HomeMy WebLinkAbout2025-04-17 AEA Agenda and docs
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REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG
Alaska Energy Authority Board Meeting April 17, 2025 9:00 am AGENDA - UPDATED
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 30, 2025
5. PUBLIC COMMENTS (2 minutes per person) see call in number above
6. COMMITTEE REPORTS – None
7. OLD BUSINESS
A. Bradley Lake Renewable Energy Certificates
i. EXECUTIVE SESSION
8. NEW BUSINESS
A. Financing Options
i. Dixon Diversion
ii. HVDC Line
B. Resolution 2025-04 – Requesting Congress to Support and Maintain Energy Investment Tax Credits
9. DIRECTOR COMMENTS
A. Annual Report
B. Power Cost Equalization Report (PCE) (PCE by Community), (PCE by Utility)
C. IIJA / IRA Update - Tracker
i. OCED – ERA Concept Papers -Memo
D. Railbelt Transmission Organization (RTO) -Update
E. Owned Assets Update
i. GRIP
ii. Dixon Diversion
iii. SSQ Line
iv. Alaska Intertie – Avalanche Damage Memo
F. Net Metering Pilot Program Update
G. Power Project Fund (PPF) Loan – Update
H. IT Update
I. Legislative Submittals (Statutorily Required Reports)
J. Legislative Update (presentations)
K. Community Outreach
L. Articles of Interest
M. Next Regularly Scheduled AEA Board Meeting – Thursday, July 10, 2025, 9:00 am.
10. EXECUTIVE SESSION – (if needed)
11. BOARD COMMENTS
12. ADJOURNMENT
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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.
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 Thursday, January 30, 2025 Anchorage, Alaska 1. CALL TO ORDER
Chair Koplin called the meeting of the Alaska Energy Authority to order on January 30, 2025, at
9:00 am.
2. ROLL CALL BOARD MEMBERS
Members present: Clay Koplin (Public Member); Duff Mitchell (Public Member); Tony Izzo (Public
Member); Robert Siedman (Public Member); Jenn Miller (Public Member); Ingemar Mathiasson
(Public Member); Adam Crum (Commissioner DOR)); Julie Sande (Commissioner DCCED).
A quorum was established.
3. AGENDA APPROVAL
There were no objections to the approval of the agenda as presented.
4. PRIOR MINUTES – November 18, 2024 MOTION: A motion was made by Mr. Izzo to approve the Minutes of November 18, 2024. Motion seconded by Ms. Miller.
A roll call was taken, and the minutes of November 18, 2024 were approved unanimously. 5. PUBLIC COMMENTS (2 minutes per person) Chair Koplin advised members of the public that they can email their written comments to publiccomment@akenergyauthority.org. The cutoff for today’s written public comments was yesterday at 4:00 p.m. Chair Koplin requested that members of the public who are online and who wish to comment to press star-nine on their phone to initiate the hand-raising function. Callers are requested to identify themselves for the record, and to keep their comments to two minutes
in length. There were no members of the public online who requested to comment at this time.
A. Terra Energy Center Project Introduction
Chair Koplin requested the guest speakers from Terra Energy Center Project keep their
presentation to 15 or 20 minutes, and to answer questions from the Board. Chad Schleusner,
General Manager of Terra Energy Center, introduced Robert Powers of Terra Energy Center. Mr.
Schleusner gave his professional background, which includes leading major projects across Alaska,
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the Lower 48, and internationally. He noted that the team at Terra Energy Center is experienced in advancing the decarbonized biomass coal-fired power plant in the West Susitna, which is identified by AEA as one of the clean energy projects for the Railbelt. Mr. Schleusner indicated that Terra Energy Center is working with a strong group of companies and industry experts to advance the project. This includes Sargent & Lundy who is a world-leading firm familiar with advancing carbon capture and major power plant projects. Additionally, there is
a strong Korean-led EPCM consortium, collaboration with University of Alaska Fairbanks (UAF),
power plant operators, pipeline development companies, major Alaska oil and gas operators, and
several technical teams advancing the environmental studies, pipeline routes, CO2 sequestration,
plant design, and project financing.
Mr. Schleusner discussed that the work completed to date shows that a biomass and coal-fired
power plant not only delivers cost competitive firm power supply, but is also the only in-state
long-term energy supply that is not dependent on international commodity markets and
price/delivery volatility related risks. Mr. Schleusner stated that Terra Energy Center is an Alaskan
company providing Alaska power for Alaskans.
Mr. Schleusner reviewed his PowerPoint presentation. He discussed the identified energy reserves and resource coal onsite to power the Railbelt is 521 million tons (Mt). He noted that less than half of that amount could power a 1-gigawatt (GW) powerplant for over 30 years. Mr. Schleusner highlighted the significant environmental baseline data collection and permitting studies completed to date. Additional permitting studies will continue in 2025. He discussed the slide showing that the coal onsite is a uniquely clean coal fuel supply. Mr. Schleusner explained that without carbon capture and sequestration (CCS), coal is cleaner than imported liquefied natural gas (LNG). He noted that most of the U.S. is familiar with the coal plants from 50 years ago using 70-year-old technology. Mr. Schleusner stated that this project is a new build of a modern coal plant integrating modern technology to create a very low emission facility that meets current standards. The unique fuel supply has no methane, unlike LNG that has methane and leaks methane through the process and emits CO2 when it is burned. A modern coal-fired powerplant has lower emissions than LNG, and is cleaner than wind with natural gas peakers. Mr. Schleusner indicated there is enough fuel onsite to power Southcentral Alaska. The
significance is that the gas can now be saved for heating and not be consumed by power
production. He discussed that coal with carbon capture is the lowest cost option of identified firm
power options in Alaska. Mr. Schleusner reviewed a recent University of Alaska Fairbanks (UAF)
study focused on fuel costs in Alaska comparing coal to LNG and gas. Coal is the lowest cost fuel
in Alaska for delivering energy. He discussed that one of the major risks associated with other
energy options of wind, solar, and grid batteries include the short supply of materials. An
additional risk is that they are subject to administrative policy changes, as shown by President
Trump’s recent executive orders.
Mr. Schleusner discussed that the proven carbon capture technology has been in use for decades.
It is identified as the best system of emission reduction and is supported by the DOE. There are
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over 5,000 miles of CO2 pipelines throughout the U.S. which have been transporting CO2 for decades. Mr. Schleusner indicated that CO2 is a commodity and Terra Energy Center can deliver CO2 security for the state. He highlighted the stakeholder support for the project. The DOE has granted funds to Alaska to develop CO2 pipelines and storage verification. Mr. Schleusner referenced the public support as shown by the 2023 Dittman Public Research Poll of Anchorage residents identifying 65% supported coal with carbon capture and 65% opposed importing LNG.
Mr. Schleusner discussed the slide showing the DOE funded coal and carbon capture projects
throughout the U.S. There is a current notice of funding opportunity (NOFO) that Terra Energy
Center is working to support and deliver a concept paper by March 1, 2025. Mr. Schleusner
summarized the collaborative process to procure the $400 million grant from U.S. Department of
Energy (DOE) and to move the project forward to a Final Investment Decision (FID) in 2026. Terra
Energy Center offers predictable, cost-competitive, in-state power with low emissions. Mr.
Schleusner reviewed the work in progress and the planned pre-front end engineering and design
(PreFEED) work for 2025. He indicated two requests for AEA: 1) to provide a letter of support for
the application to the DOE, and 2) to collaborate a plan to achieve FID in 2026 for a potential on-
line power date of 2030. Mr. Schleusner stated that Terra Energy Center is part of the energy
supply equation for Alaskan’s economy and future growth. He believes this project merits close
consideration by AEA and looks forward to working with AEA staff on the goal of secure and effective energy solutions for the Railbelt. Mr. Izzo disclosed for the sake of transparency that Matanuska Electric Association (MEA) is working closely with Terra Energy, including a non-binding term sheet for a power purchase agreement. A confidentiality agreement is in place. Ms. Miller asked Mr. Schleusner if he sees any risk that the DOE funding opportunity will be cancelled. Additionally, she requested more information regarding how strongly the project meets the objectives of that funding opportunity. Mr. Schleusner indicated there has been support for carbon capture since 2008. He does not believe that the 45Q Tax Credits are going to be rescinded. There is bipartisan support for this DOE funding and he believes there is high likelihood that the funding will move forward. Mr. Schleusner discussed that Terra Energy is in a very unique position as the only new build in the U.S. that has associated carbon capture. The DOE is keenly interested in the development of this power plant that integrates a carbon capture system on a commercial
scale.
Commissioner Crum requested an overview of the timeline for the key components of the grant.
Mr. Schleusner outlined that the concept paper is due March 1, 2025. Terra Energy would like to
have letters of support to reference in the concept paper. The full application is due on July 1,
2025. There were no other questions.
Chair Koplin asked if anyone in the room wished to make a public comment.
Mead Treadwell, Chairman and Chief Executive Officer (CEO) of Qilak LNG, discussed that Qilak
LNG is a second LNG project that is proposed to directly export LNG from the North Slope using
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gas from the Point Thompson field. Mr. Treadwell expressed support for the previous presentation, and believes it is an important project to consider. He highlighted that there are six or seven LNG projects in Texas, and three or four LNG projects in Louisiana. Mr. Treadwell indicated that there is enough gas on the North Slope to support several LNG projects. He stated that Qilak LNG proposes to export four million tons a year. Prefeasibility and shipping studies have occurred, and the feasibility study is planned for this year.
Mr. Treadwell explained the purpose of his comments today is to ask AEA to consider utilizing
Qilak LNG as well as AK LNG for delivery of LNG from the North Slope to Alaska communities. Mr.
Treadwell commented, however, that he is not speaking for AK LNG in any way. Mr. Treadwell said
that if Alaska is going to import LNG in Cook Inlet, he highlighted the opportunity to ship boxed
LNG in ISO containers to communities, to mine sites, and to places that may need cheaper and
more reliable fuel. Mr. Treadwell discussed that many of the power plants that AEA bought have
the capability for dual fuel. He referenced that AEA conducted a study in 2014 in which ice-choked
communities were ground ruled out of the study. There has now been enough advancement in
the ISO container efficiency so that regasification may require only two deliveries a year to support
a community’s needs.
Mr. Treadwell referenced a study on alternatives conducted by the Arctic Domain Awareness Center and ASRC Federal and others that followed AEA’s 2014 study. He noted that Qilak LNG has identified a contractor that is building the LNG storage facility on the North Slope for Hilcorp and appears to have one of the leading advances in technology on the ISO containers. Mr. Treadwell noted that approximately a quarter of Qilak LNG’s four million tons per year could fulfill the needs of Enstar and other Southcentral gas. He discussed that the opportunities for trading and transportation are strong, and the opportunities to load ISO containers and barges to serve Alaska communities is fairly strong as well. Mr. Treadwell believes AEA would be a very good partner with Qilak LNG to update AEA’s 2014 feasibility study. Mr. Treadwell expressed appreciation to Governor Dunleavy for the supportive State policy toward the work being conducted by Qilak LNG and other entities. He believes it is prudent to advance several different concepts, and encouraged AEA to take a stronger role. There were no questions. There were no other identified members of the public online or in-person who requested to
comment at this time.
6. COMMITTEE REPORTS
A. Personnel Committee – Employee Policies and Guidelines
Curtis Thayer, Executive Director, noted that the Personnel Committee met. He requested that the
Chair of the Personnel Committee, Mr. Izzo, provide an update. Mr. Izzo reported that the
Personnel Committee met on January 28, 2025. The attendance included Mr. Izzo, Ms. Miller, and
Commissioner Sande. Two action items were completed. The Committee elected Mr. Izzo as Chair,
and Ms. Miller as Vice-Chair. The Committee was presented with and reviewed the updated
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employee policies and guidelines document. The Committee was impressed with the work product as presented by AEA staff, and recommended by unanimous motion that the document be brought before and approved by the AEA Board. There were no comments or questions. 7. OLD BUSINESS - None 8. NEW BUSINESS
A. Resolution 2025-01 FY26 Operating and Capital Budget Submissions Ratification
Mr. Thayer explained that Resolution 2025-01 endorses the Governor’s operating and capital
budget. Included in the packet with the resolution are additional documents regarding the
Governor’s proposed budget as it relates to AEA, as well as comparisons to previous years’
budgets. Mr. Thayer discussed the page that shows AEA’s FY2026 Operating Budget Requests
ranked by priority one through six. Priority Ranking 1 is the request for working capital from the
State at $3.5 million. For the last 30 years, AIDEA has provided this working capital. Mr. Thayer
indicated there is a resolution for AIDEA to continue this position for FY26, beginning June 1, 2025.
Mr. Thayer discussed Priority Ranking 2 is for replacement funding for three positions to meet the
Circuit Rider Program at $710,000. The source is the PCE Endowment Fund. Priority Ranking 3 is
for the data library administration, hosting, expansion, and digitization. This is a reappropriation
of funds from a previous grant. Priority Ranking 4 is for the leased warehouse roof replacement. The warehouse is utilized rent-free from Department of Natural Resources (DNR) and a new roof is necessary. The ongoing issues include the options to replace the roof or to move to a smaller location. There are also issues with crime and a nearby homeless camp. Mr. Thayer discussed Priority Ranking 5 for $80,000. Priority Ranking 6 of $304,000 is to either pay for the current office space in this building that is currently rent-free from Alaska Industrial Development Export Authority (AIDEA) or to be used to look for office space elsewhere. Mr. Thayer noted that with the additional employees coming to the building, the size of the building is at capacity per the fire code.
Mr. Thayer highlighted that AEA has asked for a reappropriation in the supplemental budget of $624,000 to update the accounting system, phone system, copiers, and a hardware refresh. These are back-office needs. These funds have been identified in a reappropriation and are expected to be seen in the supplemental budget.
Mr. Thayer discussed the priority rankings of the FY2026 AEA Capital Budget Requests. Priority Ranking 1 is a $1.5 million placeholder toward the grid partnership and Grid Resilience and
Innovation Partnership (GRIP) funding. The State has put in $12.7 million. The utilities and AEA
through bonding have put in $50 million. Priority Ranking 2 is $6.5 million for the Dixon Diversion
Project that will optimize Bradley Lake and increase its energy production by approximately 50%.
An additional request is that AEA and the utilities provide another $6 million to reach the $12.5
million that will allow the on-time FERC filing in January. Mr. Thayer noted that the funding for
FY26 becomes available July 1, 2025. It behooves AEA and the utilities to acquire additional
funding now so that the spring construction is not lost.
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Mr. Thayer reported that Priority Ranking 3 is $4 million for the bulk fuel upgrades. This is the same as last year’s spending level. Priority Ranking 4 is $5 million for powerhouse upgrades, which is also the same as last year’s spending level. Mr. Thayer discussed that the formula funding for the Infrastructure Investment and Jobs Act (IIJA) and Grid Resilience has a $13.4 million request, of which $1.8 million is Unrestricted General Funds (UGF). Mr. Thayer noted that receipt authority amount will increase because there is additional eligible funding available that does not require additional match, but it does require receipt authority. Priority Ranking 6 is $6.3 million, and the
Legislature could possibly increase this amount. Priority Ranking 7 is $42 million for federal receipt
authority for the remaining balance of the Solar for All Program. Priority Ranking 8 is $4.4 million
for the Whittier-Cruise Ship Terminal Electrification Project. This is a partnership with Holland
America, contributing $6 million, and Chugach Electric Association (CEA). The State funding comes
directly from the cruise ship passenger tax.
Mr. Thayer highlighted that Priority Ranking 9 and 10 each asks for a change in language. Priority
Ranking 9 indicates that “AEA will apply for tax credits for projects funded by AEA, and will apply
for revenue from tax credits received toward renewable energy projects or as matching funds for
federal programs.” Priority Ranking 10 states “AEA holds all corporation funds in interest-bearing
accounts. Interest earned on federal grant funds and matching funds appropriated to AEA will be
appropriated to AEA as matching funds that will hedge against inflation.” Mr. Thayer discussed
that the item is the AEA Supplemental Budget is for electrical emergencies in rural Alaska at the reappropriation amount of $234,500. Mr. Thayer noted that the component details and the entries into the system are also included in the packet.
Commissioner Crum asked Mr. Thayer if there is an anticipated amount for the federal tax credits under Priority Ranking 9. Mr. Thayer indicated this is a broad federal receipt authority because the project eligibility and amounts are unknown. He noted that AEA has contracted with a national firm to identify qualified tax credits for Bradley Lake and the Dixon Diversion. However, after the activity over the last five days, the available tax credits may have changed. Commissioner Crum noted it is probably safe to say there will be some federal action in the next fiscal year to adjust the tax credits. He believes the broad receipt authority is an appropriate ask from the Legislature.
Ms. Miller expressed support for the broad receipt of the federal tax credits. She asked Mr. Thayer if AEA should broaden the ways those funds can be applied, such as fuel system upgrades in rural Alaska, or should it be specific to rural energy projects. Mr. Thayer believes the biggest opportunity for tax credits is the Dixon Diversion project. He is assuming that the tax credits will be applied to Dixon Diversion to lower the cost of the project to the consumer. Mr. Thayer assumes
that the tax credits will stay with each particular project. There were no other comments or
questions.
MOTION: A motion was made by Mr. Izzo to approve Resolution 2025-01, Fiscal Year 26
Operating and Capital Budget submission ratification as presented. Motion seconded by
Ms. Miller.
A roll call was taken, and the motion to approve Resolution 2025-01 passed unanimously.
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B. Resolution 2025-02 Use of Interest for Bradley Lake Required Project Work
Mr. Thayer explained that in 2022, the bonding resolution for the $166 million in Series 11 Bonds included required project work items approved by the Department of Law (DOL). Since then, DOL has provided an opinion that some of the funding could be used for the GRIP match to reach the needed $206.5 million. Mr. Thayer explained that the Bradley Lake Management Committee (BPMC) initially approved $20 million and approved an additional $30 million this year, totaling $50 million. The master bond resolution needs to be upgraded. Work with the bondholders is
ongoing and they are supportive of updating the resolution document from 2022. The one new
section is the WHEREAS section beginning with, “WHEREAS, the AEA desires to amend the Tenth
Supplemental Resolution and any other agreements related to the Series 2022 Bonds to permit
the Authority to apply interest earnings on the proceeds of the Series 2022 Bonds deposited in
the Eleventh Series Construction Account,” which is language supported by the bondholders. Mr.
Thayer noted that he discussed this resolution with the Railbelt utilities and requested that the
BPMC approve a concurrent resolution at their next meeting on February 14, 2025. The Railbelt
utilities’ CEOs verbally agreed.
Mr. Thayer asked Mr. Billingsley if he missed any part of the process. Mr. Billingsley commented
that procedurally, the next steps would be for the Board to pass this resolution, get concurrence
from the BPMC, and then finally, amend the bond documents.
Mr. Siedman asked if the Series 22 Bonds are subject to arbitrage and federal tax withholdings, and if so, he inquired as to the process of resolving the taxes accrued by the interest. Mr. Billingsley stated that bond Counsel can answer his questions specifically, however, it will not have an impact on the taxes that are owed. Mr. Billingsley said there could be subsidies for the bonds, but it will not have an impact on the taxes. There were no additional questions.
MOTION: A motion was made by Vice Chair Mitchell to approve Resolution 2025-02. Motion seconded by Ms. Miller.
Mr. Izzo noted that for the sake of clarity, he will discuss the reasons for his support of this resolution. The State owns Bradley Lake. The utilities are the purchasers that take power off Bradley Lake and receive lowest cost power in the Railbelt, which is firm and dispatchable. The cost is approximately four cents per kilowatt hour. The utilities do not mark that price up at all. It is a complete pass-through. The members, the consumers from Homer to Seward to the Valley to Fairbanks, pay for all the costs associated on a pro rata basis. In essence, the Seward consumer is paying the same pro rata share as the Fairbanks consumer for the power. It is a great business model and allows earnings to directly benefit those same consumers. Mr. Izzo expressed
appreciation to Mr. Thayer for a job well done.
Commissioner Crum concurred with the comments of Mr. Izzo. He believes this resolution is an
appropriate use for AEA staff and the BPMC to identify possible gains back to the fund by using
the interest accordingly. He expressed appreciation to the team for constantly reviewing ways to
maximize the use of the public financing on each project. Commissioner Crum expressed support
for the resolution, and complimented staff. There were no other comments or questions.
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A roll call was taken, and the motion to approve Resolution 2025-02 passed unanimously. C. Resolution 2025-03 Authorize AEA to borrow $3.5 million from AIDEA for working capital.
Mr. Thayer provided background information on Resolution 2025-03. He explained that prior to the separation of the AEA and AIDEA Boards, AEA had an agreement for the last 30 years to borrow $7.5 million for working capital from AIDEA without interest. When the AIDEA and AEA
Boards were split, the AIDEA Board wished to no longer provide the $7.5 million of working capital.
In conversations with AIDEA Executive Director Randy Ruaro and with the AIDEA Board Chair, the
AIDEA Board approved a resolution that AEA could borrow $3.5 million working capital for FY2025
with a 5.25% interest rate. However, Mr. Thayer explained that AEA has no mechanism to pay that
interest because there is no way to collect off the federal awards.
Mr. Thayer discussed that AEA worked with the State to take the AEA payroll out of the equation,
and to use the State’s Integrated Resource Information System (IRIS) payroll system. The State is
providing the working capital. As AEA gets reimbursed for AEA’s payroll, AEA reimburses the State.
The working capital for the grants is still outstanding. The grants are primarily focused on rural
Alaska. Based on AIDEA’s Resolution G24-02 that was passed, it was agreed that AEA would have
the availability for the working capital. The details are outlined in the included Memorandum of
Understanding (MOU). Any interest earned on the account would be given back to AIDEA, which
is the same procedure for the State.
Mr. Thayer noted that the Office of Management and Budget would like to extend the $3.5 million working capital for another year into FY26. The memo included in the Board packet outlines this intent, and the resolution before the Board is for AEA to request to borrow $3.5 million from AIDEA, including the conditions of the rent and reimbursement. Mr. Thayer explained that he is addressing this matter now because the next official meeting of AEA is in April, and this agreement is for July 1, 2025. He would like for the process to be seamless to apply for the FY2026 year. Next year’s evaluation will occur with the parties to ensure the arrangement is effective.
Commissioner Crum asked, for the public’s understanding, if this structure is similar to a line of credit for a private sector business. Mr. Thayer agreed. Commissioner Crum indicated his businesses and every business he knows of has a line of credit. There were no other comments or questions.
MOTION: A motion was made by Ms. Miller to approve Resolution 2025-03, authorizing AEA to borrow $3.5 million from AIDEA for working capital, as presented. Motion seconded
by Mr. Mathiasson.
A roll call was taken, and the motion to approve Resolution 2025-03 passed unanimously.
D. Utility Priority for Purchase of Bradley Lake Renewable Energy Certificates
Mr. Thayer explained that the AEA Board previously voted to consider selling Renewable Energy
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Credits (REC Credits) related to Bradley Lake. Mr. Thayer stated that looking forward, the amount could be $400,000 to $500,000 a year. He took the issue to the BPMC. On December 19, 2024, the BPMC wrote a letter to Chair Koplin expressing support, however, they would like to have the first right of refusal of the credits. Mr. Thayer reported that since this letter was submitted, one of the utilities has conducted a further legal analysis on their position and differing opinion. Mr. Thayer discussed that AEA’s intent of the effort to monetize REC credits was to take the funding and put it into the capital projects, such as Dixon Diversion and Bradley Lake, to benefit the rate payer.
This effort is a work in progress, and additional conversations will occur with the utilities.
Ms. Miller expressed her hope that a Renewable Portfolio Standard (RPS) is passed by the
Legislature that would provide a runway of notice of multiple years before it goes into effect. She
would hate to see that the RECs were not monetized due to the fear of a penalty and therefore
miss out on the monetary value for the rate payers.
Mr. Izzo commented that from a utility perspective, the concern is that an RPS would have the
effect of raising rates and may be an unintended consequence as a result of not having Bradley
Lake RECs. On the one hand, the RECs are being sold for the benefit of the rate payer, and then
through legislation, there is a penalty and additional costs because the RECs were given away.
When the megawatt hours are reviewed, the hope is that any legislation is based on actual energy
and not necessarily what color the energy is. The amount of renewable energy being consumed
is not going to change, and is not dependent on a penalty or no penalty. Mr. Izzo requested that
any legislation avoid such an unintended consequence.
Vice Chair Mitchell commented that AEA has discussed RECs in previous Board meetings, including selling them and ways to combine smaller RECs from other projects across Alaska. He recommended that AEA move and resolve this issue expeditiously based on the current facts, rather than hypothesize regarding future legislation. The goal is for the sale of the RECs for the benefit of Alaskans and lowering Alaskans’ cost of power. Vice Chair Mitchell hopes that the utilities will committedly resolve this issue expeditiously.
Vice Chair Mitchell commented on the portion of BPMC’s letter stating, “granted an option to purchase its portion of the RECs,” and asked Mr. Thayer if this request is at market value or a special rate. He highlighted that AEA is trying to maximize what the RECs can provide to Bradley Lake and to BPMC. Vice Chair Mitchell indicated that the letter is silent on the value proposition. He requested clarification and noted this might be part of the work in progress. Mr. Thayer agreed this is a work in progress and there was not a specific value placed on the credits at the time the letter was written. Mr. Thayer explained that the differing opinion of one of the utilities is that they
do not believe that AEA has the right as the owner to sell the REC credits, rather that the utility
already owns the REC credits. Mr. Thayer indicated those issues will have to be addressed and
resolved. The ultimate goal is to benefit the rate payer.
Vice Chair Mitchell expressed appreciation for the clarification. He noted that as an AEA Board
member and regardless of any utility’s position, he is in accord with Mr. Thayer that these are, in
fact, AEA REC credits and not the ownership of any of the utility REC credits. Vice Chair Mitchell
indicated that he does not want to get bogged down on this issue, but would rather take a solid
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approach of the position. He supports Mr. Thayer taking the stronger approach on behalf of AEA to decrease the cost of power for Alaskans.
Mr. Siedman noted that Resolution 2024-17 was discussed during a recent Board meeting, and the vote was unanimous to authorize AEA to sell the REC credits for the purposes mentioned by Vice Chair Mitchell, including lowering the cost of power and invest in the maintenance of infrastructure. Mr. Siedman commented that he wants to ensure that the sale is conducted legally. He explained that if the RECs are already being claimed, then they cannot be sold. Double-dipping
is not allowed. Mr. Siedman emphasized the importance of understanding the circumstances so
that the action of selling the RECs do not have an unintended adverse consequence.
Mr. Izzo commented that he has a different perspective compared to Vice Chair Mitchell. Mr. Izzo
believes AEA needs to be careful. The mission is to reduce the cost of energy to Alaskans. He
disclosed that MEA is not the utility challenging the RECs, nor does he represent the utility
challenging the RECs. Mr. Izzo noted that his position has been consistent as an AEA Board
member who voted to move forward with the process. However, new information has been
introduced, and a utility is challenging the RECs. Mr. Izzo indicated that he does not want hubris
to drive additional legal costs, legal challenges, or legislation that could result in a utility being
forced to pay $1.20 for something they legally had. Those consequences are contrary to reducing
the cost of energy to Alaskans. Mr. Izzo expressed appreciation to Mr. Thayer and staff for their
efforts and acknowledged that they have clearly identified an issue that must be resolved
thoughtfully, rather than abruptly.
Ms. Miller expressed support for Mr. Izzo’s comments. She indicated that it is not prudent to sell something that the utilities may have to pay for under an RPS. Ms. Miller believes that the ownership issue must be resolved. She noted that understanding the term commitment for selling the RECs could provide flexibility and comfort for the parties. Ms. Miller discussed that she has seen consideration for term commitments in contracts and on past projects to ensure that costs are not increased. She expressed appreciation for the work and good discussions of all the parties.
There were no other comments or questions.
Jennifer Bertolini, AEA, informed Chair Koplin that a member of the public who is on telephonically has their hand raised. Chair Koplin asked if there was any objection to allowing additional time for public comment. There was no objection.
Chair Koplin asked if the person on the line would like to make a public comment. Melis Coady, Susitna River Coalition, said she has a question for the representative from the Terra presentation. Ms. Coady noted that she has been curious about some of the information regarding the
proposed Susitna clean coal project. She said it is hard to find information about the project, and
that Terra Energy does not have a website. Ms. Coady commented specifically on the funding
topic areas for the Department of Energy grants, and noted that the slide in the presentation said
there is DOE funding up to $40 million. However, the funding topic area that they are applying
for is TA-2, which are for pilot projects. Although that category of funding has up to $450 million
of funding available, the plan is to award up to five projects. The minimum funding award amount
Alaska Energy Authority Page 11 of 19
would be $75 million and the maximum in that funding category is $135 million. Ms. Coady asked if AEA staff has received materials and has an understanding of what funding amount is needed for the carbon capture technology, because it is unclear if they have that funding amount.
Chair Koplin noted that the materials presented to AEA are public information and the slideshow is available on the AEA website. Chair Koplin indicated the slideshow is the only information AEA has on the subject at this time. Chair Koplin thanked Ms. Coady for her comments and question, and reiterated the materials are available online.
There were no other public comments.
9. DIRECTOR COMMENTS
A. Economic Impact Analyses
Mr. Thayer discussed that he previously sent this publicly available report to the Board members.
He noted that Conner Erickson, AEA Director of Planning, contracted with Northern Economics to
review the economic impact to Alaska of the three biggest projects on the Railbelt; Sterling
Substation to Quartz Creek (SQ) Substation transmission line update, Dixon Diversion project, and
High Voltage Direct current (HVDC) submarine transmission line across Cook Inlet. The economic
analysis is the result of the work completed by the independent, third-party Northern Economics
and is being used as the base for AEA’s conversations with funding partners, the Legislature, and were used in the Governor’s state of the State address. Mr. Thayer discussed that the projects are operating concurrently and will create over 5,000 jobs and over a billion dollars in economic activity. The number of jobs include direct, indirect, and induced. Chair Koplin clarified for the record that the data provided is the economic impact analysis during construction and not the intrinsic economic value to rates once the projects have been completed. Mr. Thayer agreed. There were no other comments or questions. B. Owned Assets Update i. Dixon Diversion Video ii. GRIP Video Mr. Thayer discussed that in 2024, Bradley Lake produced over 404,000 megawatt hours (MWh)
and Battle Creek produced approximately 38,000 MWh. The Battle Creek project was completed
in 2020, and has increased in its production of MWh each year. Mr. Thayer commented that the
environmental studies performed in 2024 for the Dixon Diversion are currently being finalized.
AEA met with a Board of Consultants and the Federal Energy Regulatory Commission (FERC) Dam
Safety at Bradley Lake last summer and last fall. The FERC filing that is expected in January of 2026
is on target to be completed. The filing will occur sooner, if possible. The Governor’s budget has
funding for the Dixon Diversion, and the hope is that full funding will be achieved with the BPMC’s
concurrence.
Alaska Energy Authority Page 12 of 19
Mr. Thayer reported that the Sterling to Quartz Transmission Line is currently under construction. Bradley Lake is not operational for the northern utilities, since it is islanded while the work is being completed. If there is a cold snap and the project must come back online, there are provisions with the contractor and CEA to bring the line back on within days. Mr. Thayer hopes to be able to share construction pictures and progress with the Board.
Mr. Thayer noted that one of the issues is a change order for up to $2 million. He explained that
the work is being conducted during the winter to work on wetlands. Mats must be used under the
equipment when the temperatures are in the 30’s and 40’s. He noted that delaying the schedule
was considered and the determination was made to keep to this year’s schedule for a few reasons;
there is no way of knowing if the weather will be any different next year, there is a limited amount
of time that Bradley Lake can be down in a year, and CEA is coordinating and conducting their
upgrade work simultaneously while Bradley Lake has its outage for 40 days, beginning from
January 7th. There were no comments or questions.
Mr. Thayer requested Jim Mendenhall, AEA, to provide an update on the GRIP 3 HVDC Line. Mr.
Mendenhall reviewed the memo provided in the packet. Stantec is reviewing the Initial Project
Plan and Schedule, Conceptual Design, Preliminary Cable Design, Critical Environmental Analysis, and the Preliminary Cost Estimate. The initial report was shared with AEA, one of the engineers, and the Technical Working Group, which consists of representatives of the Railbelt utilities. Mr. Mendenhall noted that the meeting last week included decisions regarding the transfer capability of 200 MW and the preference by the majority for a bipole, rather than a monopole. There is cost component for the bipole capability. He highlighted the review of cable routings, the best way to land the cable, and the transfer capacity between Soldotna and Nikiski. Mr. Mendenhall noted the eight-year project schedule. He stated that the meeting last week was very productive. However, it is not productive that IIJA and Department and Energy (DOE) are pretty much shut down. The official kick-off meeting that was scheduled to occur tomorrow is postponed. There is no conversation, and the DOE is not answering the phone. Mr. Mendenhall believes they were given guidance not to talk to anyone. Even under those considerations, AEA believes this is still a good infrastructure project, and AEA is optimistic it will continue.
Mr. Mendenhall discussed that Stantec’s plan is to prepare an initial project estimate to be ready
mid-February for the legislative meetings, and to have a final report out in late March of 2025. He
reiterated that AEA has $62.7 million in State and matching funds from the utilities. An additional
$143 million must be secured as a starting point.
Mr. Izzo thanked Mr. Mendenhall for his update. Mr. Izzo commented on the uncertainty related
to the funding for IIJA and the Inflation Reduction Act (IRA). He reported that through the
statewide trade organization, the regulated utilities have been requested to list out information
for the federal delegation on what projects are pending and what the impacts might be. Mr. Izzo
asked if there was any additional information in terms of inquiries. Mr. Thayer discussed the big
Alaska Energy Authority Page 13 of 19
picture, and advised that AEA received the same notice. He commented on the confusion with the President’s executive orders. Mr. Thayer noted that all of AEA’s IIJA funding, AEA’s IRA funding, and Denali Commission funding is currently on hold. He stated that a draft list identifying the affected projects has been provided to the Board. The federal amount on hold is approximately $550 million, and the non-federal required match component on hold is an additional $254 million, which totals approximately $800 million on hold for AEA.
Mr. Thayer discussed that AEA is sending out notices to all of the contractors and subrecipients,
directing them to stop spending money and to hold steady until AEA informs them otherwise. Mr.
Thayer commented that anything that deals with Diversity, Equity, and Inclusion (DEI) or the
Justice40 is removed from any federal award and is no longer being paid for, as of January 27,
2025. He explained that some of AEA’s federal funding included sections on Justice40, which will
not be reimbursed and is out of contention. Mr. Thayer discussed that some of the funding is
being reviewed on a case-by-case basis. He gave the example of $12.7 million worth of State
funding for GRIP. Mr. Thayer instructed staff to use the State funding and go back for the match
after the fact, because there are deadlines for the Legislature and Stantec needs to provide those
details. He noted that much of AEA’s federal funding does not have a State match component,
and AEA is unable to move forward because there is no funding. This situation goes into AEA’s
$3.5 million line of credit, which is normally the churn. Mr. Thayer explained that AEA has submitted bills and if they are not getting reimbursed, then that line of credit will quickly be diminished, which is a concern. Mr. Thayer noted that the AIDEA Board Resolution says the line of credit can be up to $7.5 million. He believes it is important to have the conversation with Mr. Ruaro for the additional cash flow. He thinks that ultimately, the majority of AEA’s program funding will be fine, and that the President’s executive orders are a look-back for transparency. Mr. Ruaro understands that. He explained that a President’s executive order cannot overturn an act of Congress, unless Congress decides to act. Mr. Thayer believes that the review period will vary, and he does not know if it will be a week, a month, or 90 days. Mr. Thayer explained that AEA is ensuring that all of the billing has been submitted to the federal government, so that when the federal government starts paying bills, the bills will be in the queue. Mr. Thayer believes AEA is managing the case-by-case and day-by-day circumstances the best
they can. The project list will be updated as changes occur. He discussed that AEA would update
the Denali Commission awards with the communities affected. Mr. Thayer indicated that Mr.
Billingsley is monitoring the legal side of the funding hold. Mr. Thayer stated that he will keep the
Board apprised as additional information is learned. There were no other comments or questions.
Mr. Thayer discussed that the Board previously viewed AEA’s video on Bradley Lake. He requested
to play the updated Dixon Diversion video.
A brief at-ease was taken. The Board reconvened its regular meeting.
The Dixon Diversion video was played. Mr. Thayer indicated that this video was shown last week
to the House and Senate Resources Committee. Mr. Thayer requested to play the GRIP video. The
Alaska Energy Authority Page 14 of 19
GRIP video was played. Mr. Thayer requested to play the final video focused on AEA’s efforts in rural Alaska. The video focused on rural Alaska was played. Mr. Thayer explained that the videos were created to show the interested parties in Juneau and elsewhere the work and assessments AEA has completed over the last couple of years. He thanked Brandy Dixon, Tim Sandstrom, Chris McConnel, Bryan Carey, Mr. Mendenhall, and other AEA staff for providing the context and script for the videos. Mr. Thayer indicated that narration will be added to the videos that do not have narration. There were no comments or questions.
C. Railbelt Transmission Organization (RTO) Update
The RTO Update is included in the packet. There were no questions.
D. Denali Commission Update
Mr. Thayer discussed the Active Denali Commission Awards list included in the packet. The federal
government hold on funding has affected and paused funding for every one of the projects. The
list presented was created prior to the federal government funding pause. There were no
questions.
E. PCE Endowment Mr. Thayer explained that the Power Cost Equalization (PCE) program is funded through the PCE endowment and managed by the Permanent Fund Corporation (PFC). Monthly reports are given to AEA by the PFC, and Pam Ellis, AEA Controller, tracks the earnings. Mr. Thayer indicated that AEA does not have statutory authority to determine how the funds are invested. As shown in the provided chart and schedules, the PCE fund ended in November 2024 with a little more than $1 billion. There were no questions. F. IIJA Update Mr. Thayer discussed that the information outlining the AEA IIJA/IRA Funding Opportunities is regularly provided to the Board. The highlighted sections include the notice of award on January 6, 2025, and notice of conditional awards on January 15 and 16, 2025. Mr. Thayer indicated this
list was created prior to the federal government funding pause for IIJA and IRA. He explained that
the money from the notice of award on January 6, 2025 is not yet obligated to AEA, and that
money might be in question. Additionally, AEA is closely following the status of the two
conditional awards of $36 million each. Both awards were given to AEA a couple of years ago, and
AEA is currently in the application period, but now the status is in flux.
Mr. Thayer informed that AEA will continue to submit the applications by their due dates. One has
already been submitted, and one is expected to be submitted by the Friday deadline. AEA is
assuming that when everything picks back up, the applications will be processed as normal, since
the federal funding was acquired a couple years ago and the receipt authority from the State
Alaska Energy Authority Page 15 of 19
occurred in a previous fiscal year. The total conditional award amount in question is $74 million in rebates and energy efficiency. Mr. Thayer discussed that AEA submitted applications prior to the government funding pause for a couple of other programs that are listed as Pending. He noted that AEA will continue to work on and submit applications that are listed as Considering. The High Energy Cost Grants 2025 – USDA RUS, for example, is traditionally applied for and was active prior to IIJA. Mr. Thayer
indicated that the program may not be affected because of this. AEA is acting as normal,
submitting applications and filing the billing, until such time as different information is known.
There were no questions.
i. Home Energy Rebates and Training for Residential Energy Contractors
Mr. Thayer noted that the memorandum regarding the Home Energy Rebates and Training for
Residential Energy Contractors Update was created prior to the federal government funding pause
that occurred last week.
Ms. Miller highlighted that it might be too early to know, however, she asked Mr. Thayer if he has
a sense of what portion of the funding is related to Diversity, Equity, and Inclusion (DEI) or Justice40, because that funding seems more at risk. Mr. Thayer explained that every application submitted included a required DEI component, as directed by President Biden’s executive order. President Trump’s executive order rescinded that mandate. Mr. Thayer advised that all DEI and Justice40 components are being stripped out and will not be paid for. AEA is notifying their subrecipients that the DEI and Justice40 components are no longer part of the award because they will not be paid. Mr. Thayer asked Mr. Billingsley to comment. Mr. Billingsley indicated that AEA received a notice from DOE, specifically, stating that DOE is not going to pay for anything that is DEI related. Additionally, there is the broader executive order regarding DEI. Mr. Billingsley informed that all of the applications addressed DEI and discussed the ways that DEI would be implemented. Mr. Billingsley explained that in most of the applications there is not a budget line item associated with DEI. He anticipates that AEA will be able to perform most of the scope of work and will receive the full amount of reimbursement. Mr. Billingsley noted that if AEA outlined a specific DEI activity,
that activity might not be reimbursed. He believes the situation is fairly manageable, except in
instances where the programs are entirely DEI-related or in instances of very specific budget line
items associated with DEI. The situation is evolving quickly.
Ms. Miller expressed appreciation for the clarification. She summarized that the federal grant
funding is paused for review, and that any DEI or Justice40 budgeted initiatives will not receive
funding after the pause is lifted.
Mr. Mendenhall commented regarding the GRIP project, that some upfront costs have been spent
on the Community Benefits Plan with the consultant. The funds were included under the
administrative section. There is not a specific line item or specific budget amount for the
Alaska Energy Authority Page 16 of 19
Community Benefits Plan. Work on all the Community Benefits Plans has ceased. AEA has acknowledged to DOE that work on all the Community Benefits Plans has ceased. Ms. Miller commended staff and Mr. Thayer for their additional efforts during this dynamic situation and addressing the issue in a thoughtful manner. There were no other comments or questions.
G. AEA Brochures / Publications
Mr. Thayer explained that AEA was asked to develop what he views as a pitch sheet for AEA for
the Governor’s trade mission to the United Arab Emirates (UAE). The informational document
included in the packet will be shared with legislators in Juneau. It provides a great overview of
AEA’s activities, and highlights the current Dixon Diversion project and GRIP projects. Mr. Thayer
noted that Ms. Dixon spearheaded the brochure effort and believes it is a good work product.
Mr. Thayer noted an additional request from the Governor to identify the Railbelt transmission
projects is also included in the packet. AEA worked with the different utilities on a transmission
study and developed the publication identifying the location of the projects, the type of upgrade,
and the latest cost estimates. The numbered list from one through 19 are not in priority order, but rather are in location order from Dixon Diversion northward. The projects highlighted in green indicate there is funding in progress. The two projects in Fairbanks are undertaken by Golden Valley Electric Association (GVEA). The Quartz Creek to Anchorage project is undertaken by CEA. Mr. Thayer discussed that the companion page identifies clean energy projects and uses a similar format that lists the location of the project, the type of the project, and the latest cost estimates by year, if known. Again, the numbered list from one to 17 are not in priority order, but rather are in location order from Dixon Diversion northward. Mr. Thayer indicated that this information will be updated, as needed. There were no comments or questions. H. Legislative Submittals Mr. Thayer explained that AEA is required by statute to provide the Legislature with specific reports. The reports are shared with the Board at the time they are submitted to the Legislature.
Mr. Thayer noted the reports are included in the packet as part of public notification. Mr. Thayer
stated that pending standard submittals include the Capital Project Status Report, Renewable
Energy Fund recommendations, and revised estimate of need to withdraw from Capital Reserve
Fund. There were no comments or questions.
I. Legislative Update
Mr. Thayer commented that he is pleased that the AEA Bill Tracker of legislation is a short list. He
expects the number of bills to increase. Mr. Thayer explained that depending on the legislation
and the effects on AEA, staff may have to complete a bill analysis and a fiscal note. The current
two bills do not require any AEA activity at this time. There were no comments or questions.
Alaska Energy Authority Page 17 of 19
J. Community Outreach Mr. Thayer discussed the included outline of the community outreach activities that have occurred during the previous six months. He noted that all public outreach activities related to IIJA funding, including the National Electric Vehicle Infrastructure (NEVI) projects, which were scheduled for the next month have been paused because the funding and reimbursement is paused and
questionable. AEA is in partnership with Department of Transportation (DOT). Mr. Thayer indicated
that he and senior management will still be out in the community conducting other outreach.
There were no comments or questions.
K. Articles of Interest
Mr. Thayer indicated that the current articles of interest relate specifically to AEA, and are included
for the public’s benefit. There were no comments or questions.
L. Next Regularly Scheduled AEA Board Meeting – Thursday, April 24, 2025, 9:00
am.
MOTION: A motion was made by Ms. Miller to enter into executive session to discuss confidential financial matters related to Bradley Lake that the immediate disclosure of which would have an adverse impact on the Authority. Motion seconded by Mr. Izzo.
A roll call was taken, and the motion to go into executive session passed, with Commissioner Sande absent. 10. EXECUTIVE SESSION: 11:05 a.m. – Discuss confidential financial matters related to Bradley Lake. The Board reconvened its regular meeting at 11:30 am. Chair Koplin advised that the items discussed during Executive Session were financial matters related to Bradley Lake, the immediate disclosure of which would impact the Authority. The Board did not take any formal action on matters discussed while in Executive Session.
11. BOARD COMMENTS
Mr. Mathiasson expressed appreciation for the good updates during the meeting.
Mr. Siedman noted the great meeting, and looks forward to the April meeting. He looks forward
to hearing about the federal freeze, and hopes it gets figured out sooner than later. He believes
Alaska has more on the line than any other state because many of the projects are in progress.
Halting the projects even for a moment throws a wrench in the process.
Commissioner Crum expressed appreciation for the content provided and for the efficient
Alaska Energy Authority Page 18 of 19
meeting.
Vice Chair Mitchell echoed Commissioner Crum’s sentiment regarding the efficient meeting. He commented on the commotion of President Trump’s executive orders. Vice Chair Mitchell was pleased to see in President Trump’s executive order that the kinetic movement of water, which is code for tidal hydrokinetic and hydropower, was pronounced alongside coal, natural gas, and nuclear. Vice Chair Mitchell stated that as a Co-Chair of the Legislative Affairs Committee with National Hydropower Association (NHA), there are many agencies and many trade groups
monitoring and watching what is happening. Vice Chair Mitchell communicated his understanding
that there will be cutbacks and concerns. He noted the importance of monitoring and keeping
eyes on the situation, but he believes the media has been sensationalizing. He believes the
Administration’s funding pause is like any other Administration’s actions to have their priorities
and people placed into the programs. Vice Chair Mitchell tempered that the actions are
reasonable, and everyone will just have to wear through and standby for the outcomes. He echoed
comments that with Governor Dunleavy being very close and the executive order to unleash
Alaska’s natural resources, he believes AEA should stand well to watch how this unfolds.
Mr. Izzo expressed appreciation to staff for the well-run and efficient meeting. He understands
the amount of effort and preparation required.
Chair Koplin echoed the appreciation for the efficient meeting. He complimented staff and the
Personnel Committee for their good work and for developing the new personnel manual. A Director’s Evaluation Form is being created and will soon be presented to the Board. Chair Koplin commented that he recently read the 2023 assessment of global innovation, and UAE was ranked at the top with the U.S. The UAE is well-capitalized, and Chair Koplin believes they are a great potential partner for Alaska’s businesses and industries. The UAE has been participating in the Alaska Sustainable Energy Conference.
Chair Koplin commented that he is glad to see the Susitna Watana Project again in the context of renewable energy. He has reviewed reports on the Bonneville Dam and Snake River Dam in Columbia with record salmon runs occurring recently. Chair Koplin commented on the flooding impacts on communities on the Susitna River, and he believes the state needs to reassess the flooding impacts, the water storage, and wildfire mitigations.
Chair Koplin expressed appreciation for the public comment. There have been some changes, and boxed LNG for Cordova has been reviewed. Technology advancement and cost metrics have occurred. He believes that the clean coal opportunity is great. Chair Koplin feels it is helpful that the requests that were brought to AEA were specific.
Mr. Thayer mentioned that he was reviewing information on the 15-year-old Susitna Watana
Project yesterday. He noted that if the project had stayed on schedule, there would have
technically been a grand opening ribbon cutting ceremony next year.
Chair Koplin thanked staff again.
Alaska Energy Authority Page 19 of 19
12. ADJOURNMENT There being no further business of the Board, the AEA meeting adjourned at 11:35 am.
____________________________________________ Curtis W. Thayer, Executive Director
Finance Options for
Large-Scale Projects
Dixon Diversion, $350M
AEA Revenue Bond
State of Alaska GO Gond
State Appropriation
Public-Private Partnership
DOE Low Interest Loan
Other Options
GRIP (Kenai-Beluga HVDC), $143.5M
AEA Revenue Bond
State of Alaska GO Bond
State Appropriation
Public-Private Partnership
DOE Low Interest Loan
Other Options
ALASKA ENERGY AUTHORITY
RESOLUTION NO. 2025-04
RESOLUTION OF THE ALASKA ENERGY AUTHORITY REQUESTING CONGRESS TO SUPPORT
AND MAINTAIN ENERGY INVESTMENT TAX CREDITS
WHEREAS, the Alaska Energy Authority (AEA) is a public corporation of the State of Alaska,
the State's energy office, and the lead agency for statewide energy policy and program
development, and has the mission to "reduce the cost of energy in Alaska"; and
WHEREAS, AEA, Alaska utilities, and Alaska energy developers are pursuing energy tax
credits that are critical to the success of their respective energy projects and Alaska’s energy
future. AEA, Alaska utilities, and Alaska energy developments, such as the Bradley Lake Dixon
Diversion project, appreciate the continued support of the current tax code, which creates security
and stability for projects already in planning and development. These energy projects reduce
energy costs for Alaskans and promote domestic resource development; and
WHEREAS, funding for Alaska's energy projects through investment tax credits is
consistent with Presidential Executive Orders 14153 Unleashing Alaska's Extraordinary Resource
Potential (energy, water, mining, seafood, and data processing), 14154 Unleashing American
Energy (firm base-load hydropower), 14156 Declaring a National Energy Emergency (develops
hydropower and marine energy resources) and 14179 Removing Barriers to American Leadership
in Artificial Intelligence by using domestically produced energy to fuel the edge data centers of
the future; now
NOW, THEREFORE, BE IT RESOLVED BY THE ALASKA ENERGY AUTHORITY AS
FOLLOWS:
(1) The Alaska Energy Authority urges Congress to consider each existing energy tax credit
for its ability to maintain and propel America and Alaska by spurring U.S. and Alaska new domestic
resource production and investment and reducing utility bills for U.S. and Alaska consumers and
resource developers, and creating certainty for Alaska energy developments that have already
made strategic domestic investments under current tax credit structures.
(2) The Alaska Energy Authority urges Congress to pass the “Maintaining and Enhancing
Hydroelectricity and River Restoration Act (H.R. 2160 and S. 1183),” which supports additional tax
credits for dam safety, recreational improvements, and fish passage for Alaska’ current operating
and hydropower systems and those in development. AEA appreciates that our entire
Congressional delegation are cosponsors of this critical energy legislation that benefits Alaska.
Dated at Anchorage, Alaska, this 17th day of April, 2025.
____________________________ Clay Koplin, Chair ______________________________ Curtis W. Thayer, Secretary
ALASKA ENERGY AUTHORITY
RESOLUTION NO. 2025-04
RESOLUTION OF THE ALASKA ENERGY AUTHORITY REQUESTING CONGRESS TO SUPPORT
AND MAINTAIN ENERGY INVESTMENT TAX CREDITS
WHEREAS, the Alaska Energy Authority (AEA) is a public corporation of the State of Alaska,
the State's energy office, and the lead agency for statewide energy policy and program
development, and has the mission to "reduce the cost of energy in Alaska"; and
WHEREAS, AEA, Alaska utilities, and Alaska energy developers are pursuing energy tax
credits that are critical to the success of their respective energy projects and Alaska’s energy
future. AEA, Alaska utilities, and Alaska energy developments, such as the Bradley Lake Dixon
Diversion project, appreciate the continued support of the current tax code, which creates security
and stability for projects already in planning and development. These energy projects reduce
energy costs for Alaskans and promote domestic resource development; and
WHEREAS, funding for Alaska's energy projects through investment tax credits is
consistent with Presidential Executive Orders 14153 Unleashing Alaska's Extraordinary Resource
Potential (energy, water, mining, seafood, and data processing), 14154 Unleashing American
Energy (firm base-load hydropower), 14156 Declaring a National Energy Emergency (develops
hydropower and marine energy resources) and 14179 Removing Barriers to American Leadership
in Artificial Intelligence by using domestically produced energy to fuel the edge data centers of
the future; now
NOW, THEREFORE, BE IT RESOLVED BY THE ALASKA ENERGY AUTHORITY AS
FOLLOWS:
(1) The Alaska Energy Authority urges Congress to consider each existing energy tax credit
for its ability to maintain and propel America and Alaska by spurring U.S. and Alaska new domestic
resource production and investment and reducing utility bills for U.S. and Alaska consumers and
resource developers, and creating certainty for Alaska energy developments that have already
made strategic domestic investments under current tax credit structures.
(2) The Alaska Energy Authority urges Congress to pass the “Maintaining and Enhancing
Hydroelectricity and River Restoration Act (H.R. 2160 and S. 1183),” which supports additional tax
credits for dam safety, recreational improvements, and fish passage for Alaska’ current operating
and hydropower systems and those in development. AEA appreciates that our entire
Congressional delegation are cosponsors of this critical energy legislation that benefits Alaska.
Dated at Anchorage, Alaska, this 17th day of April, 2025.
____________________________ Clay Koplin, Chair ______________________________ Curtis W. Thayer, Secretary
akenergyauthority.org
2024 Annual Report
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.
HOUSE BILL 307 ENACTS THE MOST SIGNIFICANT RAILBELT
ENERGY REFORM SINCE ALASKA STATEHOOD
Following its passage on July 31, 2024, the bill eliminates transmission wheeling
charges, established an open-access rate, and restructured AEA with a new board —
strengthening AEA’s ability to address Alaska’s energy challenges and shape its future.
Humpback Creek Hydroelectric Project, Cordova, Alaska
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 22
Financial Highlights 24
Board of Directors 26
Executive Team 26
AEA is the State’s trusted
leader in reducing energy
costs and advancing
statewide energy policy.
Table of
Contents
2024 AEA Annual Report | 3
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 $7.25 per copy.
2 | 2024 AEA Annual Report
Dixon Glacier, Alaska
The Alaska Energy Authority (AEA) is a trusted leader in advancing statewide energy policy, which
prioritizes energy affordability, resilience, and sustainability. For nearly five decades, AEA has delivered
innovative energy solutions that power our communities and fuel economic growth.
Dear Fellow Alaskans,
AEA’s efforts, including the landmark
Bradley Lake Hydroelectric Project, have
improved access to affordable, reliable
power for all Alaskans. To ensure resilient,
cost-effective, and sustainable power for
future generations, AEA is also advancing
new transmission grid infrastructure
initiatives.
With the passage of House Bill 307
last year, we took a major step toward
modernizing our Railbelt transmission
system. The bill reduced market
inefficiencies by eliminating wheeling
charges and incentivized new energy
development by extending tax-exempt
status to independent power producers
who provide their electricity to local
utilities. It also established a distinct
board of directors for AEA, enhancing the
State’s energy office’s ability to address
Alaska’s unique energy challenges and
opportunities.
In the past five years, AEA has secured
nearly $1 billion in funds through federal
grants, state appropriations, and revenue
bonds to fund transformative projects.
AEA owned assets, like the Alaska Intertie
from Willow to Healy and the Sterling-to-
Quartz Creek Transmission Line currently
being upgraded, will continue to reduce
costs and advance energy development
throughout the Railbelt.
Along with these investments, AEA has
launched another key project to further
diversify Alaska’s energy portfolio. The
$342 million Dixon Diversion project
is a major expansion of Bradley Lake,
Alaska’s largest hydroelectric facility.
This project will offset 1.5 billion cubic
feet of natural gas each year starting
in 2030 and provide clean, affordable
energy to Alaskans. As Railbelt energy
costs decrease, residential rates for rural
Alaskans will also benefit through the
Power Cost Equalization Program that
AEA administers.
Looking back on the past six years, I am
excited about what we have achieved
together, and even more optimistic about
what comes next.
Sincerely,
Mike Dunleavy
Governor
As I reflect on my first months as chair of the AEA Board of Directors, I am proud to
highlight the progress we’ve made in advancing AEA’s mission to reduce energy costs
across Alaska.
Over the past year, AEA has
achieved significant milestones,
delivering innovative energy
solutions that ensure all Alaskans
— from rural communities to urban
centers — have access to safe,
reliable, and affordable energy.
It is an honor to work alongside
our newly appointed skilled and
dedicated board. Representing
three electric cooperatives, two
independent power producers,
and an Alaska Native corporation,
they bring diverse expertise
and a shared commitment to
strengthening Alaska’s energy
future. Their experience spans
legacy and renewable power
generation, transmission, battery
storage, and advanced automation,
ensuring we are equipped to
tackle Alaska’s unique energy
challenges, from the Railbelt to
rural communities statewide.
This past year has been
transformative for AEA, marked by
accomplishments that showcase
the organization’s dedication and
innovation. One such achievement
is the Dixon Diversion Project, a
testament to the exceptional talent
and capacity of the AEA team.
Developed entirely in-house, this
initiative is set to increase the
annual energy production of AEA-
owned Bradley Lake Hydroelectric
Project by 50 percent. With the
potential to offset 1.5 billion
cubic feet of natural gas annually,
it underscores AEA’s ability to
tackle complex challenges and
deliver forward-thinking, impactful
solutions.
The board continues to be
impressed by the high levels of
engagement from AEA’s team at
every tier. Whether working with
the Legislature, collaborating
with utilities and communities
across Alaska, or engaging
with stakeholders and national
regulators, AEA consistently fosters
strong relationships and drives
meaningful progress.
2024 AEA Annual Report | 5 4 | 2024 AEA Annual Report
I want to thank my fellow board
members for their passion and
dedication to strengthening
Alaska’s energy future. On behalf
of the board of directors, I also
want to thank the AEA leadership
and team for their unwavering
commitment to managing
long-standing programs and
leveraging historic federal funding
opportunities. From Railbelt
transmission and battery storage
to generation upgrades, electric
vehicle charging infrastructure,
solar initiatives, and rural energy
projects, AEA’s work is driving
transformative change across the
state.
Looking to the future, we are
committed to reimagining Alaska’s
energy future to ensure it remains
safe, reliable, and affordable energy
for all. Alaska is a state of limitless
potential. By harnessing our local,
abundant energy resources, we are
laying the foundation for lasting
progress that empowers Alaskans
to thrive.
Clay Koplin
Chair
Letter From
THE GOVERNOR
Letter from The Chair
Sterling to Quartz Creek Transmission Line, Sterling, Alaska
One of the most transformative
developments in Alaska’s energy
landscape is the passage of House
Bill 307, which established the Railbelt
Transmission Organization (RTO)
as a division of AEA. This landmark
legislation represents the most
significant energy policy change for
the Railbelt since statehood. Since its
passing, the RTO has adopted bylaws,
established a charter, and submitted a
certificate of public convenience and
necessity application to the Regulatory
Commission of Alaska (RCA) ahead
of schedule. It is also developing an
open-access transmission tariff to
recover Railbelt backbone transmission
and ancillary service costs, with a
submission deadline of July 1, 2025.
House Bill 307 also redefined AEA’s
governance by establishing its own
distinct board of directors. This
critical change enhances AEA’s ability
to address Alaska’s unique energy
challenges and opportunities. The
energy sector is inherently complex,
intersecting with government
policy, environmental stewardship,
and economic development. With
a dedicated board, AEA is better
positioned to develop effective policies,
implement strategic plans, and allocate
resources aligned with its mission and
goals.
In rural Alaska, AEA partners with
communities to improve and replace
energy infrastructure in some of the
harshest environments on Earth. Using
advanced reality capture and mapping
technologies, AEA has assessed
234 powerhouses, 292 tank farms,
and 32 rural distribution systems to
identify critical needs. Under Governor
Dunleavy’s leadership, $126 million has
been invested in repairs, maintenance,
and new powerhouses through the
Rural Power Systems Upgrade Program.
Additionally, the Bulk Fuel Upgrade
Program has allocated $80 million
to extend the life of or replace aging
tank farms — some over 60 years
old — ensuring safe and efficient
fuel storage at more than 400 bulk
fuel facilities statewide. Helping rural
energy infrastructure reach its full
economic life are AEA’s Circuit Riders
— a dedicated team of technicians and
trainers who serve as first responders
to power system challenges. In the last
five years, they have restored power to
20 communities during emergencies,
provided remote technical assistance
over 2,000 times, delivered on-site
training on more than 400 occasions,
and helped 181 rural Alaskans complete
coursework at the Alaska Vocational
Technical Center.
On the Railbelt, AEA owns and operates
the Bradley Lake Hydroelectric Project,
Alaska’s largest hydro facility, which
generates 120 megawatts of low-cost
energy for more than 75 percent of
Alaska’s population, from Homer to
Explore available funding opportunities at https://www.akenergyauthority.org
Fairbanks. This facility contributes 10
percent of the Railbelt’s energy supply.
The Dixon Diversion Project, a $342
million initiative, will further expand
Bradley Lake’s capacity by redirecting
water from the Dixon Glacier to the
reservoir, significantly increasing
renewable energy generation and
benefiting the Railbelt transmission
system.
I want to thank Governor Dunleavy, the
Alaska Congressional Delegation, and
the Alaska State Legislature for their
steadfast support of energy initiatives
across the state. I also extend my
gratitude to the dedicated team at AEA,
whose commitment and hard work are
the driving force behind our progress.
The collaboration and partnership with
our Railbelt utilities and the Legislature
have been instrumental in advancing
these transformative projects. Together,
we are paving the way for a brighter,
more sustainable energy future for all
Alaskans.
Curtis W. Thayer
Executive Director
2024 AEA Annual Report | 7 6 | 2024 AEA Annual Report
Letter From the
Executive Director $92M AEA is investing $92 million to upgrade the Sterling to Quartz
Creek Transmission Line, increasing capacity, reducing losses,
improving reliability, and supporting renewables.
In the last five years, AEA has
secured nearly $1 billion in federal
and state grants and revenue bonds
— a 2,700 percent budget increase.
These funds are modernizing
the state’s energy infrastructure,
ensuring access to affordable,
sustainable power for all Alaskans.
Sterling to Quartz Creek Transmission Line Upgrades, Sterling, Alaska
$39M
The project will generate
$39 million in wages and
benefits, supporting workers
and local economies.
LABOR INCOME
$96M
With $96 million in total
economic output, local
businesses and investment
will see significant growth.
TOTAL ECONOMIC OUTPUT
460
The SQ Line project will create
460 jobs — 290 direct and 170
indirect — expanding Alaska’s
employment.
JOBS CREATED
Sterling to Quartz Creek Transmission Line
In December 2020, AEA acquired a critical section
of the interconnected transmission system on the
Kenai Peninsula, the Sterling Substation to Quartz
Creek (SQ) Substation Transmission Line. This
39.3-mile transmission corridor, originally built as
part of the Bradley Lake Project, plays a vital role
in delivering hydroelectric power from Bradley
Lake to Railbelt utilities. The line, previously
operating at 115 kilovolts (kV) and 69 kV, suffered
extensive damage during the 2019 Swan Lake
Fire, requiring four months and $12 million in
repairs before returning to service. In 2023, the
decommissioned 69 kV portion was removed.
Now benefiting from $92 million in upgrades, the
SQ line is undergoing a major overhaul to increase
its efficiency, reliability, and capacity. Construction
on the first phase near Kenai Lake began in late
2024 and will continue through various periods
until 2028. The upgrades include replacing
aging transmission towers and upgrading the
line’s capacity from 115 kV to 230 kV, allowing
it to handle more energy while reducing
transmission losses. Additionally, a new fiber optic
communication system will be installed, improving
equipment response times, enhancing grid safety,
and increasing overall system reliability.
These improvements will provide long-term
benefits for ratepayers by strengthening grid
resilience, improving energy efficiency, and
enabling future transmission expansion north
of Bradley Lake. By reducing energy losses and
integrating more renewable power into the
Railbelt system, the upgrades will also decrease
reliance on fossil fuels and contribute to a more
sustainable energy future. Additionally, replacing
the aging transmission structures — originally
built over 60 years ago — is a necessary step in
ensuring the long-term stability and reliability of
this critical piece of Alaska’s energy infrastructure.
Bradley Lake Hydroelectric Project
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 from Homer to Fairbanks. 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’s energy output
increased by 10 percent 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.
Dixon Diversion Project
AEA is studying the Dixon Diversion Project to optimize Bradley Lake’s energy potential.
Similar to the West Fork Upper Battle Creek Diversion Project, it would divert water from
Dixon Glacier, while also raising the Bradley Lake Dam to expand energy storage. Alaska’s
largest energy storage resource, Bradley Lake holds over 200,000 megawatt-hours. These
upgrades would boost annual energy production by 50 percent — enough to power up to
30,000 homes — and offset approximately 1.5 billion cubic feet of natural gas per year. An
offset of this magnitude is equal to about 7.5 percent of Alaska’s unmet natural gas demand
projected for 2030. AEA is preparing to file with the Federal Energy Regulatory Commission
this year and anticipates construction will begin soon, with completion targeted for 2030.
The Dixon Diversion Project would increase the energy production capacity of Bradley Lake by 50 percent and offset the equivalent of roughly 1.5 bcf/year of natural gas use.
2024 AEA Annual Report | 9 8 | 2024 AEA Annual Report
Owned Assets
Throughout the 1980s, AEA developed the state’s energy resources to
diversify Alaska’s economy and provide access to affordable energy.
AEA built and owns key Railbelt infrastructure — the Bradley Lake
Hydroelectric Project, the Sterling to Quartz Creek transmission line,
and the Alaska Intertie — which enhance grid redundancy and reduce
power costs for Railbelt consumers.
50%
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. It connects Golden Valley
Electric Association (GVEA), which serves areas
north of the Alaska Range, with Southcentral
Alaska utilities, enabling cost-effective energy
transmission and reserve capacity sharing
between Anchorage and Fairbanks. Funded by
$124 million in state appropriations with no debt
service, the Alaska Intertie helps deliver GVEA’s
share of Bradley Lake power while lowering
overall energy costs.
The Alaska Intertie is managed under the
Alaska Intertie Agreement, which includes AEA,
CEA, GVEA, and MEA. AEA plays a key role
in ensuring fair benefits to ratepayers across
the interconnected Railbelt region. Currently,
AEA is working with the Intertie Management
Committee (IMC) to upgrade communications
from Anchorage to Healy. Previously reliant on
shared microwave equipment with the Alaska
Department of Public Safety, the Alaska Intertie
will transition to a dedicated microwave system
by 2025. The IMC secured over $11 million in
Infrastructure Investment and Jobs Act funding
to reinforce structures in high snow-load areas
and enhance Railbelt data collection through
an interconnected Synchrophasor system.
Additionally, AEA and Railbelt utilities are
developing a Strategic Railbelt Transmission Plan
for 2050 and conducting engineering studies for
future transmission upgrades.
Alaska Intertie
Battery Energy
Storage Systems
2024 AEA Annual Report | 11 10 | 2024 AEA Annual Report
From 2008 to 2021, the Alaska Intertie saved GVEA customers an average of $30 million annually.
$30M
In 2022, AEA issued a $166 million bond to perform Required Project
Work for the Bradley Lake Hydroelectric Project. The majority of
these funds will be used to perform transmission line work, while the
remainder will be dedicated to Battery Energy Storage Systems (BESS).
Altogether, 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 30
years. AEA has reached agreements with Chugach Electric Association
(CEA), Matanuska Electric Association (MEA), and Homer Electric
Association to assist with BESS purchases, with negotiations underway
to finalize these agreements. Future plans include supporting Golden
Valley Electric Association in acquiring a new BESS for the northern
region of the Railbelt.
In total, AEA will invest over $28 million on BESS projects across the
Railbelt. These systems are critical to facilitating renewable power
integration as well as providing grid stability, peak load management,
emergency backup power, and ultimately cost savings for the
ratepayer.
Battery Energy Storage Systems
CEA and MEA BESS, Anchorage, Alaska
AEA was awarded the Grid Resilience
and Innovation Partnership (GRIP)
project on September 1, 2024, with
eight years to complete it. The GRIP
project specifically funds the Nikiski-
to-Beluga High-Voltage Direct Current
(HVDC) Submarine Transmission
Line, a transformative initiative to
enhance grid reliability in Alaska. The
initial contract value reflects available
state funding. The U.S. Department
of Energy (DOE) will issue change
orders as additional cost share funds
are secured. AEA has already secured
$206.5 million through DOE’s Grid
Deployment Office, requiring a 100
percent match for a total project value
of $413 million.
The Railbelt’s existing electrical
system is fragile, limiting resilience,
clean energy adoption, and fuel
diversification — hindering Alaska’s
transition to a carbon-free future. The
Nikiski-to-Beluga HVDC Submarine
Transmission Line is a transformative
project designed to enhance reliability
by creating a redundant power
pathway between Nikiski on the Kenai
Peninsula and Anchorage’s Beluga
substation.
To advance the project, AEA has
contracted an HVDC-experienced
consulting firm to develop an initial
project plan and schedule, conceptual
and preliminary cable designs, assess
critical environmental issues, and
provide a preliminary cost estimate.
AEA is also preparing to advertise
several positions to support the GRIP
project. While $62.7 million in state
matching funds have been secured, an
additional $143.8 million is needed.
This project would also benefit
Alaska’s rural communities. Lower
Railbelt energy costs translate to
reduced residential rates for remote
communities receiving Power Cost
Equalization funding, making energy
more affordable statewide.
High-Voltage Direct Current Submarine Transmission Line
House Bill 307, signed into law on July 31, 2024, established the Railbelt Transmission Organization (RTO) to
develop a non-discriminatory open access transmission tariff and fairly allocate backbone transmission costs.
RTO also replaces wheeling charges with a new mechanism that justly recovers and equitably allocates the
costs of operating the backbone system. As a division of AEA, it operates through a governance committee
with representatives from AEA, each Railbelt utility, and the Railbelt Reliability Council (ex officio, non-
voting). RTO applied for a certificate of public convenience and necessity with the Regulatory Commission of
Alaska on December 20, 2024, ahead of the January 1, 2025, deadline, and must file the tariff by July 1, 2025.
Railbelt Transmission Organization
1,470
The HVDC project will create
1,470 jobs — 950 direct and
520 indirect/induced —
boosting Alaska’s workforce.
JOBS CREATED
$129M
The project will generate
$129 million in wages and
benefits, supporting workers
and local economies.
LABOR INCOME
$332M
With $332 million in total
economic output, local
businesses and investment
will see significant growth.
TOTAL ECONOMIC OUTPUT
Haines, Alaska
Akhiok, Alaska
The Power Cost Equalization Program (PCE)
was established in 1984 to lower the cost of
electrical power incurred by rural residents and
community facilities to a level comparable to
that paid by residents of Alaska’s larger cities.
AEA administers this program, serving over
82,000 Alaskans in 188 communities that rely
primarily on diesel fuel.
The PCE program provides payments to eligible rural electric
utility companies, which then credit residential and community
facility customers up to a specified level of consumption. These
payments lower the unit cost of power for residential and
community customers.
In rural communities, pre-PCE electricity costs are often
significantly higher than urban rates. Residential and
community facility buildings in 188 communities see the
benefits of PCE credits. Based on utility filings, AEA calculates
and disburses monthly payments to eligible electric utilities.
AEA’s PCE team also provides 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 allows up to five percent of the fund’s
three-year monthly average market value to be appropriated
for PCE payments.
In recent years, the five percent draw on the endowment
fully funded PCE disbursements. In fiscal year 2018, statutory
changes determined how excess PCE Endowment Fund earnings
are allocated. These changes enabled endowment fund
earnings to fully cover PCE program administration costs and
contribute $30 million to the Community Assistance Program.
Additionally, up to $25 million could be allocated to AEA’s
Renewable Energy Fund, Rural Power System Upgrade projects,
and the Alaska Division of Community and Regional Affairs’
Bulk Fuel Revolving Loan Fund.
In fiscal year 2024, AEA disbursed $48 million in PCE payments to rural utilities — substantially more than in previous years. This increase is largely due to recent legislation that raised PCE payments from 500 to 750 kilowatt-hours to help reduce rural energy costs.
$48M
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 of 70 kWhs
per month multiplied by the
number of residents.
Power Cost
Equalization
2024 AEA Annual Report | 13 12 | 2024 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.
The BFU program upgrades or repairs fuel storage in communities under 2,000 people.
These facilities reduce per-unit fuel costs by enabling bulk purchases.
Upgrading bulk fuel facilities lowers energy costs by preventing leaks and reducing equipment failure risks.
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; however, 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 2024, AEA began preparing a new bulk
fuel facility site in Scammon Bay with eight
new tanks currently under construction, and
in Shageluk, river erosion necessitated an
emergency tank farm relocation. There are four
full BFU projects in various stages of design for
construction.
In recent years, AEA has switched its emphasis
from bulk fuel facility replacement to
Maintenance and Improvement (M&I) projects.
Currently, 12 M&I projects are planned or
underway, included in this work is dispenser
replacement, safety upgrades, electrical work,
coating and other high-return investments in
eligible community power systems.
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.
The RPSU program upgrades and builds facilities in communities under 2,000 people.
Powerhouse upgrades enhance
reliability with modern,
electronically controlled generators.
Diesel generation efficiency typically improves by 10–20%.
Alaska has approximately 400 bulk fuel facilities.
400
The average facility age exceeds 40 years, with many over 50.
40+
2024 AEA Annual Report | 15 14 | 2024 AEA Annual Report
AEA’s Rural Power Systems Upgrade (RPSU) program
enhances power generation in small, off-grid Alaska
villages. The Denali Commission is AEA’s major
federal funding partner, requiring a state match of
50 percent for non-distressed communities or 20
percent for distressed communities. In 2024, AEA
replaced the powerhouse in Napaskiak and has
begun overhauling powerhouses in Manokotak,
Nelson Lagoon, and Tuluksak. AEA is also designing a
new powerhouse in Chalkyitsik and upgrading to the
Kwethluk powerhouse. AEA manages Alaska’s federal
funding allocation from the Environmental Protection
Agency’s Diesel Emissions Reduction Act (DERA). AEA
identifies communities in need of new prime-power
diesel engines based on current engine conditions
and eligibility and utilizes DERA funds to furnish and
install new, efficient engines. This year, DERA-funded
engines were commissioned in Tenakee Springs and
Bettles, with up to five more communities set to
participate next year.
Rural Power Systems Upgrade
Bulk Fuel UpgradesNative Village of Wales, Alaska
AEA has shifted from full facility replacements to
operations and maintenance improvements that
maximize rural power systems’ benefits. Currently, it
is engaged in nine Maintenance and Improvement
(M&I) projects, including switchgear replacements,
heat recovery optimization, engine control upgrades,
and diesel genset replacements. In 2024, work
spanned engine replacements, power stabilization,
powerhouse leveling, and switchgear upgrades.
Native Village of Wales, Alaska
Chignik Lagoon, Alaska
The average bulk fuel facility contains 100,000 gallons.
100K
Nunapitchuk, Alaska
AEA’s Rural Training program equips
operators with the skills necessary to
maintain their energy infrastructure
and meet industry standards. In 2024,
44 operators from around the state
trained in Bulk Fuel, Person in Charge,
and Power Plant Operations at the
Alaska Vocational Technical Center.
Increasing the capacity of operators
to properly maintain infrastructure
and conduct regular preventative
maintenance is crucial in the efforts
to ensure greater efficiency and the
lifecycles of rural energy systems.
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 2024, Circuit
Riders assisted eligible utilities
over 300 times in providing remote
monitoring, training, and technical
consultation. On-site assistance and
minor repairs to power systems were
performed during 59 discrete visits to
rural 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. Two emergencies were
declared in 2024.
AEA is advancing inventory and assessment (I&A) of
rural Alaska’s energy infrastructure using cutting-edge
technology. The I&A process ranks bulk fuel, powerhouse,
and distribution systems by priority, with experts
evaluating the structures, equipment, and components.
Technical data is recorded, asset conditions are scored,
and findings are integrated into an AEA’s ArcGIS Energy
Data Hub with three-dimensional (3D) imaging from
drones and Light Detection and Ranging. This tool helps
address long-standing logistical challenges in rural Alaska,
supporting construction management, operator training,
and remote assistance. The 3D platform allows project
managers to track milestones and access real-time project
data, enhancing efficiency, decision-making, and cost
savings. AEA has created digital twins for 142 bulk fuel
facilities and 165 rural powerhouses statewide. In 2024, it
launched a multi-year distribution I&A effort, completing
imaging of 32 distribution systems so far. The platform’s
applications continue to grow, including Operation
and Maintenance Conversion projects where training
videos, manuals, and specifications are tagged directly to
infrastructure images for streamlined access.
Electrical Emergency AssistanceRural Training Circuit Rider and Technical Assistance
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 ensures the safe, reliable operation of rural Alaska’s power systems,
protecting multi-million dollar investments.
2024 AEA Annual Report | 17 16 | 2024 AEA Annual Report
Rural Training and Assistance
AEA’s Reality Capture Data Hub
Biomass
AEA’s biomass program reduces diesel
use, keeps fuel dollars local, and creates
jobs. It has funded over 20 woody biomass
heating systems for schools and public
buildings and provided technical support
for more than 50 systems. As co-lead of
the Alaska Wood Energy Development
Task Group with the United States
Department of Agriculture-Forest Service
(USDA-FS), AEA has helped fund over 170
feasibility studies for biomass projects. In
2024, AEA trained more than 20 cordwood
boiler operators and will expand to chip
boiler systems next year. It is also pursuing
USDA-FS grants to fund engineering
design for communities and to redesign
the Tok School’s woodchip combined
heat and power system, integrating solar
photovoltaic and battery storage for
energy security. Additionally, AEA and the
Alaska Department of Transportation and
Public Facilities leads the Alaska Biofuels
Advisory Group to advance Sustainable
Aviation Fuel and Renewable Diesel.
Electric Vehicles
AEA leads statewide electric vehicle (EV)
infrastructure deployment, collaborating
with local agencies, utilities, and
communities to reduce adoption barriers
while ensuring responsible use of federal
and state resources. The Alaska Electric
Vehicle Working Group unites utilities,
EV owners, vendors, and municipalities,
meeting quarterly, hosting technical
sessions, and sharing updates via listserv.
To develop a fast-charging network,
AEA works with Alaska Department of
Transportation and Public Facilities to plan
for National Electric Vehicle Infrastructure
Program funding along Alaska’s
Alternative Fuel Corridor from Anchorage
to Fairbanks, with expansion to additional
highways, smaller urban areas, and
ferry-connected locations. Beyond the
major road, the Alaska Rural EV Supply
Equipment Deployment project, backed
by the U.S. Department of Energy, will
install EV chargers in rural communities
and create workforce opportunities.
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 number in Alaska. These systems
range from small residential systems
to utility-scale plants. Round 16 of the
Renewable Energy Fund (REF) has funded
the construction of two solar PV projects
in rural Alaska, in Igiugig and Ruby. REF
Round 16 has also funded a solar PV
project on the Railbelt, a 45-megawatt solar
farm being designed by Solstice Energy
on the shores of Puppy Dog Lake near
Nikiski. In 2024, AEA was awarded a $62.5
million grant from the U.S. Environmental
Protection Agency’s (EPA) Greenhouse
Gas Reduction Fund Solar for All Program.
The Alaska Solar for All (AKSFA) Program
is in partnership with the Alaska Housing
Financing Corpoation, and will provide
funding and technical assistance for solar
PV systems for residents of low-income and
underserved communities in Alaska. A work
plan for AKSFA has been submitted to the
EPA and the program is expected to launch
in 2025.
Chuniisax Creek Hydroelectric Project, Atka, Alaska
Wind
Wind energy now makes up two percent
of Alaska’s annual electric generation,
a significant growth over the past
decade. AEA continues to advance wind
development through Renewable Energy
Fund grants, supporting projects from
microgrids up to utility-scale wind farms
along the Railbelt. AEA also fosters
industry collaboration by hosting the
Alaska Wind Working Group and the
semi-annual Alaska Wind Workshop.
Ongoing Railbelt feasibility studies
include Murphy Dome (Fairbanks), Little
Mount Susitna (Beluga), Homer, and
multiple Matanuska Electric Association
sites. State support is especially vital for
wind-diesel hybrid systems in remote
communities, where reducing reliance
cuts costs and boosts energy resilience. As
Alaska’s energy office, AEA also explores
cold-climate performance improvements
and battery energy storage with grid-
forming inverters to stabilize microgrids. *2023 Renewable Energy Fund: Impact and Evaluation Report
2024 AEA Annual Report | 19 18 | 2024 AEA Annual Report
About 33 percent of Alaska’s electricity generation came from renewable energy in 2022.*
33%
Renewable Energy and
Energy Efficiency
AEA’s renewable energy programs drive Alaska’s clean energy economy, partnering with local governments, non-profits, and tribal organizations to implement new solutions. They also offer technical assistance, funding, and training to expand knowledge of cost-saving energy technologies.
Hydroelectric power fueled 29 percent.*
29%
Over 65 wood heating systems have been installed in the state.*
65
Unalaska, Alaska
Home Energy Rebates
Optimizing energy use reduces costs and demand while offering practical solutions for
every Alaska community. AEA’s end-use energy efficiency programs target commercial,
public, and industrial end-use energy, as well as electrical systems. In partnership with
organizations like the Alaska Housing Finance Corporation (AHFC), AEA also supports
residential energy efficiency through technical assistance, outreach, education, and
funding across the state.
Power Pledge ChallengeAlaska Energy Efficiency Partnership
Energy Efficiency and Conservation
AEA continues to lead the Alaska
Energy Efficiency Partnership
(AEEP), a coalition of over 50
public, private, and nonprofit
organizations working to make
Alaska the most energy-efficient
state in the nation. In 2024,
quarterly meetings provided
a platform for members to
exchange insights on energy
efficiency, conservation efforts,
funding opportunities, and project
updates. Through collaboration
and integrated planning, AEEP
promotes informed decision-
making and advances energy
efficiency across Alaska.
Since 2013, AEA has partnered with
AK EnergySmart to promote energy
literacy through the Power Pledge
Challenge (PPC). Now in its twelfth
year, PPC engages K-12 students
across Alaska in energy efficiency
and conservation. From August
through November, classrooms
participate in challenges like the
AK EnergySmart lessons, school
energy audits, community energy
profiles, and creating energy-saving
public service announcements. In
2024, PPC reached 2,000 students
in 22 schools across seven regions
of the state.
Sections 50121 and 50122 of the
Inflation Reduction Act established
the Home Efficiency Rebates
and the Home Electrification and
Appliance Rebates. For these
rebates to be carried out, the
U.S. Department of Energy was
authorized to make a combined
total of $74,444,011 in formula
funds available to the state. As the
state energy office, AEA will partner
with the AHFC to design and
administer a Home Energy Rebates
program. Once implemented, it will
support energy-efficient retrofits
and high-efficiency electric projects
and appliances for single and
multifamily homes across Alaska.
Renewable Energy – Village Energy Efficiency Program
AEA’s Renewable Energy-Village Energy Efficiency Program (RE-VEEP) is an expansion on the Village Energy Efficiency Program (VEEP),
established in 2010 to reduce per capita consumption through energy efficiency. After two rounds of solicitation, a total of $1.5 million
will be sub-awarded to nine RE-VEEP projects that support building-scale renewable energy, energy efficiency, and conservation in public
buildings and facilities across Alaska. Through these types of projects, communities will reduce their energy consumption and costs.
2024 AEA Annual Report | 21 20 | 2024 AEA Annual Report
City of Chignik – Round 1: Funds will support an
energy audit, implement recommended efficiency
upgrades, and install a solar system on the Chignik
Community Hall roof.
City of Kachemak – Round 2: With an audit already
completed, funds will go toward energy efficiency
retrofits and an 8.8 kilovolt solar photovoltaic (PV)
system for the City of Kachemak Center roof.
Lake and Peninsula Borough – Round 2: Funding
will cover an energy audit, efficiency retrofits, and
a 10-kW solar PV system for the borough office in
King Salmon.
City of Nenana – Round 2: Funds will be split
between two sub-awards — one for efficiency
upgrades at the Civic Center and community
education on energy conservation, and another
for integrating the Biomass Heat Plant with the
Recreation Hall’s in-floor heating, alongside
efficiency improvements and additional educational
materials.
City of Seldovia – Round 2: Funding will support
efficiency retrofits at the Seldovia City Office/Public
Works Maintenance Shop.
City of Unalaska – Round 1 and 2: Funds will cover
an energy audit of the Pyramid Water Treatment
Plant, upgrades to the Icy Lake solar/battery system,
and replacing fluorescent T8 lighting with LED
fixtures across city facilities.
City of Whittier – Round 1: Funding will support
an energy audit and lighting efficiency retrofits
throughout Whittier’s public spaces.
RE-VEEP AWARDED PROJECTS
AEA plays a vital role in advancing Alaska’s
energy sector by administering multiple
funding programs and actively monitoring
new opportunities. AEA works closely with
the U.S. Department of Energy (DOE) and
tracks funding through Tribal and Indian
Energy loan programs to maximize resources
for Alaskans. Through strong partnerships
with U.S. DOE and National Laboratories,
AEA ensures communities benefit from
the latest funding and innovative energy
solutions.
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 helps drive energy cost savings, facilitates technology
transfers across Alaska, and leverages federal and local funding.
An independent analysis of REF examined its economic,
community, and environmental impacts. The study found that
the REF has significantly contributed to Alaska’s renewable
energy sector by offsetting approximately 85 million gallons
of diesel fuel, reducing over one million metric tons of carbon
dioxide, and returning $2.07 in benefits to residents and the
economy for every dollar invested since its inception.
To date, REF has funded 294 grants for renewable energy
projects statewide, resulting in over 110 operating projects.
In fiscal year 2024, AEA solicited applications for Round
16 of REF funding. The Renewable Energy Fund Advisory
Committee (REFAC), a nine-member committee, five of whom
are appointed by the Governor, that provides policy guidance
and funding recommendations to AEA, offered valuable input
in its consideration and review of 24 recommended projects
submitted to the Legislature for funding consideration. As
a result, in June 2024, the Legislature appropriated and the
Governor approved $10.5 million for REF Round 16 — more than
double the initial $5 million proposal. Since its inception in 2008,
the State has appropriated $327 million to REF.
House Bill 307, signed into law in July 2024,
amended Alaska Statute 42.45.010, allowing
AEA’s PPF to offer lower interest rates and
extended terms on loans for renewable energy
projects with at least $5 million in state funding.
In November 2024, AEA’s Board of Directors
approved regulatory changes to implement
these updates, improving access to low-cost
financing through significantly reduced interest
rates and extended loan terms for major power
projects generating power via renewable
energy resources. These changes allow for an
applicant to apply at a pre-determined reduced
interest rate — or three percent below the
statutory rate, but no lower than one percent —
without needing to provide justification. These
enhancements align with recommendations
from the Governor’s Alaska Energy Security Task
Force. By reducing financing costs, the changes
improve project economics and allow savings to
be passed on to ratepayers through lower energy
costs.
AEA Seeks Lower Interest Rates for Power Projects
2024 AEA Annual Report | 23 22 | 2024 AEA Annual Report
Power Project Fund
AEA administers the Power Project Fund (PPF), offering low-
interest loans to qualified applicants, including local utilities,
governments, and independent power producers. PPF provides
affordable financing for developing, expanding, and upgrading
electric power facilities, including distribution, transmission,
efficiency improvements, bulk fuel storage, and waste energy
projects. Loans cover all project phases, from feasibility studies
to construction, with terms based on a project’s useful life.
Interest rates are tied to the 30-year taxable municipal bond
yield index, currently 5.40 percent as of February 2025.
In 2024, House Bill 307 aligned PPF statutes with
recommendations from the Governor’s Alaska Energy Security
Task Force, allowing improved loan terms for certain projects.
PPF remains a key tool in Alaska’s energy development,
supporting a range of technologies, including upgrades to
diesel-fired powerhouses critical for rural energy reliability.
As of December 31, 2024, AEA’s loan portfolio stands at $30.8
million, supporting 15 loans across multiple energy regions
statewide. Through the PPF program, AEA has financed Alaska-
based independent power producers and contributed to the
development of the state’s two largest and most recent solar
farms in the Matanuska-Susitna Valley. Together, these solar
projects generate enough clean energy to power approximately
1,600 homes, improving air quality while preserving Cook Inlet’s
natural gas reserves. Additionally, the PPF program provided $20
million in financing for the Hiilangaay Hydroelectric Project, the
largest rural hydroelectric facility in Southeast Alaska, located
on Prince of Wales Island. This project has played a key role in
enabling the island’s interconnected communities to achieve
nearly 100 percent renewable power. Beyond reducing emissions
and improving air quality, it also supports the long-term
conservation of Cook Inlet’s natural gas resources, reinforcing
the state’s commitment to diversifying Alaska’s energy supply.
85M
REF has displaced approximately 85 million
gallons of diesel and 2.2 million cubic feet of
natural gas since its inception.
Hiilangaay Hydroelectric Project, Prince of Wales, AlaskaGrants and
loans
Phase 2 Whistle Hill Solar Project, Soldotna, Alaska Photo by Peninsula Solar
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, 2024 June 30, 2023
Operating expenses:
Grants and projects 36,772 26,163
Power cost equalization grants 44,931 42,332
Plant operating 8,677 9,746
General and administrative 6,887 6,707
Provision for loan recovery – –
Depreciation 12,076 11,698
State of Alaska appropriations and transfers ––
Other project expense ––
Total operating expense 109,343 96,646
Operating loss (41,090) (34,170)
Investment income (loss), net 81,018 94,280
Interest expense (10,400) (6,653)
State of Alaska reappropriations and transfers – (45,000)
Capital contributions ––
Loss on disposal of asset –(400)
Increase (decrease) in net position 29,528*8,057**
* *
NOTES REGARDING INCREASE (DECREASE) IN NET POSITION
*Net position increased primarily due to decreased distributions from PCE Endowment Fund during the year amounting to
$22.2 million. Other contributing factor is the increase in additional funding from appropriations in Renewable Energy Fund
by $3.0 million, and the $5.0 million increase in investment income from the Bradley Lake Hydroelectric Project.
**Net position increased primarily due to unrealized investment gains in the PCE Endowment Fund of ($5,900) and from the
Bradley Lake bond issuance of ($2,500). Other contributing factors was an overall decrease of ($326) from reduced revenues
of the Trans-Alaska Pipeline Liability Fund.
STATEMENTS OF NET POSITION June 30, 2024 June 30, 2023
Assets:
Restricted Investment securities and cash 1,281,491 1,226,790
Loans, net 30,832 26,459
Capital assets, net 369,244 375,794
Receivables and other assets 53,916 8,068
Total assets 1,735,438 1,637,111
Liabilities and net position:
Liabilities
Bonds payable 201,253 204,032
Other bond liabilities – –
Payables and other liabilities 122,768 51,145
Total liabilities 324,021 255,177
Net Position 1,411,462 1,381,934
Total liabilities and net position 1,735,438 1,637,111
REVENUES, EXPENSES, AND CHANGES IN NET POSITION June 30, 2024 June 30, 2023
Operating revenues:
Federal grants 12,298 10,179
Revenue from operating plants 25,802 27,461
State operating and capital revenues 23,881 23,704
Interest on loans 391 280
Other operating revenues 5,881 852
Total operating revenues 68,253 62,476
2024 AEA Annual Report | 25 24 | 2024 AEA Annual Report
FY2024 Financial Highlights
CURTIS W. THAYER Executive Director TIM SANDSTROM
Chief Operating Officer
2024 AEA Annual Report | 27 26 | 2024 AEA Annual Report
LEONARD ROBERTSON
Information Technology Officer
KAREN TURNER
Human Resources Director
CLAY KOPLIN
Chair, Board Member
ADAM CRUM
Commissioner, Alaska
Department of Revenue
DUFF MITCHELL
Vice Chair, Board Member
JULIE SANDE
Commissioner, Alaska Department
of Commerce, Community, and
Economic Development
TONY IZZO
Board Member
JENN MILLER
Board Member
INGEMAR MATHIASSON
Board Member
AUDREY ALSTROM, PE
Director of Renewable Energy
and Energy Efficiency Programs
CONNER ERICKSON
Director of Planning
Board of Directors Executive Team
ROBERT SIEDMAN
Board Member
MARK BILLINGSLEY, JD
General Counsel
BRYAN CAREY, PE
Director of Owned Assets
BRANDY M. DIXON
Communications Director
Alaska Energy Authority 813 W Northern Lights Blvd. Anchorage, AK 99503 Phone: (907) 771-3000 Fax: (907) 771-3300 E-mail: info@akenergyauthority.org
www.akenergyauthority.org @alaskaenergyauthority @alaskaenergyauthority
POWER COST
EQUALIZATION
PROGRAM
STATISTICAL REPORT
FY2024
Safe,Reliable, andAffordableEnergySolutions
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
March 1, 2025
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, 2024.
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 82,000 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.
During the fiscal year 2024, endowment earnings allowed for PCE payments at one-hundred percent resulting in approximately $45.2 million in program disbursements.
This report may be found on the AEA website at www.akenergyauthority.org/pce. Additional
copies may be obtained by emailing PCE@akenergyauthority.org.
Regards,
Curtis W. Thayer Executive Director
Attachment: FY 2024 Power Cost Equalization Annual Report
POWER COST EQUALIZATION PROGRAM
Statistical Data by Community
Reporting Period: 07/01/23 - 06/30/24
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; Klukwan ............................................................................................................................................... 40
Chistochina ...................................................................................................................................................................... 41
Chitina ............................................................................................................................................................................... 42
Chuathbaluk .................................................................................................................................................................... 43
POWER COST EQUALIZATION PROGRAM
Statistical Data by Community
Reporting Period: 07/01/23 - 06/30/24
TABLE OF CONTENTS
Circle .................................................................................................................................................................................. 44
Clark's Point ..................................................................................................................................................................... 45
Coffman Cove ................................................................................................................................................................. 46
Cold Bay ............................................................................................................................................................................ 47
Cordova ............................................................................................................................................................................ 48
Craig ................................................................................................................................................................................... 49
Crooked Creek ................................................................................................................................................................ 50
Deering.............................................................................................................................................................................. 51
Dillingham; Aleknagik .................................................................................................................................................. 52
Diomede ........................................................................................................................................................................... 53
Dot Lake; Dot Lake Village ......................................................................................................................................... 54
Eagle; Eagle Village ....................................................................................................................................................... 55
Eek....................................................................................................................................................................................... 56
Egegik ................................................................................................................................................................................ 57
Ekwok ................................................................................................................................................................................. 58
Elfin Cove .......................................................................................................................................................................... 59
Elim ..................................................................................................................................................................................... 60
Emmonak ......................................................................................................................................................................... 61
False Pass ......................................................................................................................................................................... 62
Fort Yukon........................................................................................................................................................................ 63
Galena ................................................................................................................................................................................ 64
Gambell ............................................................................................................................................................................. 65
Golovin .............................................................................................................................................................................. 66
Goodnews Bay ................................................................................................................................................................ 67
Grayling ............................................................................................................................................................................. 68
Gustavus ........................................................................................................................................................................... 69
Haines; Covenant Life .................................................................................................................................................. 70
Healy Lake ........................................................................................................................................................................ 71
Hollis .................................................................................................................................................................................. 72
Holy Cross ........................................................................................................................................................................ 73
Hoonah ............................................................................................................................................................................. 74
Hooper Bay ...................................................................................................................................................................... 75
Hughes .............................................................................................................................................................................. 76
Huslia ................................................................................................................................................................................. 77
Hydaburg ......................................................................................................................................................................... 78
Igiugig ............................................................................................................................................................................... 79
Iliamna; Newhalen; Nondalton................................................................................................................................. 80
Kake .................................................................................................................................................................................... 81
POWER COST EQUALIZATION PROGRAM
Statistical Data by Community
Reporting Period: 07/01/23 - 06/30/24
TABLE OF CONTENTS
Kaktovik ............................................................................................................................................................................ 82
Kaltag ................................................................................................................................................................................. 83
Karluk ................................................................................................................................................................................. 84
Kasigluk ............................................................................................................................................................................. 85
Kiana .................................................................................................................................................................................. 86
Kipnuk ................................................................................................................................................................................ 87
Kivalina .............................................................................................................................................................................. 88
Klawock ............................................................................................................................................................................. 89
Kobuk ................................................................................................................................................................................. 90
Kokhanok ......................................................................................................................................................................... 91
Koliganek .......................................................................................................................................................................... 92
Kongiganak...................................................................................................................................................................... 93
Kotlik .................................................................................................................................................................................. 94
Kotzebue .......................................................................................................................................................................... 95
Koyuk ................................................................................................................................................................................. 96
Koyukuk ............................................................................................................................................................................ 97
Kwethluk ........................................................................................................................................................................... 98
Kwigillingok ..................................................................................................................................................................... 99
Levelock ......................................................................................................................................................................... 100
Lime Village .................................................................................................................................................................. 101
Lower Kalskag .............................................................................................................................................................. 102
Manley Hot Springs ................................................................................................................................................... 103
Manokotak .................................................................................................................................................................... 104
Marshall ......................................................................................................................................................................... 105
McGrath ......................................................................................................................................................................... 106
Mekoryuk ...................................................................................................................................................................... 107
Mentasta ........................................................................................................................................................................ 108
Minto .............................................................................................................................................................................. 109
Mt. Village ..................................................................................................................................................................... 110
Naknek;S.Naknek;Kng Slmn ................................................................................................................................... 111
Napakiak ........................................................................................................................................................................ 112
Napaskiak ...................................................................................................................................................................... 113
Naukati ........................................................................................................................................................................... 114
Nelson Lagoon ............................................................................................................................................................ 115
New Stuyahok ............................................................................................................................................................. 116
Newtok; Mertavik ....................................................................................................................................................... 117
POWER COST EQUALIZATION PROGRAM
Statistical Data by Community
Reporting Period: 07/01/23 - 06/30/24
TABLE OF CONTENTS
Nightmute ..................................................................................................................................................................... 118
Nikolai ............................................................................................................................................................................ 119
Nikolski ........................................................................................................................................................................... 120
Noatak ............................................................................................................................................................................ 121
Nome .............................................................................................................................................................................. 122
Noorvik........................................................................................................................................................................... 123
Northway; Northway Village .................................................................................................................................. 124
Nuiqsut ........................................................................................................................................................................... 125
Nulato ............................................................................................................................................................................. 126
Nunam Iqua.................................................................................................................................................................. 127
Nunapitchuk ................................................................................................................................................................. 128
Old Harbor .................................................................................................................................................................... 129
Ouzinkie ......................................................................................................................................................................... 130
Pedro Bay ...................................................................................................................................................................... 131
Pelican ............................................................................................................................................................................ 132
Pilot Point ...................................................................................................................................................................... 133
Pilot Station .................................................................................................................................................................. 134
Pitkas Point ................................................................................................................................................................... 135
Point Hope .................................................................................................................................................................... 136
Point Lay ........................................................................................................................................................................ 137
Port Alsworth ............................................................................................................................................................... 138
Port Heiden .................................................................................................................................................................. 139
Quinhagak..................................................................................................................................................................... 140
Rampart ......................................................................................................................................................................... 141
Red Devil ....................................................................................................................................................................... 142
Ruby ................................................................................................................................................................................ 143
Russian Mission........................................................................................................................................................... 144
Sand Point ..................................................................................................................................................................... 145
Savoonga ....................................................................................................................................................................... 146
Scammon Bay .............................................................................................................................................................. 147
Selawik............................................................................................................................................................................ 148
Shageluk ........................................................................................................................................................................ 149
Shaktoolik ..................................................................................................................................................................... 150
Shishmaref .................................................................................................................................................................... 151
Shungnak ...................................................................................................................................................................... 152
Skagway ......................................................................................................................................................................... 153
Slana ................................................................................................................................................................................ 154
POWER COST EQUALIZATION PROGRAM
Statistical Data by Community
Reporting Period: 07/01/23 - 06/30/24
TABLE OF CONTENTS
Sleetmute ...................................................................................................................................................................... 155
St. George ..................................................................................................................................................................... 156
St. Mary's; Andreafsky .............................................................................................................................................. 157
St. Michael..................................................................................................................................................................... 158
St. Paul ............................................................................................................................................................................ 159
Stebbins ......................................................................................................................................................................... 160
Stony River .................................................................................................................................................................... 161
Takotna .......................................................................................................................................................................... 162
Tanana ............................................................................................................................................................................ 163
Tatitlek ............................................................................................................................................................................ 164
Teller................................................................................................................................................................................ 165
Tenakee Springs ......................................................................................................................................................... 166
Tetlin ............................................................................................................................................................................... 167
Thorne Bay; Kasaan ................................................................................................................................................... 168
Togiak ............................................................................................................................................................................. 169
Tok; Tanacross ............................................................................................................................................................. 170
Toksook Bay ................................................................................................................................................................. 171
Tuluksak ......................................................................................................................................................................... 172
Tuntutuliak .................................................................................................................................................................... 173
Tununak ......................................................................................................................................................................... 174
Twin Hills ....................................................................................................................................................................... 175
Unalakleet ..................................................................................................................................................................... 176
Unalaska ........................................................................................................................................................................ 177
Upper Kalskag ............................................................................................................................................................. 178
Venetie ........................................................................................................................................................................... 179
Wainwright ................................................................................................................................................................... 180
Wales .............................................................................................................................................................................. 181
Whale Pass .................................................................................................................................................................... 182
White Mountain .......................................................................................................................................................... 183
Yakutat ........................................................................................................................................................................... 184
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 $19.56 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
19.35 cents/kWh, “the base rate”
and $1.00/kWh, “the ceiling”.
Costs below 19.35 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 76.62 cents/kWh.
($1.00 – 19.35 cents = 80.65 cents x 95% = 76.62 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 184
FISCAL YEAR
2023
See (8)
FISCAL YEAR
2024
% Change
2023-2024%
See (5)PARTICIPATION STATISTICS
Population Served 81,996 80,809 -1.4%
Communities Served 188 188 0.0%
Participating Utilities 82 82 0.0%
Total Residential Customers (2)28,128 27,947 -0.6%
Total Community Facility Customers (2)1,973 1,936 -1.9%
Total Customer (Residential & Community Facilities) (1) (2)30,101 29,883 -0.7%
PRODUCTION STATISTICS
Total Diesel Generation (kWh)395,945,976 404,380,274 2.1%
Total "Other" (Hydro/Wind/Solar/Natural Gas) Generation (kWh)54,144,326 61,016,685 12.7%
Total Purchased Power (kWh)59,191,285 61,331,131 3.6%
Total kWh Sold (All Customers) (7)460,821,110 471,747,634 2.4%
PCE Eligible Residential kWh 113,679,601 114,240,275 0.5%
PCE Eligible Community kWh 35,646,628 36,594,143 2.7%
Total PCE Eligible - Community Facilities & Residential 149,326,229 150,834,418 1.0%
Total PCE Eligible kWh Shown as Percent of Total kWh Sold 32.4%32.0%-1.3%
Average Monthly PCE Eligible kWh - Residential Customers (3)337 341 1.1%
Average Monthly PCE Eligible kWh - Community Facilities (3)1,506 1,575 4.6%
Average Monthly PCE Eligible kWh - Community Facilities / Per Resident (3)36 38 4.2%
FINANCIAL STATISTICS
Average Price of Fuel Oil ($/gallon)4.0234 4.2254 5.0%
Total Fuel Oil Consumed (gallons)27,248,271 28,702,505 5.3%
Total Cost of Fuel Oil Purchased by the Utilities ($)109,631,453 121,279,866 10.6%
Total Non-Fuel Expenses ($) (5)108,780,039 102,931,381 -5.4%
Non-Fuel Expenses per Total kWh Sold ($) (5)0.2361 0.2182 -7.6%
Total Operating Costs per kWh ($) Sold (4)0.4740 0.4753 0.3%
PCE Legislative Funding Appropriations for Utility Payments 47,694,800 47,694,800 0.0%
Total Monthly Reports/PCE Reimbursements to Utilities Processed (6)41,584,697 45,218,683 8.7%
POWER COST EQUALIZATION PROGRAM STATISTICS
(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 FY24 and FY23 PCE payments were made at a 100% level for all 12 months
(7) Value reduced by $824,060 in FY24 and $906,508 in FY23 to eliminate double counting of kWh's
(8) Data restated. Changes from prior published data due to updated data after report production.
9 of 1859 of 184
2015*2016*2017*2018*2019*2020*2021*2022*2023*2024
PARTICIPATION
Participating Utilities 86 88 89 89 88 86 86 83 82 82
Communities Served 190 191 194 194 193 191 191 188 188 188
Population Served 81,969 82,986 83,850 83,400 81,997 81,694 81,160 79,808 81,996 80,809
PCE ELIGIBLE CUSTOMERS
Residential 27,893 28,035 27,857 28,365 28,338 28,158 27,923 27,961 28,128 27,947
Community Facilities 1,850 2,056 2,067 2,090 2,069 1,984 1,969 1,939 1,973 1,936
Total PCE Eligible Customers 29,743 30,091 29,924 30,455 30,407 30,142 29,892 29,900 30,101 29,883
FUNDING
Appropriations for Utility Payments($)$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 $47,694,800
Disbursements to Utilities ($)$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 $45,218,683
Disbursements/Customer ($)$1,257 $1,032 $872 $860 $933 $962 $790 $915 $1,382 $1,513
Funding Level 100%100%100%100%100%100%100%100%100%100%
CONSUMPTION
Total MWh Sold (MWh)450,232 446,735 462,081 458,092 453,598 455,730 440,607 460,572 460,821 471,748
PCE Eligible MWh Residential 96,453 94,816 97,751 96,597 95,606 96,544 97,510 97,417 113,680 114,240
Avg. PCE Eligible kWh/Month/Residential Customer 288 282 292 284 281 286 291 290 337 341
PCE Eligible MWh Community Facilities 32,795 34,357 35,747 34,929 34,191 34,946 34,554 35,544 35,647 36,594
Elig. kWh/Month/Capita, Community Facilities 33.3 34.5 35.5 34.9 34.7 35.6 35.5 37.1 36.2 37.7
Total PCE Eligible MWh 129,248 129,173 133,498 131,526 129,797 131,490 132,063 132,961 149,326 150,834
Eligible kWh/Month/Cust, Total Customers 362 358 372 360 356 364 368 371 413 421
COSTS
Average Price of Fuel Oil ($/gallon)$3.97 $3.24 $2.66 $2.67 $3.06 $3.07 $2.63 $3.02 $4.02 $4.23
Total Gallons of Fuel Oil Consumed 27,191,149 26,865,206 28,838,704 28,446,814 28,425,146 28,199,707 27,783,263 28,682,394 27,248,271 28,702,505
Total Cost of Fuel Oil ($)$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 $121,279,866
Total Non-Fuel Costs ($)$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 $102,931,381
FINANCIAL RATIOS
Non-Fuel Costs Per Total kWh Sold $0.1689 $0.1857 $0.1843 $0.2010 $0.1892 $0.1928 $0.1852 $0.2041 $0.2361 $0.2182
Total Operating Costs Per Total kWh Sold $0.4084 $0.3807 $0.3504 $0.3670 $0.3810 $0.3829 $0.3511 $0.3922 $0.4740 $0.4753
RATES
Avg. PCE per Eligible kWh Res. & Comm Facility ($/kWh)$0.2892 $0.2403 $0.1955 $0.1991 $0.2185 $0.2206 $0.1789 $0.2058 $0.2785 $0.2998
Weighted Avg. Residential Rate (Before PCE Paid)$0.4915 $0.4541 $0.4270 $0.4378 $0.4628 $0.4633 $0.4412 $0.4674 $0.5528 $0.5640
Weighted Avg. Residential PCE Rate (Amount PCE pays)$0.2919 $0.2432 $0.1983 $0.2010 $0.2191 $0.2226 $0.1821 $0.2101 $0.2776 $0.3012
Weighted Avg. Residential Effective Rate (1)$0.1996 $0.2108 $0.2288 $0.2368 $0.2437 $0.2407 $0.2591 $0.2572 $0.2752 $0.2628
*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 2015 - 2024
10 of 184
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
FY24 PCE Program Participating Utilities
11 of 184
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 184
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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
STATISTICAL REPORT
of the
POWER COST EQUALIZATION
PROGRAM
Fiscal Year 2024
July 1, 2023 - June 30, 2024
36th Edition
March 2025
State of Alaska Michael J. Dunleavy, Governor
Alaska Energy Authority
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
March 1, 2025
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, 2024.
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 82,000 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.
During the fiscal year 2024, endowment earnings allowed for PCE payments at one-hundred percent resulting in approximately $45.2 million in program disbursements.
This report may be found on the AEA website at www.akenergyauthority.org/pce. Additional
copies may be obtained by emailing PCE@akenergyauthority.org.
Regards,
Curtis W. Thayer Executive Director
Attachment: FY 2024 Power Cost Equalization Annual Report
TABLE OF CONTENTS
Map of Participating Utilities/Communities ....................................4
List of Participating Utilities/Communities .....................................5
Program Highlights ........................................................................6
Fiscal Year 2023 vs. 2024 .............................................................7
Fiscal Year 2024 Statistics ...................................................... 8-27
Historical Trends, Fiscal Years 2014 - 2024 .............................. 28
The Alaska Energy Authority (AEA) complies with Title II of the Americans with Disabilities Act of 1990. This publication is available
in alternative communications formats upon request. Please contact the Authority at (907) 771-3000 to make any necessary
arrangements.
Data for the Power Cost Equalization Annual Statistics is primarily based on information submitted by the utility. Changes to the
reported data and/or significant anomalies have been noted in the notes column.
Data for prior fiscal years does not include data collected after the publication of the PCE Statistical Report for that fiscal year. 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 75 copies of this report in Anchorage, Alaska for $6.70
per copy. Design and production by AEA. Printed by Service Business Printing
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 4 of 28
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
FY24 PCE Program Participating Utilities
5 of 28
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
19.35 cents/kWh, “the base rate”
and $1.00/kWh, “the ceiling”.
Costs below 19.35 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 76.62 cents/kWh.
($1.00 – 19.35 cents = 80.65 cents x 95% = 76.62 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.
6 of 28
FISCAL YEAR
2023
See (8)
FISCAL YEAR
2024
% Change
2023-2024%
See (5)PARTICIPATION STATISTICS
Population Served 81,996 80,809 -1.4%
Communities Served 188 188 0.0%
Participating Utilities 82 82 0.0%
Total Residential Customers (2)28,128 27,947 -0.6%
Total Community Facility Customers (2)1,973 1,936 -1.9%
Total Customer (Residential & Community Facilities) (1) (2)30,101 29,883 -0.7%
PRODUCTION STATISTICS
Total Diesel Generation (kWh)395,945,976 404,380,274 2.1%
Total "Other" (Hydro/Wind/Solar/Natural Gas) Generation (kWh)54,144,326 61,016,685 12.7%
Total Purchased Power (kWh)59,191,285 61,331,131 3.6%
Total kWh Sold (All Customers) (7)460,821,110 471,747,634 2.4%
PCE Eligible Residential kWh 113,679,601 114,240,275 0.5%
PCE Eligible Community kWh 35,646,628 36,594,143 2.7%
Total PCE Eligible - Community Facilities & Residential 149,326,229 150,834,418 1.0%
Total PCE Eligible kWh Shown as Percent of Total kWh Sold 32.4%32.0%-1.3%
Average Monthly PCE Eligible kWh - Residential Customers (3)337 341 1.1%
Average Monthly PCE Eligible kWh - Community Facilities (3)1,506 1,575 4.6%
Average Monthly PCE Eligible kWh - Community Facilities / Per Resident (3)36 38 4.2%
FINANCIAL STATISTICS
Average Price of Fuel Oil ($/gallon)4.0234 4.2254 5.0%
Total Fuel Oil Consumed (gallons)27,248,271 28,702,505 5.3%
Total Cost of Fuel Oil Purchased by the Utilities ($)109,631,453 121,279,866 10.6%
Total Non-Fuel Expenses ($) (5)108,780,039 102,931,381 -5.4%
Non-Fuel Expenses per Total kWh Sold ($) (5)0.2361 0.2182 -7.6%
Total Operating Costs per kWh ($) Sold (4)0.4740 0.4753 0.3%
PCE Legislative Funding Appropriations for Utility Payments 47,694,800 47,694,800 0.0%
Total Monthly Reports/PCE Reimbursements to Utilities Processed (6)41,584,697 45,218,683 8.7%
POWER COST EQUALIZATION PROGRAM STATISTICS
(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 FY24 and FY23 PCE payments were made at a 100% level for all 12 months
(7)Value reduced by $824,060 in FY24 and $906,508 in FY23 to eliminate double counting of kWh's
(8) Data restated. Changes from prior published data due to updated data after report production.
7 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
NOTES *** = Calculations cannot be made due to lack of data or other circumstances
Column a: Residential rates as reported by the utility in fiscal year 2024.
Column b: Rates based upon RCA Letter order in effect for last report filed in fiscal year 2024.
PCE rate reflects 100% funding level.
Column References:a b c d e f g h i j k
a - b i + j
Utility/Community
Last
Reported
Residential
Rate (based
on 500 kWh)
Last PCE
Rate Applied
Last
Effective
Residential
Rate
Population Reporting
Periods
Last
Reported
Number of
Residential
Customers
Last
Reported
Number of
Community
Facility
Customers
Last
Reported
Number of
Other
Customers
(Non-PCE)
PCE Eligible
kWh
Residential
PCE Eligible
kWh
Community
Facilities
PCE Eligible
kWh
Total
AKHIOK/KAGUYAK ELECTRIC
Akhiok PCE $ 0.8000 $ 0.3266 $ 0.4734 65 11 29 1 16 86,530 41,756 128,286
Utility Company Total 65 29 1 16 86,530 41,756 128,286
AKIACHAK NATIVE COMMUNITY
Akiachak PCE $ 0.7300 $ 0.3053 $ 0.4247 667 12 204 12 52 809,874 109,370 919,244
Utility Company Total 667 204 12 52 809,874 109,370 919,244
AKIAK CITY COUNCIL
Akiak PCE $ 0.6300 $ 0.3365 $ 0.2935 480 4 97 14 33 177,233 20,598 197,831
Utility Company Total 480 97 14 33 177,233 20,598 197,831
CITY OF AKUTAN
Akutan PCE $ 0.9500 $ 0.7508 $ 0.1992 1,584 12 40 11 29 201,038 139,559 340,597
Utility Company Total 1,584 40 11 29 201,038 139,559 340,597
ALASKA POWER & TELEPHONE
Allakaket; Alatna PCE $ 1.1127 $ 0.7325 $ 0.3802 180 12 78 16 17 242,497 141,820 384,317
Bettles; Evansville PCE $ 0.8501 $ 0.4830 $ 0.3671 34 12 31 8 27 62,967 28,476 91,443
Chistochina PCE $ 0.7797 $ 0.4161 $ 0.3636 56 12 50 2 19 145,324 28,328 173,652
Coffman Cove PCE $ 0.3445 $ 0.0705 $ 0.2740 201 12 198 14 58 727,883 91,115 818,998
Craig PCE $ 0.3445 $ 0.0705 $ 0.2740 992 12 658 36 356 2,945,498 833,280 3,778,778
Dot Lake; Dot Lake Village PCE $ 0.3985 $ 0.1929 $ 0.2056 48 12 27 6 14 74,406 40,320 114,726
Eagle; Eagle Village PCE $ 0.9613 $ 0.5886 $ 0.3727 124 12 142 10 32 283,791 71,044 354,835
Gustavus PCE $ 0.4243 $ 0.0758 $ 0.3485 657 12 503 4 125 1,269,806 33,816 1,303,622
Haines; Covenant Life PCE $ 0.3226 $ 0.0542 $ 0.2684 2,649 12 1,208 34 377 4,510,242 1,118,539 5,628,781
Healy Lake PCE $ 0.8236 $ 0.4578 $ 0.3658 22 12 7 3 2 14,040 18,480 32,520
Hollis PCE $ 0.3445 $ 0.0705 $ 0.2740 139 12 136 0 33 559,373 0 559,373
Hydaburg PCE $ 0.3445 $ 0.0705 $ 0.2740 347 12 115 7 60 542,680 147,144 689,824
Klawock PCE $ 0.3445 $ 0.0705 $ 0.2740 694 12 402 20 163 1,920,974 577,555 2,498,529
Mentasta PCE $ 0.7797 $ 0.4161 $ 0.3636 118 12 58 7 15 162,442 53,231 215,673
Naukati PCE $ 0.3445 $ 0.0705 $ 0.2740 131 12 89 0 22 348,953 0 348,953
Northway; Northway Village PCE $ 0.7331 $ 0.3718 $ 0.3613 223 12 91 10 35 303,420 87,338 390,758
Skagway PCE $ 0.3226 $ 0.0542 $ 0.2684 1,146 12 636 30 685 2,266,378 764,870 3,031,248
Slana PCE $ 0.7797 $ 0.4161 $ 0.3636 93 12 69 0 18 243,480 1,060 244,540
Tetlin PCE $ 0.3985 $ 0.1929 $ 0.2056 140 12 55 5 11 179,042 71,493 250,535
8 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
Columns f - h: Values extracted from utilities' most recent fiscal year 2024 monthly report
Column p: Alaska Village Electric Cooperative average price of fuel is per reported actual fuel cost divided by gallons used;
all others are per prices used to determine PCE level
Columns i, j, m: Values summed from fiscal year 2024 utility reports
l m n o p q r s t
o / n
PCE
Payments
Made
Total kWh
Sold
Diesel Fuel
Gallons
Used
Diesel Fuel
Cost
Average
Price of Fuel
per Gallon
Non Fuel
Expenses
Total
kWh
Generated
Diesel Total
kWh
Generated
Non Diesel
Total
kWh
Purchased
Total
Notes Utility/Community
AKHIOK/KAGUYAK ELECTRIC
$ 41,898 246,991 24,840 $ 84,719 $ 3.41 33,000 295,009 0 0 Rptd Fuel Used & Powerhouse
Consumption = 10mths Akhiok PCE
$ 41,898 246,991 24,840 $ 84,719 $ 3.41 33,000 295,009 0 0
AKIACHAK NATIVE COMMUNITY
$ 297,231 1,980,017 171,735 $ 707,848 $ 4.12 593,080 2,165,918 0 0 Akiachak PCE
$ 297,231 1,980,017 171,735 $ 707,848 $ 4.12 593,080 2,165,918 0 0
AKIAK CITY COUNCIL
$ 64,627 1,253,994 45,576 $ 217,508 $ 4.77 69,059 1,257,455 0 0 4 Rpts submitted No PHouse
Consumption Rptd Akiak PCE
$ 64,627 1,253,994 45,576 $ 217,508 $ 4.77 69,059 1,257,455 0 0
CITY OF AKUTAN
$ 257,037 539,849 56,061 $ 245,625 $ 4.38 457,130 600,027 103,758 0 Akutan PCE
$ 257,037 539,849 56,061 $ 245,625 $ 4.38 457,130 600,027 103,758 0
ALASKA POWER & TELEPHONE
$ 290,997 660,008 57,901 $ 427,469 $ 7.38 202,028 749,141 0 0 Allakaket; Alatna PCE
$ 51,771 371,250 36,501 $ 156,677 $ 4.29 172,578 427,500 0 0 Bettles; Evansville PCE
$ 70,295 377,775 0 $ 0 0 0 0 0
See Slana for power
generation. Non-Fuel
expenses included w/Craig
Chistochina PCE
$ 69,622 1,372,014 0 $ 0 0 0 0 0
See Craig for power
generation and non-fuel
expenses
Coffman Cove PCE
$ 321,674 13,846,526 298,243 $ 1,023,239 $ 3.43 3,776,786 4,208,399 0 35,340,967
Provides power to Coffman
Cove, Hollis, Hydaburg,
Klawock, Thorne Bay/Kassan
Craig PCE
$ 36,034 394,289 0 $ 0 0 0 0 0 See Tok for Power Generation
and non-fuel expenses Dot Lake; Dot Lake Village PCE
$ 188,372 709,520 64,661 $ 267,303 $ 4.13 320,167 825,932 21,105 0 Eagle; Eagle Village PCE
$ 62,036 3,341,840 29,247 $ 155,755 $ 5.33 940,365 406,156 3,480,245 0 Gustavus PCE
$ 247,043 13,626,725 21,832 $ 79,041 $ 3.62 1,738,984 293,449 0 14,460,054
Sells power to Chilkat Valley.
Diesel Gen & Fuel Used = 10
mths
Haines; Covenant Life PCE
$ 19,598 92,894 11,382 $ 45,219 $ 3.97 62,349 102,239 0 0 Healy Lake PCE
$ 47,772 4,873,707 0 $ 0 0 0 0 0
See Craig for power
generation and Non-Fuel
Expenses
Hollis PCE
$ 59,093 1,470,541 0 $ 0 0 0 0 0
See Craig for power
generation and Non-Fuel
Expenses Reported
Hydaburg PCE
$ 213,303 8,426,426 0 $ 0 0 0 0 0
See Craig for power
generation and Non-Fuel
Expenses
Klawock PCE
$ 87,570 480,253 0 $ 0 0 0 0 0
See Craig for power
generation and Non-Fuel
Expenses
Mentasta PCE
$ 29,621 663,433 0 $ 0 49,041 0 0 0 See Craig for power
generation Naukati PCE
$ 169,668 1,029,143 86,794 $ 296,273 $ 3.41 183,094 1,124,800 0 0 Northway; Northway Village PCE
$ 133,465 13,447,474 154,838 $ 566,383 $ 3.66 1,882,291 2,162,691 2,136,560 9,972,330 Skagway PCE
$ 100,899 465,746 111,135 $ 374,190 $ 3.37 264,735 1,481,772 0 0 Provides power to Chistochina
& Mentasta Slana PCE
$ 77,965 421,704 0 $ 0 0 0 0 0 See Tok for power generation Tetlin PCE
9 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
NOTES *** = Calculations cannot be made due to lack of data or other circumstances
Column a: Residential rates as reported by the utility in fiscal year 2024.
Column b: Rates based upon RCA Letter order in effect for last report filed in fiscal year 2024.
PCE rate reflects 100% funding level.
Column References:a b c d e f g h i j k
a - b i + j
Utility/Community
Last
Reported
Residential
Rate (based
on 500 kWh)
Last PCE
Rate Applied
Last
Effective
Residential
Rate
Population Reporting
Periods
Last
Reported
Number of
Residential
Customers
Last
Reported
Number of
Community
Facility
Customers
Last
Reported
Number of
Other
Customers
(Non-PCE)
PCE Eligible
kWh
Residential
PCE Eligible
kWh
Community
Facilities
PCE Eligible
kWh
Total
Thorne Bay; Kasaan PCE $ 0.3445 $ 0.0705 $ 0.2740 498 12 324 26 166 1,331,549 334,703 1,666,252
Tok; Tanacross PCE $ 0.3985 $ 0.1929 $ 0.2056 1,465 12 813 34 201 3,555,971 680,021 4,235,992
Whale Pass PCE $ 0.3445 $ 0.0705 $ 0.2740 84 12 86 2 19 265,310 10,727 276,037
Utility Company Total 10,041 5,776 274 2,455 21,956,026 5,133,360 27,089,386
ALASKA VILLAGE ELECTRIC COOP
Alakanuk PCE $ 0.7984 $ 0.4725 $ 0.3259 728 12 152 9 39 757,279 347,938 1,105,217
Ambler PCE $ 0.9543 $ 0.6313 $ 0.3230 256 12 74 12 22 413,309 134,642 547,951
Anvik PCE $ 0.7985 $ 0.4833 $ 0.3152 58 12 36 9 22 118,805 40,810 159,615
Bethel; Oscarville PCE $ 0.4981 $ 0.1776 $ 0.3205 6,221 12 1,649 50 1,124 8,957,933 2,718,937 11,676,870
Brevig Mission PCE $ 0.7840 $ 0.4695 $ 0.3145 437 12 87 8 33 527,237 173,421 700,658
Chevak PCE $ 0.7170 $ 0.3806 $ 0.3364 940 12 200 9 42 1,052,857 331,482 1,384,339
Eek PCE $ 0.7734 $ 0.4594 $ 0.3140 404 12 109 5 36 587,365 34,511 621,876
Ekwok PCE $ 0.8102 $ 0.4944 $ 0.3158 97 12 42 8 25 211,890 18,270 230,160
Elim PCE $ 0.8266 $ 0.5100 $ 0.3166 354 12 90 10 38 500,668 131,013 631,681
Emmonak PCE $ 0.7984 $ 0.4725 $ 0.3259 855 12 199 20 68 1,109,810 624,215 1,734,025
Gambell PCE $ 0.8336 $ 0.5002 $ 0.3334 629 12 163 14 34 864,695 246,738 1,111,433
Goodnews Bay PCE $ 0.7215 $ 0.4101 $ 0.3114 238 12 78 9 16 431,212 107,671 538,883
Grayling PCE $ 0.7449 $ 0.4323 $ 0.3126 186 12 62 9 31 276,068 103,874 379,942
Holy Cross PCE $ 0.7097 $ 0.3989 $ 0.3108 159 12 67 10 21 287,963 91,806 379,769
Hooper Bay PCE $ 0.7056 $ 0.3746 $ 0.3310 1,359 12 252 5 68 1,287,754 351,271 1,639,025
Huslia PCE $ 0.6640 $ 0.3555 $ 0.3085 313 12 105 14 35 558,543 169,593 728,136
Kaltag PCE $ 0.7301 $ 0.4183 $ 0.3118 146 12 69 10 20 255,909 94,048 349,957
Kasigluk PCE $ 0.7915 $ 0.4568 $ 0.3347 652 12 110 11 27 685,389 207,777 893,166
Kiana PCE $ 0.8014 $ 0.4860 $ 0.3154 413 12 110 13 31 615,347 252,064 867,411
Kivalina PCE $ 0.7859 $ 0.4713 $ 0.3146 426 12 87 7 32 497,991 122,917 620,908
Kobuk PCE $ 1.0945 $ 0.7645 $ 0.3300 169 12 31 3 17 177,544 99,352 276,896
Kotlik PCE $ 0.7898 $ 0.4750 $ 0.3148 613 12 121 8 37 694,579 176,581 871,160
Koyuk PCE $ 0.8428 $ 0.5254 $ 0.3174 312 12 83 9 36 455,254 157,328 612,582
Lower Kalskag PCE $ 0.8340 $ 0.5170 $ 0.3170 270 12 71 6 13 360,833 75,206 436,039
Marshall PCE $ 0.7025 $ 0.3921 $ 0.3104 479 12 106 18 31 581,533 225,991 807,524
Mekoryuk PCE $ 0.7666 $ 0.4446 $ 0.3220 192 12 85 9 33 312,232 108,401 420,633
Minto PCE $ 0.6935 $ 0.3835 $ 0.3100 171 12 74 6 27 324,677 142,590 467,267
Mt. Village PCE $ 0.6612 $ 0.2961 $ 0.3651 598 12 161 15 52 763,628 301,607 1,065,235
New Stuyahok PCE $ 0.8102 $ 0.4944 $ 0.3158 461 12 100 9 39 568,433 124,176 692,609
Nightmute PCE $ 0.7499 $ 0.4239 $ 0.3260 291 12 51 5 22 265,404 52,885 318,289
Noatak PCE $ 1.2431 $ 0.7662 $ 0.4769 540 12 115 7 30 744,364 219,488 963,852
Noorvik PCE $ 0.8091 $ 0.4933 $ 0.3158 659 12 128 10 39 799,057 423,891 1,222,948
Nulato PCE $ 0.7121 $ 0.4012 $ 0.3109 219 12 108 14 29 487,735 184,237 671,972
Nunapitchuk PCE $ 0.7915 $ 0.4568 $ 0.3347 525 12 118 9 29 658,342 80,032 738,374
Old Harbor PCE $ 0.6939 $ 0.3839 $ 0.3100 200 12 81 12 34 315,692 159,921 475,613
Pilot Station PCE $ 0.6930 $ 0.3830 $ 0.3100 627 12 126 10 31 660,935 236,357 897,292
Pitkas Point PCE $ 0.6612 $ 0.2961 $ 0.3651 121 12 25 6 6 124,088 90,555 214,643
Quinhagak PCE $ 0.6890 $ 0.3451 $ 0.3439 762 12 181 13 31 1,019,577 332,526 1,352,103
Russian Mission PCE $ 0.7124 $ 0.4015 $ 0.3109 407 12 79 6 15 390,584 69,029 459,613
Savoonga PCE $ 0.8004 $ 0.4849 $ 0.3155 833 12 162 9 55 894,328 261,967 1,156,295
Scammon Bay PCE $ 0.7909 $ 0.4760 $ 0.3149 615 12 129 8 46 684,315 196,778 881,093
10 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
Columns f - h: Values extracted from utilities' most recent fiscal year 2024 monthly report
Column p: Alaska Village Electric Cooperative average price of fuel is per reported actual fuel cost divided by gallons used;
all others are per prices used to determine PCE level
Columns i, j, m: Values summed from fiscal year 2024 utility reports
l m n o p q r s t
o / n
PCE
Payments
Made
Total kWh
Sold
Diesel Fuel
Gallons
Used
Diesel Fuel
Cost
Average
Price of Fuel
per Gallon
Non Fuel
Expenses
Total
kWh
Generated
Diesel Total
kWh
Generated
Non Diesel
Total
kWh
Purchased
Total
Notes Utility/Community
$ 142,668 3,578,897 0 $ 0 0 0 0 0
See Craig for power
generation and Non-Fuel
Expenses
Thorne Bay; Kasaan PCE
$ 1,309,889 9,742,721 804,346 $ 2,639,736 $ 3.28 2,397,743 11,631,311 0 0 Provides power to Dot
Lake/Dot Lake Village & Tetlin Tok; Tanacross PCE
$ 23,325 463,373 47,886 $ 168,688 $ 3.52 71,772 539,357 0 0 Whale Pass PCE
$ 3,752,680 79,856,259 1,724,766 $ 6,199,973 $ 3.59 12,061,933 23,952,747 5,637,910 59,773,351
ALASKA VILLAGE ELECTRIC COOP
$ 454,053 2,003,473 0 $ 0 500,650 0 0 0 Alakanuk PCE
$ 327,040 1,129,180 105,584 $ 654,312 $ 6.20 282,172 1,293,299 0 0 Ambler PCE
$ 75,728 319,554 32,910 $ 131,628 $ 4.00 79,854 365,349 0 0 Anvik PCE
$ 2,350,306 42,126,618 3,060,973 $ 13,996,770 $ 4.57 10,527,075 43,453,912 1,816,305 0 Bethel; Oscarville PCE
$ 255,217 1,299,747 103,684 $ 484,516 $ 4.67 324,795 1,417,367 0 0 Brevig Mission PCE
$ 533,623 2,501,727 159,316 $ 662,625 $ 4.16 625,160 2,134,529 685,508 0 Chevak PCE
$ 283,014 1,221,335 97,549 $ 424,074 $ 4.35 305,201 1,283,436 0 0 Eek PCE
$ 108,489 460,487 0 $ 0 115,072 0 0 0 Ekwok PCE
$ 300,425 1,248,992 101,721 $ 522,291 $ 5.13 312,112 1,319,208 0 0 Elim PCE
$ 705,466 3,499,704 390,475 $ 1,934,769 $ 4.95 874,546 5,384,844 576,406 0 Emmonak PCE
$ 504,382 2,282,673 179,671 $ 880,813 $ 4.90 570,420 2,416,859 237 0 Gambell PCE
$ 208,959 849,672 65,475 $ 291,025 $ 4.44 212,326 896,639 0 0 Goodnews Bay PCE
$ 171,701 613,905 57,342 $ 242,612 $ 4.23 153,410 701,726 0 0 Grayling PCE
$ 156,230 634,391 51,097 $ 215,546 $ 4.22 158,529 662,749 0 0 Holy Cross PCE
$ 565,981 3,411,295 224,247 $ 1,149,883 $ 5.13 852,453 3,220,561 417,900 0 Hooper Bay PCE
$ 262,739 1,198,029 92,693 $ 379,724 $ 4.10 299,377 1,257,921 0 0 Huslia PCE
$ 141,238 616,592 52,582 $ 205,080 $ 3.90 154,081 674,490 5,389 0 Kaltag PCE
$ 354,145 1,318,018 203,263 $ 951,996 $ 4.68 329,361 2,753,823 288,042 0 Kasigluk PCE
$ 406,055 1,698,815 132,904 $ 684,787 $ 5.15 424,519 1,815,817 0 0 Kiana PCE
$ 275,944 1,493,656 117,894 $ 650,789 $ 5.52 373,252 1,586,375 0 0 Kivalina PCE
$ 210,840 590,766 0 $ 0 147,627 0 0 0 Kobuk PCE
$ 401,112 1,898,815 168,130 $ 766,886 $ 4.56 474,497 2,059,222 0 0 Kotlik PCE
$ 285,093 1,270,592 101,439 $ 512,595 $ 5.05 317,510 1,352,681 0 0 Koyuk PCE
$ 199,223 621,804 0 $ 0 155,383 0 0 0 Lower Kalskag PCE
$ 309,303 1,606,684 118,333 $ 552,138 $ 4.67 401,496 1,695,813 0 0 Marshall PCE
$ 180,531 829,135 64,187 $ 302,913 $ 4.72 207,194 891,952 30,860 0 Mekoryuk PCE
$ 172,347 956,044 85,429 $ 256,924 $ 3.01 238,907 1,008,784 0 0 Minto PCE
$ 302,652 2,499,714 0 $ 624,657 624,657 0 0 0 Mt. Village PCE
$ 325,022 1,360,872 149,826 $ 692,210 $ 4.62 340,070 1,954,250 0 0 New Stuyahok PCE
$ 125,974 818,408 0 $ 0 204,513 0 0 0 Nightmute PCE
$ 738,503 1,915,740 144,703 $ 1,077,378 $ 7.45 478,727 1,938,919 132,826 0 Noatak PCE
$ 550,105 2,034,472 161,463 $ 855,792 $ 5.30 508,397 2,237,086 4,598 0 Noorvik PCE
$ 283,475 1,125,764 95,786 $ 357,463 $ 3.73 281,319 1,197,239 0 0 Nulato PCE
$ 293,522 1,335,958 0 $ 0 333,844 0 0 0 Nunapitchuk PCE
$ 188,828 789,804 59,348 $ 239,544 $ 4.04 197,365 873,988 0 0 Old Harbor PCE
$ 351,804 1,870,145 151,736 $ 524,502 $ 3.46 467,333 1,942,063 0 0 Pilot Station PCE
$ 60,937 324,459 0 $ 0 81,079 0 0 0 Pitkas Point PCE
$ 461,925 2,257,682 125,213 $ 596,612 $ 4.76 564,175 1,845,930 678,680 0 Quinhagak PCE
$ 185,560 923,072 75,124 $ 282,125 $ 3.76 230,668 979,833 0 0 Russian Mission PCE
$ 514,626 2,268,150 180,088 $ 939,865 $ 5.22 566,791 2,383,667 85 0 Savoonga PCE
$ 396,091 1,734,933 138,340 $ 632,923 $ 4.58 433,545 1,843,321 0 0 Scammon Bay PCE
11 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
NOTES *** = Calculations cannot be made due to lack of data or other circumstances
Column a: Residential rates as reported by the utility in fiscal year 2024.
Column b: Rates based upon RCA Letter order in effect for last report filed in fiscal year 2024.
PCE rate reflects 100% funding level.
Column References:a b c d e f g h i j k
a - b i + j
Utility/Community
Last
Reported
Residential
Rate (based
on 500 kWh)
Last PCE
Rate Applied
Last
Effective
Residential
Rate
Population Reporting
Periods
Last
Reported
Number of
Residential
Customers
Last
Reported
Number of
Community
Facility
Customers
Last
Reported
Number of
Other
Customers
(Non-PCE)
PCE Eligible
kWh
Residential
PCE Eligible
kWh
Community
Facilities
PCE Eligible
kWh
Total
Selawik PCE $ 0.7704 $ 0.4566 $ 0.3138 757 12 155 13 46 951,686 450,012 1,401,698
Shageluk PCE $ 0.6655 $ 0.3569 $ 0.3086 91 12 40 8 13 167,779 70,068 237,847
Shaktoolik PCE $ 0.7231 $ 0.3964 $ 0.3267 234 12 66 4 36 417,077 73,692 490,769
Shishmaref PCE $ 0.7280 $ 0.4163 $ 0.3117 590 12 150 9 47 745,798 113,310 859,108
Shungnak PCE $ 1.0945 $ 0.7645 $ 0.3300 251 12 59 8 24 323,833 160,066 483,899
St. Mary's PCE $ 0.6612 $ 0.2961 $ 0.3651 585 12 170 17 65 813,430 452,922 1,266,352
St. Michael PCE $ 0.7239 $ 0.4124 $ 0.3115 446 12 87 9 46 487,816 301,233 789,049
Stebbins PCE $ 0.7239 $ 0.4124 $ 0.3115 629 12 142 10 49 727,171 118,764 845,935
Teller PCE $ 0.8129 $ 0.4969 $ 0.3160 234 12 70 7 36 288,907 37,731 326,638
Togiak PCE $ 0.7192 $ 0.4079 $ 0.3113 770 12 204 18 82 1,028,840 242,184 1,271,024
Toksook Bay PCE $ 0.7499 $ 0.4239 $ 0.3260 638 12 134 13 39 780,183 311,887 1,092,070
Tununak PCE $ 0.7499 $ 0.4239 $ 0.3260 393 12 94 7 25 424,800 35,276 460,076
Twin Hills PCE $ 0.7192 $ 0.4079 $ 0.3113 93 10 33 5 9 217,228 74,984 292,212
Upper Kalskag PCE $ 0.8340 $ 0.5170 $ 0.3170 205 12 59 3 27 276,860 30,786 307,646
Wales PCE $ 0.8340 $ 0.5132 $ 0.3208 113 12 28 4 37 147,839 39,314 187,153
Yakutat PCE $ 0.6268 $ 0.3586 $ 0.2682 673 12 278 25 191 1,154,636 371,622 1,526,258
Utility Company Total 30,637 7,645 594 3,188 40,235,041 12,905,747 53,140,788
ANIAK LIGHT & POWER
Aniak PCE $ 0.9445 $ 0.6350 $ 0.3095 486 12 180 15 53 711,150 89,323 800,473
Utility Company Total 486 180 15 53 711,150 89,323 800,473
ARCTIC VILLAGE COUNCIL
Arctic Village PCE $ 1.0000 $ 0.7662 $ 0.2338 137 12 95 6 20 305,562 103,623 409,185
Utility Company Total 137 95 6 20 305,562 103,623 409,185
CITY OF ATKA
Atka PCE $ 0.6250 $ 0.3329 $ 0.2921 61 7 31 18 15 62,817 23,246 86,063
Utility Company Total 61 31 18 15 62,817 23,246 86,063
ATMAUTLUAK TRIBAL UTILITIES
Atmautluak PCE $ 0.6600 $ 0.4665 $ 0.1935 363 12 77 8 16 411,561 89,606 501,167
Utility Company Total 363 77 8 16 411,561 89,606 501,167
CITY OF BUCKLAND
Buckland PCE $ 0.5000 $ 0.3065 $ 0.1935 580 12 104 15 27 687,254 88,914 776,168
Utility Company Total 580 104 15 27 687,254 88,914 776,168
NATIVE VILLAGE OF CHENEGA
Chenega Bay PCE $ 1.1200 $ 0.7662 $ 0.3538 59 12 21 11 23 63,173 45,579 108,752
Utility Company Total 59 21 11 23 63,173 45,579 108,752
CITY OF CHIGNIK
Chignik PCE $ 0.6390 $ 0.3862 $ 0.2528 80 12 42 14 47 107,622 67,200 174,822
Utility Company Total 80 42 14 47 107,622 67,200 174,822
12 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
Columns f - h: Values extracted from utilities' most recent fiscal year 2024 monthly report
Column p: Alaska Village Electric Cooperative average price of fuel is per reported actual fuel cost divided by gallons used;
all others are per prices used to determine PCE level
Columns i, j, m: Values summed from fiscal year 2024 utility reports
l m n o p q r s t
o / n
PCE
Payments
Made
Total kWh
Sold
Diesel Fuel
Gallons
Used
Diesel Fuel
Cost
Average
Price of Fuel
per Gallon
Non Fuel
Expenses
Total
kWh
Generated
Diesel Total
kWh
Generated
Non Diesel
Total
kWh
Purchased
Total
Notes Utility/Community
$ 588,876 2,692,236 214,659 $ 1,024,970 $ 4.77 672,766 2,868,102 0 0 Selawik PCE
$ 87,558 508,760 40,957 $ 163,255 $ 3.99 127,135 558,567 0 0 Shageluk PCE
$ 187,031 1,023,793 64,871 $ 331,008 $ 5.10 255,837 826,769 316,533 0 Shaktoolik PCE
$ 361,289 1,785,957 135,509 $ 717,948 $ 5.30 446,295 1,849,151 0 0 Shishmaref PCE
$ 368,569 873,394 112,210 $ 1,378,752 $ 12.29 218,254 1,457,566 176,245 0 Shungnak PCE
$ 358,670 2,751,400 299,072 $ 1,121,131 $ 3.75 687,551 3,938,341 2,838,285 0 St. Mary's PCE
$ 308,564 1,837,303 0 $ 0 459,126 0 0 0 St. Michael PCE
$ 338,992 1,593,772 195,631 $ 859,937 $ 4.40 398,270 2,936,054 778,090 0 Stebbins PCE
$ 151,454 770,502 62,424 $ 322,505 $ 5.17 192,542 840,844 0 0 Teller PCE
$ 479,492 2,805,140 221,097 $ 983,383 $ 4.45 700,980 3,206,753 0 0 Togiak PCE
$ 424,989 1,801,873 252,963 $ 1,207,514 $ 4.77 450,272 3,650,321 588,655 0 Toksook Bay PCE
$ 182,257 1,017,262 0 $ 0 254,205 0 0 0 Tununak PCE
$ 106,225 252,841 0 $ 0 63,183 0 0 0 Twin Hills PCE
$ 139,201 746,929 108,744 $ 536,032 $ 4.93 186,651 1,505,898 0 0 Upper Kalskag PCE
$ 90,588 946,281 81,845 $ 392,887 $ 4.80 236,467 1,024,356 0 0 Wales PCE
$ 543,583 5,567,417 428,069 $ 1,678,580 $ 3.92 1,391,249 6,248,136 0 0 Yakutat PCE
$ 19,695,546 125,935,736 9,266,576 $ 44,395,669 $ 4.79 31,470,245 127,754,510 9,334,644 0
ANIAK LIGHT & POWER
$ 507,684 1,961,461 188,912 $ 920,641 $ 4.87 632,019 2,420,100 0 0 Aniak PCE
$ 507,684 1,961,461 188,912 $ 920,641 $ 4.87 632,019 2,420,100 0 0
ARCTIC VILLAGE COUNCIL
$ 313,423 1,014,469 0 $ 0 36,000 1,014,469 0 0
1 rpt filed covers 3 mths. No
Diesel Gen, Fuel Used, PHouse
Consump
Arctic Village PCE
$ 313,423 1,014,469 0 $ 0 NaN 36,000 1,014,469 0 0
CITY OF ATKA
$ 28,650 213,581 10,619 $ 54,934 $ 5.17 18,200 143,018 135,000 0 7 Reports received Atka PCE
$ 28,650 213,581 10,619 $ 54,934 $ 5.17 18,200 143,018 135,000 0
ATMAUTLUAK TRIBAL UTILITIES
$ 233,640 822,950 67,501 $ 362,089 $ 5.36 216,546 856,315 97,821 0 Atmautluak PCE
$ 233,640 822,950 67,501 $ 362,089 $ 5.36 216,546 856,315 97,821 0
CITY OF BUCKLAND
$ 228,852 1,810,852 83,446 $ 441,775 $ 5.29 279,543 943,846 95,821 0
Diesel Gen/Fuel Used = 6 mths
PHouse = 7 Non-Fuel
Expenses = 8 mths
Buckland PCE
$ 228,852 1,810,852 83,446 $ 441,775 $ 5.29 279,543 943,846 95,821 0
NATIVE VILLAGE OF CHENEGA
$ 83,294 224,080 23,823 $ 140,686 $ 5.91 37,847 269,997 0 0 Chenega Bay PCE
$ 83,294 224,080 23,823 $ 140,686 $ 5.91 37,847 269,997 0 0
CITY OF CHIGNIK
$ 42,361 593,459 45,676 $ 163,953 $ 3.59 114,826 639,214 0 0 Chignik PCE
$ 42,361 593,459 45,676 $ 163,953 $ 3.59 114,826 639,214 0 0
13 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
NOTES *** = Calculations cannot be made due to lack of data or other circumstances
Column a: Residential rates as reported by the utility in fiscal year 2024.
Column b: Rates based upon RCA Letter order in effect for last report filed in fiscal year 2024.
PCE rate reflects 100% funding level.
Column References:a b c d e f g h i j k
a - b i + j
Utility/Community
Last
Reported
Residential
Rate (based
on 500 kWh)
Last PCE
Rate Applied
Last
Effective
Residential
Rate
Population Reporting
Periods
Last
Reported
Number of
Residential
Customers
Last
Reported
Number of
Community
Facility
Customers
Last
Reported
Number of
Other
Customers
(Non-PCE)
PCE Eligible
kWh
Residential
PCE Eligible
kWh
Community
Facilities
PCE Eligible
kWh
Total
CHIGNIK LAGOON POWER UTILITY
Chignik Lagoon PCE $ 0.8051 $ 0.6059 $ 0.1992 75 12 67 7 15 180,357 51,532 231,889
Utility Company Total 75 67 7 15 180,357 51,532 231,889
CHIGNIK LAKE ELECTRIC UTILITY
Chignik Lake PCE $ 0.7000 $ 0.4377 $ 0.2623 61 11 42 8 5 98,197 39,775 137,972
Utility Company Total 61 42 8 5 98,197 39,775 137,972
CHITINA ELECTRIC INC.
Chitina PCE $ 1.0034 $ 0.7608 $ 0.2426 97 12 50 3 36 97,416 24,325 121,741
Utility Company Total 97 50 3 36 97,416 24,325 121,741
CIRCLE ELECTRIC LLC
Circle PCE $ 0.8844 $ 0.6051 $ 0.2793 91 12 43 7 12 101,804 62,735 164,539
Utility Company Total 91 43 7 12 101,804 62,735 164,539
CLARKS POINT VILLAGE COUNCIL
Clark's Point PCE $ 0.9332 $ 0.7397 $ 0.1935 64 11 51 5 15 118,949 13,648 132,597
Utility Company Total 64 51 5 15 118,949 13,648 132,597
CORDOVA ELECTRIC
Cordova PCE: Eyak PCE $ 0.4113 $ 0.0973 $ 0.3140 2,698 12 997 49 570 3,811,672 2,185,158 5,996,830
Utility Company Total 2,698 997 49 570 3,811,672 2,185,158 5,996,830
DIOMEDE JOINT UTLITIES
Diomede PCE $ 0.9300 $ 0.3700 $ 0.5600 82 12 34 2 13 93,080 17,244 110,324
Utility Company Total 82 34 2 13 93,080 17,244 110,324
CITY OF EGEGIK
Egegik PCE $ 0.6500 $ 0.4508 $ 0.1992 30 12 88 20 28 150,602 25,200 175,802
Utility Company Total 30 88 20 28 150,602 25,200 175,802
ELFIN COVE UTILITY COMMISSION
Elfin Cove PCE $ 0.7700 $ 0.4323 $ 0.3377 38 12 36 6 40 46,062 11,611 57,673
Utility Company Total 38 36 6 40 46,062 11,611 57,673
CITY OF FALSE PASS
False Pass PCE $ 0.7190 $ 0.4810 $ 0.2380 395 12 30 11 19 70,630 81,241 151,871
Utility Company Total 395 30 11 19 70,630 81,241 151,871
G & K INC.
Cold Bay PCE $ 1.2002 $ 0.7608 $ 0.4394 56 12 44 4 76 67,523 43,598 111,121
Utility Company Total 56 44 4 76 67,523 43,598 111,121
14 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
Columns f - h: Values extracted from utilities' most recent fiscal year 2024 monthly report
Column p: Alaska Village Electric Cooperative average price of fuel is per reported actual fuel cost divided by gallons used;
all others are per prices used to determine PCE level
Columns i, j, m: Values summed from fiscal year 2024 utility reports
l m n o p q r s t
o / n
PCE
Payments
Made
Total kWh
Sold
Diesel Fuel
Gallons
Used
Diesel Fuel
Cost
Average
Price of Fuel
per Gallon
Non Fuel
Expenses
Total
kWh
Generated
Diesel Total
kWh
Generated
Non Diesel
Total
kWh
Purchased
Total
Notes Utility/Community
CHIGNIK LAGOON POWER UTILITY
$ 140,499 439,160 24,175 $ 114,468 $ 4.73 86,818 266,546 211,894 0 Chignik Lagoon PCE
$ 140,499 439,160 24,175 $ 114,468 $ 4.73 86,818 266,546 211,894 0
CHIGNIK LAKE ELECTRIC UTILITY
$ 60,390 286,964 33,490 $ 125,295 $ 3.74 33,000 313,517 0 0
August numbers included with
September PwrHouse
Consumption = 10 mths
Chignik Lake PCE
$ 60,390 286,964 33,490 $ 125,295 $ 3.74 33,000 313,517 0 0
CHITINA ELECTRIC INC.
$ 93,222 369,095 35,600 $ 142,044 $ 3.99 185,473 460,615 0 0 Chitina PCE
$ 93,222 369,095 35,600 $ 142,044 $ 3.99 185,473 460,615 0 0
CIRCLE ELECTRIC LLC
$ 105,753 363,150 37,478 $ 150,525 $ 4.02 148,198 399,927 0 0 Power House Consumption =
8 mths Circle PCE
$ 105,753 363,150 37,478 $ 150,525 $ 4.02 148,198 399,927 0 0
CLARKS POINT VILLAGE COUNCIL
$ 98,082 312,636 34,531 $ 151,046 $ 4.37 33,000 417,908 0 0 March Report = 2 months Clark's Point PCE
$ 98,082 312,636 34,531 $ 151,046 $ 4.37 33,000 417,908 0 0
CORDOVA ELECTRIC
$ 528,214 24,878,177 389,838 $ 1,302,625 $ 3.34 6,048,641 5,161,552 21,963,523 0 Fuel Used = 11 mths Cordova PCE: Eyak PCE
$ 528,214 24,878,177 389,838 $ 1,302,625 $ 3.34 6,048,641 5,161,552 21,963,523 0
DIOMEDE JOINT UTLITIES
$ 41,380 353,626 42,644 $ 185,907 $ 4.36 298,747 427,987 0 0 Diomede PCE
$ 41,380 353,626 42,644 $ 185,907 $ 4.36 298,747 427,987 0 0
CITY OF EGEGIK
$ 80,107 673,815 59,474 $ 196,357 $ 3.30 480,721 743,107 0 0 Egegik PCE
$ 80,107 673,815 59,474 $ 196,357 $ 3.30 480,721 743,107 0 0
ELFIN COVE UTILITY COMMISSION
$ 27,115 365,889 32,664 $ 169,397 $ 5.19 99,482 436,300 0 0 Elfin Cove PCE
$ 27,115 365,889 32,664 $ 169,397 $ 5.19 99,482 436,300 0 0
CITY OF FALSE PASS
$ 72,901 558,565 29,368 $ 101,264 $ 3.45 98,947 608,585 0 0 False Pass PCE
$ 72,901 558,565 29,368 $ 101,264 $ 3.45 98,947 608,585 0 0
G & K INC.
$ 83,906 2,012,139 189,467 $ 1,399,335 $ 7.39 912,784 2,392,880 0 0 Cold Bay PCE
$ 83,906 2,012,139 189,467 $ 1,399,335 $ 7.39 912,784 2,392,880 0 0
15 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
NOTES *** = Calculations cannot be made due to lack of data or other circumstances
Column a: Residential rates as reported by the utility in fiscal year 2024.
Column b: Rates based upon RCA Letter order in effect for last report filed in fiscal year 2024.
PCE rate reflects 100% funding level.
Column References:a b c d e f g h i j k
a - b i + j
Utility/Community
Last
Reported
Residential
Rate (based
on 500 kWh)
Last PCE
Rate Applied
Last
Effective
Residential
Rate
Population Reporting
Periods
Last
Reported
Number of
Residential
Customers
Last
Reported
Number of
Community
Facility
Customers
Last
Reported
Number of
Other
Customers
(Non-PCE)
PCE Eligible
kWh
Residential
PCE Eligible
kWh
Community
Facilities
PCE Eligible
kWh
Total
CITY OF GALENA
Galena PCE $ 0.6723 $ 0.3838 $ 0.2885 435 12 204 14 175 689,759 338,290 1,028,049
Utility Company Total 435 204 14 175 689,759 338,290 1,028,049
GOLD COUNTRY ENERGY
Central PCE $ 0.8080 $ 0.5096 $ 0.2984 62 12 123 1 19 175,093 2,464 177,557
Utility Company Total 62 123 1 19 175,093 2,464 177,557
GOLOVIN POWER UTILITIES
Golovin PCE $ 0.4600 $ 0.2520 $ 0.2080 190 12 50 11 47 242,275 138,342 380,617
Utility Company Total 190 50 11 47 242,275 138,342 380,617
GWITCHYAA ZHEE UTILITY COMPANY
Fort Yukon PCE $ 0.7788 $ 0.5619 $ 0.2169 499 12 273 21 82 977,251 407,821 1,385,072
Utility Company Total 499 273 21 82 977,251 407,821 1,385,072
HUGHES POWER & LIGHT
Hughes PCE $ 0.9100 $ 0.7114 $ 0.1986 79 12 49 3 20 207,957 65,071 273,028
Utility Company Total 79 49 3 20 207,957 65,071 273,028
IGIUGIG ELECTRIC COMPANY
Igiugig PCE $ 0.9157 $ 0.7222 $ 0.1935 63 12 35 15 13 97,217 49,115 146,332
Utility Company Total 63 35 15 13 97,217 49,115 146,332
ILIAMNA NEWHALEN NONDALTON
Iliamna; Newhalen; Nondalton PCE $ 0.6693 $ 0.4010 $ 0.2683 423 12 176 14 110 686,320 241,864 928,184
Utility Company Total 423 176 14 110 686,320 241,864 928,184
INSIDE PASSAGE ELECTRIC
Angoon PCE $ 0.6142 $ 0.3283 $ 0.2859 340 12 195 7 32 694,656 145,419 840,075
Chilkat Valley/Klukwan $ 0.6142 $ 0.3283 $ 0.2859 641 12 276 11 51 890,222 146,192 1,036,414
Hoonah PCE $ 0.6142 $ 0.3283 $ 0.2859 917 12 427 27 88 1,595,356 667,244 2,262,600
Kake PCE $ 0.6142 $ 0.3283 $ 0.2859 530 12 239 13 58 850,283 208,286 1,058,569
Utility Company Total 2,428 1,137 58 229 4,030,517 1,167,141 5,197,658
IPNATCHIAQ ELECTRIC COMPANY
Deering PCE $ 0.6747 $ 0.4622 $ 0.2125 185 12 49 5 22 266,062 119,111 385,173
Utility Company Total 185 49 5 22 266,062 119,111 385,173
KARLUK IRA TRIBAL COUNCIL
Karluk PCE $ 0.7000 $ 0.5065 $ 0.1935 28 12 14 4 12 71,651 22,278 93,929
Utility Company Total 28 14 4 12 71,651 22,278 93,929
KIPNUK LIGHT PLANT
Kipnuk PCE $ 0.6902 $ 0.4967 $ 0.1935 725 12 198 7 44 888,961 184,030 1,072,991
Utility Company Total 725 198 7 44 888,961 184,030 1,072,991
16 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
Columns f - h: Values extracted from utilities' most recent fiscal year 2024 monthly report
Column p: Alaska Village Electric Cooperative average price of fuel is per reported actual fuel cost divided by gallons used;
all others are per prices used to determine PCE level
Columns i, j, m: Values summed from fiscal year 2024 utility reports
l m n o p q r s t
o / n
PCE
Payments
Made
Total kWh
Sold
Diesel Fuel
Gallons
Used
Diesel Fuel
Cost
Average
Price of Fuel
per Gallon
Non Fuel
Expenses
Total
kWh
Generated
Diesel Total
kWh
Generated
Non Diesel
Total
kWh
Purchased
Total
Notes Utility/Community
CITY OF GALENA
$ 403,812 4,623,939 368,393 $ 1,562,972 $ 4.24 1,289,261 5,330,583 0 0 Galena PCE
$ 403,812 4,623,939 368,393 $ 1,562,972 $ 4.24 1,289,261 5,330,583 0 0
GOLD COUNTRY ENERGY
$ 100,225 324,112 36,263 $ 143,269 $ 3.95 135,786 427,542 0 0 Central PCE
$ 100,225 324,112 36,263 $ 143,269 $ 3.95 135,786 427,542 0 0
GOLOVIN POWER UTILITIES
$ 83,227 946,065 77,091 $ 269,754 $ 3.50 209,202 995,820 0 0 Golovin PCE
$ 83,227 946,065 77,091 $ 269,754 $ 3.50 209,202 995,820 0 0
GWITCHYAA ZHEE UTILITY COMPANY
$ 734,644 2,684,782 211,066 $ 1,539,152 $ 7.29 457,503 3,284,603 0 0 Fort Yukon PCE
$ 734,644 2,684,782 211,066 $ 1,539,152 $ 7.29 457,503 3,284,603 0 0
HUGHES POWER & LIGHT
$ 194,232 502,696 55,779 $ 357,404 $ 6.41 129,950 586,539 0 0 Hughes PCE
$ 194,232 502,696 55,779 $ 357,404 $ 6.41 129,950 586,539 0 0
IGIUGIG ELECTRIC COMPANY
$ 101,267 321,953 28,037 $ 273,554 $ 9.76 72,057 370,196 0 22,840 Igiugig PCE
$ 101,267 321,953 28,037 $ 273,554 $ 9.76 72,057 370,196 0 22,840
ILIAMNA NEWHALEN NONDALTON
$ 367,866 2,968,105 2,333 $ 9,666 $ 4.14 1,509,165 30,060 3,722,710 0 Iliamna; Newhalen; Nondalton PCE
$ 367,866 2,968,105 2,333 $ 9,666 $ 4.14 1,509,165 30,060 3,722,710 0
INSIDE PASSAGE ELECTRIC
$ 335,083 1,664,911 134,632 $ 497,663 $ 3.70 0 1,872,414 0 0 Angoon PCE
$ 413,643 1,618,479 0 $ 0 0 0 1,188,240 710,880 Chilkat Valley/Klukwan
$ 900,327 5,365,490 302,747 $ 1,118,779 $ 3.70 0 4,524,132 1,398,358 0 Hoonah PCE
$ 422,014 2,149,547 109,357 $ 404,046 $ 3.69 0 1,676,601 814,785 0 Kake PCE
$ 2,071,067 10,798,427 546,736 $ 2,020,488 $ 3.70 0 8,073,147 3,401,383 710,880
IPNATCHIAQ ELECTRIC COMPANY
$ 175,383 835,916 61,609 $ 295,258 $ 4.79 788,423 793,080 183,196 0 Deering PCE
$ 175,383 835,916 61,609 $ 295,258 $ 4.79 788,423 793,080 183,196 0
KARLUK IRA TRIBAL COUNCIL
$ 47,575 192,820 21,714 $ 137,479 $ 6.33 53,534 219,513 0 0 Karluk PCE
$ 47,575 192,820 21,714 $ 137,479 $ 6.33 53,534 219,513 0 0
KIPNUK LIGHT PLANT
$ 532,955 1,772,841 103,540 $ 377,652 $ 3.65 1,230,833 1,435,318 699,677 0 Kipnuk PCE
$ 532,955 1,772,841 103,540 $ 377,652 $ 3.65 1,230,833 1,435,318 699,677 0
17 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
NOTES *** = Calculations cannot be made due to lack of data or other circumstances
Column a: Residential rates as reported by the utility in fiscal year 2024.
Column b: Rates based upon RCA Letter order in effect for last report filed in fiscal year 2024.
PCE rate reflects 100% funding level.
Column References:a b c d e f g h i j k
a - b i + j
Utility/Community
Last
Reported
Residential
Rate (based
on 500 kWh)
Last PCE
Rate Applied
Last
Effective
Residential
Rate
Population Reporting
Periods
Last
Reported
Number of
Residential
Customers
Last
Reported
Number of
Community
Facility
Customers
Last
Reported
Number of
Other
Customers
(Non-PCE)
PCE Eligible
kWh
Residential
PCE Eligible
kWh
Community
Facilities
PCE Eligible
kWh
Total
KOKHANOK VILLAGE COUNCIL
Kokhanok PCE $ 0.9700 $ 0.6399 $ 0.3301 145 12 59 10 15 212,163 87,903 300,066
Utility Company Total 145 59 10 15 212,163 87,903 300,066
KOTZEBUE ELECTRIC ASSOCIATION
Kotzebue PCE $ 0.4707 $ 0.2289 $ 0.2418 2,931 12 1,084 26 172 4,192,552 1,961,920 6,154,472
Utility Company Total 2,931 1,084 26 172 4,192,552 1,961,920 6,154,472
CITY OF KOYUKUK
Koyukuk PCE $ 0.9500 $ 0.6555 $ 0.2945 92 12 66 6 7 149,927 25,741 175,668
Utility Company Total 92 66 6 7 149,927 25,741 175,668
KWETHLUK INCORPORATED
Kwethluk PCE $ 0.5200 $ 0.3265 $ 0.1935 787 12 192 1 50 961,176 10,191 971,367
Utility Company Total 787 192 1 50 961,176 10,191 971,367
KWIGILLINGOK IRA COUNCIL
Kwigillingok PCE $ 0.6700 $ 0.3597 $ 0.3103 365 12 110 3 31 577,026 42,045 619,071
Utility Company Total 365 110 3 31 577,026 42,045 619,071
LEVELOCK ELECTRICAL COOP
Levelock PCE $ 1.3500 $ 0.7662 $ 0.5838 65 12 39 7 37 104,744 34,908 139,652
Utility Company Total 65 39 7 37 104,744 34,908 139,652
LIME VILLAGE ELECTRIC UTILITY
Lime Village PCE $ 1.7700 $ 0.7662 $ 1.0038 6 10 19 6 2 27,046 4,200 31,246
Utility Company Total 6 19 6 2 27,046 4,200 31,246
MANOKOTAK POWER COMPANY
Manokotak PCE $ 0.7000 $ 0.2522 $ 0.4478 484 12 127 5 37 609,559 81,158 690,717
Utility Company Total 484 127 5 37 609,559 81,158 690,717
MCGRATH LIGHT & POWER
McGrath PCE $ 0.8734 $ 0.4737 $ 0.3997 272 12 176 14 88 475,310 165,692 641,002
Utility Company Total 272 176 14 88 475,310 165,692 641,002
MIDDLE KUSKOKWIM ELECTRIC COOPERATIVE INC
Chuathbaluk PCE $ 1.4718 $ 0.7662 $ 0.7056 83 12 33 9 7 103,643 42,043 145,686
Crooked Creek PCE $ 1.4718 $ 0.7662 $ 0.7056 90 12 28 3 12 91,273 33,693 124,966
Red Devil PCE $ 1.4718 $ 0.7662 $ 0.7056 24 12 11 0 6 21,009 0 21,009
Sleetmute PCE $ 1.4718 $ 0.7662 $ 0.7056 75 12 31 5 9 99,830 48,868 148,698
Stony River PCE $ 1.4719 $ 0.7662 $ 0.7057 68 12 16 4 5 40,262 17,372 57,634
Utility Company Total 340 119 21 39 356,017 141,976 497,993
18 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
Columns f - h: Values extracted from utilities' most recent fiscal year 2024 monthly report
Column p: Alaska Village Electric Cooperative average price of fuel is per reported actual fuel cost divided by gallons used;
all others are per prices used to determine PCE level
Columns i, j, m: Values summed from fiscal year 2024 utility reports
l m n o p q r s t
o / n
PCE
Payments
Made
Total kWh
Sold
Diesel Fuel
Gallons
Used
Diesel Fuel
Cost
Average
Price of Fuel
per Gallon
Non Fuel
Expenses
Total
kWh
Generated
Diesel Total
kWh
Generated
Non Diesel
Total
kWh
Purchased
Total
Notes Utility/Community
KOKHANOK VILLAGE COUNCIL
$ 198,579 457,960 138,181 $ 891,648 $ 6.45 341,768 480,895 89,305 0 Powerhouse Consumption =
11 mths Kokhanok PCE
$ 198,579 457,960 138,181 $ 891,648 $ 6.45 341,768 480,895 89,305 0
KOTZEBUE ELECTRIC ASSOCIATION
$ 1,322,843 19,454,086 1,219,298 $ 3,990,241 $ 3.27 0 17,389,264 4,270,228 0 Non-fuel Expenses Not
Reported Kotzebue PCE
$ 1,322,843 19,454,086 1,219,298 $ 3,990,241 $ 3.27 0 17,389,264 4,270,228 0
CITY OF KOYUKUK
$ 106,764 267,927 46,004 $ 213,494 $ 4.64 120,000 406,687 0 0 Only 9 Reports Filed Koyukuk PCE
$ 106,764 267,927 46,004 $ 213,494 $ 4.64 120,000 406,687 0 0
KWETHLUK INCORPORATED
$ 317,275 1,779,229 21,309 $ 100,232 $ 4.70 210,514 2,123,316 0 0
Diesel Gen = 3 mths Fuel Used
= 2 mths PHouse Consum = 2
mths Non-Fuel Exp = 11
Kwethluk PCE
$ 317,275 1,779,229 21,309 $ 100,232 $ 4.70 210,514 2,123,316 0 0
KWIGILLINGOK IRA COUNCIL
$ 222,680 1,227,283 100,971 $ 353,008 $ 3.50 433,536 1,181,770 191,206 0 Kwigillingok PCE
$ 222,680 1,227,283 100,971 $ 353,008 $ 3.50 433,536 1,181,770 191,206 0
LEVELOCK ELECTRICAL COOP
$ 96,000 357,392 39,930 $ 189,839 $ 4.75 359,714 455,212 0 0 Levelock PCE
$ 96,000 357,392 39,930 $ 189,839 $ 4.75 359,714 455,212 0 0
LIME VILLAGE ELECTRIC UTILITY
$ 23,872 124,940 14,399 $ 167,460 $ 11.63 30,000 217,830 0 0 Reports Filed = 10 Lime Village PCE
$ 23,872 124,940 14,399 $ 167,460 $ 11.63 30,000 217,830 0 0
MANOKOTAK POWER COMPANY
$ 175,453 1,281,790 102,162 $ 380,298 $ 3.72 395,316 1,286,706 0 0
Power House Conssumption =
1 mth Non-Fuel Expenses = 10
mths
Manokotak PCE
$ 175,453 1,281,790 102,162 $ 380,298 $ 3.72 395,316 1,286,706 0 0
MCGRATH LIGHT & POWER
$ 291,600 1,922,154 142,710 $ 655,525 $ 4.59 0 2,182,439 0 0
Non-Fuel Expenses not
reported Diesel Gen & Fuel
Used x 11
McGrath PCE
$ 291,600 1,922,154 142,710 $ 655,525 $ 4.59 0 2,182,439 0 0
MIDDLE KUSKOKWIM ELECTRIC COOPERATIVE INC
$ 111,625 229,172 26,274 $ 112,645 $ 4.29 164,736 262,692 0 0 Non-Fuel Expenses x 11 mths Chuathbaluk PCE
$ 95,749 249,549 27,142 $ 119,737 $ 4.41 235,353 291,561 0 0 Crooked Creek PCE
$ 16,097 36,548 8,020 $ 35,223 $ 4.39 112,745 41,984 0 0 Red Devil PCE
$ 113,932 292,011 30,781 $ 135,460 $ 4.40 198,973 331,550 0 0 Sleetmute PCE
$ 44,159 118,299 17,549 $ 77,484 $ 4.42 154,788 146,932 0 0 Non-Fuel Expenses x 10 Stony River PCE
$ 381,562 925,579 109,766 $ 480,549 $ 4.38 866,595 1,074,719 0 0
19 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
NOTES *** = Calculations cannot be made due to lack of data or other circumstances
Column a: Residential rates as reported by the utility in fiscal year 2024.
Column b: Rates based upon RCA Letter order in effect for last report filed in fiscal year 2024.
PCE rate reflects 100% funding level.
Column References:a b c d e f g h i j k
a - b i + j
Utility/Community
Last
Reported
Residential
Rate (based
on 500 kWh)
Last PCE
Rate Applied
Last
Effective
Residential
Rate
Population Reporting
Periods
Last
Reported
Number of
Residential
Customers
Last
Reported
Number of
Community
Facility
Customers
Last
Reported
Number of
Other
Customers
(Non-PCE)
PCE Eligible
kWh
Residential
PCE Eligible
kWh
Community
Facilities
PCE Eligible
kWh
Total
NAKNEK ELECTRIC
Naknek;S.Naknek;Kng Slmn PCE $ 0.5672 $ 0.3537 $ 0.2135 800 12 682 38 364 2,111,041 672,000 2,783,041
Utility Company Total 800 682 38 364 2,111,041 672,000 2,783,041
NAPAKIAK IRCINRAQ
Napakiak PCE $ 0.8630 $ 0.2619 $ 0.6011 336 12 107 4 22 344,088 40,278 384,366
Utility Company Total 336 107 4 22 344,088 40,278 384,366
NAPASKIAK ELECTRIC UTILITY
Napaskiak PCE $ 0.7000 $ 0.3311 $ 0.3689 494 12 105 6 35 398,627 41,261 439,888
Utility Company Total 494 105 6 35 398,627 41,261 439,888
NATERKAQ LIGHT PLANT
Chefornak PCE $ 0.7400 $ 0.3665 $ 0.3735 515 12 103 19 29 540,786 77,122 617,908
Utility Company Total 515 103 19 29 540,786 77,122 617,908
NELSON LAGOON ELECTRICAL COOP
Nelson Lagoon PCE $ 0.8400 $ 0.5492 $ 0.2908 31 12 33 8 25 113,596 21,606 135,202
Utility Company Total 31 33 8 25 113,596 21,606 135,202
NEW KOLIGANEK VILLAGE COUNCIL
Koliganek PCE $ 0.5000 $ 0.3065 $ 0.1935 173 12 74 11 14 250,841 59,641 310,482
Utility Company Total 173 74 11 14 250,841 59,641 310,482
CITY OF NIKOLAI
Nikolai PCE $ 0.9000 $ 0.7065 $ 0.1935 94 12 45 8 14 147,543 54,058 201,601
Utility Company Total 94 45 8 14 147,543 54,058 201,601
NOME JOINT UTILITY SYSTEM
Nome PCE $ 0.4275 $ 0.1902 $ 0.2373 3,469 12 1,785 85 389 6,354,374 2,375,296 8,729,670
Utility Company Total 3,469 1,785 85 389 6,354,374 2,375,296 8,729,670
NORTH SLOPE BOROUGH
Anaktuvuk Pass PCE $ 0.3500 $ 0.1565 $ 0.1935 412 12 97 2 61 325,223 44,205 369,428
Atqasuk PCE $ 0.3500 $ 0.1565 $ 0.1935 283 12 68 2 55 226,306 59,406 285,712
Kaktovik PCE $ 0.3500 $ 0.1565 $ 0.1935 265 12 75 2 52 199,130 45,968 245,098
Nuiqsut PCE $ 0.0800 $ 0.0000 $ 0.0800 492 12 120 3 75 652,513 109,278 761,791
Point Hope PCE $ 0.3500 $ 0.1565 $ 0.1935 841 12 208 1 76 768,740 47,028 815,768
Point Lay PCE $ 0.3500 $ 0.1565 $ 0.1935 303 12 65 1 43 178,710 45,938 224,648
Wainwright PCE $ 0.3500 $ 0.1565 $ 0.1935 623 12 151 3 72 552,826 87,798 640,624
Utility Company Total 3,219 784 14 434 2,903,448 439,621 3,343,069
NUNAM IQUA ELECTRIC COMPANY
Nunam Iqua PCE $ 0.5622 $ 0.3506 $ 0.2116 207 12 47 6 23 251,190 169,091 420,281
Utility Company Total 207 47 6 23 251,190 169,091 420,281
20 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
Columns f - h: Values extracted from utilities' most recent fiscal year 2024 monthly report
Column p: Alaska Village Electric Cooperative average price of fuel is per reported actual fuel cost divided by gallons used;
all others are per prices used to determine PCE level
Columns i, j, m: Values summed from fiscal year 2024 utility reports
l m n o p q r s t
o / n
PCE
Payments
Made
Total kWh
Sold
Diesel Fuel
Gallons
Used
Diesel Fuel
Cost
Average
Price of Fuel
per Gallon
Non Fuel
Expenses
Total
kWh
Generated
Diesel Total
kWh
Generated
Non Diesel
Total
kWh
Purchased
Total
Notes Utility/Community
NAKNEK ELECTRIC
$ 1,006,790 21,200,582 1,582,283 $ 5,307,246 $ 3.35 7,809,584 22,751,403 0 0 Naknek;S.Naknek;Kng Slmn PCE
$ 1,006,790 21,200,582 1,582,283 $ 5,307,246 $ 3.35 7,809,584 22,751,403 0 0
NAPAKIAK IRCINRAQ
$ 100,613 778,324 0 $ 0 437,913 0 0 824,060 Purchases power from AVEC Napakiak PCE
$ 100,613 778,324 0 $ 0 NaN 437,913 0 0 824,060
NAPASKIAK ELECTRIC UTILITY
$ 140,728 673,540 79,277 $ 341,007 $ 4.30 474,038 2,731,112 0 0 Napaskiak PCE
$ 140,728 673,540 79,277 $ 341,007 $ 4.30 474,038 2,731,112 0 0
NATERKAQ LIGHT PLANT
$ 236,207 1,390,412 105,257 $ 505,207 $ 4.80 485,543 1,340,489 190,026 0 Chefornak PCE
$ 236,207 1,390,412 105,257 $ 505,207 $ 4.80 485,543 1,340,489 190,026 0
NELSON LAGOON ELECTRICAL COOP
$ 75,713 257,036 41,285 $ 193,588 $ 4.69 25,358 296,798 0 0 Nelson Lagoon PCE
$ 75,713 257,036 41,285 $ 193,588 $ 4.69 25,358 296,798 0 0
NEW KOLIGANEK VILLAGE COUNCIL
$ 95,163 609,073 57,869 $ 294,233 $ 5.08 48,000 683,290 0 0 Koliganek PCE
$ 95,163 609,073 57,869 $ 294,233 $ 5.08 48,000 683,290 0 0
CITY OF NIKOLAI
$ 135,985 391,883 36,978 $ 257,638 $ 6.97 36,000 515,894 0 0 Nikolai PCE
$ 135,985 391,883 36,978 $ 257,638 $ 6.97 36,000 515,894 0 0
NOME JOINT UTILITY SYSTEM
$ 1,660,384 29,803,988 2,069,698 $ 7,436,011 $ 3.59 5,087,349 29,930,950 1,953,896 0 Nome PCE
$ 1,660,384 29,803,988 2,069,698 $ 7,436,011 $ 3.59 5,087,349 29,930,950 1,953,896 0
NORTH SLOPE BOROUGH
$ 9,190 3,462,290 321,535 $ 2,035,799 $ 6.33 1,099,652 4,368,089 0 0 Anaktuvuk Pass PCE
$ 9,946 3,131,617 263,336 $ 1,253,716 $ 4.76 1,278,559 3,546,622 0 0 Atqasuk PCE
$ 8,841 3,623,869 381,366 $ 1,286,958 $ 3.37 1,162,352 5,243,558 0 0 Kaktovik PCE
$ 8,941 6,091,029 188,169 $ 1,047,255 $ 5.57 1,099,040 2,836,049 5,295,817 0 Residential PCE Level = Zero Nuiqsut PCE
$ 22,910 5,923,810 538,485 $ 1,787,016 $ 3.32 1,498,151 6,907,222 0 0 Point Hope PCE
$ 7,827 3,167,964 285,060 $ 955,732 $ 3.35 1,159,776 3,728,407 0 0 Point Lay PCE
$ 19,266 6,281,089 563,190 $ 1,857,795 $ 3.30 1,179,985 7,504,000 0 0 Wainwright PCE
$ 86,921 31,681,668 2,541,141 $ 10,224,271 $ 4.02 8,477,515 34,133,947 5,295,817 0
NUNAM IQUA ELECTRIC COMPANY
$ 146,302 918,617 75,598 $ 338,739 $ 4.48 124,105 987,122 0 0 Nunam Iqua PCE
$ 146,302 918,617 75,598 $ 338,739 $ 4.48 124,105 987,122 0 0
21 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
NOTES *** = Calculations cannot be made due to lack of data or other circumstances
Column a: Residential rates as reported by the utility in fiscal year 2024.
Column b: Rates based upon RCA Letter order in effect for last report filed in fiscal year 2024.
PCE rate reflects 100% funding level.
Column References:a b c d e f g h i j k
a - b i + j
Utility/Community
Last
Reported
Residential
Rate (based
on 500 kWh)
Last PCE
Rate Applied
Last
Effective
Residential
Rate
Population Reporting
Periods
Last
Reported
Number of
Residential
Customers
Last
Reported
Number of
Community
Facility
Customers
Last
Reported
Number of
Other
Customers
(Non-PCE)
PCE Eligible
kWh
Residential
PCE Eligible
kWh
Community
Facilities
PCE Eligible
kWh
Total
NUSHAGAK ELECTRIC AND
Dillingham; Aleknagik PCE $ 0.5352 $ 0.2602 $ 0.2750 2,420 12 951 49 513 4,345,621 568,472 4,914,093
Utility Company Total 2,420 951 49 513 4,345,621 568,472 4,914,093
CITY OF OUZINKIE
Ouzinkie PCE $ 0.5200 $ 0.3229 $ 0.1971 116 12 79 16 19 255,889 88,725 344,614
Utility Company Total 116 79 16 19 255,889 88,725 344,614
PEDRO BAY VILLAGE COUNCIL
Pedro Bay PCE $ 0.8167 $ 0.6175 $ 0.1992 27 12 44 4 13 38,114 22,149 60,263
Utility Company Total 27 44 4 13 38,114 22,149 60,263
PELICAN UTILITY DISTRICT
Pelican PCE $ 0.2541 $ 0.0549 $ 0.1992 83 12 72 15 30 261,837 68,443 330,280
Utility Company Total 83 72 15 30 261,837 68,443 330,280
PILOT POINT ELECTRIC UTILITY
Pilot Point PCE $ 0.6000 $ 0.4065 $ 0.1935 72 12 39 9 23 128,763 30,947 159,710
Utility Company Total 72 39 9 23 128,763 30,947 159,710
PORT HEIDEN UTILITIES
Port Heiden PCE $ 0.6500 $ 0.4552 $ 0.1948 93 10 51 8 34 149,491 47,465 196,956
Utility Company Total 93 51 8 34 149,491 47,465 196,956
PUVURNAQ POWER COMPANY
Kongiganak PCE $ 0.7600 $ 0.3996 $ 0.3604 510 12 165 5 27 593,895 99,228 693,123
Utility Company Total 510 165 5 27 593,895 99,228 693,123
RAMPART VILLAGE COUNCIL
Rampart PCE $ 0.8149 $ 0.6214 $ 0.1935 63 12 38 7 7 75,466 46,974 122,440
Utility Company Total 63 38 7 7 75,466 46,974 122,440
CITY OF RUBY
Ruby PCE $ 0.8700 $ 0.6210 $ 0.2490 128 12 99 13 28 271,013 81,697 352,710
Utility Company Total 128 99 13 28 271,013 81,697 352,710
CITY OF ST. GEORGE
St. George PCE $ 1.0000 $ 0.7662 $ 0.2338 61 10 39 7 29 55,345 36,088 91,433
Utility Company Total 61 39 7 29 55,345 36,088 91,433
ST. PAUL MUNICIPAL ELECTRIC
St. Paul PCE $ 0.6200 $ 0.4265 $ 0.1935 379 12 125 26 70 615,405 309,848 925,253
Utility Company Total 379 125 26 70 615,405 309,848 925,253
22 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
Columns f - h: Values extracted from utilities' most recent fiscal year 2024 monthly report
Column p: Alaska Village Electric Cooperative average price of fuel is per reported actual fuel cost divided by gallons used;
all others are per prices used to determine PCE level
Columns i, j, m: Values summed from fiscal year 2024 utility reports
l m n o p q r s t
o / n
PCE
Payments
Made
Total kWh
Sold
Diesel Fuel
Gallons
Used
Diesel Fuel
Cost
Average
Price of Fuel
per Gallon
Non Fuel
Expenses
Total
kWh
Generated
Diesel Total
kWh
Generated
Non Diesel
Total
kWh
Purchased
Total
Notes Utility/Community
NUSHAGAK ELECTRIC AND
$ 1,289,753 17,770,357 1,291,290 $ 4,517,733 $ 3.50 4,366,463 19,114,994 0 0 Non-Fuel Expenses x 11
months Dillingham; Aleknagik PCE
$ 1,289,753 17,770,357 1,291,290 $ 4,517,733 $ 3.50 4,366,463 19,114,994 0 0
CITY OF OUZINKIE
$ 97,206 657,389 30,825 $ 139,365 $ 4.52 98,225 365,287 353,315 0 Ouzinkie PCE
$ 97,206 657,389 30,825 $ 139,365 $ 4.52 98,225 365,287 353,315 0
PEDRO BAY VILLAGE COUNCIL
$ 36,581 201,893 22,980 $ 148,215 $ 6.45 31,948 237,639 0 0 Pedro Bay PCE
$ 36,581 201,893 22,980 $ 148,215 $ 6.45 31,948 237,639 0 0
PELICAN UTILITY DISTRICT
$ 28,120 1,552,275 6,211 $ 26,099 $ 4.20 256,338 82,369 1,648,980 0 Pelican PCE
$ 28,120 1,552,275 6,211 $ 26,099 $ 4.20 256,338 82,369 1,648,980 0
PILOT POINT ELECTRIC UTILITY
$ 64,922 360,253 38,090 $ 193,053 $ 5.07 56,599 446,830 0 0 Pilot Point PCE
$ 64,922 360,253 38,090 $ 193,053 $ 5.07 56,599 446,830 0 0
PORT HEIDEN UTILITIES
$ 89,654 480,100 40,641 $ 165,713 $ 4.08 30,000 746,285 0 0
10 Rpts Filed, Diesel kWh Gen
PHouse Consm & Fuel Used x
6 mths
Port Heiden PCE
$ 89,654 480,100 40,641 $ 165,713 $ 4.08 30,000 746,285 0 0
PUVURNAQ POWER COMPANY
$ 268,934 1,096,343 78,048 $ 308,988 $ 3.96 663,071 914,090 550,426 0 Kongiganak PCE
$ 268,934 1,096,343 78,048 $ 308,988 $ 3.96 663,071 914,090 550,426 0
RAMPART VILLAGE COUNCIL
$ 75,292 333,221 32,934 $ 177,271 $ 5.38 37,439 1,312,673 0 0 Non-Fuel Expenses x 7 months Rampart PCE
$ 75,292 333,221 32,934 $ 177,271 $ 5.38 37,439 1,312,673 0 0
CITY OF RUBY
$ 204,980 695,205 53,467 $ 356,987 $ 6.68 191,543 740,518 0 0 Ruby PCE
$ 204,980 695,205 53,467 $ 356,987 $ 6.68 191,543 740,518 0 0
CITY OF ST. GEORGE
$ 70,031 357,608 40,490 $ 414,294 $ 10.23 30,000 448,252 0 0 10 Months Filed St. George PCE
$ 70,031 357,608 40,490 $ 414,294 $ 10.23 30,000 448,252 0 0
ST. PAUL MUNICIPAL ELECTRIC
$ 401,576 2,714,499 232,706 $ 1,378,413 $ 5.92 567,124 3,139,833 0 0 St. Paul PCE
$ 401,576 2,714,499 232,706 $ 1,378,413 $ 5.92 567,124 3,139,833 0 0
23 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
NOTES *** = Calculations cannot be made due to lack of data or other circumstances
Column a: Residential rates as reported by the utility in fiscal year 2024.
Column b: Rates based upon RCA Letter order in effect for last report filed in fiscal year 2024.
PCE rate reflects 100% funding level.
Column References:a b c d e f g h i j k
a - b i + j
Utility/Community
Last
Reported
Residential
Rate (based
on 500 kWh)
Last PCE
Rate Applied
Last
Effective
Residential
Rate
Population Reporting
Periods
Last
Reported
Number of
Residential
Customers
Last
Reported
Number of
Community
Facility
Customers
Last
Reported
Number of
Other
Customers
(Non-PCE)
PCE Eligible
kWh
Residential
PCE Eligible
kWh
Community
Facilities
PCE Eligible
kWh
Total
TAKOTNA COMMUNITY ASSOC INC
Takotna PCE $ 1.0220 $ 0.6873 $ 0.3347 55 12 27 5 19 52,821 25,774 78,595
Utility Company Total 55 27 5 19 52,821 25,774 78,595
TANALIAN ELECTRIC COOPERATIVE
Port Alsworth PCE $ 0.8360 $ 0.6037 $ 0.2323 174 12 78 0 80 305,791 0 305,791
Utility Company Total 174 78 0 80 305,791 0 305,791
TANANA POWER COMPANY INC.
Tanana PCE $ 0.8495 $ 0.5163 $ 0.3332 223 12 105 7 48 328,126 168,932 497,058
Utility Company Total 223 105 7 48 328,126 168,932 497,058
TATITLEK VILLAGE IRA COUNCIL
Tatitlek PCE $ 0.9200 $ 0.7247 $ 0.1953 81 12 41 5 24 101,466 36,003 137,469
Utility Company Total 81 41 5 24 101,466 36,003 137,469
TDX ADAK GENERATING LLC
Adak PCE $ 1.8443 $ 0.7608 $ 1.0835 113 12 63 13 66 93,737 93,493 187,230
Utility Company Total 113 63 13 66 93,737 93,493 187,230
TDX CORPORATION
Sand Point PCE $ 0.8448 $ 0.5872 $ 0.2576 652 12 237 26 121 1,066,068 547,680 1,613,748
Utility Company Total 652 237 26 121 1,066,068 547,680 1,613,748
TDX MANLEY GENERATING LLC
Manley Hot Springs PCE $ 1.2141 $ 0.7608 $ 0.4533 101 12 81 12 24 151,195 34,230 185,425
Utility Company Total 101 81 12 24 151,195 34,230 185,425
CITY OF TENAKEE SPRINGS
Tenakee Springs PCE $ 0.7100 $ 0.4777 $ 0.2323 126 12 132 15 27 189,096 29,543 218,639
Utility Company Total 126 132 15 27 189,096 29,543 218,639
TULUKSAK TRADITIONAL
Tuluksak PCE $ 0.7500 $ 0.5565 $ 0.1935 420 11 106 6 13 386,552 50,788 437,340
Utility Company Total 420 106 6 13 386,552 50,788 437,340
TUNTUTULIAK COMMUNITY
Tuntutuliak PCE $ 0.7500 $ 0.4557 $ 0.2943 492 12 146 9 36 639,699 38,519 678,218
Utility Company Total 492 146 9 36 639,699 38,519 678,218
UMNAK POWER COMPANY
Nikolski PCE $ 0.7500 $ 0.5565 $ 0.1935 41 12 15 6 9 47,692 24,338 72,030
Utility Company Total 41 15 6 9 47,692 24,338 72,030
UNALAKLEET VALLEY ELECTRIC
Unalakleet PCE $ 0.6134 $ 0.3358 $ 0.2776 722 12 275 25 90 1,076,771 258,399 1,335,170
Utility Company Total 722 275 25 90 1,076,771 258,399 1,335,170
24 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
Columns f - h: Values extracted from utilities' most recent fiscal year 2024 monthly report
Column p: Alaska Village Electric Cooperative average price of fuel is per reported actual fuel cost divided by gallons used;
all others are per prices used to determine PCE level
Columns i, j, m: Values summed from fiscal year 2024 utility reports
l m n o p q r s t
o / n
PCE
Payments
Made
Total kWh
Sold
Diesel Fuel
Gallons
Used
Diesel Fuel
Cost
Average
Price of Fuel
per Gallon
Non Fuel
Expenses
Total
kWh
Generated
Diesel Total
kWh
Generated
Non Diesel
Total
kWh
Purchased
Total
Notes Utility/Community
TAKOTNA COMMUNITY ASSOC INC
$ 54,834 171,465 39,932 $ 224,053 $ 5.61 0 246,303 0 0 Non-Fuel Expenses Not
Reported Takotna PCE
$ 54,834 171,465 39,932 $ 224,053 $ 5.61 0 246,303 0 0
TANALIAN ELECTRIC COOPERATIVE
$ 188,612 944,975 75,648 $ 447,553 $ 5.92 366,300 1,018,500 0 0 Port Alsworth PCE
$ 188,612 944,975 75,648 $ 447,553 $ 5.92 366,300 1,018,500 0 0
TANANA POWER COMPANY INC.
$ 218,573 1,245,061 99,732 $ 465,197 $ 4.66 395,547 1,357,672 0 0 Provides power to Klukwan Tanana PCE
$ 218,573 1,245,061 99,732 $ 465,197 $ 4.66 395,547 1,357,672 0 0
TATITLEK VILLAGE IRA COUNCIL
$ 95,730 302,191 40,578 $ 243,204 $ 5.99 36,000 454,888 0 0 Tatitlek PCE
$ 95,730 302,191 40,578 $ 243,204 $ 5.99 36,000 454,888 0 0
TDX ADAK GENERATING LLC
$ 143,373 1,006,725 157,740 $ 912,833 $ 5.79 788,594 1,920,408 0 0 Adak PCE
$ 143,373 1,006,725 157,740 $ 912,833 $ 5.79 788,594 1,920,408 0 0
TDX CORPORATION
$ 692,349 3,343,343 271,165 $ 1,200,313 $ 4.43 1,163,351 3,724,876 0 0 Sand Point PCE
$ 692,349 3,343,343 271,165 $ 1,200,313 $ 4.43 1,163,351 3,724,876 0 0
TDX MANLEY GENERATING LLC
$ 141,973 522,644 47,727 $ 206,526 $ 4.33 417,527 593,383 868 0 Manley Hot Springs PCE
$ 141,973 522,644 47,727 $ 206,526 $ 4.33 417,527 593,383 868 0
CITY OF TENAKEE SPRINGS
$ 102,934 347,939 32,729 $ 144,515 $ 4.42 88,211 405,567 0 0 Tenakee Springs PCE
$ 102,934 347,939 32,729 $ 144,515 $ 4.42 88,211 405,567 0 0
TULUKSAK TRADITIONAL
$ 161,202 806,714 58,884 $ 220,424 $ 3.74 193,757 712,490 0 0 Tuluksak PCE
$ 161,202 806,714 58,884 $ 220,424 $ 3.74 193,757 712,490 0 0
TUNTUTULIAK COMMUNITY
$ 310,354 1,228,129 101,045 $ 422,786 $ 4.18 466,297 1,240,150 129,461 0 Tuntutuliak PCE
$ 310,354 1,228,129 101,045 $ 422,786 $ 4.18 466,297 1,240,150 129,461 0
UMNAK POWER COMPANY
$ 40,085 164,851 22,192 $ 184,370 $ 8.31 41,530 223,218 0 0 Nikolski PCE
$ 40,085 164,851 22,192 $ 184,370 $ 8.31 41,530 223,218 0 0
UNALAKLEET VALLEY ELECTRIC
$ 435,022 3,733,822 205,697 $ 782,817 $ 3.81 747,122 3,271,175 755,820 0 Unalakleet PCE
$ 435,022 3,733,822 205,697 $ 782,817 $ 3.81 747,122 3,271,175 755,820 0
25 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
NOTES *** = Calculations cannot be made due to lack of data or other circumstances
Column a: Residential rates as reported by the utility in fiscal year 2024.
Column b: Rates based upon RCA Letter order in effect for last report filed in fiscal year 2024.
PCE rate reflects 100% funding level.
Column References:a b c d e f g h i j k
a - b i + j
Utility/Community
Last
Reported
Residential
Rate (based
on 500 kWh)
Last PCE
Rate Applied
Last
Effective
Residential
Rate
Population Reporting
Periods
Last
Reported
Number of
Residential
Customers
Last
Reported
Number of
Community
Facility
Customers
Last
Reported
Number of
Other
Customers
(Non-PCE)
PCE Eligible
kWh
Residential
PCE Eligible
kWh
Community
Facilities
PCE Eligible
kWh
Total
CITY OF UNALASKA
Unalaska PCE $ 0.4627 $ 0.1686 $ 0.2941 4,113 12 810 58 191 2,138,248 2,982,274 5,120,522
Utility Company Total 4,113 810 58 191 2,138,248 2,982,274 5,120,522
UNGUSRAQ POWER COMPANY
Newtok; Mertavik PCE $ 0.8000 $ 0.6065 $ 0.1935 276 12 100 6 29 303,681 36,187 339,868
Utility Company Total 276 100 6 29 303,681 36,187 339,868
VENETIE VILLAGE ELECTRIC
Venetie PCE $ 0.9000 $ 0.7065 $ 0.1935 194 8 74 10 15 174,131 84,360 258,491
Utility Company Total 194 74 10 15 174,131 84,360 258,491
CITY OF WHITE MOUNTAIN
White Mountain PCE $ 0.5500 $ 0.3139 $ 0.2361 205 12 68 8 29 329,072 128,404 457,476
Utility Company Total 205 68 8 29 329,072 128,404 457,476
26 of 28
State of Alaska: Alaska Energy Authority
Power Cost Equalization Program Statistical Data by Utility
Fiscal Year: 2024
Columns f - h: Values extracted from utilities' most recent fiscal year 2024 monthly report
Column p: Alaska Village Electric Cooperative average price of fuel is per reported actual fuel cost divided by gallons used;
all others are per prices used to determine PCE level
Columns i, j, m: Values summed from fiscal year 2024 utility reports
l m n o p q r s t
o / n
PCE
Payments
Made
Total kWh
Sold
Diesel Fuel
Gallons
Used
Diesel Fuel
Cost
Average
Price of Fuel
per Gallon
Non Fuel
Expenses
Total
kWh
Generated
Diesel Total
kWh
Generated
Non Diesel
Total
kWh
Purchased
Total
Notes Utility/Community
CITY OF UNALASKA
$ 961,069 42,106,190 2,857,288 $ 9,980,903 $ 3.49 5,278,438 44,376,426 0 0 Unalaska PCE
$ 961,069 42,106,190 2,857,288 $ 9,980,903 $ 3.49 5,278,438 44,376,426 0 0
UNGUSRAQ POWER COMPANY
$ 206,130 548,422 88,299 $ 479,076 $ 5.43 36,000 660,351 0 0 Newtok; Mertavik PCE
$ 206,130 548,422 88,299 $ 479,076 $ 5.43 36,000 660,351 0 0
VENETIE VILLAGE ELECTRIC
$ 182,624 506,018 0 $ 0 24,000 0 0 0 Venetie PCE
$ 182,624 506,018 0 $ 0 NaN 24,000 0 0 0
CITY OF WHITE MOUNTAIN
$ 144,587 832,029 81,230 $ 258,602 $ 3.18 476,158 968,304 0 0 White Mountain PCE
$ 144,587 832,029 81,230 $ 258,602 $ 3.18 476,158 968,304 0 0
27 of 28
2015*2016*2017*2018*2019*2020*2021*2022*2023*2024
PARTICIPATION
Participating Utilities 86 88 89 89 88 86 86 83 82 82
Communities Served 190 191 194 194 193 191 191 188 188 188
Population Served 81,969 82,986 83,850 83,400 81,997 81,694 81,160 79,808 81,996 80,809
PCE ELIGIBLE CUSTOMERS
Residential 27,893 28,035 27,857 28,365 28,338 28,158 27,923 27,961 28,128 27,947
Community Facilities 1,850 2,056 2,067 2,090 2,069 1,984 1,969 1,939 1,973 1,936
Total PCE Eligible Customers 29,743 30,091 29,924 30,455 30,407 30,142 29,892 29,900 30,101 29,883
FUNDING
Appropriations for Utility Payments($)$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 $47,694,800
Disbursements to Utilities ($)$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 $45,218,683
Disbursements/Customer ($)$1,257 $1,032 $872 $860 $933 $962 $790 $915 $1,382 $1,513
Funding Level 100%100%100%100%100%100%100%100%100%100%
CONSUMPTION
Total MWh Sold (MWh)450,232 446,735 462,081 458,092 453,598 455,730 440,607 460,572 460,821 471,748
PCE Eligible MWh Residential 96,453 94,816 97,751 96,597 95,606 96,544 97,510 97,417 113,680 114,240
Avg. PCE Eligible kWh/Month/Residential Customer 288 282 292 284 281 286 291 290 337 341
PCE Eligible MWh Community Facilities 32,795 34,357 35,747 34,929 34,191 34,946 34,554 35,544 35,647 36,594
Elig. kWh/Month/Capita, Community Facilities 33.3 34.5 35.5 34.9 34.7 35.6 35.5 37.1 36.2 37.7
Total PCE Eligible MWh 129,248 129,173 133,498 131,526 129,797 131,490 132,063 132,961 149,326 150,834
Eligible kWh/Month/Cust, Total Customers 362 358 372 360 356 364 368 371 413 421
COSTS
Average Price of Fuel Oil ($/gallon)$3.97 $3.24 $2.66 $2.67 $3.06 $3.07 $2.63 $3.02 $4.02 $4.23
Total Gallons of Fuel Oil Consumed 27,191,149 26,865,206 28,838,704 28,446,814 28,425,146 28,199,707 27,783,263 28,682,394 27,248,271 28,702,505
Total Cost of Fuel Oil ($)$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 $121,279,866
Total Non-Fuel Costs ($)$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 $102,931,381
FINANCIAL RATIOS
Non-Fuel Costs Per Total kWh Sold $0.1689 $0.1857 $0.1843 $0.2010 $0.1892 $0.1928 $0.1852 $0.2041 $0.2361 $0.2182
Total Operating Costs Per Total kWh Sold $0.4084 $0.3807 $0.3504 $0.3670 $0.3810 $0.3829 $0.3511 $0.3922 $0.4740 $0.4753
RATES
Avg. PCE per Eligible kWh Res. & Comm Facility ($/kWh)$0.2892 $0.2403 $0.1955 $0.1991 $0.2185 $0.2206 $0.1789 $0.2058 $0.2785 $0.2998
Weighted Avg. Residential Rate (Before PCE Paid)$0.4915 $0.4541 $0.4270 $0.4378 $0.4628 $0.4633 $0.4412 $0.4674 $0.5528 $0.5640
Weighted Avg. Residential PCE Rate (Amount PCE pays)$0.2919 $0.2432 $0.1983 $0.2010 $0.2191 $0.2226 $0.1821 $0.2101 $0.2776 $0.3012
Weighted Avg. Residential Effective Rate (1)$0.1996 $0.2108 $0.2288 $0.2368 $0.2437 $0.2407 $0.2591 $0.2572 $0.2752 $0.2628
*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 2015 - 2024
28 of 28
Alaska Energy Authority
Federal Funding Tracker
Status Source Program Name
Award $ / Request
$
Required
Match %Required Match $
Remaining Match
$ Needed Comments
Conditional
Award Annual Diesel Emissions Reduction Act 2023 -2024 $ 1,230,478 50% $ 1,230,478 1,230,478$
Received email confirmation grant not paused on 3/4. Award date 8/23/2024, pending
final budget document from EPA. VW funds requested as match.
Awarded Annual Diesel Emissions Reduction Act 2019 -2020 $ 1,025,748 50% $ 1,025,748 -$ Received email confirmation grant not paused on 3/4.
Awarded Annual Diesel Emissions Reduction Act 2022 -2021 $ 964,479 50% $ 964,479 -$ Received email confirmation grant not paused on 3/4.
Awarded Annual State Energy Program Funding 2024 $ 480,580 0%-$ -$
Received verbal communication that SEP Annual was not ever paused on 3/4. On 3/10,
Project Officer stated she would send an email confirming the status of the program.
Awarded IIJA
Grid Resilience and Innovation Partnerships Program Topic 3 -
Subsea HVDC Line $ 206,500,000 100% $ 206,500,000 143,800,000$
Email on 3/3/2025, NETL is able to discuss topics regarding quarterly assessments,
reporting, invoicing, general project/award oversight, administrative
modifications/amendments, and closeout. Guidance is subject to change. Due to
restrictions, NETL is still limited in the scope of activities that can be performed. Sources
for match of $62.7M have been identified and $143.8M is still needed. Initial award
effective 9/1/24. Kickoff meeting took place 3/19.
Awarded IIJA
Preventing Outages and Enhancing the Resilience of the Electric
Grid to States and Indian Tribes - Formula Funding FFY22-
FFY26 $ 64,022,556 15% $ 9,603,383 -$
On 3/10 received verbal communication that states are able to draw down funds on
existing awards and POs can approve projects. It is unknown when the remaining 2
years of funding will be released. AEA has receipt authority for $39.8M federal and
$7.2M match, additional match of $1.8M and $16.9M federal receipts in FY26 budget
but allocation is not available to apply for.
Awarded IIJA
Energy Efficiency Revolving Loan Capitalization Program - IIJA
40502 $ 4,782,480 0% $ - -$
Received verbal communication that grant was not paused on 3/4. On 3/10, Project
Officer stated she would send an email confirming the status of the program. Award
effective 7/1/24. AHFC will administer program.
Awarded IIJA State Energy Program Funding $ 3,661,930 0% $ - -$
Received verbal communication that grant was not paused on 3/4. On 3/10, Project
Officer stated she would send an email confirming the status of the program. Award
effective 7/1/22. Funding split 70% AEA and 30% AHFC.
Application
Pending IIJA Transmission Acceleration Grants (TAG) Program $ 2,731,311 0% $ - -$ AEA submitted grant request for transmission planning and siting.
Awarded IIJA Energy Efficiency and Conservation Block Grant - IIJA 40552b $ 1,627,450 0% $ - -$
Received verbal communication that grant was not paused on 3/4. On 3/10, Project
Officer stated she would send an email confirming the status of the program. Award
effective 10/1/23. Subawards have been issued for REVEEP.
Awarded IIJA DC 1825 / Kwethluk Emergency Generators Repairs and Replacem 350,000$ 20% $ 87,500 -$ Per Denali Commission email of 2/3/25 - DC fulfilling IIJA obligations
Awarded IIJA DC 1735 / Ruby Power Plant Leveling 200,000$ 20% $ 40,000 -$ Per Denali Commission email of 2/3/25 - DC fulfilling IIJA obligations
Awarded IJA DC 1761 / Tuluksak BFU M&I 200,000$ 0% $ - -$ Per Denali Commission email of 2/3/25 - DC fulfilling IIJA obligationsConcept
Paper
Pending IJA Energy Improvements in Remote and Rural Areas TBD 5-20%TBD TBD
4 concept papers submitted by AEA on 2/27/25 for Tok school biomass; Nome joint
utility systems solar; rural power systems; and Bethel-Oscarville line upgrade.
Application deadline August 28, 2025.
Awarded IRA
Greenhouse Gas Reduction Fund - Solar For All Competition -
IRA 134a $ 62,450,000 0% $ - -$
Received email 2/21 informing grantees that they may resume drawing down resources
in ASAP and project officers will reengage with grantees. 2/24 ASAP account now
“open”, and we were able to submit a reimbursement request. 2/28 Met with SFA
project officer, and he reiterated we have access to the funds via ASAP and strongly
suggested we continue work. Award effective 12/10/24.
Conditional
Award IRA Home Efficiency Rebate (formula funding) $ 37,293,071 0% $ - -$
On 3/10 received verbal communication that AEA should be able to draw down funds
and states should reference the special terms and conditions in the agreement.
Allocations published in ALRD 7/1/23. AEA received notice of conditional award for the
remaining $36,358,943 on 1/15/25. Awarded early administrative funds of $934,128 on
6/1/24. AHFC will administer program.
1 of 2
4/2/2025
Alaska Energy Authority
Federal Funding Tracker
Status Source Program Name
Award $ / Request
$
Required
Match %Required Match $
Remaining Match
$ Needed Comments
Conditional
Award IRA Home Electrification and Appliance Rebates (formula funding) $ 37,150,940 0% $ - -$
On 3/10 received verbal communication that AEA should be able to draw down funds
and states should reference the special terms and conditions in the agreement.
Allocations published in ALRD 7/1/23. AEA received notice of conditional award for the
remaining $36,222,284 on 1/16/25. Awarded early administrative funds of $928,655 on
6/1/24. AHFC will administer program.
Awarded IRA
Training for Residential Energy Contractors (TREC) - Formula
Funding $ 1,293,870 0% $ - -$
On 3/10 received verbal communication that AEA should be able to draw down funds
and states should reference the special terms and conditions in the agreement. AEA
received notice of award on 1/6/25. AHFC to administer the program.
Awarded Other
Defense Community Infrastructure Pilot - National Defense
Authorization Act
Black Rapids Training Site $ 15,602,648 0% $ - -$
Per email from OLDCC on 1/30, this program is not impacted by the EOs. Award
effective 9/1/22. AEA partnered with GVEA. $12.6M federal receipt authority approved in
FY24 and GVEA received additional $3M to bury line per DOD. Subaward issued.
Application
Pending Other
Watersmart Grants: Water and Energy Efficiency Grants for
FY2024 & 2025 Bureau of Reclamation No. R24AS00052 $ 5,000,000 100% $ 5,000,000 $ 5,000,000
AEA applied for part of the Dixon Diversion Project. Match not appropriated at this time
but source of match is identified.
Application
Pending Other High Energy Cost Grants - USDA RUS $ 3,000,000 0% $ - -$ Application submitted 2/28 for Kipnuk upgrades.
Awarded Other High Energy Cost Grants - USDA RUS $ 2,974,420 0% $ 1,601,610 -$
This program is not IIJA or IRA funded. About 900k remaining on grant, which is
encumbered and awaiting an invoice from the contractor
Awarded Other High Energy Cost Grants - USDA RUS $ 2,000,000 0% $ - -$ AEA received award letter on March 26, 2025.
Awarded Other Vehicle Technology Office FFY 2022 (ARED) $ 1,670,000 20% $ 417,500 204,737$
Received verbal confirmation from PO and supervisor that ARED is not funded through
IIJA or IRA, and not subject to the federal funding pause. Award effective 10/1/23. Partial
match to be provided by site partners.
Application
Pending Other
USFS Community Wood Energy and Wood Innovation Program
FY 2025 $ 500,000 100% $ 500,000 $ 500,000 AEA applied to fund re-design and construction of the Tok School CHP system.
Conditional
Award Other Energy Future Grant $ 496,725 0%-$ NA
There has been no communication received for this program in the past few months.
AEA received notice of award on 3/9/24. AEA partnered with AML for proposal to
evaluate energy permitting in 45 municipalities. Application was selected for award -
currently under negotiation.
Awarded Other EETF Microgrid Technology 250,000$ 50%250,000$ -$
Suspended in ASAP due to grant period ending 12/31/24. AEA will request grant
modification.
Awarded Other USFS Sustainable Wood Energy Systems 2019 $ 310,000 100% $ 155,000 -$ On 2/7 verbal confirmation from USFS that payments are not paused for this grant.
Application
Pending Other USFS Wood Innovation Grant FY 2025 $ 150,000 100% $ 150,000 150,000$
AEA applied for funding to complete the engineering design for biomass systems in
Elim, Galena, and BBNA.
Awarded Other USFS Sustainable Wood Energy Systems 2022 $ 112,500 100% $ 112,500 -$
On 2/7 verbal confirmation from USFS that payments are paused for this grant. Seeking
clarification from PO since the NOFO did not reference IIJA funding.
Total 458,031,186$ 227,638,198$ 150,885,215$
Suspended IIJA
National Electric Vehicle Infrastructure Program (NEVI) - Formula
Funding FFY22-FFY26 $ 52,415,294 20% $ 10,483,059 NA Program suspended. Two bills have been introduced to eliminate the program.
Notes: AEA has requested written notice from each project office regarding the status of each program. Programs in cells highlighted red are suspended. Programs in cells highlighted orange may be paused. If cells are highlighted blue, AEA has received
verbal notice that these programs are not paused. If cells are not highlighted a color, AEA has received written notice that grants are not paused or the applications/concept papers are pending and no awards have been issued at this time. Information in
yellow highlighted cells and in bold font is new information.
2 of 2
4/2/2025
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
TO: AEA Board of Directors FROM: Curtis Thayer, Executive Director DATE: April 1, 2025 RE: Office of Clean Energy Demonstration, Energy Improvements in Rural or Remote
Areas Grant Concept Papers
The Department of Energy, Office of Clean Energy Demonstration (OCED), issued a Funding
Opportunity for Energy Improvements in Rural or Remote Areas, for awards up to $50 million to
spur innovative, community focused, clean energy solutions for rural and remote communities.
Concepts papers were due on February 27, 2025, and full applications are due by August 28,
2025.
Alaska Energy Authority team compiled and submitted the following four (4) concept papers:
1. Tok School CHP Re-design and Build Project – This project will redesign and upgrade
the existing biomass combined heat and power system to fully integrate into a solar-
battery-multiport converter project.
Total Project Cost: $2,106,000
Funding Request: $2,000,000
Non-Federal Cost share: $ 106,000
2. Nome Joint Utility Systems – Utility-Scale Solar Farm – This project will redesign and
construct a 1MW solar farm to reduce reliance on diesel fuel, save ratepayers money and
reduce greenhouse gas emissions.
Total Project Cost: $4,211,000
Funding Request: $4,000,000
Non-Federal Cost share: $ 211,000
3. Rural Alaska Power Systems: Critical Tool Supply and Inventory – This project will
address critical and widespread deficiencies faced by rural Alaska electric utilities that do
not possess the basic tools needed for regular preventative maintenance in power
generation.
Alaska Energy Authority Page 2 of 2
Total Project Cost: $2,106,000
Funding Request: $2,000,000
Non-Federal Cost share: $ 106,000
4. Bethel to Oscarville Tie-line Upgrade – This project will upgrade the poles structures
and transmission line between the city of Bethel and village of Oscarville in Alaska.
Total Project Cost: $4,000,000
Funding Request: $3,800,000
Non-Federal Cost share: $ 200,000
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 TO: Alaska Energy Authority Board THRU: Curtis. W. Thayer, Executive Director
FROM: Karen Bell, RTO Program Manager
DATE: April 2, 2025
RE: Railbelt Transmission Organization (RTO) Update
The RTO held public meetings on February 14, March 7, and March 21, 2025. In its February 14th meeting, the governance committee elected officers for the RTO. The results of the officer
elections were MEA serves as Chair, GVEA serves as Vice Chair and AEA serves as the
Secretary/Treasurer. The next RTO public meeting is scheduled for April 18, 2025.
The CPCN application for the RTO and a petition for waiver were submitted to the Regulatory
Commission of Alaska (RCA) on December 20th, prior the January 1, 2025 statutory deadline. The RCA issued U-24-042(1) granting the motion for exemptions and waivers filed by the RTO,
inviting participation by the Office of the Attorney General Regulatory Affairs and Public
Advocacy Section (RAPA) and intervention by interested persons, scheduling a prehearing
conference, and designating a Commission Panel and Docket Manager. The RTO, represented by
its legal counsel Ms. Tina Grovier from Stoel Rives, participated in the prehearing conference
held on February 18th. The RCA issued U-24-042(2) adopting a procedural schedule for the matter, including proposed hearing dates of April 14th through April 15th. On March 13th, RAPA and the RTO filed a stipulation of settlement and requested the RCA accept or approve the stipulation in its entirety. The Alaska Public Interest Research Group’s (AKPIRG) was not a party to this stipulation. On March 13th, AKPIRG filed a motion for summary disposition on application of the Open Meetings Act to RTO subcommittees. Responses to that motion are due by April 7, 2025. The RCA will issue a final decision in this docket no later than June 18th.
The RTO Working Group continues to meet regularly to develop recommendations to the RTO
for establishing an Open Access Transmission Tariff (OATT) to achieve the purposes of AS
44.83.700 - 44.83.720. The statutory deadline for the RTO to submit an OATT to the RCA is July
1, 2025.
AEA -OWNED ASSETS:
KEY UPDATES
Bryan Carey, PE
Director of Owned Assets
AEA Board of Directors
April 17, 2025
ALASKA ENERGY AUTHORITY
Railbelt Upgrade Projects
AEA-Owned Assets: Key Updates | AEA Board of Directors | April 17, 2025 2
Grid Resilience and Innovation
Partnerships (GRIP): HVDC Line
▪It provides a redundant pathway
between the Southern (Kenai
Peninsula) and Central (Anchorage and
Mat-Su) Regions
▪Thus, eliminating the single-point-of-
failure inherent in the previous system
(the system will still be subject to
single point of failure between Willow
and Healy)
▪Allows for more renewable power to
be added to the grid and distributed
across the Railbelt
▪Increases the ability to share power
between the Southern, Central, and
Northern Regions of the Railbelt,
allowing the most economical power
to be used at all times
AEA secured $206.5 million for GRIP Topic Area 3: Grid Innovation 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.
High-voltage direct current (HVDC) submarine cables will be constructed to
serve as a parallel transmission route from the Kenai Peninsula to Anchorage.
$413 Million (206.5 Million Federal and $206.5 Million Alaska Match)
The project addresses several challenges facing Alaska’s Railbelt regions:
AEA-Owned Assets: Key Updates | AEA Board of Directors | April 17, 2025 3
AEA has made significant progress on several key
project deliverables, including:
✓Preliminary Cost Estimate
-Construction costs range from $358M-$390M
✓Initial Project Plan and Schedule
-Draft issued in December
✓Critical Environmental Issues Analysis
-Draft issued in December
✓HVDC Conceptual Design
-200MW Transfer Capacity
-Bipole preferred over Monopole
✓HVDC Cable Preliminary Design
✓Issuance of RFIs for Cable and Converter Stations
March 2025 Update
4
March 2025
Update
(continued)AEA shared draft reports with Railbelt
Utility members in January 2025 —key
takeaways included:
▪Consensus 200 MW of transfer capacity
is sufficient.
▪Preference for bipole configuration over
monopole, despite a 25% cost
difference.
▪Further studies needed on the Soldotna-
Bernice Lake link.
▪Additional review required for alternate
routes in the Southern Intertie study.
Request for Information:
▪Cable and Converters
▪Date: Issued 02/14/2025
▪Several responses received, several
requested time extensions
▪Wide range of costs, lower end were
generally consistent with initial project
assumptions
Stantec report to be issued in mid April
5
Schedule
▪The statutory period for the project is eight (8) years with the following schedule:
-September 2024 –Award
-First Quarter 2025 –Develop a preliminary work plan and identify critical environmental issues
-Second Quarter 2025 –Initial design for the cable and converters
-Fourth Quarter 2025 –Commence Full Design and Permitting
-July 2027 –Complete National Environmental Policy Act (NEPA) Process
-January 2028 to December 2029 –Long Lead Items
-January 2030 to December 2031 –Construction
AEA-Owned Assets: Key Updates | AEA Board of Directors | April 17, 2025 6
Dixon Diversion Project
$342 Million
AEA is studying the Dixon Diversion Project to optimize the
Bradley Lake Hydroelectric Project's energy potential. Like the
West Fork Upper Battle Creek Diversion Project, the Dixon
Diversion Project would divert water from Dixon Glacier 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
(the equivalent of up to 30,000 homes).
▪Estimated to offset 1.5 billion cubic feet of natural gas per
year in Railbelt power generation (equal to 7.5 percent of
Alaska's unmet natural gas demand projected for 2030).
▪Estimated completion is 2031.
7
▪The Dixon Diversion Project would
be largest renewable energy project
in Alaska since Bradley Lake was
completed in 1991
▪Project components include:
-Diversion dam at toe of Dixon
Glacier
-4.7 mile long, 14’ diameter tunnel to
convey water
-Raise of Bradley Dam (7’, 14’, or 28’)
-1 mile of new access road and
installation of 3 phase power
Project Components
8
FERC License Amendment Process Status
Responsible Party Activity Dates
AEA/Stakeholders Initial Agency Consultation Jan -Mar 2022
AEA Conduct 2022 Preliminary Studies Summer 2022
Stage 1: Initial Consultation Document (ICD)
AEA File ICD, Request for Non-federal Representative, & Newspaper Notice Apr 2022
FERC FERC Issues Notice of Amendment Accepted May 2022
AEA Provide Stakeholders with Notification of Joint Meeting May 2022
AEA/Stakeholders Hold Joint Agency/Public Meeting and Site Visit Jun 14-15, 2022
FERC/Stakeholders Comments on ICD/ Proposed Studies Due Aug 14, 2022
Stage 2: Study Planning and Implementation
AEA Distribute Draft Study Plans Nov 2022
Stakeholders Comments on Draft Study Plans Dec 2022
AEA Paused Amendment Process and Refined Project Design Mar 2023 –Feb 2024
AEA/Stakeholders Project Update and Study Plan Meetings Mar -Apr 2024
AEA/Stakeholders Implement Year 1 Studies 2024
AEA/Stakeholders 2024 Study Reports & NHPA Section 106 Consultation Meetings Jan -Feb 2025
Stakeholders Comments on 2024 Study Results Mar 2025
AEA/Stakeholders Consultation with agencies, Tribes, stakeholders Late Mar 2025
AEA Implement Year 2 Studies and Review Study Results 2025
AEA/Stakeholders Consultation with agencies, Tribes, stakeholders 2025
AEA File Draft Amendment Application Jan 2026
AEA File Final Amendment Application Spring 2026
9
▪Environmental
-Refined understanding of sockeye and coho run timing and
magnitude
-Completed LiDAR mapping of Martin River to build
hydraulic models and estimate fish passage at various flows
▪Geology
-Discovered competent rock at tunnel inlet and outlet
-Similar to original Bradley power tunnel —good
analog data
▪Hydrology
-Estimated energy from Dixon reduced ~1.5%, due to low
water years in 2023/2024 and updated correlation factors
▪Project Cost
-Verified project cost with Class 4 independent estimate in
2024
-$356MM, similar to engineers estimate of $342MM
2024 Highlights
10
▪Hosted initial Board of Consultants (BOC) meeting February 4, 2025
-Attendees included AEA, BOC, contractors, and Federal Energy
Regulatory Commission (FERC) representatives
-Discussed and presented aspects of project design and engineering
studies
-BOC comprised of top experts from around the world and will
consult project through completion
-Received comments on:
o Geotechnical Drilling Report
o Drilling Program Plan
o Seismic hazard analysis
o Probable Maximum Precipitation studies
▪Presented to resource agencies Jan-Feb 2025
-Soliciting and responding to comments on 2024 study reports and
2025 study plans
-Reports posted to Dixon webpage:
https://www.akenergyauthority.org/dixon-diversion-project
Consultation
AEA-Owned Assets: Key Updates | AEA Board of Directors | April 17, 2025 11
▪Environmental
-Continue year 2 of fish, wildlife,
and cultural studies
▪Geology
-Drilling Program Plan (DPP) to
include holes on and around dam
and geophysical surveys
-Reservoir rim stability analysis
-Borrow source investigation
▪Hydrology
-Martin River stream gaging
-Refinement of energy estimates
-Probable maximum precipitation
(PMP) study
-Probable maximum flood (PMF)
study
▪Seismic
-Site specific seismic hazard analysis
using updated Alaska ground motion
models
▪Engineering
-Advance engineering to 30%
design for FERC license
-Progress engineering on dam raise,
tunnel, intake and outlet portals,
access road, and diversion dam
▪Licensing
-Prepare license articles for
submission of Draft License
Amendment Application (DLAA) in
early 2026
-Develop Protection, Mitigation,
and Enhancement (PME) measures
2025 Upcoming Activities
AEA-Owned Assets: Key Updates | AEA Board of Directors | April 17, 2025 12
Licensing and
Construction Schedule
▪2024 Year 1 Studies and engineering
▪2025 Year 2 Studies and engineering
▪2026 Draft & Final Amendment Application
▪2027 EA/EIS
▪2028 construct access road, 3-phase power
▪2029 Start TBM operations, construct diversion dam
▪2030 Tunnel and diversion complete, first water
▪2031 complete dam raise
13
Phase 1: Sterling to Quartz Creek Rebuild
October 2024-February 2025
AEA-Owned Assets: Key Updates | AEA Board of Directors | April 17, 2025 14
Construction Schedule
Phase 1
8 Miles Sterling Substation to
KNWR boundary.
(Completed March 2025)Phase 2
17 Miles Kenai National
Wildlife Refuge
(Construction 2026-2027)Phase 3
14 Miles Russian River to
Quartz Creek Substation
(Construction 2027-2028)
AEA-Owned Assets: Key Updates | AEA Board of Directors | April 17, 2025 15
▪Rebuild project consists of rebuilding the
existing 115kV transmission line and
towers/poles to a 230kV line and
towers/poles.
▪Project is designed to be operated at
230kV but will be operated at 115kV until
completion of future upgrades.
▪The line has reached its expected life span
of 50 years and consists of primarily
wooden structures.
▪The new rebuilt line will consist of primarily
steel structures that will be more resilient
to unscheduled outages.
The image depicts the
installation of a new
pile-driven foundation
for the structure.
Welder installing
the pile cap for the
structure, with two piles
supporting each one.
Rebuilding for Resilience
AEA-Owned Assets: Key Updates | AEA Board of Directors | April 17, 2025 16
▪The winter of 2024-2025 in Alaska brought
unique challenges.
▪Agency permitting required winter
construction, with conditions stipulating
12 inches of snow and frost for work to
proceed on the right-of-way.
▪A 90-ton crane was needed for the
installation of piles and towers.
▪To protect sensitive areas, large wooden
timber mats were placed to provide crane
access without damaging the ground.
The Problem:
Unfrozen Swamps
(January 2025)
The Solution:
Matting
(industrial grade)
Phase 1 Construction
Challenges
17
▪February 28, 2025 the new circuit was
energized at the original voltage of 115kV.
▪Once all transmission lines between
Anchorage and Bradley Lake Hydroelectric
Project are upgraded, the transformers will
be replaced, and the circuit will be
permanently energized at 230kV.
Completed Dead
End/Corner Structure
A successful completion
of 8 miles of a 39 mile
transmission line
Phase 1 Completion
AEA-Owned Assets: Key Updates | AEA Board of Directors | April 17, 2025 18
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 WWW.AKENERGYAUTHORITY.ORG
MEMORANDUM
TO: Curtis W. Thayer, Executive Director
FROM: Bill Price, P.E., Senior Infrastructure Engineer THROUGH: Bryan Carey, P.E., Director of Owned Assets DATE: February 27, 2025 (updated April 2nd, 2025) RE: Avalanche Damage to Alaska Intertie – Structure 616 Current Status
• On January 24th, Alaska Intertie Structure 616 (located about 8 miles north of Cantwell)
was struck and received significant damage when a large boulder was brought down by
an avalanche.
• The structure base section will need to be replaced, as it was damaged beyond repair.
• The utilities have found a similar spare structure in storage; however, it is not an exact
spare. The engineers have not yet determined if it can be modified to replace the damaged section, though it is unlikely to be viable.
• Crews were able to weld support steel as a temporary support for that damaged section. Considering the damage however, these supports are not adequate to serve as a long-term repair.
• Had this structure collapsed, it is likely it would have also damaged or brought down a few additional structures.
Repairs
• GVEA has contracted with EPS to complete the design and procurement as soon as possible. The replacement timing will depend on steel procurement times, as the repair requires a new base section. Replacement will likely occur in July 2025.
• Emergency repairs have already been completed and are anticipated to have cost approximately $50,000. This cost will be applied to the FY25 IMC Budget.
• Preliminary estimates for the permanent repair are approximately $480,000 and costs are
expected to extend into the FY26 IMC Budget.
Disaster Declaration
• The February 7th “January 2025 Interior Winter Storm Disaster Declaration” issued by the
Governor was for AkDOT, and does not apply to the Intertie.
• AEA is working with GVEA to submit a request for a new declaration through the State
Emergency Operations Center.
Photos:
• See following images:
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
MEMORANDUM
TO: Alaska Energy Authority – Board of Directors
THRU: Curtis. W. Thayer, Executive Director
FROM: Conner Erickson, AEA Planning Director
DATE: March 28th, 2025
RE: Net Metering Incentive Payment Pilot Program
Background
The Governor’s office has requested that the Alaska Energy Authority (“AEA”) create, implement,
and administer a Net Metering Incentive Pilot Program (“Program”). The Program is to be
established to achieve the following purposes:
I. Provide economic and financial incentive for utility members to enroll in those net
metering programs as offered through their local Program-participating utility, via an
accelerated rate of return on their net-metering investments through potential offsets to
their monthly electric utility bills through credits/payments earned under their net
metering program; and
II. Increase the nameplate capacity of behind-the-meter, customer-owned, utility-grid-
interconnected infrastructure through the enrollment of new net metering members or
the augmenting of existing nameplate capacity by existing net metering members; and
III. Offset the consumption of available natural gas supplies within the Cook Inlet basin, and;
IV. Provide for reduced volatility in utility load demand, including instances of short-
duration, high-peak demand owing to increasing consumer adoption of power-intensive
assets including electric vehicles, electric heat pumps, and electric boilers; and
V. Gain greater understanding as to the long-term impacts to utility grid infrastructure
owing to increased net metering program participation.
To achieve those purposes stated above, the Program is to be established as a pilot program for
the issuance of Program Incentive Payments (“Payments”) directly to the Participant to provide
increased compensation, on a dollar-per-kilowatt-hour basis, to those members of the
Participant’s existing net-metering program, for the net energy, on a kilowatt-hour basis, which
members provide to the Participant, in excess of the energy received by those members from
the Participant, for each monthly billing period, as required under Alaska Administrative Code
(“AAC”) 3 AAC 50.930(a)(2).
Payments to entities eligible under the Program to provide such increased compensation are the
product of (i) the net difference, on a dollars per kilowatt-hour basis, between the non-firm
power purchase rate paid by the Participant to their net metering program members, as
required under 3 AAC 50.930(a)(2), generally referred to as the Small Facility Power Purchase
Alaska Energy Authority Page 2 of 2
Rate (‘SFPPR’), and (ii) the Participant’s full-retail residential service rate as stated in its currently
effective Regulatory Commission of Alaska (“RCA”)-approved operating tariff. A sample
incentive payment calculation is provided in Table 1 below for reference.
Table 1: Sample Program Payment Calculation for Participant, Month X
Item ID Item Description Formula Amount
(A)
Net metered energy supplied to Participant by its enrolled net metering members, in
excess of the energy supplied by Participant to those same members, for month X
(kilowatt-hours, kWh), as stated in 3 AAC 50.930(a)(2).
- 15,000 kWh
(B)* Participant net metering non-firm power purchase rate under current operating tariff ($
per kWh), as required under 3 AAC 50.930(a)(2). - $0.05
(C) Participant full-retail residential rate under effective operating tariff ($ per kWh) - $0.25
(D) Net difference in Participant’s net-metering non-firm power purchase rate and its full-
retail residential rate under its effective electric service tariff (C) - (B) $0.20
(E) Program Payment requested by / paid to Participant for Month X (A) * (D) $3,000.00
*The non-firm power purchase rate is generally referred to as the Small Facility Power Purchase Rate (SFPPR) in a Participant’s
operating tariff.
Program Funding
The Program would be funded under a Reimbursable Services Agreement (“RSA”) between AEA
and the Governor’s office. It is understood that $1 million is to be made available for Program
payments AEA’s cost of administration. The Program would end upon the exhaustion of
available Program funds, or at a date to be determined under agreement.
Program Eligibility and Participation
All electric utilities operating under a Certificate of Public Convenience and Necessity (“CPCN”)
as issued by the RCA, and which operate a net metering program as required under 3 AAC
50.900 – 3 AAC 50.949 are eligible to participate in the Program. Participation in the Program is
on an at-will / voluntary basis. Enrollment in the Program is effectuated via the execution of a
Program-Participant Agreement (“Agreement”) between AEA and the eligible entity.
Current Status
AEA is currently working internally to draft all necessary program documentation, and execute
the necessary RSA(s) and Memorandum of Agreement with the Governor’s Office to implement
the Program. A draft of the Program Agreement is currently under review by AEA’s legal
counsel. Upon conclusion internal review, AEA plans to disseminate this Program
documentation with prospective eligible entities to ensure Program alignment, especially as
related to timing of submission of requests for payment, reporting requirements and other
matters of Program compliance. Upon this feedback and necessary review, AEA will move to
effectuate participation in the Program through the execution of necessary Program
Agreements.
Supplemental Information
A copy of the “Net Metering Incentive Payment Pilot Program Overview” is provided as an
attachment to this memo for reference.
PAYMENTS
RECEIVED
LATE FEES
RECEIVED
INTEREST
+
LATE FEES
($661,749) $2,541 $311,173
15
TOTAL # OF
PPF LOANS
$0 0.000%
TOTAL # OF
DELINQUENT LOANS
LOANS DELINQUENT
AMOUNT ($)
% OF DELINQUENT
LOANS ($)
Loan Commitments $490,143.78
Total Loan Program $40,844,902.88
0
LOAN PROGRAM SUMMARY
Outstanding Loans $30,625,556.82
Uncommitted Cash Balance $9,729,202.28
AEA Power Project Fund $31,287,306 - $30,625,557 $308,632
FISCAL YEAR-TO-DATE LOAN PORTFOLIO ACTIVITY (07/01/2024 - 2/28/2025)
LOAN ACTIVITY EARNINGS
LOAN CATEGORY STARTING
BALANCE
FUNDS
DISBURSED
ENDING
BALANCE
INTEREST
RECEIVED
LOAN DASHBOARD REPORT For Board Meeting on 4/17/2025
AEA POWER PROJECT LOAN FUND
Page 1
TOTAL ($)
$2,158,462
$372,069
$710,058
$7,996,373
$17,826,087
$2,052,652
$31,115,701
TRANSMISSION 1 BIOMASS $50,132.81
BIOMASS 1 WIND $1,054,219.58
WIND 2 DIESEL $1,117,978.99
SOLAR 3 TRANSMISSION $1,966,667.00
DIESEL 4 SOLAR $5,725,631.24
HYDRO 4 HYDRO $21,201,070.98
AEA PPF LOANS BY PROJECT TYPE AEA PPF LOANS BY PROJECT TYPE - BALANCE
(NEW & OUTSTANDING)
PROJECT TYPE # OF PROJECTS PROJECT TYPE BALANCE
TOTAL $30,625,557 $490,144 - 15
YUKON-KOYUKUK/U
TANA $1,562,509 $490,144 - 3
SOUTHEAST $17,826,087 - - 1
RAILBELT $7,996,373 - - 5
- - 1
LOWER YUKO-
KUSKOKWIM $710,058 - - 2
AEA POWER PROJECT FUND LOANS BY ENERGY REGION & PROJECT TYPE
OUTSTANDING BALANCES & NEW ACTIVITY
ENERGY REGION
AEA PPF
LOAN
BALANCE
REMAINING
LOAN
COMMITMENTS
NEW
APPLICATIONS
IN PROCESS
# OF AEA PPF
LOANS
ALEUTIANS $2,158,462 - - 3
BRISTOL BAY $372,069
Page 2
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: April 4, 2025
TO: AEA Board of Directors
FROM: Leonard Robertson, Chief Information Officer
THROUGH: Curtis Thayer
RE: Update on Recent TIT Projects and Initives
Current Environment: The current IT environment at AEA is primarily on-premise and anchored to the current building. Both AEA and its sister agency, AIDEA, have traditionally maintained a mixed environment, with the workforce anchored to assets in the facility. This setup challenges AEA operational resilience and ability to maintain an agile posture on office location.
Strategic Shift: With the expanding workforce and limited site capacity, the AEA leadership team and IT team are coordinating a strategic shift to leverage cloud resources and simplify IT operations. This shift aims to create flexibility for AEA workspace, allowing the agency to expand office space beyond its current location with minimal engineering as the migration progresses.
The timeline and approach have been modified to acknowledge the potential impact on operations in the event of a severe Ash Cloud impact on the current building infrastructure.
Current IT Projects:
1. Phone System Upgrade:
• Replacement of the current phone system with a cloud VOIP provider.
• Benefits include flexibility to change office sites, enable remote operations, and use agnostic equipment while reducing reliance on traditional on-premise architecture. 2. Email System Migration:
• Transition to a cloud-based email system.
• This will eliminate the need for on-premise equipment and convert equipment and maintenance costs to predictable usage-based operating costs.
Alaska Energy Authority Page 2 of 3
• The cloud-based service will provide increased agility and redundancy in operations, which would be costly to replicate on-premise.
• IT will work with board members to update their email accounts while existing emails are being migrated. 3. ERP/Accounting System Upgrade:
• Modification of the existing ERP project to uplift Navision to Sylogist.
• The project has been optimized to skip an on-premise lift and immediately
transition AEA accounting operations to its own instance on the cloud, completely separated from AIDEA. 4. Unified Identity System:
• Transition to a unified identity system fully segmented and contained in AEA's own Microsoft cloud tenant and account.
• All existing IT operations will be streamlined to a modern cloud service.
• On-premise file servers and active directory will be retired.
• The new licensing and service structure will provide a major security upgrade to AEA. 5. On-Premise Servers to Cloud Optimization:
• Conversion of many servers and services to Software as a Service (SaaS) or Platform as a Service (PaaS) integrated into the unified AEA identity.
• This will enhance flexibility, reduce maintenance costs, and improve scalability. 6. Security Platform Upgrade:
• Upgrade to a security platform that provides skillset and coordination compatibility with the rest of the State's Security Office.
• This will ensure a unified and robust security posture across all operations.
Priorities: Throughout these various projects, AEA has prioritized separating its operations and costs from AIDEA while maintaining an efficient and more secure unified platform. The key priorities include:
• Minimizing costs
• Converting chaotic capital costs to operational costs
• Unifying toolsets
Alaska Energy Authority Page 3 of 3
• Upskilling the workforce
• Creating worksite flexibility
• Simplifying the workforce experience
• Increasing workforce agility and efficiency
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
January 30, 2025
The Honorable Gary Stevens
President of the Senate Alaska State Legislature
State Capitol Room 111
Juneau, Alaska 99801
Dear President Stevens and Speaker Edgmon,
Pursuant to Alaska Statute AS 42.45.045(d)(3), the Alaska Energy Authority (AEA), with
concurrence from the Renewable Energy Fund Advisory Committee (REFAC), is pleased to
provide its selection of Round 17 Renewable Energy Fund (REF) recommendations to the 34th Legislature for their consideration of project funding in the Fiscal Year 2026 capital budget.
With this letter, the REFAC advances 18 recommended projects, for a total grant request of $21.2 million to the Legislature, for Fiscal Year 2026 funding consideration. The Governor’s Fiscal Year 2026 proposed capital budget includes $6.3 million for REF Round 17 grant funding. With an appropriation of $6.3 million, this would fully fund the top six projects as recommended. Should the Legislature seek to fully fund those remaining 12 projects as recommended by the REFAC, an additional $14.9 million would need to be added to the Governor’s proposed REF appropriation.
From 2008 to 2025, appropriations totaling nearly $327 million have been allocated in support
of REF projects. AEA extends its sincere appreciation for the Legislature’s continued support of
the REF program, including its appropriation of $10.5 million in Fiscal Year 2025, funding five
projects as recommended in Round 16. The REF remains a stalwart program in the state of
Alaska’s energy development toolkit, with over 100 REF funded projects currently in operation,
and over 50 in development, across all regions of the state. In addition, this state funding has
leveraged over $300 million from federal and local sources to develop projects designed to
reduce and stabilize the cost of energy in Alaska. As evidence of the REF’s efficacy in advancing
renewable energy projects throughout the state of Alaska, an independent impact analysis commissioned by AEA and conducted by a third-party research consultancy, completed in December 2023, reported that the REF program has offset approximately 85 million gallons of diesel fuel (e.g. five percent of all petroleum consumed in Alaska in 2021), 2.2 million cubic feet of natural gas, and 1,063,500 net metric tons of carbon dioxide since its inception in 2008.
As the REF program has matured, the quality of the proposed projects has improved, and
knowledge and technology transfers have enhanced the design, construction, and operation of
renewable energy projects across Alaska’s diverse climates and geographical terrain. The REF
program remains unique in its ability to fund projects across all development phases, serving as
The Honorable Bryce Edgmon Speaker of the House
Alaska State Legislature State Capitol Room 208
Juneau, Alaska 99801
AEA Rank Community Project Name Applicant Name TechnologyRecommended FundingEnergy RegionSenate Dist.House Dist.1 Pelican Pelican Hydro Relicensing Project, Restoration, Repair City of Pelican, Pelican Utilities Hydroelectric 650,474$ Southeast A 22NaknekNaknek Solar PV on Cape SuwarofNaknek Electric Association, Inc. Solar $ 3,137,848 Bristol Bay S 373SkagwayGoat Lake Hydro Storage Expansion StudyGoat Lake Hydro, Inc. Hydroelectric $ 121,250 Southeast B 34KwethlukNuvista Kwethluk Wind and Battery Project CompletionNuvista Light and Electric Cooperative Incorporated Wind $ 738,979 Lower Yukon Kuskokwim S 385 QuinhagakQuinhagak Battery Energy Storage System ProjectAlaska Village Electric Cooperative, Inc. Storage $ 443,956 Lower Yukon Kuskokwim S 386NenanaNenana Biomass District Heat System, Final PhaseCity of Nenana Biomass $ 1,223,000 Railbelt R 367 KongiganakKongiganak 100 kW Solar Energy ProjectPuvurnaq Power Company Solar $ 720,453 Lower Yukon Kuskokwim S 388 RailbeltRailbelt Wind Diversification Alaska RenewablesAlaska Renewables LLC Wind $ 2,000,000 Railbelt Various Various9HomerHomer Energy Recovery ProjectCity of Homer Hydroelectric $ 280,000 Railbelt C 610 AtmautluakAtmautluak ETS Installation, Integration and CommissioningAtmautluak Tribal Utilities Storage $ 286,227 Lower Yukon Kuskokwim S 3811 Ketchikan, Petersburg, WrangellSoutheast Alaska Grid Resiliency (SEAGR)Southeast Alaska Power Agency (SEAPA) Hydroelectric $ 4,000,000 Southeast A 1 & 212 ChevakChevak Battery Energy Storage System ProjectAlaska Village Electric Cooperative, Inc. Storage $ 968,644 Lower Yukon Kuskokwim S 3813 Pedro BayKnutson Creek Hydro Project ConstructionPedro Bay Village Council Hydroelectric $ 400,000 Bristol Bay S 3714 AkiachakAkiachak Native Community 200 kW Solar Energy ProjectAkiachak, Ltd Solar $ 67,833 Lower Yukon Kuskokwim S 3815 NomeNJUS Solar Nome Banner Ridge Solar FarmNome Joint Utility System Solar $ 4,000,000 Bering Straits T 3916 MEA service areaHunter Creek Hydroelectric Feasibility Study ProjectMatanuska Electric Association Hydroelectric $ 1,280,500 Railbelt M 2517 ChignikChignik Hydroelectric Power SystemCity of ChignikHydroelectric $ 883,012 Bristol Bay S 3718 SterlingSterling Solar ProjectUtopian Power LLC Solar $ 12,500 Railbelt D 8TOTAL21,214,676$ *If appropriated by the Legislature and approved the Governor, this funding would become effective July 1, 2025 for inclusion in the budget for Fiscal Year 2026.**Projects highlighted in blue are those projects to be funded under the REF allocation in the Governor's Fiscal Year 2026 proposed capital budgetAlaska Energy Authority - Renewable Energy Fund - Round 17 - Recommended Projects to Legislature
REDUCING THE COST OF ENERGY IN ALASKA
Renewable Energy Fund
Round 17
Status Report
Alaska Energy Authority —
Renewable Energy Fund –Round XVII
REDUCING THE COST OF ENERGY IN ALASKA
SAFE,
RELIABLE, &
AFFORDABLE
ENERGY
SOLUTIONS
Alaska State Legislature
January 2025
REDUCING THE COST OF ENERGY IN ALASKA 2
SAFE,
RELIABLE, &
AFFORDABLE
ENERGY
SOLUTIONS
Table of Contents REF Overview Page 3
REF Statutory Guidance Page 4
REF Evaluation Process Summary Page 5
REF Funding Limits Page 9
Proposed REF Capitalization for Round 17 (FY2026)Page 10
Recommended Applications Summary Page 11
Applications Forwarded for Legislature’s Decision on Funding Page 13
Partial Funding Recommendations Page 15
REDUCING THE COST OF ENERGY IN ALASKA
Renewable
Energy Fund (REF)
Overview
Established in 2008, the REF is a unique and
robust competitive grant program, which provides
critical financial assistance for statewide
renewable energy projects. The REF’s sunset date
provision was repealed with House Bill 62, signed
into law by Governor Dunleavy on May 25, 2023.
$327 million in REF
appropriations by the
State.
100+ operational projects,
53 in development, and 5
projects funded in FY25.
The 33rd Alaska State
Legislature appropriated
$10.5 million for 5 projects
recommended by AEA and
approved by the REF
Advisory Committee.
The REF funds projects across
all development phases, serving
as a catalyst for the continued
pursuit of integrating proven
and nascent technologies
within Alaska’s energy portfolio.
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 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.
5
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 2 evaluation, 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.
6
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.
7
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 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 reg ion, regional rank, and statewide rank.” This portion of the evaluation process is conducted by AEA staff in conjunction with sol icitation of advice from the Renewable Energy Fund Advisory Committee (REFAC). As statutorily required per AS 42.45.045 and set forth i n 3AAC 107.660, the authority is to solicit advice from the REFAC concerning making a final list / ranking of eligible projects.
The following items are evaluated as part of the stage four evaluation, as required per 3 AAC 107.660:
•Cost of energy burden = [HH cost of electric + HH heat cost] ÷ [HH income]
8
Cumulative through Round 16
Total Round
1-16 Funding Cost of Power Allocation Population Even Split
Energy Region Grant Funding % Total
Cost burden (HH
cost/HH income)
Allocation cost of
energy basis
Additional funding needed
to reach 50%
% of target
allocation % Total
Allocation per capita
basis
Allocation per region
basis
Aleutians $18,424,940 6%13.50%$28,394,207 ($4,227,837)65%1%$3,348,662 $27,422,307
Bering Straits $23,486,724 8%16.18%$34,017,155 ($6,478,146)69%1%$4,088,861 $27,422,307
Bristol Bay $17,590,323 6%15.99%$33,620,027 ($780,310)52%1%$2,868,848 $27,422,307
Copper River/Chugach $28,047,612 9%10.23%$21,512,838 ($17,291,193)130%1%$3,319,823 $27,422,307
Kodiak $16,659,519 6%6.96%$14,632,449 ($9,343,294)114%2%$5,311,382 $27,422,307
Lower Yukon-Kuskokwim $39,888,116 13%21.01%$44,170,624 ($17,802,804)90%4%$10,825,473 $27,422,307
North Slope $1,251,859 0%2.56%$5,388,828 $1,442,555 23%1%$4,062,948 $27,422,307
Northwest Arctic $32,841,133 11%16.94%$35,621,898 ($15,030,184)92%1%$3,149,297 $27,422,307
Railbelt $35,226,299 12%5.72%$12,036,080 ($29,208,260)293%77%$233,081,400 $27,422,307
Southeast $66,251,014 22%8.23%$17,303,821 ($57,599,103)383%10%$29,575,387 $27,422,307
Yukon-Koyukuk/Upper Tanana $20,941,945 7%26.13%$54,947,446 $6,531,777 38%1%$2,013,293 $27,422,307
Statewide $1,035,888 0%0.00%
TOTAL $301,645,374 100%$301,645,374 100%$301,645,374 $301,645,374
REDUCING THE COST OF ENERGY IN ALASKA
REF Funding Limits
REF Round XVII 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 XVII 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.
9
REDUCING THE COST OF ENERGY IN ALASKA
Proposed REF Capitalization for FY2026 / Round XVII
The State of Alaska FY2026 proposed capital budget allocates $6.3 million for REF Round 17 grant funding of recommended projects, fully funding the top 6 projects.
The current list of 18 recommended projects yields a total grant request of $21,214,676. With the proposed REF budget of $6.3 million, there would be insufficient funding to cover all current Round 17 projects as recommended. An additional appropriation of $14.9 million would need to be made to fund all of the current Round 17 recommendations.
The table to the right provides historical REF program funding from program inception through FY2025.
In the FY2025 capital budget, $10.5 was approved in support of the top five projects as recommended in REF Round 16, resulting in REF appropriations in excess of $10 million for the past three fiscal years.
10
Legislative Appropriation Fiscal Year
100,001,000$ FY2008
25,000,000$ FY2009
25,000,000$ FY2010
36,620,231$ FY2011
25,870,659$ FY2012
25,000,000$ FY2013
22,843,900$ FY2014
11,512,659$ FY2015
-$ FY2016
-$ FY2017
(3,156,000)$ FY2018 - RPSU Reappropriation
11,000,000$ FY2019
-$ FY2020
-$ FY2021
4,750,973$ FY2022
15,000,000$ FY2023
17,052,000$ FY2024
10,521,836$ FY2025
327,017,258$ TOTAL (excl. operating appropriation)
REDUCING THE COST OF ENERGY IN ALASKA
There are 18 recommended applications, totaling a request of $21.2 million.
Round XVII –Recommended Applications Summary
11
Applications by Energy Region No.of Applications REF Funds Requested
Bering Straits 1 $ 4,000,000
Bristol Bay 3 $ 4,420,860
Lower Yukon-Kuskokwim 6 $ 3,226,092
Railbelt 5 $ 4,796,000
Southeast 3 $ 4,771,724
Total 18 $21,214,676
Applications by Technology No.of Applications REF Funds Requested
Biomass 1 $1,223,000
Hydroelectric 7 $ 7,615,236
Solar 5 $ 7,938,634
Storage 3 $ 1,698,827
Wind 2 $ 2,738,979
Total 18 $21,214,676
REDUCING THE COST OF ENERGY IN ALASKA
Round XVII Geographical Distribution of Recommended Applications
12
REDUCING THE COST OF ENERGY IN ALASKA
Applications Forwarded to the Legislature for a Decision on Funding
13
*If appropriated by the Legislature and approved the Governor, this funding would become effective July 1, 2025 for inclusion in the Fiscal Year 2026 budget. Projects above orange line denote those currently funded in Fiscal Year 2026 Proposed Capital Budget.
Please see related summary report for details concerning the evaluation and description of the individual applications.
Application
No.Applicant Project Title Phase Energy Region
Election
District Technology Community
Grant Funds
Requested
Matching
Funds
Stage 3
Score
Benefit /
Cost Ratio HEC
Region
Rank
State
Rank Funding Level
Rec. Funding
Amount ($)
17006
City of Pelican, Pelican
Utilities
Pelican Hydro Relicensing
Project, Restoration, Repair
Final Design &
Permitting, Construction Southeast 2-A Hydroelectric Pelican $ 650,474 $ 50,000 76 1.63 $6,374 1 1 Full Funding $ 650,474
17014
Naknek Electric
Association, Inc.
Naknek Solar PV on Cape
Suwarof Construction Bristol Bay 37-S Solar Naknek $ 3,210,000 $ 900,000 74 0.57 $9,551 1 2 Partial Funding $ 3,137,848
17010 Goat Lake Hydro, Inc.
Goat Lake Hydro Storage
Expansion Study Reconnaissance Southeast 3-B Hydroelectric
Skagway, Haines,
Dyea, Klukwan $ 121,250 $ 52,250 71 0 $6,371 2 3 Full Funding $ 121,250
17002
Nuvista Light and Electric
Cooperative Inc
Nuvista Kwethluk Wind and
Battery Project Completion Construction
Lower Yukon-
Kuskokwim 38-S
Wind,
Storage Kwethluk $ 738,979 $ - 71 0.67 $7,869 1 4
Full Funding w/
Special Provision $ 738,979
17005
Alaska Village Electric
Cooperative, Inc.
Quinhagak Battery Energy
Storage System Project Construction
Lower Yukon-
Kuskokwim 38-S Storage Quinhagak $ 443,956 $ 707,625 70 0.88 $6,962 2 5 Full Funding $ 443,956
17012 City of Nenana
Nenana Biomass District Heat
System, Final Phase Construction Railbelt 36-R Biomass Nenana $ 1,223,000 $ 168,322 69 1.14 $6,864 1 6 Full Funding $ 1,223,000
17017
Puvurnaq Power
Company
Kongiganak 100 kW Solar Energy
Project
Final Design &
Permitting, Construction
Lower Yukon-
Kuskokwim 38-S Solar Kongiganak $ 728,603 $ 674,330 69 0.6 $9,427 3 7 Partial Funding $ 720,453
17007 Alaska Renewables LLC
Railbelt Wind Diversification
Alaska Renewables
Feasibility and
Conceptual Design Railbelt Various Wind Various $ 2,000,000 $ 2,187,000 69 1.22 $5,458 2 8 Full Funding $ 2,000,000
17001 City of Homer Homer Energy Recovery Project Construction Railbelt 6-C Hydroelectric Homer $ 280,000 $ 90,000 68 0.01 $7,120 3 9 Full Funding $ 280,000
17018
Atmautluak Tribal
Utilities
Atmautluak ETS Installation,
Integration and Commissioning Construction
Lower Yukon-
Kuskokwim 38-S Storage Atmautluak $ 286,227 $ 188,160 68 0.29 $8,538 4 10 Full Funding $ 286,227
17015
Southeast Alaska Power
Agency (SEAPA)
Southeast Alaska Grid Resiliency
(SEAGR)
Final Design &
Permitting, Construction Southeast 1-A; 2-A Hydroelectric
Petersburg, Ketchikan,
Wrangell, Metlakatla $ 4,000,000 $18,592,510 68 0 $6,730 3 11 Full Funding $ 4,000,000
Round 17 Projects Summary REF Round 17 Recommended Funding
REDUCING THE COST OF ENERGY IN ALASKA
Applications Forwarded to the Legislature for a Decision on Funding
14
*If appropriated by the Legislature and approved the Governor, this funding would become effective July 1, 2025 for inclusion in the Fiscal Year 2026 budget. Projects above orange line denote those currently funded in Fiscal Year 2026 Proposed Capital Budget.
Please see related summary report for details concerning the evaluation and description of the individual applications.
Application
No.Applicant Project Title Phase Energy Region
Election
District Technology Community
Grant Funds
Requested
Matching
Funds
Stage 3
Score
Benefit /
Cost Ratio HEC
Region
Rank
State
Rank Funding Level
Rec. Funding
Amount ($)
17004
Alaska Village Electric
Cooperative, Inc.
Chevak Battery Energy Storage
System Project Construction
Lower Yukon-
Kuskokwim 38-S
Solar,
Storage Chevak $ 968,644 $ 170,937 66 0.62 $6,902 5 12 Full Funding $ 968,644
17016
Pedro Bay Village
Council
Knutson Creek Hydro Project
Construction Construction Bristol Bay 37-S Hydroelectric Pedro Bay $ 400,000 $ 7,200,000 65 0.08 $9,390 2 13
Full Funding w/
Special Provision $ 400,000
17011 Akiachak, Ltd
Akiachak Native Community 200
kW Solar Energy Project
Final Design &
Permitting, Construction
Lower Yukon-
Kuskokwim 38-S Solar Akiachak $ 1,443,257 $ 2,265,809 64 0.33 $8,870 6 14
Partial Funding w/
Special Provision $ 67,833
17013
Nome Joint Utility
System
NJUS Solar Nome Banner Ridge
Solar Farm Construction Bering Straits 39-T
Solar,
Storage Nome $ 4,000,000 $ 50,000 60 0.57 $9,139 1 15 Full Funding $ 4,000,000
17009
Matanuska Electric
Association
Hunter Creek Hydroelectric
Feasibility Study Project
Feasibility and
Conceptual Design Railbelt Various Hydroelectric MEA service area $ 1,280,500 $ 384,500 58 0.67 $5,920 4 16 Full Funding $ 1,280,500
17008 City of Chignik
Chignik Hydroelectric Power
System
Final Design &
Permitting Bristol Bay 37-S Hydroelectric Chignik $ 883,012 $ 44,346 57 1.06 $7,701 3 17 Full Funding $ 883,012
17003 Utopian Power LLC Sterling Solar Project
Final Design &
Permitting, Construction Railbelt Various Solar Sterling $ 2,000,000 $ 2,000,000 37 0.7 $7,120 5 18
Partial Funding w/
Special Provision $ 12,500
Round 17 Projects Summary REF Round 17 Recommended Funding
REDUCING THE COST OF ENERGY IN ALASKA
Round XVI –Partial Funding Reasoning
15
App. #Project
Requested
Funding
Recommended
Funding Partial Funding Reasoning
17014
Naknek Solar
PV on Cape
Suwarof $3,210,000 $3,137,848
Partial Funding adjustment is owing to exclusion of funding for final design cost of $71,152 which is currently ongoing and already
funded. Only costs incurred after July 1, 2025, and which are within the scope of the grant agreement are eligible for funding under the
REF program.Revised funding recommendation: $3,137,848
17017
Kongiganak
100 kW Solar
Energy $728,603 $720,453
Costs associated with the applicant's administration of the REF grant are not eligible uses of REF funds. The line item for "AEA Grant
and NTP" for $8,150 is therefore removed from the funding recommendation, yielding a revised funding recommendation of $720,453.
17011
Akiachak
Native
Community
200 kW Solar
Energy $1,443,257 $67,833
Funding for final design only in Round 17 is recommended prior to recommendation for funding the construction phase,which will
better inform the additional solar capacity integration.AEA requested a copy of the USDA award, solar resource study, and updated
HOMER model from the applicant. Applicant provided the USDA grant agreement, but neither the solar resource study, or the updated
HOMER model. The applicant may re-apply in a future REF round for the construction phase once the final design is completed.
In addition, funding for grant administration is not allowable under the REF program. The $8,150 for the line item entitled "AEA award
and NTP" under the final design budget is removed from the funding recommendation, for a recommendation of $67,833 in Round 17.
17003
Sterling Solar
Project $2,000,000 $12,500
Funding for final design and permitting recommended prior to recommendation for funding the construction phase. Many aspects of
the project at this juncture are unclear and need to be revised. The applicant may re-apply in a future REF round for the construction
phase once the final design is completed. AEA staff identified several issues with the application including:lack of detail on proposed
system design, no letters of support included,not specific in stating required permits,lack of discussion of model results and no
technical analysis of proposed system was provided.
As part of the evaluation process and pursuant to 3 AAC 170.655(b), 4 applications, as provided below, have been recommended for partial funding. Partial funding recommendations were made in full consideration of project phases applied for, application scoring, project scope eligibility, and household cost of energy.
REDUCING THE COST OF ENERGY IN ALASKA 16
SAFE,
RELIABLE, &
AFFORDABLE
ENERGY
SOLUTIONS
ALASKA ENERGY AUTHORITY
813 West Northern Lights Blvd.
Anchorage, Alaska 99503
Phone: (907) 771-3000
Fax: (907) 771-3044
Toll Free (Alaska Only) 888-300-8534
Renewable Energy Fund: Round 17 Application Summaries
App #17001 Standard Application
Project Type: Hydro Energy Region: Railbelt
Applicant: City of Homer Proposed Phase(s): Construction
Applicant Type: Local Government Recommended Phase(s): Construction
Homer Energy Recovery Project
Project Description
In the City of Homer, there exists a pressure control facility located in the City's potable water distribution system. This a mission critical
pipeline where the City manages pressure for the potable water supply from the treatment plant to residences and business customers.
This pressure control facility is currently venting excess pressure that the City wants to recover and use to produce renewable energy.
The proposed project will create a flow bypass around the existing pressure control valve to flow through an energy recovery system.
This system shall utilize an integrated solution, a pressure recovery valve that will generate a new source of renewable energy, reduce
Homer's carbon footprint, save water and extend the life of its infrastructure. The proposed project shall have a capacity of 10 kW and
generate 42,000 kWh that will be used to reduce operating costs for the City's Department of Public Works, Water Utility.
DNR/DMLW Feasibility Comments
No DMLW-managed lands identified in project.Kenai Area Plan but not on State land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
"All projects proposing the development of permanent structures should conduct a geotechnical site survey to determine the potential
detrimental effects from natural hazards such as flooding, earthquakes, active faults (https://doi.org/10.14509/24956), tsunamis
https://doi.org/10.14509/29523), landslides, volcanoes, liquefaction, subsidence, storm surges, ice movement, snow avalanches,
erosion, radon (https://maps.dggs.alaska.gov/radon/), and naturally occurring asbestos, and incorporate appropriate measures to
mitigate the risks. Projects may be required to perform a geohazards site survey as a condition of receiving construction permits,
depending on location of proposed site.Updated tsunami inundation maps for Homer are located at http://doi.org/10.14509/14474.
General area is subject to landslides, earthquake hazards (http://dggs.alaska.gov/pubs/id/3883), and volcanic ash accumulation. Known
indoor radon values vary from below detection to 18.7 pCi/L."
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Renewable Energy Fund: Round 17 Application Summaries
App #17001 Standard Application
Homer Energy Recovery Project
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)16.06 Stage 2 Tech & Econ Score (100)66.00
2. Matching Resources (15)19.50 Benefit/Cost Ratio 0.01
3. Stage 2 Feasibility (25)16.50
4. Project Readiness (5)4.33 Project Rank
5. Benefits (10)1.67 Statewide (of 16 Standard applications)8
6. Local Support (5)2.00 Regional (of all applications)
7. Sustainability (10)8.33 Stage 3 Ranking Score (100)68.39
Total Stage 3 Score (100)68.39
Funding & Cost Requested Recommended
Total Cost Through Construction $370,000 $370,000 Cost of Electricity $0.24/kWh
REF Grant Funds $280,000 $280,000 Price of Fuel $3.73/Gal
Matching Funds $90,000 $90,000 Household Energy Cost $7,120
AEA Review Comments & Recommendation Full Funding
Election District: 6-C
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Renewable Energy Fund: Round 17 Application Summaries
App #17002 Standard Application
Project Type: Wind, Transmission, Storage Energy Region: Lower Yukon-Kuskokwim
Applicant: Nuvista Light and Electric Cooperative
Incorporated
Proposed Phase(s): Construction
Applicant Type: IPP Recommended Phase(s): Construction
Nuvista Kwethluk Wind and Battery Project Completion
Project Description
Kwethluk Incorporated (KI) is working with Nuvista Light & Electric Cooperative (Nuvista) on a Wind and Battery Project in Kwethluk,
Alaska. Nuvista hired Intelligent Energy Systems as the contractors for this project in 2019. Kwethluk Inc. and Nuvista hired twenty local
construction crew members to work seasonally on this project in 2020-2022. The wind and battery project includes the installation of 4 X
100 KW 24.4 wind turbines, a 500 KW battery energy storage system, 200 KW load regulating boiler, master controller to integrate the
renewable energy into the existing diesel system, and 30 electrical thermal stoves. All material and equipment are in place in Kwethluk.
The Covid 19 pandemic caused major delays and increased costs for materials (equipment and shipping via air and barge) for the wind
and battery project causing increased costs. Kwethluk has had 2 years of very wet summers making the constructions season very
difficult when dealing with heavy equipment and wet tundra/roads. The project was put on weather hold multiple times in the last two
years due to roads washing out and the work area just too wet to work in. The project had another major setback when it learned of the
poor craftsmanship of the supporting safety cables for erecting the towers in September of 2022. The project team attempted to raise
one of the towers when two spelter cable connection failed causing major structural damage to the gin pole and damage to the base
structure of the tower assembly. This has added a 1 year + delay to the project and many extra work hours to fix the damaged tower.
Since then, new cables have been replaced by the manufacturer and is currently at the job site in Kwethluk, Alaska. With these setbacks
and overlying costs, Nuvista does not have the extra funds to complete the project at this time. This application to the AEA REF Round
16 is to fund the final steps of the project (installation of the 30 ETS stoves, raise the towers) and commissioning the system.
DNR/DMLW Feasibility Comments
No DMLW-managed lands identified in project. Not in an area plan or on state land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. Geologic map https://dggs.alaska.gov/pubs/id/12857 may have useful regional geologic
information. General area is subject to erosion and flooding. This region is in the zone of sporadic to isolated permafrost (dominantly
lake thermokart terrain), meaning that ~10-50 percent or less of the ground surface is underlain by perennially frozen ground
(permafrost) (Jorgenson and others, 2008; Olefeldt and others, 2016). Radon concentrations are modeled to be low.
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Renewable Energy Fund: Round 17 Application Summaries
App #17002 Standard Application
Nuvista Kwethluk Wind and Battery Project Completion
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)17.75 Stage 2 Tech & Econ Score (100)62.33
2. Matching Resources (15)21.00 Benefit/Cost Ratio 0.67
3. Stage 2 Feasibility (25)15.58
4. Project Readiness (5)4.33 Project Rank
5. Benefits (10)1.00 Statewide (of 16 Standard applications)4
6. Local Support (5)2.00 Regional (of all applications)
7. Sustainability (10)9.33 Stage 3 Ranking Score (100)71.00
Total Stage 3 Score (100)71.00
Funding & Cost Requested Recommended
Total Cost Through Construction $$ Cost of Electricity $0.52/kWh
REF Grant Funds $738,979 $738,979 Price of Fuel $5.56/Gal
Matching Funds $00 $00 Household Energy Cost $7,869
AEA Review Comments & Recommendation Full Funding with Special Provision
Election District: 38-S
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Renewable Energy Fund: Round 17 Application Summaries
App #17003 Standard Application
Project Type: Solar Energy Region: Railbelt
Applicant: Utopian Power LLC Proposed Phase(s): Design, Construction
Applicant Type: IPP Recommended Phase(s): Design, Construction
Sterling Solar Project
Project Description
The project is a sustainable energy solution that aims to integrate a local and resilient solar energy model. The project involves the
installation of a 4MWdc solar system which will be used to generate electricity. The solar system will be on a landfill which is owned by
the Kenai Peninsula Borough and leased to Utopian Power. The energy generated will be used to power the state's communities. This
system will also feed electricity back to the grid through the local utility.
DNR/DMLW Feasibility Comments
No DMLW-managed lands identified in project. On KPB lands. In Kenai National Moose Range on Mental Health Trust Land -- cannot
dispose of land within an LDA.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. Guidebook and geologic map https://doi.org/10.14509/15941 may have useful regional
geologic information. General area is subject to earthquake hazards (http://dggs.alaska.gov/pubs/id/3883) and volcanic ash
accumulation. Known indoor radon values vary from below detection to 7.7 pCi/L.
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Renewable Energy Fund: Round 17 Application Summaries
App #17003 Standard Application
Sterling Solar Project
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)16.06 Stage 2 Tech & Econ Score (100)41.67
2. Matching Resources (15)0.00 Benefit/Cost Ratio 0.70
3. Stage 2 Feasibility (25)10.42
4. Project Readiness (5)1.50 Project Rank
5. Benefits (10)1.42 Statewide (of 16 Standard applications)16
6. Local Support (5)0.00 Regional (of all applications)
7. Sustainability (10)8.00 Stage 3 Ranking Score (100)37.39
Total Stage 3 Score (100)37.39
Funding & Cost Requested Recommended
Total Cost Through Construction $5,955,000 $5,955,000 Cost of Electricity $0.24/kWh
REF Grant Funds $2,000,000 $12,500 Price of Fuel $3.73/Gal
Matching Funds $2,000,000 $12,500 Household Energy Cost $7,120
AEA Review Comments & Recommendation Partial Funding with Special Provision
Partial Funding:
Funding for final design and permitting recommended prior to recommendation for funding construction phase. Many aspects of the
project at this juncture are unclear and need to be revised.
Project Concerns: Cost estimates are quite vague, more detail is requested prior to full funding. Lack of detail on proposed system
design, no letters of support included. Not specific in stating required permits. Lack of project presentation including lack of discussion of
model results and no technical analysis of proposed system was provided. Proposed system capacity is unclear, is the project capacity
3.2MW or 4MW?
Election District: 8-D
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Renewable Energy Fund: Round 17 Application Summaries
App #17004 Standard Application
Project Type: Storage Energy Region: Lower Yukon-Kuskokwim
Applicant: Alaska Village Electric Cooperative, Inc.Proposed Phase(s): Construction
Applicant Type: Utility Recommended Phase(s): Construction
Chevak Battery Energy Storage System Project
Project Description
Alaska Village Electric Cooperative, Inc. (AVEC) is requesting $968,644 through an Alaska Energy Authority (AEA) Renewable Energy
Fund (REF) grant to construct a Battery Energy Storage System (BESS) to be incorporated into the Chevak power system, which
includes four Northwind 100 Turbines and a power plant. Presently, in order to prevent outages during wind fluctuations, AVEC must
have a loaded diesel generator constantly running. A BESS would supply a constant spinning reserve providing power during losses of
wind resource generation for short periods while replacement diesel generation is started and brought online. Because a generator
would not be constantly running, this project would allow the power plant to burn less diesel, thus helping to lower the cost of power in
Chevak. The AEA REF grant funds would be used to incorporate a BESS into the existing wind turbine system and power plant in
Chevak, and if funded by the AEA, this effort will be supplemented with AVEC contributions. The scope of work under this funding
request is for the construction phase of this project and includes the installation of a BESS that will supply a spinning reserve of power
allowing AVEC’s Chevak power plant to operate diesels off.
DNR/DMLW Feasibility Comments
No DMLW-managed lands identified in project. On TLO lands. Not on state land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. Geologic map and report https://dggs.alaska.gov/pubs/id/13624 may have useful regional
information. General area is subject to erosion and flooding. This region is in the zone of sporadic to isolated permafrost (lake and
wetland thermokart terrain), meaning that ~10-50 percent or less of the ground surface is underlain by perennially frozen ground
(permafrost) (Jorgenson and others, 2008; Olefeldt and others, 2016). Radon concentrations are modeled to be low.
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Renewable Energy Fund: Round 17 Application Summaries
App #17004 Standard Application
Chevak Battery Energy Storage System Project
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)15.57 Stage 2 Tech & Econ Score (100)69.17
2. Matching Resources (15)16.50 Benefit/Cost Ratio 0.62
3. Stage 2 Feasibility (25)17.29
4. Project Readiness (5)4.00 Project Rank
5. Benefits (10)2.08 Statewide (of 16 Standard applications)10
6. Local Support (5)2.50 Regional (of all applications)
7. Sustainability (10)8.00 Stage 3 Ranking Score (100)65.94
Total Stage 3 Score (100)65.94
Funding & Cost Requested Recommended
Total Cost Through Construction $$ Cost of Electricity $0.52/kWh
REF Grant Funds $968,644 $968,644 Price of Fuel $4.64/Gal
Matching Funds $170,937 $170,937 Household Energy Cost $6,902
AEA Review Comments & Recommendation Full Funding
Election District: 38-S
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Renewable Energy Fund: Round 17 Application Summaries
App #17005 Standard Application
Project Type: Storage Energy Region: Lower Yukon-Kuskokwim
Applicant: Alaska Village Electric Cooperative, Inc.Proposed Phase(s): Construction
Applicant Type: Utility Recommended Phase(s): Construction
Quinhagak Battery Energy Storage System Project
Project Description
Alaska Village Electric Cooperative, Inc. (AVEC) is requesting $443,956 through an Alaska Energy Authority (AEA) Renewable Energy
Fund (REF) grant to construct a Battery Energy Storage System (BESS) to be incorporated into the Quinhagak power system, which
includes three Northwind 100 wind turbines and a power plant. Presently, in order to prevent outages during wind fluctuations, AVEC
must have a diesel generator constantly running. A BESS would supply a constant spinning reserve providing power during losses of
wind resource generation for short periods while replacement diesel generation is started and brought online. Because a generator
would not be constantly running, this project would allow the power plant to burn less diesel, thus helping to lower the cost of power in
Quinhagak.
DNR/DMLW Feasibility Comments
No DMLW-managed lands identified in project. Bristol Bay Area Plan - not on state land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. Geologic map and report https://dggs.alaska.gov/pubs/id/13624 may have useful regional
information. General area is subject to erosion and flooding. This region is in the zone of sporadic permafrost (lake and wetland
thermokart terrain), meaning that 10-50 percent of the ground surface is underlain by perennially frozen ground (permafrost) (Jorgenson
and others, 2008; Olefeldt and others, 2016). Radon concentrations are modeled to be low.
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Renewable Energy Fund: Round 17 Application Summaries
App #17005 Standard Application
Quinhagak Battery Energy Storage System Project
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)15.7 Stage 2 Tech & Econ Score (100)68.67
2. Matching Resources (15)21.00 Benefit/Cost Ratio 0.88
3. Stage 2 Feasibility (25)17.17
4. Project Readiness (5)4.00 Project Rank
5. Benefits (10)2.00 Statewide (of 16 Standard applications)5
6. Local Support (5)2.50 Regional (of all applications)
7. Sustainability (10)8.00 Stage 3 Ranking Score (100)70.37
Total Stage 3 Score (100)70.37
Funding & Cost Requested Recommended
Total Cost Through Construction $1,236,581 $1,236,581 Cost of Electricity $0.50/kWh
REF Grant Funds $443,956 $443,956 Price of Fuel $4.65/Gal
Matching Funds $707,625 $707,625 Household Energy Cost $6,962
AEA Review Comments & Recommendation Full Funding
Election District: 38-S
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Renewable Energy Fund: Round 17 Application Summaries
App #17006 Standard Application
Project Type: Hydro Energy Region: Southeast
Applicant: City of Pelican, Pelican Utilities Proposed Phase(s): Design, Construction
Applicant Type: Utility Recommended Phase(s): Design, Construction
Pelican Hydro Relicensing Project, Restoration, Repair
Project Description
The City of Pelican is in the process of relicensing its FERC license P-10198 for its 700kW Federal Energy Regulatory Commission
(FERC) hydropower project. FERC relicensing requires three significant actions: FERC regulatory relicensing, which includes
implementing a fish habitat restoration plan (FHRP), replacing a damaged trash rack, and stabilizing a Gabion Wall at the Powerhouse
from stream bank erosion. These relicensing actions are vital to ensure that the Pelican community continues to benefit from dependable
and cost-effective hydropower, which supports its residents, businesses, and the local economy. Lat: 57.95819; Long: -136.21535
DNR/DMLW Feasibility Comments
Northern Southeast Area Plan (unit C12) classified Water Resources.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. Geologic map and report https://dggs.alaska.gov/pubs/id/11998 may have some useful
regional geologic information. Tsunami inundation maps for Pelican are located at https://doi.org/10.14509/30423. General area is
subject to earthquake hazards (https://doi.org/10.14509/2356; https://www.ncei.noaa.gov/maps/hazards). Radon concentrations are
modeled to be moderate, averaging 2-4 pCi/L.
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Renewable Energy Fund: Round 17 Application Summaries
App #17006 Standard Application
Pelican Hydro Relicensing Project, Restoration, Repair
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)14.38 Stage 2 Tech & Econ Score (100)96.17
2. Matching Resources (15)10.50 Benefit/Cost Ratio 1.63
3. Stage 2 Feasibility (25)24.04
4. Project Readiness (5)5.00 Project Rank
5. Benefits (10)9.67 Statewide (of 16 Standard applications)1
6. Local Support (5)2.50 Regional (of all applications)
7. Sustainability (10)10.00 Stage 3 Ranking Score (100)76.09
Total Stage 3 Score (100)76.09
Funding & Cost Requested Recommended
Total Cost Through Construction $00 $ Cost of Electricity $0.26/kWh
REF Grant Funds $650,474 $650,474 Price of Fuel $4.89/Gal
Matching Funds $50,000 $50,000 Household Energy Cost $6,374
AEA Review Comments & Recommendation Full Funding
This project has been confirmed as an eligible project under AEA statutes AS 42.45.045(f)(1). Per a legal memo issued by AEA on July
20, 2023, the City of Pelican's (applicant) stated use of funds would be permissible use of program funds because the project is "an
addition to an existing project made after August 20, 2008.
Election District: 2-A
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Renewable Energy Fund: Round 17 Application Summaries
App #17007 Standard Application
Project Type: Wind, Transmission, Storage Energy Region: Railbelt
Applicant: Alaska Renewables LLC Proposed Phase(s): Feasibility
Applicant Type: IPP Recommended Phase(s): Feasibility
Railbelt Wind Diversification Alaska Renewables
Project Description
Following years of reconnaissance, initial field assessments, and land leasing discussions with the State of Alaska and several Alaska
Native Regional and Village Corporations, AKR now has several wind development assets which have the potential to dramatically
displace expensive fossil fuel consumption for electricity generation in Alaska. Bald Hills Wind is a project suggested by members of the
Native Village of Tyonek and would interconnect into Chugach Electric’s grid. Chatanika Wind is a project in the Interior that would
relieve the flow of power from south to north and would interconnect into GVEA’s grid. Walker Dome is a project at the center of Alaska’s
Intertie that would provide grid stability between south and north, would support the community of Healy through their energy transition
with the retirement of Healy 2, and would interconnect into GVEA’s grid. Now, AKR is advancing into the core Phase II work of site
environmental and wind resource data collection. Battery energy storage, long-duration storage, and transmission services are also key
technology investments that are relevant to some or all these projects to provide grid stability and part of the mid-term development
scope of the projects.
DNR/DMLW Feasibility Comments
"PAAD - Site 2 appears to be near accepted RS 2477 Right of way. RST Merrill River - Stony River Passes near this location. The
project will be subject to the right of way for this trail. Site 3 appears to be at the fork of two accepted RS 2477 Rights-of-way. RST 237
Circle-Fairbanks Trail a codified RS 2477 in AS 19.30.400 and uncodified RST 1908 Chena Hot Springs - Olympia Creek Trail. The
project will be subject to the Right-of-way for these two trails and travel on these two trails will not be limited by the project."Site 1: In
Yukon-Tanana Area Plan on Mental Health Trust Land; Site 2: in Kenai Area Plan on Mental Health Trust Land; Site 3: in Eastern Tanana
Area Plan on state land but unclassified.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. Geologic maps and reports may have useful regional information:
https://dggs.alaska.gov/pubs/id/12899 Geologic map (site 1); https://doi.org/10.14509/29471 Geologic map and report (site 2);
https://dggs.alaska.gov/pubs/id/12617 Geologic (map site 3).
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Renewable Energy Fund: Round 17 Application Summaries
App #17007 Standard Application
Railbelt Wind Diversification Alaska Renewables
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)12.31 Stage 2 Tech & Econ Score (100)70.54
2. Matching Resources (15)19.50 Benefit/Cost Ratio 1.22
3. Stage 2 Feasibility (25)17.64
4. Project Readiness (5)3.67 Project Rank
5. Benefits (10)5.92 Statewide (of 16 Standard applications)7
6. Local Support (5)2.50 Regional (of all applications)
7. Sustainability (10)7.33 Stage 3 Ranking Score (100)68.86
Total Stage 3 Score (100)68.86
Funding & Cost Requested Recommended
Total Cost Through Construction $$ Cost of Electricity $0.21/kWh
REF Grant Funds $2,000,000 $2,000,000 Price of Fuel $2.47/Gal
Matching Funds $2,187,000 $2,187,000 Household Energy Cost $5,458
AEA Review Comments & Recommendation Full Funding
Election District:
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Renewable Energy Fund: Round 17 Application Summaries
App #17008 Standard Application
Project Type: Hydro Energy Region: Bristol Bay
Applicant: City of Chignik Proposed Phase(s): Design
Applicant Type: Local Government Recommended Phase(s): Design
Chignik Hydroelectric Power System
Project Description
Note to reviewers: This application is a resubmittal of application 15014 from Round 15. There are minor modifications from the Round
15 application, including the addition of beneficial electrification. All changes from the previous application are identified by bold,
italicized text. The City of Chignik’s water source is Indian Lake which is impounded by a timber buttress dam. Water flows from the dam
through a 7,260 ft transmission line to the community water treatment plant. Flow from Indian Lake has also historically powered a now
decommissioned 60 kW hydroelectric turbine in local cannery, the FERC permit for which is now owned by the city. The dam and
portions of the water transmission lines are over 70 years old, near failure, and in urgent need of replacement. As of the date of this
application, the Alaska Area Office of the Indian Health Service (IHS) has approved $7,230,830 of funding ($639,987 for engineering-
including geotechnical, survey, and design- and $6,590,843 for construction) for the purpose of renovating the aging dam and water
transmission lines. This funding is being reviewed by the national level IHS and expected to be available in 2023. The dam and water
transmission line renovation project to be funded by IHS is referred to as the “dam renovation” for the remainder of this application.
Concurrent with this dam renovation, the city would like to install a hydroelectric power generation system, consisting of a penstock, new
powerhouse with a Turgo turbine, tailrace, electrical transmission to the existing diesel powerplant.. This project is referred to the
“hydroelectric system” for the remainder of this application. This application seeks funding to complete the final design and permitting
phase (Phase III) for the hydroelectric system concurrent with the design of the dam renovation. Phase III of the hydroelectric system
project will utilize a 2014 feasibility study performed by the consulting firm Hatch Ltd., and a 2018 Preliminary Engineering Report (PER)
performed by the Alaska Native Tribal Health Consortium (both documents are included in Appendix A). Because the dam renovation is
expected to be funded in 2023, is presents a unique opportunity to design the dam renovation concurrently with the hydroelectric system
in order to achieve cost savings through economies of scale and ensure that electric generation is considered in the sizing, location and
layout of the water source project. If the dam renovation is completed without the hydroelectric system, design and construction of the
hydroelectric system would be significantly more expensive, and will be limited by a dam that was designed without consideration for
future electrical generation. Therefore, it is vital that funding is provided during the current round of the REF in order to fully leverage the
dam renovation funding to achieve maximally efficient achievement of project outcomes. AEA has previously recommended this project
for design funding under the REF three times, but the State has not yet appropriated funds for it. However, this is the first application
where the dam renovation will be separately funded. The 2014 feasibility study found that the proposed hydroelectric system could meet
approximately 94.7% of the city’s electrical load, saving approximately 50,441 gallons of diesel annually at a current cost of $5.03 per
gallon. This project will save an additional 13,571 gallons of heating fuel by utilizing excess hydro-generated electricity for heating the
community clinic and school. This project will provide public benefits to both the local electric utility and individual rate payers in the form
of fuel savings to the utility and lowered utility bills for community members. This project would make the local utility financially stronger,
keep money circulating in the community that would have otherwise gone to the fuel provider, and reduce fuel use and the associated
emissions.
DNR/DMLW Feasibility Comments
Bristol Bay Area Plan - not on state land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. Geologic map and report https://doi.org/10.3133/b1969B. may have useful regional geologic
information. The coastal area in this region is subject to potential tsunami hazard, see https://doi.org/10.14509/29675 and
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Renewable Energy Fund: Round 17 Application Summaries
App #17008 Standard Application
https://www.ncei.noaa.gov/maps/hazards. General area is subject to volcanic ash accumulation and earthquake hazards. Radon
concentrations are modeled to be moderate, averaging 2-4 pCi/L.
Chignik Hydroelectric Power System
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)17.37 Stage 2 Tech & Econ Score (100)57.50
2. Matching Resources (15)10.50 Benefit/Cost Ratio 1.06
3. Stage 2 Feasibility (25)14.38
4. Project Readiness (5)3.17 Project Rank
5. Benefits (10)3.00 Statewide (of 16 Standard applications)15
6. Local Support (5)2.50 Regional (of all applications)
7. Sustainability (10)6.00 Stage 3 Ranking Score (100)56.91
Total Stage 3 Score (100)56.91
Funding & Cost Requested Recommended
Total Cost Through Construction $7,228,206 $7,228,206 Cost of Electricity $0.58/kWh
REF Grant Funds $883,012 $883,012 Price of Fuel $5.03/Gal
Matching Funds $44,346 $44,346 Household Energy Cost $7,701
AEA Review Comments & Recommendation Full Funding
Election District: 37-S
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Renewable Energy Fund: Round 17 Application Summaries
App #17009 Standard Application
Project Type: Hydro, Transmission, Storage Energy Region: Railbelt
Applicant: Matanuska Electric Association Proposed Phase(s): Feasibility
Applicant Type: Utility Recommended Phase(s): Feasibility
Hunter Creek Hydroelectric Feasibility Study Project
Project Description
This project will conduct a feasibility study of the east fork Hunter Creek hydropower resource by expanding on the findings of the
reconnaissance study completed by Eklutna, Inc. in 2013 with partial grant funding award in REF Round 4. The proposed study will
include new field studies updated and more detailed technical, regulatory, and economic analysis to determine whether the project is
feasible and a preferred project configuration. The prior reconnaissance study identified a viable 7.7 MW run-of-river hydro project on the
east fork of Hunter Creek with an estimated 27,100 MWh of annual energy output. East fork project configurations considered by the
2013 study ranged from 5.3 to 23 MW installed capacity and 21,000 to 80,900 MWh annual output. This study will also assess storage
potential at the east fork diversion site and the potential added value to the project that can be realized with reservoir and/or battery
energy storage system (BESS) to enable the project to form a Knik River microgrid.
DNR/DMLW Feasibility Comments
Proposed site (based on a single GPS coordinate and not a project footprint) is located within S016N004E31, which is state selected
lands at this point with ANILCA top-filing. It is unlikely that this location is under DNR management. However, if it is determined that this
is under DNR management, projects such as this often need development plan details such as placement of infrastructure, transmission
lines and access to be clearly defined in the application. Permits may be required for feasibility studies and for access if access
development is not within GAUs. If access involves material, a material sales contract may be needed.Knik Public Use Area- LDA
(41.23.180) -- No disposals of land within an LDA. Leases may be okay if they follow the management guidelines in the Knick River
Public Use Area Management Plan.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. Geologic map and report https://dggs.alaska.gov/pubs/id/24604 may have useful geologic
information. General area is subject to snow avalanche and landslide hazards. Radon concentrations are modeled to be moderate,
averaging 2-4 pCi/L.
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Renewable Energy Fund: Round 17 Application Summaries
App #17009 Standard Application
Hunter Creek Hydroelectric Feasibility Study Project
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)13.35 Stage 2 Tech & Econ Score (100)55.00
2. Matching Resources (15)19.50 Benefit/Cost Ratio 0.67
3. Stage 2 Feasibility (25)13.75
4. Project Readiness (5)3.50 Project Rank
5. Benefits (10)1.50 Statewide (of 16 Standard applications)14
6. Local Support (5)1.00 Regional (of all applications)
7. Sustainability (10)5.00 Stage 3 Ranking Score (100)57.60
Total Stage 3 Score (100)57.60
Funding & Cost Requested Recommended
Total Cost Through Construction $67,765,000 $67,765,000 Cost of Electricity $0.20/kWh
REF Grant Funds $1,280,500 $1,280,500 Price of Fuel $3.30/Gal
Matching Funds $384,500 $384,500 Household Energy Cost $5,920
AEA Review Comments & Recommendation Full Funding
Election District: Various
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Renewable Energy Fund: Round 17 Application Summaries
App #17010 Standard Application
Project Type: Hydro Energy Region: Southeast
Applicant: Goat Lake Hydro, Inc.Proposed Phase(s): Recon
Applicant Type: Utility Recommended Phase(s): Recon
Goat Lake Hydro Storage Expansion Study
Project Description
Alaska Power & Telephone (AP&T) subsidiary Goat Lake Hydro, Inc. requests $121,250 in AEA REF Round 16 funding for Phase I
Reconnaissance analysis examining an increase to the reservoir at Goat Lake Hydro (GLH), a currently operational hydropower project.
GLH will supply $52,250 of in-kind funding as a match. The project currently provides power to the communities of Skagway, Haines,
and Dyea, as well as to Inside Passage Electrical Cooperative (IPEC), which resells energy in the community of Klukwan.
DNR/DMLW Feasibility Comments
Northern Southeast Area Plan but not on state land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. The coastal area in this region is subject to potential tsunami hazard, see
https://dggs.alaska.gov/pubs/id/30029 and https://www.ncei.noaa.gov/maps/hazards. General area is subject to earthquake, volcanic
ash accumulation, snow avalanche, and landslide hazards. Radon concentrations are modeled to be high, averaging 4 pCi/L or greater.
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Renewable Energy Fund: Round 17 Application Summaries
App #17010 Standard Application
Goat Lake Hydro Storage Expansion Study
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)14.37 Stage 2 Tech & Econ Score (100)70.50
2. Matching Resources (15)19.50 Benefit/Cost Ratio 0.00
3. Stage 2 Feasibility (25)17.63
4. Project Readiness (5)5.00 Project Rank
5. Benefits (10)2.08 Statewide (of 16 Standard applications)3
6. Local Support (5)2.50 Regional (of all applications)
7. Sustainability (10)10.00 Stage 3 Ranking Score (100)71.08
Total Stage 3 Score (100)71.08
Funding & Cost Requested Recommended
Total Cost Through Construction $$ Cost of Electricity $0.32/kWh
REF Grant Funds $121,250 $121,250 Price of Fuel $3.60/Gal
Matching Funds $52,250 $52,250 Household Energy Cost $6,371
AEA Review Comments & Recommendation Full Funding
Election District: 3-B
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Renewable Energy Fund: Round 17 Application Summaries
App #17011 Standard Application
Project Type: Solar Energy Region: Lower Yukon-Kuskokwim
Applicant: Akiachak, Ltd Proposed Phase(s): Design, Construction
Applicant Type: Government Entity Recommended Phase(s): Design, Construction
Akiachak Native Community 200 kW Solar Energy Project
Project Description
The project proposes to install, integrate, and commission a 200-kW solar/PV array energy for the islanded hybrid wind-diesel-battery-
heat system for Akiachak Native Community village corporation, Akiachak, Ltd. (ANC), a tribally owned community utility in Akiachak, AK,
which is designated as a High Energy Cost Area with a residential retail electric rate of $0.60 per kWh. Our utility was recently awarded a
grant through the USDA High Energy Cost (HEC) grant program in the amount of $2,265,809 for the installation of 200 kW solar PV and
a battery energy storage system (500 kW/677 kVA lithium ion). While this represents a major upgrade and will be of tremendous benefit
to our community, to really be able to optimize the system it needs to be upgraded to include a total of 400 kW PV, as that will boost our
displacement of fuel from 17,000 to more than 42,000 gallons annually and more than double the kWh of solar produced annually (from
226,215 to 452,431 kWh). Due to limited availability of funds, we were not able to apply for the full capacity required to optimize our
renewable system through the USDA HEC grant; instead, we now seek to leverage that funding as match toward the current proposal,
which will allow us to gain cost efficiencies through the combining of these two projects. Other benefits to be gained by adding to our
solar array include:- Increased system reliability- Reduced diesel maintenance and operations cost due to increased hours of diesel off
operations- Improved community resilience through additional source of energy- The additional displacement of 24,514 gallons of diesel
(@$3.90/gallon = $95,605) annually, as well as an additional 900 hours of diesel off operations ($9.25/hour = $8,325) resulting in an
estimated annual reduction in operating costs in excess of $103,930 from this 200 kW addition to the overall project.- Reduced fuel
purchases, resulting in a deferral of investments in bulk fuel storage capacity as well as a reduction in harmful greenhouse gas
emissions- Support for local workforce, both during the period of construction and long-term, through on-going cost savings to our tribal
utility- Advancement of knowledge and understanding of integration and operation of diesel-renewable hybrid systems in the region.
DNR/DMLW Feasibility Comments
No DMLW-managed lands identified in project. Not on state land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. Geologic map https://dggs.alaska.gov/pubs/id/12857 may have useful information. General
area is subject to erosion and flooding. This region is in the zone of sporadic to isolated permafrost (dominantly lake thermokart terrain),
meaning that ~10-50 percent or less of the ground surface is underlain by perennially frozen ground (permafrost) (Jorgenson and others,
2008; Olefeldt and others, 2016). Radon concentrations are modeled to be low.
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Renewable Energy Fund: Round 17 Application Summaries
App #17011 Standard Application
Akiachak Native Community 200 kW Solar Energy Project
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)20.01 Stage 2 Tech & Econ Score (100)44.42
2. Matching Resources (15)21.00 Benefit/Cost Ratio 0.33
3. Stage 2 Feasibility (25)11.11
4. Project Readiness (5)0.83 Project Rank
5. Benefits (10)1.38 Statewide (of 16 Standard applications)12
6. Local Support (5)1.00 Regional (of all applications)
7. Sustainability (10)8.33 Stage 3 Ranking Score (100)63.65
Total Stage 3 Score (100)63.65
Funding & Cost Requested Recommended
Total Cost Through Construction $1,443,257 $1,443,257 Cost of Electricity $0.60/kWh
REF Grant Funds $1,443,257 $67,833 Price of Fuel $6.17/Gal
Matching Funds $2,265,809 $113,291 Household Energy Cost $8,870
AEA Review Comments & Recommendation Partial Funding with Special Provision
The USDA funded solar & battery project is currently in construction and fully funded. This project is to add additional solar capacity. It is
unclear how the USDA-funded solar panels will integrate with the four new diesel gensets in the existing diesel powerhouse. There is
concern over loss of heat recovery with integration of renewables. Technical feasibility remains in question.
AEA requested a copy of the USDA award, solar resource study, and updated HOMER model from the applicant. Applicant provided the
USDA grant agreement, but neither the solar resource study, or the updated HOMER model.
It is recommended that this project be funded for final design, which will better inform the additional solar capacity integration.
Funding for grant administration is not allowable under the REF program. The $8,150 for the line item entitled "AEA award and NTP"
under the final design budget is thus removed from the funding recommendation, for a total recommendation of $67,833 for final design.
Election District: 38-S
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Renewable Energy Fund: Round 17 Application Summaries
App #17012 Heat Application
Project Type: Biomass Energy Region: Yukon-Koyukuk/Upper Tanana
Applicant: City of Nenana Proposed Phase(s): Construction
Applicant Type: Local Government Recommended Phase(s): Construction
Nenana Biomass District Heat System, Final Phase
Project Description
The City of Nenana is a rural community located in the interior of Alaska with a population of 412 residents; 41% of which are Alaskan
Native. This is a biomass wood-chip boiler system project that will provide heat to several public buildings, provide services to the
community for needs which have never been met before, and help to dramatically reduce heating expenses. The problems this project
will address include high utility costs, local poverty rates, climate change impacts and increasing wildfire risk in our region. Nenana is not
only identified as an underserved population, but is also an area of persistent poverty with 62.75% LMI. Utilizing woody debris from local
sources and forest management projects to supply the biomass boiler mitigates wildfire risk and reduces the use of fossil fuels while
providing low-cost heat with a renewable energy source. The biomass facility will support local employment, improve community
sanitation, potentially revitalize the local milling industry, and be a major source of marketable biochar – a soil amendment that helps to
increase soil fertility for agriculture. The intended outcomes of this project are to provide ongoing employment opportunities and
affordable heat, sequester carbon, reduce use of fossil fuels andcreate healthy tree stands to mitigate wildfire risk in the region. The
City’s limited budget restricts its ability to provide adequate support to reduce poverty, address unemployment, or bolster the local
economy. The grant funding we have received to date has been utilized to design and progress into the final stages of building a
biomass wood-chip heating facility. The project began in 2019 and upon completion, will provide heat to the local K-12 school, fitness
center, water treatment plant, fire station, school recreation hall and a hookup to heat a future community greenhouse. These amenities
which will be available within the community upon the completion of this project will allow for those who live in dry cabins year-round to
have local access to safe drinking water, showers, and laundry facilities. The City will have a sustainable energy heat source to provide
renewable energy for years to come. Improved forest management practices will reduce wildfire risk in our region. The jobs created by
this project will help to improve the poverty rate and increase the resilience of our community, as energy costs are mitigated, and the City
budget can facilitate employment opportunities for year-round positions at the Biomass Heat Plant. This is the final phase of the project
which is intended to complete all remaining portions of the project and make it fully operational.
DNR/DMLW Feasibility Comments
Not on state land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. Geologic maps and reports https://dggs.alaska.gov/pubs/id/1321 and
https://dggs.alaska.gov/pubs/id/1321 may have useful information about the general geology. Location is within the Minto Flats seismic
zone, active within the past 150 years, and this region is in the zone of discontinuous to isolated permafrost (wetland thermokart terrain),
meaning that ~50-90 percent of the ground surface is underlain by perennially frozen ground (permafrost) (Jorgenson and others, 2008;
Olefeldt and others, 2016). Radon concentrations are modeled to be moderate, averaging 2-4 pCi/L.
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Renewable Energy Fund: Round 17 Application Summaries
App #17012 Heat Application
Nenana Biomass District Heat System, Final Phase
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)15.48 Stage 2 Tech & Econ Score (100)78.58
2. Matching Resources (15)13.50 Benefit/Cost Ratio 1.14
3. Stage 2 Feasibility (25)19.64
4. Project Readiness (5)4.33 Project Rank
5. Benefits (10)5.33 Statewide (of 2 Heat applications)1
6. Local Support (5)2.50 Regional (of all applications)
7. Sustainability (10)8.67 Stage 3 Ranking Score (100)69.46
Total Stage 3 Score (100)69.46
Funding & Cost Requested Recommended
Total Cost Through Construction $1,223,000 $1,223,000 Cost of Electricity $0.25/kWh
REF Grant Funds $1,223,000 $1,223,000 Price of Fuel $4.31/Gal
Matching Funds $168,322 $168,322 Household Energy Cost $6,864
AEA Review Comments & Recommendation Full Funding
Election District: 36-R
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Renewable Energy Fund: Round 17 Application Summaries
App #17013 Standard Application
Project Type: Solar Energy Region: Bering Straits
Applicant: Nome Joint Utility System Proposed Phase(s): Construction
Applicant Type: Utility Recommended Phase(s): Construction
NJUS Solar Nome Banner Ridge Solar Farm
Project Description
Nome Joint Utility Service (NJUS) proposes construction of a 1 MW capacity solar PV farm on the south slope of Banner Ridge near its
existing wind farm of two EWT wind turbines. Solar power, combined with the 2 MWh/2 MW battery energy storage system (BESS)
project (awarded to NJUS in REF Round 14) will supply Nome with renewable energy during the summer months when winds are light.
Given lower load demand during summer, this will enable NJUS to operate its lower capacity/lower minimum load Caterpillar generators
in its old powerplant instead of the highcapacity/high minimum load Wartsila generators in the new plant. NJUS envisions eventual
growth of solar capacity to perhaps 5 MW to serve anticipated load growth from new mining and national security infrastructure.
DNR/DMLW Feasibility Comments
Northwest Area Plan but not on state land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. The geologic maps and report https://doi.org/10.14509/1665 may have some useful
information about the general geology. This region is in the zone of discontinuous permafrost, meaning that 50-90 percent of the ground
surface is underlain by perennially frozen ground (permafrost) (Jorgenson and others, 2008). Radon concentrations are modeled to be
low to moderate, averaging below detection to 4 pCi/L.
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Renewable Energy Fund: Round 17 Application Summaries
App #17013 Standard Application
NJUS Solar Nome Banner Ridge Solar Farm
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)20.61 Stage 2 Tech & Econ Score (100)61.17
2. Matching Resources (15)9.00 Benefit/Cost Ratio 0.57
3. Stage 2 Feasibility (25)15.29
4. Project Readiness (5)4.50 Project Rank
5. Benefits (10)1.58 Statewide (of 16 Standard applications)13
6. Local Support (5)1.00 Regional (of all applications)
7. Sustainability (10)8.00 Stage 3 Ranking Score (100)59.99
Total Stage 3 Score (100)59.99
Funding & Cost Requested Recommended
Total Cost Through Construction $4,050,000 $4,050,000 Cost of Electricity $0.36/kWh
REF Grant Funds $4,000,000 $4,000,000 Price of Fuel $6.85/Gal
Matching Funds $50,000 $50,000 Household Energy Cost $9,139
AEA Review Comments & Recommendation Full Funding
Election District: 39-T
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Renewable Energy Fund: Round 17 Application Summaries
App #17014 Standard Application
Project Type: Solar Energy Region: Bristol Bay
Applicant: Naknek Electric Association, Inc.Proposed Phase(s): Construction
Applicant Type: Utility Recommended Phase(s): Construction
Naknek Solar PV on Cape Suwarof
Project Description
Naknek Electric Association (NEA) proposes the construction of a 1 MW capacity solar PV system on Bristol Bay Borough property at
Cape Suwarof. This will expand NEA’s existing 80 kW solar system on the Cape which has been operational for several years. Solar
power, combined with the 1.5 MWh/1.5 MW battery energy storage system (BESS) project awarded to NEA in REF Round 15, will
supply the Naknek Service Area (Naknek, South Naknek, and King Salmon) with renewable energy during the high electric demand
summer months when fish processing activities dramatically increase load demand. NEA envisions eventual growth of solar system
capacity to perhaps 4 or 5 MW, plus 2 to 3 MW of wind power, to serve fish processing needs and Naknek’s approximately 2 MW base
load.
DNR/DMLW Feasibility Comments
Bristol Bay Area Plan - but not on state land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. The geologic maps and report https://dggs.alaska.gov/pubs/id/12155 may have some useful
information just east of the study area. General area is subject to flooding and erosion, volcanic ash accumulation, and earthquake
hazards (https://www.ncei.noaa.gov/maps/hazards). The region is in the zone of isolated permafrost (dominantly lake thermokart terrain),
meaning that >0-10 percent of the ground surface is underlain by perennially frozen ground (permafrost) (Jorgenson and others, 2008;
Olefeldt and others, 2016). Radon concentrations are modeled to be low to moderate, averaging below detection to 4 pCi/L.
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Renewable Energy Fund: Round 17 Application Summaries
App #17014 Standard Application
Naknek Solar PV on Cape Suwarof
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)21.54 Stage 2 Tech & Econ Score (100)68.67
2. Matching Resources (15)16.50 Benefit/Cost Ratio 0.57
3. Stage 2 Feasibility (25)17.17
4. Project Readiness (5)5.00 Project Rank
5. Benefits (10)1.50 Statewide (of 16 Standard applications)2
6. Local Support (5)2.50 Regional (of all applications)
7. Sustainability (10)9.33 Stage 3 Ranking Score (100)73.54
Total Stage 3 Score (100)73.54
Funding & Cost Requested Recommended
Total Cost Through Construction $4,110,000 $4,110,000 Cost of Electricity $0.58/kWh
REF Grant Funds $3,210,000 $3,137,848 Price of Fuel $4.78/Gal
Matching Funds $900,000 $900,000 Household Energy Cost $9,551
AEA Review Comments & Recommendation Partial Funding
Partial Funding adjustment is owing to exclusion of funding for final design cost of $71,152 which is currently ongoing and already
funded. Only costs incurred after July 1, 2024, and which are within the scope of the grant agreement are eligible for funding under the
REF program.
Revised funding recommendation: $3,137,848
Election District: 37-S
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Renewable Energy Fund: Round 17 Application Summaries
App #17015 Standard Application
Project Type: Hydro Energy Region: Southeast
Applicant: Southeast Alaska Power Agency (SEAPA)Proposed Phase(s): Design, Construction
Applicant Type: Government Entity Recommended Phase(s): Design, Construction
Southeast Alaska Grid Resiliency (SEAGR)
Project Description
The SEAPA Southeast Alaska Grid Resiliency Project (SEAGR) will increase generating capacity at the Tyee Lake hydroelectric facility
and increase resiliency of the SEAPA electrical grid for: Metlakatla and potentially Kake electrical interconnections; Petersburg,
Wrangell, and Ketchikan beneficial electrification (load growth); Voltage and Frequency stabilization due to grid expansion and load
increases; Reliability with additional spinning reserves, increased inertia, and voltage support; Resiliency during extreme weather
conditions. The project would include installation of a third turbine and generator at Tyee. The third “unit” would have synchronous
condensing capabilities, allowing it to be synchronized to the electric grid providing voltage support and frequency security through
additional spinning inertia. Peak generation capabilities would increase 25% on the SEAPA system. Voltage support would increase
while the third generator is operated in synchronous condensing mode, allowing for efficiency gains on existing units due to power factor
corrections. Ancillary systems would be installed to support the third turbine to include 480V and 15kV switchgear
upgrades/modifications.
DNR/DMLW Feasibility Comments
Central/Southern Southeast Area Plan, Unit W-21. Designated General Use.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. The report and maps https://dggs.alaska.gov/pubs/id/2970 may have some useful information
about the general geology. General area is subject to snow avalanche and landslide hazards. Radon concentrations are modeled to be
moderate to high averaging 2 to >4 pCi/L.
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Renewable Energy Fund: Round 17 Application Summaries
App #17015 Standard Application
Southeast Alaska Grid Resiliency (SEAGR)
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)15.18 Stage 2 Tech & Econ Score (100)62.33
2. Matching Resources (15)21.00 Benefit/Cost Ratio 0.00
3. Stage 2 Feasibility (25)15.58
4. Project Readiness (5)4.50 Project Rank
5. Benefits (10)1.67 Statewide (of 16 Standard applications)9
6. Local Support (5)1.00 Regional (of all applications)
7. Sustainability (10)9.00 Stage 3 Ranking Score (100)67.93
Total Stage 3 Score (100)67.93
Funding & Cost Requested Recommended
Total Cost Through Construction $22,592,510 $22,592,510 Cost of Electricity $0.13/kWh
REF Grant Funds $4,000,000 $4,000,000 Price of Fuel $4.79/Gal
Matching Funds $18,592,510 $18,592,510 Household Energy Cost $6,730
AEA Review Comments & Recommendation Full Funding
Election District: 1-A, 2-A
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Renewable Energy Fund: Round 17 Application Summaries
App #17016 Standard Application
Project Type: Hydro Energy Region: Bristol Bay
Applicant: Pedro Bay Village Council Proposed Phase(s): Construction
Applicant Type: Utility Recommended Phase(s): Construction
Knutson Creek Hydro Project Construction
Project Description
The proposed project is an approximately 150 kW run-of-river hydroelectric project on Knutson Creek near Pedro Bay. The hydro project
will provide nearly all (~98%) of the electricity needs of the village, as well as providing a significant amount of interruptible energy to
heat the tribal council building and other community buildings in the village.
DNR/DMLW Feasibility Comments
Bristol Bay Area Plan - not on state land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. The report and maps https://dggs.alaska.gov/pubs/id/3681 and
https://dggs.alaska.gov/pubs/id/2949 may have some useful information about the general geology. General area is subject to
earthquake hazards, volcanic ash accumulation, and potential flooding from disturbances to Iliamna Lake. This region is in the zone of
sporadic permafrost, meaning that 10-50 percent of the ground surface is underlain by perennially frozen ground (permafrost)
(Jorgenson and others, 2008). Radon concentrations are modeled to be moderate, averaging 2-4 pCi/L.
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Renewable Energy Fund: Round 17 Application Summaries
App #17016 Standard Application
Knutson Creek Hydro Project Construction
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)21.18 Stage 2 Tech & Econ Score (100)47.50
2. Matching Resources (15)21.00 Benefit/Cost Ratio 0.08
3. Stage 2 Feasibility (25)11.88
4. Project Readiness (5)2.67 Project Rank
5. Benefits (10)0.50 Statewide (of 16 Standard applications)11
6. Local Support (5)1.00 Regional (of all applications)
7. Sustainability (10)6.33 Stage 3 Ranking Score (100)64.56
Total Stage 3 Score (100)64.56
Funding & Cost Requested Recommended
Total Cost Through Construction $8,551,470 $8,551,470 Cost of Electricity $0.82/kWh
REF Grant Funds $400,000 $400,000 Price of Fuel $5.29/Gal
Matching Funds $7,200,000 $7,200,000 Household Energy Cost $9,390
AEA Review Comments & Recommendation Full Funding with Special Provision
Special Provisions:-Subsurface geotech needs to be conducted first prior to issuance to grants to confirm site viability. -Fish water rights
and habitat permit still pending review. Need permit secured prior to issuance of REF grant. -Ensure DOE grants is awarded prior to
issuance of grant funds. If Federal Grant is not awarded, REF grant is to be released and be eligible for reallocation to other projects.
DOE Grants must be secured by June 30, 2025, with a tentative construction schedule for 2026. If DOE Grants not secured by June 30,
2025, REF funds will automatically be released back to REF Funds effective July 1, 2025 for reallocation to other viable REF Projects.-
REF grant funds not to be expended prior but concurrent with federal grant funds.-Site Control needs to be secured with confirmed
documents verified by AEA before moving forward with issuing grants to the grantee. Evidence of sufficient site securement to the
satisfaction of AEA necessary prior to issuance of grant funds.-Grantee must provide contingency plan for construction overruns. If costs
go above budget, grantee must provide own funds or arrange for additional financing to finish on time.
Election District: 37-S
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Renewable Energy Fund: Round 17 Application Summaries
App #17017 Standard Application
Project Type: Solar Energy Region: Lower Yukon-Kuskokwim
Applicant: Puvurnaq Power Company Proposed Phase(s): Design, Construction
Applicant Type:Recommended Phase(s): Design, Construction
Kongiganak 100 kW Solar Energy Project
Project Description
The project proposes to install, integrate, and commission a 100-kW solar/PV array energy for the islanded hybrid wind-diesel-battery-
heat system for the tribally owned community utility in Kongiganak (Kong), Puvurnaq Power Company (PPC). Kong is designated as a
High Energy Cost Area with a residential retail electric rate of $0.67 per kWh. Our utility was recently awarded a grant through the
Department of Energy Office of Indian Energy (Award No. DE-IE0000161) in the amount of $674,330 for the installation of 100 kW solar
PV. We now seek to leverage that funding as match toward the current proposal, which will allow us to add a total of 200 kW to our
islanded system while gaining cost efficiencies through the combining of these two projects. Other benefits to be gained by adding to our
solar array include:- Increased system reliability- Reduced diesel maintenance and operations cost due to increased hours of diesel off
operations- Improved community resilience through additional source of energy- A total displacement of 54,082 gallons of diesel (@
$4.01/gallon = $216,868) annually, as well as900 hours of diesel off operations (@ $9.25/hour = $8,325), resulting in an estimated total
annualreduction in operating costs for the utility in excess of $225,193, even before accounting forreduced O&M costs as a result of
reduced wear on our diesel generators.- Reduced fuel purchases, resulting in a deferral of investments in bulk fuel storage capacity as
well as a reduction in harmful greenhouse gas emissions- Support for local workforce, both during the period of construction and long-
term, through ongoing cost savings to our tribal utility- Advancement of knowledge and understanding of integration and operation of
diesel-renewable hybrid systems in the region
DNR/DMLW Feasibility Comments
Not in an area plan or on state land, but near OSL surf/subsurf.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. The map and report https://dggs.alaska.gov/pubs/id/26722 may have some useful information
about general geology, Coastal area is subject to erosion and flooding. This region is in the zone of sporadic to isolated permafrost (lake
and wetland thermokart terrain), meaning that ~10-50 percent or less of the ground surface is underlain by perennially frozen ground
(permafrost) (Jorgenson and others, 2008; Olefeldt and others, 2016). Radon concentrations are modeled to be low.
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Renewable Energy Fund: Round 17 Application Summaries
App #17017 Standard Application
Kongiganak 100 kW Solar Energy Project
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)21.26 Stage 2 Tech & Econ Score (100)54.67
2. Matching Resources (15)21.00 Benefit/Cost Ratio 0.60
3. Stage 2 Feasibility (25)13.67
4. Project Readiness (5)3.67 Project Rank
5. Benefits (10)1.00 Statewide (of 16 Standard applications)6
6. Local Support (5)0.00 Regional (of all applications)
7. Sustainability (10)8.67 Stage 3 Ranking Score (100)69.26
Total Stage 3 Score (100)69.26
Funding & Cost Requested Recommended
Total Cost Through Construction $1,402,933 $1,402,933 Cost of Electricity $0.67/kWh
REF Grant Funds $728,603 $720,453 Price of Fuel $6.33/Gal
Matching Funds $674,330 $674,330 Household Energy Cost $9,427
AEA Review Comments & Recommendation Partial Funding
Partial Funding:
Costs the applicant's administration of the REF grant are not eligible uses of REF funds. The line item for "AEA Grant and NTP" for
$8,150 is therefore removed from the funding recommendation, yielding a revised funding recommendation of $720,453.
Election District: 38-S
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Renewable Energy Fund: Round 17 Application Summaries
App #17018 Heat Application
Project Type: Wind, Other Energy Region: Lower Yukon-Kuskokwim
Applicant: Atmautluak Tribal Utilities Proposed Phase(s): Construction
Applicant Type: Utility Recommended Phase(s): Construction
Atmautluak ETS Installation, Integration and Commissioning
Project Description
ATU is requesting funds to install, integrate and commission 30 ETS units, which will be in 30 low income and elders’ homes. On-going
support will be provided by ATU. Cost increases have created the need for ATU to request $286,227 from the AEA-REF to complete our
hybrid project, which requires installing, integrating, and commissioning each of the 30 ETS units, into 30 homes. This will allow us to
increase our wind-to-heat storage and reduce the cost of diesel fuel to 30 families by about 50%, from the heat provided by the ETS
units. The ETS technology has been proven in nearby communities and can be expected to reliably produce and deliver storage and
heat and substantially reduce diesel fuel use and costs to each of these 30 households. We are currently paying $6.54 per gallon and
anticipate another $1.00 increase during 2023. For each ETS unit, we estimate each taking 2-4 days to install and integrate. This
requires an electrician to be on-site for those days. In addition, the distribution lines need to be upgraded to these homes requiring other
certified expertise. Local labor from ATU will also be provided.
DNR/DMLW Feasibility Comments
Not in an area plan or on state land.
DNR/DOF Feasibility Comments
N/A
DNR/DGGS Feasibility Comments
N/A
DNR/DGGS Geohazards Comments
See general DGGS comment on hazards. The map and report https://dggs.alaska.gov/pubs/id/26722 may have some useful information
about general geology,General area is subject to erosion and flooding. This region is in the zone of sporadic permafrost (lake and
wetland thermokart terrain), meaning that 10-50 percent of the ground surface is underlain by perennially frozen ground (permafrost)
(Jorgenson and others, 2008; Olefeldt and others, 2016). Radon concentrations are modeled to be low.
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Renewable Energy Fund: Round 17 Application Summaries
App #17018 Heat Application
Atmautluak ETS Installation, Integration and Commissioning
Stage 3 Scoring Summary
Criterion (Max Score)Score Feasibility Analysis
1. Cost of Energy (30)19.26 Stage 2 Tech & Econ Score (100)56.83
2. Matching Resources (15)21.00 Benefit/Cost Ratio 0.29
3. Stage 2 Feasibility (25)14.21
4. Project Readiness (5)5.00 Project Rank
5. Benefits (10)0.50 Statewide (of 2 Heat applications)2
6. Local Support (5)1.50 Regional (of all applications)
7. Sustainability (10)6.67 Stage 3 Ranking Score (100)68.13
Total Stage 3 Score (100)68.13
Funding & Cost Requested Recommended
Total Cost Through Construction $474,387 $474,387 Cost of Electricity $0.66/kWh
REF Grant Funds $286,227 $286,227 Price of Fuel $5.36/Gal
Matching Funds $188,160 $188,160 Household Energy Cost $8,538
AEA Review Comments & Recommendation Full Funding
Election District: 38-S
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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
January 30, 2025 Senator Elvi Gray-Jackson Chair, Legislative Budget and Audit Committee, Alaska State Legislature Alaska State Capitol Room 30 Juneau, Alaska 99801
Commissioner Julie Sande
Alaska State Bond Committee
Department of Commerce, Community, and Economic Development
P.O. Box 110400
Juneau, Alaska 99811-0400
Subject: Estimate and Statement of Withdrawals from Capital Reserve Funds
Dear Senator Gray-Jackson and Commissioner Sande:
AS 44.83.110(h) requires that the Alaska Energy Authority shall annually prepare a revised
estimate of the need to withdraw money from the capital reserve funds of the Authority and a statement of all withdrawals that have occurred from the date of issuance of the bonds to the end of the preceding calendar year. The Alaska Energy Authority currently maintains capital reserve funds subject to the reporting requirements of AS 44.83.110(h) with respect to the following bonds for the Bradley Lake Hydroelectric project:
• $40,000,000 Alaska Energy Authority Power Revenue Bonds, Seventh Series (Battle Creek
Diversion Project)
• $1,239,000 Alaska Energy Authority Power Revenue Bonds, Eighth Series (Battle Creek
Diversion Project)
• $17,000,000 Alaska Energy Authority Power Revenue Bonds, Tenth Series (Transmission Line
Projects – SSQ Line)
• $166,013,134 Alaska Energy Authority Power Revenue Bonds, Eleventh Series (Bradley Lake
Required Project Work)
The original estimate of an amount of funds to be withdrawn from the capital reserve fund during the term of the bond issues was zero. There has been no change in the Authority's original estimate. In order to maintain the capital reserve fund at the appropriate level, the bond documents provide for the withdrawal of investment earnings from the fund to be
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
January 31, 2025
The Honorable Gary Stevens Senate President Alaska State Legislature State Capitol Room 111 Juneau, Alaska 99801
The Honorable Bryce Edgmon
Speaker of the House
Alaska State Legislature
State Capitol Room 208
Juneau, Alaska 99801
Re: Alaska Energy Authority annual capital project status report
Dear Senate President Stevens and Speaker Edgmon,
As required by AS 44.83.950(b), the project status reports for the following Alaska Energy Authority capital projects are attached:
•Bradley Lake Hydroelectric Project
o Original Bradley Lake Hydroelectric Project
o West Fork Upper Battle Creek
o Sterling to Quartz Transmission (SSQ)
o Dixon Diversion Project
•Alaska lntertie Project
As required by AS 44.83.085, a Susitna-Watana Hydro project status report is available on the Alaska Energy Authority website and an electronic copy was submitted to you January 21, 2025, the 1st day of legislative session.
If you have any questions, please call me at (907) 771-3009.
Regards,
Curtis Thayer
Executive Director
CC: Lacey Sanders, Director OMB
Jordan Shilling, Legislative Director
Alaska Energy Authority Page 2 of 8
ALASKA ENERGY AUTHORITY ANNUAL CAPITAL PROJECT STATUS REPORT January 30, 2025
PROJECT: Bradley Lake Hydroelectric Project
PROJECT LOCATION: Homer, Alaska
ORIGINAL ESTIMATED PROJECT COSTS1: ORIGINAL ESTIMATED COSTS OF BATTLE CREEK DIVERSION IMPROVEMENT2:
$ 355,900,000 47,200,000
ORIGINAL ESTIMATED COSTS OF SSQ LINE ACQUISITION3: ORIGINAL ESTIMATED COSTS OF BRADLEY LAKE REQUIRED PROJECT WORK4:
16,508,569
165,855,884
CURRENT ESTIMATED PROJECT COSTS: $ 585,464,453
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 165,850,384 Construction Expenditures-Dixon Diversion 9,673,800 Total Construction & Acquisition Costs $ 555,357,826 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 162,750 Total Financing Costs 12,143,650 Total Estimated Project Costs $ 567,501,476
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 3 of 8
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 SLA2024 CH 1 $ 1 ,379,700 SLA2024 CH 1 $ 2 ,294,100 $172,671,300
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: $ 567,501,476 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 REPORT AT 12/31/24:
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 Homer Electric Association
(“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
Alaska Energy Authority Page 4 of 8
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.
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 404,000 megawatt hours (MWh). The 2024 generation was slightly higher 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.
2024 was the fourth 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 2024 the energy equivalent of the Battle Creek water was 38,200 MWh which was about the long-
term average. 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 provide cash contributions of $4.5 million.
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 Sterling to Quartz Creek
Substation (“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
Alaska Energy Authority Page 5 of 8
closing costs.
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 was in its fourth full year of
operation. 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 out-of-use 69kV transmission line was removed in 2023. 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 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
AEA and utilities are designing the transmission line upgrade from 115 kV to 230 kV between Soldotna Substation and Sterling Substation and the Sterling Substation to Quartz Substation. Construction for the first section between Sterling Substation and Quartz Substation has been bid and will occur in early 2025. Construction on follow-on sections will occur through 2028. The estimated construction cost is $92 million.
AEA is purchasing from the utilities capacity on their Battery Energy Storage Systems (BESS) to stabilize the grid from Bradley Lake power plant oscillations for $28 million. Two BESS’s (Soldotna and Anchorage) have been constructed and are in operation. Capacity purchase agreements are expected to be finalized in early 2025.
During 2024, feasibility studies continued for the prospective Dixon Diversion Project. Year one of two environmental studies were performed for licensing. Engineering geophysical work along the
tunnel alignment and conceptual facility drawings were designed. Annual energy was verified and
required facilities were optimized to reduce estimated total project cost. State capital funds will
be used to advance studies in 2025.
Alaska Energy Authority Page 6 of 8
ALASKA ENERGY AUTHORITY Annual CAPITAL PROJECT STATUS REPORT January 30, 2025 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 12/31/24 $ 16,182,455
Projection to Complete Upgrades/Improvements: 8,117,545
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 SLA2024 CH 1 SLA2024 CH 1
$ 8,160,564 $ (1,379,700) $ (2,294,100)
Source of Funds-Upgrades/Improvements $ 20,626,200
Total Source of Funds: $149,089,319
Alaska Energy Authority Page 7 of 8
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 12/31/24: 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 a 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.
AEA is working through the IMC to upgrade the communications from Anchorage to Healy. Prior to this project, communications were accomplished through microwave equipment shared with the Alaska Department of Public Safety. Once completed in 2025, Intertie communication will be accomplished through a dedicated microwave system. The IMC applied for and was awarded over $11 million dollars in funding from the Infrastructure Investment and Jobs Act (IIJA) through AEA. These funds will be used to reinforce the Intertie against snow loading in areas where snow loading has historically required in person inspection to maintain safety standards. Funding is also being used to improve data collection throughout the
Alaska Energy Authority Page 8 of 8
Railbelt with an interconnected Synchrophasor system. 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.
DATE ROLE DESCRIPTIONLOCATION TEAM MEMBERMarch 27, 2025 Newsletter Alaska Electric Vehicle Working Group (AKEVWG) April Newsletter Sent to 277 Recipients Email Brandy DixonMarch 27, 2025 Attendee Alaska Sustainable Energy Conference (ASEC) Planning Committee Virtual Brandy DixonMarch 25, 2025 Media Inquiry Follow Up questions to March 20 House Finance Committee Presentation, Tim Bradner Phone Brandy DixonMarch 18, 2025 Presenter AEA Railblet Innovation Resiliency Project Award Kickoff Presentation to Department of Energy VirtualCurtis Thyaer, Bryan Carey, Jim Mendenhall, Josi HartleyMarch 18, 2025 Media Interview AEA Updates to Gavel to Gavel, Tim Bradner, Alaska Legislative Digest Virtual Curtis ThayerMarch 14, 2025 Newsletter AKEVWG March Newsletter Sent to 279 Recipients Email Brandy DixonFebruary 19, 2025 Media Interview Federal Funding Pause Impacts, Alan Bailey, Petroleum News Phone Curtis ThayerFebruary 19, 2025 Presenter AEA Presentation to Alaska Section of the Institute of Electrical and Electrical Engineers Anchorage, AK Curtis ThayerFebruary 19, 2025 Media InquiryAccess of Inflation Reduction Act and Infrastructure Investment and Jobs Act Grant Funds, Anna Kramer, NOTUSEmail Brandy DixonFebruary 13, 2025 Newsletter AKEVWG February Newsletter Sent to 269 Recipients Email Brandy DixonFebruary 12, 2025 Presenter Southeast Conference Mid-Session Summit Juneau, AK Curtis ThayerFebruary 6, 2025 Media Inquiry Alaska’s Energy Challenges & Lou Hrkman’s Presentation, K Kaufmann, RTO Insider/NetZero Insider In Person Curtis ThayerFebruary 5, 2025 Media Inquiry AEA Projects Paused Due to Executive Order, Alex DeMarban, ADN Email Brandy DixonFebruary 5, 2025 Presenter Alaska Power Association State Legislative Conference Juneau, AK Tim SandstromFebruary 3-7, 2025 Moderator National Association of State Energy Officials Federal Forum Washington, DC Curtis ThayerJanuary 30, 2025 Attendee ASEC Planning CommitteeVirtual Brandy DixonJanuary 27, 2025 Media Interview Impacts of Executive Orders Freezing IRA/IIJA Funding, Jack Barnwell, Fairbanks Daily News-MinerPhone Curtis ThayerJanuary 16, 2025 Newsletter AKEVWG January Newsletter Sent to 272 Recipients Email Brandy DixonJanuary 15, 2025 Presenter AEA Long-Duration Energy Storage Presentation Virtual Bryan CareyJanuary 13, 2025 Media Inquiry AEA's Big Projects, Alex DeMarban, Anchorage Daily News Email Brandy DixonJanuary 13, 2025 Media Inquiry Transmission Line Project, Tim Ellis, KUAC Fairbanks Email Brandy DixonJanuary 13, 2025 Press Release AEA and DOT&PF Secure FHWA Approval for FY25 Alaska NEVI Plan Email/Social Media Brandy DixonJanuary 9, 2025 Media Inquiry Alaska’s Grid Resilience, Tim Ellis, KUAC Phone Curtis ThayerJanuary 8, 2025 Press Release AEA Awards $20.9 Million to Strengthen Interior Alaska’s Grid Resilience Email/Social Media Brandy DixonJanuary 7-17, 2025 Attendee Governor's Trade MissionUnited Arab Emirates Curtis ThayerJanuary 6, 2025 Speaker/Attendees Governor's Energy Press ConferenceRobert B. Atwood Building, Anchorage, AKCurtis Thayer, Brandy DixonDecember 19, 2024 Attendee ASEC Planning CommitteeVirtual Brandy DixonDecember 19, 2024 Attendee AEA Presentation and Discussion with Westinghouse Virtual Curtis ThayerDecember 12, 2024 Newsletter Alaska Electric Vehicle Working Group (AKEVWG) December Newsletter Sent to 269 Recipients Email Brandy DixonDecember 12, 2024 Host Legislative Lunch and LearnAEA Office, Anchorage, AK AEA TeamDecember 11-12 Vendor Booth 74th Annual Alaska Municipal League Local Government ConferenceDena’ina Civic and Convention Center, Anchorage, AKHannah Amick, Shannon Apgar-Kurtz, Katherine Aubry, Brandy Dixon, Quinlan Harris, Josi Hartley, Anna Larsen, Jim Mendenhall Dawn Molina, Taase Toli-Moana, Chris McConnell, Bill PriceDecember 9, 2024 Media Inquiry Dixon Diversion, Tim Bradner, Alaska Economic Report and Alaska Legislative Digest Email Brandy DixonAEA COMMUNITY OUTREACHLast Updated on April 2, 2025 (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 ROLE DESCRIPTIONLOCATION TEAM MEMBERDecember 5, 2024 Attendee Anchorage Assembly Retreat on Energy & InfrastructureUniversity of Alaska Anchorage, Anchorage, AKAudrey AlstromDecember 5, 2024 Speaker/Attendees AEA Presentation to Alaska Power Association Managers' Forum Crowne Plaza, Anchorage, AK Curtis Thayer, Brandy DixonNovember 25, 2024 Media Interview AEA Payments for BESS System Usage, Alan, Bailey, Petroleum News Phone Curtis ThayerNovember 16, 2024 Newsletter AKEVWG November Newsletter Sent to 269 Recipients Email Brandy DixonNovember 8, 2024 Presenter AEA Infrastructure Projects Overview Presentation to American Public Works Association Virtual Bryan CareyNovember 6, 2024 Presenter AEA Modernizing the Railbelt Grid Presentation to New Energy Alaska AEA Office, Anchorage, AK Curtis ThayerNovember 5, 2024 Presenter AEA Presentation to Anchorage Rotary Club Petroleum Club Curtis ThayerOctober 30, 2024 Host AKEVWG Technical Session: Southeast Conference Recap AEA Office/Virtual, Anchorage, AK Josi HartleyOctober 28, 2024 Presenter AEA Modernizing the Railbelt Grid Presentation to Center Right Coalitions Alaska Support Industry Alliance, Anchorage, AKCurtis ThayerOctober 24, 2024 Attendee Chugach Legislative LuncheonAlaska Native Heritage Center, Anchorage, AKCurtis Thayer, Brandy DixonOctober 23, 2024 Presenter AEA Modernizing the Railbelt Grid Presentation to Regulatory Commission of Alaska Regulatory Commission of Alaska, Anchorage, AKCurtis ThayerOctober 18, 2024 Newsletter AKEVWG October Newsletter Sent to 271 Recipients Email Brandy DixonOctober 17-19, 2024 Vendor Booth Alaska Federation of Native ConventionDena’ina Civic and Convention Center, Anchorage, AKHannah Amick, Katherine Aubry, Karen Bell, Brandy Dixon, Patrick Domitrovich, Conner Erickson, Quinlan Harris, Amy Jackson, Anna Larsen, Dean Maschner, Jim Mendenhall, Dawn Molina, Bill Price, Yosty Storms, Ashley StrevelerOctober 15, 2024 Vendor Booth Alaska Tribal Water and Sanitation SymposiumWilliam A. Egan Civic & Convention Center, Anchorage, AKJustin Tuomi, Ashley StrevelerOctober 7, 2024 Speaker/AttendeesChugach Electric and Matanuska Electric Association: Battery Energy Storage System Commissioning CeremonyChugach Electric Headquarters, Anchorage, AKCurtis Thayer, Bryan Carey, Brandy DixonOctober 4, 2024 PresenterChugach Electric and Matanuska Electric Association: Battery Energy Storage System Commissioning CeremonyWestmark Fairbanks Hotel & Conference Center, Fairbanks AKAudrey AlstromOctober 4, 2024 Attendee Chugach Electric Ribbon Cutting Ceremony: Chugach's Direct Current Fast ChargerChugach Electric Headquarters, Anchorage, AKQuinlan HarrisOctober 4, 2024 Presenter Alaska Rural Energy Conference: Utilizing Circuit Riders and Emergency Response PresentationWestmark Fairbanks Hotel & Conference Center, Fairbanks AKJustin TuomiOctober 4, 2024 Presenter Alaska Rural Energy Conference: Energy Dashboard and Statewide Survey PresentationWestmark Fairbanks Hotel & Conference Center, Fairbanks AKJustin Tuomi, Dean MaschnerAEA Community OutreachPage 2 of 2
Capital Transit is constructing a charging station for its new electric buses
https://www.juneauempire.com/news/capital-transit-is-constructing-a-charging-station-for-its-new-electric-buses/ 1/4
A Capital City Transit Center electric bus (left) and diesel bus (right) wait for passengers at the
Downtown Transit Center on Friday, March 7, 2025. (Jasz Garrett / Juneau Empire)
Capital Transit is constructing a charging
station for its new electric buses
Capital Transit superintendent says fleet offering better experience than first electric bus
received in 2020.
By Jasz Garrett
Tuesday, April 1, 2025 12:33am
The City and Borough of Juneau replaced seven 2010 diesel buses with battery -electric
vehicles in December, and now the fleet is getting its own charging station.
Rich Ross, superintendent of Capital Transit, said the new buses have run “flawlessly,”
even in the winter, except for minor charging and operational issues. Despite a learning
Capital Transit is constructing a charging station for its new electric buses
https://www.juneauempire.com/news/capital-transit-is-constructing-a-charging-station-for-its-new-electric-buses/ 2/4
curve with the new technology, two to three electric buses have been out every day
since being equipped for revenue service. The other four should hit the road in June.
“It’s been a far better experience than the electric bus we received in 2020,” Ross said.
“These ones have a much higher range, so we haven’t been experiencing any of the
range anxiety we had with that first electric bus.”
The city’s first electric bus has not moved in about two years, and Capital Transit is still
seeking approval to sell or dispose of it.
The defective bus was made by the manufacturing business Proterra. First, it was down
for nine months because it lacked a wiring harness. Once Proterra provided the city with
the part, one of the bus’s transmissions failed. The company filed for bankruptcy in
2023, just as the bus was set to service the Mendenhall Express route. The bus was
funded primarily through a Federal Transit Administration (FTA) grant, with the
remainder from a settlement fund managed by the Alaska Energy Authority.
Ross said the new buses run on all routes and currently take up to six hours to charge
at Bentwood Place. They started arriving last October, and the first bus went into
service in January. During 20-degree weather that month, the buses served Capital
Transit’s longest routes and still had battery capacity at the end of the day.
“We were able to complete 10- and 11-hour routes with them and have them return
back to our bus barn with 27% beta charge remaining,” he said.
Capital Transit is constructing a charging station for its new electric buses
https://www.juneauempire.com/news/capital-transit-is-constructing-a-charging-station-for-its-new-electric-buses/ 3/4
Construction begins at the Valley Transit Center on Monday, March 31, 2025. (Jasz Garrett / Juneau
Empire)
The working electric buses were manufactured by Gillig, the same company that
supplies the city’s diesel fleet. The electric bus interiors have a similar layout, offering
passengers a familiar but quieter riding experience. Passengers now have the option to
charge mobile devices. This month, Capital Transit also plans to add the ability to pay
for bus fare online through a mobile app, Token Transit. Fares by cash and physical
passes will still be accepted.
The electric buses may offer a smoother ride, but passengers will experience temporary
inconveniences as their new on-route charging system is installed at the Valley Transit
Center. During the construction, the public parking lot, restrooms, and public electric
vehicle chargers will be unavailable, and passengers will board and depart the bus from
the Park & Ride lot just behind their usual stop, near The Alaska Club. Constructio n
began Monday and is expected to be completed by mid -summer. A notice posted by
Capital Transit states, “This upgrade will help us provide cleaner, more efficient
transportation for our community.”
Capital Transit is constructing a charging station for its new electric buses
https://www.juneauempire.com/news/capital-transit-is-constructing-a-charging-station-for-its-new-electric-buses/ 4/4
The project is estimated to cost approximately $1.6 million, which is primarily covered
by an Alaska Department of Transportation and Public Facilities grant, with CBJ paying
$160,759.
Ross emphasized he’s not experiencing the same anxiety he did with the city’s first
electric bus, but President Donald Trump’s executive order to end an electric vehicle
mandate on Jan. 20 may put the brakes on future plans.
“It shouldn’t affect these buses at all,” Ross said. “Those funds have already been
secured, but future funding is to replace our other aging-out diesel buses. That’s the big
question we have, if there’s still going to be funding for electric buses or not.”
Eleven diesel buses remain in the Capital Transit fleet, four of which would be eligible
for replacement in 2028 and the other seven in 2030. In the past, the FTA offered
funding when buses hit 12 years of age or 500,000 miles.
CBJ was awarded $5 million in funding for the electric buses through the FTA’s Low- or
No-Emission (Low-No) Grant Program, which assists state and local governments in
purchasing or leasing zero-emission and low-emission transit buses.
Federal funding freeze could jeopardize
Tyee hydro expansion
https://www.wrangellsentinel.com/story/2025/03/19/news/federal-funding-freeze-could-jeopardize-
tyee-hydro-expansion/14342.html
Federal funding freeze could jeopardize Tyee
hydro expansion
Larry Persily, Wrangell Sentinel | Mar 19, 2025
Though a $5 million federal grant to help pay for expanding the generating
capacity at the Tyee Lake hydroelectric station is “clearly frozen,” the head of the
Southeast Alaska Power Agency hopes the funds will be released soon and the
project can stay on schedule.
The agency’s lobbyist in Washington, D.C., and others “feel fairly confident … that
freeze will be thawed,” Robert Siedman, chief executive officer of the Southeast
Alaska Power Agency, or SEAPA, said earlier this month.
The Tyee money is caught up in the nationwide spending freeze of federal funds
ordered by President Donald Trump.
If the money is released soon, the project could stay on schedule, Siedman said.
But if the freeze continues, “it does delay day by day the project.”
Wrangell and Petersburg need the power generating expansion to handle the
increased load, particularly with a growing number of homes and businesses
converting from diesel-fueled heating systems to electric heat pumps.
The project includes installing a third 10-megwatt turbine alongside the two
existing power turbines of the same size at the Tyee generating station at
Bradfield Canal, on the mainland across from Wrangell Island. Tyee went online
in 1984.
The power agency’s plan — assuming no delays — is to start making power from
the third generator in December 2027.
Federal funding freeze could jeopardize
Tyee hydro expansion
https://www.wrangellsentinel.com/story/2025/03/19/news/federal-funding-freeze-could-jeopardize-
tyee-hydro-expansion/14342.html
Design work is more than 90% complete and bids to supply the turbine were due
Feb. 28, but SEAPA extended the deadline to March 21 after receiving interest
from five or six potential suppliers, Siedman said.
The agency’s board of directors is scheduled to meet March 27 and could approve
the turbine contract.
In addition to the $5 million grant previously approved by the U.S. Department of
Energy, SEAPA is requesting $4 million from the state through a renewable
energy projects grant fund at the Alaska Energy Authority.
That money is contingent on the state budget currently under construction in
the Legislature. The governor requested funds for the energy grant program, but
not enough to reach the Tyee project on the priority list. Legislators could expand
the funding to cover Tyee, but state money is limited this year and the budget
already is in a deficit.
SEAPA is pursuing additional federal funding under an investment tax credit
program to get it close to the estimated $20 million price tag for the project.
State funding totaling more than $130 million covered the cost of building the
Tyee power station and transmission line into Wrangell and Petersburg in the
early 1980s.
Numerous Alaska projects worth over $1B remain uncertain weeks
after Trump order froze funds, consumer advocacy group reports
https://www.adn.com/business-economy/energy/2025/03/11/numerous-alaska-projects-worth-over-1b-remain-
uncertain-weeks-after-trump-order-froze-funds-consumer-advocacy-group-reports/
1/3
Numerous Alaska projects worth over $1B
remain uncertain weeks after Trump order
froze funds, consumer advocacy group
reports
By Alex DeMarban
Published: 15 hours ago
Solar panels in Bethel, photographed on Thursday, May 5, 2022. (Emily Mesner / ADN)
Alaska projects that were selected to receive more than $1 billion in federal funds remain in a
state of uncertainty after President Donald Trump froze funding in January for two major Biden-
era bills, a consumer advocacy group, businesses and other entities said on Tuesday.
Numerous Alaska projects worth over $1B remain uncertain weeks
after Trump order froze funds, consumer advocacy group reports
https://www.adn.com/business-economy/energy/2025/03/11/numerous-alaska-projects-worth-over-1b-remain-
uncertain-weeks-after-trump-order-froze-funds-consumer-advocacy-group-reports/
2/3
Affected projects include renewable energy programs, weatherization efforts and erosion
protection, often in Alaska villages where electricity costs several times the national average and
climate impacts are endangering roads and other infrastructure, they told reporters.
The information was organized and shared by the Alaska Public Interest Research Group, which
advocates for government accountability, and other groups.
In a Jan. 20 executive order, Trump froze funding for the $1.2 trillion bipartisan infrastructure act
and the $900 billion Inflation Reduction Act. A federal judge in Rhode Island
recently extended an order blocking the freeze, but the Trump administration appealed the
decision on Monday.
Groups said Tuesday that it’s uncertain what programs will receive future funding, causing
projects to be put on hold, and echoed concerns from groups and contractors nationwide.
The uncertainty is damaging Alaska’s ability to update old power systems, find new energy
sources to replace dwindling Cook Inlet natural gas, and reduce costly power and heating bills
for families, the groups said.
Project delays have halted hiring for construction jobs and threatened plans by local
governments to benefit for decades from new electric production, they said.
“Without this support, Alaskan communities, especially remote Native communities, will be left
with failing infrastructure and unaffordable energy prices,” said June Okada, infrastructure
funding analyst with the Alaska Public Interest Group. “Our government needs to uphold its
commitments by fulfilling its contractual obligations.”
An array of projects have been affected by the freeze, after being selected for funding following
extensive planning and vetting, said Tashina Duttle of DeerStone Consulting. The company
provides grant-writing and development for many projects in rural Alaska and tribal
communities.
The projects include:
• $40 million for “pre-disaster mitigation funding” in Noatak in Northwest Alaska, where
the river is causing erosion that threatens fuel tanks for power and water lines.
• $20 million for housing replacement in the Southwest Alaska village of Chefornak.
• $20 million for new solar power, clean water and housing in the Interior Alaska village of
Huslia.
• $7 million for a hydroelectric dam in Chignik on the Alaska Peninsula.
• $55 million for solar and battery-storage projects in several Northwest Alaska
communities.
Numerous Alaska projects worth over $1B remain uncertain weeks
after Trump order froze funds, consumer advocacy group reports
https://www.adn.com/business-economy/energy/2025/03/11/numerous-alaska-projects-worth-over-1b-remain-
uncertain-weeks-after-trump-order-froze-funds-consumer-advocacy-group-reports/
3/3
“Without the planned projects, communities remain trapped in a cycle of aging and
deteriorating rural electric utilities, high energy costs, and are often 100% reliant on diesel and
the fragile supply chain of fuel transportation to their communities,” Duttle said.
[Hundreds of millions in funding for Alaska energy projects on hold after Trump executive order]
One program facing challenges involves a nearly $40 million grant allowing heat pump
installation in more than 6,000 homes in communities across much of Alaska, said Andy
Romanoff with Alaska Heat Smart in Juneau. The nonprofit that works to reduce household
energy costs and promote energy efficiency.
The funding was frozen, but now at least for the moment it has been unfrozen, apparently due
to rulings by federal courts, Romanoff said.
The back-and-forth makes it difficult to know if the company should hire people for the project,
he said.
“This freezing and thawing is delaying program rollout,” he said. “We have no idea what the
long-term status is.”
The iffiness over funding affects grants designed to expand the use of solar power, including for
a program that would bring solar power to low-income households in Alaska communities, said
Chase Christie with Alaska Solar, a solar-panel installation company in Anchorage.
Alaska Solar has been involved in early discussions about participating in that program, but
questions over future funding make it hard to determine if people should be hired to prepare
for it, Christie said.
Christie said he’s optimistic the funding will ultimately be released. That will benefit households
and Southcentral Alaska as it faces a shortage of gas from Cook Inlet, he said.
“We think that it’s a win-win for the state, helping these communities,” while also addressing the
potential natural gas shortfall, he said.
Other organizers of the press conference were The Alaska Center, a nonprofit, and United Today,
Stronger Tomorrow. United Today is a community organizing group operating in multiple states
that is sponsored by Community Change, a group based in Washington, D.C., that receives
funding from progressive organizations.
Opinion: Alaska could be entering a golden age of electricity
generation. But we need clear direction from elected officials.
https://www.adn.com/opinions/2025/02/27/opinion-alaska-could-be-entering-a-golden-age-of-electricity-generation-
but-we-need-clear-direction-from-elected-officials/
1/3
Developers put brakes on multiple solar
energy projects in Southcentral Alaska, citing
costs and federal politics
By Alex DeMarban
Published: 1 day ago
Electrical transmission lines connect the Beluga Power Plant in Tyonek with Anchorage, seen in Point
MacKenzie on June 22, 2023. (Loren Holmes / ADN)
In our frenetic modern world, one of the hardest problems is gaining perspective. This is
especially true of Alaska’s energy development. Alaskans love to debate prospective
megaprojects, like the liquefied natural gas pipeline or the Susitna -Watana hydro project. Yet
we seldom pause to appreciate what we’ve already built.
The Alaska Center for Energy and Power at the University of Alaska Fairbanks has just
concluded a research project investigating how Alaskans built and operated the Railbelt
electric grid — our state’s key power infrastructure that connects the Kenai Peninsula to
Opinion: Alaska could be entering a golden age of electricity
generation. But we need clear direction from elected officials.
https://www.adn.com/opinions/2025/02/27/opinion-alaska-could-be-entering-a-golden-age-of-electricity-generation-
but-we-need-clear-direction-from-elected-officials/
2/3
Interior Alaska and serves 75 percent of the state’s population. Although most Alaskans
seldom think about the grid, it is a form of modern magic that allows inexpensive Bradley Lake
hydropower to be sent at the speed of light from Kachemak Bay to Delta Junction. On par with
the Trans-Alaska Pipeline System, the Railbelt grid is the single largest machine in Alaska.
Throughout Alaska’s history, we’ve experienced certain “golden a ges” of electrification. These
electric golden ages occurred at key moments when new technologies unlocked cheaper
energy, Alaskans needed more power to expand economic prosperity and our political leaders
worked cooperatively. Alaskan utilities and the fe deral government built impressive energy
infrastructures for national defense and economic growth. For example, by the end of one
such golden age between 1952 -1962, more than 50% of electricity was supplied by low -cost
renewable energy, namely hydropower.
These golden ages have demonstrated that we can build big things when the stars align.
Between 1904 and 2024, Alaskans built over 2.7 gigawatts of generation and 1,600 miles of
high-voltage transmission lines. Befitting the Great Land, the Railbelt grid is the biggest U.S.
power system outside of the Lower 48.
[Earlier coverage: Hundreds of millions in funding for Alaska energy projects on hold after Trump
executive order]
This history of electrifying Alaska’s Railbelt accentuates three timely insights.
First, federal spending is essential for Alaska’s power development. Approval of the Alaska
Railroad between Seward and Fairbanks created a new template for settlement and networked
electrification in 1914. Congress approved the line to “unlock” Interior Alaska and access coal,
which the U.S. Navy sought for its Pacific Fleet. Over th e next 50 years, federal investment
supported the majority of the Railbelt’s new power generation. Between 1940 and 1970, the
federal government employed more people and spent more money in Alaska than any other
entity.
Today, the federal government has awarded over a billion dollars for electricity investments,
centered on aging Railbelt generation and transmission. This is the single largest federal
investment in Alaska’s electricity system. To put $1.1 billion into perspective, it’s equivalent to
what the federal government spent to build the Alaska Railroad between 1914 and 1923 — the
very infrastructure that created the Railbelt.
Rather than putting all our energy eggs in one giant basket, these funds have been obligated to
support dozens of projects from Kotzebue to Ketchikan. This direct investment includes a crucial
new high-voltage transmission line to bring more cheap Bradley Lake hydropower to Railbelt
customers, hundreds of megawatts of new wind and solar farms, utility-scale battery
storage, community solar, rural hydro facilities, and the stabilization of existing power lines due
to thawing permafrost.
Opinion: Alaska could be entering a golden age of electricity
generation. But we need clear direction from elected officials.
https://www.adn.com/opinions/2025/02/27/opinion-alaska-could-be-entering-a-golden-age-of-electricity-generation-
but-we-need-clear-direction-from-elected-officials/
3/3
We have an Alaska Railroad-sized opportunity before us, but this funding is in jeopardy. We’ve
already seen project cancellations and Alaskans losing their livelihoods. In the face of looming
Cook Inlet gas shortages, we can’t afford a lose a single megawatt of cheap power.
Second, we’ve been most successful when building small and medium-sized facilities
commensurate with Alaska’s economy and population. While Alaskans love to dream of
megaprojects, historical evidence demonstrates that it’s more cost-effective to build
appropriately sized facilities. Megaprojects like Rampart Dam never came to fruition due to high
costs, insufficient load projections, and socio-environmental consequences. But small-to-
medium projects like Eklutna Lake (1955), Cooper Lake (1961), and Bradley Lake (1991)
hydroelectric provided cheap and reliable power, and, at the same time, backboned our modern
transmission grid.
The cumulative impact of these projects has been anything but small: Alaska’s investment in
hydro and transmission between 1980-1991 has saved the equivalent of 2 billion gallons of
diesel since 1991 and saves an additional 65 million gallons every single year.
History demonstrates that we can build out distributed power generation quickly and efficiently,
and these projects will pay big long-term dividends.
Third, transmission and power pooling are the keys to unlocking Alaska’s most efficient and
prosperous energy future. Historically, we’ve focused more on building local generation than
regional transmission lines. Yet these long-distance powerlines have proven indispensable for
creating a larger grid that has unlocked lower-cost and more diverse energy resources. Lines
built to move electricity from gas, coal, or hydropower plants have enabled access to low-cost
wind and other resources. The nature of transmission gives it a flexible character that allows for
the evolution and diversification of generation.
The history of the Railbelt grid also demonstrates the primacy of public policy and regulation in
creating a more efficient power system. While Railbelt utilities have struggled to cooperate, the
Alaska Legislature and Regulatory Commission of Alaska have provided indispensable
leadership to better unite the Railbelt. We’ve made important strides over the past decade, but
the Railbelt remains balkanized and relatively inefficient. Alaskans struggle with higher costs and
less reliable service because the Railbelt is not yet a single load balancing area, new power
projects face onerous permitting timelines, and power producers don’t have regulatory
certainty. Our power system needs clear policy directives from our elected officials. The grid is a
team sport, and we need strong captains — now more than ever.
Philip Wight is an assistant professor of history and Arctic and northern studies at the University
of Alaksa Fairbanks. This article is based on research from a new Alaska Center for Energy and
Power technical paper: “Electrifying Alaska’s Railbelt: A Generation and Transmission History,
1904-2024.”
PETROLEUM NEWS • WEEK OF FEBRUARY 23, 2025 5
www.doyondrilling.com
targeting oil, up by one from the previous week and
down 20 from 497 a year ago, with 101 rigs targeting
natural gas, up by one from the previous week and down
20 from 121 a year ago, and six miscellaneous rigs,
unchanged from the previous week and up by three from
a year ago.
Fifty-one of the rigs reported Feb. 14 were drilling
directional wells, 524 were drilling horizontal wells and
13 were drilling vertical wells.
Alaska rig count unchanged
Texas (280) was up by two rigs from the previous
week while Oklahoma (44) and Utah (13) were each up
by a single rig.
Louisiana (30) and North Dakota (32) were each
down one rig week over week.
Rig counts in other states were unchanged from the
previous week: Alaska (10), California (8), Colorado (9),
New Mexico (106), Ohio (9), Pennsylvania (15), West
Virginia (10) and Wyoming (20).
Baker Hughes shows Alaska with 10 rotary rigs active
Feb. 14, unchanged from the previous week and
unchanged from a year ago.
The rig count in the Permian, the most active basin in
the country, was up by one from the previous week at
304 and down by eight from 312 a year ago. l
continued from page 4
RIG COUNT
C
SINCE 1924
ANCHORED IN ALASKA
Cook Inlet Tug & Barge has
been providing premium
marine services for 97 years.
www.cookinlettug.com
Image by Waliszek.
l GOVERNMENT
Government spending freeze impacts Alaska
President Trump’s pause on funding from federal government grants impacting Cook Inlet transmission line, other energy projects
By ALAN BAILEY
For Petroleum News
D uring a presentation to the Alaska House Energy
Committee on Feb. 10, Curtis Thayer, executive
director of the Alaska Energy Authority, confirmed that the
current pause in federal funding associated with federal
grants applies to funding assistance for the construction of
a subsea electricity transmission line between the Kenai
Peninsula and Beluga.
The purpose of the line is to significantly increase the
transmission capacity between the Kenai Peninsula and the
Anchorage region, while also remediating the problem of
the existing transmission line being a single point of failure
in the transmission system.
The GRIP program
The federal funding of $206.5 million came through the
Department of Energy Grid Resilience and Innovation
Partnership, or GRIP, program and requires matching
funds. Using initial matching funds of $12.7 million from
the state and $50 million in bond funding available from
the Railbelt electric utilities, AEA has started work on the
project.
Thayer told the committee that
the funding had been appropriated
and approved two years ago by
Congress and President Biden, and
that AEA has a signed grant agree-
ment with the Department of Energy,
enabling the project to proceed.
And, although the grant has been
paused, DOE has reimbursed AEA
for some costs already incurred.
Moreover, in the interest of not missing a construction sea-
son for the project, AEA is continuing to move forward
with the project using the matching funds that are avail-
able, Thayer said.
Thayer said that, especially given President Trump’s
stated awareness of the importance of infrastructure and
transmission, he feels confident that the federal grant pro-
gram will move forward again.
Other projects impacted
Thayer also commented that $20 million in federal
funding in support of three projects by Golden Valley
Electric Association is also on hold. Thayer later told
Petroleum News that a total of $504 million in grant fund-
ing that comes through AEA is impacted. And there are
also other projects around Alaska that are not funded
through AEA that are also impacted — the funding associ-
ated with these projects may amount to as much as another
$500 million, Thayer said.
Thayer re-iterated his confidence that this is a tempo-
rary pause in the funding. This type of pause in federal
action is typical of what happens when a new federal
administration comes into office, he said. And there is fed-
eral money coming in for work that has already been com-
pleted, he confirmed.
Although in general the federal funding has been
paused, the National Electric Vehicle Infrastructure, or
NEVI, funding program for installing high speed electric
vehicle charging stations on the road system has been sus-
pended rather than paused. Thayer commented that the
implementation of this program has so far has proven dis-
appointing, with only 52 charging stations being approved
across the country.l
CURTIS THAYER
Trusted upstream
coverage
Advertise in
Petroleum News:
Call 907.250.9769
Interior EV expansion in limbo following
federal funding freeze
https://www.alaskasnewssource.com/2023/12/13/southcentral-ak-mayors-start-energy-solution-coalition/ 1/2
FAIRBANKS, Alaska (KTUU/KTVF) - Two plans meant to expand electric vehicle (EV) infrastructure
in the interior have been met with uncertainty following executive orders signed by President
Donald Trump.
One of the plans for the interior was prepared by the Fairbanks Area Surface Transportation
(FAST) Planning organization.
“FAST planning [is] looking specifically at the Fairbanks, North Pole area to put together a
network of charging stations,” said Jackson Fox, the executive director of FAST Planning.
That plan had set aside $2.4 million received through the Infrastructure Investment and Jobs Act.
Fox said that plan was adopted in December of 2024, and before the signing of the "Unleashing
American Energy“ order by President Trump, they planned to “issue a call for project
nominations.”
That order states that “all agencies shall immediately pause the disbursement of funds
appropriated through the Inflation Reduction Act of 2022 (Public Law 117-169) or the
Infrastructure Investment and Jobs Act (Public Law 117-58), including but not limited to funds
for electric vehicle charging stations.”
Interior EV expansion in limbo following
federal funding freeze
https://www.alaskasnewssource.com/2023/12/13/southcentral-ak-mayors-start-energy-solution-coalition/ 2/2
“We’re a little bit nervous about issuing this call for project nominations and proceeding forward
with the design effort of a bundle of these charging stations and actually installing the
infrastructure,” Fox said.
The finances for the plan would have been reimbursed and still could be if the plan is approved
by the federal government.
Most people in the interior charge their EVs at their homes, according to Fox, but visitors
coming from the Matanuska Valley, Anchorage or the Kenai Peninsula only have access to one
public charging station in Fairbanks — located at Golden Valley Electric Association.
FAST Planning is awaiting further guidance which is expected to come this summer according to
Curtis Thayer, the executive director of the Alaska Energy Authority. They also have a plan to
expand EV infrastructure that has been put on hold due to the executive orders signed by
Trump.
For the time being, Fox said going through with their plans is going to be “a risk-based
decision.”
If the federal government does not clear the reimbursement of funds meant for the plan, Fox
said they “have other projects in the queue to move forward.”
The funds meant for the EV infrastructure would then be allocated for the other projects.
“One of those is installing a compressed natural gas filling station at the university campus,” he
said.
Copyright 2025 KTVF. All rights reserved.
Developers put brakes on multiple solar energy projects in
Southcentral Alaska, citing costs and federal politics
https://www.adn.com/business-economy/energy/2025/02/18/developers-put-brakes-on-multiple-solar-energy-projects-
as-southcentral-alaska-faces-gas-shortage/
1/5
Developers put brakes on multiple solar
energy projects in Southcentral Alaska, citing
costs and federal politics
By Alex DeMarban
Published: 1 day ago
The 8.5-megawatt Houston Solar Farm, photographed on Tuesday, Aug. 29, 2023. (Loren Holmes / ADN)
The leading builder of solar farms along Alaska’s Railbelt has pulled the plug on a large
project in Nikiski, saying it does not pencil out for its investor amid persistently high costs and
uncertainty over federal tax credits.
Renewable IPP also says it can no longer afford to lead development of two other large solar
projects it had been working on, an expansion at an existing farm in Houston, in the Mat -Su,
and a new solar farm in Clear, in the Denali Borough.
But Jenn Miller, the ch ief executive of the company, said it is continuing to work with entities
involved in all three projects to find a new developer to keep them on track.
Developers put brakes on multiple solar energy projects in
Southcentral Alaska, citing costs and federal politics
https://www.adn.com/business-economy/energy/2025/02/18/developers-put-brakes-on-multiple-solar-energy-projects-
as-southcentral-alaska-faces-gas-shortage/
2/5
“At some point you just can’t break trail anymore, and you kind of have to hand it off to
someone else who can bring fresh resources to the project,” she said in an interview Tuesday.
The uncertainties come at an increasingly critical time for the Railbelt region, with a potential
gas shortage raising fears of rolling blackouts and utilities weighing costly imports of liquefied
natural gas.
Renewable IPP subsidiary Solstice Energy last week informed the Regulatory Commission of
Alaska that it was withdrawing its petition for approval for the energy project in Nikiski near
Puppy Dog Lake.
The company said in a notice that its investor has rescinded support for the current effort after
deeming “the project to no longer be economic” under the terms of a power-purchase
agreement between Solstice and Homer Electric Association.
The investor is CleanCapital of New York, which operates solar farms and energy storage
projects in several U.S. states and in Guam.
As proposed, the Nikiski project would have become the largest solar farm in Alaska, by far.
Developers put brakes on multiple solar energy projects in
Southcentral Alaska, citing costs and federal politics
https://www.adn.com/business-economy/energy/2025/02/18/developers-put-brakes-on-multiple-solar-energy-projects-
as-southcentral-alaska-faces-gas-shortage/
3/5
With capacity of 45 megawatts, it was expected to provide about 10% of the energy for Homer
Electric and power about 9,000 homes on the Kenai Peninsula, Miller said.
The solar electricity would have sold for less than the current price of natural gas, the primary
fuel for Homer Electric, helping hold down future rates.
Miller stressed that the Renewable IPP is working with CleanCapital and Homer Electric in hopes
the project can be revived.
She said the project is currently facing a “setback.”
It’s possible that a future iteration of the project can be developed with a new application before
the regulatory commission, she said.
Miller said stubbornly high interest rates that kept borrowing costs elevated, along with high
construction costs, were factors complicating the project’s economics, she said.
Also, it’s uncertain whether the new Congress will scale back tax credits for solar energy
approved in the Inflation Reduction Act, she said. That adds to concerns about the project,
which had factored the tax credits into its plans, she said.
Contributing to the questions is the new administration under President Donald Trump, she said.
Trump issued an executive order on Jan. 20 suspending funding under the Biden-era act for
further review.
“The (Solar) Investment Tax Credit is separate from that (order) but there’s still just a question in
the community about what will happen to those tax credits? What will the amount be?” she said.
And so with the uncertainty, “we don’t have a stable climate for investment to move forward,”
she said.
[Hundreds of millions in funding for Alaska energy projects on hold after Trump executive order]
Julia Bell, chief investment officer for CleanCapital, said costs for the project have come in higher
than expected, so the project will have to change in order to advance.
Alaska is a nascent market for clean energy, so ups and downs are part of the process, she said.
“Solar is important to Alaska’s future and that means we need to find ways to address these
challenges,” she said. “We are hopeful that we can push Puppy Dog Lake forward with Homer
Electric.”
Homer Electric will not develop the project but will seek to buy affordable power from it, if
constructed, said Keriann Baker, the utility’s spokesperson.
Developers put brakes on multiple solar energy projects in
Southcentral Alaska, citing costs and federal politics
https://www.adn.com/business-economy/energy/2025/02/18/developers-put-brakes-on-multiple-solar-energy-projects-
as-southcentral-alaska-faces-gas-shortage/
4/5
“We’re still interested in the project,” Baker said. “We want to see any new pricing that would
happen. But we’re still talking to Solstice and CleanCapital, and we’ll entertain what’s put before
us.”
The project is large and complex, so bumps in the process are not unusual, she said.
Renewable IPP is also stepping away from its role leading development of projects in Houston
and in Clear, Miller said.
The projects were expected to be similar in size to the Nikiski project, she said.
Miller said Renewable IPP is a small company that has spent about $500,000 on the Nikiski
project.
It can’t continue to spend money on development for another year without generating new
income, she said.
It will focus on operating the solar farms it has built in recent years, in Willow and Houston, she
said. CleanCapital owns the Houston project.
After “four years of effort and over a half-million in spend, we’ve exhausted resources to further
pursue new project development as a company,” she said in a text.
Renewable IPP has already overcome some hurdles in getting the project in Nikiski to this point,
she said.
“Sadly as a small business, we can’t afford to weather another storm,” she said.
Chris Rose, head of the Renewable Energy Alaska Project, said it is “disappointing” that the
future of the solar projects is uncertain.
New renewable energy is needed to preserve natural gas from Cook Inlet that’s running low, he
said. That will also help reduce reliance on gas imports that will push gas costs up at least 50%,
he said.
“Every electron that we can produce with local renewable energy is an electron we don’t have to
import with natural gas,” he said.
He said a renewable portfolio standard that would require electric companies to obtain a
significant amount of power from renewable energy would help provide the long-term stability
investors are seeking for renewable power projects.
Several other states have passed such requirements.
Developers put brakes on multiple solar energy projects in
Southcentral Alaska, citing costs and federal politics
https://www.adn.com/business-economy/energy/2025/02/18/developers-put-brakes-on-multiple-solar-energy-projects-
as-southcentral-alaska-faces-gas-shortage/
5/5
They have been introduced into the Alaska Legislature in recent years, including by Gov. Mike
Dunleavy in 2022.
But they have not yet made it to the floor for a vote, he said.
Hilcorp affiliate and Chugach Electric announce proposal
to convert facility in Nikiski for LNG imports
https://www.adn.com/business-economy/energy/2025/02/06/hilcorp-affiliate-and-chugach-electric-announce-proposal-to-build-lng-import-facility-in-nikiski/ 1/5
Hilcorp affiliate and Chugach Electric
announce proposal to convert facility in
Nikiski for LNG imports
By Sean Maguire, Alex DeMarban Published: 1 day ago
The shuttered Kenai LNG plant in Nikiski. (Loren Holmes / ADN file)
Harvest Alaska, an affiliate of Hilcorp Alaska, said Thursday that it is proposing to
acquire and convert a shuttered natural gas export facility in Nikiski to begin receiving
imported gas.
The imported gas could start being received at the Kenai Peninsula facility as early as
2026, with full-scale operation starting in 2028, according to Harvest Alaska.
Chugach Electric Association — the state’s largest electric utility — said it is in talks for
the potential purchase of imported gas from the plant.
Hilcorp affiliate and Chugach Electric announce proposal
to convert facility in Nikiski for LNG imports
https://www.adn.com/business-economy/energy/2025/02/06/hilcorp-affiliate-and-chugach-electric-announce-proposal-to-build-lng-import-facility-in-nikiski/ 2/5
Southcentral Alaska utilities and cities are scrambling to plan for an anticipated
shortfall of gas from Cook Inlet, which has supplied the region for decades. Railbelt
utilities have gas contracts with Hilcorp expiring in the coming years. Hilcorp, the
region’s largest gas producer, has warned it cannot meet upcoming demand beyond
those contracts based on production from the Inlet.
Last year, Chugach Electric said that imported gas could see power prices rise by
roughly 10%.
Under the proposal announced Thursday, the other four Railbelt utilities could secure
gas supplies from the plant.
“By repurposing Marathon’s existing LNG facility, we aim to provide certainty to the
Southcentral gas market while meeting the needs of Railbelt utilities,” Harvest CEO
Jason Rebrook said in a prepared statement.
The LNG plant operated for over 40 years and was mothballed in 2017.
Marathon Petroleum acquired the plant from ConocoPhillips Alaska in 2018. Marathon
has pursued plans to convert the facility in the future so that it could accept imports of
LNG, or liquefied natural gas.
Enstar — Southcentral Alaska’s natural gas utility — last month announced its own
plans for construction of an imported gas facility. The utility told state regulators that it
had signed an exclusivity agreement with Glenfarne, a New-York based company, to
advance those plans.
Both of the plants are proposed for construction in Nikiski on the Kenai Peninsula.
A need for new gas supply by 2028
It’s unclear whether Southcentral Alaska will end up with two gas import facilities in
the end, or just one, or none at all.
The two projects are both in the early phases.
Chugach Electric Association does not see the Harvest and Enstar projects as
competing endeavors, said Julie Hasquet, a spokesperson with the utility.
Chugach Electric needs new supplies of gas by March 2028, she said.
That’s when the utility’s gas supply agreement with Hilcorp, its primary gas supplier,
comes to an end.
Hilcorp affiliate and Chugach Electric announce proposal
to convert facility in Nikiski for LNG imports
https://www.adn.com/business-economy/energy/2025/02/06/hilcorp-affiliate-and-chugach-electric-announce-proposal-to-build-lng-import-facility-in-nikiski/ 3/5
“This is the first project that’s come to us that can bring us gas in 2028, so we see it as
a near-term solution,” she said.
Other projects on the table would not make gas available until later, she said.
Southcentral Alaska utilities have worked together over the past three years, studying
different projects together and individually, Hasquet said.
“We have different needs,” she said. “We have different timelines.”
The demands for natural gas are vastly different between an electric company that can
supplement its gas with renewable power, and a natural gas company that requires all
gas, she said.
“But we’re at a point now where nobody has brought a project forward that meets
Chugach’s timeline until this one,” she said.
Sutton Republican Rep. George Rauscher, who serves on the House Energy
Committee, welcomed the dueling import proposals from Enstar and Harvest Alaska.
“I think it’s good for Alaska. Competition is always good,” he said Thursday.
Separately, Enstar and Hilcorp are tangling in court in a recently filed case over the
amount of gas Hilcorp should provide for Enstar for storage.
Enstar looks at larger project
Enstar’s gas supply contract with Hilcorp ends in 2033.
Enstar has presented a timeline to the Regulatory Commission of Alaska for its effort
with Glenfarne.
That project would begin importing gas into Alaska in 2029, according to the proposal.
John Sims, president of Enstar, said the timeline for first gas is a conservative estimate.
“There’s still a lot of work that needs to be done to determine the actual start date,” he
said.
Sims that the natural gas utility is working in the coming months with Glenfarne to
determine if its project will advance.
Hilcorp affiliate and Chugach Electric announce proposal
to convert facility in Nikiski for LNG imports
https://www.adn.com/business-economy/energy/2025/02/06/hilcorp-affiliate-and-chugach-electric-announce-proposal-to-build-lng-import-facility-in-nikiski/ 4/5
It can easily be estimated that it will cost more than $100 million to build the project,
he said.
Efforts to study the project before a final investment decision can be made are
expected to cost more than $50 million.
Sims said Thursday morning that Enstar had just learned of the proposal involving
Harvest Alaska.
Enstar is pursuing a project designed to meet the gas supply needs for utilities in the
region, said Lindsay Hobson, an Enstar spokesperson.
Enstar and the electric utilities consume about 60 billion cubic feet annually. Enstar
uses most of that gas, more than 35 billion cubic feet annually.
Federal approval for Harvest plan
Larry Persily, an oil and gas analyst and former Alaska deputy commissioner of
revenue, said the Harvest Alaska proposal would benefit from federal approval granted
in 2020 for converting the former export facility into an import operation.
The decision from the Federal Energy Regulatory Commission approves about 2.5
billion cubic feet of gas imports annually, he said.
Persily said that amount might be enough to close any potential gas shortage in the
region early on, since some gas production in Cook Inlet is expected to continue.
The approved volumes for that plan can be expanded with approval from the federal
commission, he said. The license must be extended by December anyway, he said.
Persily said Harvest Alaska’s proposal to import gas through the converted facility is
likely the most cost-effective of any of the options addressing the gas shortage.
”The fact that you’ve got much of the apparatus you already need, and the federal
authorization, makes it a logical site,” he said. “You’ve got storage tanks, you’ve got a
dock, and you’ve got a pipeline connection.”
Persily said the Regulatory Commission of Alaska would not need to approve the
conversion of the Harvest facility, but the agency would regulate contracts to store or
deliver gas to utilities.
The sites for the projects are only about 1.5 miles apart, said Peter Micciche, mayor of
the Kenai Peninsula Borough, which includes Nikiski.
Hilcorp affiliate and Chugach Electric announce proposal
to convert facility in Nikiski for LNG imports
https://www.adn.com/business-economy/energy/2025/02/06/hilcorp-affiliate-and-chugach-electric-announce-proposal-to-build-lng-import-facility-in-nikiski/ 5/5
Micciche served as ConocoPhillips’ superintendent of the LNG export plant until the
shipments ended.
Micciche said he’s “agnostic” to whichever project might be built.
“I find it hard to believe that both import terminals will be constructed,” he said. “I
would assume the most viable and economic solution will result in agreements that
satisfy the gap until something else comes along.”
He said he’s pleased to see two options.
A shortage of natural gas needed to provide power and heat could have severe
economic impacts in Alaska, including a possible closure of Marathon’s Kenai
refinery that produces gasoline, diesel, jet fuel and other products sold in Alaska, he
said.
If Alaska isn’t soon importing some LNG, “we will be importing everything that matters
to us when it comes to refined products and hydrocarbons,” Micciche said.
Republican state Sen. Cathy Giessel, co-chair of the Senate Natural Resources
Committee, and Democratic state Sen. Bill Wielechowski both expressed concern
Thursday about Harvest Alaska’s plans.
The two senators last year asked the U.S. Federal Trade Commission to investigate
Hilcorp’s “virtual monopoly” over Cook Inlet gas production.
Giessel and Wielechowski said Thursday’s announcement amplified their concerns
about Hilcorp.
”They’ll have a fully integrated monopoly all up and down from import to production to
storage,” Wielechowski said.
”That’s a lot of eggs to have in one basket with one company whose owner lives in
Texas,” Giessel said.
[Correction: An earlier version of this article incorrectly reported that Chugach Electric
Association had already agreed to purchase gas from the import facility.]
Federal Approval Secured for Alaska’s Electric Vehicle Infrastructure Plan
https://www.akbizmag.com/industry/energy/federal-approval-secured-for-alaskas-electric-vehicle-infrastructure-plan/ 1/3
Federal Approval
Secured for Alaska’s
Electric Vehicle
Infrastructure Plan
Alaska Energy Authority began supporting a charging corridor between Anchorage and
Fairbanks with stations installed at Three Bears Alaska in Healy.
Federal Approval Secured for Alaska’s Electric Vehicle Infrastructure Plan
https://www.akbizmag.com/industry/energy/federal-approval-secured-for-alaskas-electric-vehicle-infrastructure-plan/ 2/3
PHOTO CREDIT: SCOTT RHODE | ALASKA BUSINESS
The third Alaska National Electric Vehicle Infrastructure
(NEVI) plan was approved by the Federal Highway
Administration (FHWA), securing $11 million in federal
funding to continue expanding the state’s electric vehicle
charging infrastructure in FY2025.
The FHWA funding enables the Alaska Energy Authority
(AEA) and Alaska Department of Transportation and
Public Facilities (DOT&PF) to complete Phase 1 of NEVI-
compliant charging stations along the Alternative Fuel
Corridor between Anchorage and Fairbanks.
Plan Shaped With Alaskans’ Input
“This funding allows us to leverage available federal resources to directly benefit Alaskans,” says
AEA Executive Director Curtis W. Thayer. “Developing EV charging infrastructure ensures our
state remains connected and is well-prepared for the future, while also addressing Alaska’s
unique transportation challenges.”
DOT&PF Commissioner Ryan Anderson adds, “The approval of the FY25 NEVI Plan is a
significant step forward for Alaska’s transportation network. Expanding EV charging
infrastructure gives Alaskans more travel options while the department continues to build a
reliable and resilient transportation system across the state for all users.”
The Phase 1 charging stations include at least four and up to eight Combined Charging System
ports, each capable of delivering 150kw. Once the Alternative Fuel Corridor is fully built out and
meets FHWA criteria, anticipated at the end of 2025, the program will transition to Phase 2. This
phase will focus on connecting smaller urban areas, rural communities on the road system, and
Alaska’s road network to Canada. It will also extend infrastructure along the Alaska Marine
Highway System to serve coastal communities.
This latest funding allocation builds on the $30 million designated for fiscal years 2022, 2023,
and 2024, bringing the total federal investment in Alaska’s EV charging infrastructure to $41
million. The FY25 NEVI Plan outlines strategies to increase reliable, fast EV charging, ensuring a
Federal Approval Secured for Alaska’s Electric Vehicle Infrastructure Plan
https://www.akbizmag.com/industry/energy/federal-approval-secured-for-alaskas-electric-vehicle-infrastructure-plan/ 3/3
consistent charging experience for residents and travelers. It also includes renewed approval for
discretionary exceptions, providing greater flexibility for placement of charging stations between
Anchorage and Fairbanks. These exceptions will specifically benefit areas like Wasilla to Trapper
Creek, Trapper Creek to Cantwell, and Healy to Nenana.
Alaska is expected to receive $52 million over five years, with updated plans to be submitted
annually to the FHWA detailing how the funds will be spent.
AEA and DOT&PF say input from Alaskans during the planning process has proven very
valuable. Community feedback has played a crucial role in shaping a plan that effectively
addresses local needs and priorities.
The NEVI program, established through the Infrastructure Investment and Jobs Act of 2021,
provides dedicated federal funding to states to support the strategic deployment of EV Level 3
Direct Current Fast Charging infrastructure. The goal is to create an interconnected, reliable
charging network, focusing on locations near interstate highway exits.
Hilcorp affiliate and Chugach Electric announce proposal
to convert facility in Nikiski for LNG imports
https://www.adn.com/business-economy/energy/2025/02/06/hilcorp-affiliate-and-chugach-electric-announce-proposal-to-build-lng-import-facility-in-nikiski/ 1/5
Hilcorp affiliate and Chugach Electric
announce proposal to convert facility in
Nikiski for LNG imports
By Sean Maguire, Alex DeMarban Published: 1 day ago
The shuttered Kenai LNG plant in Nikiski. (Loren Holmes / ADN file)
Harvest Alaska, an affiliate of Hilcorp Alaska, said Thursday that it is proposing to
acquire and convert a shuttered natural gas export facility in Nikiski to begin receiving
imported gas.
The imported gas could start being received at the Kenai Peninsula facility as early as
2026, with full-scale operation starting in 2028, according to Harvest Alaska.
Chugach Electric Association — the state’s largest electric utility — said it is in talks for
the potential purchase of imported gas from the plant.
Hilcorp affiliate and Chugach Electric announce proposal
to convert facility in Nikiski for LNG imports
https://www.adn.com/business-economy/energy/2025/02/06/hilcorp-affiliate-and-chugach-electric-announce-proposal-to-build-lng-import-facility-in-nikiski/ 2/5
Southcentral Alaska utilities and cities are scrambling to plan for an anticipated
shortfall of gas from Cook Inlet, which has supplied the region for decades. Railbelt
utilities have gas contracts with Hilcorp expiring in the coming years. Hilcorp, the
region’s largest gas producer, has warned it cannot meet upcoming demand beyond
those contracts based on production from the Inlet.
Last year, Chugach Electric said that imported gas could see power prices rise by
roughly 10%.
Under the proposal announced Thursday, the other four Railbelt utilities could secure
gas supplies from the plant.
“By repurposing Marathon’s existing LNG facility, we aim to provide certainty to the
Southcentral gas market while meeting the needs of Railbelt utilities,” Harvest CEO
Jason Rebrook said in a prepared statement.
The LNG plant operated for over 40 years and was mothballed in 2017.
Marathon Petroleum acquired the plant from ConocoPhillips Alaska in 2018. Marathon
has pursued plans to convert the facility in the future so that it could accept imports of
LNG, or liquefied natural gas.
Enstar — Southcentral Alaska’s natural gas utility — last month announced its own
plans for construction of an imported gas facility. The utility told state regulators that it
had signed an exclusivity agreement with Glenfarne, a New-York based company, to
advance those plans.
Both of the plants are proposed for construction in Nikiski on the Kenai Peninsula.
A need for new gas supply by 2028
It’s unclear whether Southcentral Alaska will end up with two gas import facilities in
the end, or just one, or none at all.
The two projects are both in the early phases.
Chugach Electric Association does not see the Harvest and Enstar projects as
competing endeavors, said Julie Hasquet, a spokesperson with the utility.
Chugach Electric needs new supplies of gas by March 2028, she said.
That’s when the utility’s gas supply agreement with Hilcorp, its primary gas supplier,
comes to an end.
Hilcorp affiliate and Chugach Electric announce proposal
to convert facility in Nikiski for LNG imports
https://www.adn.com/business-economy/energy/2025/02/06/hilcorp-affiliate-and-chugach-electric-announce-proposal-to-build-lng-import-facility-in-nikiski/ 3/5
“This is the first project that’s come to us that can bring us gas in 2028, so we see it as
a near-term solution,” she said.
Other projects on the table would not make gas available until later, she said.
Southcentral Alaska utilities have worked together over the past three years, studying
different projects together and individually, Hasquet said.
“We have different needs,” she said. “We have different timelines.”
The demands for natural gas are vastly different between an electric company that can
supplement its gas with renewable power, and a natural gas company that requires all
gas, she said.
“But we’re at a point now where nobody has brought a project forward that meets
Chugach’s timeline until this one,” she said.
Sutton Republican Rep. George Rauscher, who serves on the House Energy
Committee, welcomed the dueling import proposals from Enstar and Harvest Alaska.
“I think it’s good for Alaska. Competition is always good,” he said Thursday.
Separately, Enstar and Hilcorp are tangling in court in a recently filed case over the
amount of gas Hilcorp should provide for Enstar for storage.
Enstar looks at larger project
Enstar’s gas supply contract with Hilcorp ends in 2033.
Enstar has presented a timeline to the Regulatory Commission of Alaska for its effort
with Glenfarne.
That project would begin importing gas into Alaska in 2029, according to the proposal.
John Sims, president of Enstar, said the timeline for first gas is a conservative estimate.
“There’s still a lot of work that needs to be done to determine the actual start date,” he
said.
Sims that the natural gas utility is working in the coming months with Glenfarne to
determine if its project will advance.
Hilcorp affiliate and Chugach Electric announce proposal
to convert facility in Nikiski for LNG imports
https://www.adn.com/business-economy/energy/2025/02/06/hilcorp-affiliate-and-chugach-electric-announce-proposal-to-build-lng-import-facility-in-nikiski/ 4/5
It can easily be estimated that it will cost more than $100 million to build the project,
he said.
Efforts to study the project before a final investment decision can be made are
expected to cost more than $50 million.
Sims said Thursday morning that Enstar had just learned of the proposal involving
Harvest Alaska.
Enstar is pursuing a project designed to meet the gas supply needs for utilities in the
region, said Lindsay Hobson, an Enstar spokesperson.
Enstar and the electric utilities consume about 60 billion cubic feet annually. Enstar
uses most of that gas, more than 35 billion cubic feet annually.
Federal approval for Harvest plan
Larry Persily, an oil and gas analyst and former Alaska deputy commissioner of
revenue, said the Harvest Alaska proposal would benefit from federal approval granted
in 2020 for converting the former export facility into an import operation.
The decision from the Federal Energy Regulatory Commission approves about 2.5
billion cubic feet of gas imports annually, he said.
Persily said that amount might be enough to close any potential gas shortage in the
region early on, since some gas production in Cook Inlet is expected to continue.
The approved volumes for that plan can be expanded with approval from the federal
commission, he said. The license must be extended by December anyway, he said.
Persily said Harvest Alaska’s proposal to import gas through the converted facility is
likely the most cost-effective of any of the options addressing the gas shortage.
”The fact that you’ve got much of the apparatus you already need, and the federal
authorization, makes it a logical site,” he said. “You’ve got storage tanks, you’ve got a
dock, and you’ve got a pipeline connection.”
Persily said the Regulatory Commission of Alaska would not need to approve the
conversion of the Harvest facility, but the agency would regulate contracts to store or
deliver gas to utilities.
The sites for the projects are only about 1.5 miles apart, said Peter Micciche, mayor of
the Kenai Peninsula Borough, which includes Nikiski.
Hilcorp affiliate and Chugach Electric announce proposal
to convert facility in Nikiski for LNG imports
https://www.adn.com/business-economy/energy/2025/02/06/hilcorp-affiliate-and-chugach-electric-announce-proposal-to-build-lng-import-facility-in-nikiski/ 5/5
Micciche served as ConocoPhillips’ superintendent of the LNG export plant until the
shipments ended.
Micciche said he’s “agnostic” to whichever project might be built.
“I find it hard to believe that both import terminals will be constructed,” he said. “I
would assume the most viable and economic solution will result in agreements that
satisfy the gap until something else comes along.”
He said he’s pleased to see two options.
A shortage of natural gas needed to provide power and heat could have severe
economic impacts in Alaska, including a possible closure of Marathon’s Kenai
refinery that produces gasoline, diesel, jet fuel and other products sold in Alaska, he
said.
If Alaska isn’t soon importing some LNG, “we will be importing everything that matters
to us when it comes to refined products and hydrocarbons,” Micciche said.
Republican state Sen. Cathy Giessel, co-chair of the Senate Natural Resources
Committee, and Democratic state Sen. Bill Wielechowski both expressed concern
Thursday about Harvest Alaska’s plans.
The two senators last year asked the U.S. Federal Trade Commission to investigate
Hilcorp’s “virtual monopoly” over Cook Inlet gas production.
Giessel and Wielechowski said Thursday’s announcement amplified their concerns
about Hilcorp.
”They’ll have a fully integrated monopoly all up and down from import to production to
storage,” Wielechowski said.
”That’s a lot of eggs to have in one basket with one company whose owner lives in
Texas,” Giessel said.
[Correction: An earlier version of this article incorrectly reported that Chugach Electric
Association had already agreed to purchase gas from the import facility.]
Enstar sues Hilcorp in dispute over supply contract,
citing potential for ‘catastrophic’ gas shortage
https://www.adn.com/business-economy/energy/2025/01/24/enstar-sues-hilcorp-in-dispute-over-supply-contract-
citing-potential-for-catastrophic-gas-shortage/
1/3
Enstar sues Hilcorp in dispute over
supply contract, citing potential for
‘catastrophic’ gas shortage
By Sean Maguire
Updated: 2 minutes ago
Published: 2 minutes ago
Workers pour concrete to expand the Cook Inlet Natural Gas Storage Alaska compressor facility on Monday, July 1,
2024 in Kenai. The facility takes natural gas from producers, including Hilcorp, and stores the gas underground in a
depleted gas field until it is needed by its customers, which include Enstar and Chugach Electric. (Loren Holmes /
ADN)
Southcentral Alaska’s natural gas utility is suing Hilcorp over concerns that a cold snap
could see imminent supply shortages.
Enstar sues Hilcorp in dispute over supply contract,
citing potential for ‘catastrophic’ gas shortage
https://www.adn.com/business-economy/energy/2025/01/24/enstar-sues-hilcorp-in-dispute-over-supply-contract-
citing-potential-for-catastrophic-gas-shortage/
2/3
Enstar, which provides gas to over 150,000 customers, argued i n a complaint filed
Wednesday that Hilcorp has failed to deliver gas under contract to be stored for
periods of high demand.
”If ENSTAR is unable to meet its customers’ demands for gas because of Hilcorp’s
failures to supply the gas volumes it is contractually required to supply, the results will
be catastrophic for Southcentral Alaska,” the utility said in its request for a preliminary
injunction.
Enstar is requesting that Anchorage Judge Herman Walker order Hilcorp to start
delivering the contracted gas by Jan. 28. Walker ha s scheduled oral arguments for Jan.
31.
A spokesperson for Enstar on Friday declined to comment on the lawsuit.
In correspondence attached to the utility’s complaint, Hilcorp, which supplies roughly
90% of gas production in Cook Inlet, effectively accused Enstar of violating its contract
by improperly storing natural gas, risking supply for other users.
“We strongly disagree with their interpretation of the contracts and look forward to
resolving these issues in a timely manner,” said Matt Shuckerow, a spok esperson for
Hilcorp Alaska, by email.
Shuckerow said Hilcorp had made “various efforts” to resolve the ongoing contractual
dispute.
“We hope Enstar will come back to the table and work with us to develop a reasonable
resolution that takes into account the needs of all Alaskans that depend o n Cook Inlet
natural gas,” he said.
A looming shortfall of Cook Inlet gas has led to concerns of an energy crunch, and an
increased risk of rolling blackouts on the Railbelt, Northern Journal reported this week.
This dispute is largely unrelated, and potentially more immediate.
In its complaint filed in Anchorage Superior Court, Enstar said that its contract requires
Hilcorp to deliver 25 billion cubic feet of gas per year.
Additionally, Hilcorp is required to deliver another 4 billion cubic feet per year of “Daily
Call Option Gas” through 2033, the utility says.
Enstar said that additional gas i s required to be stored for winter and spring — periods
of higher demand to heat homes and businesses.
Enstar sues Hilcorp in dispute over supply contract,
citing potential for ‘catastrophic’ gas shortage
https://www.adn.com/business-economy/energy/2025/01/24/enstar-sues-hilcorp-in-dispute-over-supply-contract-
citing-potential-for-catastrophic-gas-shortage/
3/3
After a cold snap last year, John Sims, the president of Enstar, told lawmakers that the
utility was “extremely close” to being unable to deliver gas with its systems under
unprecedented strain.
The utility says it cur rently has less than its target volume of gas stored in Cook Inlet
Natural Gas Storage Alaska, or CINGSA.
Under current conditions, Enstar says by December it will have half its target level of
gas stored for winter.
Attached to Enstar’s complaint was correspondence between Hilcorp and the utility.
In early December, Hilcorp requested suspending delivery of that additional gas to
Enstar, with a pledge that the two parties would devise a delivery schedule in January.
Later in the month, Enstar told Hilcorp that it was requesting the extra gas to be st ored
in CINGSA.
The dispute has continued between Enstar and Hilcorp over the next few weeks.
In a Jan. 9 letter, Luke Saugier, senior vice president of Hilcorp Alaska, said that Enstar
was effectively violating its contract by improperly storing gas.
”If we deviate from these procedures, it can lead to supply imbalances, causing
shortages for other customers,” he said in a letter to the utility.
However, Enstar has argued its storage protocols were “heavily negotiated” with
Hilcorp, and that those protocol s did not change when it signed an amended contract
with the Texas-based producer last year.
The utility says that it needs all “unpurchased volumes” of gas delivered by April 1. If
Enstar faces a cold snap, the utility says it may not have the storage ca pacity to “meet
customer demand.”
This is a developing story. Check back for updates.
Why cold weather is no longer an EV battery killer
https://www.adn.com/nation-world/2025/01/23/why-cold-weather-is-no-longer-an-ev-battery-killer/ 1/3
Why cold weather is no longer an EV
battery killer
By Nicolás Rivero, The Washington Post
Updated: 1 day ago
Published: 1 day ago
A Tesla electric vehicle is charged in Westlake, Calif. (AP Photo/Mark J. Terrill, File )
Cold winters are bad news for EV batteries. But with a heat pump - the same climate-friendly
heating system that helps buildings stay warm with less energy - electric cars can run longer in
freezing temperatures.
On average, EVs lose about a fifth of their range when temperatures hit 32 degrees Fahrenheit,
according to data from Recurrent, a company that tracks the battery performance of electric
cars. That’s mainly because chilly passengers crank up the heat, w hich draws down the battery.
Why cold weather is no longer an EV battery killer
https://www.adn.com/nation-world/2025/01/23/why-cold-weather-is-no-longer-an-ev-battery-killer/ 2/3
Having a heat pump can cut range loss in half, Recurrent data show. Under most conditions,
heat pumps drain a car’s battery less than the old school electric resistance heaters that early
EVs relied on. That means the best EVs today lose only 11 percent of their range in freezing
weather.
“The concerns for EV drivers around winter weather are quickly decreasing,” said Andy
Garberson, who heads research at Recurrent.
That paves the way for more people to drive electric cars in m oderately cold places, said Greg
Brannon, director of automotive engineering at AAA. But in the coldest regions, where
temperatures regularly drop below 15 degrees Fahrenheit, drivers won’t see as much benefit
because heat pumps don’t work well at those extremes.
“It’s going to depend on the temperatures in your environment,” Brannon said.
Which EV models work best in the cold?
Recurrent used real-world data from 18,000 electric cars across the United States to measure
how long their batteries lasted in dif ferent temperatures. It ranked 20 popular EV models
according to how much range they lost in freezing weather compared with their best
performance in ideal temperatures around 70 degrees Fahrenheit.
Some EV models come with heat pumps only in certain trims or after certain model years.
Teslas, for instance, starte d coming with heat pumps only in 2021. The change made a big
difference: Model S sedans that rely on resistance heaters lost twice as much range in the cold
as newer models that have heat pumps, according to Recurrent’s analysis.
Generally, EVs that come with heat pumps did better in the cold - but not always. There are
other factors, such as battery design, that pushed some models up or down in the rankings,
Garberson said.
If you want to see the full list of EV models with heat pumps, Recurrent keeps its version here.
Why do EVs lose range in the cold?
Part of EVs’ cold weather range problem is chemistry: Colder temperatures make lithium ions
inside the battery move more sluggishly, which makes the battery less efficient. Plus, colder air
is slightly denser, which creates more drag on the car - a problem gas-powered vehicles also
deal with in the cold.
Why cold weather is no longer an EV battery killer
https://www.adn.com/nation-world/2025/01/23/why-cold-weather-is-no-longer-an-ev-battery-killer/ 3/3
But most of the range loss comes from heating. Unlike gas -powered cars, which can tap into
the waste heat from their combustion engines to warm up the cabin , electric vehicles have to
use battery power to make heat. Roughly three -quarters of range loss comes from heating,
according to a 2019 AAA study.
The traditional way to turn battery power into warmth is electric resistance heating, where the
car runs a lot of electricity through a coil that heats up and warms the air around it. But heat
pumps work differently - basically, moving existing heat around instead of creating it from
scratch - which allows them to warm up a car while using much less battery pow er.
Heat pumps, however, stop working as well when temperatures drop below about 15 degrees
Fahrenheit, according to Garberson. At that point, even cars that have heat pumps will shut
them off and switch over to backup resistance heaters.
That means on the coldest days in places such as the Midwest, when the temperature might
not rise above the single digits, it won’t make a difference if your EV has a heat pump or not,
Brannon said.
“But if you live in a more moderate environment - which most people do, you know - and
many of the daytime temperatures are in the 30s and 40s ... heat pumps would probably offer
a bigger benefit,” he said.
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Further NEVI funding announced
The Alaska Energy Authority has announced that the Federal Highway
Administration has approved the third annual funding plan for Alaska under the
National Electric Vehicle Infrastructure, or NEVI, funding program. The approval
will make a further $11 million of federal funding available for the continuing
expansion of the electric vehicle charging infrastructure across Alaska, AEA said.
NEVI funding comes from the Infrastructure Investment and Jobs Act of 2021,
which provides funding for EV charging infrastructure along public roads. Together
with $30 million awarded across fiscal years 2022 to 2024, federal investment in
Alaska’s electric vehicle charging infrastructure will amount to a total of $41 mil-
lion so far. AEA and the Alaska Department of Transportation and Public Facilities
have been focusing on the installation of high-speed charging stations along the
road corridor between Anchorage and Fairbanks. The presence of these charging
stations will improve the practicality of using electric vehicles for long distance
driving in the state. AEA says that the NEVI funded charging stations will each have
at least four charging ports, while some will have eight ports.
It is anticipated that this initial phase of charging station construction will be
completed this year, after which the focus will move to supporting smaller urban
areas and rural communities on the road system, AEA says.
“This funding allows us to leverage available federal resources to directly benefit
Alaskans,” said AEA Executive Director Curtis Thayer. “Developing EV charging
infrastructure ensures our state remains connected and is well-prepared for the
future, while also addressing Alaska’s unique transportation challenges.”
“The approval of the FY25 NEVI Plan is a significant step forward for Alaska’s
transportation network,” said DOT&PF Commissioner Ryan Anderson.
“Expanding EV charging infrastructure gives Alaskans more travel options while
the department continues to build a reliable and resilient transportation system
across the state for all users.”
—ALAN BAILEY
Division approves 2 North Slope PODs
The Alaska Department of Natural Resources’ Division of Oil and Gas has
approved plans of development for two small North Slope units, Duck Island and
Northstar.
Duck Island is operated by Hilcorp Alaska on behalf of itself and minority interest
owner Chevron U.S.A. Hilcorp Alaska operates and holds 100% working interest own-
ership in Northstar.
Both PODs cover Feb. 13, 2025, through Feb. 12, 2026.
In the 2024 POD, Hilcorp added two grassroots wells at Duck Island, MPI 2-72 and
MPI 2-74, both completed in the Ivishak reservoir, the division said. Alaska Oil and
Gas Conservation Commission records show MPI 2-72 began producing in July, but
MPI 2-74 is not yet in production as of November well data, the most recent available.
For the 2025 POD, Hilcorp plans to complete up to two rig workovers; perform
additional workovers and various non-rig wellwork as needed; conduct bridge inspec-
tions; do module leveling; and continue LACT meter upgrade project.
AOGCC data show production from Duck Island averaged 5,133 barrels per day of
crude oil in November down from 5,488 bpd in November 2023, and 491 bpd of nat-
ural gas liquids, down from 973 bpd of NGLs in November 2023.
During the 2024 POD, Hilcorp modified surface equipment, allowing produced
water to be routed to the NS-20 wells for downdip water injection. The company did
integrity wellwork on NS-24 and set a plug on the NS-20 well. Ongoing maintenance
of the island’s coastal defenses continued.
During the 2025 POD, Hilcorp will explore implementing downdip water injection
for pressure maintenance of the Kuparuk reservoir and will continue evaluation of
coiled tubing drilling options at Northstar, along with continued maintenance of coastal
defenses. AOGCC production data show Northstar averaged 2,691 bpd of crude in
November 2024 and 2,644 bpd of NGLs, compared to 3,100 bpd of crude in November
2023 and 2,622 bpd of NGLs.
—KRISTEN NELSON
EXPLORATION & PRODUCTION
l EXPLORATION & PRODUCTION
Baker Hughes US rig
down by 4 at 580
By KRISTEN NELSON
Petroleum News
T he Baker Hughes’ U.S. rotary
drilling rig count was 580 on Jan.
17, down by four from the previous week,
down by 40 from 620 a year ago and
down nine from two weeks ago. Over the
last eight weeks the rig count was
unchanged in four weeks, down in three
and up in one week with a loss of 10 and
a gain of seven, in line with the down-
ward trend dominant since the beginning
of May.
This is the lowest the domestic rotary
rig count has been since December 2021.
A drop of 17 to 731 on May 12, 2023,
was the steepest weekly drop since June
of 2020, during the first year of the
COVID-19 pandemic, when the count
also dropped by 17 to 284 on June 5, fol-
lowing drops as steep as 73 rigs in one
week in April. The count continued down
to 251 at the end of July 2020, reaching
an all-time low of 244 in mid-August
2020.
For 2024, the count peaked March 1
(and again March 15) at 629, hitting its
low point June 28 at 581. In 2023 the
count peaked early in the year at 775 on
Jan. 13, bottoming out Nov. 10 at 616.
When the count dropped to 244 in
mid-August 2020, it was the lowest the
domestic rotary rig count had been since
the Houston based oilfield services com-
pany began issuing weekly U.S. numbers
in 1944.
Prior to 2020, the low was 404 rigs in
May 2016. The count peaked at 4,530 in
1981.
The count was in the low 790s at the
beginning of 2020 prior to the COVID-19
pandemic, where it remained through
mid-March of that year when it began to
fall, dropping below what had been the
historic low in early May with a count of
374 and continuing to drop through the
third week of August 2020 when it gained
back 10 rigs.
The Jan. 17 count includes 478 rigs tar-
geting oil, down by two from the previous
week and down 19 from 497 a year ago,
with 98 rigs targeting natural gas, down
by two from the previous week and down
22 from 120 a year ago, and four miscel-
laneous rigs, unchanged from the previous
week and up by one from a year ago.
Fifty-two of the rigs reported Jan. 17
were drilling directional wells, 515 were
drilling horizontal wells and 13 were
drilling vertical wells.
Alaska rig count unchanged
California (7) and Wyoming (19) were
each up by a single rig from the previous
week.
North Dakota (32) was down by four
rigs while Louisiana (29) and Texas (281)
were each down by a single rig.
Rig counts in other states were
unchanged from the previous week:
Alaska (10), Colorado (9), New Mexico
(103), Ohio (9), Oklahoma (43),
Pennsylvania (15), Utah (11) and West
Virginia (10).
Baker Hughes shows Alaska with 10
rotary rigs active Jan. 17, unchanged from
the previous week and unchanged from a
year ago.
The rig count in the Permian, the most
active basin in the country, was
unchanged from the previous week at 304
and down by three from 307 a year ago. l
Kerr-McGee operates the Nikaitchuq
unit with a 70% interest; Armstrong
holds a 30% interest.
Buterbaugh said Kerr-McGee expect-
ed to spud an exploratory well at the
company’s second North Slope prospect,
the Tuvaaq unit, on Jan. 27. Tuvaaq,
another Kerr-McGee-operated prospect
developed by Armstrong, is in the west-
ern Milne Point region between the
Pioneer Natural Resources-operated
Oooguruk unit and the Nikaitchuq unit.
Kerr-McGee has a 42% interest in
Tuvaaq, Armstrong holds an 18% interest
and Pioneer, another Armstrong North
Slope partner, holds a 40% interest. l
continued from page 2
HISTORY
Goat Lake Hydroelectric asks to raise electricity
rates, deadline for public comment Friday
https://www.chilkatvalleynews.com/2025/01/22/goat-lake-hydroelectric-asks-to-raise-electricity-rates-deadline-for-
public-comment-friday/
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Goat Lake Hydroelectric asks to raise
electricity rates, deadline for public comment
Friday
by Rashah McChesney - Chilkat Valley News
January 22, 2025
Haines customers could face another
jump in their electricity bills if the state
approves Goat Lake Hydroelectric’s
ask to increase rates.
The company, a subsidiary of Alaska
Power & Telephone, asked to increase
rates in part due to the costs of
repairing a submarine transmission
cable which was damaged in 2019 and
cost more than $12 million to replace,
according to the company’s revenue
requirement study submitted to state
regulators. The company is looking to
generate another $618,000 a year,
according to the study.
The Regulatory Commission of Alaska put out a notice on Dec. 23 that Goat Lake proposed an
interim rate increase of 40%, effective Feb. 3, 2025, and a permanent rate increase of nearly 70%
(69.92) percent. The company provides “wholesale service” to Alaska Power Company at the
current rate of $0.06301 per kilowatt hour. The proposed interim rate is $0.08820 and the
permanent rate is $0.10710.
The company estimates that for someone on residential power using 500 kilowatt hours a
month in Haines or Skagway, the total bill could go from $129.33 to $130.30 if its permanent
rate increase is approved by state regulators. That is, that the proposed increase would likely be
offset by Power Cost Equalization, though that only applies to residential customers. And, the
company is also proposing a higher Cost of Power surcharge, or COPA, rate which fluctuates
based on the cost of fuel and purchased power. That rate can be a charge or a credit.
In his testimony to state regulators, Executive Vice President and Chief Operating Officer Jeffrey
Rice said the company has pursued other cost-cutting measures including shutting down under-
utilized equipment, and has also applied for subsidies through federal and state grant programs
Goat Lake Hydroelectric asks to raise electricity
rates, deadline for public comment Friday
https://www.chilkatvalleynews.com/2025/01/22/goat-lake-hydroelectric-asks-to-raise-electricity-rates-deadline-for-
public-comment-friday/
2/3
for hydro and renewable electricity sources. They have also upgraded equipment to reduce
manpower needs at some facilities and are sharing personnel between facilities, he said.
Eighteen people between Haines and Skagway had commented on the proposed increase as of
Wednesday.
Initially the public notice, which was put out by the Regulatory Commission of Alaska on Dec. 23,
2024, had a comment deadline of Jan. 6. But that has since been extended to Jan. 24, though the
state’s original public notice has not been updated to reflect that extension.
But the RCA again did not publish a public notice about the increases in either the Haines or
Skagway papers. In 2023 when Goat Lake Hydroelectric parent company Alaska Power &
Telephone applied for a rate increase, notice was published in the Juneau Empire and the Kenai
Peninsula Clarion – two papers published in areas where residents do not get power from AP&T.
When asked about the lack of publication, RCA spokesperson Becki Alvi attributed the lapse to
an issue with the print schedule of the two papers, according to an email she sent to the
Skagway News.
“However, a copy of the public notice was mailed to a number of entities in Haines and
Skagway, including the post offices, the cities, the chambers of commerce, the school district,
and the tribal councils,” she wrote. She also said that AP&T informed the RCA that it had given
notice to customers via customer bills, emails, via the company’s website and by meeting with
borough leaders in both communities.
Residents who have testified have spoken of the disproportionate impact on the region’s
taxpayers, businesses and schools. Haines Borough Tourism Director Rebecca Hylton said a 70%
rate increase would create “an untenable financial burden for families and individuals. Instead,
the responsibility for these costs should fall squarely on the company’s shareholders, who have
benefited from AP&T’s profits and investments.”
Haines school Superintendent Roy Getchell said staff have projected that the increase will cost
the district another $15,000 a year in energy costs.
“So between the increases last year and then this one, it just tells you a bit about how – with no
additional state funding – we’re bleeding money,” he said.
Skagway resident Kerri Raia also opposed a rise in electricity cost. She commented that she is a
year-round resident who relies on seasonal work and said her electricity bill is already
“atrocious.” “I’m afraid if this increase happens, my family will be tempted to sell our home and
relocate,” she wrote.
Goat Lake Hydroelectric asks to raise electricity
rates, deadline for public comment Friday
https://www.chilkatvalleynews.com/2025/01/22/goat-lake-hydroelectric-asks-to-raise-electricity-rates-deadline-for-
public-comment-friday/
3/3
Sara Kinjo-Hischer, Tribal Administrator for the Skagway Traditional Council, noted that the new
rates, coupled with the addition of a 14.51% rate hike Alaska Power & Telephone negotiated last
year, would result in a total rate increase of about 40%.
“Such drastic hikes have serious implications for residents, many of whom are already facing
financial hardships due to inflation and the rising costs of goods and services,” she wrote.
In her letter to the RCA, Haines resident Michelle Strohecker said the rate hike would
disproportionately affect low-income families, seniors, and other vulnerable populations.
“It is critical that utility companies prioritize efficiency, cost-saving measures, and alternative
revenue strategies before passing costs onto consumers,” she wrote. “Please consider
prioritizing the community and denying this request.”
The public comment period ends at 5 p.m. on Jan. 24. Comments can be filed here.
Skagway News publisher Gretchen Wehmhoff contributed to this story.