Loading...
HomeMy WebLinkAbout2024-03-06 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 Wednesday March 6, 2024 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 – January 24, 2024 and February 8, 2024 5. PUBLIC COMMENTS (2 minutes per person) see call in number above 6. NEW BUSINESS – NONE 7. OLD BUSINESS – A. Resolution 2024-01 FY25 Operating and Capital Budget 8. DIRECTOR COMMENTS A. Annual Report B. Power Cost Equalization (PCE): • PCE Annual Report • PCE Endowment Update C. Dixon Diversion Update D. SSQ Line Update E. Electric Vehicle Update F. IIJA Updates: • IIJA Tracker • AEA Training for Residential Energy Contractor Training (TREC) Program Grant Application. • GRIP 3 – Grant Agreement Update • Clean Energy Innovator Fellowship 2024 – White Paper G. Legislative Update H. Community Outreach I. Articles of Interest J. Next Regularly Scheduled AEA Board Meeting Wednesday, April 17, 2024 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 BOARD MEETING MINUTES Wednesday, January 24, 2024 Anchorage, Alaska 1. CALL TO ORDER Chair Pruhs called the meeting of the Alaska Energy Authority to order on January 24, 2024, at 8:30 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); Julie Sande (Commissioner DCCED); Adam Crum (Commissioner DOR (joined late)); 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. Motion seconded by Mr. Fogle. The motion to approve the agenda passed without objection. 4. PRIOR MINUTES – December 6, 2023 MOTION: A motion was made by Vice-Chair Kendig to approve the prior minutes of December 6, 2023. Motion seconded by Mr. Fogle. The motion to approve the minutes of December 6, 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. MOTION: A motion was made by Vice-Chair Kendig to enter into executive session to discuss confidential financial matters related to FY25 Budget, required project work and legislation, the immediate disclosure of which would have an adverse impact on the Authority. This is supported by the Open Meetings Act, AS 44.62.310, which allows a board to consider confidential matters in executive session. In this case, the board believes that these are subjects which would have an adverse effect upon the finances of AEA and are protected by law, due to the rules protecting personal privacy and certain business information. Motion seconded by Mr. Fogle. A roll call was taken, and the motion passed unanimously, with Commissioner Crum absent. Alaska Energy Authority Page 2 of 6 6. EXECUTIVE SESSION: 8:40 a.m. – To discuss confidential matters related to the FY25 Budget. The Board reconvened its regular meeting at 11:13 am. Chair Pruhs advised that the Board did not take any formal action on matters discussed while in Executive Session. 7.NEW BUSINESS A.Resolution No. 2024-02 Providing for Amendments to Resolution 2022-07 Executive Director and Secretary-Treasurer Curtis Thayer requested to hold this item for a future meeting, as a memorandum from the Department of Law regarding this issue is still pending. There was no objection. B.Resolution No. 2024-01 FY25 Operating and Capital Budget SubmissionsRatification Mr. Thayer requested to postpone this item until the March 6th meeting, as the Governor is expected to amend the budget by February 15th. There was no objection. C.Rural Emergencies Update Mr. Thayer asked Tim Sandstrom, AEA, to present the Rural Emergencies Update. Mr. Sandstrom reviewed the AEA Rural Programs and Project Highlights memo. Stabilization is occurring in four communities: Circle, Napaskiak, Manokotak, and Nelson Lagoon. He noted the ongoing problem of continuing build-up of unmet need in the state, which is reflected in the number of emergencies and interventions. Mr. Sandstrom believes that the unmet need will continue to worsen. Plans are being made to increase training and to find additional funding sources to mitigate those problems. Chair Pruhs believes the fundamental issue is that the communities are not getting the useful life out of the assets. Discussion occurred that most rural power systems are grant-funded and do not have monetary reserves to address issues. Mr. Sandstrom explained that AEA asks the Legislature for State funding and Denali Commission to match federal funding. The current Infrastructure Investment and Jobs Act (IIJA) does not have any funding available for bulk fuel rural power systems or rural powerhouses. The latest outage is Manokotak has the potential to completely drain AEA’s funding. Staff is seeking reimbursement from the State and emergency response companies. Mr. Sandstrom emphasized that AEA cannot respond to emergencies if there is no funding. Chair Pruhs asked Mr. Thayer if that information will be transmitted to the Legislature this session. Mr. Thayer agreed. He noted that staff is in contact with the Governor’s Office and the legislators whose districts are affected by the reduction in the powerhouse budget, especially the districts Alaska Energy Authority Page 3 of 6 that are on the watch list. Chair Pruhs asked if the funding for training money is well-spent. Mr. Sandstrom agreed, and believes the training is extending the life of the systems. Chair Pruhs asked if there has ever been a situation when AEA could not respond due to lack of funding. Mr. Sandstrom is not aware of such a situation. Chair Pruhs asked for the total amount of funding that is currently in reserves. Mr. Sandstrom informed that there is currently no reserve funding. Mr. Thayer stated that within the budget before the Legislature there is $200,000 for emergency funding. He discussed that AEA also maintains an inventory at the warehouse of commonly needed parts for rural Alaska systems that can be installed by staff supervisors. Chair Pruhs asked if his understanding is correct that since there is no money in the budget, if a major system problem occurred tomorrow, AEA would be unable to assist, unless emergency funding was provided from another organization. Mr. Sandstrom agreed with the explanation that creativity is allowed in the regulation if the community has a project planned in the future. In that case, AEA could provide stabilization before the project begins. Chair Pruhs asked for the number of communities that are down to one working generator. Mr. Thayer noted that the members were emailed the watch list communities. Mr. Sandstrom believes that approximately eight or nine of the communities on the watch list have only one working generator. Mr. Fogle asked if the statutes allow AEA to charge communities for the parts and services. Mr. Thayer indicated that the wording within the status is “may,” rather than “shall.” He explained that the affected communities do not have a revenue base and depend on community assistance from the State. Mr. Sandstrom discussed that communities participate to the extent that they can. Chair Pruhs asked if Department of Commerce has any funding they could provide. Mr. Sandstrom is supportive and deferred to Commissioner Sande for a response. Chair Pruhs asked if money can be included in last year’s supplemental budget. Mr. Thayer explained that deadline has passed and the supplemental budget is no longer a fast-track option. Chair Pruhs noted that 20% of the non-AVEC communities are on the watch list. To be proactive, he requested that staff submit a 9- 1-1 letter of emergency to the Governor’s Office and the Legislature for funding to last year’s true- up to the supplemental budget for the nine or 10 communities on the watch list that are down to one generator. Chair Pruhs emphasized the importance considering it is January and temperatures in the Interior are 40 below zero. Mr. Eledge asked if the lack of generator technicians in the job market is impacting the contractor options. Mr. Sandstrom agreed. He noted that AEA has tried to cast a wider net for contractors, but that there is only a limited pool of proven and trusted contractors available. Mr. Eledge asked if it is anticipated that additional contractors will be utilized to extend the optimal life of the generators. Mr. Sandstrom believes that the temporary mitigation for the problem is more contracting work and more supervisory personnel. He believes that the better answer will revolve around regionalization of the services for communities around a hub community with a locally based asset that can provide service work. Chair Pruhs commented that the entire industry is experiencing challenges due to the lack of technician personnel. Mr. Thayer gave an anecdote that highlighted the dedication and effort of AEA’s personnel to stabilize rural communities during their times of need. Alaska Energy Authority Page 4 of 6 Chair Pruhs suggested that a Board resolution is drafted to bring the issue of the dire need of the 10 rural communities to the forefront of attention so that staff will be able to respond to an emergency. Mr. Thayer indicated that resolution could be ready at a special meeting. There was no objection. 8. OLD BUSINESS – None 9. DIRECTOR COMMENTS A. Denali Commission Update Mr. Thayer noted that the update on the active Denali Commission awards is included in the Board packet. B. Power Project Fund (PPF) Loan Update Mr. Thayer discussed the PPF Loan dashboard included in the Board packet. There are no delinquencies. The fund is fully extended with the current outstanding loans and pending obligations. A request is within the budget to capitalize the program. C. Power Cost Equalization (PCE) Update Mr. Thayer advised the new PCE Program Management Report is included in the Board packet for informational purposes, as well as the earnings and cash flow report that will be provided to the Board on a quarterly basis. The Permanent Fund manages the PCE endowment, and the reports are for informational purposes. All audits are up to date. The RCA has suspended five communities for not submitting their monthly reports. The reasons for noncompliance vary by community. D. Required Legislative Submittals: • Capital Reserve Fund shortfall • Susitna River Power Project Annual Report • Renewable Energy Grant Fund (REF) Round 16 • Revised estimate of need to withdraw from Capital Reserve Fund Mr. Thayer reviewed the required legislative submittals included in the packet. Mr. Fogle asked Mr. Thayer to discuss the typical questions that the Legislature asks regarding the Susitna River Power Project during Mr. Thayer’s annual report and presentation. Mr. Thayer noted the conversations are generally positive and that the questions typically focus on the budget and the timeframe. No one has picked up the mantle to finish the FERC licensing. Mr. Thayer explained that the Governor’s Task Force recommended that the State review the financial modeling and review the FERC licenses to understand what shifts have occurred over the last 10 years to get to the point in time soon to make the go/no-go decision. Alaska Energy Authority Page 5 of 6 Mr. Fogle asked Mr. Thayer if he will be testifying to the Legislature regarding the Governor’s Task Force recommendations. Mr. Thayer indicated that he has not received notification to testify. The recommendations have been assigned to Senate Resources, Senate State Affairs, and the House Energy Committee. Mr. Thayer discussed that REF Round 16 recommended and ranked 24 statewide projects totaling $32 million. The listings are included in the Board packet. The Governor’s budget line item totals $5 million. Last year, the Legislature provided additional funding. The information is currently being considered by the Legislature. Mr. Thayer reviewed that the last required submittal included in the packet is the draft letter of the revised estimates of the need to withdraw money from the capital reserve fund. There were no questions. E. IIJA • Climate Pollution Reduction Grant (CPRG) Proposals • GRIP 3, PHASE 2 – Concept Paper Mr. Thayer discussed that the Department of Environmental Conservation (DEC) is the lead agency for the CPRG proposals. AEA submitted white papers and proposals in five categories: Electric Vehicle Charging Infrastructure, Dixon Diversion, Renewable Energy Fund, Rural Energy and DERA Expansion, and Solar For All. Mr. Thayer considers Dixon Diversion as the most important because it has the most immediate impact on displacing natural gas, start-to-finish within the next six years. Chair Pruhs asked what efforts were focused on the pollution in Fairbanks. Mr. Thayer explained that separate grants are proposed and coordinated through DEC for Fairbanks. Mr. Thayer discussed that there is current funding available for the transmission line from Kenai to Beluga. The GRIP 3, Phase 2 Concept Paper included in the Board packet was requested by the Governor to extend the transmission line from Beluga up to Healy. If the Concept Paper is accepted, AEA will be invited to apply for the grant. Mr. Thayer explained that AEA was granted $200 million in GRIP funding last year and as a result, he believes this project is less likely to be successful. There were no questions. F. Legislation: • Prefiled • Governor’s Mr. Thayer informed that there are currently no prefiled bills that affect AEA. As soon as the anticipated prefiled bills are released, they will be shared with the Board. Mr. Thayer explained that the Governor has submitted Executive Order 128 that separates the boards of AEA and AIDEA. The cover letter and EO is included in the Board packet. Alaska Energy Authority Page 6 of 6 G. Community Outreach Mr. Thayer highlighted that community outreach is quite extensive, as is shown in the provided listing. He expressed appreciation to Brady Dixon, AEA, and all those who participated in the multiple activities. H. Articles of Interest Mr. Thayer noted that the Articles of Interest are also included within the Board packet. I. Next Regularly Scheduled AEA Board Meeting Wednesday, March 6, 2024 Mr. Thayer requested that prior to the next regularly scheduled meeting, a special meeting is conducted to focus on rural emergencies and the definition of required project work. He noted that the meeting could be held via Teams and will be publicly posted. 10. BOARD COMMENTS Mr. Vivlamore expressed appreciation to Mr. Thayer and the team for the information provided today. Mr. Fogle echoed comments of appreciation to Mr. Thayer and staff for overseeing the huge and exciting influx of work that is occurring in Alaska that will help jumpstart Alaska’s economy and will provide jobs. Vice-Chair Kendig echoed the comments of appreciation for the information and hard work. He does not want to add extra burden on staff. Vice-Chair Kendig emphasized the importance of being able to provide explanations to the public, especially during these fast-moving times. Mr. Eledge requested Mr. Thayer to notify the Board when he receives the memorandum from Department of Law. Mr. Thayer agreed. Chair Pruhs reminded Board members to complete the HR required forms for both AEA and AIDEA. He thanked the Board members and staff for the good meeting today and for working for the best and betterment of the community. 11. ADJOURNMENT There being no further business of the Board, the AEA meeting adjourned at 11:49 am. ____________________________________________ Curtis W. Thayer, Secretary 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 BOARD MEETING MINUTES Thursday, February 8, 2024 Anchorage, Alaska 1.CALL TO ORDER Chair Pruhs called the meeting of the Alaska Energy Authority to order on February 8, 2024, at 2:00 pm. 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); Julie Sande (Commissioner DCCED); Adam Crum (Commissioner DOR (joined at 2:02 pm)); Bill Vivlamore (Public Member); and Randy Eledge (Public Member). 3.AGENDA APPROVAL MOTION: A motion was made by Mr. Fogle to approve the agenda. Motion seconded by Vice-Chair Kendig. The motion to approve the agenda passed without objection. 4.PUBLIC COMMENTS (2 minutes per person) There were no members of the public online or in-person who requested to comment. 5.NEW BUSINESS A.Resolution No. 2024-03 Rural Energy Infrastructure Executive Director and Secretary-Treasurer Curtis Thayer noted that Tim Sandstrom, AEA, was scheduled to present on this item, but he is in Juneau testifying on the Governor’s bill. Mr. Thayer reviewed Resolution No. 2024-03 regarding Rural Energy Infrastructure. The resolution highlights the strategies and opportunities contained within the Governor’s Alaska Energy Security Task Force report. Chair Pruhs advised that the draft resolution paperwork in the Board packet is entitled Resolution No. 2024-0x, but the final draft will be revised to Resolution No. 2024-03. Mr. Eledge asked for the estimated cost to implement the resolution. Mr. Thayer acknowledged that the total amount of deferred maintenance in rural Alaska is $1.1 billion. However, this resolution is not asking for that amount. The Governor has money in the budget for both rural powerhouses and bulk fuel and there is additional federal matching dollars available. Alaska Energy Authority Page 2 of 3 MOTION: A motion was made by Vice-Chair Kendig to approve Resolution No. 2024-03. Motion seconded by Mr. Fogle. A roll call was taken, and the motion to approve Resolution No. 2024-03 passed unanimously. 6.OLD BUSINESS – None It was noted for the record that the word “None” after Item 6. is an error. A.Resolution No. 2024-02 Providing for Amendments to Resolution 2022-07 Mr. Thayer explained that this action was delayed at the previous meeting while awaiting a memo from Department of Law, in which Law deemed the HVDC line is required project work. The 17-page memo is attorney/client privileged and has been provided to Board members. Mr. Thayer discussed that the memo identified four components that are required: 1) an affirmative vote of the Bradley Lake Management Committee (BPMC), 2) an affirmative vote of the AEA Board, 3) a third-party opinion, and 4) bondholder approval. Mr. Thayer discussed that the resolution relates to the December 2022 bonding for required project work associated with Bradley Lake of $156 million. At the time of the bonding, the HVDC project work was not considered. The GRIP grant funding received that relates to the HVDC line requires a $206.5 million State match. It has been determined that a portion of the required project work funding could be used toward the match. The last Whereas in Resolution No. 2024-02 expands the Bradley Lake project to include the underwater HVDC transmission line and limits the bond funding to no more than $20 million for the underwater HVDC transmission line and other approved projects of the Department of Energy. Section 1 includes the same expansion. Mr. Thayer explained how the $20 million amount was determined and that the State match would then be reduced to $186.5 million. Mr. Thayer noted that Les Krusen and David Grossklaus are on the line to answer questions. Mr. Krusen was AEA’s bond counsel on the original required project work bond and the counsel with the Department of Law on their opinion. Mr. Grossklaus is AEA’s external counsel related to GRIP transmission and activities. Mr. Eledge asked for an update on the status of the three other required components. Mr. Thayer indicated that last Friday, the BPMC approved their resolution to move forward. He stated that the third-party opinion was received and supportive. The opinion is included within the Board member’s public packet. The bondholder’s approval will be conducted after AEA’s affirmative vote. Mr. Eledge asked if the HVDC line is bidirectional. Mr. Thayer requested Jim Mendenhall, AEA, to answer. Mr. Mendenhall agreed, the line is bidirectional. Chair Pruhs asked if the $20 million covers the immediate cash flow for the foreseeable future. Mr. Alaska Energy Authority Page 3 of 3 Thayer stated the amount will provide cash flow for this year’s activities beginning in the spring and into the second year. Chair Pruhs asked if it is known when the reimbursement of the grant dollars will occur. Mr. Thayer explained that the finalization of the grant agreement is underway and the agreement will identify the reimbursement specifics of the dollar-for-dollar grant. No funds will be spent until the grant agreement is finalized. Chair Pruhs asked if the State must pay back all federal funding if for some reason the project does not get completed. Mr. Thayer indicated the grant agreement that is currently being drafted is expected to contain a clawback provision in which the State would have to reimburse the federal funding that is not spent. Chair Pruhs commented on the size of the $206 million commitment and asked if AEA and Mr. Thayer have the authorization to sign on behalf of the State for the agreement. Mr. Thayer indicated that before the grant agreement is signed, it will be reviewed by legal counsel to confirm its alignment. Chair Pruhs asked if the Board needs to review the finalized grant agreement before it is signed. Commissioner Crum explained that the finalized grant agreement will come to the Board for consideration and feedback prior to submittal to the Governor’s Office for approval. Mr. Mendenhall noted that the finalized grant agreement will be ready for review sometime after the March 6th Board meeting. He explained that there is a mechanism contained within the agreement for submittal and approval of prior spent money before the full Department of Energy award is made. There were no additional questions. MOTION: A motion was made by Vice-Chair Kendig to approve Resolution No. 2024-02. Motion seconded by Mr. Fogle. A roll call was taken, and the motion to approve Resolution No. 2024-02 passed unanimously. 7.Next Regularly Scheduled AEA Board Meeting Wednesday, March 6, 2024 8.BOARD COMMENTS Chair Pruhs expressed appreciation to all for attending and reviewing these important resolutions. A member echoed the comments of appreciation to staff for their efforts in preparation for this meeting. 9.ADJOURNMENT There being no further business of the Board, the AEA meeting adjourned at 2:29 pm. _______________________________________________ Curtis W. Thayer, Secretary ALASKA ENERGY AUTHORITY RESOLUTION NO. 2024-01 RESOLUTION OF THE ALASKA ENERGY AUTHORITY RATIFYING GOVERNORS SUBMISSION OF FY25 OPERATING BUDGET & CAPITAL BUDGET WHEREAS, the operating and capital budget of the Alaska Energy Authority (“the Authority”) are subject to the Executive Budget Act; WHEREAS, the FY25 operating and capital budget submissions for the Authority are included in the Governor’s State operating and capital budget submissions to the Alaska State Legislature (“the Legislature”) and are set out in Attachment A; WHEREAS, the Governor’s State operating and capital budget submissions, including the Authority’s operating and capital budget submissions, are subject to appropriation by the Legislature; and WHEREAS, the Board provides oversight for the Authority and its finances. NOW, THEREFORE, BE IT RESOLVED BY THE ALASKA ENERGY AUTHORITY AS FOLLOWS: Section 1. The Authority’s FY25 operating and capital budget submissions are ratified by the Board. The final FY25 operating and capital budget are subject to approval and appropriation by the Legislature. Dated at Anchorage, Alaska, this 6th day of March 2024. ____________________________________ J. Dana Pruhs, Chair ______________________________________ [SEAL] Curtis W. Thayer, Secretary FY24 58,120,700$ FY25 Gov Amend 60,541,800$ Federal State Other Total FY23 41,024,363$ 38,583,158$ 400,000$ 80,007,521$ FY24 143,715,793$ 49,568,579$ 193,284,372$ FY25 (Gov Amend) & FY24 Supp 69,660,093$ 14,516,579$ 84,176,672$ SSQ Upgrades HVDC GRIP BESS Total FY25 90,000,000$ 20,000,000$ 57,000,000$ 167,000,000$ Alaska Energy Authority Operating Budget Alaska Energy Authority - Capital Budget Alaska Energy Authority - Transmission/BESS Bonds AEA Receipts Federal Receipts General Fund (UGF) I/A Receipts (Other) CIP Receipts PPF (DGF) SDPR (Other) GF Program Receipts (DGF)PCE Renew Energy (DGF) FY24 (Authorized)$781 $1,209 $1,215 $124 $3,528 $996 $150 $50 $971 $1,401 FY25 (Gov Amd)$1,399 $1,209 $1,369 $124 $5,178 $996 $150 $50 $971 $1,401 $- $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 Thousands of Dollars RoundedAlaska Energy Authority Operating Budget FY24 (authorized) vs. FY25 (Gov Amd) FY24 (Authorized)FY25 (Gov Amd) AEA Receipts, $1,399 , 11% Federal Receipts, $1,209 , 9% General Fund (UGF), $1,369 , 11% I/A Receipts (Other), $124 , 1% CIP Receipts, $5,178 , 40% PPF (DGF), $996 , 8% SDPR (Other), $150 , 1% GF Program Receipts (DGF), $50 , 0% PCE, $971 , 8% Renew Energy (DGF), $1,401 , 11% Alaska Energy Authority FY25 Governor's Amended Operating Budget 23,524,363 5,383,158 28,907,521 20,443,833 1,816,579 22,260,412 33,660,093 1,816,579 35,476,672 7,500,000 5,500,000 13,000,000 11,000,000 8,000,000 19,000,000 11,000,000 2,000,000 13,000,000 200,000 200,000 200,000 200,000 200,000 200,000 5,000,000 5,000,000 - 15,000,000 15,000,000 22,052,000 22,052,000 5,000,000 5,000,000 10,000,000 10,000,000 20,000,000 25,000,000 7,500,000 32,500,000 25,000,000 2,500,000 27,500,000 2,500,000 2,500,000 400,000 400,000 5,000,000 5,000,000 12,752,540 - 12,752,540 3,000,000 3,000,000 74,519,420 - 74,519,420 - 10,000,000 20,000,000 30,000,000 40,000,000 50,000,000 60,000,000 70,000,000 Federal State Total Federal State Total Federal State Total FY2023 FY2024 FY2025 Alaska Energy Authority Capital Budget Compare FY23-FY25 (Gov Amend) IIJA Bulk Fuel Electrical Emergency Response Hydroelectric Development Renewable Energy Grant Fund Program Rural Power Systems Upgrades Strategic Plan for Railbelt Assets Volkswagen Settlement - Interest Port Electrification Defense Community Infrastructure Pilot Program Home Energy and High Efficiency Rebate Allocations IIJA, $35,476,672 Bulk Fuel, $13,000,000 Electrical Emergency Response , $200,000 Renewable Energy Grant Fund Program, $5,000,000 Defense Community Infrastructure Pilot Program, $3,000,000 Rural Power Systems Upgrades , $27,500,000 Alaska Energy Authority FY25 Gov Amend & FY24 Supp Capital Budget - $84,176,672 ALASKA ENERGY AUTHORITY Capital Budget Gov Request- FY2025 Project Name Federal Receipt Request (Gov Amd) State Funding Request (Gov Amd) Total Fund Code IIJA Efficiency Revolving Loan Fund Capitalization - Formula FY2025 $ 252,700 $ - $ 252,700 1002 - Fed Receipts IIJA - Statewide Grid Resilience and Reliability $ 12,110,523 $ 1,816,579 $ 13,927,102 1002 - Fed Receipts / 1003 G/F Match IRA Sec. 60103: Green House Gas Reduction Fund (Solar for All) $ 20,000,000 $ - $ 20,000,000 1002 Fed Receipts IRA Sec. 50123: State Based Energy Efficiency Contractor $ 1,296,870 $ - $ 1,296,870 1002 Fed Receipts Total IIJA/IRA Capital Requests: $ 33,660,093 $ 1,816,579 $ 35,476,672 Bulk Fuel Upgrades (state dollars are matching funds) $ 11,000,000 $ 2,000,000 $ 13,000,000 1002 - Fed Receipts / 1003 G/F Match Electrical Emergency Response $ - $ 200,000 $ 200,000 1004 - General Fund Renewable Energy Grant Fund - Round 16 $ - $ 5,000,000 $ 5,000,000 1004 - UGF Rural Power Systems Upgrades (state dollars are matching funds) $ 25,000,000 $ 2,500,000 $ 27,500,000 1002 - Fed Receipts /1003 G/F Match Implementation of Task Force Recommendations **Requested on Gov Amended $ - $ - 1004 - UGF Total $ 69,660,093 $ 11,516,579 $ 81,176,672 Project Name Federal Receipt Request (Gov Amd) State Funding Request (Gov Amd) Total Fund Code Defense Community Infrastructure Pilot Program - Black Rapids Training Site $ - $ 3,000,000 $ 3,000,000 1002 Fed Receipts Total $ 3,000,000 $ 3,000,000 Electric utility systems are part of the basic infrastructure of rural communities. New power systems are designed to meet accepted utility standards for safety, reliability, and environmental protections. FY2024 Supplemental - Request Brief Summary Extension of an electric power line to the Black Rapids Training Site. AEA partnership with GVEA. No state match is required. GVEA has committed funds to complete the project. Administrative Order 345 – Alaska Energy Security Task Force (AESTF). The State Energy Data Subcommittee (SEDS), in its recommendations stated in the December 1, 2023 AESTF report, provided four key strategies. The first strategy is to establish a data department within the Alaska Energy Authority (AEA). Additional request of $252,700 for Federal Receipt Authority necessary to fully fund the project under the SEP program requirements to begin using capitalization grant not more than 180 days after the date on which the grant is received. Request for fund capitalization to REF program for Round 16 of REF projects. FY25 Capital Budget - Request Brief Summary IIJA - Section 40101 (d) - formula grant program to strengthen and modernize America's power grid against wildfire, extreme weather, and other natural disasters. Improve resilience of the electric grid against disruptive events. Funding over five years to total over $60M. IIJA - Competitive application to be submitted September 2023. This project will enable AEA and AHFC to develop programs and deploy rooftop solar panels and community solar arrays to benefit low-income Training for energy audits of commercial and residential buildings. AEA will RSA with AHFC. Bulk fuel tank farm upgrades. Replaces aging tanks that may be leaking. Adds capacity to meet community needs. Meets code compliance standards improving life, health, and safety of community. Critical to rural communities - provides technical support when an electrical utility has lost, or will lose the ability to generate or transmit power. AS42.45.900 2023 Annual Report The subsea cable in the above photo is similar to the high-voltage direct current cable that will be installed between the Kenai Peninsula and Beluga, as part of the Railbelt Innovation Resiliency project. akenergyauthority.org 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. Letter from the Governor 4 Letter from the Chair 5 Letter from the Executive Director 6 Owned Assets 8 Power Cost Equalization 12 Rural Energy 14 Renewable Energy and Energy Efficiency 18 Grants and Loans 26 Financial Highlights 28 Board of Directors 30 Executive Team 31 AEA provides energy solutions to meet the unique needs of Alaska’s rural and urban communities. Table of Contents This publication on the activities and financial condition of AEA is submitted in accordance with Alaska Statute 44.83.940. Design and production by AEA. A total of 500 copies of the report were printed at Service Business Printing located in Anchorage, Alaska at a cost of $7.95 per copy. 2023 AEA Annual Report | 3 2 | 2023 AEA Annual Report Thanks to a historic grant from the Department of Energy secured by AEA in October 2023, Alaska has a tremendous opportunity to expand on transmission upgrades already underway and modernize the Railbelt transmission system for the benefit of all the communities it serves. Dear Fellow Alaskans, AEA was created in 1976 to promote, finance, and construct power projects that reduce energy costs in Alaska. Access to reliable and affordable energy is the foundation of economic growth and making Alaska the best place in the country to live, raise a family, and do business. As the statewide energy office, AEA plays a key role in harnessing our abundant energy resources of all kinds to achieve this objective. Thanks to a historic grant from the Department of Energy secured by AEA in October 2023, Alaska has a tremendous opportunity to expand on transmission upgrades already underway and modernize the Railbelt transmission system for the benefit of all the communities it serves. These upgrades will lead to reduced rates for Railbelt communities as we ensure that the lowest-cost power can move without constraint from Homer to Delta. The upgrades will also benefit our rural communities; when energy costs decrease on the Railbelt, there is a corresponding reduction in residential rates for Alaskans in communities that receive Power Cost Equalization. AEA also participated in the development of my Energy Security Task Force Report released in December 2023. It was charged with developing a comprehensive statewide energy plan that would evaluate energy generation, distribution, and transmission throughout Alaska and further drive at the cheapest energy for Alaskans. From oil and gas to renewables and emerging technologies, Alaska is an “all-of-the-above” state when it comes to energy. AEA will continue to lead our efforts to take advantage of every opportunity to reduce energy costs, increase energy independence, and build an Alaska for the next 50 years and beyond. Sincerely, Mike Dunleavy Governor In recent years, persistent inflation and the increased cost of living have been primary points of concern for households across the nation. Nowhere is the burden more evident than in rural Alaska where electricity costs can be up to five times higher than in urban areas. Through its Power Cost Equalization (PCE) program, AEA helps align rural electricity costs with costs in Anchorage, Fairbanks, and Juneau. In fiscal year 2023, AEA issued $42 million in PCE payments to rural electric utilities for the benefit of over 80,000 Alaskans in 188 communities. Over the last four decades, AEA has invested millions in rural Alaska. AEA administers the Bulk Fuel Upgrade program, which repairs or upgrades fuel storage facilities that lower fuel costs by allowing the community to buy fuel in large quantities. Additionally, through its Rural Power Systems Upgrade program, AEA builds and retrofits power system facilities that improve power generation efficiency. While significant investment has been made, more is needed, and AEA remains committed to the continued safe and reliable operation of rural energy infrastructure. AEA’s Renewable Energy Fund (REF) competitive grant program plays a crucial role in reducing carbon emissions by advancing clean energy projects across the state, with 80 percent of the projects funded located in rural Alaska. Last year, AEA commissioned a third-party research consultant to conduct an independent impact analysis of the program. The report affirms the efficacy of the program finding REF-funded projects have offset approximately 85 million gallons of diesel fuel, 2.2 million cubic feet of natural gas, and 1,063,500 net metric tons of carbon dioxide since 2008. To date, REF has made 289 grants to support renewable energy projects statewide. There are now over 100 operating projects built with REF contributions. With all of the work occurring in Alaska’s energy sector, AEA launched a new online digital library platform in December, aimed at improving the public’s ease of access to, and navigation of AEA’s current and historical resources. There are over 10,000 publicly available publications, technical reports, research and feasibility studies, and other documents. This number will continue to grow over the library’s life. I am proud of the progress we have made in reducing Alaska’s energy costs. However, we still have a long road ahead to ensure a brighter future for successive generations of Alaskans. Leveraging Alaska’s strategic location and its vast array of natural resources, we can lead the way in energy diversification while also bolstering Alaska’s economy and enhancing energy security. For the past decade, I have had the privilege of working closely with AEA’s dedicated team. On behalf of an appreciative board of directors, I want to thank everyone at AEA for their efforts in making Alaska a better place for all. J. Dana Pruhs Chair Letter From The Governor 2023 AEA Annual Report | 5 4 | 2023 AEA Annual Report It’s an exciting time for the energy sector, and I am pleased to present AEA’s 2023 Annual Report. This report reflects AEA’s dedicated efforts and achievements in pursuit of a sustainable and resilient energy future. Letter from The Chair In the fall of 2023, AEA was selected for a Grid Innovation and Partnership (GRIP) award of $206.5 million by the Department of Energy which will require a $206.5 million match for a total project cost of $413 million. The awarded Railbelt Innovation Resiliency project would install a new submarine high voltage direct current transmission line from the Kenai Peninsula across Cook Inlet to the existing Beluga Power Plant. This line will serve as an alternate energy pathway between the Kenai and Anchorage/ Matanuska Valley. The resilience of the electrical system will be greatly improved, increased transmission capacity will allow new renewable energy projects to be constructed and shared, and a decrease in line losses will allow more energy generated to reach consumers. Kenai Peninsula, Alaska With once-in-a-lifetime federal funds and state support, AEA’s budget has increased by over 1000 percent in the last four years. In the wake of this historical period, we have the opportunity for transformational change in the development of energy infrastructure to secure affordable and sustainable supplies for Alaska. Acting to capitalize on such opportunities, the Governor created the Alaska Energy Security Task Force (Task Force) to develop a comprehensive statewide energy plan that evaluates Alaska’s energy generation, distribution, and transmission. As a result of the Task Force’s work in which AEA participated, 60 recommendations across six energy priority areas were identified which aim to provide a more affordable and sustainable energy future for Alaska’s Coastal, Railbelt, and Rural regions. One of the most significant developments in AEA’s fiscal year 2023 was its selection by the United States Department of Energy’s (DOE) Grid Deployment Office for a $206.5 million Grid Resilience and Innovation Partnership grant to advance the Railbelt Innovation Resiliency project, which seeks to modernize and upgrade Alaska’s energy infrastructure. This was a highly competitive grant. Among the 700 applications and concept papers submitted, only 58 were selected, and Alaska received the fifth-highest dollar award. To utilize the funds, there must be a commitment to match 100 percent, or $206.5 million, bringing the project’s total cost to $413 million. These federal funds were the result of a successful collaboration between AEA and Railbelt utilities Chugach Electric Association, Golden Valley Electric Association, Homer Electric Association, Matanuska Electric Association, and Seward Electric. Using this DOE grant funding, Alaska can leverage dollar-for-dollar matching federal investment to improve resilience and energy security, diversify its energy portfolio, and accelerate the effective future integration of renewable and clean power. All of this can be achieved by upgrading the Railbelt’s grid resilience and reliability, enabling greater access to current and future clean energy resources. AEA continues to assess the Dixon Diversion project, which would fortify Alaska’s energy security by increasing overall renewable generation and mitigating exposure to fuel price volatility and supply-side disruptions. It could be operational by the end of the decade and increase the energy production capacity of the Bradley Lake Hydroelectric Project by 50 percent. In doing so the project will offset the equivalent of approximately 1.5 to 1.6 bcf/year of natural gas consumed for electricity production. An offset of this magnitude is equal to about 7.5 percent of Alaska’s unmet natural gas demand projected for 2030. Together with our partner, the Alaska Department of Transportation & Public Find funding opportunities at https://www.akenergyauthority.org Facilities, AEA received approval from the U.S. Federal Highway Administration for the second annual State of Alaska Electric Vehicle Implementation Infrastructure Plan. This approval unlocked an additional $11 million for electric vehicle charging stations throughout the state, complementing the $19 million already allocated for fiscal years 2022 and 2023. Utilizing these funds, AEA became the sixth state to award its first round of National Electric Vehicle Infrastructure (NEVI) Formula Program funding in support of nine projects across Alaska, allocating $8 million in NEVI funds. AEA remains committed to ensuring access to safe, affordable, and reliable energy for Alaskans. I would like to thank Governor Dunleavy, the Alaska Congressional Delegation, and the Alaska State Legislature for their support in these endeavors. I also wish to express my appreciation to the entire AEA team, who delivered successful outcomes across Alaska. We have much to accomplish together in the new year. Curtis W. Thayer Executive Director Letter From the Executive Director 2023 AEA Annual Report | 7 6 | 2023 AEA Annual Report AEA had an exceptional year in 2023, thanks to our talented team’s dedication and ingenuity. AEA continued to advance several initiatives to support Alaska’s energy goals and policies, which aim to ensure that Alaskans have access to safe, reliable, and affordable energy. Bradley Lake Hydroelectric Project, Alaska Bradley Lake Hydroelectric Project Dixon Diversion would increase the energy production capacity of Bradley Lake by 50 percent and offset the equivalent of roughly 1.5 to 1.6 bcf/year of natural gas use. 50% The Bradley Lake Hydroelectric Project was energized in September 1991. The project, located near Homer, Alaska, has been a low-cost source of electricity for the Railbelt for more than 30 years. The 120-megawatt (MW) facility generates about 10 percent of the total annual power used by Railbelt electric utilities and is some of the lowest-cost power for more than 550,000 Alaskans. Bradley Lake’s power generation potential was first studied in 1955 by the United States Army Corps of Engineers. AEA, then the Alaska Power Authority, assumed responsibility for the project in 1982. To date, the total project cost is approximately $400 million. The project was funded through legislative appropriations and AEA revenue bonds were repaid by the participating utilities. The Bradley Lake Project Management Committee manages the project, subject to AEA’s non-delegable rights, duties, and responsibilities. In 2020, Bradley Lake was expanded to increase energy generation through the West Fork Upper Battle Creek Diversion Project. In late 2020, AEA purchased a component of the interconnected transmission system (Sterling Quartz) located on the Kenai Peninsula to upgrade, reduce losses, and increase reliability. AEA is studying the Dixon Diversion to optimize Bradley Lake’s energy potential.Similar to the West Fork Upper Battle Creek Diversion project, the Dixon Diversion project would divert water from Dixon Glacier. This would increase Bradley Lake’s annual energy production by 50 percent, or 24,000-30,000 homes, and offset the equivalent of roughly 1.5 to 1.6 bcf/year of natural gas use. An offset of this magnitude is equal to about 7.5 percent of Alaska’s unmet natural gas demand projected for 2030. Completed in 1986, the Alaska Intertie is a 170-mile long, 345-kilovolt (kV) transmission line that stretches between Willow and Healy and operates at 138 kV. The Intertie connects Golden Valley Electric Association (GVEA), the utility that serves areas north of the Alaska Range, with Southcentral Alaska utilities. It was funded with State of Alaska appropriations totaling $124 million and has no debt service. The Intertie provides significant cost savings through the transmission of economic energy to GVEA. It delivers to GVEA its share of Bradley Lake power and enables the sharing of reserve generation capacity between the Anchorage and Fairbanks load centers. Operation of the Intertie is governed by the Alaska Intertie Agreement signed in 1985 and amended thereafter. The parties to the agreement are AEA, Chugach Electric Association, GVEA, and Matanuska Electric Association. Each of these entities has a seat on the Intertie Management Committee (IMC), which has responsibility for managing the Intertie. Through AEA’s leadership as an IMC member and with its step-in rights on financial decisions regarding the Intertie, AEA is uniquely positioned to ensure that ratepayers across the electrically interconnected Railbelt region benefit as intended under the current Alaska Intertie Agreement. In the fiscal year 2021, the IMC created an Asset Management Plan for the Alaska Intertie. The plan includes a preventive maintenance program, multi-year projections of maintenance and repair funding, climate change considerations, and analysis of factors affecting future use. The plan incorporates and facilitates some of the major changes anticipated on the Railbelt, such as increasing renewable power generation, reducing greenhouse gas production, and participation by Independent Power Producers. Alaska Intertie Owned Assets 2023 AEA Annual Report | 9 8 | 2023 AEA Annual Report Throughout the 1980s, AEA developed the state’s energy resources to help diversify Alaska’s economy and provide affordable energy to Alaskans. AEA built and owns several key pieces of Railbelt electric infrastructure — the Alaska Intertie, the Bradley Lake Hydroelectric Project, and the Sterling to Quartz Creek transmission line. These assets benefit Railbelt consumers by reducing the cost of power. In the period 2008-2021, the Alaska Intertie saved GVEA customers an average of $37 million per year.$37M Upgrade transmission line between Soldotna Substation and Sterling Substation 2 Upgrade transmission line between Bradley Lake and Soldotna Substation 1 Upgrade transmission line between Sterling Substation and Quartz Creek Substation 3 AEA has secured $206.5 million for the Grid Resilience and Innovation Partnership through the U.S. Department of Energy’s Grid Deployment Office. A cost share of 100 percent, or $206.5 million, is required for a total project amount of $413 million. The awarded Railbelt Innovation Resiliency (RIR) project aims to enhance resiliency and transfer capability along Alaska’s Railbelt, which experiences disturbances that can create problems with the connected loads or even cause the system to fail. Electrical power systems are characterized by voltage and frequency. An imbalance between generation and load causes frequency variations in a power system. To maintain optimal conditions, these two parameters must be controlled. The current Railbelt system configuration is fragile with little resilience, which restricts clean energy adoption, fuel diversification, and Alaska’s preparation for a sustainable carbon-free future. The key to achieving this objective is to reinforce interconnections between the primary regions of the Railbelt by adding parallel lines to increase resilience and implementing battery energy storage systems (BESS) to resolve long-standing frequency control and instability issues. Along with the high-voltage direct current (HVDC) submarine cable, these additions will alleviate transmission congestion and optimize interregional transfer capability. Coordinated interregional control and operations of the BESS and HVDC line will tie all the individual systems together to maximize stability and limit congestion. The project holds the promise of also benefiting Alaska’s rural communities. When energy costs decrease on the Railbelt, there is a corresponding reduction in residential rates for Alaskans who reside in remote communities that receive Power Cost Equalization funding to help pay for energy costs. Battery Energy Storage Systems for Grid Stabilization 4 Alaska Intertie, Photo by GVEA The “Railbelt” refers to the interconnected electric grid that stretches approximately 700 miles from Fairbanks through Anchorage to the Kenai Peninsula. About 75 percent of Alaska’s population is served by the Railbelt. As the largest electrical grid in the state, it is vital for statewide economic and community development.75% Railbelt Transmission Upgrades 2023 AEA Annual Report | 11 10 | 2023 AEA Annual Report Railbelt Innovation Resiliency Project AEA and the Railbelt utilities in 2022 bonded $166 million for Bradley Lake Hydroelectric Project Required Project Work. Transmission line work will use 65 percent of the funds and BESS will utilize the remaining 35 percent. These enhancements will reduce line losses, increase capacity, and improve the delivery of power from Bradley Lake to Railbelt consumers. These projects will be the initial phase of some of the most significant improvements to the Railbelt electrical grid in in 30 years. Funding for the projects comes from payments by the five Railbelt utilities — Chugach Electric Association, Golden Valley Electric Association, Homer Electric Association, Matanuska Electric Association, and Seward Electric System. Bond proceeds will be used solely to pay for transmission line upgrades and battery energy storage systems that will reduce the constraints on the Railbelt grid by improving the Kenai Peninsula’s transmission capacity to export power from Bradley Lake. Upgrades to transmission lines are more important now than ever before. A resilient Railbelt transmission system is achievable and needed to allow for better use of Bradley Lake’s potential and enable increased access to current and future renewable resources. Railbelt Transmission Line and BESS Upgrades Required Project Work St. George, Alaska Nome, Alaska The Power Cost Equalization Program (PCE) was established in 1984 to lower the cost of electrical power borne by rural residents and community facilities to a level comparable to that paid by residents of Alaska’s larger cities. AEA and the Regulatory Commission of Alaska (RCA) administer this program that serves over 80,000 Alaskans in 188 communities that rely primarily on diesel fuel. The PCE program makes payments to eligible rural electric utility companies and those companies credit their residential and community facility customers with payments made through the program up to a level of consumption. Those payments result in a reduction in the unit cost of power for residential and community customers. The pre-PCE cost of electricity in rural communities is almost always significantly more than urban electricity costs. Residential and community facility buildings in 188 communities see the benefits of PCE credits. AEA calculates the amount an eligible electric utility is due based on a filing made by the utility and issues monthly payments. PCE program staff also provide technical assistance to utility clerks who need help preparing and filing PCE reports. PCE disbursements are funded by 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 PCE. In recent years, the five percent draw on the endowment fully funded PCE disbursements. Fiscal year 2018 saw the enactment of statutory changes that address how excess PCE Endowment Fund earnings are to be used. These changes allowed the endowment fund earnings to pay for PCE program administration costs fully and the earnings could also contribute $30 million to the Community Assistance Program and up to another $25 million to the Renewable Energy Fund Program, Rural Power System Upgrade projects, and the Bulk Fuel Revolving Loan fund. During the fiscal year 2023, appropriations allowed for PCE payments at 100 percent resulting in approximately $42 million in program disbursements. $42M 750 kWh RESIDENTIAL Residential customers are eligible for PCE credit up to 750 kilowatt hours (kWhs) per month. 70 kWh PUBLIC FACILITIES Community facilities can receive PCE credit for up to 70 kWhs per month multiplied by the number of residents. Power Cost Equalization 2023 AEA Annual Report | 13 12 | 2023 AEA Annual Report Electricity costs for Alaska’s rural residents are notably higher than for urban residents. PCE lowers rural residents’ electric service costs, ensuring rural utilities’ viability and the availability of reliable, centralized power. 82 ELECTRIC UTILITIES A total of 82 rural electric utilities participate in the PCE program. In rural Alaska, diesel fuel is largely used for power generation and heating, while gasoline is used for transportation. Most rural villages are located along rivers or on the coast and get their goods via barge, including heating fuel and fuel for diesel-fired electrical generators. Many bulk fuel facilities were built more than 40 years ago and are not compliant with modern regulations. Yet they remain in service until updated or replaced, posing risks to personal safety and the environment. AEA’s Bulk Fuel Upgrade (BFU) program repairs or upgrades fuel storage facilities that help lower the cost of fuel per unit by allowing the community to buy fuel in bulk quantities. In Calendar Year 2023, Nunapitchuk, Shungnak, and Venetie received commissioned tank farms. There are six full BFU projects in various stages of design and construction. In recent years, AEA has switched its emphasis from bulk fuel facility replacement to Maintenance and Improvement (M&I) projects. Currently, 15 M&I projects are planned or underway, which target high-return investment in eligible community power systems. In addition to the normal gathering and assessment of technical data, full 3D imagery of the bulk fuel facility was captured. AEA uses 3D imaging and geographic information system software to capture imagery, collect measurements, and process data to create, edit and share 3D renderings of the systems. The project will result in a comprehensive and ongoing ranking of all facilities which will be used to inform funding agencies, and select projects. The data will also be used for construction management, operator training, and remote assistance. The 3D platform enables AEA project managers to track key project milestones and immediately assess project information. The targeted result is accelerated productivity, decision-making, and cost savings. Rural Energy In rural Alaska, AEA constructs bulk fuel tank farms, diesel powerhouses, and electrical distribution grids. Through circuit rider, emergency response, and training for operators and utility managers, AEA provides the resources necessary to support the operation of these facilities. There are about 400 bulk fuel facilities throughout Alaska. 400 Average age of each facility is over ~40 years, many are over 50 years old. 40+ AEA’s Rural Power Systems Upgrade (RPSU) program improves power generation in small Alaska villages off the electrical grid system. The Denali Commission is AEA’s major federal funding partner, which requires a state match of 50 percent for non-distressed communities or 20 percent for distressed communities. RPSU also manages Alaska’s allocation through the Environmental Protection Agency’s (EPA’s) Diesel Emissions Reduction Act (DERA). Pending yearly funding from Congress, states can apply for DERA funds based on population. EPA’s tribal DERA program also awards funds competitively nationwide. AEA uses DERA funds to replace prime-power diesel engines. AEA identifies communities for engine replacement through DERA based on current engine condition, redundancy, efficiency, and engine eligibility. In 2023, AEA oversaw Rural Power Systems Upgrade Bulk Fuel Upgrades Nunapitchuk, Alaska the construction of three powerhouse replacement projects in Napaskiak, Rampart, and Venetie. Additional RPSU design work was completed for Manokotak and Nelson Lagoon. Engine replacement with DERA funds was completed in Akiachak (four engines). Engines were purchased and transported to Grayling (two engines). Design has started in Bettles (one engine) and Tenakee Springs (two engines). In recent years, AEA’s focus has shifted from replacing full facilities to improving operations and maintenance to maximize rural power systems’ benefits. There are currently 14 active Maintenance and Improvement (M&I) projects, which target high-return investment in eligible community power systems. Projects include replacing old switchgear and control systems, maximizing heat recovery, updating engine controls to improve efficiency, and sometimes replacing diesel gensets. In 2023, 10 M&I (switchgear upgrades) projects were completed in Tenakee Springs, Kwethluk, Karluk, Chignik Bay, Atka, Ouzinkie, Unalakleet, Stevens Village, Hoonah, and Pilot Point. AEA has started a multi-year distribution inventory and assessment to evaluate the condition of distribution systems. This will provide the same benefits as inventorying and assessing power systems and bulk fuel. The data will be accessible to any entity involved in distribution systems in the village and will be gathered organically over time. AEA employs three-dimensional (3D) imaging collected by drone, LIDAR imaging, and geographic information systems to gather measurements and process data to create, edit, and share 3D renderings of the systems. The project will establish a system that will result in a comprehensive and ongoing ranking of all distribution systems eligible for AEA support. Data will be used to inform funding agencies and select projects. Venetie, Alaska 2023 AEA Annual Report | 15 14 | 2023 AEA Annual Report The average bulk fuel facility contains 100,000 gallons. 100K Perryville, Alaska AEA’s Rural Training program develops operators with the skills necessary to operate their energy infrastructure and keep operators compliant with current industry standards. In 2023, 34 operators from 25 communities were trained in Bulk Fuel, Person in Charge, and Power Plant Operations at the Alaska Vocational Technical Center. AEA is pioneering the use of 3D imaging coupled with data from every rural powerhouse to create new ways for operators to learn about their site’s specific needs. AEA has converted some operation and maintenance manuals into electronic form that has been digitized into 3D imagery of the powerhouse. Training videos are also linked to the imagery. This allows an operator to easily find, diagnose, and fix equipment in the powerhouse. The Circuit Rider and Technical Assistance programs provide essential assistance to reduce the number of emergency responses needed when there are power outages in rural communities with a population between 20 and 2,000. AEA’s team routinely instructs rural utility operators and managers on proper operations and maintenance of their generation and distribution infrastructure. During 2023, Circuit Riders assisted eligible utilities over 250 times in providing remote monitoring, training, and technical consultation. On-site assistance and minor repairs to power systems were performed in 44 communities. AEA assists rural communities during extended power outages to reduce the likelihood of death and property damage. In an electrical emergency, AEA assists the utility in responding and restoring electricity transmission and generation. Financial or technical assistance, including emergency repairs, may be provided. AEA responds to a real or potential emergency before it becomes a disaster or major loss. Engines, generators, and transformers may need to be purchased and/or installed as part of an emergency response. Four emergencies were declared in 2023.On any given day, AEA Circuit Riders respond to calls from powerhouse operators throughout rural Alaska and use 3D imagery to support, diagnose, and treat problems that arise. In December, a community contacted AEA with a high coolant temperature condition. Phone communication was not ideal. It can be easy to get confused with verbal communication, as imagery can prompt operators about valve alignment or direction on specific equipment. By having access to current imagery, many situations are clarified, preventing problematic situations from worsening. In this specific situation, AEA’s Circuit Rider provided a visual of the equipment the powerhouse operator was speaking to as well as instructions regarding the proper alignment of valves, which helped the operator through the troubleshooting process. Electrical Emergency AssistanceRural Training Circuit Rider and Technical Assistance 2023 AEA Annual Report | 17 16 | 2023 AEA Annual Report AEA’s Circuit Riders Support Rural Powerhouse Operators AEA provides comprehensive technical assistance to rural utilities to ensure infrastructure lasts its full economic life, preventing catastrophic electrical emergencies, and building community self- sufficiency. This helps assure the safe, reliable operation of rural Alaska electric generation equipment in which millions of dollars are invested. Rural Training and Assistance Biomass Biomass heat reduces diesel fuel use, keeps the money spent on fuel (wood) within the community, and creates local jobs. AEA’s biomass program has funded over 20 biomass woody biomass heating systems for schools and public buildings and provided technical support for more than 50 systems. Along with the United States Forest Service (USFS), the program has funded over 170 preliminary studies to evaluate a community’s biomass potential. In 2023, AEA, working with a consultant, conducted feasibility studies in Dillingham and Glennallen, and are working on a couple more to get projects in the pipeline for development. The team applied to the USFS’s Wood Innovations Grant program. In partnership with the Department of Natural Resources, AEA requested $500,000 to fund program activities involving forestry inventory updates, biomass feasibility studies, outreach and education, technical assistance, and training resources for rural communities. Hydroelectric In an average water year, Alaska’s principal renewable energy source, hydroelectricity, fuels more than 29 percent of the state’s electrical energy. AEA supports 51 utility- scale hydroelectric projects. The majority of Alaska’s existing hydro projects are located in the Southeast and Southcentral regions. Projects range from conceptual stages to operational facilities. Through its hydropower program, AEA improves the quality and efficiency of development, reducing construction costs. AEA coordinates with state, federal, municipalities, tribal entities, and private investors in analyzing, planning, and generally assisting hydroelectric project development. Solar Solar photovoltaic (PV) systems continue to grow in Alaska. These systems range from on- and off-grid residential to utility-scale PV. Northern latitudes often have impressive solar generation in spring and fall due to clear skies, cool temperatures, dry air, and bright, reflective snow. Solar PV systems can exceed their rated output at these times. AEA’s Power Project Fund helped finance an 8.5-megawatt solar farm in Houston on the Railbelt that went online in September 2023, and Round 15 of the Renewable Energy Fund funded the construction of two solar projects in rural Alaska. In addition, AEA is a member of the National Community Solar Partnership, which shares best practices among states. Furthermore, in 2023 AEA applied to EPA’s Solar for All program, which would fund a $100 million solar program in Alaska that targets low-income and disadvantaged communities if awarded. Wind Wind energy constitutes approximately two percent of Alaska’s annual electrical generation, representing a remarkable 400 percent growth since 2012. AEA’s active participation in the Alaska Wind Working Group and the 2023 Alaska Wind Workshop reflects a commitment to addressing policy issues and funding needs, as well as fostering dialogue crucial to advancing wind energy initiatives in the state. Our vast existing wind resources, onshore and offshore, underscore the need for continued development. In this year’s Round 15 of the Renewable Energy Fund, over $5 million was allocated to wind and wind/solar feasibility studies or conceptual design projects, covering island microgrid applications through utility-scale wind farm exploration in the Railbelt. An additional roughly $1 million was earmarked for storage solutions to enhance existing distributed wind generation.Pillar Mountain Wind Farm, Kodiak, Alaska *2023 Renewable Energy Fund: Impact and Evaluation Report About 33 percent of Alaska’s electricity generation came from renewable energy in 2022.* 33% Renewable Energy and Energy Efficiency 2023 AEA Annual Report | 19 18 | 2023 AEA Annual Report AEA’s renewable energy programs are central to Alaska’s clean energy economy. The programs work with local governments, non-profits, and tribal organizations to implement new energy solutions. They also provide technical assistance, funding, and training to increase knowledge about cost-saving energy technologies. Over the past 10 years, Alaska’s wind capacity has increased by 400 percent.* 400% Hydroelectric power fueled 29 percent.* 29% Over 65 wood heating systems have been installed in the state.* 65 Kongiganak, Alaska Join the AEEP listserv Sign up for AEEP news and updates at https://www.akenergyauthority.org/aeep Email Sign Up Clean Energy OlympicsPower Pledge ChallengeAlaska Energy Efficiency Partnership Energy Efficiency and Conservation Each quarter, more than 50 public, private, and nonprofit organizations meet to discuss energy efficiency and conservation efforts in Alaska through AEA’s energy efficiency and conservation outreach group, AEEP. Through information sharing and integrated planning, the group strives to improve Alaska’s energy efficiency and conservation behaviors. In 2023, AEEP meetings continued to focus on improving efficiency. Members discussed the Inflation Reduction Act Rebate Program, decarbonization efforts, energy data collection and use, and Commercial Property Assessed Clean Energy and Resilience. Energy efficiency funding and educational opportunities were also shared. AEA partnered with AK EnergySmart for its 11th annual Power Pledge Challenge. The program educates elementary through high school students in rural and urban Alaska on energy basics. It also educates them on energy efficiency and conservation at home and at school. Schools participate in monthly challenges such as developing community energy profiles, creating energy-saving public service announcements, or calculating energy savings by switching to LEDs. More than 2,000 students in 91 classrooms in 29 schools in eight regions throughout the state were educated on energy literacy this year as part of the program. Almost twice as many students participated this year as last. AEA supported the Renewable Energy Alaska Project’s fifth annual Clean Energy Olympics (CEO), a design competition that engages students in the engineering process through the lens of wind energy. In the CEO competition, teachers and coaches help students in 4th-12th grade build the best-designed model wind turbine, either individually or as a team. During competition showcases, models are scored on design performance and process. This year, 35 students on 13 teams competed in the state competition. Five teams qualified and competed at the 2023 National KidWind Challenge, held at the University of Colorado Boulder. Village Energy Efficiency Program The Alaska Legislature established the Village Energy Efficiency Program (VEEP) in 2010 to reduce per capita energy consumption. For several years, AEA leveraged federal State Energy Program funds to meet this mission. In 2022, AEA released a VEEP Request for Applications to fund efficiency programs. AEA, in partnership with the Denali Commission and Wells Fargo, awarded 48 communities to facilitate energy efficiency improvements throughout the state. These projects include upgrading lighting from legacy high-voltage bulbs to LED, window and garage weatherization, and upgrading HVAC systems. Despite COVID-19 setbacks and supply-chain shortages, the program is ongoing and successful, with all projects scheduled to be completed in the summer of 2024. To date, this program has collectively saved 1,189,463 kW, providing an estimated $611,498.95 in annual cost savings for the awarded communities. Renewable Energy – Village Energy Efficiency Program AEA’s newly created Renewable Energy-Village Energy Efficiency Program (RE-VEEP) expands on VEEP. In 2023, AEA released a RE-VEEP Request for Applications to award a total of $2.6 million in sub-grants to eligible local governments within Alaska to finance building-scale renewable energy, energy efficiency, and conservation projects in public buildings and facilities located in rural Alaska. Through these types of projects, communities can reduce their energy consumption and costs. 2023 AEA Annual Report | 21 20 | 2023 AEA Annual Report Optimizing energy generation and utilization lowers expenses and demand while also representing achievable objectives in energy solutions that are readily available in every Alaska community. Commercial buildings, public buildings, industrial facilities, and electrical efficiency are the focus of AEA’s end-use energy efficiency programs. AEA also leads the Alaska Energy Efficiency Partnership (AEEP), a collaborative multi-stakeholder group working to make Alaska the most energy-efficient state in the nation. As part of the State Energy Program, AEA developed a State Energy Security Profile (SESP) in collaboration with a contractor and members of an advisory committee comprised of representatives from the public and private energy sectors, in compliance with the Bipartisan Infrastructure Law. The energy sector is uniquely critical as all other infrastructure sectors depend on power and/ or fuel to operate. Threats to energy infrastructure can directly affect security and resilience within and across other critical infrastructure sectors — threatening public safety, the economy, and national security. Individual SESPs are essential for energy security planning. Alaska’s SESP describes the state’s energy landscape, people, processes, risks, and strategies for energy resilience. As part of the SESP, Alaska will work with energy partners to secure its energy infrastructure against physical and cybersecurity threats; minimize disruptions to energy supply; enhance response to and recovery from energy disruptions; and ensure a secure, reliable, and resilient energy infrastructure for the State. After reviewing Alaska’s SESP, the Department of Energy determined that it met all six elements mandated by Congress. As a result, Alaska will remain eligible for federal assistance. Port electrification projects support Alaska’s clean energy economy and drive the transition towards sustainable and eco-friendly practices within the cruise ship industry, while also yielding numerous economic, environmental, and social benefits for Alaska and its communities. Port electrification allows ships to turn off their engines, resulting in major advantages such as reducing polluting emissions that affect ports and cities and noise levels. The system can also become more cost-effective. In addition, port electrification projects aim to allow cruise ships to receive shoreside power from local Alaskan utilities and to replace traditional onboard diesel- powered generation with sustainable Alaska renewable energy resources such as hydro and clean-burning natural gas at Alaska’s cruise ship docks. By providing shoreside power to cruise ships during their time at port, these projects will significantly reduce ships’ carbon footprint and greenhouse gas emissions while visiting Alaska communities. State Energy Program: State Energy Security Profile CO2: 3,200-3,300 Metric Tons Per Year Reduced Criteria Emissions (NOx, SOx, CO, Particulate Matter): 93-96 Metric Tons Reduced Per Year Visible Emissions: Eliminated Except for Engine Startup on Departure Alaska is taking steps to reduce its carbon footprint at its cruise ship docks through infrastructure improvements. The State of Alaska, through AEA, is undertaking a project to electrify the Whittier Deep Water Dock, in collaboration with Holland America Princess. The state cruise ship head tax will support this effort. Port of Whittier Deep Water Dock, Photo by CLIA Port Electrification 2023 AEA Annual Report | 23 22 | 2023 AEA Annual Report 1. Environmental Impact: Port electrification will substantially reduce greenhouse gas emissions and air pollutants, improving air quality and mitigating cruise ship operations’ impact on local ecosystems. It is estimated that a cruise vessel emits more nitrogen oxides (NOx) than 10,000 vehicles in an eight-hour period. 2. Economic Growth: The implementation of port electrification projects will attract environmentally conscious travelers and cruise lines, enhancing Alaska’s reputation as a world leader in sustainability and a sustainable tourism destination. This, in turn, will boost local tourism revenue and create job opportunities in the clean energy sector. 3. Health and Well-being: By reducing harmful emissions from docked ships, port electrification will contribute to local communities’ health and well-being, reducing respiratory illnesses and enhancing the overall quality of life. 4. Sustainable Cruise Industry: Port electrification aligns with global sustainable travel trends. Alaska’s shipping industry will be better positioned to attract environmentally responsible travelers and maintain a competitive edge in the changing shipping landscape. Benefits of Port Electrification: 1 2 3 4 NEVI PHASE 1: Build out Alaska’s AFC NEVI PHASe 2: Extended and Marine Highway NEVI PHASe 3: Rural Hub COmmunities • Planned Nevi-funded sitesAlaska’s Alternative Fuel Corridor and State Energy Program funds, AEA funded the construction of an EV fast- charging corridor connecting Healy to Homer and Seward. This year, the corridor was completed. Sites, owned and operated by private hosts, were commissioned in Anchorage, Cantwell, Chugiak, Cooper Landing, Healy, Homer, Seward, Soldotna, and Trapper Creek. The network of 15 direct current fast charging and eight Level 2 chargers is fully operational and available to EV drivers, tourists, and travelers. National Electric Vehicle Infrastructure Program As part of the BIL, the NEVI Formula Program distributes $5 billion over the next five years (fiscal years 2022-2027) to state departments of transportation to build EV chargers along highway corridors to create a convenient, reliable, and affordable EV charging network Alaska Electric Vehicle Working Group AEA leads the Alaska Electric Vehicle Working Group (AKEVWG), which is comprised of members from across the state including the Alaska Department of Transportation and Public Facilities (DOT&PF), the Alaska Electric Vehicle Association, electric utilities, EV owners, EV vendors, municipalities, prospective charging sites, site hosts, universities, and other stakeholders. The AKEVWG meets quarterly on topics such as siting charging stations, climate considerations, and power requirements for publicly accessible charging locations. In addition to quarterly meetings, the AKEVWG facilitates technical sessions and distributes monthly newsletters through its EV listserv. Volkswagen Settlement Fund EV Project Updates With Volkswagen Settlement Trust funds nationwide. This infrastructure will serve long-distance EV travel along alternative fuel corridors (AFC). Through NEVI, Alaska will receive more than $52 million over five years to advance a statewide EV fast- charging network. NEVI will adapt Alaska’s infrastructure system to support reliable, equitable, and sustainable electric transportation. As a condition of receiving NEVI funds, Alaska is required to submit an annual NEVI implementation plan, demonstrating how the network will be completed to meet requirements set by the U.S. Department of Energy and U.S. Department of Transportation’s Joint Office for EV Infrastructure Deployment. Alaska’s EV Infrastructure Deployment Plan (The Plan) was developed by AEA and DOT&PF in collaboration with stakeholders. DOT&PF is the recipient of Federal Highway Administration (FHWA) Title 23 funds. DOT&PF will receive NEVI program funds to be jointly administered with AEA. Together, AEA and DOT&PF are working to ensure NEVI program funds are used strategically, effectively, and efficiently. The FY23 and FY24 Plans were approved by FHWA and address charging infrastructure deployment, existing and future conditions, contracting, implementation, and program evaluation. It also documents state agency coordination, stakeholder outreach, and public engagement. To establish statewide connectivity, EV charging station placement will be implemented in phases. NEVI funding, Phase One, focuses on building Alaska’s AFC. AEA will strategically deploy direct current fast-charging stations along the designated AFC, between Anchorage and Fairbanks, to build out the national charging network. Once the AFC is “fully built out” and meets FHWA’s criteria, which could take up to two years, AEA and DOT&PF will use NEVI funds to install charging infrastructure along Alaska’s Highway (non-AFC) and the Alaska Marine Highway System (AMHS). Phase Two will focus on linking small urban areas, rural communities on the road system, Alaska’s road system to Canada, and coastal communities on the AMHS. In September 2023, AEA and DOT&PF announced the first round of NEVI funding awards. Projects were selected in nine Alaskan communities between Anchorage and Fairbanks for a total investment of $8 million. The $6.4 million in NEVI funding will be matched with $1.6 million from private entities selected to install, own, and operate the new EV charging stations. The first round of NEVI sites will be located in Anchorage, Cantwell, Denali State Park, Ester, Fairbanks, Healy, Nenana, Trapper Creek, and Wasilla. AEA is the lead agency for electric vehicle (EV) infrastructure deployment in Alaska. Following the passage of the Bipartisan Infrastructure Law (BIL), also known as the Infrastructure Investment and Jobs Act, AEA has been conducting public outreach with local agencies, utilities, and other interested parties to inform Alaska’s strategic plan for deploying EV infrastructure. Scan to the QR Code to view the second annual State of Alaska EV Infrastructure Implementation Plan FY24 Electric Vehicles 2023 AEA Annual Report | 25 24 | 2023 AEA Annual Report 85M AEA contributes to the energy sector by administering several funding programs. In addition, AEA monitors funding opportunities through Tribal and Indian Energy loan programs and the United States Department of Energy (USDOE). AEA’s strong relationship with the USDOE, awareness of funding, and technical assistance available from National Laboratories is of benefit to all Alaskans. Power Project Fund AEA administers the Power Project Fund (PPF) program for loan requests from qualified applicants seeking low-interest loans. PPF enables local utilities, local governments, or independent power producers to seek low-cost financing for the development, expansion, or upgrade of electric power facilities, including distribution, transmission, efficiency and conservation, bulk fuel storage, and waste energy. With PPF, affordable loans are available for small-scale energy projects, across all project phases, including reconnaissance and feasibility studies. Loan terms are set according to a project’s useful life. Interest rates on PPF loans are formula- driven and related to the 30-year taxable municipal bond yield index, with a prevailing rate of 5.42 percent as of February 12, 2024. In 2023, AEA closed on a $4.9 million PPF loan to Energy 49 LLC to convert 45 acres in Houston, Alaska into an 8.5-megawatt (MW)- rated photovoltaic (PV) solar array making it the largest utility-scale PV solar installation in the state. The project, developed by Energy 49 LLC, a former subsidiary of Renewable IPP, LLC, the owner and operator of the Willow solar farm, is an 8.5 MW ballasted bi-facial PV solar array capable of powering approximately 1,400 homes. Power generated at the site is sold to the Matanuska Electric Association at a cost competitive rate under a 25-year Power Purchase Agreement approved by the Regulatory Commission of Alaska. The project aims to expand renewable energy production and diversify energy resources in Southcentral Alaska. The clean energy produced by the project will reduce air quality emissions related to power generation while conserving natural gas reserves in Cook Inlet. Analysis was conducted by BW Research Partnership, a third-party research consultancy. The report found that REF has catalyzed renewable energy growth in Alaska and continues to help the state meet its clean energy goals and priorities. Additionally, REF has helped local communities stabilize energy prices by reducing diesel fuel dependence for power generation and heating needs. Since REF’s inception, projects funded through the program have displaced approximately 85 million gallons of diesel and 2.2 million cubic feet of natural gas. REF has also successfully mitigated the emission of 1.1 million gross metric tons of carbon dioxide, and yielded more than $29 million dollars in avoided costs of PM2.5 pollutants. The report also finds that the REF program has made a significant contribution to Alaska’s overall economy including job creation, $237 million in labor income, and $399 million in value added. Every dollar deployed through the REF program to date has resulted in $2.07 in benefits returned to residents and the economy. 2023 REF Impact and Evaluation Report https://www.akenergyauthority.org/ref In 2023, AEA commissioned an independent impact evaluation and report on the REF Program. Renewable Energy Fund The Renewable Energy Fund (REF) was established in 2008 to help Alaskans reduce and stabilize their energy costs through the development of viable renewable energy projects. The program seeks to produce cost-effective renewable energy for heat and power, accelerating the diversification of community generation sources, which in turn can increase resiliency and mitigate negative externalities incurred by communities whose heat and power is almost exclusively powered via diesel fuel. In recognition of REF’s past and future impact in promoting the study, development, and integration of renewable energy technologies within Alaska’s statewide energy portfolio, when House Bill 62 was passed by the Legislature in May 2023, and Governor Mike Dunleavy signed the bill into law, REF’s sunset provision was repealed from statute, ensuring it is extended into perpetuity. REF’s extension into perpetuity also demonstrates REF’s efficacy in supporting the Governor’s energy policy priorities, including the continued diversification of power generation resources through the harnessing of Alaska’s vast renewable resources, improving the resilience of electrical infrastructure statewide, reducing the cost of energy, and enhancing energy security. To date, REF has made 289 grants to develop or construct renewable energy projects statewide. There are now over 100 operating projects built with REF contributions. In the fiscal year 2023, AEA solicited applications for REF Round 15. In consultation with the Renewable Energy Fund Advisory Committee (REFAC), AEA recommended 27 projects for funding, with a total grant request of $25.25 million. In June 2023, with the passage of House Bill 39, the Legislature appropriated and the Governor approved $17 million in support of 18 of the 27 recommended REF projects. In AEA’s January 2024 consultation with REFAC for Round 16, 24 projects were forwarded to the Legislature and recommended for funding consideration in the fiscal year 2025. REF has displaced approximately 85 million gallons of diesel and 2.2 million cubic feet of natural gas since its inception. Houston Solar Farm, Houston, Alaska, Photo by CleanCapital 2023 AEA Annual Report | 27 26 | 2023 AEA Annual Report Grants and loans PPF loans debt capital at favorable rates for energy projects. PPF financing is tailored to meet the specific needs of the borrower. AEA engages with projects at all stages of development. REVENUES, EXPENSES, AND CHANGES IN NET POSITION (CONT)June 30, 2023 June 30, 2022 Operating expenses: Grants and projects 26,163 18,238 Power cost equalization grants 42,332 24,222 Plant operating 9,746 7,834 General and administrative 6,707 6,319 Provision for loan recovery – – Depreciation 11,698 12,305 State of Alaska appropriations and transfers –– Other project expense –– Total operating expense 96,646 68,918 Operating loss (34,170) (37,765) Investment income (loss), net 94,280 (144,109) Interest expense (6,653) (1,568) State of Alaska reappropriations and transfers (45,000) (12,395) Capital contributions –– Loss on disposal of asset (400) – Increase (decrease) in net position 8,057*(195,837)** * * NOTES REGARDING INCREASE (DECREASE) IN NET POSITION *Net position increased primarily due to unrealized investment gains in the Power Cost Equalization (PCE) Endowment Fund of ($5,900) and from the Bradley Lake Hydroelectric Project bond issuance of ($2,500). Other contributing factors included an overall decrease of ($326) from reduced Trans-Alaska Pipeline Liability Fund revenues. **Net position decreased primarily due to unrealized investment losses in the PCE Endowment fund of ($143,842) and other funds ($267). Other contributing factors to the overall decrease were net operating losses ($39,299) and ($12,395) of net contributions made to the State of Alaska. STATEMENTS OF NET POSITION June 30, 2023 June 30, 2022 Assets: Restricted Investment securities and cash 1,226,790 1,048,505 Loans, net 26,459 27,058 Capital assets, net 375,794 385,307 Receivables and other assets 8,068 5,634 Total assets 1,637,111 1,466,504 Liabilities and net position: Liabilities Bonds payable 204,032 45,925 Other bond liabilities – 56 Payables and other liabilities 51,145 46,646 Total liabilities 255,177 92,627 Net Position 1,381,934 1,373,877 Total liabilities and net position 1,637,111 1,466,504 REVENUES, EXPENSES, AND CHANGES IN NET POSITION June 30, 2023 June 30, 2022 Operating revenues: Federal grants 10,179 8,575 Revenue from operating plants 27,461 22,657 State operating and capital revenues 23,704 3,922 Interest on loans 280 329 Other operating revenues 852 5,008 Total operating revenues 62,476 40,501 2023 AEA Annual Report | 29 28 | 2023 AEA Annual Report FY2023 Financial Highlights CURTIS W. THAYER Executive Director AUDREY ALSTROM, PE Director of Renewable Energy and Energy Efficiency Programs 2023 AEA Annual Report | 31 30 | 2023 AEA Annual Report TIM SANDSTROM Chief Operating Officer KAREN TURNER Human Resources Director J. DANA PRUHS Chair, Public Member ADAM CRUM Commissioner, Alaska Department of Revenue BILL KENDIG Vice Chair, Public Member BILL VIVLAMORE Public Member RANDY ELEDGE Public Member JULIE SANDE Commissioner, Alaska Department of Commerce, Community, and Economic Development ALBERT FOGLE Public Member BYRAN CAREY, PE Director of Owned Assets ROBERT HAWKINS Information Technology Director Board of Directors Executive Team CLAY CHRISTIAN Chief Financial Officer BRANDY M. DIXON Communications Director CONNER ERICKSON Director of Planning Alaska Energy Authority 813 W Northern Lights Blvd. Phone: (907) 771-3000 Fax: (907) 771-3300 E-mail: info@akenergyauthority.org www.akenergyauthority.org @alaskaenergyauthority @alaskaenergyauthority POWER COST EQUALIZATION PROGRAM STATISTICAL REPORT FY2023 Safe, Reliable, and Affordable Energy Solutions 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 RGYAUTHORITY.ORG March 1, 2024 Dear Fellow Alaskan, Per Alaska Statute 44.83.940, the Alaska Energy Authority (AEA) produces an annual Power Cost Equalization (PCE) Statistical Report detailing the operations of the PCE program. The attached report covers the fiscal year ending June 30, 2023. Alaska's PCE program was established in 1984 to provide economic assistance to rural residents and rural electric utilities. AEA and the Regulatory Commission of Alaska (RCA) administer the program, which serves over 80,000 residents in 188 remote communities. PCE reduces rural consumers' electric rates to levels comparable to those paid in Anchorage, Fairbanks, and Juneau. The program reimburses utilities for credits extended to its eligible residential and community facility customers. Residential customers are eligible for PCE credit up to 750-kilowatt hours (kWhs) per month. Community facilities can receive PCE credit for up to 70 kWhs per month multiplied by the community population set by the Alaska Department of Commerce, Community, and Economic Development. Participating utilities submit monthly reports, customer ledgers, and invoice copies. AEA reviews the monthly reports for accuracy and issues payments based on rates calculated by the RCA. This year, all communities filed their reports electronically through AEA's PCE Portal for the first time. The PCE Portal is an online program that streamlines the reporting process and reduces the turnaround time between reports submitted and payments issued. During the fiscal year 2023, endowment earnings allowed for PCE payments at one-hundred percent resulting in approximately $47.9 million in program disbursements. This report may be found at Alaska Energy Authority. Additional copies may be obtained by emailing PCE@akenergyauthority.org. Regards, Curtis W. Thayer Executive Director Attachment: FY 2023 Power Cost Equalization Annual Report POWER COST EQUALIZATION PROGRAM Statistical Data by Community Reporting Period: 07/01/22 - 06/30/23 TABLE OF CONTENTS Program Highlights ........................................................................................................................................................ 8 Fiscal Year 2022 vs. 2023 .............................................................................................................................................. 9 Historical Trends, Fiscal Years 2014 – 2023 ......................................................................................................... 10 List of Participating Utilities/Communities .......................................................................................................... 11 Map of Participating Utilities/Communities ........................................................................................................ 12 Adak ................................................................................................................................................................................... 13 Akhiok ................................................................................................................................................................................ 14 Akiachak............................................................................................................................................................................ 15 Akiak ................................................................................................................................................................................... 16 Akutan ............................................................................................................................................................................... 17 Alakanuk ........................................................................................................................................................................... 18 Allakaket; Alatna ............................................................................................................................................................ 19 Ambler ............................................................................................................................................................................... 20 Anaktuvuk Pass .............................................................................................................................................................. 21 Angoon ............................................................................................................................................................................. 22 Aniak .................................................................................................................................................................................. 23 Anvik .................................................................................................................................................................................. 24 Arctic Village ................................................................................................................................................................... 25 Atka .................................................................................................................................................................................... 26 Atmautluak ...................................................................................................................................................................... 27 Atqasuk ............................................................................................................................................................................. 28 Bethel; Oscarville ........................................................................................................................................................... 29 Bettles; Evansville .......................................................................................................................................................... 30 Brevig Mission ................................................................................................................................................................ 31 Buckland ........................................................................................................................................................................... 32 Central ............................................................................................................................................................................... 33 Chefornak ......................................................................................................................................................................... 34 Chenega Bay ................................................................................................................................................................... 35 Chevak ............................................................................................................................................................................... 36 Chignik Lagoon .............................................................................................................................................................. 37 Chignik Lake .................................................................................................................................................................... 38 Chignik .............................................................................................................................................................................. 39 Chilkat Valley .................................................................................................................................................................. 40 Chilkat Valley; Klukwan ............................................................................................................................................... 41 Chistochina ...................................................................................................................................................................... 42 Chitina ............................................................................................................................................................................... 43 Chuathbaluk .................................................................................................................................................................... 44 POWER COST EQUALIZATION PROGRAM Statistical Data by Community Reporting Period: 07/01/22 - 06/30/23 TABLE OF CONTENTS Circle .................................................................................................................................................................................. 45 Clark's Point ..................................................................................................................................................................... 46 Coffman Cove ................................................................................................................................................................. 47 Cold Bay ............................................................................................................................................................................ 48 Cordova ............................................................................................................................................................................ 49 Craig ................................................................................................................................................................................... 50 Crooked Creek ................................................................................................................................................................ 51 Deering.............................................................................................................................................................................. 52 Dillingham; Aleknagik .................................................................................................................................................. 53 Diomede ........................................................................................................................................................................... 54 Dot Lake; Dot Lake Village ......................................................................................................................................... 55 Eagle; Eagle Village ....................................................................................................................................................... 56 Eek....................................................................................................................................................................................... 57 Egegik ................................................................................................................................................................................ 58 Ekwok ................................................................................................................................................................................. 59 Elfin Cove .......................................................................................................................................................................... 60 Elim ..................................................................................................................................................................................... 61 Emmonak ......................................................................................................................................................................... 62 False Pass ......................................................................................................................................................................... 63 Fort Yukon........................................................................................................................................................................ 64 Galena ................................................................................................................................................................................ 65 Gambell ............................................................................................................................................................................. 66 Golovin .............................................................................................................................................................................. 67 Goodnews Bay ................................................................................................................................................................ 68 Grayling ............................................................................................................................................................................. 69 Gustavus ........................................................................................................................................................................... 70 Haines; Covenant Life .................................................................................................................................................. 71 Healy Lake ........................................................................................................................................................................ 72 Hollis .................................................................................................................................................................................. 73 Holy Cross ........................................................................................................................................................................ 74 Hoonah ............................................................................................................................................................................. 75 Hooper Bay ...................................................................................................................................................................... 76 Hughes .............................................................................................................................................................................. 77 Huslia ................................................................................................................................................................................. 78 Hydaburg ......................................................................................................................................................................... 79 Igiugig ............................................................................................................................................................................... 80 Iliamna; Newhalen; Nondalton................................................................................................................................. 81 Kake .................................................................................................................................................................................... 82 POWER COST EQUALIZATION PROGRAM Statistical Data by Community Reporting Period: 07/01/22 - 06/30/23 TABLE OF CONTENTS Kaktovik ............................................................................................................................................................................ 83 Kaltag ................................................................................................................................................................................. 84 Karluk ................................................................................................................................................................................. 85 Kasigluk ............................................................................................................................................................................. 86 Kiana .................................................................................................................................................................................. 87 Kipnuk ................................................................................................................................................................................ 88 Kivalina .............................................................................................................................................................................. 89 Klawock ............................................................................................................................................................................. 90 Klukwan ............................................................................................................................................................................. 91 Kobuk ................................................................................................................................................................................. 92 Kokhanok ......................................................................................................................................................................... 93 Koliganek .......................................................................................................................................................................... 94 Kongiganak...................................................................................................................................................................... 95 Kotlik .................................................................................................................................................................................. 96 Kotzebue .......................................................................................................................................................................... 97 Koyuk ................................................................................................................................................................................. 98 Koyukuk ............................................................................................................................................................................ 99 Kwethluk ........................................................................................................................................................................ 100 Kwigillingok .................................................................................................................................................................. 101 Levelock ......................................................................................................................................................................... 102 Lime Village .................................................................................................................................................................. 103 Lower Kalskag .............................................................................................................................................................. 104 Manley Hot Springs ................................................................................................................................................... 105 Manokotak .................................................................................................................................................................... 106 Marshall ......................................................................................................................................................................... 107 McGrath ......................................................................................................................................................................... 108 Mekoryuk ...................................................................................................................................................................... 109 Mentasta ........................................................................................................................................................................ 110 Minto .............................................................................................................................................................................. 111 Mt. Village ..................................................................................................................................................................... 112 Naknek;S.Naknek;Kng Slmn ................................................................................................................................... 113 Napakiak ........................................................................................................................................................................ 114 Napaskiak ...................................................................................................................................................................... 115 Naukati ........................................................................................................................................................................... 116 Nelson Lagoon ............................................................................................................................................................ 117 New Stuyahok ............................................................................................................................................................. 118 Newtok; Mertavik ....................................................................................................................................................... 119 POWER COST EQUALIZATION PROGRAM Statistical Data by Community Reporting Period: 07/01/22 - 06/30/23 TABLE OF CONTENTS Nightmute ..................................................................................................................................................................... 120 Nikolai ............................................................................................................................................................................ 121 Nikolski ........................................................................................................................................................................... 122 Noatak ............................................................................................................................................................................ 123 Nome .............................................................................................................................................................................. 124 Noorvik........................................................................................................................................................................... 125 Northway; Northway Village .................................................................................................................................. 126 Nuiqsut ........................................................................................................................................................................... 127 Nulato ............................................................................................................................................................................. 128 Nunam Iqua.................................................................................................................................................................. 129 Nunapitchuk ................................................................................................................................................................. 130 Old Harbor .................................................................................................................................................................... 131 Ouzinkie ......................................................................................................................................................................... 132 Pedro Bay ...................................................................................................................................................................... 133 Pelican ............................................................................................................................................................................ 134 Pilot Point ...................................................................................................................................................................... 135 Pilot Station .................................................................................................................................................................. 136 Pitkas Point ................................................................................................................................................................... 137 Point Hope .................................................................................................................................................................... 138 Point Lay ........................................................................................................................................................................ 139 Port Alsworth ............................................................................................................................................................... 140 Port Heiden .................................................................................................................................................................. 141 Quinhagak..................................................................................................................................................................... 142 Rampart ......................................................................................................................................................................... 143 Red Devil ....................................................................................................................................................................... 144 Ruby ................................................................................................................................................................................ 145 Russian Mission........................................................................................................................................................... 146 Sand Point ..................................................................................................................................................................... 147 Savoonga ....................................................................................................................................................................... 148 Scammon Bay .............................................................................................................................................................. 149 Selawik............................................................................................................................................................................ 150 Shageluk ........................................................................................................................................................................ 151 Shaktoolik ..................................................................................................................................................................... 152 Shishmaref .................................................................................................................................................................... 153 Shungnak ...................................................................................................................................................................... 154 Skagway ......................................................................................................................................................................... 155 Slana ................................................................................................................................................................................ 156 POWER COST EQUALIZATION PROGRAM Statistical Data by Community Reporting Period: 07/01/22 - 06/30/23 TABLE OF CONTENTS Sleetmute ...................................................................................................................................................................... 157 St. George ..................................................................................................................................................................... 158 St. Mary's; Andreafsky .............................................................................................................................................. 159 St. Michael..................................................................................................................................................................... 160 St. Paul ............................................................................................................................................................................ 161 Stebbins ......................................................................................................................................................................... 162 Stony River .................................................................................................................................................................... 163 Takotna .......................................................................................................................................................................... 164 Tanana ............................................................................................................................................................................ 165 Tatitlek ............................................................................................................................................................................ 166 Teller................................................................................................................................................................................ 167 Tenakee Springs ......................................................................................................................................................... 168 Tetlin ............................................................................................................................................................................... 169 Thorne Bay; Kasaan ................................................................................................................................................... 170 Togiak ............................................................................................................................................................................. 171 Tok; Tanacross ............................................................................................................................................................. 172 Toksook Bay ................................................................................................................................................................. 173 Tuntutuliak .................................................................................................................................................................... 174 Tununak ......................................................................................................................................................................... 175 Twin Hills ....................................................................................................................................................................... 176 Unalakleet ..................................................................................................................................................................... 177 Unalaska ........................................................................................................................................................................ 178 Upper Kalskag ............................................................................................................................................................. 179 Venetie ........................................................................................................................................................................... 180 Wainwright ................................................................................................................................................................... 181 Wales .............................................................................................................................................................................. 182 Whale Pass .................................................................................................................................................................... 183 White Mountain .......................................................................................................................................................... 184 Yakutat ........................................................................................................................................................................... 185 Data for prior fiscal years may differ from prior year reports due to data adjustments made after the publication went to print. Data for this fiscal year reflects monthly PCE reports that have been processed prior to publication This publication reporting on the statistics and operations of the PCE program as administered by the Alaska Energy Authority is submitted in accordance with Alaska Statute (AS) 44.83.940. AEA printed 100 copies of this report in Anchorage, Alaska for $23.20 per copy. Design and production by AEA. Printing and binding completed by Service Business Printing. HIGHLIGHTS OF THE POWER COST EQUALIZATION PROGRAM Eligibility Utility An electric utility participating in the Power Cost Equalization Program (PCE) must: a)provide electric service to the public for compensation; b) during calendar year 1983, had less than 7,500 megawatt hours of residential consumption or less than 15,000 megawatt hours if two or more communities were served; and c) during calendar year 1984, the utility has used diesel-fired generators to produce more than 75% of its electrical consumption. Customers Customer eligibility is based on actual power purchased. State and federal offices/facilities, commercial customers and public schools are excluded from PCE. Residential customers are eligible for PCE credit up to 750 kilowatt-hours (kWh/s) per month. Community facilities, as a group, can receive PCE credit for up to 70 kilowatt-hours per month multiplied by the number of residents in a community. Formula Used to determine PCE level/kWh for a utility: Formula: 95% of the eligible costs per kWh between 19.58 cents/kWh, “the base rate” and $1.00/kWh, “the ceiling”. Costs below 19.58 cents/kWh and above $1.00/kWh are not eligible for PCE. If the eligible costs are $1.00/kWh or more, the maximum PCE level is 75.97 cents/kWh. ($1.00 – 19.58 cents = 80.42 cents x 95% = 76.40 cents). A participating utility must meet generation efficiency and line loss standards; otherwise the PCE level is reduced to reflect those standards. Process The Regulatory Commission of Alaska (RCA) RCA determines the PCE level per kWh for each utility. Two categories of costs are used in determining the PCE level: a) fuel expenses: the cost of fuel, including transportation of fuel; and b) non-fuel expenses: salaries, insurance, taxes, power plant parts and supplies, interest and other reasonable costs. The Alaska Energy Authority (AEA) Eligible utilities submit monthly reports to AEA that document the eligible power sold and PCE credits applied to eligible customers’ bills. AEA calculates the amount of PCE on a monthly basis and issues payment to the utility. AEA verifies the eligibility of customers and of community facilities. In addition, AEA calculates the required pro-rated PCE levels based on available funds. Authority PCE is governed by Alaska Statutes 42.45.110-170, and by the Alaska Administrative Code 3 AAC 107.200-270 and 3 AAC 52.600-690. 8 of 185 POWER COST EQUALIZATION PROGRAM STATISTICS FISCAL YEAR 2022 See (8) FISCAL YEAR 2023 % Change 2022-2023% See (5) PARTICIPATION STATISTICS Population Served 79,808 81,996 2.7% Communities Served 188 188 0.0% Participating Utilities 83 82 -1.2% Total Residential Customers (2)27,961 28,128 0.6% Total Community Facility Customers (2)1,939 1,973 1.8% Total Customer (Residential & Community Facilities) (1) (2)29,900 30,101 0.7% PRODUCTION STATISTICS Total Diesel Generation (kWh)393,558,620 395,945,976 0.6% Total "Other" (Hydro/Wind/Solar/Natural Gas) Generation (kWh)55,181,730 54,144,326 -1.9% Total Purchased Power (kWh)57,351,798 59,191,285 3.2% Total kWh Sold (All Customers) (7)460,571,858 460,821,110 0.1% PCE Eligible Residential kWh 97,416,581 113,679,601 16.7% PCE Eligible Community kWh 35,544,014 35,646,628 0.3% Total PCE Eligible - Community Facilities & Residential 132,960,595 149,326,229 12.3% Total PCE Eligible kWh Shown as Percent of Total kWh Sold 28.9%32.4%12.2% Average Monthly PCE Eligible kWh - Residential Customers (3)290 337 16.0% Average Monthly PCE Eligible kWh - Community Facilities (3)1,528 1,506 -1.4% Average Monthly PCE Eligible kWh - Community Facilities / Per Resident (3)37 36 -2.4% FINANCIAL STATISTICS Average Price of Fuel Oil ($/gallon)3.0208 4.0234 33.2% Total Fuel Oil Consumed (gallons)28,682,394 27,248,271 -5.0% Total Cost of Fuel Oil Purchased by the Utilities ($)86,644,095 109,631,453 26.5% Total Non-Fuel Expenses ($) (5)93,982,810 108,780,039 15.7% Non-Fuel Expenses per Total kWh Sold ($) (5)0.2041 0.2361 15.7% Total Operating Costs per kWh ($) Sold (4)0.3922 0.4740 20.9% PCE Legislative Funding Appropriations for Utility Payments 32,000,000 47,694,800 49.0% Total Monthly Reports/PCE Reimbursements to Utilities Processed (6)27,361,377 41,584,697 52.0% (1) Assumes all customers were eligible to receive PCE credit. (2) Total Customers represents the number of customers reported by the utility for the last reported month. (3) Calculation assumes all residential and community facility customers were eligible to receive twelve (12) months of PCE credit. (4) "Operating" costs include both fuel and non-fuel expenses. (5) Net change between years is partially attributable to incomplete reporting by utilties. (6) During FY23 and FY22 PCE payments were made at a 100% level for all 12 months (7) Value reduced by $906,508 in FY23 and $2,265,339 in FY22 to eliminate double counting of kWh's where power is sold/purchased between utilities participating in the PCE Program. (8) Data restated. Changes from prior published data due to updated data after report production. 9 of 185 2014*2015*2016*2017*2018*2019*2020*2021*2022*2023 PARTICIPATION Participating Utilities 87 86 88 89 89 88 86 86 83 82 Communities Served 190 190 191 194 194 193 191 191 188 188 Population Served 82,427 81,969 82,986 83,850 83,400 81,997 81,694 81,160 79,808 81,996 PCE ELIGIBLE CUSTOMERS Residential 27,716 27,893 28,035 27,857 28,365 28,338 28,158 27,923 27,961 28,128 Community Facilities 1,889 1,850 2,056 2,067 2,090 2,069 1,984 1,969 1,939 1,973 Total PCE Eligible Customers 29,605 29,743 30,091 29,924 30,455 30,407 30,142 29,892 29,900 30,101 FUNDING Appropriations for Utility Payments($)$41,006,000 $41,000,000 $41,000,000 $40,000,000 $32,000,000 $32,000,000 $32,000,000 $29,500,000 $32,000,000 $47,694,800 Disbursements to Utilities ($)$39,574,138 $37,379,742 $31,042,569 $26,099,807 $26,182,235 $28,357,347 $29,006,012 $23,625,029 $27,361,377 $41,584,697 Disbursements/Customer ($)$1,337 $1,257 $1,032 $872 $860 $933 $962 $790 $915 $1,382 Funding Level 100%100%100%100%100%100%100%100%100%100% CONSUMPTION Total MWh Sold (MWh)452,119 450,232 446,735 462,081 458,092 453,598 455,730 440,607 460,572 460,821 PCE Eligible MWh Residential 95,990 96,453 94,816 97,751 96,597 95,606 96,544 97,510 97,417 113,680 Avg. PCE Eligible kWh/Month/Residential Customer 289 288 282 292 284 281 286 291 290 337 PCE Eligible MWh Community Facilities 33,429 32,795 34,357 35,747 34,929 34,191 34,946 34,554 35,544 35,647 Elig. kWh/Month/Capita, Community Facilities 33.8 33.3 34.5 35.5 34.9 34.7 35.6 35.5 37.1 36.2 Total PCE Eligible MWh 129,419 129,248 129,173 133,498 131,526 129,797 131,490 132,063 132,961 149,326 Eligible kWh/Month/Cust, Total Customers 364 362 358 372 360 356 364 368 371 413 COSTS Average Price of Fuel Oil ($/gallon)$4.21 $3.97 $3.24 $2.66 $2.67 $3.06 $3.07 $2.63 $3.02 $4.02 Total Gallons of Fuel Oil Consumed 27,919,599 27,191,149 26,865,206 28,838,704 28,446,814 28,425,146 28,199,707 27,783,263 28,682,394 27,248,271 Total Cost of Fuel Oil ($)$117,483,188 $107,842,372 $87,102,302 $76,759,457 $76,057,479 $86,989,310 $86,638,172 $73,101,431 $86,644,095 $109,631,453 Total Non-Fuel Costs ($)$73,336,386 $76,036,533 $82,964,017 $85,141,895 $92,077,547 $85,813,619 $87,853,342 $81,592,866 $93,982,810 $108,780,039 FINANCIAL RATIOS Non-Fuel Costs Per Total kWh Sold $0.1622 $0.1689 $0.1857 $0.1843 $0.2010 $0.1892 $0.1928 $0.1852 $0.2041 $0.2361 Total Operating Costs Per Total kWh Sold $0.4221 $0.4084 $0.3807 $0.3504 $0.3670 $0.3810 $0.3829 $0.3511 $0.3922 $0.4740 RATES Avg. PCE per Eligible kWh Res. & Comm Facility ($/kWh)$0.3058 $0.2892 $0.2403 $0.1955 $0.1991 $0.2185 $0.2206 $0.1789 $0.2058 $0.2785 Weighted Avg. Residential Rate (Before PCE Paid)$0.4983 $0.4915 $0.4541 $0.4270 $0.4378 $0.4628 $0.4633 $0.4412 $0.4674 $0.5528 Weighted Avg. Residential PCE Rate (Amount PCE pays)$0.3108 $0.2919 $0.2432 $0.1983 $0.2010 $0.2191 $0.2226 $0.1821 $0.2101 $0.2776 Weighted Avg. Residential Effective Rate (1)$0.1876 $0.1996 $0.2108 $0.2288 $0.2368 $0.2437 $0.2407 $0.2591 $0.2572 $0.2752 *Data maybe different from prior reports due to updated data after publishing those reports (1) Amount customers pay for first 750 kWh/month POWER COST EQUALIZATION PROGRAM HISTORICAL TRENDS Fiscal Years 2014 - 2023 10 of 185 Akhiok / Kaguyak Electric Atka, City of Napakiak Ircinraq Akiachak Native Community Atmautluak Joint Utilities Napaskiak Electric Utility Akiak Buckland, City of Naterkaq Light Plant Akutan Electric Utility Chenega IRA Village Council Chefornak* Alaska Power Company Chignik, City of Nelson Lagoon Electrical Cooperative Allakaket / Alatna Hydaburg Chignik Lagoon Power Utility New Koliganek Village Council Bettles / Evansville Klawock Chignik Lake Electric Koliganek* Chistochina Mentasta Chitina Electric Inc.Nikolai, City of Coffman Cove Naukati Circle Electric Utility Nome Joint Utility System Craig Northway / Northway Village Clarks Point Village Council North Slope Borough Dot Lake / Dot Lake Village Skagway Cordova Electric Co-op Anaktuvuk Pass Eagle / Eagle Village Slana Diomede Joint Utilities Atqasuk Point Hope Gustavus Tetlin Egegik Light and Power Kaktovik Point Lay Haines / Covenant Life Thorne Bay / Kassan Elfin Cove Utility Commission Nuiqsut Wainwright Healy Tok / Tanacross False Pass, City of Nunam Iqua Electric Company Hollis Whale Pass Galena, City of Nushagak Electric Cooperative Alaska Village Electric Cooperative G & K Inc.Aleknagik / Dillingham* Alakanuk Nightmute Cold Bay*Ouzinkie, City of Ambler Noatak Gold Country Energy Pedro Bay Village Council Anvik Noorvik Central*Pelican, City of Bethel / Oscarville Nulato Golovin Power Utilities Pilot Point Electrical Brevig Mission Nunapitchuk Gwitchyaa Zhee Utilities Port Heiden Utilities Chevak Old Harbor Fort Yukon*Puvurnaq Power Company Eek Pilot Station Hughes Power & Light Kongiganak* Ekwok Pitka's Point Igiugig Electric Company Rampart Village Council Electric Elim Quinhagak I-N-N Electric Cooperative Ruby, City of Emmonak Russian Mission Iliamna / Newhalen / Nondalton St. George, City of Gambell Savoonga Inside Passage Electric Cooperative St. Paul Municipal Electric Goodnews Bay Scammon Bay Angoon Kake Takotna Community Assoc. Inc. Grayling Selawik Chilkat Valley/Klukwan Tanalian Electric Cooperative Holy Cross Shageluk Hoonah Port Alsworth* Hooper Bay Shaktoolik Ipnatchiaq Electric Company Tanana Power Company Inc. Huslia Shishmaref Deering*Tatitlek Village IRA Council Kaltag Shungnak Kipnuk Light Plant TDX Adak Generating LLC Kasigluk St. Mary's / Andreafsky Kokhanok Village Council TDX Corporation Kiana St. Michael Kotzebue Electric Association Sand Point* Kivalina Stebbins Koyukuk, City of TDX Manley Generating LLC Kobuk Teller Kwethluk Incorporated Tenakee Springs, City of Kotlik Togiak Kwigillingok IRA Council Tuntutuliak Community Service Assoc. Koyuk Toksook Bay Levelock Electrical Coop Umnak Power Company Lower Kalskag Tununak Lime Village Electric Utility Nikolski* Marshall Twin Hills Manokotak Power Company Unalakleet Valley Electrical Cooperative Mekoryuk Upper Kalskag McGrath Light & Power Unalaska, City of Minto Wales Middle Kuskokwim Electric Ungusrag Power Company Mt. Village Yakutat Chuathbaluk Sleetmute Newtok* New Stuyahok Crooked Creek Stony River Venetie Village Electric Alutiiq Power Company Red Devil White Mountain, City of Karluk Naknek Electric Aniak Light & Power Company King Salmon Arctic Village Council Naknek / South Naknek *Single community name differs from utility name FY23 PCE Program Participating Utilities 11 of 185 Power Cost Equalization (PCE) Program Eligible Communities )Vawfw� /).� ::1::Hope 'Kivalina "-Noatak 0 ,0, Ambler Kiana O Kobuk 0 o0 Selawik Shungnak 0 Anaktuvuk Pass 0 Bettles/Evansville 0 Allakakef/Afatna 0 0Arctic Village Venetie 0 Fort Yukon 0 Beaver 0Cha/kyitsik 0 Birch Creek Oauck/and OHughes Stevens Villarie Circle 0 \. i,� .. Pau/ St. George Gambell 9 Huslia 0 Central Rampart O Koyukuk e7anana O MinT 0Man/ey?mgs Nu/atoO O OGalena ORuby OKaftag r o�· Grayling 0 Takotna Nikolai t,nviko o Shageluk Mt . Viffage0 St. Mary's/Andreafsky Holy Cross Pftka's Poirl" oPilot St<Kion O MarshaP tfuSS1"1nWssion OcrookedCreek Oo 0 McGrath Upper Kalskag_ Atmautfuak Lo�er Kalskag• Aniak Red Devi,«\, OStony River o�huathbaluk S/eefmlie 0 � Ak1achak Ka�igluk Be�e�OTufuksak O Ume Village N/JnapitcllUk 0-Akiak Toks� Biy'-7!ightmute Napakiak Kwet�fuk Chetoma\! T1.11tutu/iak0 .f(apaskiak Osca1Y1le •Eek Nondalton Ko/iganek 1/iamna O Al k • ONew St lJ'jahok \ewh!f'd a.1.:: enag o 0 O ,,;w;n Hms o . . O£kwok 01g;,,g ;g Ko/itolc) T�jal( ,c .ft olJillmgh.m OLevelock M�talC'i,� Claf1{,_'s �oin Na • So h Nal¢ef OKing Satnon ··0° • f d Karluk.� ,,,_ ,�')/;-i oUrsen� �­��arbor �·Ma, . 3. ...... O{=ag/e/Eagfe Village I •.. ,,. . Alaska Energy Regions 1111 1111 LJ LJ LJ 1111 LJ cJ LJ LJ cJ Aleutians Bering Straits Bristol Bay Copper River/Chugach Kodiak Lower Yukon-Kuskokwim North Slope Northwest Arctic Railbelt Southeast Yukon-Koyukuk/Upper Tanana Akut"e:o .. , . ALASKA ENERGY AUTHORITY 0 50 100 200 M; AEA Energy DataA3IS, March, 2019 12 of 185 Adak PCE Utility: TDX ADAK GENERATING LLC Reporting Period: 07/01/22 to 06/30/23 Community Population 179 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 63 Community Facility Customers 12 Other Customers (Non-PCE)99 Fiscal Year PCE Payments $195,829 PCE Statistical Data PCE Eligible kWh - Residential Customers 123,237 Average Annual PCE Payment per Eligible Customer $2,611 PCE Eligible kWh - Community Facility Customers 133,162 Average PCE Payment per Eligible kWh $0.76 Total PCE Eligible kWh 256,399 Last Reported Residential Rate Charged (based on 500 kWh) $1.81 Average Monthly PCE Eligible kWh per Residential Customer 163 Last Reported PCE Level (per kWh)$0.77 Average Monthly PCE Eligible kWh per Community Facility Customer 925 Effective Residential Rate (per kWh)$1.04 Average Monthly PCE Eligible Community Facility kWh per Person 62 PCE Eligible kWh vs Total kWh Sold 21.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,035,684 Fuel Used (Gallons)157,434 Non-Diesel kWh Generated 0 Fuel Cost $977,217 Purchased kWh 0 Average Price of Fuel $6.21 Total Purchased & Generated 2,035,684 Fuel Cost per kWh sold $0.83 Annual Non-Fuel Expenses $625,008 Non-Fuel Expense per kWh Sold $0.53 Total Expense per kWh Sold $1.36 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 138,661 Consumed vs Generated (kWh Sold vs Generated-Purchased) 57.9% Community Facility kWh Sold 198,727 Line Loss (%)24.6% Other kWh Sold (Non-PCE)842,161 Fuel Efficiency (kWh per Gallon of Diesel)12.93 Total kWh Sold 1,179,549 PH Consumption as % of Generation 17.4% Powerhouse (PH) Consumption kWh 355,007 Total kWh Sold & PH Consumption 1,534,556 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 13 of 185 Akhiok PCE Utility: AKHIOK/KAGUYAK ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 58 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 27 Community Facility Customers 1 Other Customers (Non-PCE)15 Fiscal Year PCE Payments $35,739 PCE Statistical Data PCE Eligible kWh - Residential Customers 87,897 Average Annual PCE Payment per Eligible Customer $1,276 PCE Eligible kWh - Community Facility Customers 30,676 Average PCE Payment per Eligible kWh $0.30 Total PCE Eligible kWh 118,573 Last Reported Residential Rate Charged (based on 500 kWh) $0.80 Average Monthly PCE Eligible kWh per Residential Customer 271 Last Reported PCE Level (per kWh)$0.32 Average Monthly PCE Eligible kWh per Community Facility Customer 2,556 Effective Residential Rate (per kWh)$0.48 Average Monthly PCE Eligible Community Facility kWh per Person 44 PCE Eligible kWh vs Total kWh Sold 46.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 296,452 Fuel Used (Gallons)30,360 Non-Diesel kWh Generated 0 Fuel Cost $103,546 Purchased kWh 0 Average Price of Fuel $3.41 Total Purchased & Generated 296,452 Fuel Cost per kWh sold $0.40 Annual Non-Fuel Expenses $36,000 Non-Fuel Expense per kWh Sold $0.14 Total Expense per kWh Sold $0.54 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 94,515 Consumed vs Generated (kWh Sold vs Generated-Purchased) 86.5% Community Facility kWh Sold 44,245 Line Loss (%)9.0% Other kWh Sold (Non-PCE)117,610 Fuel Efficiency (kWh per Gallon of Diesel)9.76 Total kWh Sold 256,370 PH Consumption as % of Generation 4.5% Powerhouse (PH) Consumption kWh 13,303 Total kWh Sold & PH Consumption 269,673 Comments Rpt Fuel Used & Powerhouse Consumption = 11 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 14 of 185 Akiachak PCE Utility: AKIACHAK NATIVE COMMUNITY Reporting Period: 07/01/22 to 06/30/23 Community Population 660 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 190 Community Facility Customers 11 Other Customers (Non-PCE)47 Fiscal Year PCE Payments $263,940 PCE Statistical Data PCE Eligible kWh - Residential Customers 746,744 Average Annual PCE Payment per Eligible Customer $1,313 PCE Eligible kWh - Community Facility Customers 76,445 Average PCE Payment per Eligible kWh $0.32 Total PCE Eligible kWh 823,189 Last Reported Residential Rate Charged (based on 500 kWh) $0.73 Average Monthly PCE Eligible kWh per Residential Customer 328 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 579 Effective Residential Rate (per kWh)$0.40 Average Monthly PCE Eligible Community Facility kWh per Person 10 PCE Eligible kWh vs Total kWh Sold 42.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,077,854 Fuel Used (Gallons)147,540 Non-Diesel kWh Generated 0 Fuel Cost $604,403 Purchased kWh 0 Average Price of Fuel $4.10 Total Purchased & Generated 2,077,854 Fuel Cost per kWh sold $0.31 Annual Non-Fuel Expenses $681,990 Non-Fuel Expense per kWh Sold $0.35 Total Expense per kWh Sold $0.67 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 798,546 Consumed vs Generated (kWh Sold vs Generated-Purchased) 92.7% Community Facility kWh Sold 161,330 Line Loss (%)4.7% Other kWh Sold (Non-PCE)966,958 Fuel Efficiency (kWh per Gallon of Diesel)14.08 Total kWh Sold 1,926,834 PH Consumption as % of Generation 2.5% Powerhouse (PH) Consumption kWh 52,464 Total kWh Sold & PH Consumption 1,979,298 Comments Rpt Diesel kWh Generated = 8 mths Rpt Powerhouse & Peak Consumption = 11 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 15 of 185 Akiak PCE Utility: AKIAK CITY COUNCIL Reporting Period: 07/01/22 to 06/30/23 Community Population 479 Last Reported Month February No. of Monthly Payments Made 8 Residential Customers 97 Community Facility Customers 13 Other Customers (Non-PCE)33 Fiscal Year PCE Payments $89,585 PCE Statistical Data PCE Eligible kWh - Residential Customers 280,118 Average Annual PCE Payment per Eligible Customer $814 PCE Eligible kWh - Community Facility Customers 20,563 Average PCE Payment per Eligible kWh $0.30 Total PCE Eligible kWh 300,681 Last Reported Residential Rate Charged (based on 500 kWh) $0.63 Average Monthly PCE Eligible kWh per Residential Customer 361 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 198 Effective Residential Rate (per kWh)$0.30 Average Monthly PCE Eligible Community Facility kWh per Person 5 PCE Eligible kWh vs Total kWh Sold 27.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,074,308 Fuel Used (Gallons)74,059 Non-Diesel kWh Generated 0 Fuel Cost $332,893 Purchased kWh 0 Average Price of Fuel $4.49 Total Purchased & Generated 1,074,308 Fuel Cost per kWh sold $0.31 Annual Non-Fuel Expenses $156,611 Non-Fuel Expense per kWh Sold $0.14 Total Expense per kWh Sold $0.45 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 318,327 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 120,290 Line Loss (%)See Comments Other kWh Sold (Non-PCE)646,932 Fuel Efficiency (kWh per Gallon of Diesel)14.51 Total kWh Sold 1,085,549 PH Consumption as % of Generation 0.0% Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 1,085,549 Comments Only 8 rpts submitted. Rpt Diesel kWh Gen = 6 mths. No Phouse Consumption Rpt *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 16 of 185 Akutan PCE Utility: CITY OF AKUTAN Reporting Period: 07/01/22 to 06/30/23 Community Population 1,588 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 45 Community Facility Customers 11 Other Customers (Non-PCE)24 Fiscal Year PCE Payments $234,704 PCE Statistical Data PCE Eligible kWh - Residential Customers 185,802 Average Annual PCE Payment per Eligible Customer $4,191 PCE Eligible kWh - Community Facility Customers 125,394 Average PCE Payment per Eligible kWh $0.75 Total PCE Eligible kWh 311,196 Last Reported Residential Rate Charged (based on 500 kWh) $0.95 Average Monthly PCE Eligible kWh per Residential Customer 344 Last Reported PCE Level (per kWh)$0.75 Average Monthly PCE Eligible kWh per Community Facility Customer 950 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 7 PCE Eligible kWh vs Total kWh Sold 60.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 548,069 Fuel Used (Gallons)46,261 Non-Diesel kWh Generated 98,573 Fuel Cost $144,443 Purchased kWh 0 Average Price of Fuel $3.12 Total Purchased & Generated 646,642 Fuel Cost per kWh sold $0.28 Annual Non-Fuel Expenses $226,227 Non-Fuel Expense per kWh Sold $0.44 Total Expense per kWh Sold $0.72 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 192,790 Consumed vs Generated (kWh Sold vs Generated-Purchased) 79.8% Community Facility kWh Sold 125,394 Line Loss (%)7.4% Other kWh Sold (Non-PCE)197,601 Fuel Efficiency (kWh per Gallon of Diesel)11.85 Total kWh Sold 515,785 PH Consumption as % of Generation 12.8% Powerhouse (PH) Consumption kWh 82,962 Total kWh Sold & PH Consumption 598,747 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 17 of 185 Alakanuk PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 737 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 149 Community Facility Customers 9 Other Customers (Non-PCE)35 Fiscal Year PCE Payments $357,370 PCE Statistical Data PCE Eligible kWh - Residential Customers 832,858 Average Annual PCE Payment per Eligible Customer $2,262 PCE Eligible kWh - Community Facility Customers 345,028 Average PCE Payment per Eligible kWh $0.30 Total PCE Eligible kWh 1,177,886 Last Reported Residential Rate Charged (based on 500 kWh) $0.60 Average Monthly PCE Eligible kWh per Residential Customer 466 Last Reported PCE Level (per kWh)$0.34 Average Monthly PCE Eligible kWh per Community Facility Customer 3,195 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 39 PCE Eligible kWh vs Total kWh Sold 58.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $539,228 Non-Fuel Expense per kWh Sold $0.27 Total Expense per kWh Sold $0.27 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 860,305 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 439,595 Line Loss (%)See Comments Other kWh Sold (Non-PCE)699,288 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 1,999,188 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 1,999,188 Comments Receives power from Emmonak via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 18 of 185 Allakaket; Alatna PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 184 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 74 Community Facility Customers 18 Other Customers (Non-PCE)15 Fiscal Year PCE Payments $270,258 PCE Statistical Data PCE Eligible kWh - Residential Customers 216,864 Average Annual PCE Payment per Eligible Customer $2,938 PCE Eligible kWh - Community Facility Customers 136,877 Average PCE Payment per Eligible kWh $0.76 Total PCE Eligible kWh 353,741 Last Reported Residential Rate Charged (based on 500 kWh) $1.10 Average Monthly PCE Eligible kWh per Residential Customer 244 Last Reported PCE Level (per kWh)$0.76 Average Monthly PCE Eligible kWh per Community Facility Customer 634 Effective Residential Rate (per kWh)$0.34 Average Monthly PCE Eligible Community Facility kWh per Person 62 PCE Eligible kWh vs Total kWh Sold 58.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 678,564 Fuel Used (Gallons)55,424 Non-Diesel kWh Generated 0 Fuel Cost $406,619 Purchased kWh 0 Average Price of Fuel $7.34 Total Purchased & Generated 678,564 Fuel Cost per kWh sold $0.67 Annual Non-Fuel Expenses $147,472 Non-Fuel Expense per kWh Sold $0.24 Total Expense per kWh Sold $0.92 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 227,992 Consumed vs Generated (kWh Sold vs Generated-Purchased) 88.8% Community Facility kWh Sold 184,427 Line Loss (%)5.2% Other kWh Sold (Non-PCE)190,161 Fuel Efficiency (kWh per Gallon of Diesel)12.24 Total kWh Sold 602,580 PH Consumption as % of Generation 6.0% Powerhouse (PH) Consumption kWh 40,889 Total kWh Sold & PH Consumption 643,469 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 19 of 185 Ambler PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 255 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 76 Community Facility Customers 12 Other Customers (Non-PCE)22 Fiscal Year PCE Payments $347,252 PCE Statistical Data PCE Eligible kWh - Residential Customers 371,861 Average Annual PCE Payment per Eligible Customer $3,946 PCE Eligible kWh - Community Facility Customers 170,055 Average PCE Payment per Eligible kWh $0.64 Total PCE Eligible kWh 541,916 Last Reported Residential Rate Charged (based on 500 kWh) $0.86 Average Monthly PCE Eligible kWh per Residential Customer 408 Last Reported PCE Level (per kWh)$0.60 Average Monthly PCE Eligible kWh per Community Facility Customer 1,181 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 56 PCE Eligible kWh vs Total kWh Sold 45.4% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,298,918 Fuel Used (Gallons)81,961 Non-Diesel kWh Generated 0 Fuel Cost $576,935 Purchased kWh 0 Average Price of Fuel $7.04 Total Purchased & Generated 1,298,918 Fuel Cost per kWh sold $0.48 Annual Non-Fuel Expenses $275,944 Non-Fuel Expense per kWh Sold $0.23 Total Expense per kWh Sold $0.71 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 479,319 Consumed vs Generated (kWh Sold vs Generated-Purchased) 91.9% Community Facility kWh Sold 276,450 Line Loss (%)4.2% Other kWh Sold (Non-PCE)438,263 Fuel Efficiency (kWh per Gallon of Diesel)15.85 Total kWh Sold 1,194,032 PH Consumption as % of Generation 3.9% Powerhouse (PH) Consumption kWh 50,284 Total kWh Sold & PH Consumption 1,244,316 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 20 of 185 Anaktuvuk Pass PCE Utility: NORTH SLOPE BOROUGH Reporting Period: 07/01/22 to 06/30/23 Community Population 410 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 100 Community Facility Customers 2 Other Customers (Non-PCE)60 Fiscal Year PCE Payments $8,430 PCE Statistical Data PCE Eligible kWh - Residential Customers 375,964 Average Annual PCE Payment per Eligible Customer $83 PCE Eligible kWh - Community Facility Customers 45,326 Average PCE Payment per Eligible kWh $0.02 Total PCE Eligible kWh 421,290 Last Reported Residential Rate Charged (based on 500 kWh) $0.35 Average Monthly PCE Eligible kWh per Residential Customer 313 Last Reported PCE Level (per kWh)$0.15 Average Monthly PCE Eligible kWh per Community Facility Customer 1,889 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 9 PCE Eligible kWh vs Total kWh Sold 11.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 4,149,858 Fuel Used (Gallons)294,861 Non-Diesel kWh Generated 0 Fuel Cost $1,548,294 Purchased kWh 0 Average Price of Fuel $5.25 Total Purchased & Generated 4,149,858 Fuel Cost per kWh sold $0.44 Annual Non-Fuel Expenses $914,420 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.70 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 786,209 Consumed vs Generated (kWh Sold vs Generated-Purchased) 85.2% Community Facility kWh Sold 45,326 Line Loss (%)5.9% Other kWh Sold (Non-PCE)2,704,189 Fuel Efficiency (kWh per Gallon of Diesel)14.07 Total kWh Sold 3,535,724 PH Consumption as % of Generation 8.9% Powerhouse (PH) Consumption kWh 368,715 Total kWh Sold & PH Consumption 3,904,439 Comments Residential PCE Level = Zero *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 21 of 185 Angoon PCE Utility: INSIDE PASSAGE ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 360 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 194 Community Facility Customers 7 Other Customers (Non-PCE)35 Fiscal Year PCE Payments $349,355 PCE Statistical Data PCE Eligible kWh - Residential Customers 691,338 Average Annual PCE Payment per Eligible Customer $1,738 PCE Eligible kWh - Community Facility Customers 165,601 Average PCE Payment per Eligible kWh $0.41 Total PCE Eligible kWh 856,939 Last Reported Residential Rate Charged (based on 500 kWh) $0.63 Average Monthly PCE Eligible kWh per Residential Customer 297 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 1,971 Effective Residential Rate (per kWh)$0.31 Average Monthly PCE Eligible Community Facility kWh per Person 38 PCE Eligible kWh vs Total kWh Sold 50.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,900,016 Fuel Used (Gallons)130,993 Non-Diesel kWh Generated 0 Fuel Cost $580,015 Purchased kWh 0 Average Price of Fuel $4.43 Total Purchased & Generated 1,900,016 Fuel Cost per kWh sold $0.34 Annual Non-Fuel Expenses $747,259 Non-Fuel Expense per kWh Sold $0.44 Total Expense per kWh Sold $0.78 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 860,144 Consumed vs Generated (kWh Sold vs Generated-Purchased) 89.8% Community Facility kWh Sold 165,601 Line Loss (%)7.2% Other kWh Sold (Non-PCE)680,376 Fuel Efficiency (kWh per Gallon of Diesel)14.50 Total kWh Sold 1,706,121 PH Consumption as % of Generation 3.0% Powerhouse (PH) Consumption kWh 56,754 Total kWh Sold & PH Consumption 1,762,875 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 22 of 185 Aniak PCE Utility: ANIAK LIGHT & POWER Reporting Period: 07/01/22 to 06/30/23 Community Population 494 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 186 Community Facility Customers 14 Other Customers (Non-PCE)56 Fiscal Year PCE Payments $219,984 PCE Statistical Data PCE Eligible kWh - Residential Customers 740,812 Average Annual PCE Payment per Eligible Customer $1,100 PCE Eligible kWh - Community Facility Customers 58,466 Average PCE Payment per Eligible kWh $0.28 Total PCE Eligible kWh 799,278 Last Reported Residential Rate Charged (based on 500 kWh) $1.93 Average Monthly PCE Eligible kWh per Residential Customer 332 Last Reported PCE Level (per kWh)$0.77 Average Monthly PCE Eligible kWh per Community Facility Customer 348 Effective Residential Rate (per kWh)$1.17 Average Monthly PCE Eligible Community Facility kWh per Person 10 PCE Eligible kWh vs Total kWh Sold 38.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,457,400 Fuel Used (Gallons)189,716 Non-Diesel kWh Generated 0 Fuel Cost $677,859 Purchased kWh 0 Average Price of Fuel $3.57 Total Purchased & Generated 2,457,400 Fuel Cost per kWh sold $0.33 Annual Non-Fuel Expenses $584,678 Non-Fuel Expense per kWh Sold $0.28 Total Expense per kWh Sold $0.61 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 888,909 Consumed vs Generated (kWh Sold vs Generated-Purchased) 84.0% Community Facility kWh Sold 58,519 Line Loss (%)15.0% Other kWh Sold (Non-PCE)1,116,191 Fuel Efficiency (kWh per Gallon of Diesel)12.95 Total kWh Sold 2,063,619 PH Consumption as % of Generation 1.1% Powerhouse (PH) Consumption kWh 25,927 Total kWh Sold & PH Consumption 2,089,546 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 23 of 185 Anvik PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 61 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 35 Community Facility Customers 9 Other Customers (Non-PCE)22 Fiscal Year PCE Payments $78,886 PCE Statistical Data PCE Eligible kWh - Residential Customers 127,423 Average Annual PCE Payment per Eligible Customer $1,793 PCE Eligible kWh - Community Facility Customers 45,716 Average PCE Payment per Eligible kWh $0.46 Total PCE Eligible kWh 173,139 Last Reported Residential Rate Charged (based on 500 kWh) $0.73 Average Monthly PCE Eligible kWh per Residential Customer 303 Last Reported PCE Level (per kWh)$0.47 Average Monthly PCE Eligible kWh per Community Facility Customer 423 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 62 PCE Eligible kWh vs Total kWh Sold 49.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 395,988 Fuel Used (Gallons)26,794 Non-Diesel kWh Generated 0 Fuel Cost $94,244 Purchased kWh 0 Average Price of Fuel $3.52 Total Purchased & Generated 395,988 Fuel Cost per kWh sold $0.27 Annual Non-Fuel Expenses $88,818 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.53 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 137,318 Consumed vs Generated (kWh Sold vs Generated-Purchased) 87.9% Community Facility kWh Sold 133,375 Line Loss (%)8.3% Other kWh Sold (Non-PCE)77,230 Fuel Efficiency (kWh per Gallon of Diesel)14.78 Total kWh Sold 347,923 PH Consumption as % of Generation 3.8% Powerhouse (PH) Consumption kWh 15,141 Total kWh Sold & PH Consumption 363,064 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 24 of 185 Arctic Village PCE Utility: ARCTIC VILLAGE COUNCIL Reporting Period: 07/01/22 to 06/30/23 Community Population 139 Last Reported Month April No. of Monthly Payments Made 10 Residential Customers 93 Community Facility Customers 6 Other Customers (Non-PCE)19 Fiscal Year PCE Payments $166,590 PCE Statistical Data PCE Eligible kWh - Residential Customers 170,516 Average Annual PCE Payment per Eligible Customer $1,683 PCE Eligible kWh - Community Facility Customers 47,534 Average PCE Payment per Eligible kWh $0.76 Total PCE Eligible kWh 218,050 Last Reported Residential Rate Charged (based on 500 kWh) $1.00 Average Monthly PCE Eligible kWh per Residential Customer 183 Last Reported PCE Level (per kWh)$0.76 Average Monthly PCE Eligible kWh per Community Facility Customer 792 Effective Residential Rate (per kWh)$0.24 Average Monthly PCE Eligible Community Facility kWh per Person 34 PCE Eligible kWh vs Total kWh Sold 38.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 566,233 Fuel Used (Gallons)2,092 Non-Diesel kWh Generated 0 Fuel Cost $17,949 Purchased kWh 0 Average Price of Fuel $8.58 Total Purchased & Generated 566,233 Fuel Cost per kWh sold $0.03 Annual Non-Fuel Expenses $18,000 Non-Fuel Expense per kWh Sold $0.03 Total Expense per kWh Sold $0.06 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 225,502 Consumed vs Generated (kWh Sold vs Generated-Purchased) 100.0% Community Facility kWh Sold 170,919 Line Loss (%)See Comments Other kWh Sold (Non-PCE)169,812 Fuel Efficiency (kWh per Gallon of Diesel)270.67 Total kWh Sold 566,233 PH Consumption as % of Generation 0.0% Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 566,233 Comments 6 rpt filed covers 2 mths ea. Rpt Disl Gen 4 mths, Fuel Used 1, No PHouse rpt *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 25 of 185 Atka PCE Utility: CITY OF ATKA Reporting Period: 07/01/22 to 06/30/23 Community Population 59 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 31 Community Facility Customers 18 Other Customers (Non-PCE)15 Fiscal Year PCE Payments $31,074 PCE Statistical Data PCE Eligible kWh - Residential Customers 96,633 Average Annual PCE Payment per Eligible Customer $634 PCE Eligible kWh - Community Facility Customers 36,454 Average PCE Payment per Eligible kWh $0.23 Total PCE Eligible kWh 133,087 Last Reported Residential Rate Charged (based on 500 kWh) $0.63 Average Monthly PCE Eligible kWh per Residential Customer 260 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 169 Effective Residential Rate (per kWh)$0.29 Average Monthly PCE Eligible Community Facility kWh per Person 51 PCE Eligible kWh vs Total kWh Sold 40.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 79,553 Fuel Used (Gallons)9,508 Non-Diesel kWh Generated 343,000 Fuel Cost $46,220 Purchased kWh 0 Average Price of Fuel $4.86 Total Purchased & Generated 422,553 Fuel Cost per kWh sold $0.14 Annual Non-Fuel Expenses $31,200 Non-Fuel Expense per kWh Sold $0.10 Total Expense per kWh Sold $0.24 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 109,333 Consumed vs Generated (kWh Sold vs Generated-Purchased) 77.2% Community Facility kWh Sold 73,878 Line Loss (%)14.0% Other kWh Sold (Non-PCE)142,898 Fuel Efficiency (kWh per Gallon of Diesel)8.37 Total kWh Sold 326,109 PH Consumption as % of Generation 8.8% Powerhouse (PH) Consumption kWh 37,250 Total kWh Sold & PH Consumption 363,359 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 26 of 185 Atmautluak PCE Utility: ATMAUTLUAK TRIBAL UTILITIES Reporting Period: 07/01/22 to 06/30/23 Community Population 370 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 77 Community Facility Customers 8 Other Customers (Non-PCE)17 Fiscal Year PCE Payments $230,250 PCE Statistical Data PCE Eligible kWh - Residential Customers 398,626 Average Annual PCE Payment per Eligible Customer $2,709 PCE Eligible kWh - Community Facility Customers 97,389 Average PCE Payment per Eligible kWh $0.46 Total PCE Eligible kWh 496,015 Last Reported Residential Rate Charged (based on 500 kWh) $0.66 Average Monthly PCE Eligible kWh per Residential Customer 431 Last Reported PCE Level (per kWh)$0.46 Average Monthly PCE Eligible kWh per Community Facility Customer 1,014 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 22 PCE Eligible kWh vs Total kWh Sold 55.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 852,728 Fuel Used (Gallons)68,525 Non-Diesel kWh Generated 218,084 Fuel Cost $413,193 Purchased kWh 0 Average Price of Fuel $6.03 Total Purchased & Generated 1,070,812 Fuel Cost per kWh sold $0.46 Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.46 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 423,617 Consumed vs Generated (kWh Sold vs Generated-Purchased) 83.4% Community Facility kWh Sold 97,389 Line Loss (%)8.4% Other kWh Sold (Non-PCE)371,902 Fuel Efficiency (kWh per Gallon of Diesel)12.44 Total kWh Sold 892,908 PH Consumption as % of Generation 8.2% Powerhouse (PH) Consumption kWh 88,263 Total kWh Sold & PH Consumption 981,171 Comments Non-fuel Cost Not Reported *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 27 of 185 Atqasuk PCE Utility: NORTH SLOPE BOROUGH Reporting Period: 07/01/22 to 06/30/23 Community Population 289 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 71 Community Facility Customers 2 Other Customers (Non-PCE)55 Fiscal Year PCE Payments $9,150 PCE Statistical Data PCE Eligible kWh - Residential Customers 251,759 Average Annual PCE Payment per Eligible Customer $125 PCE Eligible kWh - Community Facility Customers 60,148 Average PCE Payment per Eligible kWh $0.03 Total PCE Eligible kWh 311,907 Last Reported Residential Rate Charged (based on 500 kWh) $0.35 Average Monthly PCE Eligible kWh per Residential Customer 295 Last Reported PCE Level (per kWh)$0.15 Average Monthly PCE Eligible kWh per Community Facility Customer 2,506 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 17 PCE Eligible kWh vs Total kWh Sold 10.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,885,583 Fuel Used (Gallons)274,794 Non-Diesel kWh Generated 0 Fuel Cost $976,252 Purchased kWh 0 Average Price of Fuel $3.55 Total Purchased & Generated 2,885,583 Fuel Cost per kWh sold $0.32 Annual Non-Fuel Expenses $992,999 Non-Fuel Expense per kWh Sold $0.32 Total Expense per kWh Sold $0.64 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 689,175 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 60,148 Line Loss (%)See Comments Other kWh Sold (Non-PCE)2,322,738 Fuel Efficiency (kWh per Gallon of Diesel)10.50 Total kWh Sold 3,072,061 PH Consumption as % of Generation 13.0% Powerhouse (PH) Consumption kWh 375,785 Total kWh Sold & PH Consumption 3,447,846 Comments Residential PCE Level = Zero *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 28 of 185 Bethel; Oscarville PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 6,437 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 1,674 Community Facility Customers 44 Other Customers (Non-PCE)1,093 Fiscal Year PCE Payments $2,745,585 PCE Statistical Data PCE Eligible kWh - Residential Customers 9,088,380 Average Annual PCE Payment per Eligible Customer $1,598 PCE Eligible kWh - Community Facility Customers 2,577,796 Average PCE Payment per Eligible kWh $0.24 Total PCE Eligible kWh 11,666,176 Last Reported Residential Rate Charged (based on 500 kWh) $0.51 Average Monthly PCE Eligible kWh per Residential Customer 452 Last Reported PCE Level (per kWh)$0.25 Average Monthly PCE Eligible kWh per Community Facility Customer 4,882 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 33 PCE Eligible kWh vs Total kWh Sold 28.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 44,139,949 Fuel Used (Gallons)2,742,385 Non-Diesel kWh Generated 1,706,316 Fuel Cost $13,693,685 Purchased kWh 0 Average Price of Fuel $4.99 Total Purchased & Generated 45,846,265 Fuel Cost per kWh sold $0.33 Annual Non-Fuel Expenses $10,633,277 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.58 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 10,156,354 Consumed vs Generated (kWh Sold vs Generated-Purchased) 90.9% Community Facility kWh Sold 9,986,917 Line Loss (%)7.3% Other kWh Sold (Non-PCE)21,509,788 Fuel Efficiency (kWh per Gallon of Diesel)16.10 Total kWh Sold 41,653,059 PH Consumption as % of Generation 1.9% Powerhouse (PH) Consumption kWh 852,620 Total kWh Sold & PH Consumption 42,505,679 Comments Sells power to Napakiak Ircinraq Power Co for resale *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 29 of 185 Bettles; Evansville PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 34 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 33 Community Facility Customers 8 Other Customers (Non-PCE)28 Fiscal Year PCE Payments $50,916 PCE Statistical Data PCE Eligible kWh - Residential Customers 81,778 Average Annual PCE Payment per Eligible Customer $1,242 PCE Eligible kWh - Community Facility Customers 26,427 Average PCE Payment per Eligible kWh $0.47 Total PCE Eligible kWh 108,205 Last Reported Residential Rate Charged (based on 500 kWh) $0.78 Average Monthly PCE Eligible kWh per Residential Customer 207 Last Reported PCE Level (per kWh)$0.47 Average Monthly PCE Eligible kWh per Community Facility Customer 275 Effective Residential Rate (per kWh)$0.30 Average Monthly PCE Eligible Community Facility kWh per Person 65 PCE Eligible kWh vs Total kWh Sold 23.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 517,600 Fuel Used (Gallons)42,035 Non-Diesel kWh Generated 0 Fuel Cost $146,269 Purchased kWh 0 Average Price of Fuel $3.48 Total Purchased & Generated 517,600 Fuel Cost per kWh sold $0.31 Annual Non-Fuel Expenses $177,293 Non-Fuel Expense per kWh Sold $0.38 Total Expense per kWh Sold $0.70 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 102,240 Consumed vs Generated (kWh Sold vs Generated-Purchased) 89.9% Community Facility kWh Sold 35,461 Line Loss (%)5.3% Other kWh Sold (Non-PCE)327,467 Fuel Efficiency (kWh per Gallon of Diesel)12.31 Total kWh Sold 465,168 PH Consumption as % of Generation 4.8% Powerhouse (PH) Consumption kWh 24,903 Total kWh Sold & PH Consumption 490,071 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 30 of 185 Brevig Mission PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 414 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 85 Community Facility Customers 8 Other Customers (Non-PCE)32 Fiscal Year PCE Payments $188,598 PCE Statistical Data PCE Eligible kWh - Residential Customers 516,387 Average Annual PCE Payment per Eligible Customer $2,028 PCE Eligible kWh - Community Facility Customers 178,230 Average PCE Payment per Eligible kWh $0.27 Total PCE Eligible kWh 694,617 Last Reported Residential Rate Charged (based on 500 kWh) $0.51 Average Monthly PCE Eligible kWh per Residential Customer 506 Last Reported PCE Level (per kWh)$0.27 Average Monthly PCE Eligible kWh per Community Facility Customer 1,857 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 36 PCE Eligible kWh vs Total kWh Sold 55.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,348,662 Fuel Used (Gallons)85,031 Non-Diesel kWh Generated 0 Fuel Cost $238,613 Purchased kWh 0 Average Price of Fuel $2.81 Total Purchased & Generated 1,348,662 Fuel Cost per kWh sold $0.19 Annual Non-Fuel Expenses $318,739 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.45 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 553,555 Consumed vs Generated (kWh Sold vs Generated-Purchased) 92.6% Community Facility kWh Sold 289,080 Line Loss (%)2.7% Other kWh Sold (Non-PCE)405,942 Fuel Efficiency (kWh per Gallon of Diesel)15.86 Total kWh Sold 1,248,577 PH Consumption as % of Generation 4.7% Powerhouse (PH) Consumption kWh 63,088 Total kWh Sold & PH Consumption 1,311,665 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 31 of 185 Buckland PCE Utility: CITY OF BUCKLAND Reporting Period: 07/01/22 to 06/30/23 Community Population 573 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 108 Community Facility Customers 12 Other Customers (Non-PCE)26 Fiscal Year PCE Payments $186,800 PCE Statistical Data PCE Eligible kWh - Residential Customers 684,623 Average Annual PCE Payment per Eligible Customer $1,557 PCE Eligible kWh - Community Facility Customers 120,543 Average PCE Payment per Eligible kWh $0.23 Total PCE Eligible kWh 805,166 Last Reported Residential Rate Charged (based on 500 kWh) $0.50 Average Monthly PCE Eligible kWh per Residential Customer 528 Last Reported PCE Level (per kWh)$0.29 Average Monthly PCE Eligible kWh per Community Facility Customer 837 Effective Residential Rate (per kWh)$0.21 Average Monthly PCE Eligible Community Facility kWh per Person 18 PCE Eligible kWh vs Total kWh Sold 44.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,788,191 Fuel Used (Gallons)172,335 Non-Diesel kWh Generated 189,145 Fuel Cost $703,513 Purchased kWh 0 Average Price of Fuel $4.08 Total Purchased & Generated 1,977,336 Fuel Cost per kWh sold $0.39 Annual Non-Fuel Expenses $54,254 Non-Fuel Expense per kWh Sold $0.03 Total Expense per kWh Sold $0.42 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 849,405 Consumed vs Generated (kWh Sold vs Generated-Purchased) 91.3% Community Facility kWh Sold 120,543 Line Loss (%)5.3% Other kWh Sold (Non-PCE)835,827 Fuel Efficiency (kWh per Gallon of Diesel)10.38 Total kWh Sold 1,805,775 PH Consumption as % of Generation 3.4% Powerhouse (PH) Consumption kWh 67,275 Total kWh Sold & PH Consumption 1,873,050 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 32 of 185 Central PCE Utility: GOLD COUNTRY ENERGY Reporting Period: 07/01/22 to 06/30/23 Community Population 64 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 124 Community Facility Customers 1 Other Customers (Non-PCE)19 Fiscal Year PCE Payments $104,458 PCE Statistical Data PCE Eligible kWh - Residential Customers 182,729 Average Annual PCE Payment per Eligible Customer $836 PCE Eligible kWh - Community Facility Customers 3,193 Average PCE Payment per Eligible kWh $0.56 Total PCE Eligible kWh 185,922 Last Reported Residential Rate Charged (based on 500 kWh) $0.78 Average Monthly PCE Eligible kWh per Residential Customer 123 Last Reported PCE Level (per kWh)$0.43 Average Monthly PCE Eligible kWh per Community Facility Customer 266 Effective Residential Rate (per kWh)$0.36 Average Monthly PCE Eligible Community Facility kWh per Person 4 PCE Eligible kWh vs Total kWh Sold 57.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 428,341 Fuel Used (Gallons)38,933 Non-Diesel kWh Generated 0 Fuel Cost $170,457 Purchased kWh 0 Average Price of Fuel $4.38 Total Purchased & Generated 428,341 Fuel Cost per kWh sold $0.53 Annual Non-Fuel Expenses $156,228 Non-Fuel Expense per kWh Sold $0.48 Total Expense per kWh Sold $1.01 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 199,202 Consumed vs Generated (kWh Sold vs Generated-Purchased) 75.5% Community Facility kWh Sold 3,193 Line Loss (%)19.9% Other kWh Sold (Non-PCE)121,114 Fuel Efficiency (kWh per Gallon of Diesel)11.00 Total kWh Sold 323,509 PH Consumption as % of Generation 4.6% Powerhouse (PH) Consumption kWh 19,693 Total kWh Sold & PH Consumption 343,202 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 33 of 185 Chefornak PCE Utility: NATERKAQ LIGHT PLANT Reporting Period: 07/01/22 to 06/30/23 Community Population 504 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 102 Community Facility Customers 18 Other Customers (Non-PCE)28 Fiscal Year PCE Payments $255,828 PCE Statistical Data PCE Eligible kWh - Residential Customers 564,628 Average Annual PCE Payment per Eligible Customer $2,132 PCE Eligible kWh - Community Facility Customers 56,799 Average PCE Payment per Eligible kWh $0.41 Total PCE Eligible kWh 621,427 Last Reported Residential Rate Charged (based on 500 kWh) $0.74 Average Monthly PCE Eligible kWh per Residential Customer 461 Last Reported PCE Level (per kWh)$0.42 Average Monthly PCE Eligible kWh per Community Facility Customer 263 Effective Residential Rate (per kWh)$0.32 Average Monthly PCE Eligible Community Facility kWh per Person 9 PCE Eligible kWh vs Total kWh Sold 43.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,365,397 Fuel Used (Gallons)106,203 Non-Diesel kWh Generated 202,813 Fuel Cost $556,893 Purchased kWh 0 Average Price of Fuel $5.24 Total Purchased & Generated 1,568,210 Fuel Cost per kWh sold $0.39 Annual Non-Fuel Expenses $411,642 Non-Fuel Expense per kWh Sold $0.29 Total Expense per kWh Sold $0.68 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 602,769 Consumed vs Generated (kWh Sold vs Generated-Purchased) 90.7% Community Facility kWh Sold 72,383 Line Loss (%)7.9% Other kWh Sold (Non-PCE)746,745 Fuel Efficiency (kWh per Gallon of Diesel)12.86 Total kWh Sold 1,421,897 PH Consumption as % of Generation 1.5% Powerhouse (PH) Consumption kWh 23,207 Total kWh Sold & PH Consumption 1,445,104 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 34 of 185 Chenega Bay PCE Utility: NATIVE VILLAGE OF CHENEGA Reporting Period: 07/01/22 to 06/30/23 Community Population 65 Last Reported Month May No. of Monthly Payments Made 11 Residential Customers 20 Community Facility Customers 9 Other Customers (Non-PCE)18 Fiscal Year PCE Payments $52,922 PCE Statistical Data PCE Eligible kWh - Residential Customers 54,924 Average Annual PCE Payment per Eligible Customer $1,825 PCE Eligible kWh - Community Facility Customers 44,263 Average PCE Payment per Eligible kWh $0.53 Total PCE Eligible kWh 99,187 Last Reported Residential Rate Charged (based on 500 kWh) $1.12 Average Monthly PCE Eligible kWh per Residential Customer 250 Last Reported PCE Level (per kWh)$0.76 Average Monthly PCE Eligible kWh per Community Facility Customer 447 Effective Residential Rate (per kWh)$0.36 Average Monthly PCE Eligible Community Facility kWh per Person 62 PCE Eligible kWh vs Total kWh Sold 51.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 232,308 Fuel Used (Gallons)20,869 Non-Diesel kWh Generated 0 Fuel Cost $103,629 Purchased kWh 0 Average Price of Fuel $4.97 Total Purchased & Generated 232,308 Fuel Cost per kWh sold $0.53 Annual Non-Fuel Expenses $79,517 Non-Fuel Expense per kWh Sold $0.41 Total Expense per kWh Sold $0.94 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 59,353 Consumed vs Generated (kWh Sold vs Generated-Purchased) 83.6% Community Facility kWh Sold 59,354 Line Loss (%)10.6% Other kWh Sold (Non-PCE)75,616 Fuel Efficiency (kWh per Gallon of Diesel)11.13 Total kWh Sold 194,323 PH Consumption as % of Generation 5.7% Powerhouse (PH) Consumption kWh 13,252 Total kWh Sold & PH Consumption 207,575 Comments Only 11 reports filed. Diesel kWh Generated = 10 mths rpt *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 35 of 185 Chevak PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 939 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 205 Community Facility Customers 9 Other Customers (Non-PCE)44 Fiscal Year PCE Payments $436,364 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,059,157 Average Annual PCE Payment per Eligible Customer $2,039 PCE Eligible kWh - Community Facility Customers 336,947 Average PCE Payment per Eligible kWh $0.31 Total PCE Eligible kWh 1,396,104 Last Reported Residential Rate Charged (based on 500 kWh) $0.68 Average Monthly PCE Eligible kWh per Residential Customer 431 Last Reported PCE Level (per kWh)$0.40 Average Monthly PCE Eligible kWh per Community Facility Customer 3,120 Effective Residential Rate (per kWh)$0.28 Average Monthly PCE Eligible Community Facility kWh per Person 30 PCE Eligible kWh vs Total kWh Sold 54.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,341,627 Fuel Used (Gallons)97,156 Non-Diesel kWh Generated 359,810 Fuel Cost $361,757 Purchased kWh 0 Average Price of Fuel $3.72 Total Purchased & Generated 2,701,437 Fuel Cost per kWh sold $0.14 Annual Non-Fuel Expenses $653,113 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.40 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,161,636 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.7% Community Facility kWh Sold 579,737 Line Loss (%)2.7% Other kWh Sold (Non-PCE)817,026 Fuel Efficiency (kWh per Gallon of Diesel)24.10 Total kWh Sold 2,558,399 PH Consumption as % of Generation 2.6% Powerhouse (PH) Consumption kWh 69,721 Total kWh Sold & PH Consumption 2,628,120 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 36 of 185 Chignik Lagoon PCE Utility: CHIGNIK LAGOON POWER UTILITY Reporting Period: 07/01/22 to 06/30/23 Community Population 72 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 67 Community Facility Customers 7 Other Customers (Non-PCE)15 Fiscal Year PCE Payments $112,501 PCE Statistical Data PCE Eligible kWh - Residential Customers 178,566 Average Annual PCE Payment per Eligible Customer $1,520 PCE Eligible kWh - Community Facility Customers 41,341 Average PCE Payment per Eligible kWh $0.51 Total PCE Eligible kWh 219,907 Last Reported Residential Rate Charged (based on 500 kWh) $0.90 Average Monthly PCE Eligible kWh per Residential Customer 222 Last Reported PCE Level (per kWh)$0.62 Average Monthly PCE Eligible kWh per Community Facility Customer 492 Effective Residential Rate (per kWh)$0.28 Average Monthly PCE Eligible Community Facility kWh per Person 48 PCE Eligible kWh vs Total kWh Sold 52.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 326,734 Fuel Used (Gallons)26,744 Non-Diesel kWh Generated 148,899 Fuel Cost $135,340 Purchased kWh 0 Average Price of Fuel $5.06 Total Purchased & Generated 475,633 Fuel Cost per kWh sold $0.32 Annual Non-Fuel Expenses $111,449 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.59 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 232,651 Consumed vs Generated (kWh Sold vs Generated-Purchased) 88.4% Community Facility kWh Sold 41,341 Line Loss (%)4.8% Other kWh Sold (Non-PCE)146,633 Fuel Efficiency (kWh per Gallon of Diesel)12.22 Total kWh Sold 420,625 PH Consumption as % of Generation 6.7% Powerhouse (PH) Consumption kWh 32,010 Total kWh Sold & PH Consumption 452,635 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 37 of 185 Chignik Lake PCE Utility: CHIGNIK LAKE ELECTRIC UTILITY Reporting Period: 07/01/22 to 06/30/23 Community Population 63 Last Reported Month June No. of Monthly Payments Made 11 Residential Customers 42 Community Facility Customers 8 Other Customers (Non-PCE)5 Fiscal Year PCE Payments $55,144 PCE Statistical Data PCE Eligible kWh - Residential Customers 90,018 Average Annual PCE Payment per Eligible Customer $1,103 PCE Eligible kWh - Community Facility Customers 36,692 Average PCE Payment per Eligible kWh $0.44 Total PCE Eligible kWh 126,710 Last Reported Residential Rate Charged (based on 500 kWh) $0.70 Average Monthly PCE Eligible kWh per Residential Customer 195 Last Reported PCE Level (per kWh)$0.44 Average Monthly PCE Eligible kWh per Community Facility Customer 417 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 53 PCE Eligible kWh vs Total kWh Sold 46.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 311,462 Fuel Used (Gallons)32,238 Non-Diesel kWh Generated 0 Fuel Cost $135,483 Purchased kWh 0 Average Price of Fuel $4.20 Total Purchased & Generated 311,462 Fuel Cost per kWh sold $0.50 Annual Non-Fuel Expenses $30,300 Non-Fuel Expense per kWh Sold $0.11 Total Expense per kWh Sold $0.61 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 118,496 Consumed vs Generated (kWh Sold vs Generated-Purchased) 87.5% Community Facility kWh Sold 42,946 Line Loss (%)7.6% Other kWh Sold (Non-PCE)111,053 Fuel Efficiency (kWh per Gallon of Diesel)9.66 Total kWh Sold 272,495 PH Consumption as % of Generation 5.0% Powerhouse (PH) Consumption kWh 15,425 Total kWh Sold & PH Consumption 287,920 Comments Only 11 reports filed. Power House kWh Generated = 10 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 38 of 185 Chignik PCE Utility: CITY OF CHIGNIK Reporting Period: 07/01/22 to 06/30/23 Community Population 84 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 43 Community Facility Customers 14 Other Customers (Non-PCE)40 Fiscal Year PCE Payments $10,767 PCE Statistical Data PCE Eligible kWh - Residential Customers 106,555 Average Annual PCE Payment per Eligible Customer $189 PCE Eligible kWh - Community Facility Customers 70,560 Average PCE Payment per Eligible kWh $0.06 Total PCE Eligible kWh 177,115 Last Reported Residential Rate Charged (based on 500 kWh) $0.42 Average Monthly PCE Eligible kWh per Residential Customer 207 Last Reported PCE Level (per kWh)$0.17 Average Monthly PCE Eligible kWh per Community Facility Customer 420 Effective Residential Rate (per kWh)$0.24 Average Monthly PCE Eligible Community Facility kWh per Person 70 PCE Eligible kWh vs Total kWh Sold 29.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 664,227 Fuel Used (Gallons)51,265 Non-Diesel kWh Generated 0 Fuel Cost $25,571 Purchased kWh 0 Average Price of Fuel $0.50 Total Purchased & Generated 664,227 Fuel Cost per kWh sold $0.04 Annual Non-Fuel Expenses $119,825 Non-Fuel Expense per kWh Sold $0.20 Total Expense per kWh Sold $0.24 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 111,455 Consumed vs Generated (kWh Sold vs Generated-Purchased) 92.0% Community Facility kWh Sold 128,130 Line Loss (%)4.4% Other kWh Sold (Non-PCE)371,783 Fuel Efficiency (kWh per Gallon of Diesel)12.96 Total kWh Sold 611,368 PH Consumption as % of Generation 3.6% Powerhouse (PH) Consumption kWh 23,864 Total kWh Sold & PH Consumption 635,232 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 39 of 185 Chilkat Valley PCE Utility: INSIDE PASSAGE ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 591 Last Reported Month December No. of Monthly Payments Made 6 Residential Customers 221 Community Facility Customers 2 Other Customers (Non-PCE)39 Fiscal Year PCE Payments $144,336 PCE Statistical Data PCE Eligible kWh - Residential Customers 321,755 Average Annual PCE Payment per Eligible Customer $647 PCE Eligible kWh - Community Facility Customers 4,395 Average PCE Payment per Eligible kWh $0.44 Total PCE Eligible kWh 326,150 Last Reported Residential Rate Charged (based on 500 kWh) $0.68 Average Monthly PCE Eligible kWh per Residential Customer 243 Last Reported PCE Level (per kWh)$0.39 Average Monthly PCE Eligible kWh per Community Facility Customer 366 Effective Residential Rate (per kWh)$0.29 Average Monthly PCE Eligible Community Facility kWh per Person 1 PCE Eligible kWh vs Total kWh Sold 60.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 738,480 Fuel Cost $0 Purchased kWh 136,080 Average Price of Fuel $0.00 Total Purchased & Generated 874,560 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.00 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 342,330 Consumed vs Generated (kWh Sold vs Generated-Purchased) 61.9% Community Facility kWh Sold 4,395 Line Loss (%)34.8% Other kWh Sold (Non-PCE)194,928 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 541,653 PH Consumption as % of Generation 3.2% Powerhouse (PH) Consumption kWh 28,238 Total kWh Sold & PH Consumption 569,891 Comments July-Dec repts. Combined w/Kluckwan-Jan. forward *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 40 of 185 Chilkat Valley/Klukwan Utility: INSIDE PASSAGE ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 679 Last Reported Month June No. of Monthly Payments Made 6 Residential Customers 272 Community Facility Customers 11 Other Customers (Non-PCE)48 Fiscal Year PCE Payments $193,122 PCE Statistical Data PCE Eligible kWh - Residential Customers 433,447 Average Annual PCE Payment per Eligible Customer $682 PCE Eligible kWh - Community Facility Customers 64,707 Average PCE Payment per Eligible kWh $0.39 Total PCE Eligible kWh 498,154 Last Reported Residential Rate Charged (based on 500 kWh) $0.63 Average Monthly PCE Eligible kWh per Residential Customer 266 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 980 Effective Residential Rate (per kWh)$0.31 Average Monthly PCE Eligible Community Facility kWh per Person 16 PCE Eligible kWh vs Total kWh Sold 61.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 327,360 Fuel Cost $0 Purchased kWh 624,240 Average Price of Fuel $0.00 Total Purchased & Generated 951,600 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $384,052 Non-Fuel Expense per kWh Sold $0.47 Total Expense per kWh Sold $0.47 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 479,033 Consumed vs Generated (kWh Sold vs Generated-Purchased) 85.2% Community Facility kWh Sold 64,707 Line Loss (%)11.4% Other kWh Sold (Non-PCE)266,638 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 810,378 PH Consumption as % of Generation 3.4% Powerhouse (PH) Consumption kWh 32,656 Total kWh Sold & PH Consumption 843,034 Comments 6 rpts. PHouse Cnsm = 5 See individual rpts July-Dec. Purch pwr - AK Power *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 41 of 185 Chistochina PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 59 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 51 Community Facility Customers 2 Other Customers (Non-PCE)18 Fiscal Year PCE Payments $82,155 PCE Statistical Data PCE Eligible kWh - Residential Customers 152,479 Average Annual PCE Payment per Eligible Customer $1,550 PCE Eligible kWh - Community Facility Customers 26,481 Average PCE Payment per Eligible kWh $0.46 Total PCE Eligible kWh 178,960 Last Reported Residential Rate Charged (based on 500 kWh) $0.66 Average Monthly PCE Eligible kWh per Residential Customer 249 Last Reported PCE Level (per kWh)$0.36 Average Monthly PCE Eligible kWh per Community Facility Customer 1,103 Effective Residential Rate (per kWh)$0.30 Average Monthly PCE Eligible Community Facility kWh per Person 37 PCE Eligible kWh vs Total kWh Sold 50.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.00 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 161,800 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 26,481 Line Loss (%)See Comments Other kWh Sold (Non-PCE)164,599 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 352,880 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 1,426 Total kWh Sold & PH Consumption 354,306 Comments See Slana for power generation. No Non-Fuel Expenses Reported *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 42 of 185 Chitina PCE Utility: CHITINA ELECTRIC INC. Reporting Period: 07/01/22 to 06/30/23 Community Population 97 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 50 Community Facility Customers 3 Other Customers (Non-PCE)31 Fiscal Year PCE Payments $83,832 PCE Statistical Data PCE Eligible kWh - Residential Customers 101,435 Average Annual PCE Payment per Eligible Customer $1,582 PCE Eligible kWh - Community Facility Customers 10,022 Average PCE Payment per Eligible kWh $0.75 Total PCE Eligible kWh 111,457 Last Reported Residential Rate Charged (based on 500 kWh) $1.10 Average Monthly PCE Eligible kWh per Residential Customer 169 Last Reported PCE Level (per kWh)$0.77 Average Monthly PCE Eligible kWh per Community Facility Customer 278 Effective Residential Rate (per kWh)$0.33 Average Monthly PCE Eligible Community Facility kWh per Person 9 PCE Eligible kWh vs Total kWh Sold 30.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 454,964 Fuel Used (Gallons)41,844 Non-Diesel kWh Generated 0 Fuel Cost $201,534 Purchased kWh 0 Average Price of Fuel $4.82 Total Purchased & Generated 454,964 Fuel Cost per kWh sold $0.55 Annual Non-Fuel Expenses $458,667 Non-Fuel Expense per kWh Sold $1.24 Total Expense per kWh Sold $1.79 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 105,018 Consumed vs Generated (kWh Sold vs Generated-Purchased) 81.0% Community Facility kWh Sold 10,022 Line Loss (%)15.1% Other kWh Sold (Non-PCE)253,453 Fuel Efficiency (kWh per Gallon of Diesel)10.87 Total kWh Sold 368,493 PH Consumption as % of Generation 3.9% Powerhouse (PH) Consumption kWh 17,833 Total kWh Sold & PH Consumption 386,326 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 43 of 185 Chuathbaluk PCE Utility: MIDDLE KUSKOKWIM ELECTRIC COOPERATIVE INC Reporting Period: 07/01/22 to 06/30/23 Community Population 93 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 31 Community Facility Customers 10 Other Customers (Non-PCE)6 Fiscal Year PCE Payments $111,888 PCE Statistical Data PCE Eligible kWh - Residential Customers 88,252 Average Annual PCE Payment per Eligible Customer $2,729 PCE Eligible kWh - Community Facility Customers 58,198 Average PCE Payment per Eligible kWh $0.76 Total PCE Eligible kWh 146,450 Last Reported Residential Rate Charged (based on 500 kWh) $1.43 Average Monthly PCE Eligible kWh per Residential Customer 237 Last Reported PCE Level (per kWh)$0.76 Average Monthly PCE Eligible kWh per Community Facility Customer 485 Effective Residential Rate (per kWh)$0.67 Average Monthly PCE Eligible Community Facility kWh per Person 52 PCE Eligible kWh vs Total kWh Sold 62.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 278,593 Fuel Used (Gallons)28,008 Non-Diesel kWh Generated 0 Fuel Cost $107,937 Purchased kWh 0 Average Price of Fuel $3.85 Total Purchased & Generated 278,593 Fuel Cost per kWh sold $0.46 Annual Non-Fuel Expenses $175,752 Non-Fuel Expense per kWh Sold $0.75 Total Expense per kWh Sold $1.21 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 95,414 Consumed vs Generated (kWh Sold vs Generated-Purchased) 83.8% Community Facility kWh Sold 62,402 Line Loss (%)8.4% Other kWh Sold (Non-PCE)75,685 Fuel Efficiency (kWh per Gallon of Diesel)9.95 Total kWh Sold 233,501 PH Consumption as % of Generation 7.8% Powerhouse (PH) Consumption kWh 21,608 Total kWh Sold & PH Consumption 255,109 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 44 of 185 Circle PCE Utility: CIRCLE ELECTRIC LLC Reporting Period: 07/01/22 to 06/30/23 Community Population 76 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 44 Community Facility Customers 7 Other Customers (Non-PCE)13 Fiscal Year PCE Payments $130,598 PCE Statistical Data PCE Eligible kWh - Residential Customers 127,779 Average Annual PCE Payment per Eligible Customer $2,561 PCE Eligible kWh - Community Facility Customers 60,833 Average PCE Payment per Eligible kWh $0.69 Total PCE Eligible kWh 188,612 Last Reported Residential Rate Charged (based on 500 kWh) $1.02 Average Monthly PCE Eligible kWh per Residential Customer 242 Last Reported PCE Level (per kWh)$0.67 Average Monthly PCE Eligible kWh per Community Facility Customer 724 Effective Residential Rate (per kWh)$0.34 Average Monthly PCE Eligible Community Facility kWh per Person 67 PCE Eligible kWh vs Total kWh Sold 47.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 398,997 Fuel Used (Gallons)37,860 Non-Diesel kWh Generated 0 Fuel Cost $171,364 Purchased kWh 0 Average Price of Fuel $4.53 Total Purchased & Generated 398,997 Fuel Cost per kWh sold $0.43 Annual Non-Fuel Expenses $148,198 Non-Fuel Expense per kWh Sold $0.37 Total Expense per kWh Sold $0.81 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 140,172 Consumed vs Generated (kWh Sold vs Generated-Purchased) 99.2% Community Facility kWh Sold 108,244 Line Loss (%)See Comments Other kWh Sold (Non-PCE)147,371 Fuel Efficiency (kWh per Gallon of Diesel)10.54 Total kWh Sold 395,787 PH Consumption as % of Generation 2.8% Powerhouse (PH) Consumption kWh 11,325 Total kWh Sold & PH Consumption 407,112 Comments Reported Diesel kWh Gen & Power House Consumption = 10 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 45 of 185 Clark's Point PCE Utility: CLARKS POINT VILLAGE COUNCIL Reporting Period: 07/01/22 to 06/30/23 Community Population 75 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 20 Community Facility Customers 5 Other Customers (Non-PCE)31 Fiscal Year PCE Payments $96,843 PCE Statistical Data PCE Eligible kWh - Residential Customers 125,548 Average Annual PCE Payment per Eligible Customer $3,874 PCE Eligible kWh - Community Facility Customers 14,236 Average PCE Payment per Eligible kWh $0.69 Total PCE Eligible kWh 139,784 Last Reported Residential Rate Charged (based on 500 kWh) $0.93 Average Monthly PCE Eligible kWh per Residential Customer 523 Last Reported PCE Level (per kWh)$0.74 Average Monthly PCE Eligible kWh per Community Facility Customer 237 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 16 PCE Eligible kWh vs Total kWh Sold 53.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 368,463 Fuel Used (Gallons)36,102 Non-Diesel kWh Generated 0 Fuel Cost $141,601 Purchased kWh 0 Average Price of Fuel $3.92 Total Purchased & Generated 368,463 Fuel Cost per kWh sold $0.54 Annual Non-Fuel Expenses $36,000 Non-Fuel Expense per kWh Sold $0.14 Total Expense per kWh Sold $0.67 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 134,372 Consumed vs Generated (kWh Sold vs Generated-Purchased) 71.5% Community Facility kWh Sold 28,881 Line Loss (%)22.6% Other kWh Sold (Non-PCE)100,138 Fuel Efficiency (kWh per Gallon of Diesel)10.21 Total kWh Sold 263,391 PH Consumption as % of Generation 5.9% Powerhouse (PH) Consumption kWh 21,751 Total kWh Sold & PH Consumption 285,142 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 46 of 185 Coffman Cove PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 187 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 195 Community Facility Customers 14 Other Customers (Non-PCE)55 Fiscal Year PCE Payments $48,336 PCE Statistical Data PCE Eligible kWh - Residential Customers 697,126 Average Annual PCE Payment per Eligible Customer $231 PCE Eligible kWh - Community Facility Customers 87,052 Average PCE Payment per Eligible kWh $0.06 Total PCE Eligible kWh 784,178 Last Reported Residential Rate Charged (based on 500 kWh) $0.32 Average Monthly PCE Eligible kWh per Residential Customer 298 Last Reported PCE Level (per kWh)$0.07 Average Monthly PCE Eligible kWh per Community Facility Customer 518 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 39 PCE Eligible kWh vs Total kWh Sold 57.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.00 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 935,116 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 87,052 Line Loss (%)See Comments Other kWh Sold (Non-PCE)335,465 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 1,357,633 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 40,750 Total kWh Sold & PH Consumption 1,398,383 Comments See Craig for power generation. No Non-Fuel Expenses Reported *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 47 of 185 Cold Bay PCE Utility: G & K INC. Reporting Period: 07/01/22 to 06/30/23 Community Population 54 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 46 Community Facility Customers 4 Other Customers (Non-PCE)77 Fiscal Year PCE Payments $61,558 PCE Statistical Data PCE Eligible kWh - Residential Customers 55,933 Average Annual PCE Payment per Eligible Customer $1,231 PCE Eligible kWh - Community Facility Customers 42,540 Average PCE Payment per Eligible kWh $0.63 Total PCE Eligible kWh 98,473 Last Reported Residential Rate Charged (based on 500 kWh) $0.90 Average Monthly PCE Eligible kWh per Residential Customer 101 Last Reported PCE Level (per kWh)$0.72 Average Monthly PCE Eligible kWh per Community Facility Customer 886 Effective Residential Rate (per kWh)$0.18 Average Monthly PCE Eligible Community Facility kWh per Person 66 PCE Eligible kWh vs Total kWh Sold 4.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,457,360 Fuel Used (Gallons)189,117 Non-Diesel kWh Generated 0 Fuel Cost $1,294,629 Purchased kWh 0 Average Price of Fuel $6.85 Total Purchased & Generated 2,457,360 Fuel Cost per kWh sold $0.64 Annual Non-Fuel Expenses $503,722 Non-Fuel Expense per kWh Sold $0.25 Total Expense per kWh Sold $0.89 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 191,518 Consumed vs Generated (kWh Sold vs Generated-Purchased) 82.3% Community Facility kWh Sold 48,016 Line Loss (%)10.3% Other kWh Sold (Non-PCE)1,781,777 Fuel Efficiency (kWh per Gallon of Diesel)12.99 Total kWh Sold 2,021,311 PH Consumption as % of Generation 7.5% Powerhouse (PH) Consumption kWh 183,556 Total kWh Sold & PH Consumption 2,204,867 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 48 of 185 Cordova PCE: Eyak PCE Utility: CORDOVA ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 2,676 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 990 Community Facility Customers 52 Other Customers (Non-PCE)705 Fiscal Year PCE Payments $642,668 PCE Statistical Data PCE Eligible kWh - Residential Customers 3,827,708 Average Annual PCE Payment per Eligible Customer $617 PCE Eligible kWh - Community Facility Customers 2,036,846 Average PCE Payment per Eligible kWh $0.11 Total PCE Eligible kWh 5,864,554 Last Reported Residential Rate Charged (based on 500 kWh) $0.33 Average Monthly PCE Eligible kWh per Residential Customer 322 Last Reported PCE Level (per kWh)$0.09 Average Monthly PCE Eligible kWh per Community Facility Customer 3,264 Effective Residential Rate (per kWh)$0.24 Average Monthly PCE Eligible Community Facility kWh per Person 63 PCE Eligible kWh vs Total kWh Sold 24.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 7,726,426 Fuel Used (Gallons)570,648 Non-Diesel kWh Generated 18,883,734 Fuel Cost $2,295,785 Purchased kWh 0 Average Price of Fuel $4.02 Total Purchased & Generated 26,610,160 Fuel Cost per kWh sold $0.10 Annual Non-Fuel Expenses $6,192,703 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.36 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 4,848,805 Consumed vs Generated (kWh Sold vs Generated-Purchased) 89.8% Community Facility kWh Sold 2,068,103 Line Loss (%)6.3% Other kWh Sold (Non-PCE)16,979,801 Fuel Efficiency (kWh per Gallon of Diesel)13.54 Total kWh Sold 23,896,709 PH Consumption as % of Generation 3.9% Powerhouse (PH) Consumption kWh 1,031,806 Total kWh Sold & PH Consumption 24,928,515 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 49 of 185 Craig PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 969 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 648 Community Facility Customers 42 Other Customers (Non-PCE)346 Fiscal Year PCE Payments $231,166 PCE Statistical Data PCE Eligible kWh - Residential Customers 2,943,282 Average Annual PCE Payment per Eligible Customer $335 PCE Eligible kWh - Community Facility Customers 813,960 Average PCE Payment per Eligible kWh $0.06 Total PCE Eligible kWh 3,757,242 Last Reported Residential Rate Charged (based on 500 kWh) $0.32 Average Monthly PCE Eligible kWh per Residential Customer 379 Last Reported PCE Level (per kWh)$0.07 Average Monthly PCE Eligible kWh per Community Facility Customer 1,615 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 70 PCE Eligible kWh vs Total kWh Sold 31.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,477,343 Fuel Used (Gallons)174,967 Non-Diesel kWh Generated 0 Fuel Cost $696,095 Purchased kWh 32,493,570 Average Price of Fuel $3.98 Total Purchased & Generated 34,970,913 Fuel Cost per kWh sold $0.06 Annual Non-Fuel Expenses $2,764,786 Non-Fuel Expense per kWh Sold $0.23 Total Expense per kWh Sold $0.29 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 3,738,412 Consumed vs Generated (kWh Sold vs Generated-Purchased) 33.7% Community Facility kWh Sold 1,250,746 Line Loss (%)65.7% Other kWh Sold (Non-PCE)6,780,074 Fuel Efficiency (kWh per Gallon of Diesel)14.16 Total kWh Sold 11,769,232 PH Consumption as % of Generation 0.6% Powerhouse (PH) Consumption kWh 217,281 Total kWh Sold & PH Consumption 11,986,513 Comments Provides power to Coffman Cove, Hollis, Hydaburg, Klawock, Thorne Bay/Kassan *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 50 of 185 Crooked Creek PCE Utility: MIDDLE KUSKOKWIM ELECTRIC COOPERATIVE INC Reporting Period: 07/01/22 to 06/30/23 Community Population 88 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 30 Community Facility Customers 4 Other Customers (Non-PCE)18 Fiscal Year PCE Payments $93,397 PCE Statistical Data PCE Eligible kWh - Residential Customers 93,461 Average Annual PCE Payment per Eligible Customer $2,747 PCE Eligible kWh - Community Facility Customers 28,787 Average PCE Payment per Eligible kWh $0.76 Total PCE Eligible kWh 122,248 Last Reported Residential Rate Charged (based on 500 kWh) $1.43 Average Monthly PCE Eligible kWh per Residential Customer 260 Last Reported PCE Level (per kWh)$0.76 Average Monthly PCE Eligible kWh per Community Facility Customer 600 Effective Residential Rate (per kWh)$0.67 Average Monthly PCE Eligible Community Facility kWh per Person 27 PCE Eligible kWh vs Total kWh Sold 45.4% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 305,358 Fuel Used (Gallons)30,201 Non-Diesel kWh Generated 0 Fuel Cost $111,671 Purchased kWh 0 Average Price of Fuel $3.70 Total Purchased & Generated 305,358 Fuel Cost per kWh sold $0.41 Annual Non-Fuel Expenses $270,479 Non-Fuel Expense per kWh Sold $1.00 Total Expense per kWh Sold $1.42 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 97,178 Consumed vs Generated (kWh Sold vs Generated-Purchased) 88.3% Community Facility kWh Sold 34,787 Line Loss (%)7.7% Other kWh Sold (Non-PCE)137,552 Fuel Efficiency (kWh per Gallon of Diesel)10.11 Total kWh Sold 269,517 PH Consumption as % of Generation 4.1% Powerhouse (PH) Consumption kWh 12,439 Total kWh Sold & PH Consumption 281,956 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 51 of 185 Deering PCE Utility: IPNATCHIAQ ELECTRIC COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 190 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 51 Community Facility Customers 5 Other Customers (Non-PCE)19 Fiscal Year PCE Payments $153,165 PCE Statistical Data PCE Eligible kWh - Residential Customers 261,645 Average Annual PCE Payment per Eligible Customer $2,735 PCE Eligible kWh - Community Facility Customers 119,341 Average PCE Payment per Eligible kWh $0.40 Total PCE Eligible kWh 380,986 Last Reported Residential Rate Charged (based on 500 kWh) $0.67 Average Monthly PCE Eligible kWh per Residential Customer 428 Last Reported PCE Level (per kWh)$0.41 Average Monthly PCE Eligible kWh per Community Facility Customer 1,989 Effective Residential Rate (per kWh)$0.27 Average Monthly PCE Eligible Community Facility kWh per Person 52 PCE Eligible kWh vs Total kWh Sold 46.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 720,289 Fuel Used (Gallons)57,268 Non-Diesel kWh Generated 145,466 Fuel Cost $227,130 Purchased kWh 0 Average Price of Fuel $3.97 Total Purchased & Generated 865,755 Fuel Cost per kWh sold $0.28 Annual Non-Fuel Expenses $314,198 Non-Fuel Expense per kWh Sold $0.39 Total Expense per kWh Sold $0.67 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 288,081 Consumed vs Generated (kWh Sold vs Generated-Purchased) 93.9% Community Facility kWh Sold 120,770 Line Loss (%)2.5% Other kWh Sold (Non-PCE)404,410 Fuel Efficiency (kWh per Gallon of Diesel)12.58 Total kWh Sold 813,261 PH Consumption as % of Generation 3.5% Powerhouse (PH) Consumption kWh 30,707 Total kWh Sold & PH Consumption 843,968 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 52 of 185 Dillingham; Aleknagik PCE Utility: NUSHAGAK ELECTRIC AND Reporting Period: 07/01/22 to 06/30/23 Community Population 2,447 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 980 Community Facility Customers 51 Other Customers (Non-PCE)486 Fiscal Year PCE Payments $1,280,272 PCE Statistical Data PCE Eligible kWh - Residential Customers 4,455,198 Average Annual PCE Payment per Eligible Customer $1,242 PCE Eligible kWh - Community Facility Customers 645,588 Average PCE Payment per Eligible kWh $0.25 Total PCE Eligible kWh 5,100,786 Last Reported Residential Rate Charged (based on 500 kWh) $0.54 Average Monthly PCE Eligible kWh per Residential Customer 379 Last Reported PCE Level (per kWh)$0.26 Average Monthly PCE Eligible kWh per Community Facility Customer 1,055 Effective Residential Rate (per kWh)$0.28 Average Monthly PCE Eligible Community Facility kWh per Person 22 PCE Eligible kWh vs Total kWh Sold 28.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 19,190,127 Fuel Used (Gallons)1,289,976 Non-Diesel kWh Generated 0 Fuel Cost $4,316,844 Purchased kWh 0 Average Price of Fuel $3.35 Total Purchased & Generated 19,190,127 Fuel Cost per kWh sold $0.24 Annual Non-Fuel Expenses $4,698,352 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.50 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 5,033,275 Consumed vs Generated (kWh Sold vs Generated-Purchased) 93.1% Community Facility kWh Sold 970,522 Line Loss (%)3.9% Other kWh Sold (Non-PCE)11,865,631 Fuel Efficiency (kWh per Gallon of Diesel)14.88 Total kWh Sold 17,869,428 PH Consumption as % of Generation 3.0% Powerhouse (PH) Consumption kWh 567,783 Total kWh Sold & PH Consumption 18,437,211 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 53 of 185 Diomede PCE Utility: DIOMEDE JOINT UTLITIES Reporting Period: 07/01/22 to 06/30/23 Community Population 85 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 31 Community Facility Customers 2 Other Customers (Non-PCE)13 Fiscal Year PCE Payments $31,701 PCE Statistical Data PCE Eligible kWh - Residential Customers 83,946 Average Annual PCE Payment per Eligible Customer $961 PCE Eligible kWh - Community Facility Customers 12,933 Average PCE Payment per Eligible kWh $0.33 Total PCE Eligible kWh 96,879 Last Reported Residential Rate Charged (based on 500 kWh) $0.65 Average Monthly PCE Eligible kWh per Residential Customer 226 Last Reported PCE Level (per kWh)$0.38 Average Monthly PCE Eligible kWh per Community Facility Customer 539 Effective Residential Rate (per kWh)$0.27 Average Monthly PCE Eligible Community Facility kWh per Person 13 PCE Eligible kWh vs Total kWh Sold 27.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 419,735 Fuel Used (Gallons)42,342 Non-Diesel kWh Generated 0 Fuel Cost $160,033 Purchased kWh 0 Average Price of Fuel $3.78 Total Purchased & Generated 419,735 Fuel Cost per kWh sold $0.45 Annual Non-Fuel Expenses $282,217 Non-Fuel Expense per kWh Sold $0.79 Total Expense per kWh Sold $1.24 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 96,072 Consumed vs Generated (kWh Sold vs Generated-Purchased) 84.7% Community Facility kWh Sold 12,979 Line Loss (%)5.0% Other kWh Sold (Non-PCE)246,479 Fuel Efficiency (kWh per Gallon of Diesel)9.91 Total kWh Sold 355,530 PH Consumption as % of Generation 10.3% Powerhouse (PH) Consumption kWh 43,294 Total kWh Sold & PH Consumption 398,824 Comments 11 Reports filed. December = November & December *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 54 of 185 Dot Lake; Dot Lake Village PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 60 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 23 Community Facility Customers 6 Other Customers (Non-PCE)14 Fiscal Year PCE Payments $45,634 PCE Statistical Data PCE Eligible kWh - Residential Customers 87,324 Average Annual PCE Payment per Eligible Customer $1,574 PCE Eligible kWh - Community Facility Customers 46,908 Average PCE Payment per Eligible kWh $0.34 Total PCE Eligible kWh 134,232 Last Reported Residential Rate Charged (based on 500 kWh) $0.48 Average Monthly PCE Eligible kWh per Residential Customer 316 Last Reported PCE Level (per kWh)$0.28 Average Monthly PCE Eligible kWh per Community Facility Customer 652 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 65 PCE Eligible kWh vs Total kWh Sold 33.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.00 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 102,175 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 58,814 Line Loss (%)See Comments Other kWh Sold (Non-PCE)244,647 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 405,636 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 405,636 Comments See Tok for Power Generation. No Non-Fuel Expenses Reported *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 55 of 185 Eagle; Eagle Village PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 125 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 141 Community Facility Customers 11 Other Customers (Non-PCE)34 Fiscal Year PCE Payments $202,220 PCE Statistical Data PCE Eligible kWh - Residential Customers 257,757 Average Annual PCE Payment per Eligible Customer $1,330 PCE Eligible kWh - Community Facility Customers 75,348 Average PCE Payment per Eligible kWh $0.61 Total PCE Eligible kWh 333,105 Last Reported Residential Rate Charged (based on 500 kWh) $0.89 Average Monthly PCE Eligible kWh per Residential Customer 152 Last Reported PCE Level (per kWh)$0.58 Average Monthly PCE Eligible kWh per Community Facility Customer 571 Effective Residential Rate (per kWh)$0.31 Average Monthly PCE Eligible Community Facility kWh per Person 50 PCE Eligible kWh vs Total kWh Sold 47.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 816,760 Fuel Used (Gallons)72,523 Non-Diesel kWh Generated 19,287 Fuel Cost $332,022 Purchased kWh 0 Average Price of Fuel $4.58 Total Purchased & Generated 836,047 Fuel Cost per kWh sold $0.48 Annual Non-Fuel Expenses $385,965 Non-Fuel Expense per kWh Sold $0.55 Total Expense per kWh Sold $1.03 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 271,702 Consumed vs Generated (kWh Sold vs Generated-Purchased) 83.3% Community Facility kWh Sold 77,162 Line Loss (%)9.3% Other kWh Sold (Non-PCE)347,469 Fuel Efficiency (kWh per Gallon of Diesel)11.26 Total kWh Sold 696,333 PH Consumption as % of Generation 7.4% Powerhouse (PH) Consumption kWh 62,117 Total kWh Sold & PH Consumption 758,450 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 56 of 185 Eek PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 408 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 109 Community Facility Customers 5 Other Customers (Non-PCE)38 Fiscal Year PCE Payments $241,541 PCE Statistical Data PCE Eligible kWh - Residential Customers 562,362 Average Annual PCE Payment per Eligible Customer $2,119 PCE Eligible kWh - Community Facility Customers 41,794 Average PCE Payment per Eligible kWh $0.40 Total PCE Eligible kWh 604,156 Last Reported Residential Rate Charged (based on 500 kWh) $0.72 Average Monthly PCE Eligible kWh per Residential Customer 430 Last Reported PCE Level (per kWh)$0.46 Average Monthly PCE Eligible kWh per Community Facility Customer 697 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 9 PCE Eligible kWh vs Total kWh Sold 45.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,373,096 Fuel Used (Gallons)78,002 Non-Diesel kWh Generated 0 Fuel Cost $348,709 Purchased kWh 0 Average Price of Fuel $4.47 Total Purchased & Generated 1,373,096 Fuel Cost per kWh sold $0.27 Annual Non-Fuel Expenses $335,885 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.52 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 589,382 Consumed vs Generated (kWh Sold vs Generated-Purchased) 95.8% Community Facility kWh Sold 381,589 Line Loss (%)2.7% Other kWh Sold (Non-PCE)344,771 Fuel Efficiency (kWh per Gallon of Diesel)17.60 Total kWh Sold 1,315,742 PH Consumption as % of Generation 1.5% Powerhouse (PH) Consumption kWh 20,724 Total kWh Sold & PH Consumption 1,336,466 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 57 of 185 Egegik PCE Utility: CITY OF EGEGIK Reporting Period: 07/01/22 to 06/30/23 Community Population 39 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 85 Community Facility Customers 18 Other Customers (Non-PCE)27 Fiscal Year PCE Payments $86,736 PCE Statistical Data PCE Eligible kWh - Residential Customers 158,514 Average Annual PCE Payment per Eligible Customer $842 PCE Eligible kWh - Community Facility Customers 32,760 Average PCE Payment per Eligible kWh $0.45 Total PCE Eligible kWh 191,274 Last Reported Residential Rate Charged (based on 500 kWh) $0.65 Average Monthly PCE Eligible kWh per Residential Customer 155 Last Reported PCE Level (per kWh)$0.45 Average Monthly PCE Eligible kWh per Community Facility Customer 152 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 70 PCE Eligible kWh vs Total kWh Sold 28.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 736,307 Fuel Used (Gallons)58,076 Non-Diesel kWh Generated 0 Fuel Cost $177,416 Purchased kWh 0 Average Price of Fuel $3.05 Total Purchased & Generated 736,307 Fuel Cost per kWh sold $0.26 Annual Non-Fuel Expenses $317,425 Non-Fuel Expense per kWh Sold $0.47 Total Expense per kWh Sold $0.74 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 177,386 Consumed vs Generated (kWh Sold vs Generated-Purchased) 91.0% Community Facility kWh Sold 153,019 Line Loss (%)4.8% Other kWh Sold (Non-PCE)339,295 Fuel Efficiency (kWh per Gallon of Diesel)12.68 Total kWh Sold 669,700 PH Consumption as % of Generation 4.2% Powerhouse (PH) Consumption kWh 31,090 Total kWh Sold & PH Consumption 700,790 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 58 of 185 Ekwok PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 103 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 47 Community Facility Customers 8 Other Customers (Non-PCE)22 Fiscal Year PCE Payments $89,455 PCE Statistical Data PCE Eligible kWh - Residential Customers 208,740 Average Annual PCE Payment per Eligible Customer $1,626 PCE Eligible kWh - Community Facility Customers 20,215 Average PCE Payment per Eligible kWh $0.39 Total PCE Eligible kWh 228,955 Last Reported Residential Rate Charged (based on 500 kWh) $0.67 Average Monthly PCE Eligible kWh per Residential Customer 370 Last Reported PCE Level (per kWh)$0.42 Average Monthly PCE Eligible kWh per Community Facility Customer 211 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 16 PCE Eligible kWh vs Total kWh Sold 50.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $116,389 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.26 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 229,774 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 130,109 Line Loss (%)See Comments Other kWh Sold (Non-PCE)96,041 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 455,924 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 455,924 Comments Receives power from New Stuyahok Bay via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 59 of 185 Elfin Cove PCE Utility: ELFIN COVE UTILITY COMMISSION Reporting Period: 07/01/22 to 06/30/23 Community Population 32 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 40 Community Facility Customers 6 Other Customers (Non-PCE)31 Fiscal Year PCE Payments $27,419 PCE Statistical Data PCE Eligible kWh - Residential Customers 45,314 Average Annual PCE Payment per Eligible Customer $596 PCE Eligible kWh - Community Facility Customers 10,380 Average PCE Payment per Eligible kWh $0.49 Total PCE Eligible kWh 55,694 Last Reported Residential Rate Charged (based on 500 kWh) $0.79 Average Monthly PCE Eligible kWh per Residential Customer 94 Last Reported PCE Level (per kWh)$0.55 Average Monthly PCE Eligible kWh per Community Facility Customer 144 Effective Residential Rate (per kWh)$0.24 Average Monthly PCE Eligible Community Facility kWh per Person 27 PCE Eligible kWh vs Total kWh Sold 16.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 388,540 Fuel Used (Gallons)30,887 Non-Diesel kWh Generated 0 Fuel Cost $159,950 Purchased kWh 0 Average Price of Fuel $5.18 Total Purchased & Generated 388,540 Fuel Cost per kWh sold $0.48 Annual Non-Fuel Expenses $83,057 Non-Fuel Expense per kWh Sold $0.25 Total Expense per kWh Sold $0.73 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 74,783 Consumed vs Generated (kWh Sold vs Generated-Purchased) 85.1% Community Facility kWh Sold 10,380 Line Loss (%)9.4% Other kWh Sold (Non-PCE)245,656 Fuel Efficiency (kWh per Gallon of Diesel)12.58 Total kWh Sold 330,819 PH Consumption as % of Generation 5.4% Powerhouse (PH) Consumption kWh 21,124 Total kWh Sold & PH Consumption 351,943 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 60 of 185 Elim PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 345 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 89 Community Facility Customers 10 Other Customers (Non-PCE)42 Fiscal Year PCE Payments $222,113 PCE Statistical Data PCE Eligible kWh - Residential Customers 499,116 Average Annual PCE Payment per Eligible Customer $2,244 PCE Eligible kWh - Community Facility Customers 139,449 Average PCE Payment per Eligible kWh $0.35 Total PCE Eligible kWh 638,565 Last Reported Residential Rate Charged (based on 500 kWh) $0.72 Average Monthly PCE Eligible kWh per Residential Customer 467 Last Reported PCE Level (per kWh)$0.46 Average Monthly PCE Eligible kWh per Community Facility Customer 1,162 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 34 PCE Eligible kWh vs Total kWh Sold 50.4% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,337,797 Fuel Used (Gallons)77,504 Non-Diesel kWh Generated 0 Fuel Cost $302,578 Purchased kWh 0 Average Price of Fuel $3.90 Total Purchased & Generated 1,337,797 Fuel Cost per kWh sold $0.24 Annual Non-Fuel Expenses $323,252 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.49 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 536,323 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.7% Community Facility kWh Sold 283,535 Line Loss (%)4.0% Other kWh Sold (Non-PCE)446,396 Fuel Efficiency (kWh per Gallon of Diesel)17.26 Total kWh Sold 1,266,254 PH Consumption as % of Generation 1.3% Powerhouse (PH) Consumption kWh 17,535 Total kWh Sold & PH Consumption 1,283,789 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 61 of 185 Emmonak PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 861 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 208 Community Facility Customers 20 Other Customers (Non-PCE)67 Fiscal Year PCE Payments $478,587 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,072,371 Average Annual PCE Payment per Eligible Customer $2,099 PCE Eligible kWh - Community Facility Customers 594,051 Average PCE Payment per Eligible kWh $0.29 Total PCE Eligible kWh 1,666,422 Last Reported Residential Rate Charged (based on 500 kWh) $0.60 Average Monthly PCE Eligible kWh per Residential Customer 430 Last Reported PCE Level (per kWh)$0.34 Average Monthly PCE Eligible kWh per Community Facility Customer 2,475 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 57 PCE Eligible kWh vs Total kWh Sold 48.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 5,488,429 Fuel Used (Gallons)348,252 Non-Diesel kWh Generated 390,554 Fuel Cost $1,212,241 Purchased kWh 0 Average Price of Fuel $3.48 Total Purchased & Generated 5,878,983 Fuel Cost per kWh sold $0.35 Annual Non-Fuel Expenses $883,598 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.61 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,155,899 Consumed vs Generated (kWh Sold vs Generated-Purchased) 58.9% Community Facility kWh Sold 921,758 Line Loss (%)39.4% Other kWh Sold (Non-PCE)1,383,607 Fuel Efficiency (kWh per Gallon of Diesel)15.76 Total kWh Sold 3,461,264 PH Consumption as % of Generation 1.8% Powerhouse (PH) Consumption kWh 103,322 Total kWh Sold & PH Consumption 3,564,586 Comments Provides power to Alakanuk via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 62 of 185 False Pass PCE Utility: CITY OF FALSE PASS Reporting Period: 07/01/22 to 06/30/23 Community Population 397 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 30 Community Facility Customers 11 Other Customers (Non-PCE)19 Fiscal Year PCE Payments $61,600 PCE Statistical Data PCE Eligible kWh - Residential Customers 63,976 Average Annual PCE Payment per Eligible Customer $1,502 PCE Eligible kWh - Community Facility Customers 84,139 Average PCE Payment per Eligible kWh $0.42 Total PCE Eligible kWh 148,115 Last Reported Residential Rate Charged (based on 500 kWh) $0.72 Average Monthly PCE Eligible kWh per Residential Customer 178 Last Reported PCE Level (per kWh)$0.48 Average Monthly PCE Eligible kWh per Community Facility Customer 637 Effective Residential Rate (per kWh)$0.24 Average Monthly PCE Eligible Community Facility kWh per Person 18 PCE Eligible kWh vs Total kWh Sold 26.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 635,737 Fuel Used (Gallons)28,192 Non-Diesel kWh Generated 0 Fuel Cost $81,323 Purchased kWh 0 Average Price of Fuel $2.88 Total Purchased & Generated 635,737 Fuel Cost per kWh sold $0.15 Annual Non-Fuel Expenses $98,947 Non-Fuel Expense per kWh Sold $0.18 Total Expense per kWh Sold $0.33 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 116,233 Consumed vs Generated (kWh Sold vs Generated-Purchased) 86.9% Community Facility kWh Sold 86,461 Line Loss (%)9.8% Other kWh Sold (Non-PCE)349,839 Fuel Efficiency (kWh per Gallon of Diesel)22.55 Total kWh Sold 552,533 PH Consumption as % of Generation 3.3% Powerhouse (PH) Consumption kWh 20,996 Total kWh Sold & PH Consumption 573,529 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 63 of 185 Fort Yukon PCE Utility: GWITCHYAA ZHEE UTILITY COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 508 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 272 Community Facility Customers 18 Other Customers (Non-PCE)88 Fiscal Year PCE Payments $668,513 PCE Statistical Data PCE Eligible kWh - Residential Customers 939,694 Average Annual PCE Payment per Eligible Customer $2,305 PCE Eligible kWh - Community Facility Customers 395,406 Average PCE Payment per Eligible kWh $0.50 Total PCE Eligible kWh 1,335,100 Last Reported Residential Rate Charged (based on 500 kWh) $0.86 Average Monthly PCE Eligible kWh per Residential Customer 288 Last Reported PCE Level (per kWh)$0.57 Average Monthly PCE Eligible kWh per Community Facility Customer 1,831 Effective Residential Rate (per kWh)$0.29 Average Monthly PCE Eligible Community Facility kWh per Person 65 PCE Eligible kWh vs Total kWh Sold 50.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 3,150,197 Fuel Used (Gallons)212,378 Non-Diesel kWh Generated 0 Fuel Cost $1,607,824 Purchased kWh 0 Average Price of Fuel $7.57 Total Purchased & Generated 3,150,197 Fuel Cost per kWh sold $0.61 Annual Non-Fuel Expenses $465,178 Non-Fuel Expense per kWh Sold $0.18 Total Expense per kWh Sold $0.78 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 988,238 Consumed vs Generated (kWh Sold vs Generated-Purchased) 84.0% Community Facility kWh Sold 484,153 Line Loss (%)13.6% Other kWh Sold (Non-PCE)1,173,112 Fuel Efficiency (kWh per Gallon of Diesel)14.83 Total kWh Sold 2,645,503 PH Consumption as % of Generation 2.4% Powerhouse (PH) Consumption kWh 76,522 Total kWh Sold & PH Consumption 2,722,025 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 64 of 185 Galena PCE Utility: CITY OF GALENA Reporting Period: 07/01/22 to 06/30/23 Community Population 476 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 207 Community Facility Customers 14 Other Customers (Non-PCE)169 Fiscal Year PCE Payments $375,888 PCE Statistical Data PCE Eligible kWh - Residential Customers 686,334 Average Annual PCE Payment per Eligible Customer $1,701 PCE Eligible kWh - Community Facility Customers 398,691 Average PCE Payment per Eligible kWh $0.35 Total PCE Eligible kWh 1,085,025 Last Reported Residential Rate Charged (based on 500 kWh) $0.72 Average Monthly PCE Eligible kWh per Residential Customer 276 Last Reported PCE Level (per kWh)$0.40 Average Monthly PCE Eligible kWh per Community Facility Customer 2,373 Effective Residential Rate (per kWh)$0.32 Average Monthly PCE Eligible Community Facility kWh per Person 70 PCE Eligible kWh vs Total kWh Sold 24.4% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 5,116,012 Fuel Used (Gallons)375,653 Non-Diesel kWh Generated 0 Fuel Cost $1,474,707 Purchased kWh 0 Average Price of Fuel $3.93 Total Purchased & Generated 5,116,012 Fuel Cost per kWh sold $0.33 Annual Non-Fuel Expenses $7,048,167 Non-Fuel Expense per kWh Sold $1.59 Total Expense per kWh Sold $1.92 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 799,275 Consumed vs Generated (kWh Sold vs Generated-Purchased) 86.9% Community Facility kWh Sold 474,918 Line Loss (%)8.9% Other kWh Sold (Non-PCE)3,170,270 Fuel Efficiency (kWh per Gallon of Diesel)13.62 Total kWh Sold 4,444,463 PH Consumption as % of Generation 4.2% Powerhouse (PH) Consumption kWh 214,863 Total kWh Sold & PH Consumption 4,659,326 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 65 of 185 Gambell PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 620 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 167 Community Facility Customers 14 Other Customers (Non-PCE)36 Fiscal Year PCE Payments $376,974 PCE Statistical Data PCE Eligible kWh - Residential Customers 892,297 Average Annual PCE Payment per Eligible Customer $2,083 PCE Eligible kWh - Community Facility Customers 274,064 Average PCE Payment per Eligible kWh $0.32 Total PCE Eligible kWh 1,166,361 Last Reported Residential Rate Charged (based on 500 kWh) $0.68 Average Monthly PCE Eligible kWh per Residential Customer 445 Last Reported PCE Level (per kWh)$0.41 Average Monthly PCE Eligible kWh per Community Facility Customer 1,631 Effective Residential Rate (per kWh)$0.27 Average Monthly PCE Eligible Community Facility kWh per Person 37 PCE Eligible kWh vs Total kWh Sold 50.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,277,782 Fuel Used (Gallons)117,414 Non-Diesel kWh Generated 263,534 Fuel Cost $469,489 Purchased kWh 0 Average Price of Fuel $4.00 Total Purchased & Generated 2,541,316 Fuel Cost per kWh sold $0.20 Annual Non-Fuel Expenses $591,572 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.46 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 994,305 Consumed vs Generated (kWh Sold vs Generated-Purchased) 91.2% Community Facility kWh Sold 484,706 Line Loss (%)6.2% Other kWh Sold (Non-PCE)838,317 Fuel Efficiency (kWh per Gallon of Diesel)19.40 Total kWh Sold 2,317,328 PH Consumption as % of Generation 2.6% Powerhouse (PH) Consumption kWh 66,279 Total kWh Sold & PH Consumption 2,383,607 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 66 of 185 Golovin PCE Utility: GOLOVIN POWER UTILITIES Reporting Period: 07/01/22 to 06/30/23 Community Population 178 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 49 Community Facility Customers 11 Other Customers (Non-PCE)48 Fiscal Year PCE Payments $77,898 PCE Statistical Data PCE Eligible kWh - Residential Customers 236,715 Average Annual PCE Payment per Eligible Customer $1,298 PCE Eligible kWh - Community Facility Customers 138,026 Average PCE Payment per Eligible kWh $0.21 Total PCE Eligible kWh 374,741 Last Reported Residential Rate Charged (based on 500 kWh) $0.56 Average Monthly PCE Eligible kWh per Residential Customer 403 Last Reported PCE Level (per kWh)$0.23 Average Monthly PCE Eligible kWh per Community Facility Customer 1,046 Effective Residential Rate (per kWh)$0.33 Average Monthly PCE Eligible Community Facility kWh per Person 65 PCE Eligible kWh vs Total kWh Sold 43.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 921,576 Fuel Used (Gallons)78,998 Non-Diesel kWh Generated 0 Fuel Cost $283,250 Purchased kWh 0 Average Price of Fuel $3.59 Total Purchased & Generated 921,576 Fuel Cost per kWh sold $0.33 Annual Non-Fuel Expenses $178,089 Non-Fuel Expense per kWh Sold $0.21 Total Expense per kWh Sold $0.54 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 282,016 Consumed vs Generated (kWh Sold vs Generated-Purchased) 93.4% Community Facility kWh Sold 145,721 Line Loss (%)3.3% Other kWh Sold (Non-PCE)433,101 Fuel Efficiency (kWh per Gallon of Diesel)11.67 Total kWh Sold 860,838 PH Consumption as % of Generation 3.3% Powerhouse (PH) Consumption kWh 30,429 Total kWh Sold & PH Consumption 891,267 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 67 of 185 Goodnews Bay PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 249 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 79 Community Facility Customers 11 Other Customers (Non-PCE)12 Fiscal Year PCE Payments $160,370 PCE Statistical Data PCE Eligible kWh - Residential Customers 411,859 Average Annual PCE Payment per Eligible Customer $1,782 PCE Eligible kWh - Community Facility Customers 98,312 Average PCE Payment per Eligible kWh $0.31 Total PCE Eligible kWh 510,171 Last Reported Residential Rate Charged (based on 500 kWh) $0.59 Average Monthly PCE Eligible kWh per Residential Customer 434 Last Reported PCE Level (per kWh)$0.34 Average Monthly PCE Eligible kWh per Community Facility Customer 745 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 33 PCE Eligible kWh vs Total kWh Sold 65.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 818,538 Fuel Used (Gallons)58,636 Non-Diesel kWh Generated 0 Fuel Cost $209,408 Purchased kWh 0 Average Price of Fuel $3.57 Total Purchased & Generated 818,538 Fuel Cost per kWh sold $0.27 Annual Non-Fuel Expenses $198,702 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.52 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 453,702 Consumed vs Generated (kWh Sold vs Generated-Purchased) 95.1% Community Facility kWh Sold 151,684 Line Loss (%)3.0% Other kWh Sold (Non-PCE)172,978 Fuel Efficiency (kWh per Gallon of Diesel)13.96 Total kWh Sold 778,364 PH Consumption as % of Generation 1.9% Powerhouse (PH) Consumption kWh 15,471 Total kWh Sold & PH Consumption 793,835 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 68 of 185 Grayling PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 210 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 59 Community Facility Customers 10 Other Customers (Non-PCE)29 Fiscal Year PCE Payments $163,858 PCE Statistical Data PCE Eligible kWh - Residential Customers 252,703 Average Annual PCE Payment per Eligible Customer $2,375 PCE Eligible kWh - Community Facility Customers 104,044 Average PCE Payment per Eligible kWh $0.46 Total PCE Eligible kWh 356,747 Last Reported Residential Rate Charged (based on 500 kWh) $0.74 Average Monthly PCE Eligible kWh per Residential Customer 357 Last Reported PCE Level (per kWh)$0.48 Average Monthly PCE Eligible kWh per Community Facility Customer 867 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 41 PCE Eligible kWh vs Total kWh Sold 64.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 607,410 Fuel Used (Gallons)43,472 Non-Diesel kWh Generated 0 Fuel Cost $204,174 Purchased kWh 0 Average Price of Fuel $4.70 Total Purchased & Generated 607,410 Fuel Cost per kWh sold $0.37 Annual Non-Fuel Expenses $141,868 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.62 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 258,289 Consumed vs Generated (kWh Sold vs Generated-Purchased) 91.5% Community Facility kWh Sold 185,483 Line Loss (%)4.4% Other kWh Sold (Non-PCE)111,959 Fuel Efficiency (kWh per Gallon of Diesel)13.97 Total kWh Sold 555,731 PH Consumption as % of Generation 4.1% Powerhouse (PH) Consumption kWh 25,100 Total kWh Sold & PH Consumption 580,831 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 69 of 185 Gustavus PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 658 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 496 Community Facility Customers 5 Other Customers (Non-PCE)120 Fiscal Year PCE Payments $178,951 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,208,474 Average Annual PCE Payment per Eligible Customer $357 PCE Eligible kWh - Community Facility Customers 40,432 Average PCE Payment per Eligible kWh $0.14 Total PCE Eligible kWh 1,248,906 Last Reported Residential Rate Charged (based on 500 kWh) $0.46 Average Monthly PCE Eligible kWh per Residential Customer 203 Last Reported PCE Level (per kWh)$0.16 Average Monthly PCE Eligible kWh per Community Facility Customer 674 Effective Residential Rate (per kWh)$0.29 Average Monthly PCE Eligible Community Facility kWh per Person 5 PCE Eligible kWh vs Total kWh Sold 49.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 299,441 Fuel Used (Gallons)21,827 Non-Diesel kWh Generated 2,854,474 Fuel Cost $114,144 Purchased kWh 0 Average Price of Fuel $5.23 Total Purchased & Generated 3,153,915 Fuel Cost per kWh sold $0.05 Annual Non-Fuel Expenses $848,655 Non-Fuel Expense per kWh Sold $0.34 Total Expense per kWh Sold $0.38 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,423,742 Consumed vs Generated (kWh Sold vs Generated-Purchased) 80.3% Community Facility kWh Sold 40,434 Line Loss (%)15.2% Other kWh Sold (Non-PCE)1,069,122 Fuel Efficiency (kWh per Gallon of Diesel)13.72 Total kWh Sold 2,533,298 PH Consumption as % of Generation 4.5% Powerhouse (PH) Consumption kWh 141,558 Total kWh Sold & PH Consumption 2,674,856 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 70 of 185 Haines; Covenant Life PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 2,687 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 1,186 Community Facility Customers 35 Other Customers (Non-PCE)373 Fiscal Year PCE Payments $282,539 PCE Statistical Data PCE Eligible kWh - Residential Customers 4,522,588 Average Annual PCE Payment per Eligible Customer $231 PCE Eligible kWh - Community Facility Customers 1,120,189 Average PCE Payment per Eligible kWh $0.05 Total PCE Eligible kWh 5,642,777 Last Reported Residential Rate Charged (based on 500 kWh) $0.30 Average Monthly PCE Eligible kWh per Residential Customer 318 Last Reported PCE Level (per kWh)$0.06 Average Monthly PCE Eligible kWh per Community Facility Customer 2,667 Effective Residential Rate (per kWh)$0.24 Average Monthly PCE Eligible Community Facility kWh per Person 35 PCE Eligible kWh vs Total kWh Sold 41.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 409,998 Fuel Used (Gallons)29,699 Non-Diesel kWh Generated 0 Fuel Cost $130,254 Purchased kWh 14,987,638 Average Price of Fuel $4.39 Total Purchased & Generated 15,397,636 Fuel Cost per kWh sold $0.01 Annual Non-Fuel Expenses $150,715 Non-Fuel Expense per kWh Sold $0.01 Total Expense per kWh Sold $0.02 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 5,654,899 Consumed vs Generated (kWh Sold vs Generated-Purchased) 89.2% Community Facility kWh Sold 1,120,189 Line Loss (%)8.3% Other kWh Sold (Non-PCE)6,963,914 Fuel Efficiency (kWh per Gallon of Diesel)13.81 Total kWh Sold 13,739,002 PH Consumption as % of Generation 2.4% Powerhouse (PH) Consumption kWh 374,684 Total kWh Sold & PH Consumption 14,113,686 Comments Sells power to Chilkat Valley. Diesel Gen & Fuel Used = 11 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 71 of 185 Healy Lake PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 24 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 9 Community Facility Customers 3 Other Customers (Non-PCE)2 Fiscal Year PCE Payments $26,593 PCE Statistical Data PCE Eligible kWh - Residential Customers 18,487 Average Annual PCE Payment per Eligible Customer $2,216 PCE Eligible kWh - Community Facility Customers 20,160 Average PCE Payment per Eligible kWh $0.69 Total PCE Eligible kWh 38,647 Last Reported Residential Rate Charged (based on 500 kWh) $1.00 Average Monthly PCE Eligible kWh per Residential Customer 171 Last Reported PCE Level (per kWh)$0.69 Average Monthly PCE Eligible kWh per Community Facility Customer 560 Effective Residential Rate (per kWh)$0.31 Average Monthly PCE Eligible Community Facility kWh per Person 70 PCE Eligible kWh vs Total kWh Sold 42.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 100,027 Fuel Used (Gallons)11,046 Non-Diesel kWh Generated 0 Fuel Cost $45,013 Purchased kWh 0 Average Price of Fuel $4.08 Total Purchased & Generated 100,027 Fuel Cost per kWh sold $0.49 Annual Non-Fuel Expenses $66,433 Non-Fuel Expense per kWh Sold $0.73 Total Expense per kWh Sold $1.22 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 19,384 Consumed vs Generated (kWh Sold vs Generated-Purchased) 91.5% Community Facility kWh Sold 55,526 Line Loss (%)4.1% Other kWh Sold (Non-PCE)16,585 Fuel Efficiency (kWh per Gallon of Diesel)9.06 Total kWh Sold 91,495 PH Consumption as % of Generation 4.4% Powerhouse (PH) Consumption kWh 4,447 Total kWh Sold & PH Consumption 95,942 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 72 of 185 Hollis PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 138 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 137 Community Facility Customers 0 Other Customers (Non-PCE)35 Fiscal Year PCE Payments $34,411 PCE Statistical Data PCE Eligible kWh - Residential Customers 559,334 Average Annual PCE Payment per Eligible Customer $251 PCE Eligible kWh - Community Facility Customers 558 Average PCE Payment per Eligible kWh $0.06 Total PCE Eligible kWh 559,892 Last Reported Residential Rate Charged (based on 500 kWh) $0.32 Average Monthly PCE Eligible kWh per Residential Customer 340 Last Reported PCE Level (per kWh)$0.07 Average Monthly PCE Eligible kWh per Community Facility Customer 0 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 0 PCE Eligible kWh vs Total kWh Sold 12.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.00 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 792,617 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 558 Line Loss (%)See Comments Other kWh Sold (Non-PCE)3,652,012 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 4,445,187 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 16,780 Total kWh Sold & PH Consumption 4,461,967 Comments See Craig for power generation. No Non-Fuel Expenses Reported *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 73 of 185 Holy Cross PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 158 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 68 Community Facility Customers 9 Other Customers (Non-PCE)21 Fiscal Year PCE Payments $136,363 PCE Statistical Data PCE Eligible kWh - Residential Customers 281,547 Average Annual PCE Payment per Eligible Customer $1,771 PCE Eligible kWh - Community Facility Customers 66,721 Average PCE Payment per Eligible kWh $0.39 Total PCE Eligible kWh 348,268 Last Reported Residential Rate Charged (based on 500 kWh) $0.67 Average Monthly PCE Eligible kWh per Residential Customer 345 Last Reported PCE Level (per kWh)$0.41 Average Monthly PCE Eligible kWh per Community Facility Customer 618 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 35 PCE Eligible kWh vs Total kWh Sold 57.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 627,981 Fuel Used (Gallons)43,043 Non-Diesel kWh Generated 0 Fuel Cost $175,515 Purchased kWh 0 Average Price of Fuel $4.08 Total Purchased & Generated 627,981 Fuel Cost per kWh sold $0.29 Annual Non-Fuel Expenses $153,982 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.55 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 310,430 Consumed vs Generated (kWh Sold vs Generated-Purchased) 96.1% Community Facility kWh Sold 200,513 Line Loss (%)See Comments Other kWh Sold (Non-PCE)92,241 Fuel Efficiency (kWh per Gallon of Diesel)14.59 Total kWh Sold 603,184 PH Consumption as % of Generation 4.7% Powerhouse (PH) Consumption kWh 29,754 Total kWh Sold & PH Consumption 632,938 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 74 of 185 Hoonah PCE Utility: INSIDE PASSAGE ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 904 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 428 Community Facility Customers 27 Other Customers (Non-PCE)83 Fiscal Year PCE Payments $917,098 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,602,846 Average Annual PCE Payment per Eligible Customer $2,016 PCE Eligible kWh - Community Facility Customers 653,663 Average PCE Payment per Eligible kWh $0.41 Total PCE Eligible kWh 2,256,509 Last Reported Residential Rate Charged (based on 500 kWh) $0.63 Average Monthly PCE Eligible kWh per Residential Customer 312 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 2,017 Effective Residential Rate (per kWh)$0.31 Average Monthly PCE Eligible Community Facility kWh per Person 60 PCE Eligible kWh vs Total kWh Sold 43.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 4,265,340 Fuel Used (Gallons)291,353 Non-Diesel kWh Generated 1,399,870 Fuel Cost $1,288,819 Purchased kWh 0 Average Price of Fuel $4.42 Total Purchased & Generated 5,665,210 Fuel Cost per kWh sold $0.25 Annual Non-Fuel Expenses $1,675,554 Non-Fuel Expense per kWh Sold $0.32 Total Expense per kWh Sold $0.57 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 2,062,805 Consumed vs Generated (kWh Sold vs Generated-Purchased) 92.5% Community Facility kWh Sold 673,066 Line Loss (%)5.9% Other kWh Sold (Non-PCE)2,505,494 Fuel Efficiency (kWh per Gallon of Diesel)14.64 Total kWh Sold 5,241,365 PH Consumption as % of Generation 1.6% Powerhouse (PH) Consumption kWh 90,547 Total kWh Sold & PH Consumption 5,331,912 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 75 of 185 Hooper Bay PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 1,330 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 250 Community Facility Customers 7 Other Customers (Non-PCE)65 Fiscal Year PCE Payments $493,964 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,335,099 Average Annual PCE Payment per Eligible Customer $1,922 PCE Eligible kWh - Community Facility Customers 419,600 Average PCE Payment per Eligible kWh $0.28 Total PCE Eligible kWh 1,754,699 Last Reported Residential Rate Charged (based on 500 kWh) $0.54 Average Monthly PCE Eligible kWh per Residential Customer 445 Last Reported PCE Level (per kWh)$0.27 Average Monthly PCE Eligible kWh per Community Facility Customer 4,995 Effective Residential Rate (per kWh)$0.27 Average Monthly PCE Eligible Community Facility kWh per Person 26 PCE Eligible kWh vs Total kWh Sold 49.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 3,378,245 Fuel Used (Gallons)192,820 Non-Diesel kWh Generated 363,049 Fuel Cost $752,623 Purchased kWh 0 Average Price of Fuel $3.90 Total Purchased & Generated 3,741,294 Fuel Cost per kWh sold $0.21 Annual Non-Fuel Expenses $902,427 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.47 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,485,751 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.5% Community Facility kWh Sold 873,017 Line Loss (%)2.9% Other kWh Sold (Non-PCE)1,176,253 Fuel Efficiency (kWh per Gallon of Diesel)17.52 Total kWh Sold 3,535,021 PH Consumption as % of Generation 2.6% Powerhouse (PH) Consumption kWh 96,548 Total kWh Sold & PH Consumption 3,631,569 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 76 of 185 Hughes PCE Utility: HUGHES POWER & LIGHT Reporting Period: 07/01/22 to 06/30/23 Community Population 84 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 56 Community Facility Customers 3 Other Customers (Non-PCE)19 Fiscal Year PCE Payments $164,438 PCE Statistical Data PCE Eligible kWh - Residential Customers 193,815 Average Annual PCE Payment per Eligible Customer $2,787 PCE Eligible kWh - Community Facility Customers 67,416 Average PCE Payment per Eligible kWh $0.63 Total PCE Eligible kWh 261,231 Last Reported Residential Rate Charged (based on 500 kWh) $0.91 Average Monthly PCE Eligible kWh per Residential Customer 288 Last Reported PCE Level (per kWh)$0.71 Average Monthly PCE Eligible kWh per Community Facility Customer 1,873 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 67 PCE Eligible kWh vs Total kWh Sold 55.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 561,456 Fuel Used (Gallons)61,858 Non-Diesel kWh Generated 0 Fuel Cost $353,260 Purchased kWh 0 Average Price of Fuel $5.71 Total Purchased & Generated 561,456 Fuel Cost per kWh sold $0.75 Annual Non-Fuel Expenses $82,696 Non-Fuel Expense per kWh Sold $0.17 Total Expense per kWh Sold $0.92 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 229,922 Consumed vs Generated (kWh Sold vs Generated-Purchased) 84.3% Community Facility kWh Sold 77,966 Line Loss (%)9.3% Other kWh Sold (Non-PCE)165,559 Fuel Efficiency (kWh per Gallon of Diesel)9.08 Total kWh Sold 473,447 PH Consumption as % of Generation 6.4% Powerhouse (PH) Consumption kWh 35,654 Total kWh Sold & PH Consumption 509,101 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 77 of 185 Huslia PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 301 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 105 Community Facility Customers 15 Other Customers (Non-PCE)35 Fiscal Year PCE Payments $299,330 PCE Statistical Data PCE Eligible kWh - Residential Customers 532,055 Average Annual PCE Payment per Eligible Customer $2,494 PCE Eligible kWh - Community Facility Customers 181,845 Average PCE Payment per Eligible kWh $0.42 Total PCE Eligible kWh 713,900 Last Reported Residential Rate Charged (based on 500 kWh) $0.67 Average Monthly PCE Eligible kWh per Residential Customer 422 Last Reported PCE Level (per kWh)$0.41 Average Monthly PCE Eligible kWh per Community Facility Customer 1,010 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 50 PCE Eligible kWh vs Total kWh Sold 65.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,161,081 Fuel Used (Gallons)68,582 Non-Diesel kWh Generated 0 Fuel Cost $316,567 Purchased kWh 0 Average Price of Fuel $4.62 Total Purchased & Generated 1,161,081 Fuel Cost per kWh sold $0.29 Annual Non-Fuel Expenses $279,892 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.54 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 578,812 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.4% Community Facility kWh Sold 267,634 Line Loss (%)2.9% Other kWh Sold (Non-PCE)249,956 Fuel Efficiency (kWh per Gallon of Diesel)16.93 Total kWh Sold 1,096,402 PH Consumption as % of Generation 2.7% Powerhouse (PH) Consumption kWh 31,540 Total kWh Sold & PH Consumption 1,127,942 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 78 of 185 Hydaburg PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 376 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 112 Community Facility Customers 10 Other Customers (Non-PCE)62 Fiscal Year PCE Payments $42,179 PCE Statistical Data PCE Eligible kWh - Residential Customers 543,943 Average Annual PCE Payment per Eligible Customer $346 PCE Eligible kWh - Community Facility Customers 145,286 Average PCE Payment per Eligible kWh $0.06 Total PCE Eligible kWh 689,229 Last Reported Residential Rate Charged (based on 500 kWh) $0.32 Average Monthly PCE Eligible kWh per Residential Customer 405 Last Reported PCE Level (per kWh)$0.07 Average Monthly PCE Eligible kWh per Community Facility Customer 1,211 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 32 PCE Eligible kWh vs Total kWh Sold 46.4% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.00 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 648,192 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 163,603 Line Loss (%)See Comments Other kWh Sold (Non-PCE)673,686 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 1,485,481 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 35,210 Total kWh Sold & PH Consumption 1,520,691 Comments See Craig for power generation. No Non-Fuel Expenses Reported *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 79 of 185 Igiugig PCE Utility: IGIUGIG ELECTRIC COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 61 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 32 Community Facility Customers 15 Other Customers (Non-PCE)11 Fiscal Year PCE Payments $98,833 PCE Statistical Data PCE Eligible kWh - Residential Customers 95,337 Average Annual PCE Payment per Eligible Customer $2,103 PCE Eligible kWh - Community Facility Customers 49,253 Average PCE Payment per Eligible kWh $0.68 Total PCE Eligible kWh 144,590 Last Reported Residential Rate Charged (based on 500 kWh) $0.92 Average Monthly PCE Eligible kWh per Residential Customer 248 Last Reported PCE Level (per kWh)$0.72 Average Monthly PCE Eligible kWh per Community Facility Customer 274 Effective Residential Rate (per kWh)$0.19 Average Monthly PCE Eligible Community Facility kWh per Person 67 PCE Eligible kWh vs Total kWh Sold 53.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 343,011 Fuel Used (Gallons)25,999 Non-Diesel kWh Generated 0 Fuel Cost $247,810 Purchased kWh 55 Average Price of Fuel $9.53 Total Purchased & Generated 343,066 Fuel Cost per kWh sold $0.91 Annual Non-Fuel Expenses $104,866 Non-Fuel Expense per kWh Sold $0.39 Total Expense per kWh Sold $1.30 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 96,731 Consumed vs Generated (kWh Sold vs Generated-Purchased) 79.3% Community Facility kWh Sold 89,325 Line Loss (%)16.3% Other kWh Sold (Non-PCE)86,011 Fuel Efficiency (kWh per Gallon of Diesel)13.19 Total kWh Sold 272,067 PH Consumption as % of Generation 4.4% Powerhouse (PH) Consumption kWh 15,099 Total kWh Sold & PH Consumption 287,166 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 80 of 185 Iliamna; Newhalen; Nondalton PCE Utility: ILIAMNA NEWHALEN NONDALTON Reporting Period: 07/01/22 to 06/30/23 Community Population 419 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 179 Community Facility Customers 14 Other Customers (Non-PCE)105 Fiscal Year PCE Payments $355,477 PCE Statistical Data PCE Eligible kWh - Residential Customers 704,885 Average Annual PCE Payment per Eligible Customer $1,842 PCE Eligible kWh - Community Facility Customers 235,448 Average PCE Payment per Eligible kWh $0.38 Total PCE Eligible kWh 940,333 Last Reported Residential Rate Charged (based on 500 kWh) $0.62 Average Monthly PCE Eligible kWh per Residential Customer 328 Last Reported PCE Level (per kWh)$0.37 Average Monthly PCE Eligible kWh per Community Facility Customer 1,401 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 47 PCE Eligible kWh vs Total kWh Sold 29.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 40,840 Fuel Used (Gallons)2,858 Non-Diesel kWh Generated 3,918,020 Fuel Cost $10,451 Purchased kWh 0 Average Price of Fuel $3.66 Total Purchased & Generated 3,958,860 Fuel Cost per kWh sold $0.00 Annual Non-Fuel Expenses $1,475,695 Non-Fuel Expense per kWh Sold $0.47 Total Expense per kWh Sold $0.47 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 821,946 Consumed vs Generated (kWh Sold vs Generated-Purchased) 79.4% Community Facility kWh Sold 259,491 Line Loss (%)8.4% Other kWh Sold (Non-PCE)2,060,270 Fuel Efficiency (kWh per Gallon of Diesel)14.29 Total kWh Sold 3,141,707 PH Consumption as % of Generation 12.3% Powerhouse (PH) Consumption kWh 485,978 Total kWh Sold & PH Consumption 3,627,685 Comments Diesel Generation & Fuel Used rept = 10 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 81 of 185 Kake PCE Utility: INSIDE PASSAGE ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 557 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 232 Community Facility Customers 13 Other Customers (Non-PCE)59 Fiscal Year PCE Payments $428,416 PCE Statistical Data PCE Eligible kWh - Residential Customers 844,122 Average Annual PCE Payment per Eligible Customer $1,749 PCE Eligible kWh - Community Facility Customers 207,635 Average PCE Payment per Eligible kWh $0.41 Total PCE Eligible kWh 1,051,757 Last Reported Residential Rate Charged (based on 500 kWh) $0.63 Average Monthly PCE Eligible kWh per Residential Customer 303 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 1,331 Effective Residential Rate (per kWh)$0.31 Average Monthly PCE Eligible Community Facility kWh per Person 31 PCE Eligible kWh vs Total kWh Sold 52.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,619,492 Fuel Used (Gallons)106,494 Non-Diesel kWh Generated 793,060 Fuel Cost $468,448 Purchased kWh 0 Average Price of Fuel $4.40 Total Purchased & Generated 2,412,552 Fuel Cost per kWh sold $0.23 Annual Non-Fuel Expenses $969,302 Non-Fuel Expense per kWh Sold $0.48 Total Expense per kWh Sold $0.71 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 913,607 Consumed vs Generated (kWh Sold vs Generated-Purchased) 83.8% Community Facility kWh Sold 207,635 Line Loss (%)9.0% Other kWh Sold (Non-PCE)901,355 Fuel Efficiency (kWh per Gallon of Diesel)15.21 Total kWh Sold 2,022,597 PH Consumption as % of Generation 7.1% Powerhouse (PH) Consumption kWh 172,095 Total kWh Sold & PH Consumption 2,194,692 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 82 of 185 Kaktovik PCE Utility: NORTH SLOPE BOROUGH Reporting Period: 07/01/22 to 06/30/23 Community Population 266 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 77 Community Facility Customers 2 Other Customers (Non-PCE)52 Fiscal Year PCE Payments $7,578 PCE Statistical Data PCE Eligible kWh - Residential Customers 242,786 Average Annual PCE Payment per Eligible Customer $96 PCE Eligible kWh - Community Facility Customers 37,192 Average PCE Payment per Eligible kWh $0.03 Total PCE Eligible kWh 279,978 Last Reported Residential Rate Charged (based on 500 kWh) $0.35 Average Monthly PCE Eligible kWh per Residential Customer 263 Last Reported PCE Level (per kWh)$0.15 Average Monthly PCE Eligible kWh per Community Facility Customer 1,550 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 12 PCE Eligible kWh vs Total kWh Sold 7.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 5,221,694 Fuel Used (Gallons)369,727 Non-Diesel kWh Generated 0 Fuel Cost $1,189,973 Purchased kWh 0 Average Price of Fuel $3.22 Total Purchased & Generated 5,221,694 Fuel Cost per kWh sold $0.33 Annual Non-Fuel Expenses $971,298 Non-Fuel Expense per kWh Sold $0.27 Total Expense per kWh Sold $0.59 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 706,202 Consumed vs Generated (kWh Sold vs Generated-Purchased) 69.9% Community Facility kWh Sold 37,192 Line Loss (%)25.3% Other kWh Sold (Non-PCE)2,907,343 Fuel Efficiency (kWh per Gallon of Diesel)14.12 Total kWh Sold 3,650,737 PH Consumption as % of Generation 4.7% Powerhouse (PH) Consumption kWh 247,453 Total kWh Sold & PH Consumption 3,898,190 Comments Residential PCE Level = Zero *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 83 of 185 Kaltag PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 149 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 66 Community Facility Customers 10 Other Customers (Non-PCE)23 Fiscal Year PCE Payments $136,600 PCE Statistical Data PCE Eligible kWh - Residential Customers 270,344 Average Annual PCE Payment per Eligible Customer $1,797 PCE Eligible kWh - Community Facility Customers 89,390 Average PCE Payment per Eligible kWh $0.38 Total PCE Eligible kWh 359,734 Last Reported Residential Rate Charged (based on 500 kWh) $0.65 Average Monthly PCE Eligible kWh per Residential Customer 341 Last Reported PCE Level (per kWh)$0.40 Average Monthly PCE Eligible kWh per Community Facility Customer 745 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 50 PCE Eligible kWh vs Total kWh Sold 49.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 782,846 Fuel Used (Gallons)44,775 Non-Diesel kWh Generated 5,524 Fuel Cost $176,187 Purchased kWh 0 Average Price of Fuel $3.93 Total Purchased & Generated 788,370 Fuel Cost per kWh sold $0.24 Annual Non-Fuel Expenses $185,027 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.50 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 275,189 Consumed vs Generated (kWh Sold vs Generated-Purchased) 91.9% Community Facility kWh Sold 171,119 Line Loss (%)5.9% Other kWh Sold (Non-PCE)278,486 Fuel Efficiency (kWh per Gallon of Diesel)17.48 Total kWh Sold 724,794 PH Consumption as % of Generation 2.2% Powerhouse (PH) Consumption kWh 17,055 Total kWh Sold & PH Consumption 741,849 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 84 of 185 Karluk PCE Utility: KARLUK IRA TRIBAL COUNCIL Reporting Period: 07/01/22 to 06/30/23 Community Population 27 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 13 Community Facility Customers 4 Other Customers (Non-PCE)11 Fiscal Year PCE Payments $45,992 PCE Statistical Data PCE Eligible kWh - Residential Customers 70,122 Average Annual PCE Payment per Eligible Customer $2,705 PCE Eligible kWh - Community Facility Customers 21,095 Average PCE Payment per Eligible kWh $0.50 Total PCE Eligible kWh 91,217 Last Reported Residential Rate Charged (based on 500 kWh) $0.70 Average Monthly PCE Eligible kWh per Residential Customer 450 Last Reported PCE Level (per kWh)$0.50 Average Monthly PCE Eligible kWh per Community Facility Customer 439 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 65 PCE Eligible kWh vs Total kWh Sold 52.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 198,809 Fuel Used (Gallons)20,936 Non-Diesel kWh Generated 0 Fuel Cost $92,644 Purchased kWh 0 Average Price of Fuel $4.43 Total Purchased & Generated 198,809 Fuel Cost per kWh sold $0.54 Annual Non-Fuel Expenses $59,891 Non-Fuel Expense per kWh Sold $0.35 Total Expense per kWh Sold $0.88 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 79,183 Consumed vs Generated (kWh Sold vs Generated-Purchased) 86.9% Community Facility kWh Sold 24,720 Line Loss (%)11.4% Other kWh Sold (Non-PCE)68,914 Fuel Efficiency (kWh per Gallon of Diesel)9.50 Total kWh Sold 172,817 PH Consumption as % of Generation 1.7% Powerhouse (PH) Consumption kWh 3,374 Total kWh Sold & PH Consumption 176,191 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 85 of 185 Kasigluk PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 613 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 113 Community Facility Customers 12 Other Customers (Non-PCE)27 Fiscal Year PCE Payments $262,028 PCE Statistical Data PCE Eligible kWh - Residential Customers 704,139 Average Annual PCE Payment per Eligible Customer $2,096 PCE Eligible kWh - Community Facility Customers 209,932 Average PCE Payment per Eligible kWh $0.29 Total PCE Eligible kWh 914,071 Last Reported Residential Rate Charged (based on 500 kWh) $0.60 Average Monthly PCE Eligible kWh per Residential Customer 519 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 1,458 Effective Residential Rate (per kWh)$0.27 Average Monthly PCE Eligible Community Facility kWh per Person 29 PCE Eligible kWh vs Total kWh Sold 67.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,721,011 Fuel Used (Gallons)179,858 Non-Diesel kWh Generated 326,911 Fuel Cost $587,553 Purchased kWh 0 Average Price of Fuel $3.27 Total Purchased & Generated 3,047,922 Fuel Cost per kWh sold $0.43 Annual Non-Fuel Expenses $347,954 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.69 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 799,332 Consumed vs Generated (kWh Sold vs Generated-Purchased) 44.7% Community Facility kWh Sold 323,268 Line Loss (%)51.3% Other kWh Sold (Non-PCE)240,420 Fuel Efficiency (kWh per Gallon of Diesel)15.13 Total kWh Sold 1,363,020 PH Consumption as % of Generation 4.0% Powerhouse (PH) Consumption kWh 121,987 Total kWh Sold & PH Consumption 1,485,007 Comments Provides power to Nunapitchuk via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 86 of 185 Kiana PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 433 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 108 Community Facility Customers 12 Other Customers (Non-PCE)33 Fiscal Year PCE Payments $352,253 PCE Statistical Data PCE Eligible kWh - Residential Customers 643,927 Average Annual PCE Payment per Eligible Customer $2,935 PCE Eligible kWh - Community Facility Customers 255,434 Average PCE Payment per Eligible kWh $0.39 Total PCE Eligible kWh 899,361 Last Reported Residential Rate Charged (based on 500 kWh) $0.73 Average Monthly PCE Eligible kWh per Residential Customer 497 Last Reported PCE Level (per kWh)$0.47 Average Monthly PCE Eligible kWh per Community Facility Customer 1,774 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 49 PCE Eligible kWh vs Total kWh Sold 51.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,848,264 Fuel Used (Gallons)90,041 Non-Diesel kWh Generated 0 Fuel Cost $425,997 Purchased kWh 0 Average Price of Fuel $4.73 Total Purchased & Generated 1,848,264 Fuel Cost per kWh sold $0.24 Annual Non-Fuel Expenses $444,839 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.50 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 765,551 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.3% Community Facility kWh Sold 390,716 Line Loss (%)3.2% Other kWh Sold (Non-PCE)586,271 Fuel Efficiency (kWh per Gallon of Diesel)20.53 Total kWh Sold 1,742,538 PH Consumption as % of Generation 2.5% Powerhouse (PH) Consumption kWh 46,868 Total kWh Sold & PH Consumption 1,789,406 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 87 of 185 Kipnuk PCE Utility: KIPNUK LIGHT PLANT Reporting Period: 07/01/22 to 06/30/23 Community Population 712 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 203 Community Facility Customers 7 Other Customers (Non-PCE)44 Fiscal Year PCE Payments $496,932 PCE Statistical Data PCE Eligible kWh - Residential Customers 902,771 Average Annual PCE Payment per Eligible Customer $2,366 PCE Eligible kWh - Community Facility Customers 112,293 Average PCE Payment per Eligible kWh $0.49 Total PCE Eligible kWh 1,015,064 Last Reported Residential Rate Charged (based on 500 kWh) $0.69 Average Monthly PCE Eligible kWh per Residential Customer 371 Last Reported PCE Level (per kWh)$0.49 Average Monthly PCE Eligible kWh per Community Facility Customer 1,337 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 13 PCE Eligible kWh vs Total kWh Sold 56.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,376,230 Fuel Used (Gallons)101,245 Non-Diesel kWh Generated 669,936 Fuel Cost $316,806 Purchased kWh 0 Average Price of Fuel $3.13 Total Purchased & Generated 2,046,166 Fuel Cost per kWh sold $0.17 Annual Non-Fuel Expenses $1,128,952 Non-Fuel Expense per kWh Sold $0.62 Total Expense per kWh Sold $0.80 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 948,192 Consumed vs Generated (kWh Sold vs Generated-Purchased) 88.5% Community Facility kWh Sold 160,385 Line Loss (%)7.2% Other kWh Sold (Non-PCE)702,502 Fuel Efficiency (kWh per Gallon of Diesel)13.59 Total kWh Sold 1,811,079 PH Consumption as % of Generation 4.3% Powerhouse (PH) Consumption kWh 88,219 Total kWh Sold & PH Consumption 1,899,298 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 88 of 185 Kivalina PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 444 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 89 Community Facility Customers 9 Other Customers (Non-PCE)31 Fiscal Year PCE Payments $254,770 PCE Statistical Data PCE Eligible kWh - Residential Customers 509,242 Average Annual PCE Payment per Eligible Customer $2,600 PCE Eligible kWh - Community Facility Customers 116,666 Average PCE Payment per Eligible kWh $0.41 Total PCE Eligible kWh 625,908 Last Reported Residential Rate Charged (based on 500 kWh) $0.66 Average Monthly PCE Eligible kWh per Residential Customer 477 Last Reported PCE Level (per kWh)$0.41 Average Monthly PCE Eligible kWh per Community Facility Customer 1,080 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 22 PCE Eligible kWh vs Total kWh Sold 33.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,996,223 Fuel Used (Gallons)114,902 Non-Diesel kWh Generated 0 Fuel Cost $515,060 Purchased kWh 0 Average Price of Fuel $4.48 Total Purchased & Generated 1,996,223 Fuel Cost per kWh sold $0.27 Annual Non-Fuel Expenses $479,182 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.53 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 609,437 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.0% Community Facility kWh Sold 637,316 Line Loss (%)3.2% Other kWh Sold (Non-PCE)630,317 Fuel Efficiency (kWh per Gallon of Diesel)17.37 Total kWh Sold 1,877,070 PH Consumption as % of Generation 2.8% Powerhouse (PH) Consumption kWh 55,405 Total kWh Sold & PH Consumption 1,932,475 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 89 of 185 Klawock PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 709 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 392 Community Facility Customers 21 Other Customers (Non-PCE)162 Fiscal Year PCE Payments $148,452 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,847,287 Average Annual PCE Payment per Eligible Customer $359 PCE Eligible kWh - Community Facility Customers 569,515 Average PCE Payment per Eligible kWh $0.06 Total PCE Eligible kWh 2,416,802 Last Reported Residential Rate Charged (based on 500 kWh) $0.32 Average Monthly PCE Eligible kWh per Residential Customer 393 Last Reported PCE Level (per kWh)$0.07 Average Monthly PCE Eligible kWh per Community Facility Customer 2,260 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 67 PCE Eligible kWh vs Total kWh Sold 29.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.00 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 2,263,147 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 580,988 Line Loss (%)See Comments Other kWh Sold (Non-PCE)5,352,569 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 8,196,704 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 169,914 Total kWh Sold & PH Consumption 8,366,618 Comments See Craig for power generation. No Non-Fuel Expenses Reported *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 90 of 185 Klukwan PCE Utility: INSIDE PASSAGE ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 88 Last Reported Month December No. of Monthly Payments Made 6 Residential Customers 52 Community Facility Customers 9 Other Customers (Non-PCE)10 Fiscal Year PCE Payments $58,564 PCE Statistical Data PCE Eligible kWh - Residential Customers 95,445 Average Annual PCE Payment per Eligible Customer $960 PCE Eligible kWh - Community Facility Customers 36,960 Average PCE Payment per Eligible kWh $0.44 Total PCE Eligible kWh 132,405 Last Reported Residential Rate Charged (based on 500 kWh) $0.68 Average Monthly PCE Eligible kWh per Residential Customer 306 Last Reported PCE Level (per kWh)$0.39 Average Monthly PCE Eligible kWh per Community Facility Customer 684 Effective Residential Rate (per kWh)$0.29 Average Monthly PCE Eligible Community Facility kWh per Person 70 PCE Eligible kWh vs Total kWh Sold 65.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 203,223 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 203,223 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.00 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 101,887 Consumed vs Generated (kWh Sold vs Generated-Purchased) 100.0% Community Facility kWh Sold 52,051 Line Loss (%)See Comments Other kWh Sold (Non-PCE)49,285 Fuel Efficiency (kWh per Gallon of Diesel)0.00 Total kWh Sold 203,223 PH Consumption as % of Generation 0.0% Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 203,223 Comments July-Dec repts. Rec. power frm Chilkat Vly Combined w/Chilkat Vly-Jan. forward *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 91 of 185 Kobuk PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 183 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 34 Community Facility Customers 3 Other Customers (Non-PCE)14 Fiscal Year PCE Payments $213,012 PCE Statistical Data PCE Eligible kWh - Residential Customers 199,001 Average Annual PCE Payment per Eligible Customer $5,757 PCE Eligible kWh - Community Facility Customers 93,913 Average PCE Payment per Eligible kWh $0.73 Total PCE Eligible kWh 292,914 Last Reported Residential Rate Charged (based on 500 kWh) $0.10 Average Monthly PCE Eligible kWh per Residential Customer 488 Last Reported PCE Level (per kWh)$0.77 Average Monthly PCE Eligible kWh per Community Facility Customer 2,609 Effective Residential Rate (per kWh)($0.67) Average Monthly PCE Eligible Community Facility kWh per Person 43 PCE Eligible kWh vs Total kWh Sold 46.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $162,618 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.26 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 238,561 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 150,016 Line Loss (%)See Comments Other kWh Sold (Non-PCE)248,436 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 637,013 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 637,013 Comments Receives power from Shungnak Bay via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 92 of 185 Kokhanok PCE Utility: KOKHANOK VILLAGE COUNCIL Reporting Period: 07/01/22 to 06/30/23 Community Population 139 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 57 Community Facility Customers 9 Other Customers (Non-PCE)13 Fiscal Year PCE Payments $158,208 PCE Statistical Data PCE Eligible kWh - Residential Customers 189,754 Average Annual PCE Payment per Eligible Customer $2,397 PCE Eligible kWh - Community Facility Customers 63,496 Average PCE Payment per Eligible kWh $0.62 Total PCE Eligible kWh 253,250 Last Reported Residential Rate Charged (based on 500 kWh) $0.97 Average Monthly PCE Eligible kWh per Residential Customer 277 Last Reported PCE Level (per kWh)$0.70 Average Monthly PCE Eligible kWh per Community Facility Customer 588 Effective Residential Rate (per kWh)$0.27 Average Monthly PCE Eligible Community Facility kWh per Person 38 PCE Eligible kWh vs Total kWh Sold 66.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 366,000 Fuel Used (Gallons)38,979 Non-Diesel kWh Generated 96,518 Fuel Cost $192,713 Purchased kWh 0 Average Price of Fuel $4.94 Total Purchased & Generated 462,518 Fuel Cost per kWh sold $0.51 Annual Non-Fuel Expenses $59,045 Non-Fuel Expense per kWh Sold $0.15 Total Expense per kWh Sold $0.66 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 192,117 Consumed vs Generated (kWh Sold vs Generated-Purchased) 82.4% Community Facility kWh Sold 63,499 Line Loss (%)14.8% Other kWh Sold (Non-PCE)125,483 Fuel Efficiency (kWh per Gallon of Diesel)9.39 Total kWh Sold 381,099 PH Consumption as % of Generation 2.8% Powerhouse (PH) Consumption kWh 13,109 Total kWh Sold & PH Consumption 394,208 Comments Powerhouse Consumption = 10 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 93 of 185 Koliganek PCE Utility: NEW KOLIGANEK VILLAGE COUNCIL Reporting Period: 07/01/22 to 06/30/23 Community Population 176 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 75 Community Facility Customers 11 Other Customers (Non-PCE)14 Fiscal Year PCE Payments $85,376 PCE Statistical Data PCE Eligible kWh - Residential Customers 230,012 Average Annual PCE Payment per Eligible Customer $993 PCE Eligible kWh - Community Facility Customers 71,274 Average PCE Payment per Eligible kWh $0.28 Total PCE Eligible kWh 301,286 Last Reported Residential Rate Charged (based on 500 kWh) $0.50 Average Monthly PCE Eligible kWh per Residential Customer 256 Last Reported PCE Level (per kWh)$0.30 Average Monthly PCE Eligible kWh per Community Facility Customer 540 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 34 PCE Eligible kWh vs Total kWh Sold 49.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 673,925 Fuel Used (Gallons)61,854 Non-Diesel kWh Generated 0 Fuel Cost $231,335 Purchased kWh 0 Average Price of Fuel $3.74 Total Purchased & Generated 673,925 Fuel Cost per kWh sold $0.38 Annual Non-Fuel Expenses $48,000 Non-Fuel Expense per kWh Sold $0.08 Total Expense per kWh Sold $0.46 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 245,367 Consumed vs Generated (kWh Sold vs Generated-Purchased) 89.6% Community Facility kWh Sold 80,958 Line Loss (%)7.6% Other kWh Sold (Non-PCE)277,635 Fuel Efficiency (kWh per Gallon of Diesel)10.90 Total kWh Sold 603,960 PH Consumption as % of Generation 2.8% Powerhouse (PH) Consumption kWh 18,782 Total kWh Sold & PH Consumption 622,742 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 94 of 185 Kongiganak PCE Utility: PUVURNAQ POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 494 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 159 Community Facility Customers 5 Other Customers (Non-PCE)27 Fiscal Year PCE Payments $226,660 PCE Statistical Data PCE Eligible kWh - Residential Customers 584,971 Average Annual PCE Payment per Eligible Customer $1,382 PCE Eligible kWh - Community Facility Customers 95,319 Average PCE Payment per Eligible kWh $0.33 Total PCE Eligible kWh 680,290 Last Reported Residential Rate Charged (based on 500 kWh) $0.72 Average Monthly PCE Eligible kWh per Residential Customer 307 Last Reported PCE Level (per kWh)$0.38 Average Monthly PCE Eligible kWh per Community Facility Customer 1,589 Effective Residential Rate (per kWh)$0.34 Average Monthly PCE Eligible Community Facility kWh per Person 16 PCE Eligible kWh vs Total kWh Sold 59.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 948,191 Fuel Used (Gallons)77,418 Non-Diesel kWh Generated 550,822 Fuel Cost $263,647 Purchased kWh 0 Average Price of Fuel $3.41 Total Purchased & Generated 1,499,013 Fuel Cost per kWh sold $0.23 Annual Non-Fuel Expenses $487,086 Non-Fuel Expense per kWh Sold $0.43 Total Expense per kWh Sold $0.66 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 717,832 Consumed vs Generated (kWh Sold vs Generated-Purchased) 76.2% Community Facility kWh Sold 95,845 Line Loss (%)15.9% Other kWh Sold (Non-PCE)329,042 Fuel Efficiency (kWh per Gallon of Diesel)12.25 Total kWh Sold 1,142,719 PH Consumption as % of Generation 7.9% Powerhouse (PH) Consumption kWh 117,979 Total kWh Sold & PH Consumption 1,260,698 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 95 of 185 Kotlik PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 639 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 123 Community Facility Customers 9 Other Customers (Non-PCE)37 Fiscal Year PCE Payments $340,204 PCE Statistical Data PCE Eligible kWh - Residential Customers 704,896 Average Annual PCE Payment per Eligible Customer $2,577 PCE Eligible kWh - Community Facility Customers 198,142 Average PCE Payment per Eligible kWh $0.38 Total PCE Eligible kWh 903,038 Last Reported Residential Rate Charged (based on 500 kWh) $0.70 Average Monthly PCE Eligible kWh per Residential Customer 478 Last Reported PCE Level (per kWh)$0.44 Average Monthly PCE Eligible kWh per Community Facility Customer 1,835 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 26 PCE Eligible kWh vs Total kWh Sold 45.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,116,000 Fuel Used (Gallons)154,048 Non-Diesel kWh Generated 0 Fuel Cost $601,935 Purchased kWh 0 Average Price of Fuel $3.91 Total Purchased & Generated 2,116,000 Fuel Cost per kWh sold $0.30 Annual Non-Fuel Expenses $506,531 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.56 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 794,074 Consumed vs Generated (kWh Sold vs Generated-Purchased) 93.8% Community Facility kWh Sold 292,496 Line Loss (%)4.2% Other kWh Sold (Non-PCE)897,632 Fuel Efficiency (kWh per Gallon of Diesel)13.74 Total kWh Sold 1,984,202 PH Consumption as % of Generation 2.0% Powerhouse (PH) Consumption kWh 42,603 Total kWh Sold & PH Consumption 2,026,805 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 96 of 185 Kotzebue PCE Utility: KOTZEBUE ELECTRIC ASSOCIATION Reporting Period: 07/01/22 to 06/30/23 Community Population 3,004 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 1,084 Community Facility Customers 26 Other Customers (Non-PCE)172 Fiscal Year PCE Payments $1,090,140 PCE Statistical Data PCE Eligible kWh - Residential Customers 4,239,690 Average Annual PCE Payment per Eligible Customer $982 PCE Eligible kWh - Community Facility Customers 1,609,676 Average PCE Payment per Eligible kWh $0.19 Total PCE Eligible kWh 5,849,366 Last Reported Residential Rate Charged (based on 500 kWh) $0.41 Average Monthly PCE Eligible kWh per Residential Customer 326 Last Reported PCE Level (per kWh)$0.20 Average Monthly PCE Eligible kWh per Community Facility Customer 5,159 Effective Residential Rate (per kWh)$0.21 Average Monthly PCE Eligible Community Facility kWh per Person 45 PCE Eligible kWh vs Total kWh Sold 29.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 15,907,452 Fuel Used (Gallons)1,165,673 Non-Diesel kWh Generated 3,662,784 Fuel Cost $3,505,821 Purchased kWh 0 Average Price of Fuel $3.01 Total Purchased & Generated 19,570,236 Fuel Cost per kWh sold $0.18 Annual Non-Fuel Expenses $3,431,363 Non-Fuel Expense per kWh Sold $0.17 Total Expense per kWh Sold $0.35 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 6,867,862 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 1,741,140 Line Loss (%)See Comments Other kWh Sold (Non-PCE)11,008,509 Fuel Efficiency (kWh per Gallon of Diesel)13.65 Total kWh Sold 19,617,511 PH Consumption as % of Generation 2.3% Powerhouse (PH) Consumption kWh 452,850 Total kWh Sold & PH Consumption 20,070,361 Comments kWh Generated = 11 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 97 of 185 Koyuk PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 307 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 84 Community Facility Customers 9 Other Customers (Non-PCE)38 Fiscal Year PCE Payments $194,946 PCE Statistical Data PCE Eligible kWh - Residential Customers 445,892 Average Annual PCE Payment per Eligible Customer $2,096 PCE Eligible kWh - Community Facility Customers 155,448 Average PCE Payment per Eligible kWh $0.32 Total PCE Eligible kWh 601,340 Last Reported Residential Rate Charged (based on 500 kWh) $0.67 Average Monthly PCE Eligible kWh per Residential Customer 442 Last Reported PCE Level (per kWh)$0.41 Average Monthly PCE Eligible kWh per Community Facility Customer 1,439 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 42 PCE Eligible kWh vs Total kWh Sold 49.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,280,504 Fuel Used (Gallons)75,770 Non-Diesel kWh Generated 0 Fuel Cost $294,950 Purchased kWh 0 Average Price of Fuel $3.89 Total Purchased & Generated 1,280,504 Fuel Cost per kWh sold $0.24 Annual Non-Fuel Expenses $309,574 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.50 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 500,361 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.7% Community Facility kWh Sold 264,522 Line Loss (%)3.8% Other kWh Sold (Non-PCE)447,790 Fuel Efficiency (kWh per Gallon of Diesel)16.90 Total kWh Sold 1,212,673 PH Consumption as % of Generation 1.5% Powerhouse (PH) Consumption kWh 19,101 Total kWh Sold & PH Consumption 1,231,774 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 98 of 185 Koyukuk PCE Utility: CITY OF KOYUKUK Reporting Period: 07/01/22 to 06/30/23 Community Population 94 Last Reported Month June No. of Monthly Payments Made 11 Residential Customers 53 Community Facility Customers 6 Other Customers (Non-PCE)8 Fiscal Year PCE Payments $72,211 PCE Statistical Data PCE Eligible kWh - Residential Customers 153,857 Average Annual PCE Payment per Eligible Customer $1,224 PCE Eligible kWh - Community Facility Customers 32,976 Average PCE Payment per Eligible kWh $0.39 Total PCE Eligible kWh 186,833 Last Reported Residential Rate Charged (based on 500 kWh) $0.95 Average Monthly PCE Eligible kWh per Residential Customer 264 Last Reported PCE Level (per kWh)$0.39 Average Monthly PCE Eligible kWh per Community Facility Customer 500 Effective Residential Rate (per kWh)$0.56 Average Monthly PCE Eligible Community Facility kWh per Person 32 PCE Eligible kWh vs Total kWh Sold 59.4% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 447,178 Fuel Used (Gallons)42,896 Non-Diesel kWh Generated 0 Fuel Cost $157,068 Purchased kWh 0 Average Price of Fuel $3.66 Total Purchased & Generated 447,178 Fuel Cost per kWh sold $0.50 Annual Non-Fuel Expenses $95,888 Non-Fuel Expense per kWh Sold $0.30 Total Expense per kWh Sold $0.80 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 206,518 Consumed vs Generated (kWh Sold vs Generated-Purchased) 70.4% Community Facility kWh Sold 37,114 Line Loss (%)23.2% Other kWh Sold (Non-PCE)71,161 Fuel Efficiency (kWh per Gallon of Diesel)10.42 Total kWh Sold 314,793 PH Consumption as % of Generation 6.4% Powerhouse (PH) Consumption kWh 28,453 Total kWh Sold & PH Consumption 343,246 Comments Only 11 Reports Filed *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 99 of 185 Kwethluk PCE Utility: KWETHLUK INCORPORATED Reporting Period: 07/01/22 to 06/30/23 Community Population 799 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 189 Community Facility Customers 1 Other Customers (Non-PCE)34 Fiscal Year PCE Payments $269,659 PCE Statistical Data PCE Eligible kWh - Residential Customers 924,423 Average Annual PCE Payment per Eligible Customer $1,419 PCE Eligible kWh - Community Facility Customers 1,437 Average PCE Payment per Eligible kWh $0.29 Total PCE Eligible kWh 925,860 Last Reported Residential Rate Charged (based on 500 kWh) $0.52 Average Monthly PCE Eligible kWh per Residential Customer 408 Last Reported PCE Level (per kWh)$0.32 Average Monthly PCE Eligible kWh per Community Facility Customer 120 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 0 PCE Eligible kWh vs Total kWh Sold 55.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,909,654 Fuel Used (Gallons)206,841 Non-Diesel kWh Generated 0 Fuel Cost $866,031 Purchased kWh 0 Average Price of Fuel $4.19 Total Purchased & Generated 1,909,654 Fuel Cost per kWh sold $0.51 Annual Non-Fuel Expenses $646,738 Non-Fuel Expense per kWh Sold $0.38 Total Expense per kWh Sold $0.90 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,077,454 Consumed vs Generated (kWh Sold vs Generated-Purchased) 88.2% Community Facility kWh Sold 1,437 Line Loss (%)10.1% Other kWh Sold (Non-PCE)605,280 Fuel Efficiency (kWh per Gallon of Diesel)9.23 Total kWh Sold 1,684,171 PH Consumption as % of Generation 1.7% Powerhouse (PH) Consumption kWh 32,713 Total kWh Sold & PH Consumption 1,716,884 Comments Diesel Generated kWh = 9 mths. Fuel Used and PHouse Consumption = 10 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 100 of 185 Kwigillingok PCE Utility: KWIGILLINGOK IRA COUNCIL Reporting Period: 07/01/22 to 06/30/23 Community Population 380 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 101 Community Facility Customers 2 Other Customers (Non-PCE)23 Fiscal Year PCE Payments $212,587 PCE Statistical Data PCE Eligible kWh - Residential Customers 547,789 Average Annual PCE Payment per Eligible Customer $2,064 PCE Eligible kWh - Community Facility Customers 46,861 Average PCE Payment per Eligible kWh $0.36 Total PCE Eligible kWh 594,650 Last Reported Residential Rate Charged (based on 500 kWh) $0.67 Average Monthly PCE Eligible kWh per Residential Customer 452 Last Reported PCE Level (per kWh)$0.36 Average Monthly PCE Eligible kWh per Community Facility Customer 1,953 Effective Residential Rate (per kWh)$0.31 Average Monthly PCE Eligible Community Facility kWh per Person 10 PCE Eligible kWh vs Total kWh Sold 47.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,406,280 Fuel Used (Gallons)111,949 Non-Diesel kWh Generated 21,449 Fuel Cost $359,961 Purchased kWh 0 Average Price of Fuel $3.22 Total Purchased & Generated 1,427,729 Fuel Cost per kWh sold $0.29 Annual Non-Fuel Expenses $231,368 Non-Fuel Expense per kWh Sold $0.19 Total Expense per kWh Sold $0.47 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 597,084 Consumed vs Generated (kWh Sold vs Generated-Purchased) 87.4% Community Facility kWh Sold 46,861 Line Loss (%)9.9% Other kWh Sold (Non-PCE)604,176 Fuel Efficiency (kWh per Gallon of Diesel)12.56 Total kWh Sold 1,248,121 PH Consumption as % of Generation 2.7% Powerhouse (PH) Consumption kWh 38,321 Total kWh Sold & PH Consumption 1,286,442 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 101 of 185 Levelock PCE Utility: LEVELOCK ELECTRICAL COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 65 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 39 Community Facility Customers 7 Other Customers (Non-PCE)37 Fiscal Year PCE Payments $76,879 PCE Statistical Data PCE Eligible kWh - Residential Customers 101,445 Average Annual PCE Payment per Eligible Customer $1,671 PCE Eligible kWh - Community Facility Customers 35,346 Average PCE Payment per Eligible kWh $0.56 Total PCE Eligible kWh 136,791 Last Reported Residential Rate Charged (based on 500 kWh) $1.35 Average Monthly PCE Eligible kWh per Residential Customer 217 Last Reported PCE Level (per kWh)$0.65 Average Monthly PCE Eligible kWh per Community Facility Customer 421 Effective Residential Rate (per kWh)$0.70 Average Monthly PCE Eligible Community Facility kWh per Person 45 PCE Eligible kWh vs Total kWh Sold 39.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 459,016 Fuel Used (Gallons)39,879 Non-Diesel kWh Generated 0 Fuel Cost $161,320 Purchased kWh 0 Average Price of Fuel $4.05 Total Purchased & Generated 459,016 Fuel Cost per kWh sold $0.46 Annual Non-Fuel Expenses $236,960 Non-Fuel Expense per kWh Sold $0.68 Total Expense per kWh Sold $1.14 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 102,634 Consumed vs Generated (kWh Sold vs Generated-Purchased) 76.1% Community Facility kWh Sold 41,777 Line Loss (%)13.4% Other kWh Sold (Non-PCE)205,129 Fuel Efficiency (kWh per Gallon of Diesel)11.51 Total kWh Sold 349,540 PH Consumption as % of Generation 10.4% Powerhouse (PH) Consumption kWh 47,942 Total kWh Sold & PH Consumption 397,482 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 102 of 185 Lime Village PCE Utility: LIME VILLAGE ELECTRIC UTILITY Reporting Period: 07/01/22 to 06/30/23 Community Population 5 Last Reported Month April No. of Monthly Payments Made 3 Residential Customers 15 Community Facility Customers 6 Other Customers (Non-PCE)2 Fiscal Year PCE Payments $6,229 PCE Statistical Data PCE Eligible kWh - Residential Customers 7,103 Average Annual PCE Payment per Eligible Customer $297 PCE Eligible kWh - Community Facility Customers 1,050 Average PCE Payment per Eligible kWh $0.76 Total PCE Eligible kWh 8,153 Last Reported Residential Rate Charged (based on 500 kWh) $1.77 Average Monthly PCE Eligible kWh per Residential Customer 158 Last Reported PCE Level (per kWh)$0.76 Average Monthly PCE Eligible kWh per Community Facility Customer 58 Effective Residential Rate (per kWh)$1.01 Average Monthly PCE Eligible Community Facility kWh per Person 70 PCE Eligible kWh vs Total kWh Sold 18.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 67,852 Fuel Used (Gallons)7,301 Non-Diesel kWh Generated 0 Fuel Cost $81,157 Purchased kWh 0 Average Price of Fuel $11.12 Total Purchased & Generated 67,852 Fuel Cost per kWh sold $1.85 Annual Non-Fuel Expenses $9,000 Non-Fuel Expense per kWh Sold $0.21 Total Expense per kWh Sold $2.06 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 11,216 Consumed vs Generated (kWh Sold vs Generated-Purchased) 64.6% Community Facility kWh Sold 12,580 Line Loss (%)33.7% Other kWh Sold (Non-PCE)20,003 Fuel Efficiency (kWh per Gallon of Diesel)9.29 Total kWh Sold 43,799 PH Consumption as % of Generation 1.7% Powerhouse (PH) Consumption kWh 1,158 Total kWh Sold & PH Consumption 44,957 Comments Only 3 reports filed - Each covering 2 months *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 103 of 185 Lower Kalskag PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 262 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 78 Community Facility Customers 6 Other Customers (Non-PCE)12 Fiscal Year PCE Payments $165,192 PCE Statistical Data PCE Eligible kWh - Residential Customers 379,463 Average Annual PCE Payment per Eligible Customer $1,967 PCE Eligible kWh - Community Facility Customers 76,040 Average PCE Payment per Eligible kWh $0.36 Total PCE Eligible kWh 455,503 Last Reported Residential Rate Charged (based on 500 kWh) $0.66 Average Monthly PCE Eligible kWh per Residential Customer 405 Last Reported PCE Level (per kWh)$0.40 Average Monthly PCE Eligible kWh per Community Facility Customer 1,056 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 24 PCE Eligible kWh vs Total kWh Sold 68.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $169,044 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.26 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 411,159 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 115,371 Line Loss (%)See Comments Other kWh Sold (Non-PCE)135,654 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 662,184 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 662,184 Comments Receives power from Upper Kalskag via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 104 of 185 Manley Hot Springs PCE Utility: TDX MANLEY GENERATING LLC Reporting Period: 07/01/22 to 06/30/23 Community Population 98 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 78 Community Facility Customers 11 Other Customers (Non-PCE)23 Fiscal Year PCE Payments $136,682 PCE Statistical Data PCE Eligible kWh - Residential Customers 149,727 Average Annual PCE Payment per Eligible Customer $1,536 PCE Eligible kWh - Community Facility Customers 29,224 Average PCE Payment per Eligible kWh $0.76 Total PCE Eligible kWh 178,951 Last Reported Residential Rate Charged (based on 500 kWh) $1.29 Average Monthly PCE Eligible kWh per Residential Customer 160 Last Reported PCE Level (per kWh)$0.77 Average Monthly PCE Eligible kWh per Community Facility Customer 221 Effective Residential Rate (per kWh)$0.53 Average Monthly PCE Eligible Community Facility kWh per Person 25 PCE Eligible kWh vs Total kWh Sold 35.4% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 616,782 Fuel Used (Gallons)45,819 Non-Diesel kWh Generated 0 Fuel Cost $209,460 Purchased kWh 0 Average Price of Fuel $4.57 Total Purchased & Generated 616,782 Fuel Cost per kWh sold $0.41 Annual Non-Fuel Expenses $315,907 Non-Fuel Expense per kWh Sold $0.62 Total Expense per kWh Sold $1.04 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 168,269 Consumed vs Generated (kWh Sold vs Generated-Purchased) 82.0% Community Facility kWh Sold 77,682 Line Loss (%)12.9% Other kWh Sold (Non-PCE)259,572 Fuel Efficiency (kWh per Gallon of Diesel)13.46 Total kWh Sold 505,523 PH Consumption as % of Generation 5.1% Powerhouse (PH) Consumption kWh 31,513 Total kWh Sold & PH Consumption 537,036 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 105 of 185 Manokotak PCE Utility: MANOKOTAK POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 477 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 127 Community Facility Customers 5 Other Customers (Non-PCE)33 Fiscal Year PCE Payments $130,236 PCE Statistical Data PCE Eligible kWh - Residential Customers 591,663 Average Annual PCE Payment per Eligible Customer $987 PCE Eligible kWh - Community Facility Customers 62,138 Average PCE Payment per Eligible kWh $0.20 Total PCE Eligible kWh 653,801 Last Reported Residential Rate Charged (based on 500 kWh) $0.60 Average Monthly PCE Eligible kWh per Residential Customer 388 Last Reported PCE Level (per kWh)$0.25 Average Monthly PCE Eligible kWh per Community Facility Customer 1,036 Effective Residential Rate (per kWh)$0.35 Average Monthly PCE Eligible Community Facility kWh per Person 11 PCE Eligible kWh vs Total kWh Sold 54.4% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,204,677 Fuel Used (Gallons)93,595 Non-Diesel kWh Generated 0 Fuel Cost $279,912 Purchased kWh 0 Average Price of Fuel $2.99 Total Purchased & Generated 1,204,677 Fuel Cost per kWh sold $0.23 Annual Non-Fuel Expenses $192,607 Non-Fuel Expense per kWh Sold $0.16 Total Expense per kWh Sold $0.39 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 638,842 Consumed vs Generated (kWh Sold vs Generated-Purchased) 99.8% Community Facility kWh Sold 62,138 Line Loss (%)0.2% Other kWh Sold (Non-PCE)501,342 Fuel Efficiency (kWh per Gallon of Diesel)12.87 Total kWh Sold 1,202,322 PH Consumption as % of Generation 0.0% Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 1,202,322 Comments No Powerhouse Consumption Reported *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 106 of 185 Marshall PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 468 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 106 Community Facility Customers 18 Other Customers (Non-PCE)26 Fiscal Year PCE Payments $251,926 PCE Statistical Data PCE Eligible kWh - Residential Customers 577,380 Average Annual PCE Payment per Eligible Customer $2,032 PCE Eligible kWh - Community Facility Customers 202,982 Average PCE Payment per Eligible kWh $0.32 Total PCE Eligible kWh 780,362 Last Reported Residential Rate Charged (based on 500 kWh) $0.65 Average Monthly PCE Eligible kWh per Residential Customer 454 Last Reported PCE Level (per kWh)$0.40 Average Monthly PCE Eligible kWh per Community Facility Customer 940 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 36 PCE Eligible kWh vs Total kWh Sold 52.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,576,857 Fuel Used (Gallons)93,132 Non-Diesel kWh Generated 0 Fuel Cost $368,643 Purchased kWh 0 Average Price of Fuel $3.96 Total Purchased & Generated 1,576,857 Fuel Cost per kWh sold $0.25 Annual Non-Fuel Expenses $380,900 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.50 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 628,176 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.6% Community Facility kWh Sold 352,462 Line Loss (%)3.5% Other kWh Sold (Non-PCE)511,437 Fuel Efficiency (kWh per Gallon of Diesel)16.93 Total kWh Sold 1,492,075 PH Consumption as % of Generation 1.9% Powerhouse (PH) Consumption kWh 29,661 Total kWh Sold & PH Consumption 1,521,736 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 107 of 185 McGrath PCE Utility: MCGRATH LIGHT & POWER Reporting Period: 07/01/22 to 06/30/23 Community Population 274 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 191 Community Facility Customers 14 Other Customers (Non-PCE)87 Fiscal Year PCE Payments $284,344 PCE Statistical Data PCE Eligible kWh - Residential Customers 492,144 Average Annual PCE Payment per Eligible Customer $1,387 PCE Eligible kWh - Community Facility Customers 178,124 Average PCE Payment per Eligible kWh $0.42 Total PCE Eligible kWh 670,268 Last Reported Residential Rate Charged (based on 500 kWh) $0.85 Average Monthly PCE Eligible kWh per Residential Customer 215 Last Reported PCE Level (per kWh)$0.45 Average Monthly PCE Eligible kWh per Community Facility Customer 1,060 Effective Residential Rate (per kWh)$0.40 Average Monthly PCE Eligible Community Facility kWh per Person 54 PCE Eligible kWh vs Total kWh Sold 32.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,383,260 Fuel Used (Gallons)166,429 Non-Diesel kWh Generated 0 Fuel Cost $680,295 Purchased kWh 0 Average Price of Fuel $4.09 Total Purchased & Generated 2,383,260 Fuel Cost per kWh sold $0.33 Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.33 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 529,155 Consumed vs Generated (kWh Sold vs Generated-Purchased) 87.2% Community Facility kWh Sold 178,335 Line Loss (%)9.1% Other kWh Sold (Non-PCE)1,369,822 Fuel Efficiency (kWh per Gallon of Diesel)14.32 Total kWh Sold 2,077,312 PH Consumption as % of Generation 3.7% Powerhouse (PH) Consumption kWh 88,917 Total kWh Sold & PH Consumption 2,166,229 Comments Non-Fuel Costs Not Reported *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 108 of 185 Mekoryuk PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 195 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 87 Community Facility Customers 10 Other Customers (Non-PCE)32 Fiscal Year PCE Payments $135,495 PCE Statistical Data PCE Eligible kWh - Residential Customers 318,943 Average Annual PCE Payment per Eligible Customer $1,397 PCE Eligible kWh - Community Facility Customers 97,288 Average PCE Payment per Eligible kWh $0.33 Total PCE Eligible kWh 416,231 Last Reported Residential Rate Charged (based on 500 kWh) $0.67 Average Monthly PCE Eligible kWh per Residential Customer 306 Last Reported PCE Level (per kWh)$0.41 Average Monthly PCE Eligible kWh per Community Facility Customer 811 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 42 PCE Eligible kWh vs Total kWh Sold 51.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 892,473 Fuel Used (Gallons)70,627 Non-Diesel kWh Generated 6,931 Fuel Cost $259,336 Purchased kWh 0 Average Price of Fuel $3.67 Total Purchased & Generated 899,404 Fuel Cost per kWh sold $0.32 Annual Non-Fuel Expenses $207,538 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.57 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 325,127 Consumed vs Generated (kWh Sold vs Generated-Purchased) 90.4% Community Facility kWh Sold 151,317 Line Loss (%)5.8% Other kWh Sold (Non-PCE)336,532 Fuel Efficiency (kWh per Gallon of Diesel)12.64 Total kWh Sold 812,976 PH Consumption as % of Generation 3.8% Powerhouse (PH) Consumption kWh 34,419 Total kWh Sold & PH Consumption 847,395 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 109 of 185 Mentasta PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 118 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 58 Community Facility Customers 7 Other Customers (Non-PCE)16 Fiscal Year PCE Payments $93,196 PCE Statistical Data PCE Eligible kWh - Residential Customers 154,997 Average Annual PCE Payment per Eligible Customer $1,434 PCE Eligible kWh - Community Facility Customers 24,405 Average PCE Payment per Eligible kWh $0.52 Total PCE Eligible kWh 179,402 Last Reported Residential Rate Charged (based on 500 kWh) $0.66 Average Monthly PCE Eligible kWh per Residential Customer 223 Last Reported PCE Level (per kWh)$0.36 Average Monthly PCE Eligible kWh per Community Facility Customer 291 Effective Residential Rate (per kWh)$0.30 Average Monthly PCE Eligible Community Facility kWh per Person 17 PCE Eligible kWh vs Total kWh Sold 40.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.00 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 158,070 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 24,405 Line Loss (%)See Comments Other kWh Sold (Non-PCE)259,189 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 441,664 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 441,664 Comments See Slana for power generation. No Non-Fuel Expenses Reported *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 110 of 185 Minto PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 156 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 75 Community Facility Customers 6 Other Customers (Non-PCE)23 Fiscal Year PCE Payments $160,950 PCE Statistical Data PCE Eligible kWh - Residential Customers 314,927 Average Annual PCE Payment per Eligible Customer $1,987 PCE Eligible kWh - Community Facility Customers 131,040 Average PCE Payment per Eligible kWh $0.36 Total PCE Eligible kWh 445,967 Last Reported Residential Rate Charged (based on 500 kWh) $0.64 Average Monthly PCE Eligible kWh per Residential Customer 350 Last Reported PCE Level (per kWh)$0.39 Average Monthly PCE Eligible kWh per Community Facility Customer 1,820 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 70 PCE Eligible kWh vs Total kWh Sold 55.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 835,536 Fuel Used (Gallons)46,374 Non-Diesel kWh Generated 0 Fuel Cost $167,137 Purchased kWh 0 Average Price of Fuel $3.60 Total Purchased & Generated 835,536 Fuel Cost per kWh sold $0.21 Annual Non-Fuel Expenses $205,206 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.46 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 354,569 Consumed vs Generated (kWh Sold vs Generated-Purchased) 96.2% Community Facility kWh Sold 351,790 Line Loss (%)2.1% Other kWh Sold (Non-PCE)97,483 Fuel Efficiency (kWh per Gallon of Diesel)18.02 Total kWh Sold 803,842 PH Consumption as % of Generation 1.7% Powerhouse (PH) Consumption kWh 13,964 Total kWh Sold & PH Consumption 817,806 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 111 of 185 Mt. Village PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 602 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 159 Community Facility Customers 17 Other Customers (Non-PCE)55 Fiscal Year PCE Payments $302,638 PCE Statistical Data PCE Eligible kWh - Residential Customers 807,443 Average Annual PCE Payment per Eligible Customer $1,720 PCE Eligible kWh - Community Facility Customers 313,899 Average PCE Payment per Eligible kWh $0.27 Total PCE Eligible kWh 1,121,342 Last Reported Residential Rate Charged (based on 500 kWh) $0.58 Average Monthly PCE Eligible kWh per Residential Customer 423 Last Reported PCE Level (per kWh)$0.27 Average Monthly PCE Eligible kWh per Community Facility Customer 1,539 Effective Residential Rate (per kWh)$0.31 Average Monthly PCE Eligible Community Facility kWh per Person 43 PCE Eligible kWh vs Total kWh Sold 41.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $686,913 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.26 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 861,389 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 550,624 Line Loss (%)See Comments Other kWh Sold (Non-PCE)1,278,786 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 2,690,799 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 2,690,799 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 112 of 185 Naknek;S.Naknek;Kng Slmn PCE Utility: NAKNEK ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 822 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 734 Community Facility Customers 37 Other Customers (Non-PCE)394 Fiscal Year PCE Payments $898,012 PCE Statistical Data PCE Eligible kWh - Residential Customers 2,023,134 Average Annual PCE Payment per Eligible Customer $1,165 PCE Eligible kWh - Community Facility Customers 690,480 Average PCE Payment per Eligible kWh $0.33 Total PCE Eligible kWh 2,713,614 Last Reported Residential Rate Charged (based on 500 kWh) $0.58 Average Monthly PCE Eligible kWh per Residential Customer 230 Last Reported PCE Level (per kWh)$0.37 Average Monthly PCE Eligible kWh per Community Facility Customer 1,555 Effective Residential Rate (per kWh)$0.21 Average Monthly PCE Eligible Community Facility kWh per Person 70 PCE Eligible kWh vs Total kWh Sold 13.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 22,027,963 Fuel Used (Gallons)1,525,892 Non-Diesel kWh Generated 0 Fuel Cost $4,452,763 Purchased kWh 0 Average Price of Fuel $2.92 Total Purchased & Generated 22,027,963 Fuel Cost per kWh sold $0.22 Annual Non-Fuel Expenses $8,066,427 Non-Fuel Expense per kWh Sold $0.39 Total Expense per kWh Sold $0.60 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 3,017,217 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.0% Community Facility kWh Sold 1,081,003 Line Loss (%)3.8% Other kWh Sold (Non-PCE)16,605,066 Fuel Efficiency (kWh per Gallon of Diesel)14.44 Total kWh Sold 20,703,286 PH Consumption as % of Generation 2.2% Powerhouse (PH) Consumption kWh 490,877 Total kWh Sold & PH Consumption 21,194,163 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 113 of 185 Napakiak PCE Utility: NAPAKIAK IRCINRAQ Reporting Period: 07/01/22 to 06/30/23 Community Population 361 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 108 Community Facility Customers 4 Other Customers (Non-PCE)20 Fiscal Year PCE Payments $104,961 PCE Statistical Data PCE Eligible kWh - Residential Customers 362,258 Average Annual PCE Payment per Eligible Customer $937 PCE Eligible kWh - Community Facility Customers 38,039 Average PCE Payment per Eligible kWh $0.26 Total PCE Eligible kWh 400,297 Last Reported Residential Rate Charged (based on 500 kWh) $0.77 Average Monthly PCE Eligible kWh per Residential Customer 280 Last Reported PCE Level (per kWh)$0.26 Average Monthly PCE Eligible kWh per Community Facility Customer 792 Effective Residential Rate (per kWh)$0.50 Average Monthly PCE Eligible Community Facility kWh per Person 9 PCE Eligible kWh vs Total kWh Sold 55.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 770,428 Average Price of Fuel $0.00 Total Purchased & Generated 770,428 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $384,697 Non-Fuel Expense per kWh Sold $0.53 Total Expense per kWh Sold $0.53 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 366,380 Consumed vs Generated (kWh Sold vs Generated-Purchased) 93.7% Community Facility kWh Sold 38,328 Line Loss (%)6.3% Other kWh Sold (Non-PCE)317,104 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 721,812 PH Consumption as % of Generation 0.0% Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 721,812 Comments Purchases power from AVEC *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 114 of 185 Napaskiak PCE Utility: NAPASKIAK ELECTRIC UTILITY Reporting Period: 07/01/22 to 06/30/23 Community Population 487 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 103 Community Facility Customers 8 Other Customers (Non-PCE)38 Fiscal Year PCE Payments $134,828 PCE Statistical Data PCE Eligible kWh - Residential Customers 418,089 Average Annual PCE Payment per Eligible Customer $1,215 PCE Eligible kWh - Community Facility Customers 41,375 Average PCE Payment per Eligible kWh $0.29 Total PCE Eligible kWh 459,464 Last Reported Residential Rate Charged (based on 500 kWh) $0.70 Average Monthly PCE Eligible kWh per Residential Customer 338 Last Reported PCE Level (per kWh)$0.31 Average Monthly PCE Eligible kWh per Community Facility Customer 431 Effective Residential Rate (per kWh)$0.39 Average Monthly PCE Eligible Community Facility kWh per Person 7 PCE Eligible kWh vs Total kWh Sold 66.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 909,969 Fuel Used (Gallons)59,723 Non-Diesel kWh Generated 0 Fuel Cost $256,826 Purchased kWh 0 Average Price of Fuel $4.30 Total Purchased & Generated 909,969 Fuel Cost per kWh sold $0.37 Annual Non-Fuel Expenses $227,710 Non-Fuel Expense per kWh Sold $0.33 Total Expense per kWh Sold $0.70 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 435,198 Consumed vs Generated (kWh Sold vs Generated-Purchased) 76.5% Community Facility kWh Sold 41,403 Line Loss (%)19.6% Other kWh Sold (Non-PCE)219,539 Fuel Efficiency (kWh per Gallon of Diesel)15.24 Total kWh Sold 696,140 PH Consumption as % of Generation 3.9% Powerhouse (PH) Consumption kWh 35,099 Total kWh Sold & PH Consumption 731,239 Comments Rptd Diesel kWh gen = 7 mths, Non Fuel = 9 mths, Fuel Used & Phouse Cons. 10 mth *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 115 of 185 Naukati PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 137 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 89 Community Facility Customers 0 Other Customers (Non-PCE)20 Fiscal Year PCE Payments $22,350 PCE Statistical Data PCE Eligible kWh - Residential Customers 362,760 Average Annual PCE Payment per Eligible Customer $251 PCE Eligible kWh - Community Facility Customers 0 Average PCE Payment per Eligible kWh $0.06 Total PCE Eligible kWh 362,760 Last Reported Residential Rate Charged (based on 500 kWh) $0.32 Average Monthly PCE Eligible kWh per Residential Customer 340 Last Reported PCE Level (per kWh)$0.07 Average Monthly PCE Eligible kWh per Community Facility Customer 0 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 0 PCE Eligible kWh vs Total kWh Sold 53.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $27,777 Non-Fuel Expense per kWh Sold $0.04 Total Expense per kWh Sold $0.04 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 486,132 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 0 Line Loss (%)See Comments Other kWh Sold (Non-PCE)191,229 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 677,361 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 10,608 Total kWh Sold & PH Consumption 687,969 Comments See Craig for power generation *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 116 of 185 Nelson Lagoon PCE Utility: NELSON LAGOON ELECTRICAL COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 33 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 33 Community Facility Customers 8 Other Customers (Non-PCE)25 Fiscal Year PCE Payments $81,806 PCE Statistical Data PCE Eligible kWh - Residential Customers 111,531 Average Annual PCE Payment per Eligible Customer $1,995 PCE Eligible kWh - Community Facility Customers 21,978 Average PCE Payment per Eligible kWh $0.61 Total PCE Eligible kWh 133,509 Last Reported Residential Rate Charged (based on 500 kWh) $0.84 Average Monthly PCE Eligible kWh per Residential Customer 282 Last Reported PCE Level (per kWh)$0.64 Average Monthly PCE Eligible kWh per Community Facility Customer 229 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 56 PCE Eligible kWh vs Total kWh Sold 52.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 283,301 Fuel Used (Gallons)49,897 Non-Diesel kWh Generated 0 Fuel Cost $273,316 Purchased kWh 0 Average Price of Fuel $5.48 Total Purchased & Generated 283,301 Fuel Cost per kWh sold $1.08 Annual Non-Fuel Expenses $26,505 Non-Fuel Expense per kWh Sold $0.11 Total Expense per kWh Sold $1.19 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 117,958 Consumed vs Generated (kWh Sold vs Generated-Purchased) 89.0% Community Facility kWh Sold 36,483 Line Loss (%)3.3% Other kWh Sold (Non-PCE)97,762 Fuel Efficiency (kWh per Gallon of Diesel)5.68 Total kWh Sold 252,203 PH Consumption as % of Generation 7.7% Powerhouse (PH) Consumption kWh 21,798 Total kWh Sold & PH Consumption 274,001 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 117 of 185 New Stuyahok PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 480 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 98 Community Facility Customers 9 Other Customers (Non-PCE)40 Fiscal Year PCE Payments $253,019 PCE Statistical Data PCE Eligible kWh - Residential Customers 538,866 Average Annual PCE Payment per Eligible Customer $2,365 PCE Eligible kWh - Community Facility Customers 115,180 Average PCE Payment per Eligible kWh $0.39 Total PCE Eligible kWh 654,046 Last Reported Residential Rate Charged (based on 500 kWh) $0.67 Average Monthly PCE Eligible kWh per Residential Customer 458 Last Reported PCE Level (per kWh)$0.42 Average Monthly PCE Eligible kWh per Community Facility Customer 1,066 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 20 PCE Eligible kWh vs Total kWh Sold 50.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,868,427 Fuel Used (Gallons)110,649 Non-Diesel kWh Generated 0 Fuel Cost $475,595 Purchased kWh 0 Average Price of Fuel $4.30 Total Purchased & Generated 1,868,427 Fuel Cost per kWh sold $0.37 Annual Non-Fuel Expenses $331,979 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.62 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 573,605 Consumed vs Generated (kWh Sold vs Generated-Purchased) 69.6% Community Facility kWh Sold 280,042 Line Loss (%)27.9% Other kWh Sold (Non-PCE)446,792 Fuel Efficiency (kWh per Gallon of Diesel)16.89 Total kWh Sold 1,300,439 PH Consumption as % of Generation 2.5% Powerhouse (PH) Consumption kWh 46,358 Total kWh Sold & PH Consumption 1,346,797 Comments Provides power to Ekwok via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 118 of 185 Newtok; Mertavik PCE Utility: UNGUSRAQ POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 264 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 96 Community Facility Customers 6 Other Customers (Non-PCE)24 Fiscal Year PCE Payments $175,581 PCE Statistical Data PCE Eligible kWh - Residential Customers 255,779 Average Annual PCE Payment per Eligible Customer $1,721 PCE Eligible kWh - Community Facility Customers 26,158 Average PCE Payment per Eligible kWh $0.62 Total PCE Eligible kWh 281,937 Last Reported Residential Rate Charged (based on 500 kWh) $0.80 Average Monthly PCE Eligible kWh per Residential Customer 222 Last Reported PCE Level (per kWh)$0.60 Average Monthly PCE Eligible kWh per Community Facility Customer 363 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 8 PCE Eligible kWh vs Total kWh Sold 54.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 522,868 Fuel Used (Gallons)22,894 Non-Diesel kWh Generated 0 Fuel Cost $101,148 Purchased kWh 0 Average Price of Fuel $4.42 Total Purchased & Generated 522,868 Fuel Cost per kWh sold $0.20 Annual Non-Fuel Expenses $36,000 Non-Fuel Expense per kWh Sold $0.07 Total Expense per kWh Sold $0.27 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 302,446 Consumed vs Generated (kWh Sold vs Generated-Purchased) 98.7% Community Facility kWh Sold 28,968 Line Loss (%)1.0% Other kWh Sold (Non-PCE)184,731 Fuel Efficiency (kWh per Gallon of Diesel)22.84 Total kWh Sold 516,145 PH Consumption as % of Generation 0.2% Powerhouse (PH) Consumption kWh 1,239 Total kWh Sold & PH Consumption 517,384 Comments Rpt Diesel kWh Gen & PHouse Consu = 1 mth, Fuel Used = 7 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 119 of 185 Nightmute PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 304 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 53 Community Facility Customers 5 Other Customers (Non-PCE)23 Fiscal Year PCE Payments $98,566 PCE Statistical Data PCE Eligible kWh - Residential Customers 271,750 Average Annual PCE Payment per Eligible Customer $1,699 PCE Eligible kWh - Community Facility Customers 52,053 Average PCE Payment per Eligible kWh $0.30 Total PCE Eligible kWh 323,803 Last Reported Residential Rate Charged (based on 500 kWh) $0.60 Average Monthly PCE Eligible kWh per Residential Customer 427 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 868 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 14 PCE Eligible kWh vs Total kWh Sold 38.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $213,712 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.26 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 286,344 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 103,330 Line Loss (%)See Comments Other kWh Sold (Non-PCE)447,488 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 837,162 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 837,162 Comments Receives power from Toksook Bay via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 120 of 185 Nikolai PCE Utility: CITY OF NIKOLAI Reporting Period: 07/01/22 to 06/30/23 Community Population 92 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 40 Community Facility Customers 8 Other Customers (Non-PCE)11 Fiscal Year PCE Payments $120,024 PCE Statistical Data PCE Eligible kWh - Residential Customers 136,500 Average Annual PCE Payment per Eligible Customer $2,501 PCE Eligible kWh - Community Facility Customers 49,766 Average PCE Payment per Eligible kWh $0.64 Total PCE Eligible kWh 186,266 Last Reported Residential Rate Charged (based on 500 kWh) $0.90 Average Monthly PCE Eligible kWh per Residential Customer 284 Last Reported PCE Level (per kWh)$0.67 Average Monthly PCE Eligible kWh per Community Facility Customer 518 Effective Residential Rate (per kWh)$0.23 Average Monthly PCE Eligible Community Facility kWh per Person 45 PCE Eligible kWh vs Total kWh Sold 48.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 446,222 Fuel Used (Gallons)38,294 Non-Diesel kWh Generated 0 Fuel Cost $226,093 Purchased kWh 0 Average Price of Fuel $5.90 Total Purchased & Generated 446,222 Fuel Cost per kWh sold $0.59 Annual Non-Fuel Expenses $36,000 Non-Fuel Expense per kWh Sold $0.09 Total Expense per kWh Sold $0.68 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 139,716 Consumed vs Generated (kWh Sold vs Generated-Purchased) 85.8% Community Facility kWh Sold 50,068 Line Loss (%)10.3% Other kWh Sold (Non-PCE)193,125 Fuel Efficiency (kWh per Gallon of Diesel)11.65 Total kWh Sold 382,909 PH Consumption as % of Generation 3.9% Powerhouse (PH) Consumption kWh 17,354 Total kWh Sold & PH Consumption 400,263 Comments Rpt Fuel Used 10 mths, PHouse Consm 7 mths, Diesel kWh Gen 11 mths. *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 121 of 185 Nikolski PCE Utility: UMNAK POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 42 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 15 Community Facility Customers 5 Other Customers (Non-PCE)9 Fiscal Year PCE Payments $29,664 PCE Statistical Data PCE Eligible kWh - Residential Customers 43,082 Average Annual PCE Payment per Eligible Customer $1,483 PCE Eligible kWh - Community Facility Customers 10,444 Average PCE Payment per Eligible kWh $0.55 Total PCE Eligible kWh 53,526 Last Reported Residential Rate Charged (based on 500 kWh) $0.75 Average Monthly PCE Eligible kWh per Residential Customer 239 Last Reported PCE Level (per kWh)$0.55 Average Monthly PCE Eligible kWh per Community Facility Customer 174 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 21 PCE Eligible kWh vs Total kWh Sold 39.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 176,966 Fuel Used (Gallons)22,733 Non-Diesel kWh Generated 0 Fuel Cost $184,117 Purchased kWh 0 Average Price of Fuel $8.10 Total Purchased & Generated 176,966 Fuel Cost per kWh sold $1.35 Annual Non-Fuel Expenses $79,020 Non-Fuel Expense per kWh Sold $0.58 Total Expense per kWh Sold $1.93 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 45,684 Consumed vs Generated (kWh Sold vs Generated-Purchased) 77.0% Community Facility kWh Sold 14,437 Line Loss (%)9.4% Other kWh Sold (Non-PCE)76,225 Fuel Efficiency (kWh per Gallon of Diesel)7.78 Total kWh Sold 136,346 PH Consumption as % of Generation 13.6% Powerhouse (PH) Consumption kWh 24,046 Total kWh Sold & PH Consumption 160,392 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 122 of 185 Noatak PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 533 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 119 Community Facility Customers 7 Other Customers (Non-PCE)29 Fiscal Year PCE Payments $727,236 PCE Statistical Data PCE Eligible kWh - Residential Customers 770,260 Average Annual PCE Payment per Eligible Customer $5,772 PCE Eligible kWh - Community Facility Customers 208,842 Average PCE Payment per Eligible kWh $0.74 Total PCE Eligible kWh 979,102 Last Reported Residential Rate Charged (based on 500 kWh) $0.67 Average Monthly PCE Eligible kWh per Residential Customer 539 Last Reported PCE Level (per kWh)$0.77 Average Monthly PCE Eligible kWh per Community Facility Customer 2,486 Effective Residential Rate (per kWh)($0.10) Average Monthly PCE Eligible Community Facility kWh per Person 33 PCE Eligible kWh vs Total kWh Sold 53.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,956,224 Fuel Used (Gallons)106,376 Non-Diesel kWh Generated 0 Fuel Cost $1,099,316 Purchased kWh 0 Average Price of Fuel $10.33 Total Purchased & Generated 1,956,224 Fuel Cost per kWh sold $0.60 Annual Non-Fuel Expenses $465,121 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.86 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 870,952 Consumed vs Generated (kWh Sold vs Generated-Purchased) 93.1% Community Facility kWh Sold 328,824 Line Loss (%)4.5% Other kWh Sold (Non-PCE)622,212 Fuel Efficiency (kWh per Gallon of Diesel)18.39 Total kWh Sold 1,821,988 PH Consumption as % of Generation 2.3% Powerhouse (PH) Consumption kWh 45,673 Total kWh Sold & PH Consumption 1,867,661 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 123 of 185 Nome PCE Utility: NOME JOINT UTILITY SYSTEM Reporting Period: 07/01/22 to 06/30/23 Community Population 3,524 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 1,770 Community Facility Customers 82 Other Customers (Non-PCE)391 Fiscal Year PCE Payments $1,184,569 PCE Statistical Data PCE Eligible kWh - Residential Customers 6,282,133 Average Annual PCE Payment per Eligible Customer $640 PCE Eligible kWh - Community Facility Customers 2,229,757 Average PCE Payment per Eligible kWh $0.14 Total PCE Eligible kWh 8,511,890 Last Reported Residential Rate Charged (based on 500 kWh) $0.46 Average Monthly PCE Eligible kWh per Residential Customer 296 Last Reported PCE Level (per kWh)$0.19 Average Monthly PCE Eligible kWh per Community Facility Customer 2,266 Effective Residential Rate (per kWh)$0.28 Average Monthly PCE Eligible Community Facility kWh per Person 53 PCE Eligible kWh vs Total kWh Sold 29.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 29,627,293 Fuel Used (Gallons)1,878,311 Non-Diesel kWh Generated 1,866,796 Fuel Cost $5,218,876 Purchased kWh 0 Average Price of Fuel $2.78 Total Purchased & Generated 31,494,089 Fuel Cost per kWh sold $0.18 Annual Non-Fuel Expenses $4,598,783 Non-Fuel Expense per kWh Sold $0.16 Total Expense per kWh Sold $0.34 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 8,688,238 Consumed vs Generated (kWh Sold vs Generated-Purchased) 92.7% Community Facility kWh Sold 3,382,835 Line Loss (%)3.2% Other kWh Sold (Non-PCE)17,127,983 Fuel Efficiency (kWh per Gallon of Diesel)15.77 Total kWh Sold 29,199,056 PH Consumption as % of Generation 4.1% Powerhouse (PH) Consumption kWh 1,297,423 Total kWh Sold & PH Consumption 30,496,479 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 124 of 185 Noorvik PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 640 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 135 Community Facility Customers 10 Other Customers (Non-PCE)37 Fiscal Year PCE Payments $450,852 PCE Statistical Data PCE Eligible kWh - Residential Customers 792,951 Average Annual PCE Payment per Eligible Customer $3,109 PCE Eligible kWh - Community Facility Customers 409,754 Average PCE Payment per Eligible kWh $0.37 Total PCE Eligible kWh 1,202,705 Last Reported Residential Rate Charged (based on 500 kWh) $0.69 Average Monthly PCE Eligible kWh per Residential Customer 489 Last Reported PCE Level (per kWh)$0.44 Average Monthly PCE Eligible kWh per Community Facility Customer 3,415 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 53 PCE Eligible kWh vs Total kWh Sold 58.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,192,185 Fuel Used (Gallons)135,410 Non-Diesel kWh Generated 12,436 Fuel Cost $571,230 Purchased kWh 0 Average Price of Fuel $4.22 Total Purchased & Generated 2,204,621 Fuel Cost per kWh sold $0.28 Annual Non-Fuel Expenses $525,097 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.53 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 937,138 Consumed vs Generated (kWh Sold vs Generated-Purchased) 93.3% Community Facility kWh Sold 601,914 Line Loss (%)5.1% Other kWh Sold (Non-PCE)517,876 Fuel Efficiency (kWh per Gallon of Diesel)16.19 Total kWh Sold 2,056,928 PH Consumption as % of Generation 1.6% Powerhouse (PH) Consumption kWh 34,583 Total kWh Sold & PH Consumption 2,091,511 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 125 of 185 Northway; Northway Village PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 234 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 92 Community Facility Customers 9 Other Customers (Non-PCE)35 Fiscal Year PCE Payments $180,690 PCE Statistical Data PCE Eligible kWh - Residential Customers 311,237 Average Annual PCE Payment per Eligible Customer $1,789 PCE Eligible kWh - Community Facility Customers 69,841 Average PCE Payment per Eligible kWh $0.47 Total PCE Eligible kWh 381,078 Last Reported Residential Rate Charged (based on 500 kWh) $0.65 Average Monthly PCE Eligible kWh per Residential Customer 282 Last Reported PCE Level (per kWh)$0.35 Average Monthly PCE Eligible kWh per Community Facility Customer 647 Effective Residential Rate (per kWh)$0.30 Average Monthly PCE Eligible Community Facility kWh per Person 25 PCE Eligible kWh vs Total kWh Sold 35.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,176,000 Fuel Used (Gallons)91,913 Non-Diesel kWh Generated 0 Fuel Cost $355,591 Purchased kWh 0 Average Price of Fuel $3.87 Total Purchased & Generated 1,176,000 Fuel Cost per kWh sold $0.33 Annual Non-Fuel Expenses $148,561 Non-Fuel Expense per kWh Sold $0.14 Total Expense per kWh Sold $0.46 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 341,012 Consumed vs Generated (kWh Sold vs Generated-Purchased) 92.5% Community Facility kWh Sold 69,841 Line Loss (%)5.5% Other kWh Sold (Non-PCE)677,488 Fuel Efficiency (kWh per Gallon of Diesel)12.79 Total kWh Sold 1,088,341 PH Consumption as % of Generation 1.9% Powerhouse (PH) Consumption kWh 22,848 Total kWh Sold & PH Consumption 1,111,189 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 126 of 185 Nuiqsut PCE Utility: NORTH SLOPE BOROUGH Reporting Period: 07/01/22 to 06/30/23 Community Population 525 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 121 Community Facility Customers 3 Other Customers (Non-PCE)75 Fiscal Year PCE Payments $8,269 PCE Statistical Data PCE Eligible kWh - Residential Customers 614,354 Average Annual PCE Payment per Eligible Customer $67 PCE Eligible kWh - Community Facility Customers 102,631 Average PCE Payment per Eligible kWh $0.01 Total PCE Eligible kWh 716,985 Last Reported Residential Rate Charged (based on 500 kWh) $0.08 Average Monthly PCE Eligible kWh per Residential Customer 423 Last Reported PCE Level (per kWh)$0.00 Average Monthly PCE Eligible kWh per Community Facility Customer 2,851 Effective Residential Rate (per kWh)$0.08 Average Monthly PCE Eligible Community Facility kWh per Person 16 PCE Eligible kWh vs Total kWh Sold 11.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,979,358 Fuel Used (Gallons)152,501 Non-Diesel kWh Generated 5,762,730 Fuel Cost $717,622 Purchased kWh 0 Average Price of Fuel $4.71 Total Purchased & Generated 7,742,088 Fuel Cost per kWh sold $0.12 Annual Non-Fuel Expenses $954,655 Non-Fuel Expense per kWh Sold $0.15 Total Expense per kWh Sold $0.27 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 979,180 Consumed vs Generated (kWh Sold vs Generated-Purchased) 80.2% Community Facility kWh Sold 102,631 Line Loss (%)14.5% Other kWh Sold (Non-PCE)5,124,283 Fuel Efficiency (kWh per Gallon of Diesel)12.98 Total kWh Sold 6,206,094 PH Consumption as % of Generation 5.4% Powerhouse (PH) Consumption kWh 415,164 Total kWh Sold & PH Consumption 6,621,258 Comments Residential PCE Level = Zero *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 127 of 185 Nulato PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 223 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 108 Community Facility Customers 15 Other Customers (Non-PCE)24 Fiscal Year PCE Payments $295,017 PCE Statistical Data PCE Eligible kWh - Residential Customers 434,768 Average Annual PCE Payment per Eligible Customer $2,399 PCE Eligible kWh - Community Facility Customers 184,940 Average PCE Payment per Eligible kWh $0.48 Total PCE Eligible kWh 619,708 Last Reported Residential Rate Charged (based on 500 kWh) $0.77 Average Monthly PCE Eligible kWh per Residential Customer 335 Last Reported PCE Level (per kWh)$0.51 Average Monthly PCE Eligible kWh per Community Facility Customer 1,027 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 69 PCE Eligible kWh vs Total kWh Sold 60.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,085,051 Fuel Used (Gallons)52,768 Non-Diesel kWh Generated 0 Fuel Cost $271,542 Purchased kWh 0 Average Price of Fuel $5.15 Total Purchased & Generated 1,085,051 Fuel Cost per kWh sold $0.27 Annual Non-Fuel Expenses $260,943 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.52 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 461,152 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.2% Community Facility kWh Sold 334,493 Line Loss (%)3.9% Other kWh Sold (Non-PCE)226,531 Fuel Efficiency (kWh per Gallon of Diesel)20.56 Total kWh Sold 1,022,176 PH Consumption as % of Generation 1.9% Powerhouse (PH) Consumption kWh 20,962 Total kWh Sold & PH Consumption 1,043,138 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 128 of 185 Nunam Iqua PCE Utility: NUNAM IQUA ELECTRIC COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 216 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 48 Community Facility Customers 6 Other Customers (Non-PCE)23 Fiscal Year PCE Payments $139,157 PCE Statistical Data PCE Eligible kWh - Residential Customers 250,761 Average Annual PCE Payment per Eligible Customer $2,577 PCE Eligible kWh - Community Facility Customers 168,765 Average PCE Payment per Eligible kWh $0.33 Total PCE Eligible kWh 419,526 Last Reported Residential Rate Charged (based on 500 kWh) $0.55 Average Monthly PCE Eligible kWh per Residential Customer 435 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 2,344 Effective Residential Rate (per kWh)$0.22 Average Monthly PCE Eligible Community Facility kWh per Person 65 PCE Eligible kWh vs Total kWh Sold 45.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 989,407 Fuel Used (Gallons)75,167 Non-Diesel kWh Generated 0 Fuel Cost $323,466 Purchased kWh 0 Average Price of Fuel $4.30 Total Purchased & Generated 989,407 Fuel Cost per kWh sold $0.35 Annual Non-Fuel Expenses $116,886 Non-Fuel Expense per kWh Sold $0.13 Total Expense per kWh Sold $0.47 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 272,818 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.1% Community Facility kWh Sold 202,079 Line Loss (%)2.0% Other kWh Sold (Non-PCE)455,726 Fuel Efficiency (kWh per Gallon of Diesel)13.16 Total kWh Sold 930,623 PH Consumption as % of Generation 3.9% Powerhouse (PH) Consumption kWh 38,601 Total kWh Sold & PH Consumption 969,224 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 129 of 185 Nunapitchuk PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 567 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 119 Community Facility Customers 11 Other Customers (Non-PCE)33 Fiscal Year PCE Payments $218,355 PCE Statistical Data PCE Eligible kWh - Residential Customers 639,686 Average Annual PCE Payment per Eligible Customer $1,680 PCE Eligible kWh - Community Facility Customers 111,685 Average PCE Payment per Eligible kWh $0.29 Total PCE Eligible kWh 751,371 Last Reported Residential Rate Charged (based on 500 kWh) $0.60 Average Monthly PCE Eligible kWh per Residential Customer 448 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 846 Effective Residential Rate (per kWh)$0.27 Average Monthly PCE Eligible Community Facility kWh per Person 16 PCE Eligible kWh vs Total kWh Sold 55.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $343,140 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.26 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 675,961 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 251,365 Line Loss (%)See Comments Other kWh Sold (Non-PCE)416,833 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 1,344,159 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 1,344,159 Comments Receives power from Kasigluk via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 130 of 185 Old Harbor PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 210 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 85 Community Facility Customers 11 Other Customers (Non-PCE)30 Fiscal Year PCE Payments $202,097 PCE Statistical Data PCE Eligible kWh - Residential Customers 305,653 Average Annual PCE Payment per Eligible Customer $2,105 PCE Eligible kWh - Community Facility Customers 155,301 Average PCE Payment per Eligible kWh $0.44 Total PCE Eligible kWh 460,954 Last Reported Residential Rate Charged (based on 500 kWh) $0.74 Average Monthly PCE Eligible kWh per Residential Customer 300 Last Reported PCE Level (per kWh)$0.48 Average Monthly PCE Eligible kWh per Community Facility Customer 1,177 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 62 PCE Eligible kWh vs Total kWh Sold 64.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 790,356 Fuel Used (Gallons)44,747 Non-Diesel kWh Generated 0 Fuel Cost $207,475 Purchased kWh 0 Average Price of Fuel $4.64 Total Purchased & Generated 790,356 Fuel Cost per kWh sold $0.29 Annual Non-Fuel Expenses $183,607 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.54 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 327,055 Consumed vs Generated (kWh Sold vs Generated-Purchased) 91.0% Community Facility kWh Sold 255,779 Line Loss (%)4.3% Other kWh Sold (Non-PCE)136,397 Fuel Efficiency (kWh per Gallon of Diesel)17.66 Total kWh Sold 719,231 PH Consumption as % of Generation 4.7% Powerhouse (PH) Consumption kWh 36,825 Total kWh Sold & PH Consumption 756,056 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 131 of 185 Ouzinkie PCE Utility: CITY OF OUZINKIE Reporting Period: 07/01/22 to 06/30/23 Community Population 114 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 77 Community Facility Customers 16 Other Customers (Non-PCE)20 Fiscal Year PCE Payments $69,964 PCE Statistical Data PCE Eligible kWh - Residential Customers 238,791 Average Annual PCE Payment per Eligible Customer $752 PCE Eligible kWh - Community Facility Customers 93,213 Average PCE Payment per Eligible kWh $0.21 Total PCE Eligible kWh 332,004 Last Reported Residential Rate Charged (based on 500 kWh) $9.99 Average Monthly PCE Eligible kWh per Residential Customer 258 Last Reported PCE Level (per kWh)$0.19 Average Monthly PCE Eligible kWh per Community Facility Customer 485 Effective Residential Rate (per kWh)$9.80 Average Monthly PCE Eligible Community Facility kWh per Person 68 PCE Eligible kWh vs Total kWh Sold 51.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 562,083 Fuel Used (Gallons)43,369 Non-Diesel kWh Generated 163,883 Fuel Cost $205,756 Purchased kWh 0 Average Price of Fuel $4.74 Total Purchased & Generated 725,966 Fuel Cost per kWh sold $0.32 Annual Non-Fuel Expenses $94,481 Non-Fuel Expense per kWh Sold $0.15 Total Expense per kWh Sold $0.47 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 261,660 Consumed vs Generated (kWh Sold vs Generated-Purchased) 88.8% Community Facility kWh Sold 139,944 Line Loss (%)9.0% Other kWh Sold (Non-PCE)243,320 Fuel Efficiency (kWh per Gallon of Diesel)12.96 Total kWh Sold 644,924 PH Consumption as % of Generation 2.2% Powerhouse (PH) Consumption kWh 15,745 Total kWh Sold & PH Consumption 660,669 Comments All Hydro = 1 mth *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 132 of 185 Pedro Bay PCE Utility: PEDRO BAY VILLAGE COUNCIL Reporting Period: 07/01/22 to 06/30/23 Community Population 40 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 42 Community Facility Customers 4 Other Customers (Non-PCE)8 Fiscal Year PCE Payments $27,324 PCE Statistical Data PCE Eligible kWh - Residential Customers 34,004 Average Annual PCE Payment per Eligible Customer $594 PCE Eligible kWh - Community Facility Customers 18,110 Average PCE Payment per Eligible kWh $0.52 Total PCE Eligible kWh 52,114 Last Reported Residential Rate Charged (based on 500 kWh) $0.82 Average Monthly PCE Eligible kWh per Residential Customer 67 Last Reported PCE Level (per kWh)$0.62 Average Monthly PCE Eligible kWh per Community Facility Customer 377 Effective Residential Rate (per kWh)$0.19 Average Monthly PCE Eligible Community Facility kWh per Person 38 PCE Eligible kWh vs Total kWh Sold 29.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 213,201 Fuel Used (Gallons)21,609 Non-Diesel kWh Generated 0 Fuel Cost $115,381 Purchased kWh 0 Average Price of Fuel $5.34 Total Purchased & Generated 213,201 Fuel Cost per kWh sold $0.65 Annual Non-Fuel Expenses $48,748 Non-Fuel Expense per kWh Sold $0.27 Total Expense per kWh Sold $0.92 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 50,566 Consumed vs Generated (kWh Sold vs Generated-Purchased) 83.6% Community Facility kWh Sold 18,110 Line Loss (%)8.7% Other kWh Sold (Non-PCE)109,526 Fuel Efficiency (kWh per Gallon of Diesel)9.87 Total kWh Sold 178,202 PH Consumption as % of Generation 7.7% Powerhouse (PH) Consumption kWh 16,376 Total kWh Sold & PH Consumption 194,578 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 133 of 185 Pelican PCE Utility: PELICAN UTILITY DISTRICT Reporting Period: 07/01/22 to 06/30/23 Community Population 92 Last Reported Month March No. of Monthly Payments Made 9 Residential Customers 73 Community Facility Customers 15 Other Customers (Non-PCE)34 Fiscal Year PCE Payments $21,714 PCE Statistical Data PCE Eligible kWh - Residential Customers 185,421 Average Annual PCE Payment per Eligible Customer $247 PCE Eligible kWh - Community Facility Customers 53,130 Average PCE Payment per Eligible kWh $0.09 Total PCE Eligible kWh 238,551 Last Reported Residential Rate Charged (based on 500 kWh) $0.25 Average Monthly PCE Eligible kWh per Residential Customer 282 Last Reported PCE Level (per kWh)$0.06 Average Monthly PCE Eligible kWh per Community Facility Customer 394 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 64 PCE Eligible kWh vs Total kWh Sold 22.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 474,426 Fuel Used (Gallons)33,994 Non-Diesel kWh Generated 702,422 Fuel Cost $147,578 Purchased kWh 0 Average Price of Fuel $4.34 Total Purchased & Generated 1,176,848 Fuel Cost per kWh sold $0.14 Annual Non-Fuel Expenses $138,560 Non-Fuel Expense per kWh Sold $0.13 Total Expense per kWh Sold $0.27 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 272,767 Consumed vs Generated (kWh Sold vs Generated-Purchased) 88.9% Community Facility kWh Sold 230,769 Line Loss (%)7.4% Other kWh Sold (Non-PCE)542,484 Fuel Efficiency (kWh per Gallon of Diesel)13.96 Total kWh Sold 1,046,020 PH Consumption as % of Generation 3.7% Powerhouse (PH) Consumption kWh 43,887 Total kWh Sold & PH Consumption 1,089,907 Comments 9 rpts filed = 3 x 2mths each. kWh Hydro only x 2 mths, Fuel Used = 7 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 134 of 185 Pilot Point PCE Utility: PILOT POINT ELECTRIC UTILITY Reporting Period: 07/01/22 to 06/30/23 Community Population 59 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 44 Community Facility Customers 9 Other Customers (Non-PCE)23 Fiscal Year PCE Payments $69,709 PCE Statistical Data PCE Eligible kWh - Residential Customers 129,119 Average Annual PCE Payment per Eligible Customer $1,315 PCE Eligible kWh - Community Facility Customers 43,343 Average PCE Payment per Eligible kWh $0.40 Total PCE Eligible kWh 172,462 Last Reported Residential Rate Charged (based on 500 kWh) $0.60 Average Monthly PCE Eligible kWh per Residential Customer 245 Last Reported PCE Level (per kWh)$0.40 Average Monthly PCE Eligible kWh per Community Facility Customer 401 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 61 PCE Eligible kWh vs Total kWh Sold 47.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 465,690 Fuel Used (Gallons)42,215 Non-Diesel kWh Generated 0 Fuel Cost $147,315 Purchased kWh 0 Average Price of Fuel $3.49 Total Purchased & Generated 465,690 Fuel Cost per kWh sold $0.40 Annual Non-Fuel Expenses $193,194 Non-Fuel Expense per kWh Sold $0.53 Total Expense per kWh Sold $0.93 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 146,048 Consumed vs Generated (kWh Sold vs Generated-Purchased) 78.5% Community Facility kWh Sold 55,014 Line Loss (%)16.4% Other kWh Sold (Non-PCE)164,329 Fuel Efficiency (kWh per Gallon of Diesel)11.03 Total kWh Sold 365,391 PH Consumption as % of Generation 5.2% Powerhouse (PH) Consumption kWh 24,055 Total kWh Sold & PH Consumption 389,446 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 135 of 185 Pilot Station PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 609 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 128 Community Facility Customers 12 Other Customers (Non-PCE)29 Fiscal Year PCE Payments $368,803 PCE Statistical Data PCE Eligible kWh - Residential Customers 640,899 Average Annual PCE Payment per Eligible Customer $2,634 PCE Eligible kWh - Community Facility Customers 234,553 Average PCE Payment per Eligible kWh $0.42 Total PCE Eligible kWh 875,452 Last Reported Residential Rate Charged (based on 500 kWh) $0.70 Average Monthly PCE Eligible kWh per Residential Customer 417 Last Reported PCE Level (per kWh)$0.45 Average Monthly PCE Eligible kWh per Community Facility Customer 1,629 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 32 PCE Eligible kWh vs Total kWh Sold 47.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,919,823 Fuel Used (Gallons)88,647 Non-Diesel kWh Generated 0 Fuel Cost $380,891 Purchased kWh 0 Average Price of Fuel $4.30 Total Purchased & Generated 1,919,823 Fuel Cost per kWh sold $0.21 Annual Non-Fuel Expenses $467,993 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.46 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 687,371 Consumed vs Generated (kWh Sold vs Generated-Purchased) 95.5% Community Facility kWh Sold 279,843 Line Loss (%)3.0% Other kWh Sold (Non-PCE)866,026 Fuel Efficiency (kWh per Gallon of Diesel)21.66 Total kWh Sold 1,833,240 PH Consumption as % of Generation 1.5% Powerhouse (PH) Consumption kWh 28,082 Total kWh Sold & PH Consumption 1,861,322 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 136 of 185 Pitkas Point PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 124 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 24 Community Facility Customers 6 Other Customers (Non-PCE)6 Fiscal Year PCE Payments $63,292 PCE Statistical Data PCE Eligible kWh - Residential Customers 142,918 Average Annual PCE Payment per Eligible Customer $2,110 PCE Eligible kWh - Community Facility Customers 93,553 Average PCE Payment per Eligible kWh $0.27 Total PCE Eligible kWh 236,471 Last Reported Residential Rate Charged (based on 500 kWh) $0.58 Average Monthly PCE Eligible kWh per Residential Customer 496 Last Reported PCE Level (per kWh)$0.27 Average Monthly PCE Eligible kWh per Community Facility Customer 1,299 Effective Residential Rate (per kWh)$0.31 Average Monthly PCE Eligible Community Facility kWh per Person 63 PCE Eligible kWh vs Total kWh Sold 68.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $87,693 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.26 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 156,069 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 187,444 Line Loss (%)See Comments Other kWh Sold (Non-PCE)0 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 343,513 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 343,513 Comments Receives power from St. Mary's/Andreafsky via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 137 of 185 Point Hope PCE Utility: NORTH SLOPE BOROUGH Reporting Period: 07/01/22 to 06/30/23 Community Population 879 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 207 Community Facility Customers 2 Other Customers (Non-PCE)79 Fiscal Year PCE Payments $18,340 PCE Statistical Data PCE Eligible kWh - Residential Customers 804,267 Average Annual PCE Payment per Eligible Customer $88 PCE Eligible kWh - Community Facility Customers 58,848 Average PCE Payment per Eligible kWh $0.02 Total PCE Eligible kWh 863,115 Last Reported Residential Rate Charged (based on 500 kWh) $0.35 Average Monthly PCE Eligible kWh per Residential Customer 324 Last Reported PCE Level (per kWh)$0.15 Average Monthly PCE Eligible kWh per Community Facility Customer 2,452 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 6 PCE Eligible kWh vs Total kWh Sold 15.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 6,910,038 Fuel Used (Gallons)524,526 Non-Diesel kWh Generated 0 Fuel Cost $1,682,529 Purchased kWh 0 Average Price of Fuel $3.21 Total Purchased & Generated 6,910,038 Fuel Cost per kWh sold $0.30 Annual Non-Fuel Expenses $1,301,415 Non-Fuel Expense per kWh Sold $0.23 Total Expense per kWh Sold $0.53 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,906,801 Consumed vs Generated (kWh Sold vs Generated-Purchased) 81.6% Community Facility kWh Sold 58,848 Line Loss (%)14.5% Other kWh Sold (Non-PCE)3,674,252 Fuel Efficiency (kWh per Gallon of Diesel)13.17 Total kWh Sold 5,639,901 PH Consumption as % of Generation 3.8% Powerhouse (PH) Consumption kWh 264,908 Total kWh Sold & PH Consumption 5,904,809 Comments Residential PCE Level = Zero *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 138 of 185 Point Lay PCE Utility: NORTH SLOPE BOROUGH Reporting Period: 07/01/22 to 06/30/23 Community Population 308 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 65 Community Facility Customers 1 Other Customers (Non-PCE)44 Fiscal Year PCE Payments $5,622 PCE Statistical Data PCE Eligible kWh - Residential Customers 236,138 Average Annual PCE Payment per Eligible Customer $85 PCE Eligible kWh - Community Facility Customers 32,548 Average PCE Payment per Eligible kWh $0.02 Total PCE Eligible kWh 268,686 Last Reported Residential Rate Charged (based on 500 kWh) $0.35 Average Monthly PCE Eligible kWh per Residential Customer 303 Last Reported PCE Level (per kWh)$0.15 Average Monthly PCE Eligible kWh per Community Facility Customer 2,712 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 9 PCE Eligible kWh vs Total kWh Sold 8.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 3,506,418 Fuel Used (Gallons)277,993 Non-Diesel kWh Generated 0 Fuel Cost $899,676 Purchased kWh 0 Average Price of Fuel $3.24 Total Purchased & Generated 3,506,418 Fuel Cost per kWh sold $0.30 Annual Non-Fuel Expenses $905,205 Non-Fuel Expense per kWh Sold $0.30 Total Expense per kWh Sold $0.60 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 587,983 Consumed vs Generated (kWh Sold vs Generated-Purchased) 86.2% Community Facility kWh Sold 32,548 Line Loss (%)13.2% Other kWh Sold (Non-PCE)2,400,348 Fuel Efficiency (kWh per Gallon of Diesel)12.61 Total kWh Sold 3,020,879 PH Consumption as % of Generation 0.6% Powerhouse (PH) Consumption kWh 21,003 Total kWh Sold & PH Consumption 3,041,882 Comments Residential PCE Level = Zero Phouse kWh Gen = 11 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 139 of 185 Port Alsworth PCE Utility: TANALIAN ELECTRIC COOPERATIVE Reporting Period: 07/01/22 to 06/30/23 Community Population 181 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 82 Community Facility Customers 0 Other Customers (Non-PCE)74 Fiscal Year PCE Payments $179,270 PCE Statistical Data PCE Eligible kWh - Residential Customers 298,500 Average Annual PCE Payment per Eligible Customer $2,186 PCE Eligible kWh - Community Facility Customers 0 Average PCE Payment per Eligible kWh $0.60 Total PCE Eligible kWh 298,500 Last Reported Residential Rate Charged (based on 500 kWh) $0.83 Average Monthly PCE Eligible kWh per Residential Customer 303 Last Reported PCE Level (per kWh)$0.62 Average Monthly PCE Eligible kWh per Community Facility Customer 0 Effective Residential Rate (per kWh)$0.21 Average Monthly PCE Eligible Community Facility kWh per Person 0 PCE Eligible kWh vs Total kWh Sold 33.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 963,849 Fuel Used (Gallons)74,587 Non-Diesel kWh Generated 0 Fuel Cost $434,452 Purchased kWh 0 Average Price of Fuel $5.82 Total Purchased & Generated 963,849 Fuel Cost per kWh sold $0.49 Annual Non-Fuel Expenses $307,318 Non-Fuel Expense per kWh Sold $0.35 Total Expense per kWh Sold $0.83 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 334,253 Consumed vs Generated (kWh Sold vs Generated-Purchased) 92.3% Community Facility kWh Sold 0 Line Loss (%)5.3% Other kWh Sold (Non-PCE)555,637 Fuel Efficiency (kWh per Gallon of Diesel)12.92 Total kWh Sold 889,890 PH Consumption as % of Generation 2.4% Powerhouse (PH) Consumption kWh 22,936 Total kWh Sold & PH Consumption 912,826 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 140 of 185 Port Heiden PCE Utility: PORT HEIDEN UTILITIES Reporting Period: 07/01/22 to 06/30/23 Community Population 91 Last Reported Month June No. of Monthly Payments Made 11 Residential Customers 51 Community Facility Customers 8 Other Customers (Non-PCE)34 Fiscal Year PCE Payments $76,383 PCE Statistical Data PCE Eligible kWh - Residential Customers 166,283 Average Annual PCE Payment per Eligible Customer $1,295 PCE Eligible kWh - Community Facility Customers 45,785 Average PCE Payment per Eligible kWh $0.36 Total PCE Eligible kWh 212,068 Last Reported Residential Rate Charged (based on 500 kWh) $9.99 Average Monthly PCE Eligible kWh per Residential Customer 296 Last Reported PCE Level (per kWh)$0.46 Average Monthly PCE Eligible kWh per Community Facility Customer 520 Effective Residential Rate (per kWh)$9.53 Average Monthly PCE Eligible Community Facility kWh per Person 46 PCE Eligible kWh vs Total kWh Sold 40.4% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 850,025 Fuel Used (Gallons)39,258 Non-Diesel kWh Generated 0 Fuel Cost $121,731 Purchased kWh 0 Average Price of Fuel $3.10 Total Purchased & Generated 850,025 Fuel Cost per kWh sold $0.23 Annual Non-Fuel Expenses $33,000 Non-Fuel Expense per kWh Sold $0.06 Total Expense per kWh Sold $0.29 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 184,579 Consumed vs Generated (kWh Sold vs Generated-Purchased) 61.8% Community Facility kWh Sold 48,781 Line Loss (%)36.4% Other kWh Sold (Non-PCE)291,856 Fuel Efficiency (kWh per Gallon of Diesel)21.65 Total kWh Sold 525,216 PH Consumption as % of Generation 1.8% Powerhouse (PH) Consumption kWh 15,346 Total kWh Sold & PH Consumption 540,562 Comments 11 Rpts Filed, Diesel kWh Gen & PHouse Consm = 4 mths, Fuel Used = 4 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 141 of 185 Quinhagak PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 744 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 172 Community Facility Customers 14 Other Customers (Non-PCE)40 Fiscal Year PCE Payments $397,268 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,013,432 Average Annual PCE Payment per Eligible Customer $2,136 PCE Eligible kWh - Community Facility Customers 360,564 Average PCE Payment per Eligible kWh $0.29 Total PCE Eligible kWh 1,373,996 Last Reported Residential Rate Charged (based on 500 kWh) $0.62 Average Monthly PCE Eligible kWh per Residential Customer 491 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 2,146 Effective Residential Rate (per kWh)$0.28 Average Monthly PCE Eligible Community Facility kWh per Person 40 PCE Eligible kWh vs Total kWh Sold 59.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,829,146 Fuel Used (Gallons)132,971 Non-Diesel kWh Generated 631,937 Fuel Cost $479,174 Purchased kWh 0 Average Price of Fuel $3.60 Total Purchased & Generated 2,461,083 Fuel Cost per kWh sold $0.21 Annual Non-Fuel Expenses $586,453 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.46 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,111,053 Consumed vs Generated (kWh Sold vs Generated-Purchased) 93.3% Community Facility kWh Sold 507,144 Line Loss (%)4.3% Other kWh Sold (Non-PCE)679,078 Fuel Efficiency (kWh per Gallon of Diesel)13.76 Total kWh Sold 2,297,275 PH Consumption as % of Generation 2.3% Powerhouse (PH) Consumption kWh 57,788 Total kWh Sold & PH Consumption 2,355,063 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 142 of 185 Rampart PCE Utility: RAMPART VILLAGE COUNCIL Reporting Period: 07/01/22 to 06/30/23 Community Population 62 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 35 Community Facility Customers 7 Other Customers (Non-PCE)7 Fiscal Year PCE Payments $76,354 PCE Statistical Data PCE Eligible kWh - Residential Customers 76,654 Average Annual PCE Payment per Eligible Customer $1,818 PCE Eligible kWh - Community Facility Customers 49,263 Average PCE Payment per Eligible kWh $0.61 Total PCE Eligible kWh 125,917 Last Reported Residential Rate Charged (based on 500 kWh) $0.81 Average Monthly PCE Eligible kWh per Residential Customer 183 Last Reported PCE Level (per kWh)$0.62 Average Monthly PCE Eligible kWh per Community Facility Customer 586 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 66 PCE Eligible kWh vs Total kWh Sold 59.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 263,645 Fuel Used (Gallons)25,074 Non-Diesel kWh Generated 0 Fuel Cost $153,386 Purchased kWh 0 Average Price of Fuel $6.12 Total Purchased & Generated 263,645 Fuel Cost per kWh sold $0.72 Annual Non-Fuel Expenses $54,310 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.98 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 81,634 Consumed vs Generated (kWh Sold vs Generated-Purchased) 80.5% Community Facility kWh Sold 74,292 Line Loss (%)6.3% Other kWh Sold (Non-PCE)56,251 Fuel Efficiency (kWh per Gallon of Diesel)10.51 Total kWh Sold 212,177 PH Consumption as % of Generation 13.2% Powerhouse (PH) Consumption kWh 34,822 Total kWh Sold & PH Consumption 246,999 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 143 of 185 Red Devil PCE Utility: MIDDLE KUSKOKWIM ELECTRIC COOPERATIVE INC Reporting Period: 07/01/22 to 06/30/23 Community Population 23 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 11 Community Facility Customers 0 Other Customers (Non-PCE)6 Fiscal Year PCE Payments $20,824 PCE Statistical Data PCE Eligible kWh - Residential Customers 27,257 Average Annual PCE Payment per Eligible Customer $1,893 PCE Eligible kWh - Community Facility Customers 0 Average PCE Payment per Eligible kWh $0.76 Total PCE Eligible kWh 27,257 Last Reported Residential Rate Charged (based on 500 kWh) $1.43 Average Monthly PCE Eligible kWh per Residential Customer 206 Last Reported PCE Level (per kWh)$0.76 Average Monthly PCE Eligible kWh per Community Facility Customer 0 Effective Residential Rate (per kWh)$0.67 Average Monthly PCE Eligible Community Facility kWh per Person 0 PCE Eligible kWh vs Total kWh Sold 60.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 51,342 Fuel Used (Gallons)9,007 Non-Diesel kWh Generated 0 Fuel Cost $33,032 Purchased kWh 0 Average Price of Fuel $3.67 Total Purchased & Generated 51,342 Fuel Cost per kWh sold $0.74 Annual Non-Fuel Expenses $105,176 Non-Fuel Expense per kWh Sold $2.35 Total Expense per kWh Sold $3.09 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 27,571 Consumed vs Generated (kWh Sold vs Generated-Purchased) 87.2% Community Facility kWh Sold 0 Line Loss (%)8.3% Other kWh Sold (Non-PCE)17,220 Fuel Efficiency (kWh per Gallon of Diesel)5.70 Total kWh Sold 44,791 PH Consumption as % of Generation 4.4% Powerhouse (PH) Consumption kWh 2,281 Total kWh Sold & PH Consumption 47,072 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 144 of 185 Ruby PCE Utility: CITY OF RUBY Reporting Period: 07/01/22 to 06/30/23 Community Population 141 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 98 Community Facility Customers 13 Other Customers (Non-PCE)27 Fiscal Year PCE Payments $153,884 PCE Statistical Data PCE Eligible kWh - Residential Customers 254,820 Average Annual PCE Payment per Eligible Customer $1,386 PCE Eligible kWh - Community Facility Customers 82,500 Average PCE Payment per Eligible kWh $0.46 Total PCE Eligible kWh 337,320 Last Reported Residential Rate Charged (based on 500 kWh) $0.75 Average Monthly PCE Eligible kWh per Residential Customer 217 Last Reported PCE Level (per kWh)$0.55 Average Monthly PCE Eligible kWh per Community Facility Customer 529 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 49 PCE Eligible kWh vs Total kWh Sold 50.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 665,590 Fuel Used (Gallons)51,859 Non-Diesel kWh Generated 0 Fuel Cost $289,707 Purchased kWh 0 Average Price of Fuel $5.59 Total Purchased & Generated 665,590 Fuel Cost per kWh sold $0.43 Annual Non-Fuel Expenses $133,124 Non-Fuel Expense per kWh Sold $0.20 Total Expense per kWh Sold $0.63 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 267,330 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 82,852 Line Loss (%)See Comments Other kWh Sold (Non-PCE)316,371 Fuel Efficiency (kWh per Gallon of Diesel)12.83 Total kWh Sold 666,553 PH Consumption as % of Generation 3.9% Powerhouse (PH) Consumption kWh 26,095 Total kWh Sold & PH Consumption 692,648 Comments Non Fuel Expenses = 7 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 145 of 185 Russian Mission PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 420 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 79 Community Facility Customers 7 Other Customers (Non-PCE)16 Fiscal Year PCE Payments $172,596 PCE Statistical Data PCE Eligible kWh - Residential Customers 382,073 Average Annual PCE Payment per Eligible Customer $2,007 PCE Eligible kWh - Community Facility Customers 64,682 Average PCE Payment per Eligible kWh $0.39 Total PCE Eligible kWh 446,755 Last Reported Residential Rate Charged (based on 500 kWh) $0.66 Average Monthly PCE Eligible kWh per Residential Customer 403 Last Reported PCE Level (per kWh)$0.41 Average Monthly PCE Eligible kWh per Community Facility Customer 770 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 13 PCE Eligible kWh vs Total kWh Sold 48.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 977,336 Fuel Used (Gallons)54,496 Non-Diesel kWh Generated 0 Fuel Cost $223,526 Purchased kWh 0 Average Price of Fuel $4.10 Total Purchased & Generated 977,336 Fuel Cost per kWh sold $0.24 Annual Non-Fuel Expenses $234,545 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.50 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 397,114 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.0% Community Facility kWh Sold 101,157 Line Loss (%)3.8% Other kWh Sold (Non-PCE)420,497 Fuel Efficiency (kWh per Gallon of Diesel)17.93 Total kWh Sold 918,768 PH Consumption as % of Generation 2.1% Powerhouse (PH) Consumption kWh 21,008 Total kWh Sold & PH Consumption 939,776 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 146 of 185 Sand Point PCE Utility: TDX CORPORATION Reporting Period: 07/01/22 to 06/30/23 Community Population 648 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 242 Community Facility Customers 27 Other Customers (Non-PCE)112 Fiscal Year PCE Payments $740,237 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,091,410 Average Annual PCE Payment per Eligible Customer $2,752 PCE Eligible kWh - Community Facility Customers 544,320 Average PCE Payment per Eligible kWh $0.45 Total PCE Eligible kWh 1,635,730 Last Reported Residential Rate Charged (based on 500 kWh) $0.57 Average Monthly PCE Eligible kWh per Residential Customer 376 Last Reported PCE Level (per kWh)$0.34 Average Monthly PCE Eligible kWh per Community Facility Customer 1,680 Effective Residential Rate (per kWh)$0.23 Average Monthly PCE Eligible Community Facility kWh per Person 70 PCE Eligible kWh vs Total kWh Sold 49.4% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 3,113,670 Fuel Used (Gallons)223,865 Non-Diesel kWh Generated 0 Fuel Cost $1,101,457 Purchased kWh 594,170 Average Price of Fuel $4.92 Total Purchased & Generated 3,707,840 Fuel Cost per kWh sold $0.33 Annual Non-Fuel Expenses $1,164,128 Non-Fuel Expense per kWh Sold $0.35 Total Expense per kWh Sold $0.68 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,234,615 Consumed vs Generated (kWh Sold vs Generated-Purchased) 89.4% Community Facility kWh Sold 692,953 Line Loss (%)7.9% Other kWh Sold (Non-PCE)1,385,420 Fuel Efficiency (kWh per Gallon of Diesel)13.91 Total kWh Sold 3,312,988 PH Consumption as % of Generation 2.7% Powerhouse (PH) Consumption kWh 100,824 Total kWh Sold & PH Consumption 3,413,812 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 147 of 185 Savoonga PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 810 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 161 Community Facility Customers 10 Other Customers (Non-PCE)55 Fiscal Year PCE Payments $425,155 PCE Statistical Data PCE Eligible kWh - Residential Customers 917,167 Average Annual PCE Payment per Eligible Customer $2,486 PCE Eligible kWh - Community Facility Customers 262,967 Average PCE Payment per Eligible kWh $0.36 Total PCE Eligible kWh 1,180,134 Last Reported Residential Rate Charged (based on 500 kWh) $0.68 Average Monthly PCE Eligible kWh per Residential Customer 475 Last Reported PCE Level (per kWh)$0.43 Average Monthly PCE Eligible kWh per Community Facility Customer 2,191 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 27 PCE Eligible kWh vs Total kWh Sold 48.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,459,748 Fuel Used (Gallons)185,776 Non-Diesel kWh Generated 6,909 Fuel Cost $743,568 Purchased kWh 0 Average Price of Fuel $4.00 Total Purchased & Generated 2,466,657 Fuel Cost per kWh sold $0.31 Annual Non-Fuel Expenses $616,004 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.56 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,035,361 Consumed vs Generated (kWh Sold vs Generated-Purchased) 97.8% Community Facility kWh Sold 654,392 Line Loss (%)0.8% Other kWh Sold (Non-PCE)723,280 Fuel Efficiency (kWh per Gallon of Diesel)13.24 Total kWh Sold 2,413,033 PH Consumption as % of Generation 1.4% Powerhouse (PH) Consumption kWh 34,968 Total kWh Sold & PH Consumption 2,448,001 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 148 of 185 Scammon Bay PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 577 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 124 Community Facility Customers 8 Other Customers (Non-PCE)46 Fiscal Year PCE Payments $327,360 PCE Statistical Data PCE Eligible kWh - Residential Customers 659,651 Average Annual PCE Payment per Eligible Customer $2,480 PCE Eligible kWh - Community Facility Customers 219,596 Average PCE Payment per Eligible kWh $0.37 Total PCE Eligible kWh 879,247 Last Reported Residential Rate Charged (based on 500 kWh) $0.68 Average Monthly PCE Eligible kWh per Residential Customer 443 Last Reported PCE Level (per kWh)$0.42 Average Monthly PCE Eligible kWh per Community Facility Customer 2,287 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 32 PCE Eligible kWh vs Total kWh Sold 49.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,936,588 Fuel Used (Gallons)124,805 Non-Diesel kWh Generated 0 Fuel Cost $508,172 Purchased kWh 0 Average Price of Fuel $4.07 Total Purchased & Generated 1,936,588 Fuel Cost per kWh sold $0.28 Annual Non-Fuel Expenses $456,009 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.54 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 695,885 Consumed vs Generated (kWh Sold vs Generated-Purchased) 92.2% Community Facility kWh Sold 349,318 Line Loss (%)4.3% Other kWh Sold (Non-PCE)741,093 Fuel Efficiency (kWh per Gallon of Diesel)15.52 Total kWh Sold 1,786,296 PH Consumption as % of Generation 3.5% Powerhouse (PH) Consumption kWh 67,124 Total kWh Sold & PH Consumption 1,853,420 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 149 of 185 Selawik PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 780 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 160 Community Facility Customers 14 Other Customers (Non-PCE)46 Fiscal Year PCE Payments $496,086 PCE Statistical Data PCE Eligible kWh - Residential Customers 966,998 Average Annual PCE Payment per Eligible Customer $2,851 PCE Eligible kWh - Community Facility Customers 513,951 Average PCE Payment per Eligible kWh $0.33 Total PCE Eligible kWh 1,480,949 Last Reported Residential Rate Charged (based on 500 kWh) $0.67 Average Monthly PCE Eligible kWh per Residential Customer 504 Last Reported PCE Level (per kWh)$0.42 Average Monthly PCE Eligible kWh per Community Facility Customer 3,059 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 55 PCE Eligible kWh vs Total kWh Sold 54.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 2,840,861 Fuel Used (Gallons)191,747 Non-Diesel kWh Generated 0 Fuel Cost $770,192 Purchased kWh 0 Average Price of Fuel $4.02 Total Purchased & Generated 2,840,861 Fuel Cost per kWh sold $0.28 Annual Non-Fuel Expenses $691,363 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.54 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,153,739 Consumed vs Generated (kWh Sold vs Generated-Purchased) 95.3% Community Facility kWh Sold 711,528 Line Loss (%)3.5% Other kWh Sold (Non-PCE)842,964 Fuel Efficiency (kWh per Gallon of Diesel)14.82 Total kWh Sold 2,708,231 PH Consumption as % of Generation 1.2% Powerhouse (PH) Consumption kWh 32,775 Total kWh Sold & PH Consumption 2,741,006 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 150 of 185 Shageluk PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 100 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 38 Community Facility Customers 8 Other Customers (Non-PCE)17 Fiscal Year PCE Payments $90,307 PCE Statistical Data PCE Eligible kWh - Residential Customers 138,011 Average Annual PCE Payment per Eligible Customer $1,963 PCE Eligible kWh - Community Facility Customers 70,626 Average PCE Payment per Eligible kWh $0.43 Total PCE Eligible kWh 208,637 Last Reported Residential Rate Charged (based on 500 kWh) $0.68 Average Monthly PCE Eligible kWh per Residential Customer 303 Last Reported PCE Level (per kWh)$0.43 Average Monthly PCE Eligible kWh per Community Facility Customer 736 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 59 PCE Eligible kWh vs Total kWh Sold 44.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 506,982 Fuel Used (Gallons)31,450 Non-Diesel kWh Generated 0 Fuel Cost $145,041 Purchased kWh 0 Average Price of Fuel $4.61 Total Purchased & Generated 506,982 Fuel Cost per kWh sold $0.31 Annual Non-Fuel Expenses $119,559 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.56 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 151,076 Consumed vs Generated (kWh Sold vs Generated-Purchased) 92.4% Community Facility kWh Sold 136,223 Line Loss (%)5.3% Other kWh Sold (Non-PCE)181,040 Fuel Efficiency (kWh per Gallon of Diesel)16.12 Total kWh Sold 468,339 PH Consumption as % of Generation 2.3% Powerhouse (PH) Consumption kWh 11,677 Total kWh Sold & PH Consumption 480,016 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 151 of 185 Shaktoolik PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 214 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 66 Community Facility Customers 4 Other Customers (Non-PCE)34 Fiscal Year PCE Payments $160,151 PCE Statistical Data PCE Eligible kWh - Residential Customers 421,654 Average Annual PCE Payment per Eligible Customer $2,288 PCE Eligible kWh - Community Facility Customers 78,502 Average PCE Payment per Eligible kWh $0.32 Total PCE Eligible kWh 500,156 Last Reported Residential Rate Charged (based on 500 kWh) $0.66 Average Monthly PCE Eligible kWh per Residential Customer 532 Last Reported PCE Level (per kWh)$0.39 Average Monthly PCE Eligible kWh per Community Facility Customer 1,635 Effective Residential Rate (per kWh)$0.27 Average Monthly PCE Eligible Community Facility kWh per Person 31 PCE Eligible kWh vs Total kWh Sold 48.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 903,611 Fuel Used (Gallons)54,822 Non-Diesel kWh Generated 210,702 Fuel Cost $213,722 Purchased kWh 0 Average Price of Fuel $3.90 Total Purchased & Generated 1,114,313 Fuel Cost per kWh sold $0.21 Annual Non-Fuel Expenses $265,452 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.46 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 484,782 Consumed vs Generated (kWh Sold vs Generated-Purchased) 93.3% Community Facility kWh Sold 180,678 Line Loss (%)3.5% Other kWh Sold (Non-PCE)374,378 Fuel Efficiency (kWh per Gallon of Diesel)16.48 Total kWh Sold 1,039,838 PH Consumption as % of Generation 3.1% Powerhouse (PH) Consumption kWh 35,065 Total kWh Sold & PH Consumption 1,074,903 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 152 of 185 Shishmaref PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 581 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 153 Community Facility Customers 9 Other Customers (Non-PCE)47 Fiscal Year PCE Payments $315,780 PCE Statistical Data PCE Eligible kWh - Residential Customers 737,492 Average Annual PCE Payment per Eligible Customer $1,949 PCE Eligible kWh - Community Facility Customers 107,888 Average PCE Payment per Eligible kWh $0.37 Total PCE Eligible kWh 845,380 Last Reported Residential Rate Charged (based on 500 kWh) $0.70 Average Monthly PCE Eligible kWh per Residential Customer 402 Last Reported PCE Level (per kWh)$0.44 Average Monthly PCE Eligible kWh per Community Facility Customer 999 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 15 PCE Eligible kWh vs Total kWh Sold 48.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,810,600 Fuel Used (Gallons)146,956 Non-Diesel kWh Generated 0 Fuel Cost $485,296 Purchased kWh 0 Average Price of Fuel $3.30 Total Purchased & Generated 1,810,600 Fuel Cost per kWh sold $0.28 Annual Non-Fuel Expenses $448,987 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.53 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 774,981 Consumed vs Generated (kWh Sold vs Generated-Purchased) 97.1% Community Facility kWh Sold 345,531 Line Loss (%)See Comments Other kWh Sold (Non-PCE)638,275 Fuel Efficiency (kWh per Gallon of Diesel)12.32 Total kWh Sold 1,758,787 PH Consumption as % of Generation 3.7% Powerhouse (PH) Consumption kWh 66,464 Total kWh Sold & PH Consumption 1,825,251 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 153 of 185 Shungnak PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 244 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 56 Community Facility Customers 9 Other Customers (Non-PCE)21 Fiscal Year PCE Payments $360,325 PCE Statistical Data PCE Eligible kWh - Residential Customers 344,081 Average Annual PCE Payment per Eligible Customer $5,543 PCE Eligible kWh - Community Facility Customers 153,476 Average PCE Payment per Eligible kWh $0.72 Total PCE Eligible kWh 497,557 Last Reported Residential Rate Charged (based on 500 kWh) $0.10 Average Monthly PCE Eligible kWh per Residential Customer 512 Last Reported PCE Level (per kWh)$0.77 Average Monthly PCE Eligible kWh per Community Facility Customer 1,421 Effective Residential Rate (per kWh)($0.67) Average Monthly PCE Eligible Community Facility kWh per Person 52 PCE Eligible kWh vs Total kWh Sold 53.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,521,425 Fuel Used (Gallons)117,876 Non-Diesel kWh Generated 193,423 Fuel Cost $1,074,345 Purchased kWh 0 Average Price of Fuel $9.11 Total Purchased & Generated 1,714,848 Fuel Cost per kWh sold $1.15 Annual Non-Fuel Expenses $238,500 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $1.41 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 410,378 Consumed vs Generated (kWh Sold vs Generated-Purchased) 54.5% Community Facility kWh Sold 219,997 Line Loss (%)41.4% Other kWh Sold (Non-PCE)303,884 Fuel Efficiency (kWh per Gallon of Diesel)12.91 Total kWh Sold 934,259 PH Consumption as % of Generation 4.1% Powerhouse (PH) Consumption kWh 70,960 Total kWh Sold & PH Consumption 1,005,219 Comments Provides power to Kobuk via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 154 of 185 Skagway PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 1,203 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 625 Community Facility Customers 41 Other Customers (Non-PCE)649 Fiscal Year PCE Payments $151,990 PCE Statistical Data PCE Eligible kWh - Residential Customers 2,263,672 Average Annual PCE Payment per Eligible Customer $228 PCE Eligible kWh - Community Facility Customers 742,128 Average PCE Payment per Eligible kWh $0.05 Total PCE Eligible kWh 3,005,800 Last Reported Residential Rate Charged (based on 500 kWh) $0.30 Average Monthly PCE Eligible kWh per Residential Customer 302 Last Reported PCE Level (per kWh)$0.06 Average Monthly PCE Eligible kWh per Community Facility Customer 1,508 Effective Residential Rate (per kWh)$0.24 Average Monthly PCE Eligible Community Facility kWh per Person 51 PCE Eligible kWh vs Total kWh Sold 23.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,918,746 Fuel Used (Gallons)137,138 Non-Diesel kWh Generated 2,532,010 Fuel Cost $641,076 Purchased kWh 9,284,936 Average Price of Fuel $4.67 Total Purchased & Generated 13,735,692 Fuel Cost per kWh sold $0.05 Annual Non-Fuel Expenses $1,523,944 Non-Fuel Expense per kWh Sold $0.12 Total Expense per kWh Sold $0.17 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 3,136,904 Consumed vs Generated (kWh Sold vs Generated-Purchased) 92.0% Community Facility kWh Sold 818,107 Line Loss (%)6.5% Other kWh Sold (Non-PCE)8,677,815 Fuel Efficiency (kWh per Gallon of Diesel)13.99 Total kWh Sold 12,632,826 PH Consumption as % of Generation 1.6% Powerhouse (PH) Consumption kWh 213,163 Total kWh Sold & PH Consumption 12,845,989 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 155 of 185 Slana PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 105 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 75 Community Facility Customers 1 Other Customers (Non-PCE)17 Fiscal Year PCE Payments $114,534 PCE Statistical Data PCE Eligible kWh - Residential Customers 245,719 Average Annual PCE Payment per Eligible Customer $1,507 PCE Eligible kWh - Community Facility Customers 2,584 Average PCE Payment per Eligible kWh $0.46 Total PCE Eligible kWh 248,303 Last Reported Residential Rate Charged (based on 500 kWh) $0.66 Average Monthly PCE Eligible kWh per Residential Customer 273 Last Reported PCE Level (per kWh)$0.36 Average Monthly PCE Eligible kWh per Community Facility Customer 215 Effective Residential Rate (per kWh)$0.30 Average Monthly PCE Eligible Community Facility kWh per Person 2 PCE Eligible kWh vs Total kWh Sold 53.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,416,887 Fuel Used (Gallons)100,615 Non-Diesel kWh Generated 0 Fuel Cost $387,754 Purchased kWh 0 Average Price of Fuel $3.85 Total Purchased & Generated 1,416,887 Fuel Cost per kWh sold $0.84 Annual Non-Fuel Expenses $173,946 Non-Fuel Expense per kWh Sold $0.38 Total Expense per kWh Sold $1.21 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 268,768 Consumed vs Generated (kWh Sold vs Generated-Purchased) 32.7% Community Facility kWh Sold 2,584 Line Loss (%)65.9% Other kWh Sold (Non-PCE)191,295 Fuel Efficiency (kWh per Gallon of Diesel)14.08 Total kWh Sold 462,647 PH Consumption as % of Generation 1.5% Powerhouse (PH) Consumption kWh 21,083 Total kWh Sold & PH Consumption 483,730 Comments Provides power to Chistochina & Mentasta *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 156 of 185 Sleetmute PCE Utility: MIDDLE KUSKOKWIM ELECTRIC COOPERATIVE INC Reporting Period: 07/01/22 to 06/30/23 Community Population 89 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 32 Community Facility Customers 7 Other Customers (Non-PCE)9 Fiscal Year PCE Payments $114,355 PCE Statistical Data PCE Eligible kWh - Residential Customers 97,136 Average Annual PCE Payment per Eligible Customer $2,932 PCE Eligible kWh - Community Facility Customers 52,543 Average PCE Payment per Eligible kWh $0.76 Total PCE Eligible kWh 149,679 Last Reported Residential Rate Charged (based on 500 kWh) $1.43 Average Monthly PCE Eligible kWh per Residential Customer 253 Last Reported PCE Level (per kWh)$0.76 Average Monthly PCE Eligible kWh per Community Facility Customer 626 Effective Residential Rate (per kWh)$0.67 Average Monthly PCE Eligible Community Facility kWh per Person 49 PCE Eligible kWh vs Total kWh Sold 54.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 310,979 Fuel Used (Gallons)26,978 Non-Diesel kWh Generated 0 Fuel Cost $101,644 Purchased kWh 0 Average Price of Fuel $3.77 Total Purchased & Generated 310,979 Fuel Cost per kWh sold $0.37 Annual Non-Fuel Expenses $152,451 Non-Fuel Expense per kWh Sold $0.55 Total Expense per kWh Sold $0.92 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 108,203 Consumed vs Generated (kWh Sold vs Generated-Purchased) 89.2% Community Facility kWh Sold 73,026 Line Loss (%)6.1% Other kWh Sold (Non-PCE)96,023 Fuel Efficiency (kWh per Gallon of Diesel)11.53 Total kWh Sold 277,252 PH Consumption as % of Generation 4.8% Powerhouse (PH) Consumption kWh 14,897 Total kWh Sold & PH Consumption 292,149 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 157 of 185 St. George PCE Utility: CITY OF ST. GEORGE Reporting Period: 07/01/22 to 06/30/23 Community Population 68 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 40 Community Facility Customers 7 Other Customers (Non-PCE)30 Fiscal Year PCE Payments $98,374 PCE Statistical Data PCE Eligible kWh - Residential Customers 74,895 Average Annual PCE Payment per Eligible Customer $2,093 PCE Eligible kWh - Community Facility Customers 53,898 Average PCE Payment per Eligible kWh $0.76 Total PCE Eligible kWh 128,793 Last Reported Residential Rate Charged (based on 500 kWh) $1.00 Average Monthly PCE Eligible kWh per Residential Customer 156 Last Reported PCE Level (per kWh)$0.76 Average Monthly PCE Eligible kWh per Community Facility Customer 642 Effective Residential Rate (per kWh)$0.24 Average Monthly PCE Eligible Community Facility kWh per Person 66 PCE Eligible kWh vs Total kWh Sold 35.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 517,237 Fuel Used (Gallons)42,092 Non-Diesel kWh Generated 0 Fuel Cost $376,391 Purchased kWh 0 Average Price of Fuel $8.94 Total Purchased & Generated 517,237 Fuel Cost per kWh sold $1.02 Annual Non-Fuel Expenses $36,000 Non-Fuel Expense per kWh Sold $0.10 Total Expense per kWh Sold $1.12 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 92,879 Consumed vs Generated (kWh Sold vs Generated-Purchased) 71.2% Community Facility kWh Sold 83,168 Line Loss (%)22.9% Other kWh Sold (Non-PCE)192,055 Fuel Efficiency (kWh per Gallon of Diesel)12.29 Total kWh Sold 368,102 PH Consumption as % of Generation 5.9% Powerhouse (PH) Consumption kWh 30,634 Total kWh Sold & PH Consumption 398,736 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 158 of 185 St. Mary's PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 593 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 171 Community Facility Customers 17 Other Customers (Non-PCE)66 Fiscal Year PCE Payments $333,968 PCE Statistical Data PCE Eligible kWh - Residential Customers 805,140 Average Annual PCE Payment per Eligible Customer $1,776 PCE Eligible kWh - Community Facility Customers 448,139 Average PCE Payment per Eligible kWh $0.27 Total PCE Eligible kWh 1,253,279 Last Reported Residential Rate Charged (based on 500 kWh) $0.58 Average Monthly PCE Eligible kWh per Residential Customer 392 Last Reported PCE Level (per kWh)$0.27 Average Monthly PCE Eligible kWh per Community Facility Customer 2,197 Effective Residential Rate (per kWh)$0.31 Average Monthly PCE Eligible Community Facility kWh per Person 63 PCE Eligible kWh vs Total kWh Sold 45.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 3,834,671 Fuel Used (Gallons)512,751 Non-Diesel kWh Generated 2,373,829 Fuel Cost $1,898,327 Purchased kWh 0 Average Price of Fuel $3.70 Total Purchased & Generated 6,208,500 Fuel Cost per kWh sold $0.69 Annual Non-Fuel Expenses $703,111 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.94 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 878,293 Consumed vs Generated (kWh Sold vs Generated-Purchased) 44.4% Community Facility kWh Sold 752,188 Line Loss (%)49.9% Other kWh Sold (Non-PCE)1,123,769 Fuel Efficiency (kWh per Gallon of Diesel)7.48 Total kWh Sold 2,754,250 PH Consumption as % of Generation 5.7% Powerhouse (PH) Consumption kWh 356,763 Total kWh Sold & PH Consumption 3,111,013 Comments Provides power to Pitkas Point via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 159 of 185 St. Michael PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 450 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 86 Community Facility Customers 9 Other Customers (Non-PCE)40 Fiscal Year PCE Payments $250,121 PCE Statistical Data PCE Eligible kWh - Residential Customers 516,967 Average Annual PCE Payment per Eligible Customer $2,633 PCE Eligible kWh - Community Facility Customers 299,840 Average PCE Payment per Eligible kWh $0.31 Total PCE Eligible kWh 816,807 Last Reported Residential Rate Charged (based on 500 kWh) $0.63 Average Monthly PCE Eligible kWh per Residential Customer 501 Last Reported PCE Level (per kWh)$0.38 Average Monthly PCE Eligible kWh per Community Facility Customer 2,776 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 56 PCE Eligible kWh vs Total kWh Sold 43.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $484,199 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.26 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 617,794 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 662,280 Line Loss (%)See Comments Other kWh Sold (Non-PCE)616,647 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 1,896,721 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 1,896,721 Comments Receives power from Stebbins via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 160 of 185 St. Paul PCE Utility: ST. PAUL MUNICIPAL ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 391 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 124 Community Facility Customers 21 Other Customers (Non-PCE)76 Fiscal Year PCE Payments $361,661 PCE Statistical Data PCE Eligible kWh - Residential Customers 596,056 Average Annual PCE Payment per Eligible Customer $2,494 PCE Eligible kWh - Community Facility Customers 322,397 Average PCE Payment per Eligible kWh $0.39 Total PCE Eligible kWh 918,453 Last Reported Residential Rate Charged (based on 500 kWh) $0.57 Average Monthly PCE Eligible kWh per Residential Customer 401 Last Reported PCE Level (per kWh)$0.37 Average Monthly PCE Eligible kWh per Community Facility Customer 1,279 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 69 PCE Eligible kWh vs Total kWh Sold 33.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 3,201,582 Fuel Used (Gallons)237,594 Non-Diesel kWh Generated 0 Fuel Cost $1,116,776 Purchased kWh 0 Average Price of Fuel $4.70 Total Purchased & Generated 3,201,582 Fuel Cost per kWh sold $0.40 Annual Non-Fuel Expenses $613,237 Non-Fuel Expense per kWh Sold $0.22 Total Expense per kWh Sold $0.62 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 624,117 Consumed vs Generated (kWh Sold vs Generated-Purchased) 86.6% Community Facility kWh Sold 340,732 Line Loss (%)9.7% Other kWh Sold (Non-PCE)1,806,735 Fuel Efficiency (kWh per Gallon of Diesel)13.48 Total kWh Sold 2,771,584 PH Consumption as % of Generation 3.7% Powerhouse (PH) Consumption kWh 119,421 Total kWh Sold & PH Consumption 2,891,005 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 161 of 185 Stebbins PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 622 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 141 Community Facility Customers 11 Other Customers (Non-PCE)40 Fiscal Year PCE Payments $254,475 PCE Statistical Data PCE Eligible kWh - Residential Customers 695,642 Average Annual PCE Payment per Eligible Customer $1,674 PCE Eligible kWh - Community Facility Customers 104,291 Average PCE Payment per Eligible kWh $0.32 Total PCE Eligible kWh 799,933 Last Reported Residential Rate Charged (based on 500 kWh) $0.63 Average Monthly PCE Eligible kWh per Residential Customer 411 Last Reported PCE Level (per kWh)$0.38 Average Monthly PCE Eligible kWh per Community Facility Customer 790 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 14 PCE Eligible kWh vs Total kWh Sold 50.2% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 3,680,698 Fuel Used (Gallons)226,347 Non-Diesel kWh Generated 0 Fuel Cost $845,270 Purchased kWh 0 Average Price of Fuel $3.73 Total Purchased & Generated 3,680,698 Fuel Cost per kWh sold $0.53 Annual Non-Fuel Expenses $406,847 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.79 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 758,725 Consumed vs Generated (kWh Sold vs Generated-Purchased) 43.3% Community Facility kWh Sold 374,935 Line Loss (%)54.3% Other kWh Sold (Non-PCE)460,055 Fuel Efficiency (kWh per Gallon of Diesel)16.26 Total kWh Sold 1,593,715 PH Consumption as % of Generation 2.4% Powerhouse (PH) Consumption kWh 87,565 Total kWh Sold & PH Consumption 1,681,280 Comments Provides power to St. Michael via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 162 of 185 Stony River PCE Utility: MIDDLE KUSKOKWIM ELECTRIC COOPERATIVE INC Reporting Period: 07/01/22 to 06/30/23 Community Population 51 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 17 Community Facility Customers 5 Other Customers (Non-PCE)5 Fiscal Year PCE Payments $43,614 PCE Statistical Data PCE Eligible kWh - Residential Customers 36,886 Average Annual PCE Payment per Eligible Customer $1,982 PCE Eligible kWh - Community Facility Customers 20,200 Average PCE Payment per Eligible kWh $0.76 Total PCE Eligible kWh 57,086 Last Reported Residential Rate Charged (based on 500 kWh) $1.43 Average Monthly PCE Eligible kWh per Residential Customer 181 Last Reported PCE Level (per kWh)$0.76 Average Monthly PCE Eligible kWh per Community Facility Customer 337 Effective Residential Rate (per kWh)$0.67 Average Monthly PCE Eligible Community Facility kWh per Person 33 PCE Eligible kWh vs Total kWh Sold 55.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 131,884 Fuel Used (Gallons)19,246 Non-Diesel kWh Generated 0 Fuel Cost $72,597 Purchased kWh 0 Average Price of Fuel $3.77 Total Purchased & Generated 131,884 Fuel Cost per kWh sold $0.70 Annual Non-Fuel Expenses $134,463 Non-Fuel Expense per kWh Sold $1.30 Total Expense per kWh Sold $2.01 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 37,444 Consumed vs Generated (kWh Sold vs Generated-Purchased) 78.3% Community Facility kWh Sold 20,451 Line Loss (%)8.9% Other kWh Sold (Non-PCE)45,308 Fuel Efficiency (kWh per Gallon of Diesel)6.85 Total kWh Sold 103,203 PH Consumption as % of Generation 12.8% Powerhouse (PH) Consumption kWh 16,947 Total kWh Sold & PH Consumption 120,150 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 163 of 185 Takotna PCE Utility: TAKOTNA COMMUNITY ASSOC INC Reporting Period: 07/01/22 to 06/30/23 Community Population 56 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 27 Community Facility Customers 4 Other Customers (Non-PCE)17 Fiscal Year PCE Payments $42,817 PCE Statistical Data PCE Eligible kWh - Residential Customers 59,923 Average Annual PCE Payment per Eligible Customer $1,381 PCE Eligible kWh - Community Facility Customers 21,981 Average PCE Payment per Eligible kWh $0.52 Total PCE Eligible kWh 81,904 Last Reported Residential Rate Charged (based on 500 kWh) $1.02 Average Monthly PCE Eligible kWh per Residential Customer 185 Last Reported PCE Level (per kWh)$0.71 Average Monthly PCE Eligible kWh per Community Facility Customer 458 Effective Residential Rate (per kWh)$0.31 Average Monthly PCE Eligible Community Facility kWh per Person 33 PCE Eligible kWh vs Total kWh Sold 39.4% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 273,428 Fuel Used (Gallons)26,260 Non-Diesel kWh Generated 0 Fuel Cost $124,335 Purchased kWh 0 Average Price of Fuel $4.73 Total Purchased & Generated 273,428 Fuel Cost per kWh sold $0.60 Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.60 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 63,615 Consumed vs Generated (kWh Sold vs Generated-Purchased) 75.9% Community Facility kWh Sold 22,112 Line Loss (%)8.7% Other kWh Sold (Non-PCE)121,908 Fuel Efficiency (kWh per Gallon of Diesel)10.41 Total kWh Sold 207,635 PH Consumption as % of Generation 15.3% Powerhouse (PH) Consumption kWh 41,891 Total kWh Sold & PH Consumption 249,526 Comments Non Fuel Expenses Not Reported *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 164 of 185 Tanana PCE Utility: TANANA POWER COMPANY INC. Reporting Period: 07/01/22 to 06/30/23 Community Population 231 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 103 Community Facility Customers 7 Other Customers (Non-PCE)49 Fiscal Year PCE Payments $222,420 PCE Statistical Data PCE Eligible kWh - Residential Customers 301,061 Average Annual PCE Payment per Eligible Customer $2,022 PCE Eligible kWh - Community Facility Customers 154,991 Average PCE Payment per Eligible kWh $0.49 Total PCE Eligible kWh 456,052 Last Reported Residential Rate Charged (based on 500 kWh) $0.77 Average Monthly PCE Eligible kWh per Residential Customer 244 Last Reported PCE Level (per kWh)$0.42 Average Monthly PCE Eligible kWh per Community Facility Customer 1,845 Effective Residential Rate (per kWh)$0.35 Average Monthly PCE Eligible Community Facility kWh per Person 56 PCE Eligible kWh vs Total kWh Sold 39.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,257,186 Fuel Used (Gallons)91,101 Non-Diesel kWh Generated 0 Fuel Cost $402,740 Purchased kWh 0 Average Price of Fuel $4.42 Total Purchased & Generated 1,257,186 Fuel Cost per kWh sold $0.35 Annual Non-Fuel Expenses $400,911 Non-Fuel Expense per kWh Sold $0.35 Total Expense per kWh Sold $0.70 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 306,705 Consumed vs Generated (kWh Sold vs Generated-Purchased) 91.7% Community Facility kWh Sold 155,772 Line Loss (%)6.3% Other kWh Sold (Non-PCE)690,313 Fuel Efficiency (kWh per Gallon of Diesel)13.80 Total kWh Sold 1,152,790 PH Consumption as % of Generation 2.0% Powerhouse (PH) Consumption kWh 25,576 Total kWh Sold & PH Consumption 1,178,366 Comments Provides power to Klukwan *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 165 of 185 Tatitlek PCE Utility: TATITLEK VILLAGE IRA COUNCIL Reporting Period: 07/01/22 to 06/30/23 Community Population 81 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 40 Community Facility Customers 5 Other Customers (Non-PCE)22 Fiscal Year PCE Payments $117,074 PCE Statistical Data PCE Eligible kWh - Residential Customers 125,358 Average Annual PCE Payment per Eligible Customer $2,602 PCE Eligible kWh - Community Facility Customers 45,285 Average PCE Payment per Eligible kWh $0.69 Total PCE Eligible kWh 170,643 Last Reported Residential Rate Charged (based on 500 kWh) $0.92 Average Monthly PCE Eligible kWh per Residential Customer 261 Last Reported PCE Level (per kWh)$0.72 Average Monthly PCE Eligible kWh per Community Facility Customer 755 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 47 PCE Eligible kWh vs Total kWh Sold 59.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 447,722 Fuel Used (Gallons)39,489 Non-Diesel kWh Generated 0 Fuel Cost $250,756 Purchased kWh 0 Average Price of Fuel $6.35 Total Purchased & Generated 447,722 Fuel Cost per kWh sold $0.87 Annual Non-Fuel Expenses $36,000 Non-Fuel Expense per kWh Sold $0.12 Total Expense per kWh Sold $0.99 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 128,113 Consumed vs Generated (kWh Sold vs Generated-Purchased) 64.5% Community Facility kWh Sold 51,431 Line Loss (%)25.6% Other kWh Sold (Non-PCE)109,342 Fuel Efficiency (kWh per Gallon of Diesel)11.34 Total kWh Sold 288,886 PH Consumption as % of Generation 9.9% Powerhouse (PH) Consumption kWh 44,410 Total kWh Sold & PH Consumption 333,296 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 166 of 185 Teller PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 250 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 70 Community Facility Customers 7 Other Customers (Non-PCE)35 Fiscal Year PCE Payments $115,899 PCE Statistical Data PCE Eligible kWh - Residential Customers 291,782 Average Annual PCE Payment per Eligible Customer $1,505 PCE Eligible kWh - Community Facility Customers 51,725 Average PCE Payment per Eligible kWh $0.34 Total PCE Eligible kWh 343,507 Last Reported Residential Rate Charged (based on 500 kWh) $0.51 Average Monthly PCE Eligible kWh per Residential Customer 347 Last Reported PCE Level (per kWh)$0.43 Average Monthly PCE Eligible kWh per Community Facility Customer 616 Effective Residential Rate (per kWh)$0.08 Average Monthly PCE Eligible Community Facility kWh per Person 17 PCE Eligible kWh vs Total kWh Sold 41.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 889,731 Fuel Used (Gallons)62,724 Non-Diesel kWh Generated 0 Fuel Cost $236,736 Purchased kWh 0 Average Price of Fuel $3.77 Total Purchased & Generated 889,731 Fuel Cost per kWh sold $0.28 Annual Non-Fuel Expenses $213,226 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.54 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 312,370 Consumed vs Generated (kWh Sold vs Generated-Purchased) 93.9% Community Facility kWh Sold 200,514 Line Loss (%)1.4% Other kWh Sold (Non-PCE)322,374 Fuel Efficiency (kWh per Gallon of Diesel)14.18 Total kWh Sold 835,258 PH Consumption as % of Generation 4.8% Powerhouse (PH) Consumption kWh 42,339 Total kWh Sold & PH Consumption 877,597 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 167 of 185 Tenakee Springs PCE Utility: CITY OF TENAKEE SPRINGS Reporting Period: 07/01/22 to 06/30/23 Community Population 122 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 132 Community Facility Customers 15 Other Customers (Non-PCE)29 Fiscal Year PCE Payments $114,562 PCE Statistical Data PCE Eligible kWh - Residential Customers 198,610 Average Annual PCE Payment per Eligible Customer $779 PCE Eligible kWh - Community Facility Customers 29,653 Average PCE Payment per Eligible kWh $0.50 Total PCE Eligible kWh 228,263 Last Reported Residential Rate Charged (based on 500 kWh) $0.89 Average Monthly PCE Eligible kWh per Residential Customer 125 Last Reported PCE Level (per kWh)$0.46 Average Monthly PCE Eligible kWh per Community Facility Customer 165 Effective Residential Rate (per kWh)$0.43 Average Monthly PCE Eligible Community Facility kWh per Person 20 PCE Eligible kWh vs Total kWh Sold 64.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 409,949 Fuel Used (Gallons)37,584 Non-Diesel kWh Generated 0 Fuel Cost $203,055 Purchased kWh 0 Average Price of Fuel $5.40 Total Purchased & Generated 409,949 Fuel Cost per kWh sold $0.58 Annual Non-Fuel Expenses $91,186 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.83 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 259,665 Consumed vs Generated (kWh Sold vs Generated-Purchased) 86.1% Community Facility kWh Sold 29,653 Line Loss (%)8.7% Other kWh Sold (Non-PCE)63,569 Fuel Efficiency (kWh per Gallon of Diesel)10.91 Total kWh Sold 352,887 PH Consumption as % of Generation 5.2% Powerhouse (PH) Consumption kWh 21,306 Total kWh Sold & PH Consumption 374,193 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 168 of 185 Tetlin PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 133 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 51 Community Facility Customers 5 Other Customers (Non-PCE)8 Fiscal Year PCE Payments $85,991 PCE Statistical Data PCE Eligible kWh - Residential Customers 176,657 Average Annual PCE Payment per Eligible Customer $1,536 PCE Eligible kWh - Community Facility Customers 67,770 Average PCE Payment per Eligible kWh $0.35 Total PCE Eligible kWh 244,427 Last Reported Residential Rate Charged (based on 500 kWh) $0.48 Average Monthly PCE Eligible kWh per Residential Customer 289 Last Reported PCE Level (per kWh)$0.28 Average Monthly PCE Eligible kWh per Community Facility Customer 1,130 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 42 PCE Eligible kWh vs Total kWh Sold 59.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.00 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 203,275 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 68,702 Line Loss (%)See Comments Other kWh Sold (Non-PCE)141,768 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 413,745 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 413,745 Comments See Tok for power generation *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 169 of 185 Thorne Bay; Kasaan PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 542 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 319 Community Facility Customers 29 Other Customers (Non-PCE)156 Fiscal Year PCE Payments $100,907 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,294,567 Average Annual PCE Payment per Eligible Customer $290 PCE Eligible kWh - Community Facility Customers 345,162 Average PCE Payment per Eligible kWh $0.06 Total PCE Eligible kWh 1,639,729 Last Reported Residential Rate Charged (based on 500 kWh) $0.32 Average Monthly PCE Eligible kWh per Residential Customer 338 Last Reported PCE Level (per kWh)$0.07 Average Monthly PCE Eligible kWh per Community Facility Customer 992 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 53 PCE Eligible kWh vs Total kWh Sold 47.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $0 Non-Fuel Expense per kWh Sold See Comments Total Expense per kWh Sold $0.00 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,714,414 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 345,678 Line Loss (%)See Comments Other kWh Sold (Non-PCE)1,430,932 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 3,491,024 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 68,953 Total kWh Sold & PH Consumption 3,559,977 Comments See Craig for power generation *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 170 of 185 Togiak PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 807 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 204 Community Facility Customers 18 Other Customers (Non-PCE)81 Fiscal Year PCE Payments $373,178 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,031,523 Average Annual PCE Payment per Eligible Customer $1,681 PCE Eligible kWh - Community Facility Customers 252,209 Average PCE Payment per Eligible kWh $0.29 Total PCE Eligible kWh 1,283,732 Last Reported Residential Rate Charged (based on 500 kWh) $0.60 Average Monthly PCE Eligible kWh per Residential Customer 421 Last Reported PCE Level (per kWh)$0.35 Average Monthly PCE Eligible kWh per Community Facility Customer 1,168 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 26 PCE Eligible kWh vs Total kWh Sold 41.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 3,225,059 Fuel Used (Gallons)192,366 Non-Diesel kWh Generated 0 Fuel Cost $642,479 Purchased kWh 0 Average Price of Fuel $3.34 Total Purchased & Generated 3,225,059 Fuel Cost per kWh sold $0.21 Annual Non-Fuel Expenses $789,318 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.46 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,158,280 Consumed vs Generated (kWh Sold vs Generated-Purchased) 95.9% Community Facility kWh Sold 550,144 Line Loss (%)2.4% Other kWh Sold (Non-PCE)1,383,522 Fuel Efficiency (kWh per Gallon of Diesel)16.77 Total kWh Sold 3,091,946 PH Consumption as % of Generation 1.8% Powerhouse (PH) Consumption kWh 56,894 Total kWh Sold & PH Consumption 3,148,840 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 171 of 185 Tok; Tanacross PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 1,401 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 803 Community Facility Customers 34 Other Customers (Non-PCE)199 Fiscal Year PCE Payments $1,465,955 PCE Statistical Data PCE Eligible kWh - Residential Customers 3,477,626 Average Annual PCE Payment per Eligible Customer $1,751 PCE Eligible kWh - Community Facility Customers 550,538 Average PCE Payment per Eligible kWh $0.36 Total PCE Eligible kWh 4,028,164 Last Reported Residential Rate Charged (based on 500 kWh) $0.48 Average Monthly PCE Eligible kWh per Residential Customer 361 Last Reported PCE Level (per kWh)$0.28 Average Monthly PCE Eligible kWh per Community Facility Customer 1,349 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 33 PCE Eligible kWh vs Total kWh Sold 42.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 11,349,560 Fuel Used (Gallons)767,605 Non-Diesel kWh Generated 0 Fuel Cost $2,976,140 Purchased kWh 0 Average Price of Fuel $3.88 Total Purchased & Generated 11,349,560 Fuel Cost per kWh sold $0.31 Annual Non-Fuel Expenses $2,351,747 Non-Fuel Expense per kWh Sold $0.25 Total Expense per kWh Sold $0.56 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 4,062,724 Consumed vs Generated (kWh Sold vs Generated-Purchased) 83.3% Community Facility kWh Sold 550,538 Line Loss (%)14.9% Other kWh Sold (Non-PCE)4,836,430 Fuel Efficiency (kWh per Gallon of Diesel)14.79 Total kWh Sold 9,449,692 PH Consumption as % of Generation 1.9% Powerhouse (PH) Consumption kWh 212,397 Total kWh Sold & PH Consumption 9,662,089 Comments Supplies power to Dot Lake/Dot Lake Village & Tetlin *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 172 of 185 Toksook Bay PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 612 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 131 Community Facility Customers 13 Other Customers (Non-PCE)43 Fiscal Year PCE Payments $321,459 PCE Statistical Data PCE Eligible kWh - Residential Customers 766,720 Average Annual PCE Payment per Eligible Customer $2,232 PCE Eligible kWh - Community Facility Customers 317,994 Average PCE Payment per Eligible kWh $0.30 Total PCE Eligible kWh 1,084,714 Last Reported Residential Rate Charged (based on 500 kWh) $0.60 Average Monthly PCE Eligible kWh per Residential Customer 488 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 2,038 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 43 PCE Eligible kWh vs Total kWh Sold 59.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 3,746,226 Fuel Used (Gallons)225,884 Non-Diesel kWh Generated 233,037 Fuel Cost $823,833 Purchased kWh 0 Average Price of Fuel $3.65 Total Purchased & Generated 3,979,263 Fuel Cost per kWh sold $0.45 Annual Non-Fuel Expenses $464,967 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.71 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 845,542 Consumed vs Generated (kWh Sold vs Generated-Purchased) 45.8% Community Facility kWh Sold 611,341 Line Loss (%)51.0% Other kWh Sold (Non-PCE)364,502 Fuel Efficiency (kWh per Gallon of Diesel)16.58 Total kWh Sold 1,821,385 PH Consumption as % of Generation 3.3% Powerhouse (PH) Consumption kWh 130,331 Total kWh Sold & PH Consumption 1,951,716 Comments Provides power to Nightmute & Tununnak via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 173 of 185 Tuntutuliak PCE Utility: TUNTUTULIAK COMMUNITY Reporting Period: 07/01/22 to 06/30/23 Community Population 485 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 147 Community Facility Customers 9 Other Customers (Non-PCE)35 Fiscal Year PCE Payments $306,472 PCE Statistical Data PCE Eligible kWh - Residential Customers 636,982 Average Annual PCE Payment per Eligible Customer $1,965 PCE Eligible kWh - Community Facility Customers 37,518 Average PCE Payment per Eligible kWh $0.45 Total PCE Eligible kWh 674,500 Last Reported Residential Rate Charged (based on 500 kWh) $0.65 Average Monthly PCE Eligible kWh per Residential Customer 361 Last Reported PCE Level (per kWh)$0.46 Average Monthly PCE Eligible kWh per Community Facility Customer 347 Effective Residential Rate (per kWh)$0.19 Average Monthly PCE Eligible Community Facility kWh per Person 6 PCE Eligible kWh vs Total kWh Sold 56.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,232,370 Fuel Used (Gallons)95,526 Non-Diesel kWh Generated 110,615 Fuel Cost $359,552 Purchased kWh 0 Average Price of Fuel $3.76 Total Purchased & Generated 1,342,985 Fuel Cost per kWh sold $0.30 Annual Non-Fuel Expenses $407,299 Non-Fuel Expense per kWh Sold $0.34 Total Expense per kWh Sold $0.64 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 688,582 Consumed vs Generated (kWh Sold vs Generated-Purchased) 88.9% Community Facility kWh Sold 59,848 Line Loss (%)9.0% Other kWh Sold (Non-PCE)445,131 Fuel Efficiency (kWh per Gallon of Diesel)12.90 Total kWh Sold 1,193,561 PH Consumption as % of Generation 2.1% Powerhouse (PH) Consumption kWh 28,516 Total kWh Sold & PH Consumption 1,222,077 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 174 of 185 Tununak PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 396 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 87 Community Facility Customers 7 Other Customers (Non-PCE)27 Fiscal Year PCE Payments $141,350 PCE Statistical Data PCE Eligible kWh - Residential Customers 426,629 Average Annual PCE Payment per Eligible Customer $1,504 PCE Eligible kWh - Community Facility Customers 35,994 Average PCE Payment per Eligible kWh $0.31 Total PCE Eligible kWh 462,623 Last Reported Residential Rate Charged (based on 500 kWh) $0.60 Average Monthly PCE Eligible kWh per Residential Customer 409 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 429 Effective Residential Rate (per kWh)$0.26 Average Monthly PCE Eligible Community Facility kWh per Person 8 PCE Eligible kWh vs Total kWh Sold 44.9% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 0 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $263,024 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.26 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 459,326 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 202,799 Line Loss (%)See Comments Other kWh Sold (Non-PCE)368,202 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 1,030,327 PH Consumption as % of Generation N/A Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 1,030,327 Comments Receives power from Toksook Bay via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 175 of 185 Twin Hills PCE Utility: TWIN HILLS VILLAGE COUNCIL Reporting Period: 07/01/22 to 06/30/23 Community Population 85 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 35 Community Facility Customers 6 Other Customers (Non-PCE)7 Fiscal Year PCE Payments $36,984 PCE Statistical Data PCE Eligible kWh - Residential Customers 104,527 Average Annual PCE Payment per Eligible Customer $902 PCE Eligible kWh - Community Facility Customers 28,463 Average PCE Payment per Eligible kWh $0.28 Total PCE Eligible kWh 132,990 Last Reported Residential Rate Charged (based on 500 kWh) $0.50 Average Monthly PCE Eligible kWh per Residential Customer 249 Last Reported PCE Level (per kWh)$0.27 Average Monthly PCE Eligible kWh per Community Facility Customer 395 Effective Residential Rate (per kWh)$0.23 Average Monthly PCE Eligible Community Facility kWh per Person 28 PCE Eligible kWh vs Total kWh Sold 55.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 0 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 300,168 Average Price of Fuel $0.00 Total Purchased & Generated 300,168 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $20,652 Non-Fuel Expense per kWh Sold $0.09 Total Expense per kWh Sold $0.09 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 128,677 Consumed vs Generated (kWh Sold vs Generated-Purchased) 80.1% Community Facility kWh Sold 28,463 Line Loss (%)19.9% Other kWh Sold (Non-PCE)83,274 Fuel Efficiency (kWh per Gallon of Diesel)N/A Total kWh Sold 240,414 PH Consumption as % of Generation 0.0% Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 240,414 Comments Purchases power from AVEC. Reported non-fuel expense = 10 months *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 176 of 185 Unalakleet PCE Utility: UNALAKLEET VALLEY ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 734 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 276 Community Facility Customers 24 Other Customers (Non-PCE)89 Fiscal Year PCE Payments $401,296 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,100,962 Average Annual PCE Payment per Eligible Customer $1,338 PCE Eligible kWh - Community Facility Customers 268,194 Average PCE Payment per Eligible kWh $0.29 Total PCE Eligible kWh 1,369,156 Last Reported Residential Rate Charged (based on 500 kWh) $0.63 Average Monthly PCE Eligible kWh per Residential Customer 332 Last Reported PCE Level (per kWh)$0.31 Average Monthly PCE Eligible kWh per Community Facility Customer 931 Effective Residential Rate (per kWh)$0.32 Average Monthly PCE Eligible Community Facility kWh per Person 30 PCE Eligible kWh vs Total kWh Sold 37.8% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 3,278,860 Fuel Used (Gallons)215,274 Non-Diesel kWh Generated 639,194 Fuel Cost $749,173 Purchased kWh 0 Average Price of Fuel $3.48 Total Purchased & Generated 3,918,054 Fuel Cost per kWh sold $0.21 Annual Non-Fuel Expenses $361,044 Non-Fuel Expense per kWh Sold $0.10 Total Expense per kWh Sold $0.31 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,277,981 Consumed vs Generated (kWh Sold vs Generated-Purchased) 92.5% Community Facility kWh Sold 462,215 Line Loss (%)4.4% Other kWh Sold (Non-PCE)1,882,049 Fuel Efficiency (kWh per Gallon of Diesel)15.23 Total kWh Sold 3,622,245 PH Consumption as % of Generation 3.1% Powerhouse (PH) Consumption kWh 122,548 Total kWh Sold & PH Consumption 3,744,793 Comments Non-Fuel reported = 8 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 177 of 185 Unalaska PCE Utility: CITY OF UNALASKA Reporting Period: 07/01/22 to 06/30/23 Community Population 4,195 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 808 Community Facility Customers 58 Other Customers (Non-PCE)198 Fiscal Year PCE Payments $1,174,180 PCE Statistical Data PCE Eligible kWh - Residential Customers 2,126,177 Average Annual PCE Payment per Eligible Customer $1,356 PCE Eligible kWh - Community Facility Customers 2,907,960 Average PCE Payment per Eligible kWh $0.23 Total PCE Eligible kWh 5,034,137 Last Reported Residential Rate Charged (based on 500 kWh) $0.48 Average Monthly PCE Eligible kWh per Residential Customer 219 Last Reported PCE Level (per kWh)$0.18 Average Monthly PCE Eligible kWh per Community Facility Customer 4,178 Effective Residential Rate (per kWh)$0.29 Average Monthly PCE Eligible Community Facility kWh per Person 58 PCE Eligible kWh vs Total kWh Sold 12.5% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 42,695,436 Fuel Used (Gallons)2,756,745 Non-Diesel kWh Generated 0 Fuel Cost $11,783,226 Purchased kWh 0 Average Price of Fuel $4.27 Total Purchased & Generated 42,695,436 Fuel Cost per kWh sold $0.29 Annual Non-Fuel Expenses $5,402,527 Non-Fuel Expense per kWh Sold $0.13 Total Expense per kWh Sold $0.43 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 3,920,517 Consumed vs Generated (kWh Sold vs Generated-Purchased) 94.3% Community Facility kWh Sold 3,146,439 Line Loss (%)3.7% Other kWh Sold (Non-PCE)33,195,452 Fuel Efficiency (kWh per Gallon of Diesel)15.49 Total kWh Sold 40,262,408 PH Consumption as % of Generation 2.0% Powerhouse (PH) Consumption kWh 859,258 Total kWh Sold & PH Consumption 41,121,666 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 178 of 185 Upper Kalskag PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 203 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 58 Community Facility Customers 3 Other Customers (Non-PCE)26 Fiscal Year PCE Payments $109,561 PCE Statistical Data PCE Eligible kWh - Residential Customers 298,392 Average Annual PCE Payment per Eligible Customer $1,796 PCE Eligible kWh - Community Facility Customers 32,874 Average PCE Payment per Eligible kWh $0.33 Total PCE Eligible kWh 331,266 Last Reported Residential Rate Charged (based on 500 kWh) $0.66 Average Monthly PCE Eligible kWh per Residential Customer 429 Last Reported PCE Level (per kWh)$0.40 Average Monthly PCE Eligible kWh per Community Facility Customer 913 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 13 PCE Eligible kWh vs Total kWh Sold 45.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 1,374,169 Fuel Used (Gallons)93,674 Non-Diesel kWh Generated 0 Fuel Cost $320,663 Purchased kWh 0 Average Price of Fuel $3.42 Total Purchased & Generated 1,374,169 Fuel Cost per kWh sold $0.44 Annual Non-Fuel Expenses $187,993 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.69 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 329,577 Consumed vs Generated (kWh Sold vs Generated-Purchased) 53.6% Community Facility kWh Sold 131,932 Line Loss (%)43.9% Other kWh Sold (Non-PCE)274,905 Fuel Efficiency (kWh per Gallon of Diesel)14.67 Total kWh Sold 736,414 PH Consumption as % of Generation 2.5% Powerhouse (PH) Consumption kWh 34,618 Total kWh Sold & PH Consumption 771,032 Comments Provides power to Lower Kalskag via intertie *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 179 of 185 Venetie PCE Utility: VENETIE VILLAGE ELECTRIC Reporting Period: 07/01/22 to 06/30/23 Community Population 185 Last Reported Month May No. of Monthly Payments Made 11 Residential Customers 107 Community Facility Customers 9 Other Customers (Non-PCE)16 Fiscal Year PCE Payments $240,255 PCE Statistical Data PCE Eligible kWh - Residential Customers 236,287 Average Annual PCE Payment per Eligible Customer $2,071 PCE Eligible kWh - Community Facility Customers 104,887 Average PCE Payment per Eligible kWh $0.70 Total PCE Eligible kWh 341,174 Last Reported Residential Rate Charged (based on 500 kWh) $0.90 Average Monthly PCE Eligible kWh per Residential Customer 201 Last Reported PCE Level (per kWh)$0.70 Average Monthly PCE Eligible kWh per Community Facility Customer 1,059 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 52 PCE Eligible kWh vs Total kWh Sold 71.1% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 479,990 Fuel Used (Gallons)0 Non-Diesel kWh Generated 0 Fuel Cost $0 Purchased kWh 0 Average Price of Fuel $0.00 Total Purchased & Generated 479,990 Fuel Cost per kWh sold See Comments Annual Non-Fuel Expenses $30,000 Non-Fuel Expense per kWh Sold $0.06 Total Expense per kWh Sold $0.06 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 258,304 Consumed vs Generated (kWh Sold vs Generated-Purchased) 100.0% Community Facility kWh Sold 105,809 Line Loss (%)See Comments Other kWh Sold (Non-PCE)115,877 Fuel Efficiency (kWh per Gallon of Diesel)0.00 Total kWh Sold 479,990 PH Consumption as % of Generation 0.0% Powerhouse (PH) Consumption kWh 0 Total kWh Sold & PH Consumption 479,990 Comments 11 Rpts, Diesel kWh Gen 3 mths, Non-Fuel Ex 10 mths, No Fuel Used & PHouse Consm *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 180 of 185 Wainwright PCE Utility: NORTH SLOPE BOROUGH Reporting Period: 07/01/22 to 06/30/23 Community Population 638 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 149 Community Facility Customers 3 Other Customers (Non-PCE)73 Fiscal Year PCE Payments $18,014 PCE Statistical Data PCE Eligible kWh - Residential Customers 582,341 Average Annual PCE Payment per Eligible Customer $119 PCE Eligible kWh - Community Facility Customers 102,136 Average PCE Payment per Eligible kWh $0.03 Total PCE Eligible kWh 684,477 Last Reported Residential Rate Charged (based on 500 kWh) $0.35 Average Monthly PCE Eligible kWh per Residential Customer 326 Last Reported PCE Level (per kWh)$0.15 Average Monthly PCE Eligible kWh per Community Facility Customer 2,837 Effective Residential Rate (per kWh)$0.20 Average Monthly PCE Eligible Community Facility kWh per Person 13 PCE Eligible kWh vs Total kWh Sold 11.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 7,366,540 Fuel Used (Gallons)547,038 Non-Diesel kWh Generated 0 Fuel Cost $1,748,002 Purchased kWh 0 Average Price of Fuel $3.20 Total Purchased & Generated 7,366,540 Fuel Cost per kWh sold $0.29 Annual Non-Fuel Expenses $1,050,942 Non-Fuel Expense per kWh Sold $0.17 Total Expense per kWh Sold $0.46 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,377,862 Consumed vs Generated (kWh Sold vs Generated-Purchased) 82.3% Community Facility kWh Sold 102,136 Line Loss (%)12.8% Other kWh Sold (Non-PCE)4,582,757 Fuel Efficiency (kWh per Gallon of Diesel)13.47 Total kWh Sold 6,062,755 PH Consumption as % of Generation 4.9% Powerhouse (PH) Consumption kWh 363,634 Total kWh Sold & PH Consumption 6,426,389 Comments Residential PCE Level = Zero *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 181 of 185 Wales PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 142 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 30 Community Facility Customers 5 Other Customers (Non-PCE)31 Fiscal Year PCE Payments $82,900 PCE Statistical Data PCE Eligible kWh - Residential Customers 163,213 Average Annual PCE Payment per Eligible Customer $2,369 PCE Eligible kWh - Community Facility Customers 52,700 Average PCE Payment per Eligible kWh $0.38 Total PCE Eligible kWh 215,913 Last Reported Residential Rate Charged (based on 500 kWh) $0.68 Average Monthly PCE Eligible kWh per Residential Customer 453 Last Reported PCE Level (per kWh)$0.43 Average Monthly PCE Eligible kWh per Community Facility Customer 878 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 31 PCE Eligible kWh vs Total kWh Sold 26.3% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 781,004 Fuel Used (Gallons)41,072 Non-Diesel kWh Generated 0 Fuel Cost $161,936 Purchased kWh 0 Average Price of Fuel $3.94 Total Purchased & Generated 781,004 Fuel Cost per kWh sold $0.20 Annual Non-Fuel Expenses $209,799 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.45 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 212,732 Consumed vs Generated (kWh Sold vs Generated-Purchased) See Comments Community Facility kWh Sold 321,618 Line Loss (%)See Comments Other kWh Sold (Non-PCE)287,481 Fuel Efficiency (kWh per Gallon of Diesel)19.02 Total kWh Sold 821,831 PH Consumption as % of Generation 4.5% Powerhouse (PH) Consumption kWh 35,429 Total kWh Sold & PH Consumption 857,260 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 182 of 185 Whale Pass PCE Utility: ALASKA POWER COMPANY Reporting Period: 07/01/22 to 06/30/23 Community Population 84 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 88 Community Facility Customers 2 Other Customers (Non-PCE)19 Fiscal Year PCE Payments $16,750 PCE Statistical Data PCE Eligible kWh - Residential Customers 263,198 Average Annual PCE Payment per Eligible Customer $186 PCE Eligible kWh - Community Facility Customers 10,572 Average PCE Payment per Eligible kWh $0.06 Total PCE Eligible kWh 273,770 Last Reported Residential Rate Charged (based on 500 kWh) $0.32 Average Monthly PCE Eligible kWh per Residential Customer 249 Last Reported PCE Level (per kWh)$0.07 Average Monthly PCE Eligible kWh per Community Facility Customer 441 Effective Residential Rate (per kWh)$0.25 Average Monthly PCE Eligible Community Facility kWh per Person 10 PCE Eligible kWh vs Total kWh Sold 61.0% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 517,653 Fuel Used (Gallons)47,938 Non-Diesel kWh Generated 0 Fuel Cost $193,587 Purchased kWh 0 Average Price of Fuel $4.04 Total Purchased & Generated 517,653 Fuel Cost per kWh sold $0.43 Annual Non-Fuel Expenses $47,836 Non-Fuel Expense per kWh Sold $0.11 Total Expense per kWh Sold $0.54 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 317,808 Consumed vs Generated (kWh Sold vs Generated-Purchased) 86.7% Community Facility kWh Sold 10,572 Line Loss (%)8.7% Other kWh Sold (Non-PCE)120,645 Fuel Efficiency (kWh per Gallon of Diesel)10.80 Total kWh Sold 449,025 PH Consumption as % of Generation 4.5% Powerhouse (PH) Consumption kWh 23,504 Total kWh Sold & PH Consumption 472,529 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 183 of 185 White Mountain PCE Utility: CITY OF WHITE MOUNTAIN Reporting Period: 07/01/22 to 06/30/23 Community Population 189 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 69 Community Facility Customers 8 Other Customers (Non-PCE)28 Fiscal Year PCE Payments $122,511 PCE Statistical Data PCE Eligible kWh - Residential Customers 306,225 Average Annual PCE Payment per Eligible Customer $1,591 PCE Eligible kWh - Community Facility Customers 115,193 Average PCE Payment per Eligible kWh $0.29 Total PCE Eligible kWh 421,418 Last Reported Residential Rate Charged (based on 500 kWh) $0.55 Average Monthly PCE Eligible kWh per Residential Customer 370 Last Reported PCE Level (per kWh)$0.33 Average Monthly PCE Eligible kWh per Community Facility Customer 1,200 Effective Residential Rate (per kWh)$0.22 Average Monthly PCE Eligible Community Facility kWh per Person 51 PCE Eligible kWh vs Total kWh Sold 52.6% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 917,276 Fuel Used (Gallons)72,552 Non-Diesel kWh Generated 0 Fuel Cost $227,665 Purchased kWh 0 Average Price of Fuel $3.14 Total Purchased & Generated 917,276 Fuel Cost per kWh sold $0.28 Annual Non-Fuel Expenses $119,261 Non-Fuel Expense per kWh Sold $0.15 Total Expense per kWh Sold $0.43 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 324,790 Consumed vs Generated (kWh Sold vs Generated-Purchased) 87.3% Community Facility kWh Sold 117,207 Line Loss (%)7.5% Other kWh Sold (Non-PCE)358,556 Fuel Efficiency (kWh per Gallon of Diesel)12.64 Total kWh Sold 800,553 PH Consumption as % of Generation 5.2% Powerhouse (PH) Consumption kWh 48,065 Total kWh Sold & PH Consumption 848,618 Comments Reported Non-Fuel = 9 mths *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 184 of 185 Yakutat PCE Utility: ALASKA VILLAGE ELECTRIC COOP Reporting Period: 07/01/22 to 06/30/23 Community Population 697 Last Reported Month June No. of Monthly Payments Made 12 Residential Customers 278 Community Facility Customers 28 Other Customers (Non-PCE)190 Fiscal Year PCE Payments $708,617 PCE Statistical Data PCE Eligible kWh - Residential Customers 1,251,754 Average Annual PCE Payment per Eligible Customer $2,316 PCE Eligible kWh - Community Facility Customers 454,510 Average PCE Payment per Eligible kWh $0.42 Total PCE Eligible kWh 1,706,264 Last Reported Residential Rate Charged (based on 500 kWh) $0.61 Average Monthly PCE Eligible kWh per Residential Customer 375 Last Reported PCE Level (per kWh)$0.43 Average Monthly PCE Eligible kWh per Community Facility Customer 1,353 Effective Residential Rate (per kWh)$0.17 Average Monthly PCE Eligible Community Facility kWh per Person 54 PCE Eligible kWh vs Total kWh Sold 29.7% Additional Statistical Data Reported by Community* Generated and Purchased kWh Generation Costs Diesel kWh Generated 6,439,055 Fuel Used (Gallons)409,018 Non-Diesel kWh Generated 0 Fuel Cost $1,649,977 Purchased kWh 0 Average Price of Fuel $4.03 Total Purchased & Generated 6,439,055 Fuel Cost per kWh sold $0.29 Annual Non-Fuel Expenses $1,467,920 Non-Fuel Expense per kWh Sold $0.26 Total Expense per kWh Sold $0.54 Consumed and Sold kWh Efficiency and Line Loss Residential kWh Sold 1,398,922 Consumed vs Generated (kWh Sold vs Generated-Purchased) 89.3% Community Facility kWh Sold 1,424,425 Line Loss (%)8.6% Other kWh Sold (Non-PCE)2,926,841 Fuel Efficiency (kWh per Gallon of Diesel)15.74 Total kWh Sold 5,750,188 PH Consumption as % of Generation 2.1% Powerhouse (PH) Consumption kWh 135,275 Total kWh Sold & PH Consumption 5,885,463 Comments *The data contained in this report is primarily based on information submitted by the utility with their monthly PCE reports. Changes to the reported data and/or significant anomalies have been noted in the comments. 185 of 185 Safe,Reliable, and AffordableEnergySolutions Alaska Energy Authority 813 W Northern Lights Blvd. Anchorage, AK 99503 Phone: (907) 771-3000 Fax: (907) 771-3044 Toll Free: (888) 300-8534 akenergyauthority.org Page 1 of 2 PCE Cost Equalization (PCE) Endowment Fund (Managed by APFC) Reporting of Investment Gain (Loss) by Month and YTD And Fund Balance as of 01/31/2024 (in Thousands) $14,681 ($9,762)($13,770)($16,140) $34,200 $22,377 ($4,704) $14,681 $4,919 ($8,851)($23,989)$10,211 $32,588 $27,884 $950,973 $941,098 $927,182 $899,929 $934,034 $957,123 $944,310 1.65% -1.10% -1.56%-1.88% 3.85% 2.46% -0.52% 1.65% 0.55% -1.00% -2.79% 1.15% 3.58% 3.10% -4.00% -3.00% -2.00% -1.00% 0.00% 1.00% 2.00% 3.00% 4.00% 5.00% ($200,000) $0 $200,000 $400,000 $600,000 $800,000 $1,000,000 $1,200,000 July August September October November December January Investment Gain (Loss) Monthly Investment Gain (Loss) YTD Fund Balance Page 2 of 2 PCE Cost Equalization (PCE) Endowment Fund (Managed by APFC) Reporting of Investment Gain (Loss) by Month and YTD And Fund Balance as of 01/31/2024 (in Thousands) Month Investment Gain (Loss) Monthly Investment Gain (Loss) YTD Fund Balance Rate of Return Monthly Investment Rate of Return YTD Transfers to AEA Transfers to AEA YTD Operating Admin Expenses Admin Expenses YTD Month Total Amount Invested Return for the Month Rate of Return YTD July $14,681 $14,681 $950,973 1.65%1.65%($10,471)($10,471)($99)($99)July $892,145 1.65%1.65% August ($9,762)$4,919 $941,098 -1.10%0.55%$0 ($10,471)($113)($213)August $887,665 -1.10%0.55% September ($13,770)($8,851)$927,182 -1.56%-1.00%$0 ($10,471)($146)($359)September $882,675 -1.56%-1.00% October ($16,140)($23,989)$899,929 -1.88%-2.79%($12,000)($22,471)($115)($473)October $858,708 -1.88%-2.79% November $34,200 $10,211 $934,034 3.85%1.15%$0 ($22,471)($95)($569)November $888,320 3.85%1.15% December $22,377 $32,588 $957,123 2.46%3.58%$0 ($22,471)($121)($689)December $910,627 2.46%3.58% January ($4,704)$27,884 $944,310 -0.52%3.10%($8,000)($30,471)($109)($798)January $899,497 -0.52%3.10% February February March March April April May May June June 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 RGYAUTHORITY.ORG Dixon Diversion Update 2/19/24 Over the course of 2023, economics concerning the Dixon Diversion Project (“Project”) have changed, with estimates related to project scope, total development cost, and potential energy output being continually refined. To the benefit of the project, feasibility research efforts by the Alaska Energy Authority (AEA) and contracted engineering firms, have yielded increasingly favorable project economics. The initial proposition for Project was comprised of two development options. The first option under consideration is a diversion tunnel option from the terminus of the Dixon glacier into Bradley Lake. The second, or alternative, option is a run-of-river hydroelectric generation facility constructed on Martin River, in the proximate area of the Dixon Glacier. Preliminary feasibility research on the two alternatives rendered the run-of-river option on Martin River not economically feasible owing to concerns over excessive project costs. The diversion option is now the singluar option under study, as leveraging the existing power generation assets and transmission infrastructure at Bradley Lake via a diversion tunnel has proven far more economic and cost-effective. It is estimated that the shortfall in natural gas between availalble Cook Inlet gas supply and demand via Railbelt electric and gas utilities is estimated at 20 Bcf in the year 2030. When considering the 1.5 Bcf displaced by the Project, this would account for approximately 7.5% of such unmet natural gas demand in 2030. Conceputal Design Cost Refinements In early 2023, AEA, in conjunction with its engineering contractors provided a conceptual project development cost estimate of $415 million. As conceptual design engineering has progressed, with sole focus on the diversion option, significant cost savings have been realized. Initial conceptual cost estimates had included an access road built to the diversion site. Further consideration of this initial design has resulted in the access road being removed from the Project scope. It has been determined that the diversion dam and intake can be constructed with helicopter support at a substantially lower cost than building a new access road, and has additional ancillary benefits including reducing impact to wildlife habitat, area wetlands, and preserving the natual aesthetics of the site. Per the current conceptual design, the following provides a summary of the project footprint and scope of the Project’s primary construction elements:  Intake and diversion at Dixon Glacier  14-foot diameter diversion tunnel from Dixon Glacier to Bradley Lake  Half-mile access road from West Fork of Upper Battle Creek to downstream tunnel portal  14-foot dam raise at Bradley Lake Dam (additional storage of 55,000 acre-feet)  High-voltage (3-phase) electrical service from Bradley Hydro Station to Bradley Lake Dam and downstream tunnel portal. Alaska Energy Authority Page 2 of 7 Continual revisions to the conceptual design have resulted in significant reductions in development cost from $415 million to a revised estimate of $342 million, as stated in a November 2023 memo from cost and constructability consultants D. Hertel & Associates, LLC (DHA) which provides an Opinion of Probable Constructon Cost (OPCC). The basis of this cost includes Alaska prevailing wage rates as well as equipment rates developed by the US Army Corps of Engineers, and adjusted for site conditions, including rock engagement and current fuel cost. Construction quantities and cost bases used in the cost estimate were developed by DOWL and DHA. The revised $342 million estimate as stated in the OPCC is inclusive of a contractor’s Indirect Costs of 15%, markup (overhead and profit) of 15%, a bond and insurance cost of 4.1%, an allowance of 7% of construction costs for unlisted items, and a design and post- award construction contingency of 25%. The estimate is also inclusive of additional required costs including FERC Licensing, Geologic & Hydrologic Studies, Feasibility Design, Final Design, and Construction Administration. The current cost estimate of $342 million and supporting OPCC anticipates all work being completed under a single construction contract. Potential cost and schedule advantages may realized by awarding the various Project components under multiple contracts with such savings associated with the elimination of potential subcontractor markups associated with electrical installation, dam improvements, and tunnel work, and increased number of bids, enhancing price competition among potential bidders. Project Enhancements In addition to reductions in total estimated project cost, hydrology assessments, including gauging and surveying at the intake site, and the leveraging of synthetic daily flow records in comparison with Upper Bradley discharge, have yielded more favorable water diversion estimates for the Project, further improving the economics of the Project. While flow volumes for diversion to Bradley Lake are sensitive to historical records, more recent records are understood to be more reasonably representational of future flows. The current revised flow estimates for water diverted via the diversion tunnel are: Based on Bradley records and higher reservoir level with dam raise approximately 1 megawatt- hour (MWh) is generated per 1 acre-foot (ac-ft) of water. The new flow measurements yielding greater flow rates have resulted in a design revision which replaces the initial 12-foot diameter diversion tunnel with a 14-foot diameter diversion tunnel, allowing for the diversion of an additional 15,000 to 22,000 acre-feet of diverted water per year. The increased tunnel diameter also provides for additional benefits to the Project including easier vehicle movement, ventilation, and power routing. Dixon Diversion Diverted Flow Estimates Record Acre-Feet of Water 30-Year 159,000 20-Year 165,500 10-Year 182,800 Alaska Energy Authority Page 3 of 7 The 14-foot Bradley Lake Dam raise as proposed also would provide additional benefits including increased storage of an estimated 55,000 acre-feet of water to be used during the winter. In addition, owing to the higher elevation of the reservoir the efficiency of generation, ac-ft to MWh, for all current Bradley Lake generation will be improved. The additional efficiency of higher lake lake level on existing generation will yield an additional 8,000 MWh per year above the Dixon Diversion energy increases. While infrastructure costs are still significant, and primarily associated with the provision of 3- phase power from Bradley Hydro Station to Bradley Lake, there are considerable cost-savings in this approach. High voltage power, needed for the operation of the tunnel-boring-machine (TBM), would also benefit potential configurations of the diversion structure and the spillway gates for raising Bradley Reservoir. There would be numerous opportunities during Project construction to utilize Bradley-sourced renewable high voltage power in place of diesel power. Should diesel generation be utilized in lieu of the 3-phase power extension, there are significant risks of project delays owing to issues with the conveyance of needed diesel fuel to the Project site, especially during the winter months, with an estimated 600,000 gallons (or 110,000 gallons per month) needed during the winter construction season for operation of the TBM. Delays in fuel delivery, or winter shutdown of the TBM operation would result in additional cost, and likely an additional season of construction. Diesel operation of the TBM operation would likely cost an additional $4 million, as well as lost power production revenues of one year. Project Economics When comparing the proposed Dixon Diversion Project with past, larger, utility-scale hydropower, and select wind projects on a total development cost per annual energy output (MWh) basis, Dixon Diversion at the current cost estimate of $342 million, is cost-competitive. As indicated in Attachment A: Comparison of Utility-Scale Alaska Renewable Energy Projects on a Cost per Annual Energy Output Basis, Dixon Diversion, assuming an annual energy output of 190,800 MWh, ranks as the third lowest cost per annual energy output ($1,792 per MWh) of those projects identified, falling between Snettisham’s Crater Lake at $1,720 per MWh and Bradley Lake at $2,150 per MWh. On a strict annual energy output (MWh) basis, Dixon Diversion ranks as the third highest-yield hydro facility, between Snettisham’s Long Lake at 195,000 MWh and Tyee Lake Hydro at 130,000 MWh. The Dixon Diversion Project, leveraging existing Bradley Lake generation assets and transmission infrastructure, is a cost-effective addition to the lowest cost of power generating facility on the Railbelt, Bradley Lake. At an estimated 190,800 MWh, the Dixon Diversion project would add 48% in available energy output to Bradley Lake, taking the average annual energy output of Bradley Lake from 400,000 MWh to 590,800 MWh. In a January 2023 presentation1 to its Board, and as provided in Table 1 below, Chugach Electric Association, Inc. (CEA) calculated an estimated base, short-run avoided cost of $96 per MWh in 2033. At a base load contract rate of $12 per Mcf, the avoided cost estimate increases to $146 per MWh, and under a base load contract rate scenario assuming $18 per Mcf, the avoided cost estimate increases to $207 per MWh. 1 Presentation: Dixon Diversion Economics – Regular Board of Directors’ Meeting – January 25, 2023. For reference: Chugach -Hilcorp currently gas contract: Regulatory Commission of Alaska - TA481-8; Letter Order #: L2000085 Alaska Energy Authority Page 4 of 7 In comparison, estimates as to the levelized cost of energy (LCOE) for Dixon Diversion are provided in Table 2 below, applying a range of debt interest rates from 4% to 6%, 30 year financing term, a total development cost of $342 million, annual operations and maintenance cost of $500,000, and an annual energy output of 190,800 MWh. As noted in Table 2, the LCOE for Dixon Diversion is calculated at below CEA’s avoided cost at the rate of $12 per Mcf, indicating favorable economics for the Project. Furthermore, as the cost escalations concerning cost for natural gas for the Railbelt electric utilities is not known at this time, any cost escalations above $12 per Mcf of natural gas, will improve the economics of the Project relative to natural- gas fired generation. Project Benefits In an analysis of information provided by the Railbelt utilities as sourced from their 2022 annual reports to the Regulatory Commission of Alaska (RCA), concerning the efficiency of gas-fired generation units, it was calculated that the weighted average efficiency of all primary gas-fired generation units on the Railbelt was approximately 8.1 kilowatt-hours (kWh) per cubic foot of natural gas. With an estimated average annual energy output of 190,800 MWh, or 190.8 million kWh for Dixon Diversion, this would equate to around 1.5 billion cubic feet (Bcf) of natural gas displaced on an annual basis. For consideration as to the relative size of this displacement, in a report2 by Berkeley Research Group in August 2023, it was estimated that the shortfall in natural gas between availalble Cook Inlet gas supply and demand via Railbelt electric and gas utilities is estimated at 20 Bcf in the year 2030. When considering the 1.5 Bcf displaced by the Project, this would account for approximately 7.5% of such unmet natural gas demand in 2030. The Dixon Diversion Project, leveraging existing Bradley Lake generation assets and transmission infrastructure, can be reasonably considered a cost-effective addition to the lowest cost of power generation on the Railbelt, Bradley Lake. At an estimated 190,800 MWh, the Dixon 2 Berkeley Research Group (BRG) – Cook Inlet Gas Supply Project Summary and RFI – Aug 2023 Table 1 Chugach Electric Association - Reported Avoided Cost Estimate - 2033 to 2082 Item Avoided Cost ($/MWh) Base Avoided Cost (2.5% escalator)96$ Avoided Cost $12 Gas in 2028 (2.5% escalator)146$ Avoided Cost $18 Gas in 2028 (2.5% escalator)207$ Table 2: Dixon Diversion - Levelized Cost of Energy Estimates Development Cost 342,000,000$ Development Cost 342,000,000$ Development Cost 342,000,000$ Annual O&M 500,000$ Annual O&M 500,000$ Annual O&M 500,000$ Annual Output 190,800 Annual Output 190,800 Annual Output 190,800 Interest rate 4.0%Interest rate 5.0%Interest rate 6.0% LCOE ($/MWh)106$ LCOE ($/MWh)119$ LCOE ($/MWh)133$ Conceptual Design Estimate (@ 4%)Conceptual Design Estimate (@ 5%)Conceptual Design Estimate (@ 6%) Alaska Energy Authority Page 5 of 7 Diversion project would add 48% in available energy output to Bradley Lake, taking the average annual energy output of Bradley Lake from 400,000 MWh to 590,800 MWh. Furthermore, there is added economic value, relative to other renewable energy generation sources, for hydroelectric projects like Bradley Lake, whose annual energy output would be substantially supplemented by the Dixon Diverison Project. Impoundment (i.e. storage) hydroeletric facilities like Bradley Lake are much more strategically valuable generation assets owing to their ability to be variably dispatched, or ability to load-follow, depending on the load required by the eletric system. In contrast, wind and solar generation are intermittent sources of power and can only produce power contingent on adequate wind or insolation, which requires other sources of dispatchable power (natural gas, naptha, diesel, hydro, etc...) to be available. Project Schedule Studies (2024 – 2025): Typically, two years of studies are required for FERC license amendments that may impact fish & game habitat. AEA intends to proceed with engineering and environmental studies in 2024 using State funds and remaining R&C funds. On the engineering side, the intent would be for continued gaging of Martin River, drilling core holes to obtain rock samples at the proposed tunnel inlet and outlet, and advancing design engineering. For environmental studies, the priority are the required fisheries studies as these tend to require two years and will inform the minimum instream flow requirements that will affect how much energy will be contributed from the Project. The overall project construction duration is anticipated to be about 3 years, with completion in 2030. Licensing (2026 – 2027): During this time a draft license amendment, final lincense amendment, and Environmental Analysis will be prepared. Pre-Construction (2027): An aggressive pre-construction project schedule has bid and Notice to Proceed to Contractor occuring in the October-December 2027 timeframe. This procurement is inclusive of those long lead time components, such as the TBM, electrical equipment for the high-voltage system, dam spillway gates, and intake gates at Dixon. This schedule would allow the contractor the winter season to plan, as well as a full first season of construction. Year 1 Construction (2028): Year 1 construction would primarily concentrate on installation of the electrical conduits from Bradley Station to Bradley Lake, as well as the access to the downstream portal and portal development, and development of workforce housing. Initial construction of the Dixon diversion dam and the upstream portal could be developed in the first season, but could be Alaska Energy Authority Page 6 of 7 delayed until the second season without delaying commissioning of the project. This work would likely include improvements to the upstream portal to facilitate receiving of the TBM as the TBM reaches that point. Access to the diversion and upstream portal would be by means of helicopter. Improvements associated with raising Bradley Dam could occur during any of the summer seasons. Completion of these improvements would rely on procurement of the spillway gate equipment. Year 2 Construction (2029): Year 2 construction would focus on the development of the “starter” tunnel, taking place early in the year. TBM tunneling operations would begin in year 2 and are anticipated to run through the winter season, operating from line power installed in the prior year. Year 3 Construction (2030) Year 3 construction is anticipated to include completion of the TBM operation, dismantling and removal of the TBM. Upon completion of the tunnel to the upstream portal, completion of the inlet structure and associated mechanical work can be done. At this time, it may be possible for diversion access to be through the completed tunnel and eliminate the need for helicopter access. Electrical work within the tunnel to bring power and communication to the diversion structure is done, and then following, completion, testing, and commissioning of the Project. Attachments  Attachment A: Comparison of Utility-Scale Alaska Renewable Energy Projects on a Cost per Annual Energy Output Basis Attachment A: Comparison of Utility-Scale Alaska Renewable Energy Projects on a Cost per Annual Energy Output Basis Alaska Energy Authority Page 7 of 7 SOLDOTNA TO QUARTZ TRANSMISSION UPGRADE Introduction The Soldotna Substation to Quartz Creek Substation transmission line plays a vital role in Alaska's Railbelt electric grid, which serves over 75% of the state’s population. About 87% of the energy from Bradley Lake Hydroelectric Project (Bradley) crosses this section going to the central and northern utilities. The 115kV transmission line is fifty years old and will require replacement as many of the support structures are approaching the end of their useful life. This section represents some of the highest line loss per mile of Bradley energy. The upgrade will size the conductor, insulators, and poles/towers to 230kV standards. A fiber–optic communication line will also be installed along the route. Benefits are: • Reduced line losses so that more energy makes it to the consumer. • Greater capacity for increasing energy during peak periods. • Greater capacity will allow new projects to convey energy. • Greater secure communication and control of system. • Increased resilience to wildfires and other unplanned events. Once all transmission line has been upgraded from Anchorage to Soldotna then transformers will be upgraded to 230kV and line will operate at 230kV. Because of constraints on how long the transmission line can be out-of-service and the various land ownerships the line crosses, the effort has been divided into five projects, each with independent utility. The projects are as follows from West to East: • Project 5: Soldotna Substation to Sterling Substation (14 miles) • Project 1: Sterling Substation to Kenai National Wildlife Refuge (8 miles) • Project 2: Kenai National Wildlife Refuge (17 miles) • Project 3: Kenai National Wildlife Refuge and Chugach National Forest to Cooper Creek (9 miles) • Project 4: Cooper Creek to Quartz creek Substation (5 miles) Authorization • Bradley Project Management Committee authorized by resolution proceeding with the design and procurement of materials for this section of transmission line. • Department of Law and Independent Consultant found that this project met the definitions of Bradley Required Project Work. • Project was listed in Bradley Series Eleventh bonds. Project Components • 54 miles of new transmission line (operated at 115kV, insulated to 230kV) • New support structures • Fiber optic communication line Project Schedule Project schedule is based on outage constraints, permitting, and seasonal construction. Project schedule subject to change based on the above criteria. Majority of work is over wetlands and can only occur during late winter months. Outages cannot occur concurrently with other transmission projects because that would island communities from power and prevent Bradley power from going north during critical periods. • Project 1 o Construction Q1 2025 • Project 2 o Environmental Assessment summer 2024 o Construction Q1 2027 • Project 3 o Environmental Assessment summer 2024 o Construction Q1 2028 • Project 4 o Construction Q1 2025 • Project 5 o Construction Q4 2025 – Q1 2027 Utilities are discussing having longer line outages (isolate the Kenai from grid) to shorten the schedule. Project Economics • Current estimated cost: $90 million Project Funding • Project will be supported through Bond Funding of Bradley Lake Required Project Work Transmission route show below for Sterling to Quartz section. 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 MEMORANDUM DATE: February 13, 2024 TO: Curtis W. Thayer, Executive Director FROM: Audrey Alstrom, Director – Renewable Energy and Energy Efficiency SUBJECT: Electric Vehicle Program Update National Electric Vehicle Infrastructure (NEVI) Formula Program Background: The Bipartisan Infrastructure Law (BIL) established the National Electric Vehicle Infrastructure (NEVI) formula funding program, allocating $52 million to Alaska over the next five years to build EV charging stations along highway corridors to create a nationwide network of electric vehicle (EV) chargers. The primary goal of this federal program is to deploy EV charging stations and create an interconnected network that facilitates data collection, accessibility, and reliability. In this initiative, the Alaska Energy Authority (AEA) has taken a leadership role as the state's primary agency responsible for EV planning and implementation. Additionally, the State of Alaska Department of Transportation and Public Facilities (DOT&PF) has been designated as the recipient of FHWA Title 23 funds and is pivotal in administering the NEVI program. Collaboration among AEA, DOT&PF, and the Federal Highway Administration (FHWA) occurs through bi- monthly meetings, where they discuss progress and coordinate tasks and responsibilities within the NEVI program. NEVI Sites: Last spring, AEA issued a Request for Applications (RFA) to install NEVI-compliant Electric Vehicle Supply Equipment (EVSE) at sites located along the Alaska Alternative Fuel Corridor (AFC) between Anchorage and Fairbanks. Through the RFA process, the evaluation committee selected nine Alaska communities to receive a total investment of $6.4 million in NEVI funds this round. The funding will be matched with $1.6 million from private entities selected to install, own, and operate the new EV charging stations for a total investment of $8 million. A visual depiction of the selected EV charging sites along the corridor is below in Figure 1. AEA has been closely collaborating with DOT&PF to oversee the Design and Construction phases for the chosen sites. AEA and DOT&PF are developing site host project agreements, and DOT&PF's environmental team has begun the NEPA environmental review. Upon the conclusion of the NEPA process, the final design and construction phases will commence. Construction activities for the selected sites are projected to take place from April 2024 through October 2025. Alaska Energy Authority Page 2 of 4 Figure 1. NEVI AFC Awards NEVI Plan: The NEVI program mandates that states annually submit a NEVI Implementation Plan (referred to as "The Plan") to the Joint Office of Energy and Transportation (The Joint Office) and FHWA. This plan serves as the guiding document that outlines and regulates programmatic activities, encompassing the construction of EV infrastructure, public outreach and education, labor and workforce development initiatives, and more. AEA and DOT&PF will submit the FY25 NEVI Implementation Plan in the summer of 2024. Department of Energy: Vehicle Technologies Office In November 2023, AEA, in collaboration with various partners, submitted an application to the Department of Energy (DOE) with the purpose of installing charging stations and conducting outreach in rural Alaska. The grant partners include DOT&PF, Launch Alaska, Alaska Municipal League, Yellowstone-Teton Clean Cities Coalition, and the Alaska Center for Energy and Power. AEA was chosen as the recipient of an award under this program, amounting to $1.67 million, with an additional $330,000 contributed from the state and partner sources as a match. The total project budget for this initiative stands at $2 million. AEA is working through grant agreements and beginning the first phase of the project. Alaska Energy Authority Page 3 of 4 Volkswagen Settlement EVSE Sites In 2018, Alaska became a beneficiary of $8.125 million from the Volkswagen Environmental Mitigation Trust (Trust). With Trust funds, the Department of Energy (DOE) State Energy Program (SEP) funds, and private matching funds from site hosts, AEA installed 15 fast chargers and eight level two electric vehicle (EV) chargers at nine stations connecting Seward and Homer to Healy. All Volkswagen sites are commissioned and operational. Volkswagen Sites: • Anchorage: Dimond Center • Cantwell, Jack River Inn • Chugiak: Three Bears Alaska • Cooper Landing: Grizzly Ridge • Healy: Three Bears Alaska • Homer: AJ’s Old Town Steakhouse and Tavern • Seward: Seward Chamber of Commerce • Soldotna: Custom Seafoods • Trapper Creek: Three Bears Alaska Current Statewide EV Ownership as of February 5, 2024: Alaska Energy Authority Page 4 of 4 AEA Infrastructure Funding Opportunities Note: New information is in bold font in cells highlighted yellow Page 1 of 2 last updated 2/22/2024 %$ Awarded Defense Community Infrastructure Pilot - National Defense Authorization Act Black Rapids Training Site $ 12,602,648 0%$0 AEA partnered with GVEA for Black Rapids Training Site. Requesting additional $3M in federal receipt authority in FY24 supplemental budget for a total of $15.6M. Awarded Energy Efficiency and Conservation Block Grant - IIJA 40552b $ 1,627,450 0%$0 Match to be provided by site partners. AEA issued RFA (RE- VEEP) for subawards due 2/27/24. Awarded National Electric Vehicle Infrastructure Program (NEVI) FFY 22-24 - IIJA 11401 $ 30,086,630 20%$6,017,326 AEA partnered with DOT, DOT responsible for receipt authority. Total funding expected is $52M. Awarded Preventing Outages and Enhancing the Resilience of the Electric Grid, Formula Grants to States and Indian Tribes FFY 2022-2023 - IIJA 40101d $ 24,221,046 15%$3,633,157 Additional formula funding of $36M expected over the next 3 years, listed as conditional award. AEA has receipt authority for $24.2M federal award and $5.4M match. Solicitation for subawards closed 2/16/24. Awarded State Energy Program Funding - IIJA 40109 $ 3,661,930 0%$0 AEA applicant. Funding split 70% AEA and 30% AHFC. Awarded Vehicle Technology Office FFY 2022 $ 1,670,000 20%$417,500 Match to be provided by site partners. $83,937,687 $ 73,869,704 $10,067,983 Conditional Award Defense Community Infrastructure Pilot - National Defense Authorization Act - Black Rapids Training Site additional $3 million $ 3,000,000 0%$0 AEA lead applicant partnered with GVEA. Requesting additional $3M in federal receipt authority in FY24 supplemental budget for a total of $15.6M. Conditional Award Energy Efficiency Revolving Loan Capitalization Program - IIJA 40502 $ 4,782,480 0%$0 Received notice of an increase in the amount of formula funding on 10/27. AEA resubmitted application 11/1/23. Requesting additional $240k in federal receipt authority in FY24 supplemental budget. AEA and AHFC are partners. Conditional Award Grid Resilience and Innovation Partnerships Program Topic 3 - IIJA 40103b $ 206,500,000 100%$206,500,000 AEA notified by DOE for negotiation of financial assistance award in the amount of $206.5M. 100% match required or $206.5M, funding source unknown. Conditional Award Home Efficiency Rebates (formula funding) - IRA 50121 $ 37,368,480 0%$0 AEA applicant as State Energy Office. AHFC administer the program. Application due 1/31/25. Conditional Award Home Electrification and Appliance Rebates (formula funding) - IRA 50122 $ 37,150,940 0%$0 AEA applicant as State Energy Office. AHFC administer the program. Application due 1/31/25. Conditional Award National Electric Vehicle Infrastructure Program (NEVI) FFY 25-26 - IIJA 11401 $ 22,328,390 20%$4,465,678 Program is formula funding that DOT will apply for as the allocation for each fiscal year is released. Conditional Award Preventing Outages and Enhancing the Resilience of the Electric Grid, Formula Grants to States and Indian Tribes FFY 2024-2026 - IIJA 40101d (formula funding) $ 41,848,064 15%$6,277,210 Formula funding that AEA will apply for as the allocation for each year is released. AEA has receipt authority for $5.4M of match and needs authority for remaining match of $4.2. FFY24 application deadline is 4/17/24, State allocation for FFY24 is $17,627,018. Conditional Award High Energy Cost Grants - USDA RUS $ 2,000,000 0%$0 AEA received notice that their application was selected for Manokotak. Conditional Award Training for Residential Energy Contractors (TREC) (formula funding) - IRA 50123 (Previously known as Energy Auditor Contractor Training Program) $ 1,293,870 0%$0 AEA applicant as State Energy Office. AHFC to administer the program. AEA submitted the application on 1/30/24. $573,515,112 $ 356,272,224 $ 217,242,888 AK Funding Award / Request Comments Required Match Status GO Federal Receipt Authority Grant Program Name Total Awarded: Total Conditional Award: AEA Infrastructure Funding Opportunities Note: New information is in bold font in cells highlighted yellow Page 2 of 2 last updated 2/22/2024 %$ AK Funding Award / Request Comments Required Match Status GO Federal Receipt Authority Grant Program Name Pending Energy Future Grant $ 496,725 0%$0 Application submitted. AEA to partner with AML to evaluate energy permitting in 45 municipalities. Pending Greenhouse Gas Reduction Fund - Solar For All Competition - IRA 134a $ 100,000,000 0%$0 AEA/AHFC partners. Application Submitted 10/11/2023. Pending Wood Innovations Grant Program FFY 2024 - IRA 23002 $ 500,000 100%$500,000 Application submitted. $101,496,725 $ 100,996,725 $ 500,000 Considering Clean Energy Innovator Fellowship Program NA TBD TBD Applications for Prospective Host Institutions due March 5. Applications for fellows to open in March 2024. AEA will apply for Host opportunity. Considering Clean Heavy Duty Vehicles - IRA 60101 NA TBD TBD Funding opportunity not issued at this time. Considering Clean Ports Program - IRA 60102 NA TBD TBD Funding opportunity not issued at this time. Considering Climate Pollution Reduction Grants Competition $4.3 Billion - IRA 60114 NA TBD TBD Application due 4/1/24. AEA will submit 1 application for the Dixon Diversion Project and will be the lead on a coalition application for Rural Energy Programs with tribal consortium. Considering Defense Community Infrastructure Pilot - National Defense Authorization Act NA TBD TBD Funding opportunity to be issued early 2024. AEA plans to re-submit application for Eielson upgrades with partner GVEA, $10.2 million grant request. Considering Energy Auditor Training Program - IIJA 40503 NA 0%$0 Concept paper due 3/28/2024. Application due 6/28/24. Considering Energy Improvements in Remote and Rural Areas FY24-FY26 - IIJA 40103c NA TBD TBD Funding for FY 2024 - 2026 not open at this time. Considering Grid Resilience and Innovation Partnerships Program Topic 1 - IIJA 40101c NA 33- 100%TBD MEA submitted concept paper partnering with Railbelt utilities and AEA. Application due 4/17/24. 1/3 required match for small utilities. Considering Grid Resilience and Innovation Partnerships Program Topic 2 - IIJA 40107 NA 100%TBD FFY 2024 - 2025 opportunity. Concept paper due 1/12/24. Application due 5/22/24. Considering Grid Resilience and Innovation Partnerships Program Topic 3 - IIJA 40103b NA 100%TBD AEA submitted concept paper 1/11/24 partnering with Railbelt utilities. Application due 4/17/24. Considering Transmission Siting & Economic Development Grants Program - IRA 50152 NA 5- 100%TBD Application deadline 4/5/24. AEA and AML submitted a concept as partners for economic development. AEA/AML concept paper encouraged to apply, AEA needs to confirm eligibility of HVDC line size. Considering Watersmart Grants: Water and Energy Efficiency Grants for FY2024 & 2025 Bureau of Reclamation Opportunity No. R24AS00052 NA 100%TBD Application Period 1 deadline 10/30/24 AEA may apply for part of Dixon Diversion Project. NA TBDTotal Considering: Total Pending: 1 2024-02-21 FOA-0002740 Grid Resilience and Innovation Partnerships (GRIP), Topic Area 3 Alaska Energy Authority Railbelt Innovation Resiliency Project STATEMENT OF PROJECT OBJECTIVES (SOPO) A. OBJECTIVES The Railbelt Innovation Resiliency Project (RIR) aims to enhance resiliency and transfer capability along the Alaska Railbelt. The Railbelt has experienced decreasing frequency regulation, slowed disturbance response and increasing magnitude natural frequency oscillations. The current configuration of the Railbelt system is fragile with little resilience, which restricts the adoption of clean energy, diversification of the fuel supply, and Alaska's preparation for a sustainable carbon- free future. A key priority to achieve this objective is to reinforce interconnections between the primary regions of the Railbelt by adding parallel lines to increase resilience and implementing Battery Energy Storage Systems (BESS) to resolve long-standing frequency control and instability issues. Along with the High Voltage Direct Current (HVDC) submarine cable, these additions will alleviate transmission congestion and optimize interregional transfer capability. The project's innovative solutions hold the promise of curbing escalating energy prices, which currently rank among the highest in the nation, while providing rural residents and disadvantaged communities with an opportunity to enhance community viability. Sharing these solutions with other communities will support collective efforts toward achieving clean, reliable, and affordable energy for all. B. SCOPE OF WORK The RIR project involves several primary components to meet the project's objectives. The projects involve the interconnection of existing AC Transmission with a High Voltage Direct Current (HVDC) submarine circuit and three large capacity Battery Energy Storage systems (BESS). Coordinated interregional control and operations of the BESS and HVDC line will tie all the individual systems together to maximize stability and limit congestion. The first component is a HVDC transmission tie connection between the Kenai Peninsula and northwest across Cook Inlet to the Beluga substation. This transmission tie consists of an HVDC cable and the associated converter stations. The overall objective of this segment is to construct a parallel path between the Central region and Southern region which will improve transfer capability and increase resilience. The parallel line will reduce generating costs and will provide an optional path if fires or avalanches interrupt power transfer. The tie connection adds a new bay on the Kenai along with a converter station. A similar process is repeated on the west side of Cook Inlet where the HVDC transitions back to AC at the Beluga substation. 2 2024-02-21 The second component includes the addition of two Battery Energy Storage Systems (BESS). The new BESS units will be located in both Northern and Central regions and will augment the existing BESS unit in the Southern region. Incorporating BESS units in all three regions (Southern, Central & Northern) will provide significant reliability and economic benefit to the entire Railbelt. The Northern BESS will be installed within a building to provide maximum protection from Fairbanks’ extreme temperatures. Both BESS units will include battery modules, power transformers, switchgear and associated bus, steel, control, fire suppression and communications equipment. The entire project (scope and duration) will require Project Management and Reporting systems to be in place. Initial tasks will be to prepare the following documents: • Project Management Plan • Community Benefits Plan • NEPA Compliance Statement • Cybersecurity Plan • Project Schedule • Project Budget Our initial task breakdown list will include the following: • Preliminary Design (Allow Environmental/Permitting efforts to commence) • Environmental/Permitting • Design & Engineering • Land Acquisition • Procurement of Long-Lead Items • Right of Way Clearing & Site Preparation • Construction • Testing & Commissioning • Note: List of initial tasks is attached 3 2024-02-21 C. TASKS TO BE PERFORMED Task 1.0: Project Management and Planning Subtask 1.0010: Project Management Plan (PMP): Within 30 days of award, the Recipient shall provide the Project Management Plan (PMP) to the designated Federal Project Officer (FPO). The Recipient shall not proceed beyond Task 1.0 until the PMP has been accepted by the FPO. AEA is currently finalizing the PMP for this project. We expect to submit a PMP on or before March 8, 2024. Subtask 1.0020: Community Benefits Plan Alaska Energy Authority has engaged a consultant, Agnew-Beck, to assist with our Community Benefit Plan. Their initial scope of work will be to assist AEA with the completion of two Department of Energy documents: ‘Community Benefits Outcomes and Objectives’ and ‘Recipient Reporting—Community Benefits Report’. The purpose of these documents is to create the structure and deliverables through which Community Benefits Plan grant reporting for AEA’s awarded 2023 GRIP application will occur. These documents will create a plan for how AEA will comply with and report upon DOE Community Benefits Plan requirements, outlining what, exactly, AEA plans to do, and on what timeline AEA will accomplish those tasks. Our goal is to have these documents submitted to DOE on or before March 15, 2024. Subtask 1.0030: National Environmental Policy Act (NEPA) Compliance As required, AEA will undertake the NEPA process to consider the potential environmental consequences of the project, to consult with other interested agencies, to document the analysis, and to make this information available to the public for comment before the implementation of the project. AEA believes that this project could require an Environmental Impact Statement (EIS). If an EIS is required, AEA will undertake a study with a Lead Agency to identify and analyze adverse environmental impacts and reasonable alternatives as appropriate. Subtask 1.0040: Cybersecurity Plan (CSP) The CSP shall be revised and resubmitted as often as necessary, during the course of the project, to capture any major/significant changes. A Cybersecurity Plan for the project was submitted to DOE on December 18, 2023 4 2024-02-21 D. DELIVERABLES Listed below are a summary of the initial document to be submitted. Subtask 1.001: Project Management Plan as outlined above. Expect to submit on or before March 8, 2024 Subtask 1.0020: Community Benefits Plan as outlined above. Expect to submit on or before March 15, 2024 Subtask 1.0030: NEPA Compliance Statement of intent to comply with the NEPA process included Subtask 1.0040: Cybersecurity Plan Submitted to DOE on December 18, 2023 Note: Alaska Energy Authority is working with Alaska’s Governor and the Alaska Legislature on a funding plan for the required matching funds. AEA expect to have a funding plan in place along with AEA Board approval for the plan in mid-March. Additional deliverables as well as any documents that the DOE and AEA determine are applicable will be delivered to DOE. In addition to the deliverables listed above, the Recipient shall submit all periodic, topical, final, and other reports in accordance with the Federal Assistance Reporting Checklist and accompanying instructions. E. BRIEFINGS/TECHNICAL PRESENTATIONS The Recipient shall prepare, and present periodic briefings, technical presentations and demonstrations as requested by the Federal Project Officer, which may be held at a DOE or the Recipient’s facility, other mutually agreeable location, or via webinar. Such meetings may include all or a combination of the following: Kickoff Briefing - Not more than 60 days after submission of the Project Management Plan, the Recipient shall prepare and present a project summary briefing as part of a Project Kickoff Meeting. Pre-Continuation Briefing(s) – Not less than 90 days prior to the planned start of a phase relative to an established go/no go decision point, the Recipient shall brief the DOE on the performance relative to project success criteria, milestones, Go/No-Go Decision point metrics that are documented in the Project Management Plan (PMP), and their plans for the 5 2024-02-21 subsequent periods of work. The Go/No-Go Decision will be based on the successful completion of both the work relative to the milestones and metrics as defined in the PMP (including approval of associated deliverables) as well as meeting the established requirements of the Community Benefits Outcomes and Objectives (CBOO) as detailed in the CBP for the given performance period. The Recipient will not begin the next phase of work (or a subsequent task/subtask) until receiving written authorization from the DOE Contracting Officer (CO) to proceed in accordance with the award terms and conditions. The DOE will consider the information from this briefing, as well as the content of deliverables submitted to date, prior to authorizing continuing the project. Final Project Briefing - Not less than 30 days prior to the end of the project, the Recipient shall prepare and present a Final Project Briefing on the results and accomplishments of the entire project. Other Briefings – The Recipient shall prepare and present technical, financial, and/or administrative briefings as requested by the DOE. A project technical review briefing will be conducted no less than annually. Additionally, the DOE may require Recipients to make technical presentations at national and/or industry conferences. 6 2024-02-21 Alaska Energy Authority Railbelt Innovation Resiliency Project Initial Task List SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 4 SPECIAL TERMS AND CONDITIONS FOR USE IN MOST GRANTS AND COOPERATIVE AGREEMENTS 7 LEGAL AUTHORITY AND EFFECT (JUNE 2015) ........................................................................................ 7 RESOLUTION OF CONFLICTING CONDITIONS ........................................................................................ 7 AWARD AGREEMENT TERMS AND CONDITIONS – BIPARTISAN INFRASTRUCTURE LAW / INFLATION REDUCTION ACT (DECMBER 2014) (NETL – MARCH 2023)................................................. 7 CONFERENCE SPENDING (FEBRUARY 2015) ............................................................................................ 7 PAYMENT PROCEDURES - REIMBURSEMENT THROUGH THE AUTOMATED CLEARING HOUSE (ACH) VENDOR INQUIRY PAYMENT ELECTRONIC REPORTING SYSTEM (VIPERS) ...................... 8 COST SHARING NOT INVOLVED ................................................................................................................. 8 REBUDGETING AND RECOVERY OF INDIRECT COSTS - REIMBURSABLE INDIRECT COSTS AND FRINGE BENEFITS ................................................................................................................................. 9 REBUDGETING AND RECOVERY OF INDIRECT COSTS - REIMBURSABLE INDIRECT COSTS ...... 9 REBUDGETING AND RECOVERY OF INDIRECT COSTS - INDIRECT COSTS AND FRINGE BENEFITS ARE NOT REIMBURSABLE ...................................................................................................... 10 PRE-AWARD COSTS (DECEMBER 2014) ................................................................................................... 10 USE OF PROGRAM INCOME - DEDUCTION ............................................................................................. 10 STATEMENT OF FEDERAL STEWARDSHIP ............................................................................................. 10 STATEMENT OF SUBSTANTIAL INVOLVEMENT................................................................................... 10 SITE VISITS ..................................................................................................................................................... 11 REPORTING REQUIREMENTS (APRIL 2023) ............................................................................................ 11 PUBLICATIONS .............................................................................................................................................. 12 FEDERAL, STATE, AND MUNICIPAL REQUIREMENTS ......................................................................... 12 INTELLECTUAL PROPERTY PROVISIONS AND CONTACT INFORMATION..................................... 12 NOTICE REGARDING THE PURCHASE OF AMERICAN-MADE EQUIPMENT AND PRODUCTS -- SENSE OF CONGRESS ................................................................................................................................... 12 INSURANCE COVERAGE (DECEMBER 2014) ........................................................................................... 13 REAL PROPERTY (DECEMBER 2014) ........................................................................................................ 13 EQUIPMENT (DECEMBER 2014) ................................................................................................................. 13 SUPPLIES (DECEMBER 2014) ...................................................................................................................... 14 INTANGIBLE PROPERTY (DECEMBER 2014) ........................................................................................... 14 PROPERTY TRUST RELATIONSHIP (DECEMBER 2014) ......................................................................... 14 INSOLVENCY, BANKRUPTCY OR RECEIVERSHIP ................................................................................ 14 PERFORMANCE OF WORK IN UNITED STATES ..................................................................................... 15 CATEGORICAL EXCLUSION (CX) ................................................................................................................. 15 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 5 DECONTAMINATION AND/OR DECOMMISSIONING (D &D) COSTS ................................................. 15 SYSTEM FOR AWARD MANAGEMENT AND UNIVERSAL IDENTIFIER REQUIREMENTS ............ 15 FINAL INCURRED COST AUDIT (DECEMBER 2014) .............................................................................. 16 LOBBYING RESTRICTIONS (MARCH 2012) .............................................................................................. 16 CORPORATE FELONY CONVICTION AND FEDERAL TAX LIABILITY ASSURANCES (MARCH 2014).................................................................................................................................................................. 17 NONDISCLOSURE AND CONFIDENTIALITY AGREEMENTS ASSURANCES (JUNE 2015) ............. 17 REPORTING OF MATTERS RELATED TO RECIPIENT INTEGRITY AND PERFORMANCE (DECEMBER 2015) ......................................................................................................................................... 18 SUBAWARD/SUBCONTRACT CHANGE NOTIFICATION .......................................................................... 19 GO/NO-GO DECISION 20 IMPLEMENTATION OF EXECUTIVE ORDER 13798, PROMOTING FREE SPEECH AND RELIGIOUS LIBERTY (NOVEMBER 2020) 21 CONTINUED USE OF REAL PROPERTY AND EQUIPMENT (OCTOBER 2022) ...................................... 21 FOREIGN NATIONAL PARTICIPATION – APPROVAL REQUIRED (MARCH 2023) ............................... 21 POST AWARD DUE DILIGENCE REVIEWS (SEPTEMBER 2023)............................................................... 22 EXPORT CONTROL (MARCH 2023) ................................................................................................................ 22 INTERIM CONFLICT OF INTEREST POLICY FOR FINANCIAL ASSISTANCE (MARCH 2023) ............ 22 ORGANIZATIONAL CONFLICT OF INTEREST (MARCH 2023) ................................................................. 23 BUY AMERICAN REQUIREMENT FOR INFRASTRUCTURE PROJECTS (MARCH 2023) ..................... 23 PROHIBITION ON CERTAIN TELECOMMUNICATIONS AND VIDEO SURVEILLANCE SERVICES OR EQUIPMENT (MARCH 2023) 27 PROHIBITION RELATED TO FOREIGN GOVERNMENT-SPONSORED TALENT RECRUITMENT PROGRAMS (MARCH 2023) 28 PARTICIPANTS AND OTHER COLLABORATING ORGANIZATIONS (SEPTEMBER 2023) .................. 28 HUMAN SUBJECTS RESEARCH (MARCH 2023) .......................................................................................... 29 FRAUD, WASTE AND ABUSE (MARCH 2023) .............................................................................................. 30 TRANSPARENCY OF FOREIGN CONNECTIONS (SEPTEMBER 2023) ..................................................... 30 FOREIGN COLLABORATION CONSIDERATIONS (MARCH 2023) ........................................................... 31 REPORTING SUBAWARD AND EXECUTIVE COMPENSATION (SEPTEMBER 2023) ........................... 32 POTENTIALLY DUPLICATIVE FUNDING NOTICE (MARCH 2023) .......................................................... 34 REQUIRED RISK MITIGATION (MARCH 2023) ............................................................................................ 34 REPORTING, TRACKING AND SEGREGATION OF INCURRED COSTS (MARCH 2023) ...................... 35 COMMUNITY BENEFITS OUTCOMES AND OBJECTIVES – NETL .......................................................... 35 CYBERSECURITY PLAN (SEPTEMBER 2023) .............................................................................................. 35 DAVIS-BACON ACT REQUIREMENTS (MARCH 2023) ............................................................................... 35 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 6 AFFIRMATIVE ACTION AND PAY TRANSPARENCY REQUIREMENTS (SEPTEMBER 2023) ............ 37 SIGNAGE (SEPTEMBER 2023) 38 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 7 SPECIAL TERMS AND CONDITIONS FOR USE IN MOST GRANTS AND COOPERATIVE AGREEMENTS LEGAL AUTHORITY AND EFFECT (JUNE 2015) (a) A DOE financial assistance award is valid only if it is in writing and is signed, either in writing or electronically, by a DOE Contracting Officer. (b) Recipients are free to accept or reject the award. A request to draw down DOE funds constitutes the Recipient's acceptance of the terms and conditions of this Award. RESOLUTION OF CONFLICTING CONDITIONS Any apparent inconsistency between Federal statutes and regulations and the terms and conditions contained in this award must be referred to the DOE Award Administrator for guidance. AWARD AGREEMENT TERMS AND CONDITIONS – BIPARTISAN INFRASTRUCTURE LAW / INFLATION REDUCTION ACT (DECMBER 2014) (NETL – MARCH 2023) This award/agreement consists of the Assistance Agreement cover page, plus the following: Attachment 1 Intellectual Property Provisions Attachment 2 Statement of Project Objectives Attachment 3 Federal Assistance Reporting Checklist and Instructions Attachment 4 Budget Information Attachment 5 Community Benefits Outcomes and Objectives The following are incorporated into this Award by reference: • DOE Assistance Regulations, 2 CFR part 200 as amended by 2 CFR part 910 at https://www.eCFR.gov. • Research Terms & Conditions (November 12, 2020) and the DOE Agency Specific Requirements (November 2020) at https://www.nsf.gov/awards/managing/rtc.jsp. • National Policy Requirements (November 12, 2020) at https://www.nsf.gov/awards/managing/rtc.jsp. • Public Law 117-58, also known as the Bipartisan Infrastructure Law (BIL). • The Recipient’s application/proposal as approved by DOE. CONFERENCE SPENDING (FEBRUARY 2015) The recipient shall not expend any funds on a conference not directly and programmatically related to the purpose for which the grant or cooperative agreement was awarded that would defray the cost to the United States Government of a conference held by any Executive branch department, agency, board, commission, or office for which the cost to the United States Government would otherwise exceed $20,000, thereby circumventing the required notification by the head of any such Executive Branch department, agency, board, commission, or office to the Inspector General (or senior ethics official for any entity without an Inspector General), of the date, location, and number of employees attending such conference. SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 8 PAYMENT PROCEDURES - REIMBURSEMENT THROUGH THE AUTOMATED CLEARING HOUSE (ACH) VENDOR INQUIRY PAYMENT ELECTRONIC REPORTING SYSTEM (VIPERS) a. Method of Payment. Payment will be made by reimbursement through ACH. b. Requesting Reimbursement. Requests for reimbursements must be made electronically through Department of Energy's Oak Ridge Financial Service Center (ORFSC) VIPERS. To access and use VIPERS, you must enroll at https://vipers.doe.gov. Detailed instructions on how to enroll are provided on the web site. For non-construction awards, you must submit a Standard Form (SF) 270, "Request for Advance or Reimbursement" at https://vipers.doe.gov and attach a file containing appropriate supporting documentation. The file attachment must show the total federal share claimed on the SF 270, the non-federal share claimed for the billing period if cost sharing is required, and cumulative expenditures to date (both Federal and non-Federal) for each of the following categories: salaries/wages and fringe benefits; equipment; travel; participant/training support costs, if any; other direct costs, including subawards/contracts; and indirect costs. For construction awards, you must submit a SF 271, "Outlay Report and Request for Reimbursement for Construction Programs," through VIPERS. c. Timing of submittals. Submittal of the SF 270 or SF 271 should coincide with your normal billing pattern, but not more frequently than every two weeks. Requests for reimbursement must be limited to the amount of disbursements made during the billing period for the federal share of direct project costs and the proportionate share of any allowable indirect costs incurred during that billing period. At a minimum, Recipient’s should meet the required cost share percentage (specified in the Cost Sharing Term) by each go/no go decision point specified in the Statement of Project Objectives (Attachment 2). d. Adjusting payment requests for available cash. You must disburse any funds that are available from repayments to and interest earned on a revolving fund, program income, rebates, refunds, contract settlements, audit recoveries, credits, discounts, and interest earned on any of those funds before requesting additional cash payments from DOE/NNSA. e. Payments. The DOE approving official will approve the invoice as soon as practicable but not later than 30 days after your request is received, unless the billing is improper. Upon receipt of an invoice payment authorization from the DOE approving official, the ORFSC will disburse payment to you. You may check the status of your payments at the VIPER web site. All payments are made by electronic funds transfer to the bank account identified on the ACH Vendor/Miscellaneous Payment Enrollment Form (SF 3881) that you filed. COST SHARING NOT INVOLVED a. Total Estimated Project Cost is the sum of the Government share and Recipient share of the estimated project costs. The Recipient's cost share must come from non-Federal sources unless otherwise allowed by law. By accepting federal funds under this award, you agree that you are liable for your percentage share of total allowable project costs, on a budget period basis, even if the project is terminated early or is not funded to its completion. This cost is shared as follows: SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 9 Budget Period No.$%$% 1 #DIV/0!#DIV/0!$0 Total Project $0 #DIV/0!$0 #DIV/0!$0 TotalGovernment Share Recipient Share b. If you discover that you may be unable to provide cost sharing of at least the amount identified in paragraph a of this term, you should immediately provide written notification to the DOE Award Administrator indicating whether you will continue or phase out the project. If you plan to continue the project, the notification must describe how replacement cost sharing will be secured. c. You must maintain records of all project costs that you claim as cost sharing, including in-kind costs, as well as records of costs to be paid by DOE/NNSA. Such records are subject to audit. d. Failure to provide the cost sharing required by this term may result in the subsequent recovery by DOE/NNSA of some or all the funds provided under the award. REBUDGETING AND RECOVERY OF INDIRECT COSTS - REIMBURSABLE INDIRECT COSTS AND FRINGE BENEFITS a. If actual allowable indirect costs are less than those budgeted and funded under the award, you may use the difference to pay additional allowable direct costs during the project period. If at the completion of the award the Government's share of total allowable costs (i.e., direct and indirect), is less than the total costs reimbursed, you must refund the difference. b. Recipients are expected to manage their indirect costs. DOE will not amend an award solely to provide additional funds for changes in indirect cost rates. DOE recognizes that the inability to obtain full reimbursement for indirect costs means the recipient must absorb the underrecovery. Such underrecovery may be allocated as part of the organization's required cost sharing. REBUDGETING AND RECOVERY OF INDIRECT COSTS - REIMBURSABLE INDIRECT COSTS a. If actual allowable indirect costs are less than those budgeted and funded under the award, you may use the difference to pay additional allowable direct costs during the project period. If at the completion of the award the Government's share of total allowable costs (i.e., direct and indirect), is less than the total costs reimbursed, you must refund the difference. b. Recipients are expected to manage their indirect costs. DOE will not amend an award solely to provide additional funds for changes in indirect cost rates. DOE recognizes that the inability to obtain full reimbursement for indirect costs means the recipient must absorb the underrecovery. Such underrecovery may be allocated as part of the organization's required cost sharing. c. The budget for this award includes indirect costs, but does not include fringe benefits. Therefore, fringe benefit costs shall not be charged to nor shall reimbursement be requested for this project nor shall the fringe benefit costs for this project be allocated to any other federally sponsored project. In addition, fringe benefit costs shall not be counted as cost share unless approved by the Contracting Officer. SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 10 REBUDGETING AND RECOVERY OF INDIRECT COSTS - INDIRECT COSTS AND FRINGE BENEFITS ARE NOT REIMBURSABLE The budget for this award does not include indirect costs or fringe benefits. Therefore, these expenses shall not be charged to nor reimbursement requested for this project nor shall the fringe and indirect costs from this project be allocated to any other federally sponsored project. In addition, indirect costs or fringe benefits shall not be counted as cost share unless approved by the Contracting Officer. REBUDGETING AND RECOVERY OF INDIRECT COSTS – DE MINIMIS RATE AND FRINGE BENEFITS: a. The Recipient has elected to charge a de minimis rate of 10% allocated to a base of modified total direct costs (MTDC) per 2 CFR Part 200.414(f). This methodology must be used consistently until the Recipient choses to negotiate indirect cost billing rates. De minimis costs are not verifiable from the Recipient’s records, therefore, the Recipient cannot claim the resulting indirect costs as cost share per 2 CFR Part 200.306(b)(1). b. If the recipient has elected to include fringe benefits in the MTDC, fringe benefit costs have been allocated to this award under a segregated fringe billing rate. The fringe costs were found to be reasonable, allocable, and allowable as reflected in the budget. PRE-AWARD COSTS (DECEMBER 2014) You are entitled to reimbursement for costs incurred on or after [], as authorized by the pre-award costs letter dated [], if such costs are allowable in accordance with the applicable Federal cost principles referenced in 2 CFR part 200 as amended by 2 CFR part 910. USE OF PROGRAM INCOME - DEDUCTION If you earn program income during the project period as a result of this award, you must deduct the program income from the total allowable project costs to determine the net allowable costs on which the Federal share is based. STATEMENT OF FEDERAL STEWARDSHIP DOE/NNSA will exercise normal Federal stewardship in overseeing the project activities performed under this award. Stewardship activities include, but are not limited to, conducting site visits; reviewing performance and financial reports; providing technical assistance and/or temporary intervention in unusual circumstances to correct deficiencies which develop during the project; assuring compliance with terms and conditions; and reviewing technical performance after project completion to ensure that the award objectives have been accomplished. STATEMENT OF SUBSTANTIAL INVOLVEMENT DOE has substantial involvement in work performed under awards made as a result of this FOA. DOE does not limit its involvement to the administrative requirements of the award. Instead, DOE has substantial involvement in the direction and redirection of the technical aspects of the project as a whole. Substantial involvement includes, but is not limited to, the following: SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 11 1. DOE shares responsibility with the recipient for the management, control, direction, and performance of the project. 2. DOE may intervene in the conduct or performance of work under this award for programmatic reasons. Intervention includes the interruption or modification of the conduct or performance of project activities. 3. DOE may redirect or discontinue funding the project based on the outcome of DOE’s evaluation of the project at the Go/No-Go decision point(s) as identified in the Project Management Plan. 4. Reviewing and concurring with ongoing technical performance to ensure that adequate progress has been obtained within the current Budget Period authorized by DOE before work can commence on subsequent Budget Periods. 5. DOE participates in major project decision-making processes. SITE VISITS DOE/NNSA's authorized representatives have the right to make site visits at reasonable times to review project accomplishments and management control systems and to provide technical assistance, if required. You must provide, and must require your subrecipients to provide, reasonable access to facilities, office space, resources, and assistance for the safety and convenience of the government representatives in the performance of their duties. All site visits and evaluations must be performed in a manner that does not unduly interfere with or delay the work. REPORTING REQUIREMENTS (APRIL 2023) a. Requirements. The reporting requirements for this award are identified on the Federal Assistance Reporting Checklist, DOE F 4600.2, attached to this award. Failure to comply with these reporting requirements is considered a material noncompliance with the terms of the award. Noncompliance may result in withholding of future payments, suspension, or termination of the current award, and withholding of future awards. A willful failure to perform, a history of failure to perform, or unsatisfactory performance of this and/or other financial assistance awards, may also result in a debarment action to preclude future awards by Federal agencies. b. Dissemination of scientific/technical reporting products. Reporting project results in scientific and technical information (STI) publications/products to the DOE Office of Scientific and Technical Information (OSTI) ensures dissemination of research results to the public as well as preservation of the results. The DOE form F 4600.2, B. Scientific/Technical Reporting, has instructions for the DOE Energy Link (E-Link) system managed by OSTI. Scientific/technical reports and other STI products submitted under this award will be disseminated publicly on the Web via OSTI.GOV (https://www.osti.gov), unless the STI contains patentable material, protected data, or SBIR/STTR data, which must be indicated per instructions in DOE 4600.2. c. Restrictions. Restrictions. STI products submitted to the DOE via E-link must not contain any Protected Personally Identifiable Information (PII), limited rights data, classified information, information subject to export control classification, or other information not subject to public release. The Contracting Officer or Technical Project Officer should be contacted with any questions. Limited rights data means data (other than computer software) developed at private expense that embody trade secrets or are commercial or financial and confidential or privileged. SBIR/STTR Protected Data, and other data subject to statutory data protection SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 12 authorized by the award may be submitted, provided such data is properly marked and identified during submission. Submissions must not contain any “Proprietary”, “Confidential” or “Business Sensitive” markings or similar restrictive markings not authorized by the applicable government agreement.; it is acknowledged that DOE has the right to cancel or ignore such markings. PUBLICATIONS a. You are encouraged to publish or otherwise make publicly available the results of the work conducted under the award. b. An acknowledgment of Federal support and a disclaimer must appear in the publication of any material, whether copyrighted or not, based on or developed under this project, as follows: Acknowledgment: "This material is based upon work supported by the Department of Energy, Grid Deployment Office, under Award Number DE-GD0000XXX." Disclaimer: "This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof." FEDERAL, STATE, AND MUNICIPAL REQUIREMENTS You must obtain any required permits and comply with applicable federal, state, and municipal laws, codes, and regulations for work performed under this award. INTELLECTUAL PROPERTY PROVISIONS AND CONTACT INFORMATION a. The intellectual property provisions applicable to this award are provided as an attachment to this award or are referenced on the Assistance Agreement Face Page. A list of all intellectual property provisions may be found at http://energy.gov/gc/standard-intellectual-property-ip-provisions-financial-assistance-awards b. Questions regarding intellectual property matters should be referred to the DOE Award Administrator and the Patent Counsel designated as the service provider for the DOE office that issued the award. The IP Service Providers List is found at http://energy.gov/gc/downloads/intellectual-property-ip-service-providers-acquisition- and-assistance-transactions NOTICE REGARDING THE PURCHASE OF AMERICAN-MADE EQUIPMENT AND PRODUCTS -- SENSE OF CONGRESS It is the sense of the Congress that, to the greatest extent practicable, all equipment and products purchased with funds made available under this award should be American-made. SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 13 INSURANCE COVERAGE (DECEMBER 2014) See 2 CFR 200.310 for insurance requirements for real property and equipment acquired or improved with Federal funds. REAL PROPERTY (DECEMBER 2014) Subject to the conditions set forth in 2 CFR Part 200.311, title to real property acquired or improved under a Federal award will vest upon acquisition in the non-Federal entity. The non-Federal entity cannot encumber this property and must follow the requirements of 2 CFR Part 200.311 before disposing of the property. Except as otherwise provided by Federal statutes or by the Federal awarding agency, real property will be used for the originally authorized purpose as long as needed for that purpose. When real property is no longer needed for the originally authorized purpose, the non-Federal entity must obtain disposition instructions from the Federal awarding agency or pass-through entity. The instructions must provide for one of the following alternatives: (a) retain title after compensating the Federal awarding agency as described in 2 CFR Part 200.311(c)(1); (b) Sell the property and compensate the federal awarding agency as specified in CFR Part 200.311(c)(2); or (c) transfer title to the Federal awarding agency or to a third Party designated/approved by the Federal awarding agency as specified in CFR Part 200.311(c)(3). See 2 CFR Part 200.311 for additional requirements pertaining to real property acquired or improved under a Federal award. Also see 2 CFR Part 910.360 for amended requirements for Real Property for For-Profit recipients. EQUIPMENT (DECEMBER 2014) Subject to the conditions provided in 2 CFR Part 200.313, title to equipment (property) acquired under a Federal award will vest conditionally with the non-Federal entity. The non-Federal entity cannot encumber this property and must follow the requirements of 2 CFR Part 200.313 before disposing of the property. States must use equipment acquired under a Federal award by the state in accordance with state laws and procedures. Equipment must be used by the non-Federal entity in the program or project for which it was acquired as long as it is needed, whether or not the project or program continues to be supported by the Federal award. When no longer needed for the originally authorized purpose, the equipment may be used by programs supported by the Federal awarding agency in the priority order specified in 2 CFR Part 200.313(c)(1)(i) and (ii). Management requirements, including inventory and control systems, for equipment are provided in 2 CFR Part 200.313(d). When equipment acquired under a Federal award is no longer needed, the non-Federal entity must obtain disposition instructions from the Federal awarding agency or pass-through entity. SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 14 Disposition will be made as follows: (a) items of equipment with a current fair market value of $5,000 or less may be retained, sold, or otherwise disposed of with no further obligation to the Federal awarding agency; (b) Non-Federal entity may retain title or sell the equipment after compensating the Federal awarding agency as described in 2 CFR Part 200.313(e)(2); or (c) transfer title to the Federal awarding agency or to an eligible third Party as specified in CFR Part 200.313(e)(3). See 2 CFR Part 200.313 for additional requirements pertaining to equipment acquired under a Federal award. Also see 2 CFR Part 200.439 Equipment and other capital expenditures. See 2 CFR Part 910.360 for amended requirements for Equipment for For-Profit recipients. SUPPLIES (DECEMBER 2014) See 2 CFR Part 200.314 for requirements pertaining to supplies acquired under a Federal award. See also § 200.453 Materials and supplies costs, including costs of computing devices. INTANGIBLE PROPERTY (DECEMBER 2014) Title to intangible property (as defined in 2 CFR Part 200.59) acquired under a Federal award vests upon acquisition in the non-Federal entity. Intangible property includes trademarks, copyrights, patents and patent applications. See 2 CFR Part 200.315 for additional requirements pertaining to intangible property acquired under a Federal award. Also see 2 CFR Part 910.362 for amended requirements for Intellectual Property for For-Profit recipients. PROPERTY TRUST RELATIONSHIP (DECEMBER 2014) Real property, equipment, and intangible property, that are acquired or improved with a Federal award must be held in trust by the non-Federal entity as trustee for the beneficiaries of the project or program under which the property was acquired or improved. See 2 CFR Part 200.316 for additional requirements pertaining to real property, equipment, and intangible property acquired or improved under a Federal award. INSOLVENCY, BANKRUPTCY OR RECEIVERSHIP a. You shall immediately notify the DOE of the occurrence of any of the following events: (i) you or your parent's filing of a voluntary case seeking liquidation or reorganization under the Bankruptcy Act; (ii) your consent to the institution of an involuntary case under the Bankruptcy Act against you or your parent; (iii) the filing of any similar proceeding for or against you or your parent, or its consent to, the dissolution, winding-up or readjustment of your debts, appointment of a receiver, conservator, trustee, or other officer with similar powers over you, under any other applicable state or federal law; or (iv) your insolvency due to your inability to pay your debts generally as they become due. SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 15 b. Such notification shall be in writing and shall: (i) specifically set out the details of the occurrence of an event referenced in paragraph a; (ii) provide the facts surrounding that event; and (iii) provide the impact such event will have on the project being funded by this award. c. Upon the occurrence of any of the four events described in the first paragraph, DOE reserves the right to conduct a review of your award to determine your compliance with the required elements of the award (including such items as cost share, progress towards technical project objectives, and submission of required reports). If the DOE review determines that there are significant deficiencies or concerns with your performance under the award, DOE reserves the right to impose additional requirements, as needed, including (i) change your payment method; or (ii) institute payment controls. d. Failure of the Recipient to comply with this term may be considered a material noncompliance of this financial assistance award by the Contracting Officer. PERFORMANCE OF WORK IN UNITED STATES The Recipient agrees that at least 100% of the direct labor cost for the project (including subrecipient labor) shall be incurred in the United States, unless the Recipient can demonstrate to the satisfaction of the Department of Energy that the United States economic interest will be better served through a greater percentage of the work being performed outside the United States. CATEGORICAL EXCLUSION (CX) DOE must comply with the National Environmental Policy Act (NEPA) prior to authorizing the use of federal funds. Based on all information provided by the Recipient, DOE has made a NEPA determination by issuing a CX, thereby authorizing use of funds for the defined project activities. If the Recipient later adds to or modifies the activities reviewed and approved under the original DOE NEPA determination, the Recipient must notify the DOE Contracting Officer before proceeding with the new and/or modified activities. Those additions or modifications may be subject to review by the DOE NEPA Compliance Officer and approval by the DOE Contracting Officer, and may require a new NEPA determination. [insert any special conditions, if applicable] DECONTAMINATION AND/OR DECOMMISSIONING (D &D) COSTS Notwithstanding any other terms of this Agreement, the Government shall not be responsible for or have any obligation to the recipient for (i) Decontamination and/or Decommissioning (D&D) of any of the recipient's facilities, or (ii) any costs which may be incurred by the recipient in connection with the D&D of any of its facilities due to the performance of the work under this Agreement, whether said work was performed prior to or subsequent to the effective date of this Agreement. SYSTEM FOR AWARD MANAGEMENT AND UNIVERSAL IDENTIFIER REQUIREMENTS A. Requirement for System for Award Management (SAM) Unless exempted from this requirement under 2 CFR 25.110, the prime recipient must remain registered and maintain current information in SAM for the entire period of performance of the award. This includes providing information on the prime recipient’s immediate and highest level owner and subsidiaries, as well as on all of its predecessors that have been awarded a Federal contract or Federal financial assistance agreements within the last three years, if applicable, until the prime SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 16 recipient submits the final financial report required under this award or receives the final payment, whichever is later. This requires the prime recipient to review its information in SAM at least annually after the initial registration, and to update its information as soon as there are changes. Reviews and updates may be required more frequently due to changes in recipient information or as required by another award term. B. Requirement for Unique Entity Identifier If authorized to make subawards under this award, the prime recipient: 1. Must notify potential subrecipients that no entity (see definition in paragraph C of this award term) may receive a subaward until the entity has provided its unique entity identifier to the prime recipient. 2. Must not make a subaward to an entity unless the entity has provided its unique entity identifier to the prime recipient. Subrecipients are not required to obtain an active SAM registration, but must obtain a unique entity identifier. C. Definitions For purposes of this term: 1. System for Award Management (SAM) means the Federal repository into which a recipient must provide information required for the conduct of business as a recipient. Additional information about registration procedures may be found at the SAM internet site (currently at https://www.sam.gov). 2. Unique Entity Identifier means the identifier assigned by SAM to uniquely identify business entities. 3. Entity includes non-Federal entities as defined at 2 CFR 200.1 and also includes all of the following for purposes of this part: a. A foreign organization; b. A foreign public entity; c. A domestic for-profit organization; and d. A Federal agency. 4. Subaward has the meaning given in 2 CFR 200.1. 5. Subrecipient has the meaning given in 2 CFR 200.1. FINAL INCURRED COST AUDIT (DECEMBER 2014) In accordance with 2 CFR Part 200 as amended by 2 CFR Part 910, DOE reserves the right to initiate a final incurred cost audit on this award. If the audit has not been performed or completed prior to the closeout of the award, DOE retains the right to recover an appropriate amount after fully considering the recommendations on disallowed costs resulting from the final audit. LOBBYING RESTRICTIONS (MARCH 2012) SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 17 By accepting funds under this award, you agree that none of the funds obligated on the award shall be expended, directly or indirectly, to influence congressional action on any legislation or appropriation matters pending before Congress, other than to communicate to Members of Congress as described in 18 U.S.C. 1913. This restriction is in addition to those prescribed elsewhere in statute and regulation. CORPORATE FELONY CONVICTION AND FEDERAL TAX LIABILITY ASSURANCES (MARCH 2014) By entering into this agreement, the undersigned attests that [] has not been convicted of a felony criminal violation under Federal law in the 24 months preceding the date of signature. The undersigned further attests that [] does not have any unpaid Federal tax liability that has been assessed, for which all judicial and administrative remedies have been exhausted or have lapsed, and that is not being paid in a timely manner pursuant to an agreement with the authority responsible for collecting the tax liability. For purposes of these assurances, the following definitions apply: A Corporation includes any entity that has filed articles of incorporation in any of the 50 states, the District of Columbia, or the various territories of the United States [but not foreign corporations]. It includes both for- profit and non-profit organizations. NONDISCLOSURE AND CONFIDENTIALITY AGREEMENTS ASSURANCES (JUNE 2015) (1) By entering into this agreement, the undersigned attests that [] does not and will not require its employees or contractors to sign internal nondisclosure or confidentiality agreements or statements prohibiting or otherwise restricting its employees or contactors from lawfully reporting waste, fraud, or abuse to a designated investigative or law enforcement representative of a Federal department or agency authorized to receive such information. (2) The undersigned further attests that [] does not and will not use any Federal funds to implement or enforce any nondisclosure and/or confidentiality policy, form, or agreement it uses unless it contains the following provisions: a.‘‘These provisions are consistent with and do not supersede, conflict with, or otherwise alter the employee obligations, rights, or liabilities created by existing statute or Executive order relating to (1) classified information, (2) communications to Congress, (3) the reporting to an Inspector General of a violation of any law, rule, or regulation, or mismanagement, a gross waste of funds, an abuse of authority, or a substantial and specific danger to public health or safety, or (4) any other whistleblower protection. The definitions, requirements, obligations, rights, sanctions, and liabilities created by controlling Executive orders and statutory provisions are incorporated into this agreement and are controlling.’’ b. The limitation above shall not contravene requirements applicable to Standard Form 312, Form 4414, or any other form issued by a Federal department or agency governing the nondisclosure of classified information. c. Notwithstanding provision listed in paragraph (a), a nondisclosure or confidentiality policy form or agreement that is to be executed by a person connected with the conduct of an intelligence or intelligence- related activity, other than an employee or officer of the United States Government, may contain provisions appropriate to the particular activity for which such document is to be used. Such form or agreement shall, at a SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 18 minimum, require that the person will not disclose any classified information received in the course of such activity unless specifically authorized to do so by the United States Government. Such nondisclosure or confidentiality forms shall also make it clear that they do not bar disclosures to Congress, or to an authorized official of an executive agency or the Department of Justice, that are essential to reporting a substantial violation of law. REPORTING OF MATTERS RELATED TO RECIPIENT INTEGRITY AND PERFORMANCE (DECEMBER 2015) a. General Reporting Requirement If the total value of your currently active grants, cooperative agreements, and procurement contracts from all Federal awarding agencies exceeds $10,000,000 for any period of time during the period of performance of this Federal award, then you as the recipient during that period of time must maintain the currency of information reported to the System for Award Management (SAM) that is made available in the designated integrity and performance system (currently the Federal Awardee Performance and Integrity Information System (FAPIIS)) about civil, criminal, or administrative proceedings described in paragraph 2 of this award term and condition. This is a statutory requirement under section 872 of Public Law 110-417, as amended (41 U.S.C. 2313). As required by section 3010 of Public Law 111-212, all information posted in the designated integrity and performance system on or after April 15, 2011, except past performance reviews required for Federal procurement contracts, will be publicly available. b. Proceedings About Which You Must Report Submit the information required about each proceeding that: 1. Is in connection with the award or performance of a grant, cooperative agreement, or procurement contract from the Federal Government; 2. Reached its final disposition during the most recent five year period; and 3. Is one of the following: (A) A criminal proceeding that resulted in a conviction, as defined in paragraph 5 of this award term and condition; (B) A civil proceeding that resulted in a finding of fault and liability and payment of a monetary fine, penalty, reimbursement, restitution, or damages of $5,000 or more; (C) An administrative proceeding, as defined in paragraph 5. of this award term and condition, that resulted in a finding of fault and liability and your payment of either a monetary fine or penalty of $5,000 or more or reimbursement, restitution, or damages in excess of $100,000; or (D) Any other criminal, civil, or administrative proceeding if: (i) It could have led to an outcome described in paragraph 2.c.(1), (2), or (3) of this award term and condition; SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 19 (ii) It had a different disposition arrived at by consent or compromise with an acknowledgment of fault on your part; and (iii) The requirement in this award term and condition to disclose information about the proceeding does not conflict with applicable laws and regulations. c. Reporting Procedures Enter in the SAM Entity Management area the information that SAM requires about each proceeding described in paragraph 2 of this award term and condition. You do not need to submit the information a second time under assistance awards that you received if you already provided the information through SAM because you were required to do so under Federal procurement contracts that you were awarded. d. Reporting Frequency During any period of time when you are subject to the requirement in paragraph 1 of this award term and condition, you must report proceedings information through SAM for the most recent five year period, either to report new information about any proceeding(s) that you have not reported previously or affirm that there is no new information to report. Recipients that have Federal contract, grant, and cooperative agreement awards with a cumulative total value greater than $10,000,000 must disclose semiannually any information about the criminal, civil, and administrative proceedings. e. Definitions For purposes of this award term and condition: 1. Administrative proceeding means a non-judicial process that is adjudicatory in nature in order to make a determination of fault or liability (e.g., Securities and Exchange Commission Administrative proceedings, Civilian Board of Contract Appeals proceedings, and Armed Services Board of Contract Appeals proceedings). This includes proceedings at the Federal and State level but only in connection with performance of a Federal contract or grant. It does not include audits, site visits, corrective plans, or A. Reporting of Matters Related to Recipient Integrity and Performance. 2. Conviction, for purposes of this award term and condition, means a judgment or conviction of a criminal offense by any court of competent jurisdiction, whether entered upon a verdict or a plea, and includes a conviction entered upon a plea of nolo contendere. 3. Total value of currently active grants, cooperative agreements, and procurement contracts includes— (A) Only the Federal share of the funding under any Federal award with a recipient cost share or match; and (B) The value of all expected funding increments under a Federal award and options, even if not yet exercised. SUBAWARD/SUBCONTRACT CHANGE NOTIFICATION Except for subawards and/or subcontracts specifically proposed as part of the Recipient’s Application for award, the Recipient must notify the DOE Contracting Officer and Project Officer in writing 30 days prior to SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 20 the execution of new or modified subawards/subcontracts. This notification does not constitute a waiver of the prior approval requirements outlined in 2 CFR 200, nor does it relieve the Recipient from its obligation to comply with applicable Federal statutes, regulations, and executive orders. In order to satisfy this notification requirement, Recipient documentation must, as a minimum, include the following: 1. A description of the research to be performed, the service to be provided, or the equipment to be purchased; 2. Cost share commitment letter if the subawardee is providing cost share to the award; 3. Updated budget justification, budget pages; 4. An assurance that the process undertaken by the Recipient to solicit the subaward/subcontract complies with their written procurement procedures as outlined in 2 CFR 200.317 through 200.327. 5. An assurance that no planned, actual or apparent conflict of interest exists between the Recipient and the selected subawardee/subcontractor and that the Recipient’s written standards of conduct were followed;1 6. A completed Environmental Questionnaire, if applicable; 7. An assurance that the subawardee/subcontractor is not a debarred or suspended entity; and 8. An assurance that all required award provisions will be flowed down in the resulting subaward/subcontract. The Recipient is responsible for making a final determination to award or modify subawards/subcontracts under this agreement, but the Recipient may not proceed with the subaward/subcontract until the Contracting Officer determines, and provides the Recipient written notification, that the information provided is adequate. Should the Recipient not receive a written notification of adequacy from the Contracting Officer within 30 days of the submission of the subaward/subcontract documentation stipulated above, Recipient may proceed to award or modify the proposed subaward/subcontract. GO/NO-GO DECISION The Government has elected to include a go/no-go decision in the Statement of Project Objectives (SOPO) of the award. If it is advantageous for the Government to proceed beyond the technical milestone(s) set forth in the SOPO, the Contracting Officer will notify the recipient in writing authorizing the recipient to proceed beyond the technical milestone(s) in the SOPO. If it is determined that it would not be advantageous for the Government to proceed beyond the technical milestone(s), the Contracting Officer will notify the recipient in 1 It is DOE’s position that the existence of a “covered relationship” as defined in 5 C.F.R. § 2635.502(a)&(b) between a member of the Recipient’s owners or senior management and a member of a subawardee’s/subcontractor’s owners or senior management creates at a minimum an apparent conflict of interest that would require the Recipient to notify the Contracting Officer and provide detailed information and justification (including, for example, mitigation measures) as to why the subaward or subcontract does not create an actual conflict of interest. Recipients must also notify the Contracting Officer of any new subcontract or subaward to: (1) an entity that is owned or otherwise controlled by the Recipient; or (2) an entity that is owned or otherwise controlled by another entity that also owns or otherwise controls the Recipient, as it is DOE’s position that these situations also create at a minimum an apparent conflict of interest. SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 21 writing of such decision and the award is considered completed. The maximum liability to the Government is limited to the allowable, allocable, and reasonableness of the cost incurred by the recipient within the funds made available. The Government reserves the right to deobligate any remaining funds from the award. The recipient shall submit all final deliverables, including a final scientific/technical report, for the completed work in accordance with the reporting requirements of the award. IMPLEMENTATION OF EXECUTIVE ORDER 13798, PROMOTING FREE SPEECH AND RELIGIOUS LIBERTY (NOVEMBER 2020) States, local governments, or other public entities may not condition sub-awards in a manner that would discriminate, or disadvantage sub-recipients based on their religious character. CONTINUED USE OF REAL PROPERTY AND EQUIPMENT (OCTOBER 2022) Real property and equipment purchased with project funds (federal share and recipient cost share) under this Award are subject to the requirements at 2 CFR 200.311, 200.313, and 200.316 (non-Federal entities, except for-profit entities) and 2 CFR 910.360 (for-profit entities). The Recipient may continue to use the real property and equipment after the conclusion of the award period of performance so long as the Recipient: a. Continues to use the property for the authorized project purposes; b. Complies with the applicable reporting requirements and regulatory property standards; c. As applicable to for-profit entities, UCC filing statements are maintained; and d. Submits a written Request for Continued Use for DOE authorization, which is approved by the DOE Contracting Officer. The Recipient must request authorization from the Contracting Officer to continue to use the property for the authorized project purposes beyond the award period of performance (“Request for Continued Use”). The Recipient’s written Request for Continued Use must identify the property and include: a summary of how the property will be used (must align with the authorized project purposes); a proposed use period (e.g., perpetuity, until fully depreciated, or a calendar date where the Recipient expects to submit disposition instructions); acknowledgement that the recipient shall not sell or encumber the property or permit any encumbrance without prior written DOE approval; current fair market value of the property; and an Estimated Useful Life or depreciation schedule for equipment. When the property is no longer needed for authorized project purposes, the Recipient must request disposition instructions from DOE. For-profit entity disposition requirements are set forth at 2 CFR 910.360. Property disposition requirements for other non-federal entities are set forth in 2 CFR 200.310 through 200.316. FOREIGN NATIONAL PARTICIPATION – APPROVAL REQUIRED (MARCH 2023) If the Recipient (including any of its subrecipients and contractors) anticipates involving foreign nationals in the performance of this award, the Recipient must provide DOE with specific information about each foreign national to ensure compliance with the requirements for foreign national participation and access approvals. The volume and type of information required may depend on various factors associated with the award. SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 22 Approval for foreign nationals in Principal Investigator/Co-Principal Investigator roles, from countries of risk (i.e., China, Iran, North Korea, and Russia), and from countries identified on the U.S. Department of State’s list of State Sponsors of Terrorism (https://www.state.gov/state-sponsors-of-terrorism/) must be obtained from DOE before they can participate in the performance of any work under this award. A “foreign national” is defined as any person who is not a United States citizen by birth or naturalization. DOE may elect to deny a foreign national’s participation in the award. Likewise, DOE may elect to deny a foreign national’s access to a DOE sites, information, technologies, equipment, programs, or personnel. DOE’s determination to deny participation or access is not appealable. The Recipient must include this term in any subaward and in any applicable contractual agreement(s) associated with this award. POST AWARD DUE DILIGENCE REVIEWS (SEPTEMBER 2023) During the period of performance of the Award, DOE may conduct ongoing due diligence reviews, through Government resources, to identify potential risks of undue foreign influence. In the event a risk is identified, DOE may require risk mitigation measures, including but not limited to, requiring an individual or entity not participate in the Award. EXPORT CONTROL (MARCH 2023) The United States government regulates the transfer of information, commodities, technology, and software considered to be strategically important to the U.S. to protect national security, foreign policy, and economic interests without imposing undue regulatory burdens on legitimate international trade. There is a network of Federal agencies and regulations that govern exports that are collectively referred to as “Export Controls.” The Recipient is responsible for ensuring compliance with all applicable United States Export Control laws and regulations relating to any work performed under the award. The Recipient must immediately report to DOE any export control violations related to the project funded under this award, at the recipient or subrecipient level, and provide the corrective action(s) to prevent future violations. INTERIM CONFLICT OF INTEREST POLICY FOR FINANCIAL ASSISTANCE (MARCH 2023) The DOE interim Conflict of Interest Policy for Financial Assistance (COI Policy) can be found at https://www.energy.gov/management/department-energy-interim-conflict-interest-policy-requirements- financial-assistance. This policy is applicable to all non-Federal entities applying for, or that receive, DOE funding by means of a financial assistance award (e.g., a grant, cooperative agreement, or technology investment agreement) and, through the implementation of this policy by the entity, to each Investigator who is planning to participate in, or is participating in, the project funded wholly or in part under this Award. The term “Investigator” means the PI and any other person, regardless of title or position, who is responsible for the purpose, design, conduct, or reporting of a project funded by DOE or proposed for funding by DOE. The Recipient must flow down the requirements of the interim COI Policy to any subrecipient non-Federal entities, with the exception of DOE National Laboratories. Further, the Recipient must identify all financial conflicts of interests (FCOI), i.e., managed and unmanaged/ unmanageable, in its initial and ongoing FCOI reports. SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 23 Prior to award, the Recipient was required to: 1) ensure all Investigators on this Award completed their significant financial disclosures; 2) review the disclosures; 3) determine whether a FCOI exists; 4) develop and implement a management plan for FCOIs; and 5) provide DOE with an initial FCOI report that includes all FCOIs (i.e., managed and unmanaged/unmanageable). Within 180 days of the date of the Award, the Recipient must be in full compliance with the other requirements set forth in DOE’s interim COI Policy. ORGANIZATIONAL CONFLICT OF INTEREST (MARCH 2023) Organizational conflicts of interest are those where, because of relationships with a parent company, affiliate, or subsidiary organization, the Recipient is unable or appears to be unable to be impartial in conducting procurement action involving a related organization (2 CFR 200.318(c)(2)). The Recipient must disclose in writing any potential or actual organizational conflict of interest to the DOE Contracting Officer. The Recipient must provide the disclosure prior to engaging in a procurement or transaction using project funds with a parent, affiliate, or subsidiary organization that is not a state, local government, or Indian tribe. For a list of the information that must be included the disclosure, see Section VI. of the DOE interim Conflict of Interest Policy for Financial Assistance at https://www.energy.gov/management/department-energy-interim-conflict-interest-policy-requirements- financial-assistance. If the effects of the potential or actual organizational conflict of interest cannot be avoided, neutralized, or mitigated, the Recipient must procure goods and services from other sources when using project funds. Otherwise, DOE may terminate the Award in accordance with 2 CFR 200.340 unless continued performance is determined to be in the best interest of the Federal government. The Recipient must flow down the requirements of the interim COI Policy to any subrecipient non-Federal entities, with the exception of DOE National Laboratories. The Recipient is responsible for ensuring subrecipient compliance with this term. If the Recipient has a parent, affiliate, or subsidiary organization that is not a state, local government, or Indian tribe, the Recipient must maintain written standards of conduct covering organizational conflicts of interest. BUY AMERICAN REQUIREMENT FOR INFRASTRUCTURE PROJECTS (MARCH 2023) A. Definitions Components are defined as the articles, materials, or supplies incorporated directly into the end manufactured product(s). Construction Materials are an article, material, or supply—other than an item primarily of iron or steel; a manufactured product; cement and cementitious materials; aggregates such as stone, sand, or gravel; or aggregate binding agents or additives—that is used in an infrastructure project and is or consists primarily of non-ferrous metals, plastic and polymer-based products (including polyvinylchloride, composite building materials, and polymers used in fiber optic cables), glass (including optic glass), lumber, drywall, coatings (paints and stains), optical fiber, clay brick; composite building materials; or engineered wood products. SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 24 Domestic Content Procurement Preference Requirement- means a requirement that no amounts made available through a program for federal financial assistance may be obligated for an infrastructure project unless— (A) all iron and steel used in the project are produced in the United States; (B) the manufactured products used in the project are produced in the United States; or (C) the construction materials used in the project are produced in the United States. Also referred to as the Buy America Requirement. Infrastructure includes, at a minimum, the structures, facilities, and equipment located in the United States, for: roads, highways, and bridges; public transportation; dams, ports, harbors, and other maritime facilities; intercity passenger and freight railroads; freight and intermodal facilities; airports; water systems, including drinking water and wastewater systems; electrical transmission facilities and systems; utilities; broadband infrastructure; and buildings and real property; and generation, transportation, and distribution of energy -including electric vehicle (EV) charging. The term “infrastructure” should be interpreted broadly, and the definition provided above should be considered as illustrative and not exhaustive. Manufactured Products are items used for an infrastructure project made up of components that are not primarily of iron or steel; construction materials; cement and cementitious materials’ aggregates such as stone, sand, or gravel; or aggregate binding agents or additives. Primarily of iron or steel means greater than 50% iron or steel, measured by cost. Project- means the construction, alteration, maintenance, or repair of infrastructure in the United States. Public- The Buy America Requirement does not apply to non-public infrastructure. For purposes of this guidance, infrastructure should be considered “public” if it is: (1) publicly owned or (2) privately owned but utilized primarily for a public purpose. Infrastructure should be considered to be “utilized primarily for a public purpose” if it is privately operated on behalf of the public or is a place of public accommodation. B. Buy America Requirement None of the funds provided under this award (federal share or recipient cost-share) may be used for a project for infrastructure unless: 1. All iron and steel used in the project is produced in the United States—this means all manufacturing processes, from the initial melting stage through the application of coatings, occurred in the United States; 2. All manufactured products used in the project are produced in the United States—this means the manufactured product was manufactured in the United States; and the cost of the components of the manufactured product that are mined, produced, or manufactured in the United States is greater than 55 percent of the total cost of all components of the SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 25 manufactured product, unless another standard for determining the minimum amount of domestic content of the manufactured product has been established under applicable law or regulation; and 3. All construction materials are manufactured in the United States—this means that all manufacturing processes for the construction material occurred in the United States. The Buy America Requirement only applies to articles, materials, and supplies that are consumed in, incorporated into, or permanently affixed to an infrastructure project. As such, it does not apply to tools, equipment, and supplies, such as temporary scaffolding, brought into the construction site and removed at or before the completion of the infrastructure project. Nor does a Buy America Requirement apply to equipment and furnishings, such as movable chairs, desks, and portable computer equipment, that are used at or within the finished infrastructure project but are not an integral part of the structure or permanently affixed to the infrastructure project. Recipients are responsible for administering their award in accordance with the terms and conditions, including the Buy America Requirement. The recipient must ensure that the Buy America Requirement flows down to all subawards and that the subawardees and subrecipients comply with the Buy America Requirement. The Buy America Requirement term and condition must be included all sub-awards, contracts, subcontracts, and purchase orders for work performed under the infrastructure project. C. Certification of Compliance The Recipient must certify or provide equivalent documentation for proof of compliance that a good faith effort was made to solicit bids for domestic products used in the infrastructure project under this Award. The Recipient must also maintain certifications or equivalent documentation for proof of compliance that those articles, materials, and supplies that are consumed in, incorporated into, affixed to, or otherwise used in the infrastructure project, not covered by a waiver or exemption, are produced in the United States. The certification or proof of compliance must be provided by the suppliers or manufacturers of the iron, steel, manufactured products and construction materials and flow up from all subawardees, contractors and vendors to the Recipient. The Recipient must keep these certifications with the award/project files and be able to produce them upon request from DOE, auditors or Office of Inspector General. D. Waivers When necessary, the Recipient may apply for, and DOE may grant, a waiver from the Buy America Requirement. Requests to waive the application of the Buy America Requirement must be in writing to the Contracting Officer. Waiver requests are subject to review by DOE and the Office of Management and Budget, as well as a public comment period of no less than 15 calendar days. Waivers must be based on one of the following justifications: SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 26 1. Public Interest- Applying the Buy America Requirement would be inconsistent with the public interest; 2. Non-Availability- The types of iron, steel, manufactured products, or construction materials are not produced in the United States in sufficient and reasonably available quantities or of a satisfactory quality; or 3. Unreasonable Cost- The inclusion of iron, steel, manufactured products, or construction materials produced in the United States will increase the cost of the overall project by more than 25 percent. Requests to waive the Buy America Requirement must include the following: • Waiver type (Public Interest, Non-Availability, or Unreasonable Cost); • Recipient name and Unique Entity Identifier (UEI); • Award information (Federal Award Identification Number, Assistance Listing number); • A brief description of the project, its location, and the specific infrastructure involved; • Total estimated project cost, with estimated federal share and recipient cost share breakdowns; • Total estimated infrastructure costs, with estimated federal share and recipient cost share breakdowns; • List and description of iron or steel item(s), manufactured goods, and/or construction material(s) the recipient seeks to waive from the Buy America Preference, including name, cost, quantity(ies), country(ies) of origin, and relevant Product Service Codes (PSC) and North American Industry Classification System (NAICS) codes for each; • A detailed justification as to how the non-domestic item(s) is/are essential the project; • A certification that the recipient made a good faith effort to solicit bids for domestic products supported by terms included in requests for proposals, contracts, and non-proprietary communications with potential suppliers; • A justification statement—based on one of the applicable justifications outlined above—as to why the listed items cannot be procured domestically, including the due diligence performed (e.g., market research, industry outreach, cost analysis, cost-benefit analysis) by the recipient to attempt to avoid the need for a waiver. This justification may cite, if applicable, the absence of any Buy America-compliant bids received for domestic products in response to a solicitation; and • Anticipated impact to the project if no waiver is issued. The Recipient should consider using the following principles as minimum requirements contained in their waiver request: • Time-limited: Consider a waiver constrained principally by a length of time, rather than by the specific project/award to which it applies. Waivers of this type may be appropriate, for example, when an item that is “non-available” is widely used in the project. When requesting such a waiver, the Recipient should identify a reasonable, definite time frame (e.g., no more than one to two years) designed so that the waiver is reviewed to ensure the condition for the SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 27 waiver (“non-availability”) has not changed (e.g., domestic supplies have become more available). • Targeted: Waiver requests should apply only to the item(s), product(s), or material(s) or category(ies) of item(s), product(s), or material(s) as necessary and justified. Waivers should not be overly broad as this will undermine domestic preference policies. • Conditional: The Recipient may request a waiver with specific conditions that support the policies of IIJA/BABA and Executive Order 14017. DOE may request, and the Recipient must provide, additional information for consideration of this wavier. DOE may reject or grant waivers in whole or in part depending on its review, analysis, and/or feedback from OMB or the public. DOEs final determination regarding approval or rejection of the waiver request may not be appealed. Waiver requests may take up to 90 calendar days to process. PROHIBITION ON CERTAIN TELECOMMUNICATIONS AND VIDEO SURVEILLANCE SERVICES OR EQUIPMENT (MARCH 2023) As set forth in 2 CFR 200.216, recipients and subrecipients are prohibited from obligating or expending project funds (Federal and non-Federal funds) to: (1) Procure or obtain; (2) Extend or renew a contract to procure or obtain; or (3) Enter into a contract (or extend or renew a contract) to procure or obtain equipment, services, or systems that uses covered telecommunications equipment or services as a substantial or essential component of any system, or as critical technology as part of any system. As described in Public Law 115- 232, section 889, covered telecommunications equipment is telecommunications equipment produced by Huawei Technologies Company or ZTE Corporation (or any subsidiary or affiliate of such entities). (i) For the purpose of public safety, security of government facilities, physical security surveillance of critical infrastructure, and other national security purposes, video surveillance and telecommunications equipment produced by Hytera Communications Corporation, Hangzhou Hikvision Digital Technology Company, or Dahua Technology Company (or any subsidiary or affiliate of such entities). (ii) Telecommunications or video surveillance services provided by such entities or using such equipment. (iii) Telecommunications or video surveillance equipment or services produced or provided by an entity that the Secretary of Defense, in consultation with the Director of the National Intelligence or the Director of the Federal Bureau of Investigation, reasonably believes to be an entity owned or controlled by, or otherwise connected to, the government of a covered foreign country. See Public Law 115-232, section 889 for additional information. SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 28 PROHIBITION RELATED TO FOREIGN GOVERNMENT-SPONSORED TALENT RECRUITMENT PROGRAMS (MARCH 2023) A. Prohibition Persons participating in a Foreign Government-Sponsored Talent Recruitment Program of a Foreign Country of Risk are prohibited from participating in this Award. The Recipient must exercise ongoing due diligence to reasonably ensure that no individuals participating on the DOE-funded project are participating in a Foreign Government-Sponsored Talent Recruitment Program of a Foreign Country of Risk. Consequences for violations of this prohibition will be determined according to applicable law, regulations, and policy. Further, the Recipient must notify DOE within five (5) business days upon learning that an owner of the Recipient or subrecipient or individual on the project team is or is believed to be participating in a Foreign Government-Sponsored Talent Recruitment Program of a Foreign Country of Risk. DOE may modify and add requirements related to this prohibition to the extent required by law. B. Definitions 1. Foreign Government-Sponsored Talent Recruitment Program. An effort directly or indirectly organized, managed, or funded by a foreign government, or a foreign government instrumentality or entity, to recruit science and technology professionals or students (regardless of citizenship or national origin, or whether having a full-time or part-time position). Some foreign government-sponsored talent recruitment programs operate with the intent to import or otherwise acquire from abroad, sometimes through illicit means, proprietary technology or software, unpublished data and methods, and intellectual property to further the military modernization goals and/or economic goals of a foreign government. Many, but not all, programs aim to incentivize the targeted individual to relocate physically to the foreign state for the above purpose. Some programs allow for or encourage continued employment at United States research facilities or receipt of federal research funds while concurrently working at and/or receiving compensation from a foreign institution, and some direct participants not to disclose their participation to U.S. entities. Compensation could take many forms including cash, research funding, complimentary foreign travel, honorific titles, career advancement opportunities, promised future compensation, or other types of remuneration or consideration, including in-kind compensation. 2. Foreign Country of Risk. DOE has designated the following countries as foreign countries of risk: Iran, North Korea, Russia, and China. This list is subject to change. PARTICIPANTS AND OTHER COLLABORATING ORGANIZATIONS (SEPTEMBER 2023) Prior to award, the Recipient was required to provide the following information on participants and other collaborating organizations. If there are any changes to Participants and Collaborating Organizations information previously submitted to DOE, the Recipient must submit updated information within thirty (30) calendar days after the end of the quarterly reporting period in which the change occurred: A. What individuals have worked on the project Provide the following information for individuals at the prime recipient and subrecipient level: (1) all senior and key personnel; and (2) each person who has worked or is expected to work at least one SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 29 person month per year on the project regardless of the source of compensation (a person month equals approximately 160 hours of effort). i. Name ii. Organization iii. Job Title iv. Role in the project v. Start and end date (month and year) working on the project vi. State, U.S. territory, and/or country of residence vii. Whether this person collaborated with an individual or entity located in a foreign country in connection with the scope of this Award, and viii. If yes to vii, whether the person traveled to the foreign country as part of that collaboration, and, if so, where and what the duration of stay was. B. Organizations Identify all subrecipients, contractors, U.S. National Laboratories, partners, and collaborating organizations. Recipients must also include all foreign collaborators as outline din the Foreign Collaboration Considerations term of the award Terms and Conditions. For each, provide name, UEI, zip code or latitude/longitude, role in the project, contribution to the project and start and end date. HUMAN SUBJECTS RESEARCH (MARCH 2023) Research involving human subjects, biospecimens, or identifiable private information conducted with Department of Energy (DOE) funding is subject to the requirements of DOE Order 443.1C, Protection of Human Research Subjects, 45 CFR Part 46, Protection of Human Subjects (subpart A which is referred to as the “Common Rule”), and 10 CFR Part 745, Protection of Human Subjects. Federal regulation and the DOE Order require review by an Institutional Review Board (IRB) of all proposed human subjects research projects. The IRB is an interdisciplinary ethics board responsible for ensuring that the proposed research is sound and justifies the use of human subjects or their data; the potential risks to human subjects have been minimized; participation is voluntary; and clear and accurate information about the study, the benefits and risks of participating, and how individuals’ data/specimens will be protected/used, is provided to potential participants for their use in determining whether or not to participate. The Recipient shall provide the Federal Wide Assurance number identified in item 1 below and the certification identified in item 2 below to DOE prior to initiation of any project that will involve interactions with humans in some way (e.g., through surveys); analysis of their identifiable data (e.g., demographic data and energy use over time); asking individuals to test devices, products, or materials developed through research; and/or testing of commercially available devices in buildings/homes in which humans will be present. Note: This list of examples is illustrative and not all inclusive. No DOE funded research activity involving human subjects, biospecimens, or identifiable private information shall be conducted without: SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 30 1) A registration and a Federal Wide Assurance of compliance accepted by the Office of Human Research Protection (OHRP) in the Department of Health and Human Services; and 2) Certification that the research has been reviewed and approved by an Institutional Review Board (IRB) provided for in the assurance. IRB review may be accomplished by the awardee’s institutional IRB; by the Central DOE IRB; or if collaborating with one of the DOE national laboratories, by the DOE national laboratory IRB. The Recipient is responsible for ensuring all subrecipients comply and for reporting information on the project annually to the DOE Human Subjects Research Database (HSRD) at https://science.osti.gov/HumanSubjects/Human-Subjects-Database/home. Note: If a DOE IRB is used, no end of year reporting will be needed. Additional information on the DOE Human Subjects Research Program can be found at: https://science.osti.gov/ber/human-subjects. FRAUD, WASTE AND ABUSE (MARCH 2023) The mission of the DOE Office of Inspector General (OIG) is to strengthen the integrity, economy and efficiency of DOE’s programs and operations including deterring and detecting fraud, waste, abuse and mismanagement. The OIG accomplishes this mission primarily through investigations, audits, and inspections of Department of Energy activities to include grants, cooperative agreements, loans, and contracts. The OIG maintains a Hotline for reporting allegations of fraud, waste, abuse, or mismanagement. To report such allegations, please visit https://www.energy.gov/ig/ig‐hotline. Additionally, the Recipient must be cognizant of the requirements of 2 CFR 200.113 Mandatory disclosures, which states: The non‐Federal entity or applicant for a Federal award must disclose, in a timely manner, in writing to the Federal awarding agency or pass‐through entity all violations of Federal criminal law involving fraud, bribery, or gratuity violations potentially affecting the Federal award. Non‐Federal entities that have received a Federal award including the term and condition outlined in appendix XII of 2 CFR Part 200 are required to report certain civil, criminal, or administrative proceedings to SAM (currently FAPIIS). Failure to make required disclosures can result in any of the remedies described in § 200.339. (See also 2 CFR part 180, 31 U.S.C. 3321, and 41 U.S.C. 2313.) TRANSPARENCY OF FOREIGN CONNECTIONS (SEPTEMBER 2023) The Recipient must notify the DOE Contracting Officer within fifteen (15) business days of learning of the following circumstances in relation to the Recipient and subrecipients: 1. Any current or pending subsidiary, foreign business entity, or offshore entity that is based in or funded by any foreign country of risk or foreign entity based in a country of risk; SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 31 2. Any current or pending contractual or financial obligation or other agreement specific to a business arrangement, or joint venture-like arrangement with an entity owned by a country of risk or foreign entity based in a country of risk; 3. Any current or pending change in ownership structure of the Recipient or subrecipients that increases foreign ownership related to a country of risk. Each notification shall be accompanied by a complete and up-to-date capitalization table showing all equity interests held including limited liability company (LLC) and partnership interests, as well as derivative securities. Include both the number of shares issued to each equity holder, as well as the percentage of that series and of all equity on fully diluted basis. For each equity holder, provide the place of incorporation and the principal place of business, as applicable. If the equity holder is a natural person, identify the citizenship(s); 4. Any current or pending venture capital or institutional investment by an entity that has a general partner or individual holding a leadership role in such entity who has a foreign affiliation with any foreign country of risk; 5. Any current or pending technology licensing or intellectual property sales to a foreign country of risk; and 6. Any changes to the Recipient or the subrecipients’ board of directors, including additions to the number of directors, the identity of new directors, as well as each new director’s citizenship, shareholder affiliation (if applicable); each notification shall include a complete up-to-date list of all directors (and board observers), including their full name, citizenship and shareholder affiliation, date of appointment, duration of term, as well as a description of observer rights as applicable. Should DOE determine the connection poses a risk to economic or national security, DOE will require measures to mitigate or eliminate the risk. DOE has designated the following countries as foreign countries of risk: Iran, North Korea, Russia, and China. This list is subject to change. Recognizing the disclosures may contain business confidential information, subrecipients may submit their disclosures directly to DOE. FOREIGN COLLABORATION CONSIDERATIONS (MARCH 2023) A. Consideration of new collaborations with foreign entities, organizations, and governments. The Recipient must provide DOE with advanced written notification of any potential collaboration with foreign entities, organizations or governments in connection with its DOE-funded award scope. The Recipient must await further guidance from DOE prior to contacting the proposed foreign entity, organization or government regarding the potential collaboration or negotiating the terms of any potential agreement. B. Existing collaborations with foreign entities, organizations and governments. The Recipient must provide DOE with a written list of all existing foreign collaborations, organizations, and governments in which has entered in connection with its DOE-funded award scope. C. In general, a collaboration will involve some provision of a thing of value to, or from, the Recipient. A thing of value includes but may not be limited to all resources made available to, or from, the recipient SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 32 in support of and/or related to the Award, regardless of whether or not they have monetary value. Things of value also may include in-kind contributions (such as office/laboratory space, data, equipment, supplies, employees, students). In-kind contributions not intended for direct use on the Award but resulting in provision of a thing of value from or to the Award must also be reported. Collaborations do not include routine workshops, conferences, use of the Recipient’s services and facilities by foreign investigators resulting from its standard published process for evaluating requests for access, or the routine use of foreign facilities by awardee staff in accordance with the Recipient’s standard policies and procedures. REPORTING SUBAWARD AND EXECUTIVE COMPENSATION (SEPTEMBER 2023) a. Reporting of first-tier subawards. 1. Applicability. Unless the Recipient is exempt as provided in paragraph d. of this award term, the Recipient must report each action that equals or exceeds $30,000 in Federal funds for a subaward to a non-Federal entity or Federal agency (see definitions in paragraph e. of this award term). 2. Where and when to report. i. The non-Federal entity or Federal agency must report each obligating action described in paragraph a.1. of this award term to http://www.fsrs.gov. ii. For subaward information, report no later than the end of the month following the month in which the obligation was made. (For example, if the obligation was made on November 7, 2010, the obligation must be reported by no later than December 31, 2010.) 3. What to report. The Recipient must report the information about each obligating action that the submission instructions posted at http://www.fsrs.gov specify. b. Reporting total compensation of recipient executives for non-Federal entities. 1. Applicability and what to report. The Recipient must report total compensation for each of its five most highly compensated executives for the preceding completed fiscal year, if i. The total Federal funding authorized to date under this Federal award is $30,000 or more as defined in 2 CFR 170.320; ii. In the preceding fiscal year, the Recipient received: a) 80 percent or more of the Recipient’s annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at 2 CFR 170.320 (and subawards); and b) $25,000,000 or more in annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at 2 CFR 170.320 (and subawards); and iii. The public does not have access to information about the compensation of the executives through periodic reports filed under section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 33 U.S.C. 78m(a), 78o(d)) or section 6104 of the Internal Revenue Code of 1986. (To determine if the public has access to the compensation information, see the U.S. Security and Exchange Commission total compensation filings at https://www.sec.gov/answers/execomp.htm.) 2. Where and when to report. The Recipient must report executive total compensation described in paragraph b.1. of this award term: i. As part of the Recipients registration profile at https://www.sam.gov. ii. By the end of the month following the month in which this award is made, and annually thereafter. c. Reporting of total compensation of subrecipient executives. 1. Applicability and what to report. Unless the Recipient is exempt as provided in paragraph d. of this award term, for each first-tier non-Federal entity subrecipient under this award, the Recipient shall report the names and total compensation of each of the subrecipient's five most highly compensated executives for the subrecipient's preceding completed fiscal year, if: i. In the subrecipient’s preceding fiscal year, the subrecipient received; a) 80 percent or more of its annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at 2 CFR 170.320 (and subawards); and b) $25,000,000 or more in annual gross revenues from Federal procurement contracts (and subcontracts), and Federal financial assistance subject to the Transparency Act (and subawards); and ii. The public does not have access to information about the compensation of the executives through periodic reports filed under section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a), 78o(d)) or section 6104 of the Internal Revenue Code of 1986. (To determine if the public has access to the compensation information, see the U.S. Security and Exchange Commission total compensation filings at https://www.sec.gov/answers/execomp.htm.) 2. Where and when to report. The Recipient must report subrecipient executive total compensation described in paragraph c.1. of this award term: i. To the recipient ii. By the end of the month following the month during which the Recipient makes the subaward. For example, if a subaward is obligated on any date during the month of October of a given year ( i.e., between October 1 and 31), the Recipient must report any required compensation information of the subrecipient by November 30 of that year. d. Exemptions If, in the previous tax year, the Recipient had gross income, from all sources, under $300,000, it is exempt from the requirements to report: SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 34 i. Subawards, and ii. The total compensation of the five most highly compensated executives of any subrecipient. e. Definitions. For purposes of this award term: 1. Federal Agency means a Federal agency as defined at 5 U.S.C. 551(1) and further clarified by 5 U.S.C. 552(f). 2. Non-Federal entity means all of the following, as defined in 2 CFR part 25: i. A Governmental organization, which is a State, local government, or Indian tribe; ii. A foreign public entity; iii. A domestic or foreign nonprofit organization; and iv. A domestic or foreign for-profit organization. 3. Executive means officers, managing partners, or any other employees in management positions. 4. Subaward: i. This term means a legal instrument to provide support for the performance of any portion of the substantive project or program for which the Recipient received this award and that the recipient awards to an eligible subrecipient. ii. The term does not include the Recipient’s procurement of property and services needed to carry out the project or program (for further explanation, see 2 CFR 200.331). iii. A subaward may be provided through any legal agreement, including an agreement that the Recipient or a subrecipient considers a contract. 5. Subrecipient means a non-Federal entity or Federal agency that: i. Receives a subaward from the Recipient under this award; and ii. Is accountable to the Recipient for the use of the Federal funds provided by the subaward. 6. Total compensation means the cash and noncash dollar value earned by the executive during the recipient's or subrecipient's preceding fiscal year. For more information on disclosure and reporting requirements, see 17 CFR 229.402(c)(2). POTENTIALLY DUPLICATIVE FUNDING NOTICE (MARCH 2023) If the Recipient or subrecipients have or receive any other award of federal funds for activities that potentially overlap with the activities funded under this Award, the Recipient must promptly notify DOE in writing of the potential overlap and state whether project funds (i.e., recipient cost share and federal funds) from any of those other federal awards have been, are being, or are to be used (in whole or in part) for one or more of the identical cost items under this Award. If there are identical cost items, the Recipient must promptly notify the DOE Contracting Officer in writing of the potential duplication and eliminate any inappropriate duplication of funding. REQUIRED RISK MITIGATION (MARCH 2023) SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 35 [Placeholder – In the event DOE determines the award requires mitigation measures to address undue foreign influence risks, the mitigations measures would be captured in a T&C, depending on the nature of the required measure.] REPORTING, TRACKING AND SEGREGATION OF INCURRED COSTS (MARCH 2023) BIL funds can be used in conjunction with other funding, as necessary to complete projects, but tracking and reporting must be separate to meet the reporting requirements of the BIL and related Office of Management and Budget (OMB) Guidance. The Recipient must keep separate records for BIL funds and must ensure those records comply with the requirements of the BIL. COMMUNITY BENEFITS OUTCOMES AND OBJECTIVES – NETL The Recipient must meet the stated objectives and milestones set forth in its Community Benefits Outcomes and Objectives (CBOO) Plan, which is incorporated into the Award. A report on the Recipient’s progress towards meeting the objectives and milestones set forth in the CBOO must be provided on an annual basis. CYBERSECURITY PLAN (SEPTEMBER 2023) The Secretary of Energy, per BIL Section 40126, designated the DOE’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER) as responsible for coordinating cybersecurity project plans for IIJA provisions the Secretary deemed to have a cyber risk. CESER coordinates with DOE National Laboratory Subject Matter Experts (SMEs) to provide project lifecycle support activities that maintain or improve the project cybersecurity over its lifecycle. The Recipient is responsible for maintaining and improving project cybersecurity throughout the period of performance, including responding to DOE feedback on the plans and the associated milestones, deliverables, including attending associated cybersecurity plan lifecycle support meeting dates with CESER and DOE SMEs. Any revisions to the cybersecurity plans and all related deliverables shall be emailed securely to CR-IIJACybersecurityplans@hq.doe.gov. Any DOE and/or National Laboratory review comments or feedback provided to Recipients does not constitute an endorsement or approval of any specific elements within the cybersecurity plan or the proposed security approach. Therefore, such feedback should not be referenced or used in marketing or promotional materials. All cybersecurity plans and deliverables are exempt from disclosure under the Freedom of Information Act (5 U.S.C. § 552) pursuant to Section 40126(e). This exemption is limited to information provided to or collected by the federal government described in Pub. L. 117-58 § 41026, 42 U.S.C. § 18725. DAVIS-BACON ACT REQUIREMENTS (MARCH 2023) This award is funded under Division D of the Bipartisan Infrastructure Law (BIL). All laborers and mechanics employed by the recipient, subrecipients, contractors or subcontractors in the performance of construction, alteration, or repair work in excess of $2,000 on an award funded directly by or assisted in whole or in part by funds made available under this award shall be paid wages at rates not less than those prevailing on similar projects in the locality, as determined by the Secretary of Labor in accordance with subchapter IV of chapter 31 of title 40, United States Code commonly referred to as the “Davis-Bacon Act” (DBA). SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 36 Recipients shall provide written assurance acknowledging the DBA requirements for the award or project and confirming that all of the laborers and mechanics performing construction, alteration, or repair work in excess of $2,000 on projects funded directly by or assisted in whole or in part by and through funding under the award are paid or will be paid wages at rates not less than those prevailing on projects of a character similar in the locality as determined by Subchapter IV of Chapter 31 of Title 40, United States Code (Davis-Bacon Act). The Recipient must comply with all Davis-Bacon Act requirements, including but not limited to: (1) ensuring that the wage determination(s) and appropriate Davis-Bacon clauses and requirements are flowed down to and incorporated into any applicable subcontracts or subrecipient awards. (2) being responsible for compliance by any subcontractor or subrecipient with the Davis-Bacon labor standards. (3) receiving and reviewing certified weekly payrolls submitted by all subcontractors and subrecipients for accuracy and to identify potential compliance issues. (4) maintaining original certified weekly payrolls for 3 years after the completion of the project and must make those payrolls available to the DOE or the Department of Labor upon request, as required by 29 CFR 5.6(a)(2). (5) conducting payroll and job-site reviews for construction work, including interviews with employees, with such frequency as may be necessary to assure compliance by its subcontractors and subrecipients and as requested or directed by the DOE. (6) cooperating with any authorized representative of the Department of Labor in their inspection of records, interviews with employees, and other actions undertaken as part of a Department of Labor investigation. (7) posting in a prominent and accessible place the wage determination(s) and Department of Labor Publication: WH-1321, Notice to Employees Working on Federal or Federally Assisted Construction Projects. (8) notifying the Contracting Officer of all labor standards issues, including all complaints regarding incorrect payment of prevailing wages and/or fringe benefits, received from the recipient, subrecipient, contractor, or subcontractor employees; significant labor standards violations, as defined in 29 CFR 5.7; disputes concerning labor standards pursuant to 29 CFR parts 4, 6, and 8 and as defined in FAR 52.222- 14; disputed labor standards determinations; Department of Labor investigations; or legal or judicial proceedings related to the labor standards under this Contract, a subcontract, or subrecipient award. (9) preparing and submitting to the Contracting Officer, the Office of Management and Budget Control Number 1910-5165, Davis Bacon Semi-Annual Labor Compliance Report, by April 21 and October 21 of each year. Form submittal will be administered through the iBenefits system (https://doeibenefits2.energy.gov) or its successor system. SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 37 The Recipient must undergo Davis-Bacon Act compliance training and must maintain competency in Davis- Bacon Act compliance. The Contracting Officer will notify the Recipient of any DOE sponsored Davis-Bacon Act compliance trainings. The Department of Labor offers free Prevailing Wage Seminars several times a year that meet this requirement, at https://www.dol.gov/agencies/whd/government- contracts/construction/seminars/events. The Department of Energy has contracted with, a third-party DBA electronic payroll compliance software application. The Recipient must ensure the timely electronic submission of weekly certified payrolls as part of its compliance with the Davis-Bacon Act unless a waiver is granted to a particular contractor or subcontractor because they are unable or limited in their ability to use or access the software. Davis Bacon Act Electronic Certified Payroll Submission Waiver A waiver must be granted before the award starts. The applicant does not have the right to appeal DOE’s decision concerning a waiver request. For additional guidance on how to comply with the Davis-Bacon provisions and clauses, see https://www.dol.gov/agencies/whd/government-contracts/construction and https://www.dol.gov/agencies/whd/government-contracts/protections-for-workers-in-construction. AFFIRMATIVE ACTION AND PAY TRANSPARENCY REQUIREMENTS (SEPTEMBER 2023) All federally assisted construction contracts exceeding $10,000 annually will be subject to the requirements of Executive Order 11246: (1) Recipients, subrecipients, and contractors are prohibited from discriminating in employment decisions on the basis of race, color, religion, sex, sexual orientation, gender identity or national origin. (2) Recipients and Contractors are required to take affirmative action to ensure that equal opportunity is provided in all aspects of their employment. This includes flowing down the appropriate language to all subrecipients, contractors and subcontractors. (3) Recipients, subrecipients, contractors and subcontractors are prohibited from taking adverse employment actions against applicants and employees for asking about, discussing, or sharing information about their pay or, under certain circumstances, the pay of their co‐workers. The Department of Labor’s (DOL) Office of Federal Contractor Compliance Programs (OFCCP) uses a neutral process to schedule contractors for compliance evaluations. OFCCP’s Technical Assistance Guide should be consulted to gain an understanding of the requirements and possible actions the recipients, subrecipients, contractors and subcontractors must take. See OFCCP’s Technical Assistance Guide at: https://www.dol.gov/sites/dolgov/files/ofccp/Construction/files/ConstructionTAG.pdf?msclkid=9e397d68c4b11 1ec9d8e6fecb6c710ec. Additionally, for construction projects valued at $35 million or more and lasting more than one year, Recipients, subrecipients, contractors, or subcontractors may be selected by OFCCP to participate in the Mega Construction Project Program. DOE, under relevant legal authorities including Sections 205 and 303(a) of Executive Order 11246, will require participation as a condition of the award. This program offers extensive SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 38 compliance assistance with EO 11246. For more information regarding this program, see https://www.dol.gov/agencies/ofccp/construction/mega-program. SIGNAGE (SEPTEMBER 2023) The Recipient is encouraged to display DOE standard infrastructure investment signage, available for download from DOE (https://www.energy.gov/branding), during construction of the project. Expenditures for such signage shall be a permitted eligible cost of the project. 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 Clean Energy Innovator Fellowship 2024 Overview: The Clean Energy Innovator Fellowship (CEIF) program funds recent graduates and energy professionals to support critical energy organizations to advance clean energy solutions that will help decarbonize the power system, electrify transportation and industry, and make the U.S. power system more equitable and inclusive. The program recruits candidates from diverse backgrounds to spend up to two years supporting eligible host organizations. The U.S. Department of Energy (DOE) facilitates the process of matching host institutions and candidates. Additional program information can be found here: Clean Energy Innovator Fellowship | Department of Energy. Innovator Fellows receive a stipend to support their participation in the CEIF program and an allowance for education and professional development opportunities. The goal of the program is to increase access to clean energy career opportunities across the country and accelerate the national transition to resilient and affordable clean energy. Eligibility: The 2024 host application period closes March 5, 2024. Eligible host entities are electric public utility commissions in the United States and U.S. territories, electric cooperatives and municipal utilities, Puerto Rican essential energy organizations, tribal utilities, inter-tribal councils and other tribal organizations, and grid operators. New this year, State Energy Offices are now considered priority Hosts institutions. Applications for Fellows will open in March 2024 and open to recent graduates with bachelor’s, master’s, or doctoral degrees, and mid-career professionals in fields relevant to electricity generation, transmission, and distribution. Funding: The CEIF is a $6 million DOE Program that began in 2022. It provides stipends and an education allowance to Innovator Fellows to support host institution projects that will help decarbonize the U.S. power system, electrify transportation and industry, and make the power system more equitable and inclusive. Stipends are determined by degree level received and years of relevant professional experience. How It Works: Host institutions and fellowship candidates must each apply separately to participate in the program. DOE will facilitate the process of matching host institutions and fellows. The application, interview, and selection process is as follows: 1. Applications • Prospective host institutions apply to the DOE with a specific project scope. The staff member of an eligible institution who will mentor the Fellow and provide guidance on Alaska Energy Authority Page 2 of 2 the project should submit the application and participate in the Fellow selection process. Only one application may be submitted per host institution. • Fellowship candidates apply to DOE describing their interest in the opportunity and their relevant skills and experience. 2. DOE Review • DOE reviews Host institution applications and selects Host institutions and projects that fit the program criteria and budget o DOE may conduct a 15-minute interview with a Host institution for clarification purposes • DOE conducts initial reviews of all candidate applications for completeness and minimal requirements according to program criteria o DOE may conduct a 15-minute interview with a candidate for clarification purposes 3. Host Institution-Fellowship Candidate Interviews • Host institutions review fellowship candidate applications and conduct fellowship candidate interviews. Hosts select candidates for interviews based on information submitted in the candidate applications. 4. Innovator Fellow Selection • Host institutions notify DOE of selected fellowship candidate • DOE conducts a 30-minute interview with the fellowship candidate and Host institution Mentor to confirm Host-Fellow match. o A Host institution and selected fellowship candidate are not guaranteed a match until an offer is made and accepted by the fellowship candidate Types of Projects: DOE is in interested in projects focused on the following: clean energy development, distributed energy, electrification, equity and energy justice, essential grid services, grid resilience, regulation, and tribal energy. About the Host Application: The application is comprised of 20 questions, some requiring detailed responses. Each application must be completed and submitted, with an email confirmation received. Potential Host applicants can preview the application questions here: 2024 CEIF Host Institution Application Review and will complete/submit their application at this link: The Clean Energy Innovator FellowshipHost Institution Application (orau.org) Recommendation: New this year, State Energy Offices are deemed priority host institutions. Therefore, AEA is eligible to apply for this opportunity. Audrey Alstrom, Director of Renewable Energy and Energy Efficiency will be applying for AEA to be a host institution. Audrey Audrey and Bryan Carey, Director of Owned Assets, will be co-mentors. AEA EXECUTIVE ORDER 128 OVERVIEW Curtis W. Thayer Executive Director Senate State Affairs Committee January 30, 2024 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. 2AEA Executive Order 128 Overview | Senate State Affairs Committee | January 30, 2024 AEA Active Projects and Services 3AEA Executive Order 128 Overview | Senate State Affairs Committee | January 30, 2024 Executive Order 128: The “Why” Historical: From 1976 until 1993, AEA was governed by its own board of directors. Distinct Purpose: The underlying purposes of AIDEA and AEA are fundamentally different. AEA’s mission is to reduce the cost of energy in Alaska. Whereas, AIDEA's mission is to provide various means of financing to promote economic growth and diversity. Unique Mission: In addition to the lowering the cost of energy in Alaska, AEA works to diversify Alaska’s energy portfolio, and increase resiliency, reliability, and redundancy —and our mission is growing. Exponential Growth: AEA’s capital budget has increased over 1,000% in the last four years. Distinct Expertise: A distinctive set of skills and expertise is required for optimal governance. It is common and appropriate for a single-purpose entity to have a governing board made up of experts in the topic area. Staffing: AEA has 68 PCNs (20 IIJA PCNs pending); AIDEA has 31 PCNs; and Shared Services 15 PCNs. “As governor, I find that it is in the best interests of efficient administration to separate the membership of the board of directors of the Alaska Energy Authority from the membership of the board of directors of the Alaska Industrial Development and Export Authority.” —EO 128 4AEA Executive Order 128 Overview | Senate State Affairs Committee | January 30, 2024 New AEA Board Makeup As proposed in the Governor’s EO 128, AEA’s board membership makeup would include: (1) the commissioner of commerce, community, and economic development (2) six public members appointed by the governor as follows: -(A) one member with expertise or experience in managing or operating an electric utility that is not connected to an interconnected electric energy transmission network, as that term is defined in AS 42.05.790; -(B) one member with expertise or experience in developing energy projects in rural communities; -(C) one member with expertise or experience in managing or operating an electric utility connected to an interconnected electric energy transmission network, as that term is defined in AS 42.05.790; -(D) one member with financial expertise in large-scale energy project development; and -(E) two members with expertise or experience in finance, energy policy, energy technology, engineering, law, or economics. 5AEA Executive Order 128 Overview | Senate State Affairs Committee | January 30, 2024 AEA’s Exponential Growth AEA has received —and anticipates a substantial increase in —federal funding from the Infrastructure Investment and Jobs Act (IIJA) and others, over the next several years. Pipeline of federal funding: -$84 million awarded (Energy Efficiency Conservation Block Grant, Department of Defense Grant, State Energy Planning Grant, National Electric Vehicle Infrastructure grant, and Grid Resilience 40101(d) Grant) -$573.5 million conditionally awarded (Grid Resilience and Innovation Partnerships, Energy Efficiency Reconciliation Loan Capitalization Program, and Home Efficiency and Appliance Rebates) -$104 million competitive applications pending decision (Solar for All, Wood Innovations Grant, and Energy Future Grant, and High-Energy cost grant) Availability of tax incentives for clean energy projects and direct pay reimbursement available for tax exempt entities for the first time. In addition to AEA’s netbook value of $1.3 billion, several large projects are underway: -$413 million to build an undersea High Voltage Direct Current from the Kenai Peninsula to Anchorage -$342 million for the Dixon Diversion Project to increase the annual energy production of Bradley Lake by 50 percent (Estimated to offset 1.5 billion cubic feet of natural gas per year in Railbelt power generation) -$90 million for Railbelt transmission upgrades (Sterling Substation and Quartz Creek transmission line) 6AEA Executive Order 128 Overview | Senate State Affairs Committee | January 30, 2024 AEA’s Statutory Programs Alaska Energy Security Task Force: Development of the Governor’s Alaska Energy Security Task Force Report submitted in December 2023. New federal funding diversifies AEA’s existing statutory programs and projects portfolio including: -Rural Power System Upgrades and Bulk Fuel Upgrades:AEA continues to manage legacy funding for critical rural energy projects and training programs in partnership with the Denali Commission. -Renewable Energy Fund: AEA also manages this competitive grant program, and has received legislative funding for the last three consecutive fiscal years (over $37 million). -Alaska Intertie:AEA-owned transmission asset that saves Interior ratepayers nearly $40 million annually. -Bradley Lake Hydroelectric Project:AEA-owned generation asset that provides 10 percent of Railbelt's energy. o Required Project Work is anticipated to utilize the bond proceeds from the $166 million bond issuance, which are being planned, and will progress in the next several years (transmission and BESS). o New federal funds for transmission, grid resiliency, and other power projects may be leveraged by the bond funds to advance energy projects and reduce the cost of energy in the state. -Power Cost Equalization: AEA manages this annual ~$45 million program vital for rural Alaskans. -Renewable Energy and Energy Efficiency Programs: To promote Alaska's clean energy sector, AEA manages biomass, hydro, solar, and wind programs and projects across the state. 7AEA Executive Order 128 Overview | Senate State Affairs Committee | January 30, 2024 Total Capital Appropriations FY2021 to FY2024 (in thousands) 8AEA Executive Order 128 Overview | Senate State Affairs Committee | January 30, 2024 Alaska Energy Authority 813 W Northern Lights Blvd. Anchorage, AK 99503 Phone: (907) 771-3000 Fax: (907) 771-3044 akenergyauthority.org For more information, please contact AEA Executive Director Curtis W. Thayer Contact Us 9 813 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 ANNUAL CAPITAL PROJECT STATUS REPORT January 30, 2024 PROJECT: Bradley Lake Hydroelectric Project PROJECT LOCATION: Homer, Alaska ORIGINAL ESTIMATED PROJECT COSTS 1: $ 355,900,000 ORIGINAL ESTIMATED COSTS OF BATTLE CREEK DIVERSION IMPROVEMENT2: 47,200,000 ORIGINAL ESTIMATED COSTS OF SSQ LINE ACQUISITION 3: 16,508,569 ORIGINAL ESTIMATED COSTS OF BRADLEY LAKE REQUIRED PROJECT WORK 4: 165,855,884 $ 585,464,453 CURRENT ESTIMATED PROJECT COSTS: Construction Expenditures-Original Construction $ 316,902,894 Construction Expenditures-Battle Creek Diversion 46,422,179 Construction & Acquisition Cost – SSQ Transmission Line 16,508,569 Construction Expenditures-Bradley Lake Required Project Work 165,855,884 Construction Expenditures-Dixon Diversion 6,000,000 Total Construction & Acquisition Costs $ 551,689,526 Financing Costs-Original Construction 11,316,424 Financing Costs-Battle Creek Diversion Improvement 173,045 Financing Costs –SSQ 115-Kv Transmission Line 491,431 Financing Costs-Bradley Lake Required Project Work 157,250 Total Financing Costs 12,138,150 Total Estimated Project Costs $ 563,827,676 SOURCE OF FUNDS: Appropriated Funds: SLA1979 CH 80 $ 80,000 SLA1981 CH 92 $ 5,000,000 SLA1981 CH 92 $ 10,000,000 SLA1982 CH 141 $ 3,000,000 SLA1984 CH 171 $ 50,000,000 SLA1985 CH 96 $ 50,000,000 1 Excludes project financing costs. Also excludes major maintenance and repair costs and preconstruction costs associated with Battle Creek diversion. Excludes costs associated with the SSQ Line acquisition and remediation. Excludes costs associated with Bradley Lake Required Project Work. 2 Excludes project financing costs. Battle Creek diversion construction costs are included in this estimate. 3 Excludes project financing costs. SSQ Line acquisition and remediation costs are included in this estimate. 4 Excludes project financing costs. Bradley Lake Require Project Work costs are included in this estimate. Alaska Energy Authority Page 2 of 4 SLA1986 CH 41 $(50,000,000) SLA1986 CH 41 $ 50,000,000 SLA1986 CH 128 $ 50,000,000 SLA1987 CH 96 $(50,000,000) SLA1987 CH 96 $ 50,000,000 SLA1988 CH 172 $ 7,000,000 SLA1993 CH 19 $(12,082,500) SLA2022 CH 11 $ 1,000,000 SLA2023 CH 1 $ 5,000,000 $168,997,500 Other: Power Revenue Bonds, includes interest earnings $165,221,818 Battle Creek Diversion Power Revenue Bonds, includes interest earnings 42,105,633 Participating Utility Cash Contributions 4,489,591 SSQ 115-kV Transmission Line Bonds 17,000,000 Bradley Lake Required Project Work Bonds 166,013,134 Total Source of Funds: $563,827,676 PROJECT DESCRIPTION: Bradley Lake is a hydroelectric project located near Homer, Alaska with an installed capacity of 120 megawatts. Construction of the Bradley Lake Project was substantially completed in 1991, with the date of commercial operation declared to be September 1, 1991. The Battle Creek Diversion Project and the Sterling Substation to Quartz Creek Substation (SSQ) transmission line were added in 2020. The project continues to provide electric power to the Railbelt utilities from the Kenai Peninsula to Fairbanks. The project is operated and maintained by Homer Electric Association. PROJECT STATUS AT 12/31/23: The Bradley Lake Project Management Committee (“BPMC”) has responsibility to operate and maintain the Bradley Lake hydroelectric project. The BPMC was established pursuant to Section 13 of the Agreement for the Sale and Purchase of Electric Power (“Power Sales Agreement”) dated December 8, 1987. The members of the BPMC include the Alaska Energy Authority (“AEA”) and the five purchasers under the Power Sales Agreement - Chugach Electric Association, Inc (“CEA”).; Golden Valley Electric Association, Inc (“GVEA”).; the City of Seward (“Seward Electric System”); Alaska Electric and Energy Cooperative, Inc. (“AE&EC”); and Matanuska Electric Association, Inc. (“MEA”). Originally, the Alaska Electric Generation & Transmission Cooperative, Inc. (“AEG&T”) was a purchaser under the Power Sales Agreement for the benefit of HEA and MEA. AEG&T assigned its rights under the Power Sales Agreement pertaining to MEA to MEA in 2015, and its rights pertaining to HEA to AE&EC in 2003. HEA is an additional party to the Power Sales Agreement, and is the entity represented on the BPMC while AE&EC has no direct vote as a consequence of the individual representation of HEA. Originally, the Municipality of Anchorage’s Municipal Light & Power (“ML&P”) was a purchaser under the Power Sales Agreement. CEA acquired ML&P on October 30, 2020, and its rights under the Power Sales Agreement. Alaska Energy Authority Page 3 of 4 Originally, the Project encompassed 5,498 acres of federal lands. All of these lands were conveyed to the State of Alaska, pursuant to the Alaska Statehood Act, through five separate Tentative Approvals (TAs) and a Patent from the United States that became effective Spring 2018. AEA is no longer required to pay annual charges for the use and occupancy of lands that were owned by the United States. Bradley Lake hydroelectric project generation for the year was 376,000 megawatt hours (MWh). The 2023 generation was slightly lower than the long term annual mean generation of 390,000 MWh. The project’s ongoing maintenance and repairs are funded by the purchasers and not by state appropriation. 2023 was the third full year in operation for the new West Fork Upper Battle Creek Diversion project (“Battle Creek”). The project was completed in 2020 and was expected to increase the Bradley Lake Hydropower Project’s annual energy generation by approximately 37,000 MWh. In 2023 the energy equivalent of the Battle Creek water was greater than 40,000 MWh. All five of the Railbelt utilities are participating in the cost & energy from this project. Preconstruction activities for the Battle Creek diversion project were partially funded by a $3 million allocation of an ARCTEC Energy Project appropriation (FSSLA11 CH 5). Additional funding sources include a $500,000 Renewable Energy Grant, a $500,000 contribution by the participating utilities to match the Renewable Energy Grant, and an additional $1.2 million contribution by the participating utilities. In December 2017, the Authority issued, as a private placement, $47 million of Power Revenue Bonds for the long-term financing of the construction costs of the Battle Creek Diversion Project. The Power Revenue Bonds consist of $40 million New Clean Renewable Energy Bonds (“NCREB”); $1.2 million Qualified Energy Conservation Bonds (“QECB”); and $5.8 million Taxable Draw-Down Bonds. The tax subsidies associated with the NCREB and QECBs significantly reduce the net interest costs of financing the WFUBC construction project. The draw period on the $5.8 million Alaska Energy Authority Power Revenue, Ninth Series Taxable Draw-Down Bonds expired in December 2020 with no draws made on this Series. The participating utilities will provide cash contributions of $4.5 million. 2023 was the third full year in operation for the purchased Sterling Substation to Quartz Creek Substation (“SSQ Line”), and certain related rights, rights of way, and permits as part of the Bradley Lake Project. The SSQ Line is approximately 39.3 miles of 115 kV and 69 kV transmission line. The transmission line delivers Bradley Lake hydroelectric generated power from HEA’s grid to transmission lines linked to all the other Railbelt utilities. In the summer of 2019, the SSQ Line was out-of-service for an extended time after receiving damage during the Swan Lake Fire. It took four months to bring the line back into service costing an estimated $12 million to Railbelt Utility ratepayers. The addition of the SSQ Line to the Bradley Lake Project is a benefit to Alaska ratepayers through better cost alignment, increased reliability, and future prospects for upgrades to the line, decreasing line losses and allowing increased transmission north of Bradley Lake Power. In December 2020, the Authority issued, as a private placement, $17 million of Power Revenue Bonds for the long-term financing of the acquisition costs of the SSQ Line. The line was purchased from HEA for $13.3 million. Additional costs include remediation of the 69kV line, Inspection/Repair outside of the Fire Zone, Right of Way (“ROW”) transfer and upgrade costs, funding of the Capital Reserve account, and bond issuance closing costs. Alaska Energy Authority Page 4 of 4 In December 2022, 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 bond proceeds will be used solely to pay for transmission line upgrades and battery energy storage systems that will reduce the constraints on the Railbelt grid by improving the Kenai Peninsula’s transmission capacity to export power from Bradley Lake, while also allowing for the integration of additional renewable energy generation. Funding for the projects is coming from payments by the five Railbelt utilities above those required to retire Bradley Lake project bonds, and will come at no additional cost to ratepayers or added burden on the State treasury. These projects include: • 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 During 2023 feasibility studies continued for the prospective Dixon Diversion Project. Annual energy was verified and required facilities were optimized to reduce estimated total project cost by $75 million. State capital funds will be used to advance studies in 2024. 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 ANNUAL CAPITAL PROJECT STATUS REPORT January 30, 2024 PROJECT: Alaska Intertie Project PROJECT LOCATION: Willow to Healy, Alaska CURRENT ESTIMATED PROJECT COSTS: Construction Expenditures-Original Construction $124,245,687 Construction Expenditures-Upgrades/Improvements through 12/31/23 15,864,467 Projection to Complete Upgrades/Improvements: 8,435,533 Total Estimated Project Costs $148,545,687 SOURCE OF FUNDS: Appropriated Funds: Original Construction SLA1980 CH 50 $ 3,000,000 SLA1981 CH 92 $ 36,000,000 SLA1981 CH 92 $ 40,000,000 SLA1983 CH107 $ 25,000,000 SLA1984 CH171 $ 18,600,000 SLA1987 CH127 $ 5,896,400 FY87 Administrative Lapse $ (33,281) Source of Funds-Original Construction $128,463,119 Improvements/Upgrades SLA2002 CH 1 $ 20,300,000 SLA2008 CH 29 $ (10,000,000) SLA2008 CH 29 $ 10,000,000 SLA2011 CH 5 $ 5,000,000 SLA2012 CH 5 $ (9,160,564) SLA2012 CH 5 $ 8,160,564 Source of Funds-Upgrades/Improvements $ 24,300,000 Total Source of Funds: $152,763,119 Alaska Energy Authority Page 2 of 3 PROJECT DESCRIPTION: The Alaska Intertie (“AKI”) transmission line is a 170-mile long, 345 kilovolt (kV) transmission line between Willow and Healy. It is owned by the Alaska Energy Authority (“AEA”) and operated at 138kV. The AKI was built in the mid 1980’s with State of Alaska appropriations of approximately $124 million. The AKI is one of a number of transmission segments that, when connected together, move power throughout the Railbelt Grid from Delta through Fairbanks to Anchorage down to the southernmost limit at Nanwalek. The project includes transmission towers, conductors, the Cantwell substation, transformers at the Healy and Teeland substations (Knik Road), and Railbelt system stability devices (Static VAR Compensators) at three locations that are necessary to allow the utilities to remain interconnected and for power to flow between utilities. The project is owned outright by AEA, and carries no debt. PROJECT STATUS AT 12/31/23 The AKI continues normal operations carrying Bradley Lake and economy power north into the Golden Valley Electric Association (“GVEA”) system. The economy power is generated by Chugach Electric Association (“CEA”), Homer Electric Association (“HEA”) and Matanuska Electric Association (“MEA”). Although power generally flows north, the line is available for GVEA to transfer energy south if an emergency situation finds the Cook Inlet region short of electric power. AEA has signed a service agreement with GE Solutions LLC for maintenance, repair, training, parts, and telephonic support of the Static VAR Compensators, which were installed in 2015. This service agreement ensures this critical infrastructure can be reliably and economically maintained. The Second Amended and Restated Alaska Intertie Agreement (“ARAIA”) was signed by AEA and the Railbelt utility participants (participants) in March 2014. The participants include GVEA, CEA, and MEA. Originally, the Municipality of Anchorage’s Municipal Light & Power (“ML&P”) was a purchaser under the ARAIA. CEA acquired ML&P on October 30, 2020, and its rights under the ARAIA. The participants and AEA each have a seat on the Intertie Management Committee (“IMC”). The IMC has responsibility to operate and maintain the AKI. The IMC adopted bylaws to govern their operation, and retained contracts and operating procedures to maintain an easy transition to the amended agreement. The longstanding Intertie Operating Committee (“IOC”) continues to recommend operating policies, procedures, and standard practices to the IMC for consideration. Additional Background: Agreements were developed over a span of 30 years to govern the cooperative management and operation of the connected network at large. AEA has agreements with participating utilities to ensure the AKI operates with prudent maintenance and operation by utilities. CEA is the southern region operator and GVEA is the northern region operator. MEA provides maintenance of the AKI in the southern region. GVEA provides maintenance in the northern region. Potential extension of the AKI to the Point MacKenzie area – In 2002, AEA, working collaboratively with the intertie participants, explored extending the AKI to connect with the southcentral transmission system at a location determined to be most reliable to the bulk-electric system. In Alaska Energy Authority Page 3 of 3 analyzing this potential project, it was determined that the Point MacKenzie area was the optimal location for the terminus, strengthening the transmission inter-connection and ultimately assisting in the movement of energy from the Bradley Lake Hydroelectric Project to Fairbanks, ensuring increased capacity and reliability of power transmission in southcentral Alaska and providing greater flexibility for dispatching generation resources for region-wide ratepayer benefit. Currently the Authority, in consultation with the intertie participants, is discussing how to move forward with the Intertie extension project. AEA EXECUTIVE ORDER 128 OVERVIEW Curtis W. Thayer Executive Director Senate Resources Committee January 31, 2024 ALASKA ENERGY AUTHORITY AEA Executive Order 128 Overview | Senate Resources Committee | January 31, 2024 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. 2 AEA Executive Order 128 Overview | Senate Resources Committee | January 31, 2024 AEA Active Projects and Services 3 Executive Order 128: The “Why” 4AEA Executive Order 128 Overview | Senate Resources Committee | January 31, 2024 Historical: From 1976 until 1993, AEA was governed by its own board of directors. Distinct Purpose: The underlying purposes of AIDEA and AEA are fundamentally different. Unique Mission: Reduce the cost of energy in Alaska, diversify Alaska’s energy portfolio, and increase resiliency, reliability, and redundancy —and our mission is growing (owned assets, energy data department). Exponential Growth: AEA’s capital budget has increased over 1,000% in the last four years. Distinct Expertise: A distinctive set of skills and expertise is required for optimal governance. It is common and appropriate for a single-purpose entity to have a governing board made up of experts in the topic area. Staffing: AEA has 68 PCNs; AIDEA has 31 PCNs; and Shared Services 15 PCNs. “As governor, I find that it is in the best interests of efficient administration to separate the membership of the board of directors of the Alaska Energy Authority from the membership of the board of directors of the Alaska Industrial Development and Export Authority.” —EO 128 New AEA Board Makeup 5AEA Executive Order 128 Overview | Senate Resources Committee | January 31, 2024 As proposed in the Governor’s EO 128, AEA’s board membership makeup would include: (1) the commissioner of commerce, community, and economic development (2) six public members appointed by the governor as follows: -(A) one member with expertise or experience in managing or operating an electric utility that is not connected to an interconnected electric energy transmission network, as that term is defined in AS 42.05.790; -(B) one member with expertise or experience in developing energy projects in rural communities; -(C) one member with expertise or experience in managing or operating an electric utility connected to an interconnected electric energy transmission network, as that term is defined in AS 42.05.790; -(D) one member with financial expertise in large-scale energy project development; and -(E) two members with expertise or experience in finance, energy policy, energy technology, engineering, law, or economics. AEA’s Exponential Growth 6AEA Executive Order 128 Overview | Senate Resources Committee | January 31, 2024 AEA has received —and anticipates a substantial increase in —federal funding from the Infrastructure Investment and Jobs Act (IIJA) and others, over the next several years. Pipeline of federal funding: -$84 million awarded (Energy Efficiency Conservation Block Grant, Department of Defense Grant, State Energy Planning Grant, National Electric Vehicle Infrastructure grant, and Grid Resilience 40101(d) Grant) -$573.5 million conditionally awarded (Grid Resilience and Innovation Partnerships, Energy Efficiency Reconciliation Loan Capitalization Program, and Home Efficiency and Appliance Rebates) -$104 million competitive applications pending decision (Solar for All, Wood Innovations Grant, and Energy Future Grant, and High-Energy cost grant) Availability of tax incentives for clean energy projects and direct pay reimbursement available for tax exempt entities for the first time. In addition to AEA’s netbook value of $1.3 billion, several large projects are underway: -$413 million to build an undersea High Voltage Direct Current from the Kenai Peninsula to Anchorage -$342 million for the Dixon Diversion Project to increase the annual energy production of Bradley Lake by 50 percent (Estimated to offset 1.5 billion cubic feet of natural gas per year in Railbelt power generation) -$90 million for Railbelt transmission upgrades (Sterling Substation and Quartz Creek transmission line) AEA’s Statutory Programs 7AEA Executive Order 128 Overview | Senate Resources Committee | January 31, 2024 Alaska Energy Security Task Force: Development of the Governor’s Alaska Energy Security Task Force Report submitted in December 2023. New federal funding diversifies AEA’s existing statutory programs and projects portfolio including: -Rural Power System Upgrades and Bulk Fuel Upgrades:AEA continues to manage legacy funding for critical rural energy projects and training programs in partnership with the Denali Commission. -Renewable Energy Fund: AEA also manages this competitive grant program, and has received legislative funding for the last three consecutive fiscal years (over $37 million). -Alaska Intertie:AEA-owned transmission asset that saves Interior ratepayers nearly $40 million annually. -Bradley Lake Hydroelectric Project:AEA-owned generation asset that provides 10 percent of Railbelt's energy. o Required Project Work is anticipated to utilize the bond proceeds from the $166 million bond issuance, which are being planned, and will progress in the next several years (transmission and BESS). o New federal funds for transmission, grid resiliency, and other power projects may be leveraged by the bond funds to advance energy projects and reduce the cost of energy in the state. -Power Cost Equalization: AEA manages this annual ~$45 million program vital for rural Alaskans. -Renewable Energy and Energy Efficiency Programs: To promote Alaska's clean energy sector, AEA manages biomass, hydro, solar, and wind programs and projects across the state. Total Capital Appropriations FY2021 to FY2024 (in thousands) 8AEA Executive Order 128 Overview | Senate Resources Committee | January 31, 2024 AEA Executive Order 128 Overview | Senate Resources Committee | January 31, 2024 Alaska Energy Authority 813 W Northern Lights Blvd. Anchorage, AK 99503 Phone: (907) 771-3000 Fax: (907) 771-3044 akenergyauthority.org For more information, please contact AEA Executive Director Curtis W. Thayer Contact Us 9 AEA OVERVIEW AND PROGRAMS UPDATE Curtis W. Thayer Executive Director House Energy Committee February 1, 2024 ALASKA ENERGY AUTHORITY AEA Overview and Programs Update | House Energy Committee | February 1, 2024 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. 2 AEA Overview and Programs Update | House Energy Committee | February 1, 2024 AEA Active Projects and Services 3 60+ Subcommittee Meetings 11 Task Force Meetings 150+ Hours of Public Meetings 8 Energy Symposiums with 16 hours of OnDemand learning 6 Subcommittees have created over 60 preliminary actions for considerations: Railbelt Transmission, Generation, and Storage Coastal Generation, Distribution, and Storage Rural Generation, Distribution, and Storage State Energy Data Incentives and Subsidies Statutes and Regulations 4 Alaska Energy Security Task Force 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 5 Dixon Diversion Project BRADLEY LAKE HYDROELECTRIC PROJECT AEA owns the 120-megawatt hydro facility, which produces ~10% of the total annual electricity at 4.5 cents per kilowatt-hour and is used by more than 550,000 Alaskans on the Railbelt (~54,400 homes/year).AEA is studying the Dixon Diversion Project to optimize the energy potential of the AEA-owned Bradley Lake Hydroelectric Project. Like the West Fork Upper Battle Creek Diversion Project, the Dixon Diversion Project would divert water from Dixon Glacier in order to increase Bradley Lake's annual energy production by 50 percent. Located five miles from Bradley Lake and would utilize existing powerhouse at Bradley Lake Estimated annual energy 100,000-200,000 MWh (~24,000-30,000 homes) Estimated to offset 1.5 billion cubic feet of natural gas per year in Railbelt power generation Estimated completion is 2030 *Funding will be used for engineering studies (feasibility, hydrological, geological) and environmental studies (fisheries, water quality, geomorphology). 6 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. 7AEA Overview and Programs Update | House Energy Committee | February 1, 2024 AEA Overview and Programs Update | House Energy Committee | February 1, 2024 8 Houston Solar Farm, Houston, AK St. George Island, Pribilof Islands, AKSt. George Island, Pribilof Islands, AK Power Cost Equalization (PCE) The PCE program was established in 1985 as one of the components of a statewide energy plan. Saint Paul, Alaska The cost of electricity for Alaska’s rural residents is notably higher than for urban residents. PCE lowers the cost of electric service paid by rural residents. Ultimately ensuring the viability of rural utilities and the availability of reliable, centralized power. 9 ~197 eligible communities 42 Active projects ~400 rural bulk fuel facilities 34 Active projects Rural Power Systems Upgrade Bulk Fuel Upgrade AEA and Federal Partners, Denali Commission (*$2 Million) Rural Power Systems Upgrades and Bulk Fuel Upgrades* AEA Overview and Programs Update | House Energy Committee | February 1, 2024 Electric Emergency Response AEA provides support when an electric utility has lost or will lose the ability to generate or transmit power to its customers and the condition is a threat to life, health, and/or property. Funding provides the current level of technical support through the Electrical Emergencies Program. In fiscal year 2024, $200,000 was appropriated. During the fiscal year 2023 there were six (6) electrical emergencies. Power was restored within24 hours in each case. The average cost of an electrical emergency assistance is approximately $45,000 each. 10 Renewable Energy Fund (REF) AEA, in concert with the REF Advisory Committee, has forwarded to the Legislature a capitalization request of $32 million for Round 16 of the REF. An appropriation of $32 million would fully fund all 24 recommended projects. Funding approval for the REF is at a sole discretion of the Legislature and Governor. $317 million invested in the REF by the State since inception. 100+ operational projects and 60 are in development. For Fiscal Year 2024 the 33rd Alaska State Legislature appropriated $17 million for 18 projects recommended by AEA and approved by the REF Advisory Committee. REF Highlights Round 13: 11 Projects –$4.75M Round 14: 27 Projects –$15M Round 15: 18 Projects –$17M AEA Overview and Programs Update | House Energy Committee | February 1, 2024 11 AEA Overview and Programs Update | House Energy Committee | February 1, 2024 The PPF loan program continues to see an increase in applications due to federal matching fund requirements and other incentives. The Inflation Reduction Act provides tax credits of up to 40%. A fund capitalization of $25 million would allow for additional funds needed to support the increased demand in funding. The PPF loan program continues to see an increase in applications due to federal matching fund requirements and other incentives. The Inflation Reduction Act provides tax credits of up to 40%. A fund capitalization would allow for additional funds needed to support the increased demand in funding. Power Project Fund (PPF) Loan Program Outstanding Loans $31 Million 16 Loans Competitive Rates Current PPF Interest Rate 5.39% as of January 2024 Pending Applications $755,500 Loans Under Review Uncommitted Cash Balance Program in abeyance until additional capital is secured 12 AEA Overview and Programs Update | House Energy Committee | February 1, 2024 Grid Resilience and Innovation Partnerships (GRIP) Increases transfer capacity between regions that enables higher renewable energy integration into the electricity system. Improves resilience and reliability for tribal and disadvantaged communities in the Railbelt region, and a reduction in reliance on fossil fuel generation and associated emissions. Supports the retention of high- quality jobs in the region, including 650 highly paid jobs with competitive employer-sponsored benefits. Creates apprenticeship and internship programs to train a new generation of lineworkers and wireworkers to reinvigorate Alaska’s energy workforce. AEA secured $206.5 million for GRIP Topic Area 3: Grid Innovation through the United States Department of Energy’s Grid Deployment Office. A cost share of 100 percent, or $206.5 million, is required for a total project amount of $413 million. The Railbelt Innovation Resiliency project will construct a High Voltage Direct Current submarine cable to serve as a parallel transmission route from the Kenai Peninsula to Anchorage, creating a much-needed redundant system in case of disruptive events. Antipcated outcomes and benefits include: 13 $413 Million (206.5 Million Federal and $206.5 Million Alaska Match) Railbelt Transmission Upgrades 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. 14 Grid Resilience Formula Grant Program, IIJA 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.” Over the next five years, Alaska will receive $60 million in federal formula grants to catalyze projects to increase grid resilience against disruptive events. In August 2023, the first two years of allocations, $22.2 million, were awarded to AEA. After that, AEA plans to launch a competitive solicitation for the funds later in the year. For fiscal year 2025, AEA requests $12,110,523 in Federal Receipt Authority and $1,816,579 in matching funds. 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. 15 $60 Million (Over Five Years) State of Alaska Electric Vehicle (EV) Infrastructure Implementation Plan AEA and the Alaska Department of Transportation & Public Facilities (DOT&PF), continue their partnership in deploying the State of Alaska EV Infrastructure Implementation Plan.For fiscal years 2022-2027, Alaska will receive over $52 million. The first round of Alaska NEVI awards was announced on September 25, 2023. AEA and DOT&PF selected projects in nine Alaskan communities for a total investment of $8 million. The $6.4 million in NEVI funding will be matched with $1.6 million from private entities selected to install, own, and operate the new EV charging stations. On September 29, 2023, the Federal Highway Administration approved the fiscal year 2024 plan, which unlocks $11 million in addition to $19 million that became available in the fiscal years 2022 and 2023. 16AEA Overview and Programs Update | House Energy Committee | February 1, 2024 $52 Million (Over Five Years) AEA Overview and Programs Update | House Energy Committee | February 1, 2024 Home Efficiency Rebates Rebates for energy efficiency retrofits range from $2,000-$4,000 for individual households and up to $400,000 for multifamily buildings. Grants to states to provide rebates for home retrofits. Up to $2,000 for retrofits reducing energy use by 20% or more, and up to $4,000 for retrofits saving 35% or more. Maximum rebates amounts are doubled for retrofits of low-and moderate-income homes. Alaska’s Allocation is $37.4 million No State match is required. This funding is not available at this time. Home Electrification and Appliance Rebates Develop a high efficiency electric home rebate program. Inclusive of means testing and will provide 50% of the project cost for incomes ranging from 80% to 150% of area median income. Rebates to cover 100% of the proposed cost for incomes 80% of area medium income and below, with similar tiers applied for multifamily buildings. Includes a $14,000 cap per household, with an $8,000 cap for heat pump costs, $1,750 for a heat pump water heater, and $4,000 for electrical panel/service upgrade. Other eligible rebates include electric stoves, clothes dryers, and insulation/air sealing measures. Alaska’s Allocation is $37.1 million . No State match is required. This funding is not available at this time. 17 AEA is collaborating with the Alaska Housing Financing Corporation to distribute Alaska’s allocation of $74 Million Home Energy and High Efficiency Rebate Allocations Black Rapids Training Site (BRTS) Defense Community Infrastructure Pilot Program AEA partnered with Golden Valley Electric Cooperative (GVEA) was awarded this grant from the Office of Local Defense Community Cooperation under the Defense Community Infrastructure Pilot Program. Federal Receipt Authority of $12.7 Million received in fiscal year 2024. A $3 million supplemental budget request was submitted by AEA to complete additional work requested by the Department of Defense. No State match is required. $15.7 Million GVEA will use the funds to extend an transmission line 34 miles along the Richardson Highway to BTRS. Currently, BTRS is powered by three diesel generators that are nearing the end of their useful lives. This extension will improve long-term sustainability and reliability for BRTS by tying them into GVEA’s power grid. AEA Overview and Programs Update | House Energy Committee | February 1, 2024 18 Other Federal Funding Opportunities Energy Efficiency Revolving Loan Fund –$4.5 million $4,569,780 to establish and capitalize a revolving loan fund, under which the State shall provide loans and grants for residential energy audits, upgrades, and retrofits to increase energy efficiency, physical conform and air quality of existing building infrastructure. AEA will administer the program in collaboration with the Alaska Housing Finance Corporation (AHFC). State Energy Program –$3.6 million $3,661,930 to develop Statewide Energy Plan and Statewide Energy Security Profile, as well as (1) update AkWarm Energy Modeling Software to the requirements imposed by the Inflation Reduction Act and (2) modernize Alaska Retrofit Information Systems database to accept the AkWarm modifications in collaboration with AHFC. Electric Vehicle (EV) Charging Equipment Competitive –$1.6 million $1,670,000 to (1) increase access to vehicle electrification in multiple rural and underserved communities across Alaska; (2) demonstrate the benefits of EVs to key decision-makers and the broader public to accelerate clean transportation transition; and (3) support the development of community charging equipment. A 20% match is required, shared by AEA and project partners. Funds will become available in Fall 2023. State-Based Home Energy Efficiency Contractor Training Grant Program –$1.3 million $1.3 million to fund a State-Based Home Energy Efficiency Contractor Training Grant Program to develop and implement a state workforce energy program that prepares workers to deliver energy efficiency, electrification, and clean energy improvements, including those covered by the Inflation Reduction Act Home Energy Rebate Programs. 19AEA Overview and Programs Update | House Energy Committee | February 1, 2024 AEA and AHFC collaborating to develop a Statewide Solar Program: -AEA focus on development of community solar projects in disadvantaged communities using a Renewable Energy Fund- style grant program. -AHFC focus on residential rooftop solar for low income households. Program benefits: -Energy cost savings -Increased resiliency -Equitable access to solar -Asset ownership benefits low income and disadvantaged communities -Workforce development -Reduction in greenhouse gas emissions This is a competitive grant program —no match required. AEA and AHFC submitted an application for a $100 million grant. Solar For All Competition $100 Million (Application Pending) 20 AEA Overview and Programs Update | House Energy Committee | February 1, 2024 Alaska Energy Authority 813 W Northern Lights Blvd. Anchorage, AK 99503 Phone: (907) 771-3000 Fax: (907) 771-3044 akenergyauthority.org For more information, please contact AEA Executive Director Curtis W. Thayer Contact Us 21 Senate Bill 125: Alaska’s Energy Subsidiary Presented by Alaska Housing Finance Corporation & Alaska Energy Authority to the Senate Finance Committee Feb. 8, 2024 2 INTRODUCTION Bryan Butcher CEO/Executive Director Alaska Housing Finance Corporation Akis Gialopsos Deputy Executive Director Alaska Housing Finance Corporation Curtis W. Thayer Executive Director Alaska Energy Authority Tim Sandstrom Chief Operating Officer Alaska Energy Authority PRESENTATION OUTLINE •Policy objectives •Role of Alaska Housing Finance Corporation (AHFC) in energy •Role of Alaska Energy Authority (AEA) in energy •Senate Bill 125 overview and proposed implementation 3 POLICY OBJECTIVES Create a subsidiary corporation of the Alaska Housing Finance Corporation to •Coordinate with Alaska Energy Authority, provide technical assistance for renewable energy projects and home improvements •Magnetize federal, private for-profit, and private non-profit capital to enhance an investment stack for renewable opportunities •Collaborate to provide financing opportunities and tools for renewable projects for Alaskans. 4 POLICY OBJECTIVES (CONTINUED) Subsidiary proposed to spur sustainable energy projects: •The subsidiary would help spur energy innovation consistent with Governor Dunleavy’s administration objectives •Office of Energy Innovation (AO 340) •Alaska Energy Security Task Force (AO 344) 5 Subsidiary can help Alaska be competitive for historic federal funding opportunities to improve the energy profile for homes and businesses: •The U.S. Environmental Protection Agency’s Greenhouse Gas Reduction Fund (GHGRF) grant opportunity from a pool of $27 billion in available funding (award announcements expected in spring/summer 2024; funds distributed nationally later) •Waivers from the Department of Energy for loan guarantees if funded through a State Energy Finance Institute (e.g. Energy Subsidiary) •Stacked with time limited energy tax credits POLICY OBJECTIVES (CONTINUED) 6 Joint Application with AHFC and AEA on Solar for All: Aggregate $100 million applied to EPA for the Solar for All portion of the Greenhouse Gas Reduction Fund •Evenly split between AHFC (residential solar installation) and community utility grade solar (AEA) •Required focus on lower income households •$5 million set aside for financing POLICY OBJECTIVES SUMMARY 7 Alaska Housing Finance Corporation (AHFC) has a long track record of managing innovative programs to tackle energy challenges for homeowners and communities. ROLE OF AHFC IN ENERGY 8 Energy Efficiency Interest Rate Reduction: •AHFC offers interest rate reductions when financing new or existing energy efficient homes, or when borrowers make energy improvements to an existing home Renovation Loan Option: •Allows for improvements that increases a home’s value; increases the energy efficiency of a home; and incorporates universal design principles to age-in-place –all while improving Alaska’s aging housing stock Since FY20, AHFC has financed 434 renovation loans for just over $100M ROLE OF AHFC IN ENERGY (CONTINUED) 9 Weatherization: •AHFC administers the federal and state weatherization program, making rural and urban homes in Alaska safer, more resilient to the elements, and more affordable to heat. •Manages AK Warm Energy Modeling Software, Home Energy Rating System (HERS) and statewide database of all home energy audits. •Provides training and certification for all Energy Raters •Building and Energy Codes –reference statutory requirements to ensure investments meet thermal and lighting standards Workforce readiness EENow training ROLE OF AHFC IN ENERGY (CONTINUED) 10 Experiences meeting unique challenges: •AHFC has a tradition of working with sister agencies and organizations, stepping up, and meeting the needs of Alaskans •Standing up programs to help Alaskans in need: •Home Energy Rebate •Emergency Rental Assistance and Homeowner Assistance •Standing up subsidiaries to meet policy needs of Alaskans: •Alaska Corporation on Affordable Housing ROLE OF AHFC IN ENERGY (CONTINUED) 11 Alaska Housing Finance Corporation has decades of experience crafting programs and structures to meet the energy needs of Alaskans. ROLE OF AHFC IN ENERGY SUMMARY 12 Alaska Corporation for Affordable Housing is constructing 58 new units in Fairbanks. Completion date: Sept. 2024. ABOUT AEA 13 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. 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 ACTIVE PROJECTS AND SERVICES 14 Senate Bill 125 proposes one key action for the Legislature’s consideration: •Empower AHFC to work with AEA on developing sustainable energy development through several tools, including establishing a non-profit subsidiary corporation. SENATE BILL 125: OVERVIEW 15 1.Legislation empowering AHFC to establish a non-profit subsidiary is enacted; 2.The AHFC Board of Directors, in consultation with legal counsel, creates a non-profit subsidiary corporation. Composes bylaws and initial regulations by AHFC for the non-profit subsidiary; 3.The non-profit subsidiary acquires relevant staff and works with Alaska Energy Authority and AHFC on crafting the sustainable energy development programs articulated in Senate Bill 125; 4.The non-profit subsidiary begins aggregating federal, state, and/or third- party funding. Funding stack and conditions inform programmatic development. SENATE BILL 125: PROPOSED POLICY IMPLEMENTATION PROCESS 16 QUESTIONS? 17 REDUCING THE COST OF ENERGY IN ALASKA Renewable Energy Fund Round 16 Recommended Projects Conner Erickson -AEA Director of Planning Karen Bell -AEA Manager of Planning REDUCING THE COST OF ENERGY IN ALASKA SAFE, RELIABLE, & AFFORDABLE ENERGY SOLUTIONS House Energy CommitteeFebruary 13, 2024 REDUCING THE COST OF ENERGY IN ALASKA Renewable Energy Fund (REF) Overview AEA, in concert with the REF Advisory Committee, has forwarded to the Legislature a capitalization request of $32 million for Round 16 of the REF. An appropriation of $32 million would fund all 24 recommended projects. Funding approval for the REF is at a sole discretion of the Legislature and Governor. $317 million in REF appropriations by the State since REF’s inception in 2008. 100+ operational projects, 60 are in development. The REF’s sunset date provision was repealed with House Bill 62, signed into law by Governor Dunleavy on May 25, 2023. 02 REF Highlights Round 15: 18 Projects –$17M Round 14: 27 Projects –$15M Round 13: 11 Projects –$4.75M REDUCING THE COST OF ENERGY IN ALASKA REF: Impact and Evaluation Report 2023 -Key Findings 3 REF has played a significant role in supporting the development of Alaska's renewable energy sector. Key findings of the report are: Approximately 85 million gallons of diesel and approximately 2.2 million cubic feet of natural gas have been displaced cumulatively through 2022. Approximately 1,110,424 gross metric tons of CO2 and approximately 1,063,548 net metric tons of CO2 were mitigated cumulatively through 2022. Since its inception the REF program has secured over $317 million in state funds, leveraging over $300 million in federal and local funds. Every dollar deployed through the REF program resulted in $2.07 in benefits returned to residents and the economy. The REF program has created approximately 2,930 new jobs. . Note: AEA commissioned BW Research Partnership, an independent third-party research consultancy, to assess the economic, community, and environmental impacts of the REF program. The report can be accessed on AEA’s website, 2023 REF Evaluation Report. 03 REDUCING THE COST OF ENERGY IN ALASKA REF 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: o Has a population of 10,000 or less, and o does not have economically viable renewable energy resources it can develop. ELIGIBLE APPLICANTS INCLUDE: electric utility holding a certificate of public convenience and necessity (CPCN); independent power producer ; local government; or, or other governmental utility, including a tribal council and housing authority. 04 REDUCING THE COST OF ENERGY IN ALASKA REF Funding Limits REF Round XVI Grant Funding Limits Phase Low Energy Cost Areas*High Energy Cost Areas** Total Project Grant Limit $2 Million $4 Million Phase I:Reconnaissance Phase II:Feasibility and Conceptual Design The per project total of Phase I and II is limited to 20% of anticipated construction cost (Phase IV), not to exceed $2 Million. Phase III: Final Design and Permitting 20% of anticipated construction cost (Phase IV), and counting against the total construction grant limit below. Phase IV:Construction and Commissioning $2 Million per project, including final design and permitting (Phase III) costs, above. $4 Million per project, including final design and permitting (Phase III) costs, above. Exceptions Biofuel projects Biofuel projects where the applicant does not intend to generate electricity or heat for sale to the public are limited to reconnaissance and feasibility phases only at the limits expressed above. Biofuel is a solid, liquid or gaseous fuel produced from biomass, excluding fossil fuels. Geothermal projects The per-project total of Phase I and II for geothermal projects is limited to 20% of anticipated construction costs (Phase IV), not to exceed $2 million /$4 million (low/high cost areas). Any amount above the usual $2 million cap spent on these two phases combined shall reduce the total Phase III and IV grant limit by the same amount, thereby keeping the same total grant dollar cap as all other projects. This exception recognizes the typically increased cost of the feasibility stage due to test well drilling. REF Round XVI funding limits are governed 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 connected to the Railbelt electrical grid or 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 Areas are 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. 5 REDUCING THE COST OF ENERGY IN ALASKA REF Rounds 16 Timeline June 29, 2023 August 29, 2023 January 9, 2024 January 25, 2024 July 1, 2024December 2023 Request for Application Posted AEA’s Evaluation of Applications Complete Application Submission Deadline Meeting with Renewable Energy Fund Advisory Committee (REFAC) If Capital Funds Are Appropriated by Legislature, and approved by the Governor, Issuance of Grant Agreements Can Begin AEA Provides Recommendations Approved by REFAC to Legislature 29 REDUCING THE COST OF ENERGY IN ALASKA 6 REDUCING THE COST OF ENERGY IN ALASKA REF Evaluation Process: Stage 1 Eligibility and Completeness The 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 fail to meet the requirements of Stage 1 are rejected by the Authority. Each applicant whose application is rejected is notified of the Authority’s decision. 7 STAGE 1 CRITERIA PASS/FAIL Applicant eligibility, including formal authorization and ownership, site control, and operation PASS/FAIL Project Eligibility PASS/FAIL Complete application,including Phase description(s)PASS/FAIL REDUCING THE COST OF ENERGY IN ALASKA REF Evaluation Process: Stage 2 Technical and Economic Feasibility Stage 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. 8 CRITERIA CRITERIA DESCRIPTION WEIGHT 1 Project management, development, and operation 25% 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 ALASKA REF Evaluation Process: Stage 3 Project Ranking Stage 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 •Compliance All Stage 3 criteria are weighted as follows as part of the evaluation process. The Stage 3 scoring is used to determine the ranking score. 9 CRITERIA CRITERIA DESCRIPTION WEIGHT 1 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/Fail 9 Compliance Pass/Fail REDUCING THE COST OF ENERGY IN ALASKA REF Evaluation Process: Stage 4 Ranking and Regional Spreading Stage 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 of advice from the Renewable Energy Fund Advisory Committee (REFAC ). As 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. 10 REFAC Roles Statutes (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 in AS 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 rank. REDUCING THE COST OF ENERGY IN ALASKA REFAC Advisory Committee 11 NAME TITLE SECTOR APPOINTED BY Clay Koplin Chief Executive Officer, Cordova Electric Cooperative Small rural electric utility Governor Rose,Chris Founder / Executive Director, RenewableEnergy Alaska Project (REAP)Business/organizationinvolved in renewable energy Governor Iliodor Philemonof III Government Relations Administrator, Calista Corporation Representative of an Alaska Native Organization Governor Amberg, Alicia Executive Director, Associated General Contractors of Alaska Denali Commission Governor Janorschke,Bradley General Manager,Homer Electric Association Large urban electric utility Governor Stedman, Bert Senator Senate Member 2 Senate President Wilson, David Senator Senate Member 1 Senate President Carpenter, Ben Representative House Member 2 Speaker of the House Cronk, Mike Representative House Member 1 Speaker of the House REDUCING THE COST OF ENERGY IN ALASKA Proposed REF Capitalization for FY2025 / Round XVI The State of Alaska FY2025 proposed capital budget allocates $5 million for REF Round 16 grant funding of recommended projects. The current list of 24 recommended applications yields a total grant request of $32,006,012. With the proposed REF budget of $5 million, there would be insufficient funding to cover the current Round 16 recommendations. Additional funding of $27.06 million would need to be allocated to fund all of the current Round 16 recommendations or some of the Round 16 recommendations will not be funded. The table to the right indicates historical REF program funding from the inception of the REF program to the FY2024 appropriation. $17M was approved in the FY2024 capital budget for REF Round 15, the largest REF capitalization since FY2014. 12 REDUCING THE COST OF ENERGY IN ALASKA Round XVI –Recommended Applications Summary The 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)Construction Several applications received in Round 16 requested funding for more than one phase. 13 Applications by Project Phase No.of Applications REF Funds Recommended Construction 11 $ 16,268,668 Design 1 $ 883,012 Design, Construction 8 $ 11,183,082 Feasibility 2 $ 3,280,500 Reconnaissance 1 $ 121,250 Reconnaissance, Feasibility 1 $ 269,500 Total 24 $32,006,012 $0 $2,000,000 $4,000,000 $6,000,000 $8,000,000 $10,000,000 $12,000,000 $14,000,000 $16,000,000 $18,000,000 Recommended Funding by Project Phase REDUCING THE COST OF ENERGY IN ALASKA There are 24 recommended applications, totaling a request of $32 million. Round XVI –Recommended Applications Summary 14 Applications by Energy Region No.of Applications REF Funds Recommended Bering Straits 1 $ 4,000,000 Bristol Bay 4 $ 6,144,569 Lower Yukon-Kuskokwim 6 $ 3,226,092 Northwest Arctic 1 $ 3,675,000 Railbelt 7 $ 6,957,514 Southeast 3 $ 4,771,724 Yukon-Koyukuk Tanana 2 $ 3,231,113 Total 24 $32,006,012 Applications by Technology No.of Applications REF Funds Recommended Biomass 3 $2,607,514 Hydro 7 $ 7,615,236 Solar 8 $ 13,670,456 Storage 4 $ 5,373,827 Wind 2 $ 2,738,979 Total 24 $32,006,012 $0 $2,000,000 $4,000,000 $6,000,000 $8,000,000 $10,000,000 $12,000,000 $14,000,000 $16,000,000 Biomass Hydro Solar Storage Wind Recommend Funding by Technology $0 $1,000,000 $2,000,000 $3,000,000 $4,000,000 $5,000,000 $6,000,000 $7,000,000 $8,000,000 Recommend Funding by Energy Region REDUCING THE COST OF ENERGY IN ALASKA Round XVI Geographical Distribution of Recommended Applications 15 REDUCING THE COST OF ENERGY IN ALASKA Applications Forwarded to the Legislature for a Decision on Funding 16 •*If appropriated by the Legislature and approved the Governor, this funding would become effective July 1, 2024 for inclusion in the Fiscal Year 2025 budget. Orange line indicates the limit of recommended projects able to be funded with a $5 million appropriation; funding additional projects will require an increased appropriation to the total recommended funding amount. The Kotzebue Community Scale Energy Storage and Inertia Project would only be funded up to $991,887. Recommended Projects Recommendation App. #Applicant Project Title Phase Energy Region Election District Technology Community Grant Funds Requested Matching Funds Stage 3 Score Benefit / Cost Ratio HEC RegionRank State Rank Funding Level Funding Amount 16028 Tanana Chiefs Conference Ruby Community Solar PV and Battery Storage Design, Construction Yukon-Koyukuk/Upper Tanana 36-R Solar, Storage Ruby $2,008,113 $874,906 90 1.23 $12,913 1 1 Full w/Special Provision $2,008,113 16005 Solstice Energy LLC Kenai Peninsula Solar Farm Design, Construction Railbelt various Solar HEA service area $2,000,000 $48,027,664 88 1.77 $7,120 1 2 Full $2,000,000 16022 Kotzebue Electric Association Kotzebue Community Scale Energy Storage and Inertia Construction Northwest Arctic 40-T Storage Kotzebue $4,000,000 $3,500,000 85 1.73 $7,920 1 3 Partial $3,675,000 16015 Alaska Electric & Energy Coop AEEC / KPB CPL Landfill Gas CHP Project Construction Railbelt 6-C Biomass Homer $1,115,014 $875,000 84 1.61 $7,120 2 4 Full $1,115,014 16013 Igiugig Village Council Igiugig Tribal Utility Solar PV Design, Construction Bristol Bay 37-S Solar Igiugig $1,723,709 $20,933 77 1.03 $13,627 1 5 Full $1,723,709 16008 City of Pelican, Utilities Pelican Hydro Relicensing Project, Restoration, Repair Design, Construction Southeast 2-A Hydro Pelican $650,474 $50,000 76 1.63 $6,374 1 6 Full $650,474 16020 Naknek Electric Association Naknek Solar PV on Cape Suwarof Construction Bristol Bay 37-S Solar Naknek $3,210,000 $900,000 74 0.57 $9,551 2 7 Partial $3,137,848 16014 Goat Lake Hydro, Inc.Goat Lake Storage Expansion Study Reconnaissance Southeast 3-B Hydro Skagway $121,250 $52,250 71 0 $6,371 2 8 Full $121,250 Please see related summary report for details regarding details of the individual applications available on AEA’s website -REF Round 16 Summary Report. REDUCING THE COST OF ENERGY IN ALASKA 17 Recommended Projects Recommendation App. #Applicant Project Title Phase Energy Region Election District Technology Community Grant Funds Requested Matching Funds Stage 3 Score Benefit / Cost Ratio HEC RegionRank State Rank Funding Level Funding Amount 16003 Nuvista Light &Electric Coop Nuvista Kwethluk Wind and Battery Project Completion Construction Lower Yukon-Kuskokwim 38-S Wind, Storage Kwethluk $738,979 $0 71 0.67 $7,869 1 9 Full w/Special Provision $738,979 16007 Alaska Village Electric Cooperative Quinhagak Battery Energy Storage System Project Construction Lower Yukon-Kuskokwim 38-S Storage Quinhagak $443,956 $707,625 70 0.88 $6,962 2 10 Full $443,956 16018 City of Nenana Nenana Biomass District Heat System, Final Phase Construction Yukon-Koyukuk /Upper Tanana 36-R Biomass Nenana $1,223,000 $168,322 69 1.14 $6,864 2 11 Full $1,223,000 16025 Puvurnaq Power Kongiganak 100 kW Solar Energy Design, Construction Lower Yukon-Kuskokwim 38-S Solar Kongiganak $728,603 $674,330 69 0.6 $9,427 3 12 Partial $720,453 16009 Alaska Renewables Railbelt Wind Diversification Alaska Renewables Feasibility Railbelt various Wind, Transmission, Storage Railbelt $2,000,000 $2,187,000 69 1.22 $5,458 4 13 Full $2,000,000 16001 City of Homer Homer Energy Recovery Project Construction Railbelt 6-C Hydro Homer $280,000 $90,000 68 0.01 $7,120 5 14 Full $280,000 16026 Atmautluak Tribal Utilities Atmautluak ETS Installation, Integration and Commissioning Construction Lower Yukon-Kuskokwim 38-S Wind, Other Atmautluak $286,227 $188,160 68 0.29 $8,538 4 15 Full $286,227 16021 Southeast Alaska Power Agency Southeast Alaska Grid Resiliency (SEAGR)Design, Construction Southeast 1-A, 2A Hydro Ketchikan, Petersburg, Wrangell $4,000,000 $18,592,510 68 0 $6,730 3 16 Full $4,000,000 Please see related summary report for details regarding details of the individual applications available on AEA’s website -REF Round 16 Summary Report. Applications Forwarded to the Legislature for a Decision on Funding REDUCING THE COST OF ENERGY IN ALASKA 18 ** Note: On Jan. 9, 2024, the REFAC voted to change the rank for application #16024 from a rank of 11 to a rank of 23 due to potential technical risks associated with fuel supply commitments. Recommended Projects Recommendation App. #Applicant Project Title Phase Energy Region Election District Technology Community Grant Funds Requested Matching Funds Stage 3 Score Benefit / Cost Ratio HEC RegionRank State Rank Funding Level Funding Amount 16006 Alaska Village Electric Coop. Chevak Battery Energy Storage System Project Construction Lower Yukon-Kuskokwim 38-S Storage Chevak $968,644 $0 66 0.62 $6,902 5 17 Full $968,644 16023 Pedro Bay Village Council Knutson Creek Hydro Project Construction Construction Bristol Bay 37-S Hydro Pedro Bay $400,000 $7,200,000 65 0.08 $9,390 3 18 Full w/Special Provision $400,000 16016 Akiachak, Ltd Akiachak Native Community 200 kW Solar Energy Project Design, Construction Lower Yukon-Kuskokwim 38-S Solar Akiachak $1,443,257 $2,265,809 64 0.33 $8,870 6 19 Partial w/Special Provision $67,833 16019 Nome Joint Utility System NJUS Solar Nome Banner Ridge Solar Farm Construction Bering Straits 39-T Solar Nome $4,000,000 $50,000 60 0.57 $9,139 1 20 Full $4,000,000 16012 Matanuska Electric Association Hunter Creek Hydroelectric Feasibility Study Project Feasibility Railbelt various Hydro, Transmission, Storage MEA service area $1,280,500 $384,500 58 0.67 $5,920 6 21 Full $1,280,500 16010 City of Chignik Chignik Hydroelectric Power System Design Bristol Bay 37-S Hydro Chignik $883,012 $44,346 57 1.06 $7,701 4 22 Full $883,012 **16024 Golden Valley Electric Healy Unit 2 Coal to Biomass Fuel Conversion Recon, Feasibility Railbelt various Biomass GVEA service area $269,500 $58,500 70 0 $8,420 3 23 Full $269,500 16004 Utopian Power LLC Sterling Solar Project Design, Construction Railbelt 8-D Solar Sterling $2,000,000 $2,000,000 37 0.7 $7,120 7 24 Partial w/Special Provision $12,500 Applications Forwarded to the Legislature for a Decision on Funding REDUCING THE COST OF ENERGY IN ALASKA Alaska Energy Authority 813 W Northern Lights Blvd. Anchorage, AK 99503 Phone: (907) 771-3000 Fax: (907) 771-3044 akenergyauthority.org Thank You 19 Page 1 of 1 Legislative Requests/AEA Responses Date Request Who Assigned to Date answered 2/8/24 Gas generation in Anchorage bowl. Anne Rittgers from Senator Bishops Office Curtis 2/8/24 2/5/24 SuWa Hydro Project Status Letter- resend Anneliese from Senator Hughes office Jennifer 2/2/24 1/16/24 Su-Wa Hydro questions Senator Hughes Curtis 1/23/24 12/16/23 Hydroelectric project funding. OMB through Micaela Fowler. Tim / Conner / Curtis 12/15/23 15 year lookback on all energy projects the state has funded in Fairbanks Region. GO and GLO Tim / Curtis 12/18/23 12/1/23 Alaska Energy Security Task Force Report Representative Rauscher’s office (Craig Valdez) Curtis 12/2/2023 11/15/23 How does GRIP Award fit into the “comprehensive statewide energy plan.” How do the two battery banks integrate with Westinghouse Announcement. Representative Mike Prax Conner / Curtis 12/2/2023 February 14-15, Legislative Visits Legislative Visits – EO 128 Feb 14 Curtis’ Meetings Tim’s Meetings 8:30 am Senator Jess Kiehl, RM 514 Rep. Kevin McCabe, RM 102 9:00 am Rep. Andrew Gray, RM 434 Rep. Cliff Groh, RM 430 9:30 am Rep. Donna Mears, RM 112 10:00 am Rep. Mike Cronk, RM 418 Rep Genevieve Mina, RM 420 10:30 am 11:00 am Governor’s Office - meeting (LUNCH) 11:30 am Travel to Baranof (Douglas Room, 127) Rep. Delana Johnson, RM 505 12:00 pm Presentation - Greater Fairbanks Chamber – Fly in Luncheon – Baranoff Hotel Sen. David Wilson, RM 124 (12:15 pm) 12:30 pm Representative Saddler RM 204 1:00 pm Travel back to Legislature Senator Robert Myers, RM 417 1:30 pm Rep Calvin Schrage, RM 404(1:30-1:45 pm) Rep. Laddie Shaw, RM 403 1:45 pm Senator Gary Stevens RM 111(1:45 pm) 2:00 pm Rep. Zack Fields, RM 13 Rep. David Eastman, RM 114 2:30 pm Rep. Justin Ruffridge, RM 104 (2:25 pm) Senator Mike Shower, RM 419 3:00 pm Speaker Cathy Tilton, RM 208 3:30 pm Rep. Mike Cronk, RM 418 4:00 pm Rep Jennie Armstrong, RM 422 (4:15 pm) 4:30 pm Rep. Rebecca Himschoot, RM 409 5:00 pm Senator Cathy Giesel, RM 427 Rep. Dan Ortiz, RM 500 5:15 pm Rep Julie Coulombe, RM 502 (5:15 pm) Feb. 15 Curtis’ Meetings Tim’s Meetings 8:30 am Senator Donny Olson, RM 508 Rep. Maxine Dibert, RM 424 9:00 am Rep. Edgmon / Senator Hoffman Rep. Mike Prax, RM 108 9:30 am Rep. Craig Johnson, RM 216 10:00 am Senator Murkowski – Address 10:30 am 11:00 am Senator Click Bishop, RM 504 Senator Matt Claman, RM 429 11:30 am Senator Bert Stedman, RM 518 Senator Elvi Gray-Jackson, RM 30 DATE DESCRIPTION TOPIC AND AUDIENCELOCATION TEAM MEMBERFebruary 22, 2024 Media Interview Chignik Power Restored, Christina McDermott, KDLG in Dillingham Phone Curtis W. ThayerFebruary 20, 2024 PresenterAEA Overview and Programs Update to Fairbanks Economic Development Corporation: Energy for All Alaska Task ForceVirtual Curtis W. ThayerFebruary 19, 2024 Attendee Utility Working Group Comms Monthly Check-In Virtual Brandy M. DixonFebruary 14, 2024 Presenter AEA Overview and Programs Update to Greater Fairbanks Chamber of Commerce In Person Curtis W. ThayerFebruary 8, 2024 Newsletter AKEVWG February Newsletter Sent to 266 Recipients Email Brandy M. DixonFebruary 7, 2024 Presenter AEA Overview and Programs Update to Southeast Conference Virtual Curtis W. ThayerFebruary 7, 2024 Presenter AEA Presentation to Alaska Forum on the Environment In PersonAudrey Alstrom, Conner EricksonFebruary 6-9, 2024 Attendee/Opening Remarks 2024 National Association of State Energy Officials (NASEO) Energy Policy Outlook ConferenceThe Fairmont, Washington, DCCurtis W. ThayerFebruary 6, 2024 Media Interview Bond Package, James Brooks, Alaska Beacon Phone Curtis W. ThayerFebruary 1, 2024 Presenter AEA Executive Order 128 Overview Presentation to House Energy Committee In Person Curtis W. ThayerFebruary 1, 2024 Presenter AEA Overview and Programs Update to House Energy Committee In Person Curtis W. ThayerJanuary 31, 2024 Host/Presenter AEA RE-VEEP Informational Presentation to Applicants In Person Yosty StormsJanuary 31, 2024 Presenter AEA Overview and Programs Update to Alaska Power Association In Person Curtis W. ThayerJanuary 29, 2024 Press Release AEA releases 2023 REF Impact and Evaluation Report Email/Social Media Brandy M. DixonJanuary 25, 2024 Vendor Booth AEA Vendor Booth at the Mat-Su Transportation FairFairgrounds, Ravel Hall, Palmer, AKQuinlan Harris, Yosty StormsJanuary 24, 2024 Presenter AEA SESP Presentation to NASEO Island Cohort In Person Audrey AlstromJanuary 22, 2024 Media Interview Executive Order 128, James Brooks, Alaska Beacon Phone Curtis W. ThayerJanuary 18, 2024 Host AKEVWG Technical Session: DriveOhio – Construction and Opening of the first NEVI-Funded Sites In-Person/Virtual AEA EV TeamJanuary 17, 2024 Presenter AEA ARPPOW Meeting to Rural Operator Virtual Kyle KillmerJanuary 12, 2024 Newsletter AKEVWG January Newsletter Sent to 266 Recipients Email Brandy M. DixonJanuary 9, 2024 Host/Presenter Renewable Energy Grant Fund Advisory Committee Meeting In Person/VirtualKaren Bell, Conner EricksonJanuary 9, 2024 Media Inquiry Manokotak, Christina McDermott, KDLG Radio in Dillingham Phone Call Tim SandstromJanuary 2, 2024 Press Release AEA opens application for $22.1 million in grid resilience sub-awards Email/Social Media Brandy M. DixonDecember 21, 2023 Podcast Alaska Powerline Podcast, Michael Rovito, Alaska Power Association Virtual Curtis W. ThayerDecember 20, 2023 Press Release AEA awarded $1.67 million from DOE for EV charging infrastructure in rural Alaska Email/Social Media Brandy M. DixonDecember 19, 2023 Press Release AEA announces $2.6 million in grants available for rural energy projects Email/Social Media Brandy M. DixonDecember 14, 2023 Newsletter AKEVWG December Newsletter Sent to 265 Recipients Email Brandy M. DixonDecember 14, 2023 Host/Presenter Alaska Electric Vehicle Working Group (AKEVWG) Technical Session: Car Dealership Panel DiscussionVirtual Josi HartleyDecember 14, 2023 Attendee Utility Working Group Comms Monthly Check-In Virtual Brandy M. DixonDecember 11, 2023 Press Release AEA launches a new digital library of over 7,500 items Email/Social Media Brandy M. DixonDecember 8, 2023 Media Interview Alaska National Electric Vehicle Infrastructure (NEVI) Plan, Madeleine Ngo, The New York Time Phone CallCurtis W. Thayer, Josi HartleyDecember 6, 2023 PresenterAEA Federal Funding Presentation to 73rd Annual Alaska Municipal League Local GovernmentConferenceIn Person Conner EricksonAEA COMMUNITY OUTREACHLast Updated on February 22, 2024 (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 MEMBERDecember 6-8, 2023Attendee/Presenter/VendorBooth73rd Annual Alaska Municipal League Local Government ConferenceDena’ina Civic and ConventionCenter, Anchorage, AKAudrey Alstrom, Katherine Aubrey, Karen Bell, Brandy M. Dixon, Conner Erickson, Josi Hartley, Anna M. Larsen, Taase Toli-Moana, Bill Price, Curtis W. ThayerNovember 29, 2023 Attendee/Presenter Legislative Forum: Energy Generation and TransmissionLegislative Information Office,Anchorage , AKBrandy M. Dixon, CurtisThayer, Tim SandstromNovember 28, 2023 PresenterAEA Overview and Funding Opportunities Presentation to 33rd Annual Bureau of Indian Affairs' TribalProviders ConferenceIn Person Audrey AlstromNovember 28-30, 2023Attendee/Presenter/Vendor Booth33rd Annual Bureau of Indian Affairs' Tribal Providers ConferenceDena’ina Civic and Convention Center, Anchorage, AKAudrey Alstrom, Katherine Aubrey, Karen Bell, Brandy M. Dixon, Conner Erickson, Josi Hartley, Quinlan Harris, Dawn Molina, Khae Pasao, Bill Price, Yosty Storms, Karen TurnerNovember 23, 2023 Presenter AEA and Task Force Overview Presentation to Golden Valley Electric Association In Person Curtis W. ThayerNovember 15, 2023 Host Alaska Energy Security Task Force Meeting In-Person/Virtual Curtis W. ThayerNovember 15, 2023 Presenter Institute of Electrical and Electronics Engineers, Alaska's Electric Vehicles Program In Person Josi HartleyNovember 9, 2023 Newsletter AKEVWG November Newsletter Sent to 270 Recipients Email Brandy M. DixonNovember 9, 2023 Media Inquiry Inflation Reduction Act Home Rebate Programs, Madeleine Ngo, The New York Times Email Brandy M. DixonNovember 9, 2023 Attendee Utility Working Group Comms Monthly Check-In Virtual Brandy M. DixonNovember 7, 2023 Press Release AEA and DOT&PF Receive FHWA Approval for FY24 Alaska NEVI Plan Email/Social Media Brandy M. DixonNovember 7, 2023 Host Alaska Energy Security Task Force Meeting In-Person/Virtual Curtis W. ThayerNovember 7, 2023 Media Interview Grid Resilience and Innovation Partnership Program Award, James Brooks, Alaska Beacon Phone Curtis W. ThayerOctober 31, 2023 Host Alaska Energy Security Task Force Meeting In-Person/Virtual Curtis W. ThayerOctober 30, 2023 Media Inquiry Renewable Energy in Alaska, Jim Carlton, The Wall Street Journal Phone Brandy M. DixonOctober 26, 2023 Host AKEVWG Technical Session: Site Host Selection, Schedule and Path Forward In-Person/Virtual Josi HartleyOctober 26, 2023 Media Inquiry Alaska Energy Security Task Force Report Public Testimony, Tim Ellis, KUAC Fairbanks Email Brandy M. DixonOctober 23, 2023 Media Inquiry GRIP 1 and 2 Applications Status, Alan Bailey, Petroleum News Email Brandy M. DixonOctober 19-20, 2023 HostPower Cost Equalization Walk-In Information Session at the 2023 Alaska Federation of NativesConventionWilliam A. Egan Civic & Convention Center, Anchorage, AKKatherine AubreyOctober 18, 2023 Press Release Press Release AEA Secures $206.5 Million from U.S. DOE to modernize Alaska’s energy infrastructureEmail Brandy M. DixonOctober 16, 2023 Media Inquiry Alaska NEVI Plan, Tim Bradner, Frontiersman Email Brandy M. DixonOctober 16-19, 2023 Attendee 2023 National Association of State Energy Officials (NASEO) Annual MeetingHilton Portland Downtown, Portland, ORCurtis W. ThayerOctober 16, 2023 Media Inquiry Alaska NEVI Plan, Tim Bradner, Frontiersman Email Brandy M. DixonOctober 16, 2023 Newsletter AKEVWG October Newsletter Sent to 266 Recipients Email Brandy M. DixonOctober 16, 2023 Media Inquiry Energy Efficiency and Conservation Block Grant Program, Jenny Willoughby, KTNA Email Brandy M. DixonOctober 13, 2023 Press Release AEA Awarded $1.6 Million in U.S. DOE Funds for Clean Energy Projects in Alaska Email/Social Media Brandy M. DixonOctober 13, 2023 Media Interview Village Energy Efficiency Program, Haley Lehman, Fairbanks Daily News-Miner Phone Curtis W. ThayerOctober 10, 2023 Host Alaska Energy Security Task Force Meeting In-Person/Virtual Curtis W. ThayerAEA Community OutreachPage 2 of 4 DATE DESCRIPTION TOPIC AND AUDIENCELOCATION TEAM MEMBEROctober 5, 2023 Presenter AEA Infrastructure Update Presentation to Alaska Bankers Association Wells Fargo, Anchorage, AK Curtis W. ThayerOctober 3-5, 2023 Attendee/Host Alaska-Canada Wood Energy ConferencePipeline Training Center, Fairbanks, AKSean ArcillaOctober 3, 2023 Host Alaska Energy Security Task Force Meeting In-Person/Virtual Curtis W. ThayerOctober 3, 2023 Attendee Atlantic Council: The Frontiers Project MeetingDena’ina Civic and ConventionCenter, Anchorage, AKAudrey Alstrom, JimMendenhall, Curtis W. ThayerSeptember 29, 2023 Co-Host/Attendee Chugach Drive ElectricAnchorage Museum, Anchorage, AKJosi HartleySeptember 28, 2023 Presenter Alaska's Electric Vehicles (EV) Program to Society of American Military EngineersBP Energy Center, Anchorage, AKJosi HartleySeptember 27, 2023 Panelist Alaska Chamber Fall ForumHilton Anchorage, Anchorage AKCurtis W. ThayerSeptember 27, 2023 Presenter AEA Overview and Task Force Update Presentation to EPA Region 10U.S. Courthouse and FederalBuilding, Anchorage, AKCurtis W. ThayerSeptember 26, 2023 Exhibitor Alaska Grant Symposium (Expo -Style) hosted by Alaska’s Congressional DelegationHotel Captain Cook, Anchorage, AKHotel Captain Cook, Anchorage, AK Karen Bell, Conner Erickson, Quinlan Harris, Jim Mendenhall, Dawn Molina, Ashley Streveler, Wendy SturdivantSeptember 25 and 27, 2023 Presenter/Speaker Alaska Infrastructure Development SymposiumHotel Captain Cook, Anchorage, AKBryan Carey, Josi Hartley, Curtis W. ThayerSeptember 25, 2023 Press Release AEA and DOT&PF Announce First Round of Alaska NEVI Funding Email/Social Media Brandy M. DixonSeptember 21-22, 2023 AttendeeNASEO-NARUC-NGA-NASUCA Western Regional Roundtable: Equity Considerations in ElectricityPlanning and PolicyDenver, CO Audrey AlstromSeptember 19, 2023 Host Alaska Energy Security Task Force MeetingAEA Office (In-Person/Virtual) Anchorage AKCurtis W. ThayerSeptember 14, 2023 Newsletter AKEVWG September Newsletter Sent to 232 Recipients Email Brandy M. DixonSeptember 13, 2023 Attendee Clean Transportation Leadership RoundtableThe Lakefront Anchorage, Anchorage, AKJosi HartleySeptember 13, 2023 Host/Moderator/Speaker National Hydropower Association Alaska Regional MeetingHotel Captain Cook, Anchorage, AKAudrey Alstrom, Karen Bell, Bryan Carey, Curtis W. ThayerSeptember 7-8, 2023 Attendee/Speaker/Sponsor Alaska Wind WorkshopDena’ina Civic and ConventionCenter, Anchorage, AKSean Arcilla, Karen Bell, Quinlan Harris, Josi Hartley, Yosty StormsSeptember 7, 2023 Media Inquiry Alaska NEVI Awards, Madeleine Ngo, New York EmailSeptember 7, 2023 Host Commercial Property Assessed Clean Energy and Resilience WorkshopAEA Office (In-Person/Virtual) Anchorage AKAudrey Alstrom, Karen Bell, Josi Hartley, Ashley StrevelerAugust 30, 2023 Media Interview Grid Resilience Formula Program Award, Jamie Diep, KBBI AM 890 Phone Curtis W. ThayerAugust 29, 2023 Attendee/Speaker Houston Solar Farm Ribbon CuttingHouston Solar Farm SiteHouston, AKBrandy Dixon, ConnerErickson, Curtis W. ThayerAugust 29, 2023 Host Alaska Energy Security Task Force Meeting In-Person/Virtual Curtis W. ThayerAEA Community OutreachPage 3 of 4 DATE DESCRIPTION TOPIC AND AUDIENCELOCATION TEAM MEMBERAugust 28, 2023 Media Interview Aging Bulk Fuel Tanks, James Brooks, Alaska Beacon PhoneCurtis W. ThayerTim SandstromAugust 22, 2023 Attendee Alaska Utilities Working Group: Cook Inlet Gas Supply Poll Results Presentation Virtual Brandy M. DixonAEA Community OutreachPage 4 of 4 2/22/24, 1:39 PM Lawmakers aim numerous bills at alleviating Southcentral Alaska’s natural gas supply crunch - Alaska Beacon https://alaskabeacon.com/2024/02/20/lawmakers-aim-numerous-bills-at-alleviating-southcentral-alaskas-natural-gas-supply-crunch/1/9 ECONOMY & ENVIRONMENT GOVERNMENT & POLITICS Lawmakers aim numerous bills at alleviating Southcentral Alaska’s natural gas supply crunch A looming shortfall in gas deliveries inspires bills to slash taxes and royalties, aid utilities and encourage use of renewable energy BY: YERETH ROSEN - FEBRUARY 20, 2024 11:26 AM        Cook Inlet waves roll onto the beach at Kenai on Aug. 14, 2018. For decades, the Cook Inlet basin has supplied natural gas to fuel Southcentral Alaska. But now, even though the region still holds much natural gas, along with abundant sources of renewable energy, there are multiple threats to what used to be reliable supplies. Alaska lawmakers are considering several bills to address those threats. (Photo by Yereth Rosen/Alaska Beacon) When Southcentral Alaska utilities nearly ran out of deliverable natural gas during last month’s extreme cold snap, state lawmakers received a clear message: The looming shortage of energy has become an urgent problem.  2/22/24, 1:39 PM Lawmakers aim numerous bills at alleviating Southcentral Alaska’s natural gas supply crunch - Alaska Beacon https://alaskabeacon.com/2024/02/20/lawmakers-aim-numerous-bills-at-alleviating-southcentral-alaskas-natural-gas-supply-crunch/2/9 For years, there have been warnings about dwindling supplies of natural gas that heat homes and keep the lights on in Alaska’s most populous region. In the aftermath of a potential natural gas supply interruption, lawmakers said now is the time to act on those warnings. “I’ve got 60 years’ worth of reports in my oce on energy plans in this state. We have known what to do for 60 years, and we have done nothing,” Sen. Click Bishop, R-Fairbanks, said at a joint hearing of the House and Senate Resources Committees held on Feb. 7. “And we’ve got to do something. And it happens right here in this room. And it’s got to happen this session.” Lawmakers are now pondering a series of bills promising action. Some bills seek to stimulate more natural gas production. Some seek to create more eciency and cost savings for utilities. Some are aimed at encouraging development of more renewable energy to supplement and possibly replace natural gas. Challenges result from market changes At the heart of the problem is the unusual nature of the market for Cook Inlet basin natural gas.  A jackup rig that was brought to Cook Inlet for temporary work is seen on Aug. 15, 2018, near the beach just north of Kenai. (Photo by Yereth Rosen/Alaska Beacon) There is no lack of natural gas reserves in the Cook Inlet region. According to the U.S. Geological Survey, there is abundant known and yet-to-be-discovered natural gas in the basin: potentially 19 trillion cubic feet within the entire basin, according to a 2011 2/22/24, 1:39 PM Lawmakers aim numerous bills at alleviating Southcentral Alaska’s natural gas supply crunch - Alaska Beacon https://alaskabeacon.com/2024/02/20/lawmakers-aim-numerous-bills-at-alleviating-southcentral-alaskas-natural-gas-supply-crunch/3/9 assessment, including a potential 1.7 trillion cubic feet onshore in the Susitna area, according to a 2017 assessment. Rather, the problem is the inability to get that energy source to users. While Southcentral Alaska is the state’s most densely populated region, it is isolated and has long been considered too small on its own to support a functioning natural gas basin. That constrained-market problem has been recognized since the rst Cook Inlet region natural gas well was drilled in the 1950s. For decades, it was addressed by securing large anchor customers in Asia to achieve needed economies of scale. Starting in 1969, large quantities of Cook Inlet natural gas was liqueed at a plant in Kenai and shipped to Asia, mostly to Japan. A nearby plant that opened at around the same time converted Cook Inlet natural gas into fertilizer and also sent its product to overseas markets. But the Kenai liqueed natural gas plant made its last shipments in 2015; if it reopens, it is expected to receive LNG imports rather than send out exports. The Agrium fertilizer plant shut down in 2007, though there are glimmers of hope for some kind of resumed operations. Many proposals in search for solution That leaves the Alaska Legislature, the industry and municipalities trying to gure out some alternatives to a system that worked well in past decades but may no longer be viable. On the exploration and development side, Gov. Mike Dunleavy and some legislators are pushing for lowered taxes or royalty holidays or both. A measure introduced in January by Dunleavy, House Bill 276 and Senate Bill 184, would reduce royalties for Cook Inlet production to 5%; normally, state royalty rates are 12.5% or more. “This bill is a key component of the State’s eorts to incentivize and develop critical energy resources in the Cook Inlet,” Dunleavy’s transmittal letter says. 2/22/24, 1:39 PM Lawmakers aim numerous bills at alleviating Southcentral Alaska’s natural gas supply crunch - Alaska Beacon https://alaskabeacon.com/2024/02/20/lawmakers-aim-numerous-bills-at-alleviating-southcentral-alaskas-natural-gas-supply-crunch/4/9  A historical timeline of oil and gas development in the Cook Inlet basin is seen on the wall on Aug. 15, 2018, at the Kenai Visitors and Cultural Center. The center has a small museum that features exhibits about the Kenai Peninsula’s petroleum history, which dates back to the 1950s. (Photo by Yereth Rosen/Alaska Beacon) Another measure, House Bill 223, would reduce royalties and taxes, eliminating taxes entirely for new natural gas production. “The impact of HB 223 extends beyond mere economic metrics; it’s about securing a prosperous future for Alaska through a more robust and dynamic natural gas industry,” says the statement from the sponsor, Rep. George Rauscher, R-Sutton. A recent experiment with that idea, however, did not provide evidence that such a generous scal approach would do much to motivate new investment. A state auction in December that oered royalty-free Cook Inlet leases drew only a tepid response; just six bids were received, about the same number as in other recent Cook Inlet lease sales. Three were from Hilcorp, the dominant company operating in the inlet region. At the Feb. 7 hearing, Hilcorp‘s senior vice president for Alaska, Luke Saugier, was noncommittal when asked by Sen. Forrest Dunbar, D-Anchorage, if royalty relief would result in more production by the company. John Sims, president of Enstar Natural Gas Co., the region’s natural gas utility, said at the same hearing that scal incentives being contemplated would not be helpful without a requirement that producers use them to provide uninterrupted supplies. “We can’t have royalty relief and then have the producers give us an interruptible contract,” Sims told lawmakers. 2/22/24, 1:39 PM Lawmakers aim numerous bills at alleviating Southcentral Alaska’s natural gas supply crunch - Alaska Beacon https://alaskabeacon.com/2024/02/20/lawmakers-aim-numerous-bills-at-alleviating-southcentral-alaskas-natural-gas-supply-crunch/5/9 A dierent measure aimed at stimulating development, House Bill 257, would allow “qualied persons” to obtain Cook Inlet basin seismic data from the state without cost. Such data describes geologic structures and is useful to companies seeking to explore for hydrocarbons. Even though the price charged by the state for such data is low, the charge is still a barrier to potential exploration companies, said Rep. Tom McKay, R-Anchorage, the measure’s sponsor.  Cook Inlet seismic data sold by the state between 2018 and 2023 reaped $336,661, with about two-thirds of that paid by academic institutions, according to information presented by the Department of Natural Resources at a Feb. 5 hearing of the House Resources Committee.  The downtown Anchorage skyline is seen from the Tony Knowles Coastal Trial on June 3, 2022. Although Anchorage is Alaska’s largest city, it and the surrounding Southcentral region are considered small and isolated natural-gas markets. (Photo by Yereth Rosen/Alaska Beacon) Another measure, Senate Bill 220, would give the Regulatory Commission of Alaska authority over natural gas storage. It was introduced on Feb. 8 by Senate Majority Leader Cathy Giessel, R- Anchorage. The ability to store natural gas during times of low demand is seen as crucial to meeting needs at times of high demand, such as the recent cold snap that gripped Southcentral and Interior Alaska. Utility assistance, renewable incentives under consideration 2/22/24, 1:39 PM Lawmakers aim numerous bills at alleviating Southcentral Alaska’s natural gas supply crunch - Alaska Beacon https://alaskabeacon.com/2024/02/20/lawmakers-aim-numerous-bills-at-alleviating-southcentral-alaskas-natural-gas-supply-crunch/6/9 Other bills are aimed at improving eciency and operations of utilities that deliver electricity along the entire Railbelt, the corridor from Fairbanks to the tip of the Kenai Peninsula. Among them is a measure introduced in January by the governor, Senate Bill 217 and House Bill 307, that focuses on integrated transmission lines used by multiple utilities. The bill seeks to “reduce articial barriers to new projects that can otherwise deliver benets to Alaska consumers,” the governor’s transmittal letter said. The bill would eliminate certain charges imposed as power is sent through an integrated transmission system and would tax independent power producers the same way that cooperative and municipal electric utilities are taxed. A bill sponsored by Sen. Bill Wielechowski, Senate Bill 152, would expand access to net metering, a practice in which individuals or companies that produce their own energy through devices like solar power can get credits against their utility charges. Expanding access to net metering would help Southcentral Alaska cope with potential natural gas shortages, Wielechowski has argued. The bill was introduced last May and is currently in the Senate Labor and Commerce Committee. Lawmakers have oated the idea of borrowing money through general obligation bonds to help utilities upgrade their transmission systems, with most of the benet going to Southcentral utilities. No bill has been introduced yet, but if lawmakers do approve one, voters would have the nal say on whether the state issues its rst general obligation bonds since 2012. Other bills are aimed at stimulating renewable energy development in the region to reduce the need for natural gas. Dual bills in the House and Senate, Senate Bill 101 and House Bill 121, would establish renewable performance standards that are considered helpful in attracting investment in projects. Pending measures introduced last year by the governor, Senate Bill 125 and House Bill 154, would create an “Alaska Energy Independence Fund,” to be administered as a subsidiary of the Alaska Housing Finance Corp. In some ways an extension of the energy conservation programs already administered by AHFC, the proposed fund is intended to help homeowners and communities throughout the state pay for energy-conservation and renewable- energy initiatives. Neither bill made it out of the committee process 2/22/24, 1:39 PM Lawmakers aim numerous bills at alleviating Southcentral Alaska’s natural gas supply crunch - Alaska Beacon https://alaskabeacon.com/2024/02/20/lawmakers-aim-numerous-bills-at-alleviating-southcentral-alaskas-natural-gas-supply-crunch/7/9 last year, but the Senate version got a hearing earlier this month in that body’s nance committee. Looking at geothermal energy  Mount Spurr ’s summit crater is seen from the air on March 7, 2023. Escaping gas from one of the volcano’s main fumaroles and a dry crater oor can be seen. (Photo by Taryn Lopez/Alaska Volcano Obser vatory) Another measure introduced by the governor, Senate Bill 69 and House Bill 74, would broaden the denition of geothermal energy and streamline some regulations on potential projects. The measures were introduced last year, and the most recent action was a Senate Finance Committee hearing on Jan. 22. Although Alaska is teeming with active volcanoes and steaming hot springs, stimulating geothermal development has proved dicult. Though active volcanoes are close enough to Anchorage to dump ash on the city during periodic eruptions, development attempts so far have fallen short. “The problem is they’re just not located near our population base,” Wielechowski said in an interview. Even Mount Spurr, an active volcano just 80 miles west of Anchorage, may be too distant from the market. A state lease sale held last fall that oered 36,000 acres for exploration there drew no bids. Additionally, the geothermal resources in Alaska are not as hot as those elsewhere, such as Iceland, where geothermal energy is used successfully, Wielechowski said. 2/22/24, 1:39 PM Lawmakers aim numerous bills at alleviating Southcentral Alaska’s natural gas supply crunch - Alaska Beacon https://alaskabeacon.com/2024/02/20/lawmakers-aim-numerous-bills-at-alleviating-southcentral-alaskas-natural-gas-supply-crunch/8/9 However, geothermal development attempts continue. The state Division of Oil and Gas announced last month that it intends to grant a permit to a company to continue exploring for geothermal resources at Augustine Volcano, located on an island in lower Cook Inlet about 175 miles southwest of Anchorage. GET THE MORNING HE ADLINES DELIVERED TO YOUR INBOX S U B S C R I B E R E P U B L I S H Our stories may be republished online or in print under Creative Commons license CC BY-NC-ND 4.0. We ask that you edit only for style or to shorten, provide proper attribution and link to our web site. Please see our republishing guidelines for use of photos and graphics. YERETH R O SE N  Yereth Rosen came to Alaska in 1987 to work for the Anchorage Times. She has reported for Reuters, for the Alaska Dispatch News, for Arctic Today and for other organizations. She covers environmental issues, energy, climate change, natural resources, economic and business news, health, science and Arctic concerns. In her free time, she likes to ski and watch her son's hockey games. M O R E F R O M A U T H O R REL ATED NE WS From abortion to zoning: Short summaries of every bill in… BY JAMES BROOKS March 21, 2023 In an era of climate change, Alaska’s predators fall prey to… BY LOIS PARSHLEY, GRIST January 13, 2024 2/22/24, 1:42 PM Alaska Senate moves toward rejecting some of Gov. Dunleavy's 12 executive orders - Alaska Public Media https://alaskapublic.org/2024/02/16/alaska-senate-moves-toward-rejecting-some-of-gov-dunleavys-12-executive-orders/1/4 Alaska Senate moves toward rejecting some of Gov. Dunleavy’s 12 executive orders Sen. Jesse Bjorkman, R-Nikiski, exits the Senate chamber after a floor session on Jan. 29, 2024. (Eric Stone/Alaska Public Media) The Alaska Senate is working on nixing several of the dozen executive orders Gov. Mike Dunleavy issued earlier this year. The orders are mostly related to restructuring or eliminating various boards or commissions, and they’re set to become law unless the Legislature votes them down by mid-March. Senate committees have moved quickly to examine the 12 orders, said Senate President Gary Stevens, R-Kodiak. “We’ve never seen so many, in my experience, at one time,” he said. “We’re going through them very methodically, one at a time, making sure that they go through our committees.” The Dunleavy administration says the executive orders are efforts to eliminate inefficiencies in government and enhance accountability, but senators have heard public opposition to many of the orders as they’ve moved through committees. Several people speaking out against them have said the boards Dunleavy wants to eliminate provide important public input to ensure that a variety of perspectives are heard. By Eric Stone, Alaska Public Media - Juneau -February 16, 2024 0:000:00 / 3:21/ 3:21 2/22/24, 1:42 PM Alaska Senate moves toward rejecting some of Gov. Dunleavy's 12 executive orders - Alaska Public Media https://alaskapublic.org/2024/02/16/alaska-senate-moves-toward-rejecting-some-of-gov-dunleavys-12-executive-orders/2/4 Sen. Bill Wielechowski, D-Anchorage, said that’s been a worry for his constituents. “I think the theme is a concentration of power that many people are concerned with,” Wielechowski said. One order that drew particular interest would eliminate the management council for Wood- Tikchik State Park in Southwest Alaska. The board includes representatives of the governor’s administration, plus members of local governments and tribal groups. Wood-Tikchik is the only state park with such a management council, and the council’s chair, Cody Larson, said its structure is key to maintaining community buy-in. “We can only move at the speed of trust,” Larson told the committee. Others pushed back against orders eliminating the Susitna Basin Recreation Rivers Advisory Board and the advisory council for the Chilkat Bald Eagle Preserve in Haines. Another order would give the commissioner of the Alaska Department of Fish and Game the authority to regulate the “live capture, possession, transport, or release of native or exotic game or their eggs.” That’s currently the prerogative of the Board of Game, and Fairbanks-based wildlife biologist Michael Spindler told the committee that the board should retain that authority. “Without proper research, there’s a risk that a newly introduced species could threaten our valuable native game mammals and fisheries with excessive competition, disease or parasites,” he said. “The current Board of Game process involves multiple individuals with varying perspectives and in-depth qualifications.” Opposition to the four orders heard in the Senate Resources Committee was voluminous. Sen. Cathy Giessel, R-Anchorage and co-chair of the committee, said her committee received a three-inch-thick stack of written comments on the four orders in addition to public testimony. Over in the Senate Labor and Commerce Committee, midwives, barbers and masseuses spoke out against executive orders that would absorb their licensing boards into the Department of Commerce, Community and Economic Development. Committee chair Sen. Jesse Bjorkman, R-Nikiski, said he was listening. “It’s my desire to represent the interests of my constituents on the Kenai Peninsula who hold those professions and who have overwhelmingly expressed concern about the state government chloroforming their boards, which provide them a professional voice in crafting regulations that govern their professions,” he said. Some executive orders were not the subject of much opposition, though. That includes an order eliminating the Criminal Justice Information Advisory Board, which has met only five 2/22/24, 1:42 PM Alaska Senate moves toward rejecting some of Gov. Dunleavy's 12 executive orders - Alaska Public Media https://alaskapublic.org/2024/02/16/alaska-senate-moves-toward-rejecting-some-of-gov-dunleavys-12-executive-orders/3/4 times since 2014 and last got together half a decade ago. Another that would absorb the Alaska Council on EMS into the Department of Health also found some support from EMS professionals who said the structure of the board was outdated. One of the orders would separate the boards of the Alaska Industrial Development and Export Authority and the Alaska Energy Authority. Sen. Scott Kawasaki, D-Fairbanks, said it’s an idea lawmakers have kicked around in the past, but he said it should have come to the Legislature as a bill, not a unilateral order. “That’s sort of the process that this legislative body is used to seeing when it comes to it, not just splashing a dozen executive orders at us at the beginning of the legislative session,” he said. And one executive order hasn’t yet been heard at all in either the House or Senate. It would allow the governor to appoint all members of a board that advises the Alaska Marine Highway System. It’s scheduled for its first hearing in the Senate Transportation Committee on Feb. 20, and public testimony is slated for Feb. 22. To prevent the orders from taking effect would require a majority vote in a joint session of the Legislature, and Stevens, the Senate president, said he plans to hold an up-or-down vote on all 12. But that means the House would have to vote to invite the Senate to a joint session, and Stevens said that’s no sure bet. “We can’t force the House to meet with us. The only way we can, we can uphold or overturn the governor’s — I guess, overturn the governor’s executive orders — is by a meeting, a joint meeting, of the House and Senate. So we’re hoping the House moves ahead,” Stevens said. Rep. Craig Johnson, R-Anchorage, the House Rules Committee chair, said the leaders of both bodies need to work out the details, but he said the House was open to calling a joint session. “I don’t think there’s any reluctance to do that,” Johnson said. Stevens says he expects to discuss the prospect of a joint session with the House speaker the week of Feb. 19. Eric Stone, Alaska Public Media - Juneau Eric Stone covers state government, tracking the Alaska Legislature, state policy and its impact on all Alaskans. Reach him at estone@alaskapublic.org. Website 2/22/24, 1:47 PM It's time to reconsider the Susitna hydroelectric project | Editorials | newsminer.com https://www.newsminer.com/opinion/editorials/its-time-to-reconsider-the-susitna-hydroelectric-project/article_37c7ccbe-c7a4-11ee-bdaa-4f394a9bf1a0…1/3 https://www.newsminer.com/opinion/editorials/its-time-to-reconsider-the-susitna-hydroelectric- project/article_37c7ccbe-c7a4-11ee-bdaa-4f394a9bf1a0.html It's time to reconsider the Susitna hydroelectric project Feb 11, 2024 Alaska Energy Authority An artist’s rendition of the proposed dam on the Susitna River. Alaska Energy Authority News-Miner opinion: In 2015, former Gov. Bill Walker turned off the tap to one of the state’s energy dreams, the Susitna-Watana Hydroelectric Project. The Alaska Energy Authority (AEA), in 2011, estimated that the dam would deliver more than half of the Railbelt’s electric demand by 2025, offering a clean, renewable energy source amid the constant fluctuations of oil prices and the perpetually sidelined quest to build a natural gas pipeline from the North Slope southward. 2/22/24, 1:47 PM It's time to reconsider the Susitna hydroelectric project | Editorials | newsminer.com https://www.newsminer.com/opinion/editorials/its-time-to-reconsider-the-susitna-hydroelectric-project/article_37c7ccbe-c7a4-11ee-bdaa-4f394a9bf1a0…2/3 The Department of Energy is now doling out $72 million in federal funds for 46 hydro projects in 19 states, including the Blind Slough Hydroelectric Plant refurbishment project in Petersburg. With the Biden administration’s goal of cleaner energy sources coupled with the outrageous cost of energy in Interior Alaska, perhaps it’s time to revisit the idea of a Susitna dam. The concept isn’t new; it was first proposed in the 1960s by the U.S. Bureau of Reclamation, under the Department of the Interior, to bring cheaper energy to the Interior. Support flowed heavily after record-high oil prices in 2008 caused electric bills to spike. But what goes up must go down and oil prices fell, leading to an eventual budget dilemma for the Walker administration. Support for the project dried up. In 2019, Gov. Mike Dunleavy rescinded Gov. Walker ’s hold on the project as part of Dunleavy’s plan to explore more energy options for Alaska. The Legislature, however, has yet to act in authorizing any movement on the project. Today, the Susitna-Watana Hydroelectric Project looms as an opportunity waiting to be seized so long as federal funding continues to roll out. Restarting the venture is not just a strategic move, it is a vital step toward ensuring Alaska’s energy security and propelling economic development. As the state grapples with its energy future, the Susitna-Watana project is worthy of reconsideration. Situated along the Susitna River, the hydroelectric venture boasts a potential capacity of 600 megawatts, making it a substantial contributor to the state’s power grid. The estimated cost for the completion of the project, according to the Alaska Energy Authority, stands at $5.19 billion. While this figure may seem daunting, it’s important to view it as an investment in Alaska’s sustainable future. 2/22/24, 1:47 PM It's time to reconsider the Susitna hydroelectric project | Editorials | newsminer.com https://www.newsminer.com/opinion/editorials/its-time-to-reconsider-the-susitna-hydroelectric-project/article_37c7ccbe-c7a4-11ee-bdaa-4f394a9bf1a0…3/3 The economic benefits of restarting the project are compelling. The AEA estimates that during the construction phase, thousands of jobs would be created, injecting a significant boost into the state economy. As Alaska seeks to diversify its economy beyond the fluctuations of oil and gas, investing in renewable energy infrastructure is a necessity for long-term economic stability. The project would also provide a baseline power supply for solar and wind ventures, thus creating a diverse energy portfolio. The project was, as expected, met with pushback and concern from environmental groups who claimed it would threaten fish habitats and wildlife but there is more than one way to cook a salmon. Susitna planners have taken a comprehensive approach to address those issues. Studies conducted by the U.S. Army Corps of Engineers and the AEA have examined the potential impact on the Susitna River ’s ecosystem. Mitigation measures have been incorporated into the project’s design to minimize adverse effects, ensuring that environmental sustainability remains at the forefront. The hydroelectric facility’s low greenhouse gas emissions, when compared to conventional fossil fuel sources, align with the state’s goal of cleaner energy and a greener future. In addition to its environmental benefits, the Susitna-Watana project aligns with national energy goals. With the Biden administration’s focus on clean energy and reducing carbon emissions, federal support for such a project is more likely. Securing federal funding would significantly alleviate the financial burden on the state and expedite the project’s completion. Alaska is at a crossroads, and the Susitna-Watana Hydroelectric Project offers a path toward a more sustainable future for tomorrow’s families. The initial investment, although significant, pales in comparison to the long-term benefits. As the demand for energy grows and the imperative for clean, renewable sources intensifies, restarting the Susitna-Watana project becomes not just a choice but a responsibility. 2/22/24, 1:27 PM In this issue: NEVI Plan Spotlight, EV Sales, and Upcoming Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=cb7f1a3e8a 1/7 View this email in your browser Alaska Electric Vehicle Working Group Newsletter, February 8, 2024 Plan Spotlight As part of our ongoing spotlight on various parts of Alaska’s Electric Vehicle Infrastructure Implementation Plan, this month we will highlight the Equity Considerations section. This section explores Alaska’s unique blend of demographics, ranging from people living in remote areas of the state to those living in urban hubs. It discusses how AEA plans to meet and track equity requirements for those residing in disadvantaged communities (DACs) throughout the state. There are three sub-sections to the Equity Considerations section, 1) Identification and Outreach to DACs in the State, 2) Process to 2/22/24, 1:27 PM In this issue: NEVI Plan Spotlight, EV Sales, and Upcoming Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=cb7f1a3e8a 2/7 Identify, Quantify, and Measure Benefits to DACs, and 3) Benefits to DACs through this Plan. Below are highlights from each of these sub-sections. However, we encourage you to read the full Equity Considerations Section on pages 68-72 of the Plan. Identification and Outreach to Disadvantaged Communities (DACs) in the State Justice40 is an initiative that sets a goal of 40% of certain federal investments, like NEVI, benefitting DACs. (If you want to learn more about how Justice40 boundaries are set, read our August 2023 Newsletter) 39.8% of Railbelt residents live in DACs, so Alaska is well on its way to meeting the minimum 40% benefit requirement for the buildout of the Alternative Fuel Corridor (AFC). The AFC runs through the Railbelt from Anchorage to Fairbanks. 30 of the 54 communities and local governments on our stakeholder list lie within Justice40 boundaries — that’s 56%! Process to Identify, Quantify, and Measure Benefits to DACs Identify infrastructure that is installed within Justice40 boundaries. AEA will use mapping tools to evaluate whether infrastructure outside of, but close to, a Justice40 boundary may also benefit a nearby DAC. Track labor hours related to DAC public engagement. Coordinate with the Alaska Works Partnership, Alaska Apprenticeship Training Coordinators Association, Alaska General Contractors, and Associated Builders and Contractors to support women and minorities' participation in apprenticeship programs. This is so that DACs can be integrated into the clean energy job pipeline. Benefits for DACs under this Plan Improve clean transportation access through charger location. Decrease the transportation energy costs by enabling reliable access to affordable charging. Reduce environmental exposure to transportation emissions. Increase the clean energy job pipeline, job training, and enterprise creation in disadvantaged communities. Economic impacts on business owners. Knowledge sharing and program awareness. 2/22/24, 1:27 PM In this issue: NEVI Plan Spotlight, EV Sales, and Upcoming Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=cb7f1a3e8a 3/7 EV Sales — are they declining? There’s been a lot of talk online about whether electric vehicle (EV) sales are stalling. Fuel was added to this fire when Ford recently announced that they would be cutting their planned production of the electric F-150 Lightning in half in 2024. Are consumers walking away from EVs? We’ll let the numbers speak for themselves. The Argonne National Laboratory highlighted the following statistics: In 2023, over 1.4 million plug-in EVs were sold (this includes battery EVs and plug-in hybrids). That’s an increase in sales of over 50% from 2022. Plug-in EVs accounted for 9.84% of total monthly vehicle sales in December 2023, and 9.1% of all sales throughout 2023. That’s up from 6.8% of total sales in 2022. So, what is happening? Some EVs are indeed sitting unsold on dealer lots longer than in the past. This duration of sitting unsold on a lot is measured using a metric called days’ supply. A higher days’ supply can indicate that inventory levels are increasing slightly faster than sales are increasing, which creates surplus inventory. This increase in days’ supply doesn’t necessarily mean EV sales are decreasing. Instead it could indicate that production is outpacing sales (which, as the numbers above show, are still going strong). Auto manufacturers base their production levels on projections that are often not entirely accurate. This is regardless of whether the vehicle is an EV or has a traditional internal combustion engine. When differences arise between projection and reality, 2/22/24, 1:27 PM In this issue: NEVI Plan Spotlight, EV Sales, and Upcoming Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=cb7f1a3e8a 4/7 manufacturers will adjust their production levels, such as when Ford announced they would scale back Lightning production. The average days’ supply for EVs at the end of November 2023 was 114 days compared to a 71-day average across all auto manufacturers. Conversely, certain EV models had lower supply days numbers than the national average. These models include the Chevy Bolt EUV, Subaru Solterra, and Toyota bZ4X at 59-, 42-, and 68-day supplies respectively. At the same time, the Ford F-150 Lightning had a 111-day supply — likely part of the reasoning behind Ford’s announcement to scale back production of the electric truck. Even though Lightning production is reduced, it has not gone away completely. Ford still plans to produce 1,600 new Lightnings a week! It is also important to note that a high days’ supply number is not representative of the entire EV market since vehicles like Teslas (the bestselling EV brand in the United States) and Rivians aren’t sold by dealers, so they aren’t sitting on dealer lots. Additionally, these days’ supply numbers can vary significantly regionally and have been increasing for not only EVs but traditional internal combustion engine vehicles as well. The average days’ supply for all vehicles is 17 days higher in November 2023 than in November 2022, indicating all vehicles have been sitting on lots longer. Latest Alaska EV Count 2/22/24, 1:27 PM In this issue: NEVI Plan Spotlight, EV Sales, and Upcoming Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=cb7f1a3e8a 5/7 Upcoming Events Combined Working Group & Technical Session, Friday, March 22, 2024 11:30 a.m.-1 p.m. AEA Office, Denali Room 813 W Northern Lights Blvd. Anchorage, AK 99503 *Stay tuned for instructions on how to join virtually. 2/22/24, 1:27 PM In this issue: NEVI Plan Spotlight, EV Sales, and Upcoming Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=cb7f1a3e8a 6/7 Anchorage Transportation Fair, Thursday, March 28, 2024 Stop by anytime between 3 to 7 p.m. Alaska Airlines Center 3550 Providence Dr, Anchorage, AK 99508 To learn more click here. What We're Reading Correcting The Record About Electric Vehicle Sales | Department of Energy Are electric vehicle sales really losing their charge? | The Week Light Duty Electric Drive Vehicles Monthly Sales Updates | Argonne National Laboratory (anl.gov) Are EV Sales Really ‘Slowing’? - Heatmap News New-Vehicle Inventory Surpasses 2.5 Million Units, 71 Days' Supply - Cox Automotive Inc. (coxautoinc.com) Facebook LinkedIn Website Subscribe Past Issues 2/22/24, 1:27 PM In this issue: NEVI Plan Spotlight, EV Sales, and Upcoming Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=cb7f1a3e8a 7/7 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. Copyright © 2024 Alaska Energy Authority, All rights reserved. Want to change how you receive these emails? You can update your preferences or unsubscribe from this list. 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 RGYAUTHORITY.ORG PRESS RELEASE Brandy M. Dixon Communications Director (907) 771-3078 FOR IMMEDIATE RELEASE January 29, 2023 AEA releases 2023 Renewable Energy Fund Impact and Evaluation Report Report highlights renewable energy fund’s 15-year investment in clean energy (Anchorage) — The Alaska Energy Authority (AEA) today announced the release of its 2023 Alaska Renewable Energy Fund (REF) Impact and Evaluation Report. The report details information about the REF’s efficacy in diversifying Alaska’s energy generation portfolio through the harnessing of Alaska’s vast renewable energy resources. AEA commissioned BW Research Partnership, an independent third-party research consultancy, to assess the economic, community, and environmental impacts of the state’s competitive grant program, the REF. The report finds that the REF has played a significant role in supporting the development of Alaska's renewable energy sector. To date, the fund has financed over 100 renewable projects, primarily wind and hydroelectric, with 60 more currently under development. The program has secured over $317 million in state funds, and successfully leveraged over $300 million in federal and local funds, with rural-community projects comprising over 80 percent of all REF awards. Such investment has led to significant reductions in carbon-based power generation and its associated carbon emissions, such as greenhouse gas emissions and PM2.5 pollutants in Alaska. Per the report, the REF has offset approximately 85 million gallons of diesel fuel (e.g. five percent of all petroleum consumed in Alaska in 2021), 2.2 million cubic feet of natural gas, and 1,063,500 net metric tons of carbon dioxide. The report also finds that the REF program has made a significant contribution to Alaska’s overall economy with 2,931 new jobs created, $237 million in labor income, and $399 million in value added. Every dollar deployed through the REF program to date has resulted in $2.07 in benefits returned to residents and the economy. With ongoing investment in the program, the REF continues to support Alaska's transition to a clean energy economy and enables AEA to diversify Alaska's energy portfolio increasing resiliency, reliability, and redundancy through the sustainable deployment of viable renewable energy resources. ### About the Alaska Energy Authority The Alaska Energy Authority is a public corporation of the state. Its 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. To learn more, visit akenergyauthority.org. 1/24/24, 2:51 PM Enstar president warns of natural gas shortfall, delayed solutions for Southcentral Alaska - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/01/24/enstar-president-warns-of-natural-gas-shortfall-delayed-solutions-for-southcentral-alaska/1/11   Obituaries •Games •ADN Store •e-Edition •Sponsored Content • Promotions •Get our free newsletters ADVERTISEMENT Energy Enstar president warns of natural gas shortfall, delayed solutions for Southcentral Alaska By Alex DeMarban Updated: 1 hour ago Published: 1 hour ago    Alaska News   •  Politics   •  Opinions   •  Talk to us Get our free newslettersSections 1/24/24, 2:51 PM Enstar president warns of natural gas shortfall, delayed solutions for Southcentral Alaska - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/01/24/enstar-president-warns-of-natural-gas-shortfall-delayed-solutions-for-southcentral-alaska/2/11 The setting sun illuminates steam rising from the George M. Sullivan Plant 2A electrical generation station along the Glenn Highway Wednesday, Jan. 17, 2024 in Anchorage. The $300 million, 120-megawatt plant burns natural gas and was brought online in 2016. (Loren Holmes / ADN) The head of the largest utility in Southcentral Alaska expressed dire concerns this week that the state’s natural gas shortage may come quicker than people have come to expect, raising the risk for power interruptions in the future. John Sims, president of gas company Enstar, said in an interview if everything runs smoothly — meaning no gas-supply interruptions or cold weather causing excess demand — the region should have the gas it needs for the near-term. “But I start to get really, really concerned in, in 2027, 2028,” he said. Enstar provides gas to heat home and buildings in the Anchorage and Matanuska- Susitna areas, and portions of the Kenai Peninsula. It serves 150,000 customers. Sims said he’s also worried that power companies’ plans to receive imported liquefied natural gas to fill the gap may not be possible until 2028, due to permitting 1/24/24, 2:51 PM Enstar president warns of natural gas shortfall, delayed solutions for Southcentral Alaska - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/01/24/enstar-president-warns-of-natural-gas-shortfall-delayed-solutions-for-southcentral-alaska/3/11 timelines at state and federal agencies. That’s a year later than estimated by an initial report issued last summer by a working group involving the utilities along the Railbelt from Homer to Fairbanks, and state entities. Members of the Regulatory Commission of Alaska have raised similar points, saying the looming gas shortfall in the region could lead to potentially catastrophic outcomes if utilities aren’t prepared. ADVERTISEMENT On Wednesday, the commission began a series of meetings with power companies to hear their plans for rationing power, if needed, to protect vital facilities such as hospitals and to prevent blackouts or forced power outages. The commission met first with the relatively small Homer Electric Association, serving much of the Kenai Peninsula. Hilcorp, producing more than 80% of the gas used in the Railbelt, warned Enstar and other utilities in 2022 that it did not have enough natural gas reserves in the basin to provide for new gas supply contracts after existing ones expire in the coming years. The warning has sent utilities scrambling to find new sources of power, including renewable energy projects that could require lengthy timelines to complete, and potentially costly imports of liquefied natural gas. Alaska Gov. Mike Dunleavy has proposed legislation for temporary royalty rate reductions on oil and gas production from new pools, in an attempt to incentivize investments. Electric utilities have said they are evaluating opportunities to import liquified natural gas to avoid any supply gaps. Hilcorp said this week in a statement it will meet the obligations of its gas supply agreements with utilities. In 2024, it will spend hundreds of millions of dollars to develop its leases in the Cook Inlet basin, Hilcorp said. 1/24/24, 2:51 PM Enstar president warns of natural gas shortfall, delayed solutions for Southcentral Alaska - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/01/24/enstar-president-warns-of-natural-gas-shortfall-delayed-solutions-for-southcentral-alaska/4/11 [Report: Alaska’s Railbelt can shift to renewables, but that would require big capital investment] “However, it’s important to note that the natural gas under Hilcorp’s leasehold alone cannot continue to meet nearly all Railbelt gas demand,” the company said in a statement. “Railbelt utilities and other gas producers need to identify additional sources of natural gas supply for Southcentral Alaska.” “We will continue to collaborate with Railbelt utilities, state and local governments, and the public to find energy solutions for Alaska,” Hilcorp said. A one-year extension for Homer Electric Homer Electric, serving about 25,000 members, is the region’s first electric utility to have its gas contract with Hilcorp to expire. The contract expires this spring, on March 31. But Enstar, the region’s largest natural gas buyer, has recently worked out an arrangement that would provide Homer Electric with a one-year extension, Sims said. Enstar’s gas-supply contract with Hilcorp is set to end in 2033, Sims said. Hilcorp provides about 90% of Enstar’s gas, said Sims. To extend Homer Electric’s contract, Enstar amended its gas supply contract with Hilcorp to accept an additional 3.5 billion cubic feet of gas for a yearlong period, close to a 10% increase in what Enstar normally buys for its own customers. Enstar will sell the extra gas to Homer Electric Association for the 12 months, Sims said. A Homer Electric spokeswoman said the utility signed a contract with Enstar to buy the gas. 1/24/24, 2:51 PM Enstar president warns of natural gas shortfall, delayed solutions for Southcentral Alaska - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/01/24/enstar-president-warns-of-natural-gas-shortfall-delayed-solutions-for-southcentral-alaska/5/11 The changes will be submitted to the regulatory commission for approval, Enstar and Homer Electric officials said. Sims said Hilcorp is not obligated to explain how it’s making the extra gas available. Hilcorp did not respond to that question from a reporter. ADVERTISEMENT Sims said the extra gas is likely coming from Cook Inlet gas that would have been used to meet future needs. [Royalty-free lease offerings in Alaska’s Cook Inlet basin draw tepid response] “I think ultimately, what we’ve done is we’ve moved gas volumes from one year and just brought them forward,” he said. Under the deal with Hilcorp, Enstar agreed to more quickly draw down some of the gas stored in its parent company’s underground storage reservoir, Cook Inlet Natural Gas Storage Alaska. It essentially means there will be “a little bit less in the tank” that could be available for a potential future emergency, Sims said. A potential financial penalty that ensures Hilcorp delivers its gas will be waived, for an amount over the next three years that applies to the extra delivery of 3.5 billion cubic feet, Sims said. “Because this is gas that Hilcorp hadn’t planned on delivering at this point in time, they negotiated to reduce the amount that they were obligated to provide if they can’t deliver,” Sims said. Also, the amended contract will slightly boost Enstar’s gas-cost adjustment, affecting all Enstar customers. ADVERTISEMENT 1/24/24, 2:51 PM Enstar president warns of natural gas shortfall, delayed solutions for Southcentral Alaska - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/01/24/enstar-president-warns-of-natural-gas-shortfall-delayed-solutions-for-southcentral-alaska/6/11 The average annual residential gas bill in the service area will rise slightly, by $3.82, a representative with Enstar said. The average annual bill is about $1,585. Enstar concerned about its own gas supply Hilcorp’s gas supply contract with the Chugach Electric Association, the largest power utility in Alaska, is set to end in 2028. “Chugach is confident that we will meet the gas needs of our members,” said Arthur Miller, chief executive of Chugach Electric. Chugach is unique among power utilities in the Railbelt because it has a two-thirds working interest in the Beluga River Unit gas field that provides most of the utility’s gas needs, he said. The remaining 40% is met through its contract with Hilcorp. “As has been discussed, we are actively evaluating opportunities to import liquified natural gas to fill any gas supply needs in 2027 and beyond,” Miller said in a prepared statement. “Chugach is expected to make a decision on importing LNG in the first or second quarter of this year.” [Electric utilities push back on proposal from Native village and Anchorage Assembly leaders to remove Eklutna River hydropower dam] Chugach also has a long-term gas storage arrangement for gas storage with Cook Inlet Natural Gas Storage Alaska, and is looking for additional gas storage. The storage supplements gas supply when demand rises in winter. Homer Electric has previously said it is working with the Railbelt utilities to identify future sources of fuel, including renewable energy and importing liquefied natural gas. As long as Hilcorp meets its contractual obligations and Enstar does not have deliverability issues, Matanuska Electric said its members are covered. Matanuska Electric’s gas supply contract with Hilcorp ends in 2028. 1/24/24, 2:51 PM Enstar president warns of natural gas shortfall, delayed solutions for Southcentral Alaska - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/01/24/enstar-president-warns-of-natural-gas-shortfall-delayed-solutions-for-southcentral-alaska/7/11 “We do recognize that things are getting tighter in the Cook Inlet and we are not seeing signs of improvement, which raises some concerns,” Julie Estey, a spokeswoman with Matanuska Electric, said in an email. “With reliability as our member’s number one priority, we have plans in place to manage gas shortfall situations in coordination with Enstar and the other electric utilities.” “MEA’s dual fuel engines at the Eklutna Generation Station allow us to switch seamlessly to diesel to provide continuous power to our members during critical situations and can also be an asset to the larger system by reducing demand,” Estey said. Matanuska Electric will provide more details on that subject at regulatory commission meetings in the future, Estey said. ADVERTISEMENT Enstar also receives gas Bluecrest and from Furie, now HEX, Sims said. John Hendrix, president of HEX, a small Cook Inlet producer, said the company has always met and will continue meeting its contractual obligations to utilities. Hendrix said its current gas supply contracts with Enstar end in April 2026. HEX provides only 5% of the gas needed by the Railbelt utilities, he said. Hendrix said the state should equalize royalty payments so they’re fair to every producer in Cook Inlet. That would benefit fields like the Kitchen Lights Unit owned by HEX, which has high royalty payments, he said. “This is a solvable problem,” he said. “There’s gas in Cook Inlet.” Benji Johnson, president of BlueCrest Energy, another small Cook Inlet producer, said the company has met and continues to meet its gas supply contracts. ADVERTISEMENT BlueCrest has a large, proven but undeveloped offshore field called Cosmopolitan, he said. “There is no question that the gas is there and could make up market 1/24/24, 2:51 PM Enstar president warns of natural gas shortfall, delayed solutions for Southcentral Alaska - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/01/24/enstar-president-warns-of-natural-gas-shortfall-delayed-solutions-for-southcentral-alaska/8/11 shortages for many years,” he said in a text. [Chugach files plan with regulators to create community solar farm that members can buy power from] Experts have said Cook Inlet remains home to large amounts of gas, but the huge cost of exploration and development, in such a small market, often make new drilling uneconomical. Johnson said developing Cosmopolitan will require big investments to install a new offshore platform and subsea pipelines, and then drill for gas, he said. The company is working with potential investors, but doesn’t have a final investment commitment, he said. Alaska has a reputation as an unstable tax regime for producers, so investors look elsewhere, he said. Sims said he worries that Enstar, as early as 2027 or 2028, may begin to face a shortfall in its own gas supply. He said some of the solutions to the dilemma could include expedited state and federal permitting timelines to allow liquefied natural gas imports to begin as quickly as possible. Incentives such as those proposed by the governor might also help result in unexpected supplies of new gas, Sims said. The state and federal government should fully support Cook Inlet producers to boost their chances of success he said. Sims said consulting firms for Enstar and the electric utilities will soon provide the regulatory commission with an update to findings they presented last year about the dilemma. He said the consultant for Enstar, Berkeley Research Group, is expected to recommend imports of liquefied natural gas as the best near-term solution to avoid shortages in future gas supply. Utilities will need to move quickly to come up with a plan, he said. 1/24/24, 2:51 PM Enstar president warns of natural gas shortfall, delayed solutions for Southcentral Alaska - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/01/24/enstar-president-warns-of-natural-gas-shortfall-delayed-solutions-for-southcentral-alaska/9/11 “We don’t have a lot of time to dilly-dally and contemplate,” he said. • • • Do you have additional ideas for coverage on this topic? Do you have questions? Do you see an er ror? What's missing? Are you involved in the stor y or affected by it and have additional thoughts about it? Let us know here. Do you have additional ideas for coverage on this topic? Do you have questions? Do you see an error? Are you involved in the story or affected by it and have additional thoughts about it? Let us know here. 0/1000 Your contact info: Thank you for reaching out. A reporter may be in touch to talk with you about your experiences. We won't publish any information about you without checking with you first. Name Email address Phone Number Yes, I want to sign up for the ADN’s daily newsletter to get the latest updates on local news, politics, and other topics in Alaska. Please don't publish my name I am over 16 years old I accept the Terms of Service Submit Powered by Hearken | Terms of Service | Privacy Policy Alex DeMarban Alex DeMarban is a longtime Alaska journalist who covers business, the oil and gas industries and general assignments. Reach him at 907-257-4317 or alex@adn.com. Most Read 1/24/24, 2:51 PM Report: Alaska’s Railbelt can shift to renewables, but that would require big capital investment - Alaska Beacon https://alaskabeacon.com/2024/01/23/report-alaskas-railbelt-can-shift-to-renewables-but-that-would-require-big-capital-investment/1/6 ECONOMY & ENVIRONMENT GOVERNMENT & POLITICS Report: Alaska’s Railbelt can shift to renewables, but that would require big capital investment Dierent mixes of energy sources could result in renewables supplying between 70% and 96% electrical power by 2050, UAF group’s analysis nds BY: YERETH ROSEN - JANUARY 23, 2024 5:00 AM        Sunlight reects off solar panels lining the student recreation building at the University of Alaska Fairbanks campus on June 2, 2018. Solar and wind energy, with a blend of other sources, can help Alaska's Railbelt generate 70% to 96% of its electricity from renewables, according to a new report from UAF's Alaska Center for Energy and Power. (Photo by Yereth Rosen/Alaska Beacon) Alaska’s most populous corridor can generate most of its electricity through renewable energy, but would require signicant upfront  1/24/24, 2:51 PM Report: Alaska’s Railbelt can shift to renewables, but that would require big capital investment - Alaska Beacon https://alaskabeacon.com/2024/01/23/report-alaskas-railbelt-can-shift-to-renewables-but-that-would-require-big-capital-investment/2/6 capital investment, a University of Alaska Fairbanks team said in a new report. The report, issued last week by UAF’s Alaska Center for Energy and Power, found that by 2050 non-fossil energy can supply anywhere from 70% to 96% of the power needed to produce electricity along the Railbelt. The region comprises communities from Fairbanks in the Interior to Seward on the Kenai Peninsula, the corridor along the Alaska Railroad line that hold the vast majority of the state’s population. The report compared four scenarios for power generation, from a continuation of the current heavy reliance on natural gas to varying blends of solar, wind, hydro, tidal and nuclear energy. Under the business-as-usual scenario, with continued use of existing power plants, some new fossil fuel units and continued use of wind and solar energy at current rates, renewables would supply 11% of energy to generate electricity, and required capital investment would be $2.3 billion. The other scenarios would require much more investment: $7.7 billion for a mix integrating tidal power, wind and solar to achieve 70% renewable energy; $10.1 billion for a mix of wind, solar and small modular nuclear reactions to achieve 96% zero-carbon generation; and $11.8 billion for a mixture of large-scale hydro, wind and solar projects to achieve 88% renewable energy. Findings were presented Friday during a meeting of the state Senate Resources Committee. One takeaway from the report is that wind and solar are consistently the cheapest forms of energy, but that they have quantity limits, said Jeremy VanderMeer, a research assistant professor at ACEP and one of the report authors. For that reason, there is a need to mix in hydropower, continued fossil fuel use, batteries or some combination of those, VanderMeer told the committee. “You need rm sources or power. Firm just means you can rely on it to supply power whenever you need it,” he said. Investment would target improvements in power transmission through the Railbelt communities, said Derek Stenclik, founding partner of Telos Energy, a company that specializes in isolated energy systems. Stenclik was a report coauthor. 1/24/24, 2:51 PM Report: Alaska’s Railbelt can shift to renewables, but that would require big capital investment - Alaska Beacon https://alaskabeacon.com/2024/01/23/report-alaskas-railbelt-can-shift-to-renewables-but-that-would-require-big-capital-investment/3/6  Wind turbines on Fire Island, off the coast of Anchorage, are silhouetted against the evening sky on Sept. 23, 2023. The turbines are owned and operated by a subsidary of Cook Inlet Region Inc. and supply energy to Chugach Electric Association. (Photo by Yereth Rosen/Alaska Beacon) “Transmission is really a key enabler for all of these portfolios,” Stenclik told the committee. Battery storage is another “key enabler,” and something that would prevent interruptions or blackouts, he said.  While the need to invest $10 billion or so may seem daunting, that capital investment can be oset by future savings in annual operations costs, Steve Colt, an ACEP research professor and a report coauthor, told the committee. “If we were able to make that kind of investment, we would have to pay a lot of money for capital, but we would potentially save three quarters of a billion dollars of fuel costs every year,” Colt told the senators. “So to me, that helps put in perspective the daunting challenge of investing maybe $10 billion, that you could save something approaching $1 billion every year for as long as the equipment operates.” In the long term, costs of the four dierent scenarios evaluated in the report were largely equal, he said. There is pending legislation that would address some of the needs described in the report. 1/24/24, 2:51 PM Report: Alaska’s Railbelt can shift to renewables, but that would require big capital investment - Alaska Beacon https://alaskabeacon.com/2024/01/23/report-alaskas-railbelt-can-shift-to-renewables-but-that-would-require-big-capital-investment/4/6 In response to a question from Sen. Matt Claman, D-Anchorage, Stenclik said that legislation to establish a renewable energy portfolio standard, or RPS, would probably be helpful and could be important for the Railbelt. He pointed to experience in the Lower 48, where plant development may be economically justied but where “having that RPS or having that policy backing provides the certainty to the investors and the certainty to the market to bring it to fruition,” he said, pointing to his experience in the Lower 48. “I do think a lot of the projects would be economic in their own right today. But I think it does provide that certainty and the scaolding that we can start using to build out a roadmap,” he said. There are two pending versions of that legislation, House Bill 121 and Senate Bill 101, but neither made it to the House or Senate oor last year. Additionally, said resources committee Co-Chair Cathy Giessel, R- Anchorage, legislation is in the works to help upgrade the transmission system. Work on the report started in 2022. It was funded by the federal government through the Oce of Naval Research and by the state, ACEP said. Railbelt utilities and the Alaska Energy Authority helped in the research, and Telos provided modeling and analysis support, ACEP said. GET THE MORNING HE ADLINES DELIVERED TO YOUR INBOX S U B S C R I B E 1/24/24, 2:57 PM FEDC task force talks state energy security plan | Alaska News | newsminer.com https://www.newsminer.com/news/alaska_news/fedc-task-force-talks-state-energy-security-plan/article_68882e0a-b4a5-11ee-992e-5f14f1a3713b.html 1/5 https://www.newsminer.com/news/alaska_news/fedc-task-force-talks-state-energy-security-plan/article_68882e0a- b4a5-11ee-992e-5f14f1a3713b.html FEDC task force talks state energy security plan Jack Barnwell Jan 17, 2024 Andrew Lesh photo, Fairbanks Gov. Mike Dunleavy launched the task force with instructions to find solutions and a way to lower energy costs. Andrew Lesh photo, Fairbanks Energy costs will be a huge topic in Alaska’s 2024 legislative session, but lawmakers and the governor ’s office have some concepts on which to move because of a final energy task force report. 1/24/24, 2:57 PM FEDC task force talks state energy security plan | Alaska News | newsminer.com https://www.newsminer.com/news/alaska_news/fedc-task-force-talks-state-energy-security-plan/article_68882e0a-b4a5-11ee-992e-5f14f1a3713b.html 2/5 Karl Hanneman, president and CEO of International Tower Hill Mines and a task force member, sees the plan as the start of a long-term solution with some immediate recommendations. Hanneman provided his own snapshot of the report during a Fairbanks Economic Development Corporation “Energy for All Alaska” meeting on Tuesday. The 218-page main volume and corresponding 1,174-page supplemental document was released on Dec. 1, 2023, and was the effort of several months worth of task force committee meetings, public testimony and webinars. Gov. Mike Dunleavy launched the task force with instructions to find solutions and a way to lower energy costs to 10 cents per kilowatt-hour (kWh). By comparison, Fairbanks residents pay 25 cents kWh, among the highest on the Railbelt. “It was a good group and a diverse group,” Hanneman said. “Our task was to find out how to reduce cost and increase security for heat and power in Alaska.” He added Dunleavy’s orders included “thinking bold, thinking outside the box and not just the norm of what had been under discussion before.” Six committees developed more than 40 strategies, 100 action items and 39 steps the state should consider for immediate implementation. Jomo Stewart, FEDC’s executive director, noted his organization’s own consideration was find a energy equivalent of $2 per gallon, or 5 cents/kWh when using a space heating analysis. “Going down to 10 cents a kilowatt-hour would be a major accomplishment ... but still not cheap power,” Stewart said. Hanneman acknowledged 10 cents/kWh isn’t cheap, but added the national average hovers around 16 cents. “That 10 cent goal would be phenomenal, but it is a stretch goal and never any discussion or expectation of electricity could get to the point where you can use it for space heating,” Hanneman said. “Nobody sees that in the cards.” Hanneman said the task force hosted a series of virtual symposiums. The report’s second volume includes white papers on each of the more immediate recommended actions. 1/24/24, 2:57 PM FEDC task force talks state energy security plan | Alaska News | newsminer.com https://www.newsminer.com/news/alaska_news/fedc-task-force-talks-state-energy-security-plan/article_68882e0a-b4a5-11ee-992e-5f14f1a3713b.html 3/5 “We came to a consensus on how to value these metrics ... and that was affordability, reliability and resilience,” Hanneman said. The actions and goals were split into short-term, middle and long-range categories. “The short-term goal was to minimize regret cost while continuing to provide reliability,” Hanneman said. He noted that includes ensuring a continued supply of natural gas as the Cook Inlet’s current supply has come into question over the past two years. “If we have the idea of a long-term solution, let’s not set ourselves up so we can never achieve it,” Hanneman said. “If we don’t want to be importing [liquefied natural gas] long term, let’s not put all our eggs into one basket and set ourselves up where that’s our only choice for 40 years.” He also backed progressing the proposed Alaska LNG pipeline or at least developing a much smaller “bullet train” or in-state pipeline to leverage the North Slope’s vast supply of natural gas. “There’s a perspective out there that if it doesn’t happen now ... it won’t ever happen,” Hanneman said. “We should work like beavers to accomplish it in the next two years, get it over the line.” The key would be funding and investors, something that can be challenging, he said. “But Alaska needs a long-term supply of natural gas,” Hanneman said. “It heats people’s homes and keeps their water hot ... we have to have it.” Mid-term goals include investments in infrastructure while long-term goals involves diversifying the state’s sources of energy generation. “We definitely need to include renewables but we don’t want to burn the bridges on the reliable sources we have now, including coal,” Hanneman said. Hanneman said one major downside was not prioritizing action items, despite arguments from him and a few other task force members. However, he had his own six preferences he said would have filtered to the top. 1/24/24, 2:57 PM FEDC task force talks state energy security plan | Alaska News | newsminer.com https://www.newsminer.com/news/alaska_news/fedc-task-force-talks-state-energy-security-plan/article_68882e0a-b4a5-11ee-992e-5f14f1a3713b.html 4/5 His top preference, he said, would be unifying all existing Bradley Lake and Railbelt transmission assets under a central authority. He said this would allow the state to better identify matching funds to leverage federal grants. “Alaska is not a grid, it is an extension cord running south to north,” Hanneman said. “While the rest of America runs on a grid, we have no redundancy ... we’re all exposed to an avalanche, or slide or a unit going down.” He added future sources of energy should be allowed to compete to provide power, but that requires better infrastructure to carry that power. Alaska received a massive $206 million federal grant to improve the Railbelt transmission line from Bradley Lake to Anchorage and then from Anchorage to Healy. It also provides for battery storage facilities in Fairbanks and Anchorage. But the grant requires a 50% match from Alaska, or another $206 million, before it can receive the federal dollars. “The backbone upon which we transmit the power needs to be improved and we need to be able to connect to Glennallen and Valdez so that we can have integration,” Hanneman said. Other major goals include overhauling the state’s Power Cost Equalization Program, which provides a massive subsidy to rural Alaskan communities based on Railbelt costs. The PCE program, he said, should be maintained and expanded until all Alaskans benefit from lower costs. But he said there are challenges that need to be addressed, including better management of grants. Other concepts include supporting new hydroelectric projects, such as the Dixon Diversion at Project on the Kenai Peninsula, about five miles southwest of Homer ’s Bradley Lake dam. “It needs to be an immediate focus, to get after it,” Hanneman said. Asked about the Susitna hydroelectric project, Hannenan said the proposal has been to first reevaluate the capital and operational costs, which haven’t been updated since 2008. Once those costs are updated, he said it would carry the conversation whether it would be viable. 1/24/24, 2:57 PM FEDC task force talks state energy security plan | Alaska News | newsminer.com https://www.newsminer.com/news/alaska_news/fedc-task-force-talks-state-energy-security-plan/article_68882e0a-b4a5-11ee-992e-5f14f1a3713b.html 5/5 jbarnwell Hanneman also supported developing and adopting a Clean Energy Standard that promotes incentives rather than penalties. “If you do it with penalties, then it’s not likely we are achieving lofty goals in a timeline dreamed of,” he said. “You’ll just end up with higher costs and you’re stabbing yourself in the back.” When Hanneman said the task force didn’t define clean energy, Lorali Simon with Usbelli Coal Mine took some exception. “When someone says clean energy, it implies there is dirty energy, and how is that defined?” Simon said. “Is it all fossil fuels, some fossil fuels, or could coal-fired plants with the right technology installed be considered under a clean energy standard?” Hanneman agreed that a lack of definition can be frustrating, but reiterated a desire for incentives. “If we do this right, the market and the cost structure will drive the right solution,” Hanneman said. Contact reporter Jack Barnwell at 907-459-7587 or jbarnwell@newsminer.com. 1/24/24, 2:55 PM Alaska Village Electric Cooperative proposes 14.9% average rate increase https://www.kyuk.org/economy/2024-01-17/alaska-village-electric-cooperative-proposes-14-9-average-rate-increase 1/3 Alaska Village Electric Cooperative proposes 14.9% average rate increase KYUK | By Sage Smiley Published January 17, 2024 at 11:38 AM AKST Gabby Hiestand Salgado /KYUK AVEC's power plant in Bethel. The electrical cooperative that powers communities across Western Alaska, Kodiak Island, Southeast Alaska, and Southwest Alaska is proposing an average rate increase of almost 15%. Alaska Village Electric Cooperative (AVEC) President and CEO Bill Stamm said that the cooperative is proposing a rate increase because “everything is more expensive.” “I think everybody that lives in rural Alaska has felt the increase in costs of just about everything,” Stamm said. “And unfortunately, we're not immune to that.” Stamm said that the proposed AVEC rate increase is what the cooperative needs to stay in business. He said that the nancial contrast between 2021 and 2022 was stark for Donate KYUK 1/24/24, 2:55 PM Alaska Village Electric Cooperative proposes 14.9% average rate increase https://www.kyuk.org/economy/2024-01-17/alaska-village-electric-cooperative-proposes-14-9-average-rate-increase 2/3 AVEC. In 2021, the electrical provider had an operating budget with a $1.7 million surplus. The next year, it was $4.8 million in the hole. Higher prices don’t just impact day-to-day operations. As a cooperative, Stamm said, the budget surplus gets reinvested into capital improvement projects in member communities. He said that increased costs and longer lead times on materials have signicantly delayed infrastructure projects for the electric cooperative, which serves 59 communities, most of them in Western Alaska. Stamm said that the cooperative did a cost-of-service study in 2023. “We found that not only were we under-collecting revenue in general, there were some communities that were under-collecting more than others,” Stamm said. AVEC has different rates for small and large customers in different communities, as well as for residential and commercial customers. Proposed rate increases vary depending on the type of service, but basically work out to 14.9%. This is on top of the prior year’s increase of around 9%, Stamm said. How exactly a rate increase impacts customers will depend on fuel costs, which vary widely between communities throughout the cooperative’s service areas and are charged separately from other electrical costs. “We burn over 9 million gallons of diesel fuel a year throughout Alaska,” Stamm said. “All of that diesel fuel has to be transported and stored in the communities, and then brought to our power plants and used. And the cost of doing that in each community varies greatly depending on how far away they are from the source and how dicult it is to get fuel there. Some of it’s delivered by barge; some of it has to be own in.” If approved, rate increases would go into effect on the last day of February 2024. An increase to AVEC rates won’t necessarily directly translate to the same increase on a customer’s electricity bill. That’s in large part due to the state’s power cost equalization program, which subsidizes energy costs in rural communities. Stamm told KYUK in 2021 that if power cost equalization were not in place, electrical costs in some rural areas could more than double. 1/24/24, 2:55 PM Alaska Village Electric Cooperative proposes 14.9% average rate increase https://www.kyuk.org/economy/2024-01-17/alaska-village-electric-cooperative-proposes-14-9-average-rate-increase 3/3 AVEC will hold a public hearing on the proposed rate increases at 10 a.m. on Jan. 29 in their Anchorage boardroom. Members can register to join in person or by teleconference. Find more information here. Economy Sage Smiley Sage Smiley is KYUK's news director. See stories by Sage Smiley 1/24/24, 2:54 PM Governor's executive orders get rid of bureaucratic layers, and one splits AEA and AIDEA - Must Read Alaska https://mustreadalaska.com/governors-executive-orders-get-rid-of-bureaucratic-layers-and-splits-aea-and-aidea/1/2 Governor’s executive orders get rid of bureaucratic layers, and one splits AEA and AIDEA Gov. Mike Dunleavy has a dozen executive orders that he has sent to the Alaska Legislature. They were read into the record at the opening of the 2024 legislative session on Tuesday. Some are routine, but others are new. One executive order splits the Alaska Energy Authority away from the Alaska Industrial Development and Export Authority, so it has its own dedicated energy board. Right now the two agencies share a board. AEA, which is larger than the Alaska Railroad, used to have its own board, until the Legislature combined the boards over a decade ago. These are two billion-dollar corporation that operate with a single volunteer board. AEA’s capital budget has increased over 1,000 percent in the last five years, which may have led to the need to separate the boards again. Another executive order changes the Marine Highway Operations Board so that all the seats are appointed by the governor, and none by the Legislature. The governor would also do away with three occupational boards that were created by the Legislature over the years. They are the Massage Board, Barbers and Hairdressers Board, and Board of Midwives. The massage field and hair professionals would be managed by regulation through the Department of Commerce, and the 43 midwives in the state would be also regulated by the Department of Commerce, rather than seven of their midwife colleagues. The Emergency Medical Services Council would also be regulated by the Department of Health as well, rather than through a citizen board. The governor is getting rid of two legislatively designated park boards: The Wood-Tikchik State Park Management Council and the Chilkat Bald Eagle Preserve Council. Both areas would be managed through the Department of Natural Resources, not by a separate board. By Suzanne Downing -January 16, 2024 1/24/24, 2:54 PM Governor's executive orders get rid of bureaucratic layers, and one splits AEA and AIDEA - Must Read Alaska https://mustreadalaska.com/governors-executive-orders-get-rid-of-bureaucratic-layers-and-splits-aea-and-aidea/2/2 Separate boards require staff time and this may be a way to reduce bureaucratic layers. These executive orders would go into law if not disapproved in a joint session within 60 days. The Legislature would have to muster 31 “no” votes to stop the governor’s executive orders. Two years ago, the governor split the Department of Health and Social Services into two departments via executive order so that the Department of Health could have more focus. Suzanne Downing Suzanne Downing had careers in business and journalism before serving as the Director of Faith and Community-based Initiatives for Florida Gov. Jeb Bush and returning to Alaska to serve as speechwriter for Gov. Sean Parnell. Born on the Oregon coast, she moved to Alaska in 1969.  All Stories The 907 Politics Columns MRAK Show The Social Almanac Newsletter Shop Donate About us Must Read Alaska is news of people, politics, policy, culture, and happenings in Alaska. Contact 4021 West Hill Road, Homer, AK 99603 JDF@mustreadalaska.com  The latest © Must Read Alaska Peltola — lawmaker or lawbreaker? North Pole school visit looked like illegal campaign event THE 907 January 24, 2024 Assembly, on vote of 9-3, overrides mayor’s veto of the Assembly newly minted subpoena powers THE 907 January 23, 2024 Mayor Dave Bronson les for reelection THE 907 January 23, 2024 1/24/24, 2:58 PM Manokotak has power, but generator repairs are still underway https://www.kdlg.org/infrastructure/2024-01-15/manokotak-has-power-but-generator-repairs-are-still-underway 1/2 Manokotak has power, but generator repairs are still underway KDLG 670AM | By Christina McDermott Published January 15, 2024 at 10:28 AM AKST LISTEN • 1:25 The school in Manokotak. December, 2023. According to Mayor Melvin Andrews, residents lost power when all three of the city’s generators failed on December 13. In the face of oncoming storms, in late December the city had issued an emergency declaration, requested state aid, and opened its school as a shelter. A January 1 article from KTUU said that the Bristol Bay Native Association and the Bristol Bay Native Corporation agreed to send aid to the community in the form of cots, blankets, food and drink and propane Donate 1/24/24, 2:58 PM Manokotak has power, but generator repairs are still underway https://www.kdlg.org/infrastructure/2024-01-15/manokotak-has-power-but-generator-repairs-are-still-underway 2/2 The rst repairs came around New Years’ Day. The Alaska Energy Authority’s chief operating ocer Tim Sandstrom said that, as of January 9, a contractor was preparing to connect the town to a repaired generator. At that time, he said a secondary generator is currently being tested and should be installed in about a week. The City of Manokotak announced on Facebook that residents who incurred expenses to keep themselves warm and their homes lit during the blackouts could present their receipts to the city by January 11. But it said that Governor Mike Dunleavy hadn’t declared Manokotak under a state of emergency, so it did not know if the state would reimburse them. The community’s local utility provider, Manokotak Natives Limited, did not respond to requests for comment. The Alaska Energy Authority said they worked with Manokotak Natives Limited to address the broken generators. Get in touch with the author at christina@kdlg.org or 907-842-2200. Infrastructure Christina McDermott Christina McDermott began reporting for KDLG, Dillingham’s NPR member station, in March 2023. Previously, she worked with KCBX News in San Luis Obispo, California, where she focused on local news and cultural stories. She’s passionate about producing evocative, sound-rich work that informs and connects the public. See stories by Christina McDermott Currently Playing on AM 670: 2/22/24, 1:33 PM In this issue: NEVI Plan Spotlight, Funding Opportunity, Technical Session Recap, and January Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=037f033a68 1/7 View this email in your browser Alaska Electric Vehicle Working Group Newsletter, January 11, 2024 A Closer Look at the NEVI Plan To receive the over $50 million in funding that has been allocated to Alaska by the National Electric Vehicle Infrastructure (NEVI) Formula Program, the Alaska Energy Authority (AEA) and the Alaska Department of Transportation and Public Facilities (DOT&PF) developed Alaska’s Electric Vehicle Infrastructure Implementation Plan, which outlines how the funds will be used. AEA and DOT&PF submitted Alaska’s first fiscal year 2023 plan in late summer 2022, and the Federal Highway Administration (FHWA) approved it, granting us access to the first year of funding! Alaska’s plan must be updated 2/22/24, 1:33 PM In this issue: NEVI Plan Spotlight, Funding Opportunity, Technical Session Recap, and January Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=037f033a68 2/7 and resubmitted every year to obtain the next year’s funding, so AEA and DOT&PF submitted the updated NEVI plan for fiscal year 2024 last year. The FHWA approved this updated plan in the fall of 2023, giving us access to another year of funding. We’re already thinking about how we will update the plan, which we will submit later this year for fiscal year 2025 funding. Have you read the plan? It’s okay if you haven’t read the plans in their entirety. We realize that these plans are long — they must list out the various details of how Alaska plans to use the NEVI funds (the updated fiscal year 2024 plan was 112 pages long from front cover to back)! We want to help make the plans as accessible and digestible to all Alaskans as possible, so we will be breaking the plan down and highlighting some of the sections in our upcoming newsletters. This month we’ll focus on the plan’s vision and high-level program goals. You can read this entire section starting on page 19 of the fiscal year 2024 Plan. Plan Vision “Adapting Alaska’s unique infrastructure system to support reliable, equitable, and sustainable electric transportation while meeting community and economic needs.” High-Level Program Goals 1. Deploy EV charging stations that are reliable and accessible for work, recreation, and tourism to inspire driver confidence 2/22/24, 1:33 PM In this issue: NEVI Plan Spotlight, Funding Opportunity, Technical Session Recap, and January Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=037f033a68 3/7 2. Ensure the benefits are distributed and applied equitably for all Alaskans. 3. Support the existing and future demand for electrified transportation. 4. Implement an outreach and education program to train, retain, and diversify the workforce in support of the electric transportation system. 5. Collect data to measure program performance and make informed deployment decisions. 6. Invest strategically to make Alaska’s infrastructure more resilient and independent. 7. Work with international partners to connect to the continental network. Infrastructure Funds Beyond NEVI NEVI isn't Alaska's only source of funding for EV infrastructure! In our June 2023 newsletter, we informed you that we were negotiating future funds. We are pleased to announce that AEA was awarded $1.67 million from the National Energy Technology Lab through the Vehicle Technology Office at the United States Department of Energy (DOE). DOE’s award will be complemented by an additional $417,496 from AEA and project partners, making a total of $2 million available for electric vehicle supply equipment (EVSE) over the next three years. These funds will be used for the Alaska Rural Electric Vehicle Supply Equipment Deployment (ARED) project, which aims to reduce barriers to EV adoption in rural Alaska. AEA’s project partners include the Alaska Center for Energy and Power, DOT&PF, the Alaska Municipal League, and Launch Alaska. 2/22/24, 1:33 PM In this issue: NEVI Plan Spotlight, Funding Opportunity, Technical Session Recap, and January Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=037f033a68 4/7 How to get involved AEA will select nine rural communities for ARED based on their grid infrastructure, geographical distribution, and interest in EVs and EVSEs. Contact AEA's EV team at electricvehicles@akenergyauthority. org if you are interested in participating or learning more about ARED. Technical Session Recap Missed our last technical session? Don’t worry! In the December technical session, we hosted a panel discussion focusing on EV sales and had representatives from car dealerships across the state help answer questions. The questions below were addressed with interesting and varying responses! If you’re interested in hearing what our panelists had to say, check out the recording here (Passcode: qQ@X7PX&). 1. Are you noticing increased interest in EVs? 2. Are you noticing increased demand for EVs? 3. What do your inventory numbers look like over the next 5 years? 4. Do you plan to install chargers at your dealerships? 5. Have you seen an impact in demand from the tax credits 2/22/24, 1:33 PM In this issue: NEVI Plan Spotlight, Funding Opportunity, Technical Session Recap, and January Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=037f033a68 5/7 6. What are the conversations you’re having with your customers regarding EVs? 7. Do you feel Alaskans are holding out for the pickup models vs the sedan models? 8. What does the future of your business look like with current EV growth projections, especially as it relates to your maintenance department? EVs in Alaska Continue to Grow In our December 2023 newsletter, we noted Alaska's EV registration count at 2,551. The Alaska Division of Motor Vehicles reported recently that there are now 2,593 EVs registered in the state of Alaska, representing steady growth. Mark Your Calendar 2/22/24, 1:33 PM In this issue: NEVI Plan Spotlight, Funding Opportunity, Technical Session Recap, and January Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=037f033a68 6/7 Technical Session, Thursday, January 18, 2024 Topic: DriveOhio – Construction and Opening of the first NEVI Funded Sites Noon-1 p.m. Join on Zoom Meeting ID: 868 8314 4613 Passcode: 269374 888 475 4499 US Toll-free 833 548 0276 US Toll-free 833 548 0282 US Toll-free 877 853 5257 US Toll-free Mat-Su Transportation Fair, Thursday, January 25, 2024 Stop by anytime between 3 to 7 p.m. Palmer Fairgrounds, Raven Hall 12878 E Rebarchek Ave Palmer, AK 99654 To learn more visit mat-su-transportation-fair.com 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. 2/22/24, 1:33 PM In this issue: NEVI Plan Spotlight, Funding Opportunity, Technical Session Recap, and January Events https://us10.campaign-archive.com/?u=7bde743be4d525a5f52d948ed&id=037f033a68 7/7 Stay up to date on AEA's EV efforts at our website here. Copyright © 2024 Alaska Energy Authority, All rights reserved. Want to change how you receive these emails? You can update your preferences or unsubscribe from this list.