thirteen voting members and five ex officio members appointed by, and serving at the pleasure of, the governor. The governor shall select two co-chairs from the voting members. The voting members are as follows: • The Commissioner of the Department of Environmental Conservation, or the Commissioner ’s designee. • The Commissioner of the Department of Natural Resources, or the Commissioner ’s designee. • The Executive Director of the Alaska Energy Authority, or the Executive Director ’s designee. • One member from the University of Alaska with a background in energy. • One member from a utility that represents rural Alaska or a community receiving power cost equalization. • One member who represents a city, borough, or municipality. • One member with a Railbelt utility background. • One member from the oil and gas industry. • One member from the mining industry. • One member with a background in economic development. • One member from the business community. • One member from any segment of the Alaskan energy industry. • One member of the general public. The five ex officio members are as follows: • One member from the Regulatory Commission of Alaska. • One representative from the Denali Commission. • One representative from the U.S. Department of Energy, Arctic Energy Office. • One member of the Alaska State Senate, appointed by the Senate President, and one member of the Alaska House of Representatives, appointed by the Speaker of the House. DUTIES AND RESPONSIBILITIES The Task Force plan shall include the following: • Establish a baseline energy portfolio for the State of Alaska. • Identify and evaluate potential future changes that could occur to energy supply and distribution in the state; the impacts of such changes; and the opportunity for mitigating impacts and leveraging opportunities associated with such change. • Identify solutions for meeting Alaska’s energy needs now and in the future with a focus on affordability, reliability and security. • Identify policies, programs, regulatory changes, and funding that could accelerate adoption of these energy strategies. • Develop and maintain a public database of taskforce information and recommend strategies for sharing energy data and information through an energy data portal. • Recommend a statewide energy goal, a plan to achieve it, and identify additional work that may be required to refine this vision. The Task Force shall deliver an initial report to the Governor by May 19, 2023. Once the report is received, further clarification and deliverables may be identified that would require additional work by the Task Force. The co-chairs of the Task Force shall report regularly to the Office of the Governor on activities conducted and issues that arise under this Order. ADMINISTRATIVE SUPPORT The Task Force is assigned to the Governor ’s Office of Energy Innovation for administrative purposes. GENERAL PROVISIONS Consistent with law and available appropriations, each designated state agency shall use existing personnel and monetary resources to comply with this Order. Task Force members receive no compensation or other remuneration from the state for their service as members; however, members of the Task Force who are not state or federal employees are entitled to per diem and travel expenses in the same manner permitted for members of state boards and commissions under AS 39.20.180. Per diem and travel expenses for members of the Task Force who are a representative of a state or federal agency are the responsibility of that agency. The Task Force may create advisory-only subcommittees. The Task Force will meet monthly, at a minimum. Additional meetings may be called by the co-chairs. The Task Force and its subcommittees will use teleconferencing and other electronic means, to the extent practicable, in order to gain maximum public participation at minimum cost. At times and locations to be determined by the co-chairs, the Task Force may convene public meetings to present information and receive comments. Meetings of the Task Force and any subcommittee shall be conducted in accordance with AS 44.62.310 – 44.62.319 (Open Meetings Act). Records of the Task Force and any subcommittee are subject to inspection and copying as public records under AS 40.25.100 – 40.25.295 (Alaska Public Records Act). EFFECTIVE DATE AND DURATION This Order takes effect immediately. The Task Force will sunset on October 31, 2023. DATED this 23rd day of February, 2023. Page 6 Legislative Digest No. 6/2023 Legislators ponder course on coastal management initiative (Cont.)Continued from page 3 – Continued at top, page 7 Governor adds to Renewable Energy Fund; bills to extend program move in Senate, House The governor’s amended FY 2024 budget would add $7.5 million to the state’s Renewable Energy Fund administered by the Alaska Energy Authority. This follows a $15 million appropriation last year to the fund for current-year FY 2023. With last year’s funding 31 new renewable projects were proposed. AEA’s recommended list will be to the Legislature in March. Since the REF’s inception $275 million has been invested in projects by the state with an additional $229 million in other funds added from local and federal sources. PCE comes up in House Energy and there is criticism Meanwhile, bills to extend the REF until 2033 moved out of committees in the House and Senate last week. The House bill, HB 62, cleared the House Energy Committee, and is now in House Rules Com- mittee, but not without some pointed questions in the Energy Committee about Power Cost Equalization, or PCE, from its Republican members. The topic of PCE came up when Gary Hennigh, city administra- tor for King Cove, described a frustrating problem with the PCE formula that has resulted in King Cove receiving no PCE support. Residents there pay rates higher than other rural communities that do receive the support. The problem occurs because King Cove took the initiative to get itself off diesel through two local hydro projects. The city was on hydro for 99 percent of its power in the last six months of 2022. Because the city has no expense for diesel for power generation its gets no PCE support. Committee chair Rep. George Rauscher, R-Palmer, was surprised at this and said he will investigate. his could open up a wide-ranging discussion of the program within the Republican House Majority. Meanwhile, there’s little doubt the legislation extending the REF will pass. It it doesn’t the REF will terminate this year. Health care: The governor’s FY 2024 budget amendments include $24 million in additional state funding for Medicaid. In his press conference the governor indicated this is to provide support for health providers. Details will be forthcoming. Bills to watch: • The governor has introduced bills in the House snd Senate on contractor-controlled insurance pro- grams. Currently the state sets limitations on these including the ability to name additional insured, which crimps the efficient management of large projects • A resolution supporting the Willow oil project is due on the floor of the Sente early this week. It matches a House resolution. Alaska Sen. Dan Sullivan asked for these to demonstrate Alaska support for the project. . . . Energy/Resources . . .