HomeMy WebLinkAbout2026-01-16_BPMC-AgendaBRADLEY LAKE PROJECT MANAGEMENT COMMITTEE MEETING AGENDA January 16, 2026 10:00 AM To participate dial 1-888-585-9008 and use code 212-753-619#
Jim Mendenhall
Ryan McLaughlin
Martin Law
Mark Ziesmer
1.CALL TO ORDER
2.ROLL CALL (for Committee members)
3.PUBLIC ROLL CALL (for all others present)
4.AGENDA APPROVAL
5.PUBLIC COMMENTS
6.APPROVAL OF MEETING MINUTES – December 5, 2025
7.NEW BUSINESS
8.OLD BUSINESS
A.2026 BPMC Meeting Schedule
B.2021 REF Funding for Bradley Expansion
C.CIPLink (Grip 3, Phase 1) Update
D.Bradley Lake Expansion Project Update
E.SQ Upgrade Update
F.Bradley Lake Expansion and CIPLINK Financing Update
9.OPERATORS REPORT
10.COMMITTEE REPORTS
A.Budget vs. Actuals
B.O&D Report Josh Crowell
11.EXECUTIVE SESSION – (Bylaws Section 5.11.4) –To discuss (1) confidential matters theimmediate knowledge of which would clearly have an adverse effect upon the finances of theAuthority or the Project; and (2) confidential matters discussed with an attorney for theCommittee of a member of the Committee, the immediate knowledge of which could have anadverse effect on the legal position of the Committee of the Authority.
12.MEMBERS COMMENTS
13.NEXT MEETING DATE – March 20, 2026 (pending approval)
14.ADJOURNMENT
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BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE (BPMC) MEETING MINUTES December 5, 2025
1.CALL TO ORDER
Chair Tony Izzo called the meeting of the Bradley Lake Hydroelectric Project Management Committee to order at 10:04 a.m. A quorum was established.
2.ROLL CALL (for Committee members)
Tony Izzo (Matanuska Electric Association [MEA]); Arthur Miller (Chugach Electric Association [CEA]); Dan Bishop (Golden Valley Electric Association [GVEA]); Brad Janorschke (Homer Electric Association [HEA]); Brian Hickey (City of Seward); and Curtis Thayer (Alaska Energy Authority [AEA]).
3.PUBLIC ROLL CALL (for all others present)
Jennifer Bertolini, Mark Billingsley, Patrick Domitrovich, Pamela Ellis, Josi Hartley, Ryan McLaughlin, Jim Mendenhall, William Price, Robert Varga, Mark Ziesmer (AEA); Chris Lallish (Aldrich CPAs & Advisors); Joel Paisner (Ascent Law Partners); Matt Clarkson, Sherri Highers, Chris Koehler, Andrew Laughlin, Mike Miller, Paul Millwood (CEA); Molly Howard (GVEA); Andrew Jensen (Governor’s Office); Larry Jorgensen, Martin Law, Andrew Patrick (HEA); David Pease, Matt Reisterer, Tony Zellers (MEA); and Julian Jensen (RT Casey).
4.AGENDA APPROVAL
Chair Izzo requested that the agenda is amended to move Item 8F. Old Business, SQ Upgrade Update to Item 8A., and the remaining items progress sequentially.
MOTION: A motion was made by Mr. Thayer to approve and amend the agenda moving Item 8F. to Item 8A. and adjust accordingly. Motion seconded by Vice Chair Miller.
A roll call was taken, and the motion to approve the agenda as amended passed unanimously.
5.PUBLIC COMMENTS - None.
6.APPROVAL OF MEETING MINUTES – September 19, 2025
MOTION: A motion was made by Mr. Thayer to approve the Minutes of September 19, 2025. Motion seconded by Vice-Chair Miller.
A roll call was taken, and the motion to approve the Minutes of September 19, 2025, passed unanimously.
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7. NEW BUSINESS
A. FY25 BPMC Audited Financial Statements and Letter
Mark Ziesmer, AEA, introduced Chris Lallish, Aldrich CPAs & Advisors, to lead the audit discussion. Mr. Lallish reviewed the report included in the Board packet. Aldrich was hired to complete the special-purpose framework audit for the year ending June 30, 2025, and to issue an opinion on those financial statements. Management provided full cooperation throughout the process. No audit adjustments were needed, and no material weaknesses were identified. Mr. Lallish indicated that an unmodified opinion was issued. This is the highest form of assurance.
Mr. Lallish discussed that the audit included the operating and revenue funds of BPMC in accordance with auditing standards generally accepted in the United States. The audit was conducted to obtain the reasonable assurance that there were no material misstatements, however, the financial statements are ultimately the responsibility of the BPMC. Mr. Lallish reviewed the Statements of Assets and Liabilities. Overall, the assets decreased by approximately $1.3 million, due to decreases in cash and IRS subsidies receivable. The total liabilities also decreased approximately $1.3 million, due to a decrease in the payable to utilities for the Operations and Maintenance (O&M) refund. The total assets and total liabilities always equal each other for BPMC, due to the nature of no net income being recorded because of the refund of the surplus.
Mr. Lallish reviewed the Statements of Revenues and Expenses. The revenue is primarily derived from budgeted contributions for expenses, debt service, and capital activity for the year. This year, the major expenses were O&M and debt service payments. The O&M details are found on page 11. Mr. Lallish noted the Statements of Cash Flows shows the change in cash balance for the year. The Notes to the Financial Statements are required. They give background information on the funds. Note 1 provides information on the significant accounting policies. Note 2 lists details on the cash balances and where the money is invested. Note 3 outlines the major contracts and agreements of BPMC. Note 4 reviews all the related party activity, including accounts payable details and dollars related to the contract. Note 5 details the surplus refunds to be returned to the member utilities in 2026 at the direction of the Committee. Note 6 explains the shortage and funding for the SSQ Line in June 2023 that was collected by the BPMC in 2024. It is expected that Note 6 will no longer be included in next year’s financial statements.
Mr. Lallish discussed the supplemental schedule and Statements of Expenses. This information provides a more detailed analysis of the O&M expenses compared to the budget and the prior year actual expenditures.
Mr. Lallish expressed appreciation to Pam Ellis, AEA Controller, and Mr. Ziesmer, for their accurate and timely information during the process, thus making the audit as smooth as possible. There were no comments or questions.
MOTION: A motion was made by Mr. Thayer to accept the FY2025 BPMC audited financial
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statements, as presented. Motion seconded by Mr. Hickey. A roll call was taken, and the motion to approve the audited financial statements passed unanimously. B. FY25 Refund of Surplus
Mr. Ziesmer gave a high-level overview of the FY25 surplus refunds as outlined in the report in the packet. The total surplus refund amount for FY25 is $1,969,060. The refunds are divided into three categories. The Bradley Lake refunds total $1,796,642, which includes an O&M refund of $394,403 for O&M, and a Renewal and Contingency (R&C) refund of $1,402,238. The Battle Creek refunds total $17,230, and are entirely for O&M. The SSQ Line refunds total $155,188, and are entirely for O&M. These refunds will be distributed to member utilities based on their share percentages as detailed in the report. Mr. Ziesmer reviewed Note 5 – Surplus Refunds of the financial statements. This links the amounts in the financial statements to the amounts in the report. There were no comments or questions.
MOTION: A motion was made by Mr. Thayer to approve the $1,796,641.53 Bradley Lake utilities refund, the $17,230.35 Battle Creek utilities refund, and the $155,187.85 for the SSQ Line refund, as presented. Motion seconded by Vice Chair Miller. A roll call was taken, and the motion to approve the utilities refunds, as presented, passed unanimously. C. 2026 BPMC Meeting Schedule
Chair Izzo noted that the proposed meeting schedule for 2026 is included in the packet. He suggested that members approve the January 16, 2026, meeting, review the other dates during the interim and make a final decision during the January meeting. There was no objection.
MOTION: A motion was made by Mr. Janorschke to accept January 16, 2026, as the next meeting date, and consider the other meeting dates at that meeting. Motion seconded by Mr. Thayer. A roll call was taken, and the motion passed unanimously. 8. OLD BUSINESS A. SQ Upgrade Update Chris Koehler, CEA, stated he is the Project Manager on the Sterling Substation to Quartz Creek Transmission Line rebuild. He said the contract for the steel pole structures has been executed. The vendor has submitted the calculations and those have been formally approved by the engineering contractor. The vendor drawings are in progress. The design is at 90%. The foundation designs are being finalized. The remaining materials are expected to be procured by the end of the first quarter in 2026. The bid will be issued in May of 2026, and the bids will be
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due in August 2026. The construction is anticipated to begin in October 2026. Mr. Koehler noted that a field review of Project 3 has been completed. The geotech field work is in progress and is anticipated to be completed by the end of next week. The engineers will begin the steel pole structure drawings early next year, with the bid to come out in May 2026. Mr. Thayer asked for a project budget update. Mr. Koehler discussed that the Project 2 steel pole structures are approximately $1.1 million over the anticipated amount. The forecast budget for the completion of the project totals approximately $90 million. Mr. Janorschke asked if the $90 million includes the substation transformers. Chair Izzo indicated the $90 million does not include the transformers, but it does include the wire. B. Dispute Resolution Process – Wheeling Services Agreement C. IRS Refund and Interest Mr. Thayer discussed that this item is a follow-up to the issue of staff chasing the IRS subsidy checks for Battle Creek Series 7 and 8 bonds. The checks were finally received for 2024 and for 2025 and have been deposited in the U.S. Bank. Mr. Thayer recognized Senator Sullivan publicly for his direct engagement with the IRS. Mr. Thayer believes that staff would still be chasing the receipt of the checks had Senator Sullivan not intervened. Mr. Thayer noted that the error was due to U.S. Bank, and as a result of discussions, BPMC now has a new client manager and a new analyst. Additionally, U.S. Bank has compensated BPMC for the missed interest due to their error. The interest amount deposited in the account is $15,168. The issue has been resolved and there is a path forward with U.S. Bank to ensure this error does not repeat. Direct deposit has been established. D. Renewable Energy Credits (REC’s) Update Mr. Thayer reviewed that CEA and AEA have agreed to a standstill agreement that is expected to be signed soon. While the arbitrator decides the ownership of the RECs, this agreement allows AEA to sell the RECs. Mr. Thayer noted that BPMC gave the green light for this to occur back in 2024. During this delay of a year, there has been missed opportunity of $1.6 million revenue from selling the RECs and the vintage RECs. The hope is to get the agreement signed and to sell the 2025 RECs in December. Mr. Janorschke noted for transparency that he believes that HEA is on the standstill agreement with CEA. Mr. Thayer agreed and stated that all of the utilities will be treated equally, even if the utility is not part of the standstill agreement. Vice Chair Miller reiterated CEA’s maintained perspective that if another utility wants to convey their RECs to AEA at any time, CEA still has no objection. Chair Izzo asked if AEA’s missed opportunity revenue of $1.6 million from the RECs would be subject to interest. Mr. Thayer noted that the funds would be deposited into an interest-bearing account. However, the $1.6 million is a lost opportunity because the RECs were not sold when
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the BPMC had agreed to sell them. E. CIPLink (Grip 3, Phase 1) Update Jim Mendenhall, AEA, provided the Grid Resilience and Innovation Partnerships (GRIP) 3, Phase 1 update. Mr. Mendenhall noted that the report on the Cook Inlet Power Link (CIPLink) project has been provided. The Department of Energy (DOE) is beginning to ramp back up after some shutdowns. Some name changes have been made; however, the people are still the same. On November 5, 2025, a meeting occurred with AEA and DOE to discuss the next phase and to complete the Go/No-Go presentation. This was well received. CIPLink remains in good standing with DOE as negotiations begin for Budget Period 2, starting July 1, 2025, up through June 30, 2027. Mr. Mendenhall discussed that the DOE has requested a credit for some of the community benefits programs. AEA gave an estimate of the budgeted amount, and requested those funds are reallocated into the other cost categories of the project. Mr. Mendenhall outlined that the environmental review and paperwork for the 2026 season were submitted and some of the permits have been received. HDR is the contractor to help with the project. He noted that Stantec is conducting the major equipment procurement. Discussions occurred last month with Stantec and EPS to determine the interface at the substation, including the best termination point, the landfall location, and the final system configuration options. Mr. Mendenhall indicated that both Mark Billingsley and Josi Hartley of AEA have been working hard on pursuing additional financial avenue. AEA continues to have the $64.2 million in state appropriation. The additional $142.3 million is being sought to fully meet the cost obligations. Meetings will occur next week with the Energy Loan Program Office, which has recently changed its name to the Energy Dominance Financing Office. Mr. Mendenhall reported that through September 30, 2025, a total of $1.25 million has been spent, and approximately $1.15 million has been billed. Once the Budget Period 2 contract is in place, the expenses from July 1, 2025, will be billed. Mr. Hickey requested to comment. He referenced the written report for the EDRRC provided to members. Additionally, he attended the Energy Policy Tour in Hawaii with a group of Railbelt individuals in his role as General Manager of Seward Electric. Mr. Hickey advised that this is his final report. Chair Izzo expressed appreciation to Mr. Hickey and noted that he jumped ahead to Item 8G. on the agenda. Chair Izzo asked the Committee if they had any comments or questions regarding agenda Item 8D. CIPLink Update. F. Bradley Lake Expansion Project Update Ryan McLaughlin, AEA, provided the Bradley Lake Expansion Update. Mr. McLaughlin discussed that design and licensing efforts are advancing as preparations continue to submit the draft license amendment application by late January of 2026. The subsurface investigations at the
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Bradley Dam have been completed. Drilling crews and geophysics crews were onsite for approximately 6 weeks. Conditions were challenging and eight of the ten planned holes were drilled. The primary objectives of the effort included evaluating the seismic stability of the existing embankment dam, installing vibrating wiring piezometers to monitor the water level throughout the dam, performing packer testing to determine permeability, evaluating the bedrock contact beneath the spillway, and evaluating the efficacy of the existing grout curtain. The drilling effort was successful, and the engineers are engaged in the process of reviewing the data collected. Mr. McLaughlin indicated that additional subsurface investigations would occur in 2026 and will include two deep boreholes midway along the tunnel alignment to confirm the bedrock. Mr. McLaughlin explained that the first picture in the packet is of the drill crew on top of the embankment dam. The second picture is also on the embankment dam and represents the challenging conditions during the majority of the subsurface investigations. Mr. McLaughlin discussed that the second Board of Consultants (BOC) meeting was held on October 29, 2025. The main focus of the meeting was discussing the methodologies and status of the Probable Maximum Precipitation (PMP) study, Probable Maximum Flood (PMF) study, and seismic studies. Initial results indicate that the PMP storm is slightly lower than the original 1982 study. However, the PMF will be a little higher. Additionally, the BOC discussed the results of the preliminary seismic study analysis on Bradley Dam to determine potential wave runup against the dam. Preliminary design drawings of the project elements were also shared during the productive meeting. Mr. McLaughlin noted that a follow-up meeting with the BOC and Federal Energy Regulatory Commission (FERC) occurred. The formal report is due on Monday and there will be two weeks to respond to those comments. Mr. McLaughlin discussed that FERC accepted the recommendation that the future Dixon Diversion Dam is classified as a low-hazard dam and that the 100-year flood can be used as the Inflow Design Flood. Mr. McLaughlin continued the presentation and indicated the hope to install 3-phase power from the powerhouse to the dam in advance of the onsite arrival of the tunnel boring machine. EPS has designed the transformer and is completing the procurement documents. The lead time for the equipment is approximately two years. The cost is estimated at $500,000, and there is margin for this in the budget. The remaining equipment for the power upgrades is planned to be purchased in the fall of 2026, for the installation date of 2027. The current estimate is $12.3 million, including construction costs and contingency. This prepurchase amount is not included in the budget. Mr. McLaughlin discussed that design documents for a 16-foot pool raise will be submitted in the Draft License Amendment Application. The scenario includes raising the existing spillway by 8.5 feet, installing a 7.5-foot Obermeyer gate, and raising the embankment dam by 13 feet. Additional conversations with the utilities will occur regarding using the maximum area of impact in the Draft License Amendment Application. Mr. McLaughlin noted that the final year of environmental studies has concluded. The field season included juvenile and adult salmon
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surveys, raptor surveys, discharge measurements, wetland delineations, and cultural resources studies. Preliminary discussions with the resource agencies have begun regarding potential protection mitigation and enhancement measures for the project. Mr. McLaughlin showed the picture of the Martin River at the low flow of 220 cfs. He commented that the entire drainage shown in the picture can fill with water during floods. Mr. Thayer noted that according to Bryan Carey, adding more boulders and structures will be required on the back half of the dam when the dam is relicensed. Mr. Thayer asked Mr. McLaughlin if they are taking that into account when the project is mobilized while working on raising the dam. Mr. McLaughlin agreed. He noted it is possible that modifications to the dam and spillway may be required, and it would make sense to complete that work simultaneously. Mr. Thayer indicated that members of the staff will be working with the FERC Chair next week, and one of the topics on the agenda is the Bradley Expansion Project. Additional meetings are scheduled, and Mr. Thayer will provide reports to the Board. Mr. Janorschke commented that his understanding is that the Operations and Dispatch (O&D) Committee recommended a 14-foot dam raise in the application. However, the plan now is to build a 16-foot dam raise. He asked if his understanding is correct. Mr. McLaughlin explained that the parameters in the draft application are not steadfast. He gave the example of the Battle Creek draft application that included an open channel rather than the pipeline. Mr. McLaughlin discussed that changes can be made, and that the draft license application is primarily for the resource agencies and the environmental aspects. Mr. Janorschke asked if the BOC is comprised of the O&D Committee plus outside experts. Mr. McLaughlin noted that the BOC is an approved group required by FERC. They are internationally recognized engineer experts in hydrology and dam stability. Vice Chair Miller asked Mr. McLaughlin how often the cost estimates for the overall project are reviewed. Mr. McLaughlin explained that there is no set schedule of review. However, a review and updated cost estimate will occur in December and January and will utilize the engineering documents that will be included in the draft license amendment application. Vice Chair Miller asked if it is possible to share the updated cost estimate with the utilities as soon as it is completed. Mr. McLaughlin agreed. Mr. Thayer indicated that the updated cost estimate will also be shared with the O&D Committee. Mr. Bishop inquired as to the status of the organizations’ governing boards approving the Dixon financing in 2026. Mr. Thayer explained that staff are leading the effort to analyze the different financing options. Staff will first report to the Alaska Energy Authority (AEA) Board and then will report to the BPMC. There are currently several different options. Staff is scheduled to meet with CFC next week. Additionally, staff have been invited to submit an application to the Energy Dominance Committee, even though this project is typically too small to be considered. Other options include bonding and traditional financing. Mr. Thayer and Mr. Ziesmer met with the State Bond Bank last month. They approved the allotment of tax-exempt bonds that the State
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has the ability to receive. These could be utilized as a possible financing mechanism. Mr. Thayer explained that the Energy Dominance Finance Office / Loan Program Office (LPO) may fund the project at approximately 70%. The remaining 30% will have to be funded from other options. Mr. Thayer advised that a special Board meeting will occur with AEA’s Finance Committee on December 15, 2025, to continue the review of the options. Mr. Thayer noted that the financial advisors reviewed the option of a private partner partnership, and they advised against that option. Mr. Thayer discussed that staff are conducting the same financial research for the $142 million needed for the CIPLink project. He noted that the BPMC’s path is narrower since a federal grant is involved and there is no option for tax exempt bonds. G. Railbelt Regional Coordination Update Chair Izzo indicated that the report is included in the packet and that Mr. Hickey provided the verbal report earlier in the meeting. 9. OPERATORS REPORT
Chair Izzo noted that Martin Law, HEA, will provide the Operators Report. Mr. Law advised that the Operator’s Report is included in the Committee packet. The new parts have been successfully tested for the spare housing for the needle valve rebuild. However, one bushing was opened up by Voith from the original specifications. This does not appear to affect the performance of the needle. Voith will provide an explanation for their action. Additionally, Kosonen Consulting conducted a condition assessment of the needle valves in operation. The valves remain in good condition and should operate with no issues for the next two to five years. Based on this information, the rebuild of the needles has been postponed for two years. Annual monitoring and inspections will occur during the planned outage, and regular monitoring will occur during the daily rounds. Mr. Law directed the members’ attention to the pictures in the packet showing the needle valve rebuild. Chair Izzo expressed appreciation to Mr. Law for his complete report and for the photos that provide context, scale, and nature of the work at Bradley. 10. COMMITTEE REPORTS A. Budget vs. Actuals Mr. Ziesmer discussed the Bradley Lake Budget to Actual Expenses Report as of September 30, 2025. He explained that there was no FY26 activity recorded for Schedule A, Schedule E, and Schedule H, which are Non-R&C Capital Projects for Bradley Lake, Battle Creek, and SSQ. The total O&M expenses were $1,476,970, which is $456,874 below budget. Most of the FERC categories are within or close to budget. Mr. Ziesmer noted that FERC 539 Miscellaneous Hydraulic Power Generation Expenses were over budget by $28,500 in contractual expenses due to recent invoices. He believes this is a timing issue between the annualized budget and actual
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expenses. It is expected to balance over time. Additionally, FERC 928 Regulatory Commission Expenses have a large underspend variance of $147,500. Mr. Ziesmer believes this amount will mitigate throughout the year.
Mr. Ziesmer reviewed Schedule D Renewal and Contingency (R&C) Fund Disbursements and Repayments. The R&C expenses totaled $154,317 and covered the fire alarm system replacement and the Bradley Expansion Project. The cumulative costs for the Bradley Expansion Project since inception have reached $8,340,556. Mr. Ziesmer reviewed Schedule F Battle Creek O&M expenses. The total amount was $130,094, which is $53,352 below budget. The expenses are primarily driven by the 4% allocation from Bradley Lake.
Mr. Ziesmer reviewed Schedule I SSQ Line O&M expenses. The total amount was $5,098, which is $63,372 below budget. The majority of the costs are related to overhead line maintenance. Mr. Ziesmer reviewed Appendix A, which is related to Bond Series 11 funding. The cumulative spending was $16,180,636. Of this amount, $14,683,354 was directly related to the two SSQ upgrade projects. There were no other comments or questions.
B. O&D Report Molly Howard, GVEA, said she is filling in for Josh Crowell who prepared the report, which is in the packet. There were no questions or comments. MOTION: A motion was made by Mr. Thayer to enter into executive session to (1) discuss confidential matters the immediate knowledge of which would have an adverse effect on the Authority or the project; and (2) matters discussed with an attorney for the Committee or a member of the Committee, the immediate knowledge of which may have an adverse effect on the legal position of the Committee or the Authority. Motion seconded by Vice Chair Miller.
A roll call was taken, and the motion to go into executive session passed unanimously. 11. EXECUTIVE SESSION: 11:04 a.m. - (Bylaws Section 5.11.4) –To (1) discuss confidential financial matters the immediate knowledge of which may have an adverse effect on the Authority or Project; and (2) matters discussed with an attorney for the Committee or a member of the Committee, the immediate knowledge of which could have an adverse effect on the legal position of the Committee or the Authority. The Committee reconvened its regular meeting at 12:06 p.m. Chair Izzo stated that no formal action was taken on matters discussed while in executive session. 12. MEMBERS COMMENTS Mr. Hickey expressed appreciation for the diligent efforts for the clean annual audit. He enjoyed the Operator’s Report, especially the pictures. Mr. Janorschke thanked the Vice Chair for filling in for the Chair and keeping the meeting on track. He expressed appreciation for the clean audit and for the diligent reports given today. He
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wished everyone a Merry Christmas. Mr. Bishop reiterated appreciation for the efforts from AEA, the Committees, the auditors, and for the comprehensive financial reporting. Vice Chair Miller echoed the comments of appreciation for the updates provided today. He looks forward to continuing the positive momentum on the Bradley Lake Expansion Project. Vice Chair Miller thanked Mr. McLaughlin for his efforts on the project. Vice Chair Miller thanked Mr. Hickey for his extensive work in the Railbelt regional coordination efforts over the last several years and in assisting with grant funding opportunities. Chair Izzo echoed the previous comments of appreciation, especially to Mr. Hickey for the fifth largest Grid Resilience and Innovation Partnerships (GRIP) grant in the country, and for the clean audit opinion. He thanked Jennifer Bertolini, AEA, for her diligence. Mr. Thayer noted that the “Lunch and Learn” session yesterday included approximately nine gubernatorial candidates, 10 legislators, and staff. The key points and takeaways included the Bradley Lake Expansion Project and CIPLink Project. The PowerPoint presentation and the links presented yesterday are on the website. Mr. Thayer noted his appreciation for CEA’s presentation with the Chamber of Commerce reviewing these same key points. He gave high praises to staff for their work, especially to Mr. Mendenhall, Mr. Ziesmer, Ms. Hartley, Mr. McLaughlin, Ms. Bertolini, and William Price, AEA. Mr. Thayer advised that Bryan Carey is coming out of retirement to work part-time as a consultant with Mr. McLaughlin. This will maintain consistency and will provide the historical knowledge necessary for the projects. There were no other comments. 13. NEXT MEETING DATE – January 16, 2026 Chair Izzo said the next meeting date is January 16, 2026. 14. ADJOURNMENT There being no further business for the committee, the meeting adjourned at 12:13 p.m. _________________________________ Tony Izzo, Chair _____________________________________ Curtis Thayer, Secretary
2026 Proposed BPMC Meeting Dates: January 16, 2026 March 20, 2026 May 1, 2026 June 19, 2026 July 24, 2026 September 25, 2026 December 4, 2026
Renewable Energy Fund Round 14
Grant Application – Standard Form
AEA 23001 Page 1 of 33 11/16/2021
Application Forms and Instructions
This instruction page and the following grant application constitutes the Grant Application Form for
Round 14 of the Renewable Energy Fund (REF). A separate application form is available for
projects with a primary purpose of producing heat (see Request for Applications (RFA) Section
1.5). This is the standard form for all other projects, including projects that will produce heat and
electricity. An electronic version of the RFA and both application forms is available online at:
https://www.akenergyauthority.org/What-We-Do/Grants-Loans/Renewable-Energy-Fund/2021-
REF-Application.
What follows are some basic information and instructions for this application:
x The Alaska Energy Authority (AEA) expects this application to be used as part of a two-year
solicitation cycle with an opt-out provision in the second year of the cycle.
x If you are applying for grants for more than one project, provide separate application forms for
each project.
x Multiple phases (e.g. final design, construction) for the same project may be submitted as one
application.
x If you are applying for grant funding for more than one phase of a project, provide milestones
and grant budget for each phase of the project (see Sections 3.1 and 3.2.2).
x In order to ensure that grants provide sufficient benefit to the public, AEA may limit
recommendations for grants to preliminary development phases in accordance with 3 Alaska
Administrative Code (ACC) 107.605(1).
x If some work has already been completed on your project and you are requesting funding for
an advanced phase, submit information sufficient to demonstrate that the preceding phases are
completed and funding for an advanced phase is warranted. Supporting documentation may
include, but is not limited to, reports, conceptual or final designs, models, photos, maps, proof
of site control, utility agreements, business and operation plans, power sale agreements,
relevant data sets, and other materials. Please provide a list of supporting documents in
Section 11 of this application and attach the documents to your application.
x If you have additional information or reports you would like the Authority to consider in
reviewing your application, either provide an electronic version of the document with your
submission or reference a web link where it can be downloaded or reviewed. Please provide a
list of additional information; including any web links, in Section 12 of this application and attach
the documents to your application. For guidance on application best practices please refer to
the resource-specific Best Practices Checklists; links to the checklists can be found in the
appendices list at the end of the accompanying REF Round 14 RFA.
x In the Sections below, please enter responses in the spaces provided. You may add additional
rows or space to the form to provide sufficient space for the information, or attach additional
sheets if needed.
x If you need assistance with your application, please contact AEA’s Grants Coordinator by email
at grants@akenergyauthority.org or by phone at (907) 771-3081.
Renewable Energy Fund Round 14
Grant Application – Standard Form
AEA 23001 Page 2 of 33 11/16/2021
REMINDER:
x AEA is subject to the Public Records Act AS 40.25, and materials submitted to AEA may be
subject to disclosure requirements under the act if no statutory exemptions apply.
x All applications received will be posted on the Authority web site after final recommendations
are made to the legislature. Please submit resumes as separate PDFs if the applicant would
like those excluded from the web posting of this application.
x In accordance with 3 AAC 107.630 (b) Applicants may request trade secrets or proprietary
company data be kept confidential subject to review and approval by AEA. If you want
information to be kept confidential the applicant must:
o Request the information be kept confidential.
o Clearly identify the information that is the trade secret or proprietary in their application.
o Receive concurrence from the Authority that the information will be kept confidential. If
the Authority determines it is not confidential, it will be treated as a public record in
accordance with AS 40.25 or returned to the applicant upon request.
Renewable Energy Fund Round 14
Grant Application – Standard Form
AEA 23001 Page 3 of 33 11/16/2021
SECTION 1 – APPLICANT INFORMATION
Please specify the legal grantee that will own, operate, and maintain the project upon completion.
Name Chugach Electric Association, Inc.
On behalf of the Bradley Lake Management Committee (BPMC)
Tax ID #92-0014224
Date of last financial statement audit: April 9, 2021 for year end 12/31/2020
Mailing Address: Physical Address:
PO Box 196300 5601 Electron Drive
Anchorage, AK 99519-6300 Anchorage, AK 99518
Telephone: Fax: Email:
(907) 762-4192 (907) 562-6994 sean_skaling@chugachelectric.com
1.1 Applicant Point of Contact / Grants Coordinator
Name: Title:
Sean Skaling Business & Sustainable Program Development Manager
Mailing Address:
Chugach Electric Association, Inc.
PO Box 196300
Anchorage, AK 99519-6300
Telephone: Fax: Email:
(907) 762-4192 (907) 562-6994 sean_skaling@chugachelectric.com
1.1.1 Applicant Signatory Authority Contact Information
Name: Title:
Lee Thibert Chief Executive Officer
Mailing Address:
Chugach Electric Association, Inc.
PO Box 196300
Anchorage, AK 99519-6300
Telephone: Fax: Email:
(907) 762-4747 (907) 562-6994 lee_thibert@chugachelectric.com
1.1.2 Applicant Alternate Points of Contact
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Name Telephone: Fax: Email:
Arthur Miller (907) 762-4758 (907) 762-4816 arthur_miller@chugachelectric.com
1.2 Applicant Minimum Requirements
Please check as appropriate. If applicants do not meet the minimum requirements, the application
will be rejected.
1.2.1 Applicant Type
܈܈ An electric utility holding a certificate of public convenience and necessity under AS 42.05
CPCN # 8 and CPCN # 121, or
܆ An independent power producer in accordance with 3 AAC 107.695 (a) (1)
CPCN #______, or
܆ A local government, or
܆ A governmental entity (which includes tribal councils and housing authorities)
Additional minimum requirements
܈ 1.2.2 Attached to this application is formal approval and endorsement for the project by the
applicant’s board of directors, executive management, or other governing authority. If the
applicant is a collaborative grouping, a formal approval from each participant’s governing
authority is necessary. (Indicate yes by checking the box)
܈ 1.2.3 As an applicant, we have administrative and financial management systems and follow
procurement standards that comply with the standards set forth in the grant agreement
(Section 3 of the RFA). (Indicate yes by checking the box)
܈ 1.2.4 If awarded the grant, we can comply with all terms and conditions of the award as
identified in the Standard Grant Agreement template at
https://www.akenergyauthority.org/What-We-Do/Grants-Loans/Renewable-Energy-
Fund/2021-REF-Application (Any exceptions should be clearly noted and submitted with the
application.) (Indicate yes by checking the box)
܈ 1.2.5 We intend to own and operate any project that may be constructed with grant funds for
the benefit of the general public. If no please describe the nature of the project and who will
be the primary beneficiaries. (Indicate yes by checking the box)
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SECTION 2 – PROJECT SUMMARY
2.1 Project Title
Provide a 4 to 7 word title for your project. Type in the space below.
Dixon Diversion Feasibility Project
2.2 Project Location
2.2.1 Location of Project – Latitude and longitude (preferred), street address, or
community name.
Latitude and longitude coordinates may be obtained from Google Maps by finding you project’s
location on the map and then right clicking with the mouse and selecting “What is here? The
coordinates will be displayed in the Google search window above the map in a format as follows:
61.195676.-149.898663. If you would like assistance obtaining this information, please contact
AEA’s Grants Coordinator by email at grants@akenergyauthority.org or by phone at (907) 771-
3081.
Latitude 59.69163 Longitude -150.91268
The location identified by the latitude and longitude coordinates above is the end of Dixon Glacier
where water will be either diverted to Bradley Lake or captured in a run-of-river hydro facility and
returned to the Martin River drainage.
2.2.2 Community benefiting – Name(s) of the community or communities that will be the
beneficiaries of the project.
Railbelt electric utility service areas of Chugach Electric Association, Inc. (Chugach), Homer
Electric Association, Inc. (HEA), Golden Valley Electric Association, Inc. (GVEA), Matanuska
Electric Association, Inc. (MEA) and the City of Seward.
2.3 Project Type
Please check as appropriate.
2.3.1 Renewable Resource Type
܆܆ Wind տ Biomass or Biofuels (excluding heat-only)
܈ Hydro, Including Run of River տ Hydrokinetic
܆ Geothermal, Excluding Heat Pumps տ Transmission of Renewable Energy
܆ Solar Photovoltaic տ Storage of Renewable
տ Other (Describe)տ Small Natural Gas
2.3.2 Proposed Grant Funded Phase(s) for this Request (Check all that apply)
Pre-Construction Construction
տ Reconnaissance տ Final Design and Permitting
܈ Feasibility and Conceptual Design տ Construction
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2.4 Project Description
Provide a brief, one-paragraph description of the proposed project.
Dixon Diversion would be an expansion to the Bradley Lake Hydroelectric Project. Two project
alternatives are currently being studied. The primary option would build a tunnel to divert water from
the Dixon Glacier watershed to Bradley Lake to increase the energy output of the existing Bradley
Lake power plant. The other alternative would transport water by tunnel to a new power plant located
on the Lower Martin River. Either alternative would generate enough energy annually to be among
the largest hydroelectric projects in Alaska. The diversion project would generate an estimated
168,000 MWh annually, which would increase Bradley Lake’s energy output by about 44 percent.
This application uses the first option of diverting water to Bradley Lake for the estimated project costs
and energy generation. The Martin River alternative is likely to have similar but higher costs and
energy generation.
2.5 Scope of Work
Provide a short narrative for the scope of work detailing the tasks to be performed under this
funding request. This should include work paid for by grant funds and matching funds or performed
as in-kind match.
Matching and grant funds will be used to perform some of the many engineering and environmental
studies required by agencies to obtain a license amendment to the Bradley Lake Hydroelectric
Project license. It is expected that feasibility, conceptual design, and environmental studies will cost
more than $5 million. The results of these studies will significantly advance the knowledge of
geology, vegetation, fish, and wildlife populations of the area.
2.6 Previous REF Applications for the Project
See Section 1.15 of the RFA for the maximum per project cumulative grant award amount
Round
Submitted
Title of application Application
#, if known
Did you
receive a
grant? Y/N
Amount of REF
grant awarded
($)
No previous applications have been
submitted for this project
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SECTION 3 – Project Management, Development, and Operation
3.1 Schedule and Milestones
Please fill out the schedule below (or attach a similar sheet) for the work covered by this funding
request. Be sure to identify key tasks and decision points, including go/no go decisions, in your
project along with estimated start and end dates for each of the milestones and tasks. Please
clearly identify the beginning and ending of all phases (I. Reconnaissance, II. Feasibility and
Conceptual Design, III. Final Design and Permitting, and IV. Construction) of your proposed
project. See the RFA, Sections 2.3-2.6 for the recommended milestones for each phase. Add
additional rows as needed.
Tas
k # Milestones Tasks
Start
Date
End
Date Deliverables
1 Conceptual
Analysis &
Recommendation
Determine
conceptual
configurations of
elements, cost
estimates, and
energy
11/2021 6/2023 Conceptual Alternatives
Analysis &
Recommendations
2 Detailed
Hydrology
Assessment
Install stream gauges
on Dixon fork
stream and Martin
River, precipitation,
and glacier volume
change
11/2021 6/2023 Hydrology Report
3 Environmental
Studies
Consultation with
Agencies on
required studies and
perform studies
7/2022 6/2025 Environmental Study
Reports
4 Geotechnical
Investigation
Drilling of rock 6/2023 6/2024 Geotechnical Report
5 Draft Amendment
& Exhibits
Draft Amendment
and Exhibits for
review prior to
submitting to FERC
1/2024 6/2024 Draft Amendment with
Exhibits
6 Final Amendment
and Exhibits
Final amendment
with engineering
layout, costs,
environmental
studies
1/2025 6/2025 Final Amendment
7 Preliminary
Design Report
Write a conceptual
business and
operations plan
1/2024 6/2025 Preliminary Design Report
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3.2 Budget
3.2.1 Funding Sources
Indicate the funding sources for the phase(s) of the project applied for in this funding request.
Grant funds requested in this application $1,000,000
Cash match to be provideda $1,000,000
In-kind match to be provideda $0
Energy efficiency match providedb $0
Total costs for project phase(s) covered in application (sum of
above)
$2,000,000
Describe your financial commitment to the project and the source(s) of match. Indicate whether
these matching funds are secured or pending future approvals. Describe the impact, if any, that
the timing of additional funds would have on the ability to proceed with the grant.
The BPMC is committed to providing the stated matching funds of $1,000,000 to complete this work.
The matching funds are secured and approved. See the attached BPMC Resolution No. 21-03 for
the matching funds commitment. BPMC’s match and other funding sources will not impact the ability
of this grant to proceed rapidly once issued. All funds received from the REF will reduce project
costs that are ultimately paid for by the customers of the Railbelt utilities. Therefore, the grant will
decrease the cost of energy for about three quarters of the state’s population.
a Attach documentation for proof (see Section 1.18 of the Request for Applications)
b See Section 8.2 of this application and Section 1.18 of the RFA for requirements for Energy Efficiency
Match.
3.2.2 Cost Overruns
Describe the plan to cover potential cost increases or shortfalls in funding.
BPMC will be responsible to manage or cover any cost overruns.
3.2.3 Total Project Costs
Indicate the anticipated total cost by phase of the project (including all funding sources). Use actual
costs for completed phases. Indicate if the costs were actual or estimated.
Reconnaissance Actual $500,000
Feasibility and Conceptual Design Estimated $7,000,000
Final Design and Permitting Estimated $2,000,000
Construction Estimated $175,000,000
Total Project Costs (sum of above)Estimated $184,500,000
Metering/Tracking Equipment [not included in project
cost]
Estimated $0
3.2.4 Funding Subsequent Phases
If subsequent phases are required beyond the phases being applied for in this application,
describe the anticipated sources of funding and the likelihood of receipt of those funds.
x State and/or federal grants
x Loans, bonds, or other financing options
x Additional incentives (i.e. tax credits)
x Additional revenue streams (i.e. green tag sales or other renewable energy subsidies or
programs that might be available)
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Final design and construction costs will be paid by the five Railbelt utilities participating in the BPMC.
If state or federal grants are available and awarded, those funds would help offset the project cost
and will lower the cost of energy for all residences and businesses served by those utilities,
approximately three quarters of the population of the state from Homer to Fairbanks. Renewable
Energy Certificates (green tags) from Bradley Lake are not anticipated at this time.
3.2.3 Budget Forms
Applications MUST include a separate worksheet for each project phase that was identified in
Section 2.3.2 of this application — I. Reconnaissance, II. Feasibility and Conceptual Design, III.
Final Design and Permitting, and IV. Construction. Please use the tables provided below to detail
your proposed project’s total budget. Be sure to use one table for each phase of your project, and
delete any unnecessary tables. The milestones and tasks should match those listed in 3.1 above.
If you have any question regarding how to prepare these tables or if you need assistance preparing
the application please feel free to contact AEA’s Grants Coordinator by email at
grants@akenergyauthority.org or by phone at (907) 771-3081.
Phase 2 — Feasibility and Conceptual Design
Milestone or Task
Anticipated
Completion
Date
RE- Fund
Grant Funds
Grantee
Matching
Funds
Source of
Matching
Funds:
Cash/In-
kind/Federal
Grants/Other
State
Grants/Other
TOTALS
(List milestones based on
phase and type of project.
See Sections 2.3 thru 2.6 of
the RFA )
Conceptual Analysis &
Recommendation 6/2023 $187,500 $187,500 BPMC Cash $375,000
Detailed Hydrology
Assessment 6/2023 $187,500 $187,500 BPMC Cash $375,000
Various Environmental
Studies 6/2025
Geotechnical Investigation 6/2024 $625,000 $625,000 BPMC Cash $1,250,000
Draft Amendment 6/2024
Final Amendment 6/2025
Preliminary Design Report 6/2025
TOTALS $1,000,000 $1,000,000 BPMC Cash $2,000,000
Budget Categories:
Direct Labor & Benefits
Travel & Per Diem
Equipment
Materials & Supplies
Contractual Services $1,000,000 $1,000,000 BPMC Cash $2,000,000
Construction Services
Other
TOTALS $1,000,000 $1,000,000 BPMC Cash $2,000,000
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3.2.4 Cost Justification
Indicate the source(s) of the cost estimates used for the project budget, including costs for future
phases not included in this application.
The cost estimates in this application are based on prior Alaska hydroelectric projects under the
jurisdiction of the Federal Energy Regulatory Commission (FERC), specifically Bradley Lake,
Susitna-Watana, Grant Lake, and Cooper Lake hydroelectric projects. Project team members have
worked on all these projects.
3.3 Project Communications
3.3.1 Project Progress Reporting
Describe how you plan to monitor the progress of the project and keep AEA informed of the status.
Who will be responsible for tracking the progress? What tools and methods will be used to track
progress?
The progress of this project will be a regular agenda item for the BPMC. AEA and the Railbelt utilities
are members of BPMC. In addition, monthly or more frequent updates will be presented to utility
engineers and AEA management.
The engineering team comprised of utility and AEA staff engineers will be responsible for tracking
progress using various means of communication and planning tools including Microsoft Word, Excel,
SharePoint, and Project.
Due to AEA’s ownership of Bradley Lake Hydroelectric Project and its role in the BPMC, AEA will be
well informed of this project’s progress.
3.3.2 Financial Reporting
Describe the controls that will be utilized to ensure that only costs that are reasonable, ordinary
and necessary will be allocated to this project. Also discuss the controls in place that will ensure
that no expenses for overhead, or any other unallowable costs will be requested for reimbursement
from the REF Grant Program.
Budget for studies will be approved by the BPMC utilities and AEA through existing established
processes with strong controls. Utilities submit expenses to BPMC. These are verified by AEA
accounting staff and approved by other utilities through BPMC. All utilities and the BPMC are audited
annually. Expenses for overhead or other unallowable costs will not be requested for reimbursement
and will be reviewed through the BPMC accounting process.
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SECTION 4 – QUALIFICATIONS AND EXPERIENCE
4.1 Project Team
Include resumes for known key personnel and contractors, including all functions below, as an
attachment to your application. In the electronic submittal, please submit resumes as separate
PDFs if the applicant would like those excluded from the web posting of this application.
4.1.1 Project Manager
Indicate who will be managing the project for the Grantee and include contact information. If the
applicant does not have a project manager indicate how you intend to solicit project management
support. If the applicant expects project management assistance from AEA or another government
entity, state that in this section.
The BPMC will designate staff or hire a project manager for this project. The project manager will
be supported by utility engineers experienced with hydroelectric permitting and hydro project
management including Mike Brodie (Chugach Electric Association, Inc.), Mike Salzetti (Homer
Electric Association, Inc.), and Bryan Carey (Alaska Energy Authority). Additionally, Betsy McGregor
(Alaska Energy Authority) will participate in the permitting process. She has extensive hydro
permitting experience in Alaska, having managed the Susitna Watana permitting process.
Chugach on behalf of the BPMC requests project management assistance from AEA.
Submitted with this application are the resumes of Mike Salzetti and Mike Brodie.
Resume statements for Bryan Carey and Betsy McGregor are below.
Bryan Carey, P.E., Owned Asset/Hydro Manager.
Bryan Carey is the project manager for the Alaska Energy Authority’s Bradley Lake Hydroelectric
Project (Alaska’s largest Hydro project), Alaska Industrial Export Development Authority owned
Snettisham Hydroelectric Project, and was the Project Engineer for the Susitna-Watana
Hydroelectric Project. As the project manager/engineer he has directed numerous studies for
licensing or amendments with Federal Energy Regulatory Commission (FERC). Recently he
managed the West Fork Upper Battle Creek Diversion Project to divert water to Bradley Lake from
project initiation, FERC license amendment, and construction.
In addition to the hydroelectric work he has been the project manager for various rural Alaska energy
projects that include bulk fuel facilities, power plants, and small hydroelectric & wind projects.
Mr. Carey received a Bachelor of Science degree in engineering from the University of Alaska
Fairbanks and a Master of Business Administration from University of Alaska Anchorage.
Betsy McGregor, Preliminary Design and Environmental Manager.
Betsy McGregor is the environmental manager for the Alaska Energy Authority and works on a wide
breadth of development projects. Ms. McGregor is a fisheries and wildlife biologist by training and
has 29 years of experience in natural resources in Alaska and the Pacific Northwest. In addition to
her field experience, Betsy has extensive experience in agency consultation and preparing technical
and regulatory documents associated with Federal Energy Regulatory Commission (FERC) licensing
and compliance; National Environmental Policy Act; Clean Water Act Section 404 Wetlands
permitting and Section 401 Water Quality Certification; National Historic Preservation Act Section
106; Endangered Species Act; Bald and Golden Eagle Protection Act; ADF&G Fish Habitat Permits;
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and right-of-way easements. She was the Environmental Manager for the Susitna-Watana
Hydroelectric Project FERC integrated licensing process, directing a team of consultants through
consultation, study planning, study implementation and FERC filings. She provided technical support
for the Bradley Lake FERC license amendment for the West Fork Upper Battle Creek Diversion
Project and compliance with the Lower Battle Creek fish habitat implementation plan. She currently
serves as the agency’s project manager for the construction of the Fivemile Creek Hydroelectric
Project and licensing study activities associated with the Nuyakuk Hydroelectric Project.
In addition to the hydroelectric work, she is the Volkswagen Program Manager for the State of
Alaska, the Electric Vehicle Program Manager for the agency, and has assisted AIDEA with the
Ambler Access Project permitting.
Ms. McGregor received a Bachelor of Science degree in Wildlife Science from Purdue University.
4.1.2 Project Accountant
Indicate who will be performing the accounting of this project for the grantee. If the applicant does
not have a project accountant indicate how you intend to solicit financial accounting support.
BPMC will account for this project as part of routine business. BPMC accounting is managed by
AEA.
4.1.3 Expertise and Resources
Describe the project team including the applicant, partners, and contractors.
For each member of the project team, indicate:
x the milestones/tasks in 3.1 they will be responsible for;
x the knowledge, skills, and experience that will be used to successfully deliver the tasks;
x how time and other resource conflicts will be managed to successfully complete the task.
If contractors have not been selected to complete the work, provide reviewers with sufficient detail
to understand the applicant’s capacity to successfully select contractors and manage complex
contracts.
Chugach Electric Association, Inc. is the applicant and has extensive experience in permitting,
licensing, building, operating, maintaining, and re-licensing hydroelectric projects in Alaska including
Cooper Lake, Eklutna Lake, and is a member of the BPMC. Chugach is applying on behalf of the
BPMC to support the project.
The other partners are the other four Railbelt electric utilities on the Railbelt who receive power from
Bradley Lake and form the BPMC: Homer Electric Association, Inc., Seward Electric, Matanuska
Electric Association, Inc., and Golden Valley Electric Association, Inc. Alaska Energy Authority,
owner of Bradley Lake hydro is also a partner in the project.
The BPMC will oversee all milestones and tasks described in Section 3.1 above. The tasks will be
conducted mostly by contractors selected for their experience and expertise in each of the task
areas. Time and resource conflicts will be managed through the contracts issued.
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The contractors have not been selected. BPMC, AEA and the participating utilities have extensive
experience issuing and managing contracts for complex projects. New Requests for Proposals are
expected to be issued in spring 2022 for the project environmental, engineering, and licensing
expertise. Existing team members have managed the FERC licensing process for license
amendments at Bradley Lake, Cooper Lake, and a new license at Grant Lake.
The BPMC regularly manages complex projects, such as the maintenance and refurbishment of
Bradley Lake Hydro plant and the addition of Battle Creek Diversion Project, also funded by the
Renewable Energy Fund.
4.2 Local Workforce
Describe how the project will use local labor or train a local labor workforce.
Local contractors will be solicited to the maximum extent because of their local knowledge and cost.
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SECTION 5 – TECHNICAL FEASIBILITY
5.1 Resource Availability
5.1.1 Assessment of Proposed Energy Resource
Describe the potential extent/amount of the energy resource that is available, including average
resource availability on an annual basis. For pre-construction applications, describe the resource to
the extent known. For design and permitting or construction projects, please provide feasibility
documents, design documents, and permitting documents (if applicable) as attachments to this
application (See Section 11). Likelihood of the resource being available over the life of the project.
See the “Resource Assessment” section of the appropriate Best Practice Checklist for additional
guidance.
The Dixon basin is a coastal, 20-square-mile, high-elevation area. Based on previous work, the
average annual precipitation is estimated around 120 inches of water. Glacial melt of Dixon Glacier
increases the outflow greater than the precipitation alone.
Two potential projects are currently being studied. An engineering alternatives report is due in the
first half of 2022 which will guide the decision of which project to pursue.
The primary alternative is the diversion of this water into the Bradley Lake reservoir (see orange line
in Figure 1). Assuming diversion of 75% of the water, the project would generate an estimated
168,000 MWh from the existing Bradley Lake Hydroelectric facility.
The other alternatives would harness the energy from the water dropping 1,000 feet over a relatively
short distance in a run-of-river configuration which would return the water to the Martin River basin
(see green line in Figure 1 below). Assuming diversion of 95 percent of the water, the project would
generate an estimated 174,000 MWh per year from a new hydro power plant.
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Figure 1: Development Alternatives
5.1.2 Alternatives to Proposed Energy Resource
Describe the pros and cons of your proposed energy resource vs. other alternatives that may be
available for the market to be served by your project.
Alternatives to this project are to continue using fossil fuels (natural gas from Cook Inlet, liquid
petroleum, and coal) to meet the majority of electric demand in the Railbelt, or develop wind, solar,
new hydro, or other forms of renewable energy. The strong advantage this project has over the
other alternatives is this project is expected to be less expensive than the other generating sources
and would displace the incumbent fossil fuels. Additionally, if the decision is made to divert water
into the existing Bradley Lake it will have relatively low environmental impact (especially as compared
to fossil fuels or a new storage hydro project), the license amendment process is likely simpler, and
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it is less likely to spur opposition. The run-of-river option also has the benefit over the alternatives
that the environmental impacts are likely relatively minimal compared to storage hydro or other
alternatives. However, due to its location next to Bradley Lake hydro project and sharing its
transmission infrastructure, the run-of-river project would allow more of Bradley Lake’s water to
remain stored when the water is flowing through the run-of-river project. Both project alternatives
result in a fully or virtually dispatchable new renewable energy source, which is of value in the Railbelt
grid and which solar and wind can not provide without large energy storage devices.
5.1.3 Permits
Provide the following information as it may relate to permitting and how you intend to address
outstanding permit issues. See the “Environmental and Permitting Risks” section of the appropriate
Best Practice Checklist for additional guidance.
x List of applicable permits
x Anticipated permitting timeline
x Identify and describe potential barriers including potential permit timing issues, public
opposition that may result in difficulty obtaining permits, and other permitting barriers
The project will be licensed and regulated by the FERC. Permits will be applied for and acquired
within the FERC timeline and during final design. All land is owned by the State of Alaska
Department of Natural Resources and is non parkland. Project is planned to be low visibility, with
minimal impact to fish and game populations around the project. The FERC process requires public
input and permits be completed prior to construction. Public education and communication will be
an important part of the development process. Public opposition is expected to be low due to the
characteristics of the project alternatives and its location.
5.2 Project Site
Describe the availability of the site and its suitability for the proposed energy system. Identify
potential land ownership issues, including whether site owners have agreed to the project or how
you intend to approach land ownership and access issues. See the “Site control” section of the
appropriate Best Practice Checklist for additional guidance.
All project lands are owned by the State of Alaska. Easements and permits are expected to be
straight forward as they would be an expansion of existing Bradley Lake easements. The project
would be consistent with Bradley Lake land use which makes the easement and permit expansions
simple and non-controversial.
5.3 Project Technical & Environmental Risk
5.3.1 Technical Risk
Describe potential technical risks and how you would address them.
x Which tasks are expected to be most challenging?
x How will the project team reduce the risk of these tasks?
x What internal controls will be put in place to limit and deal with technical risks?
See the “Common Planning Risks” section of the appropriate Best Practice Checklist for additional
guidance.
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During the feasibility phase, the greatest risks are managing cost and the safety of field crews.
BPMC’s management process and contracting language will mitigate cost risks. All utilities and AEA
have strong safety cultures and procedures to ensure the safety of field crews.
During the construction phase, the long underground tunnels will be the most challenging. The
project team will perform a robust study of the terrain and geology to better understand risk of
tunneling. The construction budget will have contingencies for various unexpected rock conditions.
All of these risks will be minimized through the procurement processes to hire contractors for various
steps of the project.
BPMC recently built a very similar project, the Battle Creek Diversion, and successfully navigated
the technical and environmental risks. This project will run parallel to the Battle Creek project using
the same tools and procedures, but this time with the benefit of the recent experience on the same
type of project in the same geographic area. For example, the team will work closely with
stakeholders and consulting agencies to ensure a smooth process. The plan and path forward will
be carefully planned and communicated. This proposal takes into account flow reservations and
currently assumes a 25% flow reservation. If flow reservation is increased to 50%, the preliminary
project economics remain positive.
The team is confident it can successfully navigate the technical and environmental risks this project
presents, especially given its recent success with the same type of project at Bradley Lake.
5.3.2 Environmental Risk
Explain whether the following environmental and land use issues apply, and if so which project
team members will be involved and how the issues will be addressed. See the “Environmental and
Permitting Risks” section of the appropriate Best Practice Checklist for additional guidance.
x Threatened or endangered species
x Habitat issues
x Wetlands and other protected areas
x Archaeological and historical resources
x Land development constraints
x Telecommunications interference
x Aviation considerations
x Visual, aesthetics impacts
x Identify and describe other potential barriers
Previous Bradley Lake amendments have not identified threatened or endangered species, habitat
issues, archaeological resources, land development constraints, telecommunications, or aviation
issues in the vicinity of the project. There may be minor wetland impacts while constructing the
access road, though most ground is well drained. The project location is not visible to the public
unless they are in a plane.
5.4 Technical Feasibility of Proposed Energy System
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In this section you will describe and give details of the existing and proposed systems. The
information for existing system will be used as the baseline the proposal is compared to and also
used to make sure that proposed system can be integrated.
Only complete sections applicable to your proposal. If your proposal only generates electricity, you
can remove the sections for thermal (heat) generation.
5.4.1 Basic Operation of Existing Energy System
Describe the basic operation of the existing energy system including: description of control system;
spinning reserve needs and variability in generation (any high loads brought on quickly); and
current voltage, frequency, and outage issues across system. See the “Understanding the Existing
System” section of the appropriate Best Practice Checklist for additional guidance.
The existing energy system is the Alaska Railbelt grid serving communities from Homer to Fairbanks.
The Dixon Diversion project would significantly augment the existing Bradley Lake project, which is
arguably the most valuable generation asset on the Railbelt. Bradley Lake provides a large amount
of dispatchable energy for all Railbelt utilities, which directly offsets natural gas and other fossil fuels,
allows for the integration of more variable renewable generation resources, and provides dispatching
flexibility of the most efficient natural gas generators. By either adding more water to Bradley Lake
or creating a new run-of-river hydro project that would allow Bradley Lake to store more water, the
Dixon Diversion project allows all Railbelt utilities to increase the generation potential of Bradley
Lake. The project will increase Bradley Lake’s generation load factor, and dispatchers will have
greater flexibility to use Bradley Lake at higher capacities throughout much of the year.
Chugach welcomes specific questions or requests for other information about the Railbelt system
that can help AEA evaluate this project.
5.4.2.1Existing Power Generation Units
Include for each unit include: resource/fuel, make/model, design capacity (kW), minimum
operational load (kW), RPM, electronic/mechanical fuel injection, make/model of genset
controllers, hours on genset
Unit 1: This project will displace energy from fossil fuel units in the Railbelt.
Unit 2: AEA’s Evaluation Model contains the information needed for the Railbelt system.
Unit 3:
Unit 4:
Unit 5:
Unit 6:
5.4.2 Existing Energy Generation Infrastructure and Production
In the following tables, only fill in areas below applicable to your project. You can remove extra
tables. If you have the data below in other formats, you can attach them to the application (see
Section 11).
Is there operational heat recovery? (Y/N) If yes estimated
annual displaced heating fuel (gallons)
Yes, the primary natural gas
generators on the Railbelt operate in
combined cycle with a steam
generator.
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5.4.2.2 Existing Distribution System
Describe the basic elements of the distribution system. Include the capacity of the step-up
transformer at the powerhouse, the distribution voltage(s) across the community, any transmission
voltages, and other elements that will be affected by the proposed project.
This project serves the Railbelt grid from Homer to Fairbanks and power from the project is delivered
at transmission voltages. If specific details are needed for application review, please contact
Chugach Electric.
5.4.2.3 Existing Thermal Generation Units (if applicable to your project)
Generation
unit
Resource/
Fuel type
Design
capacity
(MMBtu/hr)
Make Model Average
annual
efficiency
Year
Installed
Hours
Not
applicable
5.4.2.5 Annual Electricity Production and Fuel Consumption (Existing System)
Use most recent year. Replace the section (Type 1), (Type 2), and (Type 3) with generation
sources
Month Generati
on (Type
1)
(kWh)
Generatio
n (Type 2)
(kWh)
Generatio
n (Type 3)
(kWh)
Fuel
Consumptio
n
(Diesel-
Gallons)
Fuel
Consumptio
n
[Other]
Pea
k
Loa
d
Minimu
m Load
January
February
March
April
May
June
July
August
Septembe
r
October
November
December
Total
5.4.2.4 O&M and replacement costs for
existing units
Power Generation Thermal Generation
i. Annual O&M cost for labor
ii. Annual O&M cost for non-labor
iii. Replacement schedule and cost for
existing units
Covered by AEA’s REF Evaluation
Model for the Railbelt. Contact Chugach
if additional information would be helpful.
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5.4.3 Future Trends
Describe the anticipated energy demand in the community, or whatever will be affected by the
project, over the life of the project. Explain how the forecast was developed and provide year by
year forecasts. As appropriate, include expected changes to energy demand, peak load, seasonal
variations, etc. that will affect the project.
The electric demand in the Railbelt is expected to remain fairly steady over the 50-year life of the
hydro project, barring any significant changes to economic conditions or population. Most of the
Railbelt utilities have been experiencing overall reductions of load over the past decade resulting
mostly from end-use energy efficiency improvements and slow or declining economic conditions. It
is expected that these efficiency changes will continue, but at a slower rate in the coming decades
and will be matched with increased loads and beneficial electrification such as the electrification of
transportation. The US Energy Information Administration in their Annual Energy Outlook, which
projects energy use to 2050, projects less than 1 percent growth per year through 2050. This
projection is a combination of energy efficiency measures that reduce load and economic
development that increases load at a greater pace. Due to current economic conditions in Alaska,
it is likely that demand will continue to decrease slightly each year before economic growth and the
addition of electric vehicles to the load surpass the efficiency decline. On the relatively large (by
Alaska standards) Railbelt grid, these changes are expected to be slow, incremental changes to an
otherwise stable load.
5.4.4 Proposed System Design
Provide the following information for the proposed renewable energy system:
x A description of renewable energy technology specific to project location
x The total proposed capacity and a description of how the capacity was determined
x Integration plan, including upgrades needed to existing system(s) to integrate renewable
energy system: Include a description of the controls, storage, secondary loads, distribution
upgrades that will be included in the project
x Civil infrastructure that will be completed as part of the project—buildings, roads, etc.
x Include what backup and/or supplemental system will be in place
See the “Proposed System Design” section of the appropriate Best Practice Checklist for additional
guidance.
The most likely of the two project options is the diversion of water to Bradley Lake, which requires a
tunnel to be constructed from Bradley Lake to the proposed intake location. The intake structure
would be small and similar to the recently constructed Battle Creek intake. An access road to the
intake site may need to be constructed from an existing stream bridge. Under a separate project,
the Bradley Lake spillway and/or dam may be raised to store more water. Under this project option
no new power plant would be needed as the diverted water would ultimately flow to Bradley Lake.
The existing power plant is already integrated into the transmission system.
Under the run-of-river project alternative, a new power plant would be added that would interconnect
with existing transmission infrastructure. The size of the plant would be determined after additional
feasibility work is completed.
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5.4.4.1 Proposed Power Generation Units
Unit #Resource/
Fuel type
Design
capacity
(kW)
Make Model Expected
capacity
factor
Expected
life
(years)
Expected
Availability
5.4.4.2 Proposed Thermal Generation Units (if applicable)
Generation
unit
Resource/
Fuel type
Design
capacity
(MMBtu/hr)
Make Model Expected
Average
annual
efficiency
Expected
life
5.4.5 Basic Operation of Proposed Energy System
x To the best extent possible, describe how the proposed energy system will operate: When will
the system operate, how will the system integrate with the existing system, how will the
control systems be used, etc.
x When and how will the backup system(s) be expected to be used
See the “Proposed System Design” section of the appropriate Best Practice Checklist for additional
guidance.
The diverted water from Dixon Diversion will increase the water flow through the existing Bradley
Lake power plant. The Bradley Lake power plant is already integrated into the Railbelt grid and the
power is provided to all Railbelt electric utilities according to existing agreements. The addition of
diverted water from Dixon Diversion will provide more water and therefore more energy through the
existing dam. Utilities currently use Bradley Lake power to supplement and refine their dispatch of
other fossil fuel based generation and variable renewable energy generation to maximize the
efficiency of their systems. The additional energy through the Bradley Lake Power Project will allow
for greater efficiency by all participating utilities and will 1) directly displace natural gas and other
fossil fuel generation; 2) allow operators to more efficiently use their existing generation; 3) provide
more energy to back up variable renewable generation, such as Fire Island Wind, which is backed
up primarily by Bradley Lake and other storage hydro facilities.
The water flows from Dixon Diversion will be greatest in warmer months and will be less in colder
months. The additional volume of water added to Bradley Lake will allow each utility to take more
energy from Bradley Lake throughout the year with less concern about winter lake levels.
No new generators, uses
existing Bradley Lake
Hydroelectric generators
Not Applicable
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Future separate projects to increase the height of the spillway or the height of the dam and spillway
would result in more water storage and allow for additional seasonal flexibility of dispatch. The
Bradley Lake Power Project was built with the ability to additional another generation in the future.
5.4.3.1 Expected Capacity Factor 52%
Bradley Lake’s current capacity factor is
approximately 36%. With the addition of water
diverted from Dixon Diversion, the capacity
factor would increase to about 52%
5.4.5.2 Annual Electricity Production and Fuel Consumption (Proposed System)
Month Generation
(Proposed
System)
(kWh)
Generation
(Type 2)
(kWh)
Generation
(Type 3)
(kWh)
Fuel
Consumption
(Diesel-
Gallons)
Fuel
Consumption
[Other]
Secondary
load
(kWh)
Storage
(kWh)
January 12,600,000
February 12,600,000
March 14,000,000
April 14,000,000
May 14,000,000
June 15,400,000
July 15,400,000
August 15,400,000
September 15,400,000
October 14,000,000
November 12,600,000
December 12,600,000
Total 168,000,000
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5.4.6 Proposed System Operating and Maintenance (O&M) Costs
O&M costs can be estimated in two ways for the standard application. Most proposed renewable
energy projects will fall under Option 1 because the new resource will not allow for diesel
generation to be turned off. Some projects may allow for diesel generation to be turned off for
periods of time; these projects should choose Option 2 for estimating O&M.
Option 1: Diesel generation ON
For projects that do not result in shutting down
diesel generation there is assumed to be no
impact on the base case O&M. Please indicate
the estimated annual O&M cost associated with
the proposed renewable project.
$ 250,000
Option 2: Diesel generation OFF
For projects that will result in shutting down
diesel generation please estimate:
1. Annual non-fuel savings of shutting off
diesel generation
2. Estimated hours that diesel generation
will be off per year.
3. Annual O&M costs associated with the
proposed renewable project.
1. $
2. Hours diesel OFF/year:
3. $
5.4.7 Fuel Costs
Estimate annual cost for all applicable fuel(s) needed to run the proposed system (Year 1 of
operation)
Diesel
(Gallons)
Electricity Propane
(Gallons)
Coal
(Tons)
Wood Other
5.4.5.3 Annual Heating Fuel Consumption (Proposed System)
Month Diesel
(Gallons)
Electricity Propane
(Gallons)
Coal
(Tons)
Wood
(Cords,
green tons,
dry tons)
Other
January
February
March
April
May
June
July
August
September
October
November
December
Total
Not Applicable
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Unit cost
($)
Annual
Units
Total
Annual
cost ($)
5.5 Performance and O&M Reporting
For construction projects only
5.5.1 Metering Equipment
Please provide a short narrative, and cost estimate, identifying the metering equipment that will be
used to comply with the operations reporting requirement identified in Section 3.15 of the Request
for Applications.
Water flow meters would be installed to measure the amount of water diverted to Bradley Lake. The
cost would be small, have not been estimated and are included in the construction cost.
5.5.2 O&M reporting
Please provide a short narrative about the methods that will be used to gather and store reliable
operations and maintenance data, including costs, to comply with the operations reporting
requirement identified in Section 3.15 of the Request for Applications
The BPMC is an established, well-functioning organization that tracks all Bradley Lake Project
expenses, including operations and maintenance expense. BPMC financial records are audited on
an annual basis. Performance in terms of energy generation, water measurement and other similar
performance metrics are already in place and any additional measures will be incorporated into
BPMC’s procedures. The metrics will be reported according to the grant agreement requirements.
Electric costs to run communications
and valves would be de minimis.
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SECTION 6 – ECONOMIC FEASIBILITY AND BENEFITS
6.1 Economic Feasibility
6.1.1 Economic Benefit
Annual Lifetime (50 years)
Anticipated Diesel Fuel Displaced for Power
Generation (gallons)
10,400,000 gallons of
diesel equivalent
520,000,000 gallons
Anticipated Fuel Displaced for Heat
(gallons)
00
Total Fuel displaced (gallons)10,400,000 520,000,000
Anticipated Diesel Fuel Displaced for Power
Generation ($)
$9,240,000 (year 1
natural gas savings)
168,000 MWh
generated times
avoided cost of fuel
displaced and O&M of
$55/MWh
$235,000,000 (NPV over
50 years; assumes 2%
annual increase to avoided
cost, 5% discount rate).
Anticipated Fuel Displaced for Heat ($)0
Anticipated Power Generation O&M Cost
Savings
Embedded in fuel
estimate.
Anticipated Thermal Generation O&M Cost
Savings
Total Other costs savings (taxes, insurance,
etc.)
00
Total Fuel, O&M, and Other Cost Savings $9,240,000 $235,000,000
Calculated as the NPV
cost savings (utility fuel
costs avoided minus cost
to purchase the energy
from this project) using 5%
discount rate. AEA may
calculate this differently
from a grant project
perspective.
6.1.2 Economic Benefit
Explain the economic benefits of your project. Include direct cost savings and other economic
benefits, and how the people of Alaska will benefit from the project. Note that additional revenue
sources (such as tax credits or green tags) to pay for operations and/or financing, will not be
included as economic benefits of the project.
Where appropriate, describe the anticipated energy cost in the community, or whatever will be
affected by the project, over the life of the project. Explain how the forecast was developed and
provide year-by-year forecasts
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The economic model used by AEA is available at https://www.akenergyauthority.org/What-We-
Do/Grants-Loans/Renewable-Energy-Fund/2021-REF-Application. This economic model may be
used by applicants but is not required. The final benefit/cost ratio used will be derived from the
AEA model to ensure a level playing field for all applicants. If used, please submit the model with
the application.
The project will reduce direct energy cost to approximately three quarters of Alaskans who live in
communities served by the Railbelt utilities. The lower cost of energy in the Railbelt reduces costs
to rural communities who purchase goods and services from the Railbelt region. The lower cost also
helps rural residents and government/tribal organizations due to the Power Cost Equalization (PCE)
formula. The PCE formula is based on equalizing certain rural electric costs to match the average
electric cost in Anchorage, Fairbanks and Juneau, cities that are past beneficiaries of State grants
to develop low-cost hydro projects. The Dixon Diversion project will help lower the cost of electricity
in both Anchorage and Fairbanks and therefore it will lower electric costs in PCE communities.
Based on 75% flow of estimated Dixon, the estimated annual generation from the project is 168,000
MWh per year. Based on preliminary cost estimates, the benefit of the project to the participating
utilities could exceed $170 million (NPV) over the 50-year life of the project, when accounting for the
cost-based purchase price of the additional energy generated as a result of this diversion project.
6.1.3 Economic Risks
Discuss potential issues that could make the project uneconomic to operate and how the project
team will address the issues. Factors may include:
x Low prices for diesel and/or heating oil
x Other projects developed in community
x Reductions in expected energy demand: Is there a risk of an insufficient market for energy
produced over the life of the project.
x Deferred and/or inadequate facility maintenance
x Other factors
Hydroelectric projects have a high initial cost. This diversion project also has a high cost, but it uses
existing generation and transmission sources, thereby significantly reducing the cost as compared
to a new hydroelectric project. Once constructed, hydroelectric projects commonly operate for more
than 100 years, though this project was calculated using the economic life of 50 years. Since the
precipitation will continue at the Dixon basin, this project’s energy generation appears to be economic
over its 50-year life. As natural gas prices rise the hydroelectric energy becomes relatively lower
cost. As long as there is a Railbelt needing energy there will be a market for Dixon energy.
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6.1.4 Public Benefit for Projects with Direct Private Sector Sales
For projects that include direct sales of power to private sector businesses (sawmills, cruise ships,
mines, etc.), please provide a brief description of the direct and indirect public benefits derived from
the project as well as the private sector benefits and complete the table below. See Section 1.6 in
the Request for Applications for more information.
Not Applicable
Renewable energy resource availability (kWh per month)
Estimated direct sales to private sector businesses (kWh)
Revenue for displacing diesel generation for use at private sector businesses ($)
Estimated sales for use by the Alaskan public (kWh)
Revenue for displacing diesel generation for use by the Alaskan public ($)
6.2 Other Public Benefit
Describe the non-economic public benefits to Alaskans over the lifetime of the project. For the
purpose of evaluating this criterion, public benefits are those benefits that would be considered
unique to a given project and not generic to any renewable resource. For example, decreased
greenhouse gas emission, stable pricing of fuel source, won’t be considered under this category.
Some examples of other public benefits include:
x The project will result in developing infrastructure (roads, trails, pipes, power lines, etc.) that can
be used for other purposes
x The project will result in a direct long-term increase in jobs (operating, supplying fuel, etc.)
x The project will solve other problems for the community (waste disposal, food security, etc.)
x The project will generate useful information that could be used by the public in other parts of the
state
x The project will promote or sustain long-term commercial economic development for the
community
1. The project will develop additional infrastructure including roads.
2. Roads will increase access for other projects such as wind energy development and public
access for hiking and hunting.
3. The project will reduce Alaska’s estimated greenhouse gas emissions by up to 195,000
tons/year.
4. The project will help Railbelt utilities move toward their renewable energy and carbon
reduction goals without raising costs to ratepayers.
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SECTION 7 – SUSTAINABILITY
Describe your plan for operating the completed project so that it will be sustainable throughout its
economic life.
At a minimum for construction projects, a business and operations plan should be attached and the
applicant should describe how it will be implemented. See Section 11.
7.1.1 Operation and Maintenance
Demonstrate the capacity to provide for the long-term operation and maintenance of the proposed
project for its expected life
x Provide examples of success with similar or related long-term operations
x Describe the key personnel that will be available for operating and maintaining the
infrastructure.
x Describe the training plan for existing and future employees to become proficient at operating
and maintaining the proposed system.
x Describe the systems that will be used to track necessary supplies
x Describe the system will be used to ensure that scheduled maintenance is performed
The project will be managed by the BPMC. The BPMC has managed the Bradley Lake Hydroelectric
project, including operations and maintenance, for 30 years. Insurance and special inspections by
FERC finds Bradley Lake has been maintained in good condition.
Employees start out as trainees with a training plan. Many operating workers at Bradley Lake stay
long term which ensures knowledge about maintaining project is not lost. A computerized
maintenance management system ensures O&M is performed at the scheduled times and that
necessary supplies are ready.
7.1.2 Financial Sustainability
xx Describe the process used (or propose to use) to account for operational and capital costs.
x Describe how rates are determined (or will be determined). What process is required to set
rates?
x Describe how you ensure that revenue is collected.
x If you will not be selling energy, explain how you will ensure that the completed project will be
financially sustainable for its useful life.
This project is well-positioned to be financially sustainable and secure because it is an addition to an
existing successful hydro project with established governance and financial structures that are
managed by AEA and the participating five electric utilities. Governing documents, power sales
agreements, O&M agreements and other materials are publicly available at:
https://www.akenergyauthority.org/What-We-Do/Railbelt-Energy/Bradley-Lake-Hydroelectric-
Project/Bradley-Lake-Governing-Documents
AEA provides the accounting support for BPMC’s capital and operating expenses. Bradley Lake
expenses are submitted by the utilities to AEA for review, approval, coding, and processing. The
financials for Bradley Lake are reviewed by the BPMC and audited annually.
Project costs would be paid by each of the participating utility members of the BPMC. In general,
utility costs are recovered on a dollar-for-dollar basis through existing and well-established cost of
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power adjustment processes. In general, cost of power adjustment factors are included in all retail
(residential and commercial) classes of service.
Power purchase contracts already exist for Bradley Lake power so revenue for the project through
the sale of the additional energy is assured. Additionally, the increased energy output from this
project will likely be below the utilities’ avoided costs, so it will reduce the cost of energy to ratepayers,
thereby strengthening the assurance that the energy will be purchased.
7.1.2.1 Revenue Sources
Briefly explain what if any effect your project will have on electrical rates in the proposed benefit
area over the life of the project. If there is expected to be multiple rates for electricity, such as a
separate rate for intermittent heat, explain what the rates will be and how they will be determined
Collect sufficient revenue to cover operational and capital costs
x What is the expected cost-based rate (as consistent with RFA requirements)
x If you expect to have multiple rate classes, such as excess electricity for heat, explain what
those rates are expected to be and how those rates account for the costs of delivering the
energy (see AEA’s white paper on excess electricity for heat)..
x Annual customer revenue sufficient to cover costs
x Additional incentives (i.e. tax credits)
x Additional revenue streams (i.e. green tag sales or other renewable energy subsidies or
programs that might be available)
It is expected that this project would lower the electric rates of all five Railbelt utilities. The project
cost is expected to result in a cost of energy that is below the utilities’ current avoided costs.
At this preliminary stage, the cost-based rate for energy from the proposed project is expected to be
approximately $0.022 per kWh.
A more reliable project cost, calculated benefit of the project, and the attendant impact on electric
rates will be determined after the necessary studies have been made, including the economic viability
of the project.
Revenue sources will be the five Railbelt electric utilities who will ultimately recover the costs through
electric rates charged to their customers.
7.1.2.2 Power Purchase/Sale
The power purchase/sale information should include the following:
x Identification of potential power buyer(s)/customer(s)
x Potential power purchase/sales price - at a minimum indicate a price range (consistent with the
Section 3.16 of the RFA)
Identify the potential power buyer(s)/customer(s) and anticipated power purchase/sales price
range. Indicate the proposed rate of return from the grant-funded project. Include letters of support
or power purchase agreement from identified customers.
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The additional energy from this project is expected to be purchased by the existing purchasers of
Bradley Lake power: Chugach Electric, GVEA, HEA, MEA, and the City of Seward. The cost of the
energy is not yet known at this pre-feasibility stage but is estimated to cost approximately 2.2 cents
per kWh using current estimates. The price range is conservatively estimated to be 2 to 4 cents per
kWh. The utilities’ current avoided cost for fuel and avoided O&M is about 5.5 cents per kWh or
higher, resulting in cost savings to utility rate payers.
SECTION 8 – PROJECT READINESS
8.1 Project Preparation
Describe what you have done to prepare for this award and how quickly you intend to proceed with
work once your grant is approved.
Specifically address your progress towards or readiness to begin, at a minimum, the following:
x The phase(s) that must be completed prior to beginning the phase(s) proposed in this application
x The phase(s) proposed in this application
x Obtaining all necessary permits
x Securing land access and use for the project
x Procuring all necessary equipment and materials
Refer to the RFA and/or the pre-requisite checklists for the required activities and deliverables for
each project phase. Please describe below and attach any required documentation.
The BPMC is performing reconnaissance and pre-feasibility studies on the Dixon Project with its own
funding. An engineering alternatives report will be completed in 2022 identifying the best option for
the project (diversion to Bradley Lake or run-of-river hydroelectric facility). If grant funds are
acquired, then such funds will be committed to feasibility engineering and environmental studies
within months. Contractors will acquire permits and land access as needed prior to study field work.
8.2 Demand- or Supply-Side Efficiency Upgrades
If you have invested in energy efficiency projects that will have a positive impact on the proposed
project, and have chosen to not include them in the economic analysis, applicants should provide
as much documentation as possible including:
1. Explain how it will improve the success of the RE project
2. Energy efficiency pre and post audit reports, or other appropriate analysis,
3. Invoices for work completed,
4. Photos of the work performed, and/or
5. Any other available verification such as scopes of work, technical drawings, and payroll for
work completed internally.
Not applicable
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SECTION 9 – LOCAL SUPPORT AND OPPOSITION
Describe local support and opposition, known or anticipated, for the project. Include letters,
resolutions, or other documentation of local support from the community that would benefit from
this project. Provide letters of support, memorandum of understandings, cooperative agreements
between the applicant, the utility, local government and project partners. The documentation of
support must be dated within one year of the RFA date of November 16, 2021. Please note that
letters of support from legislators will not count toward this criterion.
Please see attached Resolution from the BPMC, which represents support from all Railbelt electric
utilities.
SECTION 10 – COMPLIANCE WITH OTHER AWARDS
Identify other grants that may have been previously awarded to the Applicant by AEA for this or
any other project. Describe the degree you have been able to meet the requirements of previous
grants including project deadlines, reporting, and information requests.
Chugach received an EETF grant from AEA for the battery and flywheel demonstration project which
has helped inform Chugach’s decisions regarding the addition of a larger grid battery. Chugach has
been responsive to requests by AEA and shares performance information with Alaska Center for
Energy and Power as needed per agreement between AEA and Chugach.
Chugach works closely with AEA on many projects, including supporting electric vehicle charging
developments.
SECTION 11 – LIST OF SUPPORTING DOCUMENTATION FOR PRIOR PHASES
In the space below, please provide a list of additional documents attached to support completion of
prior phases.
No prior phases have been completed.
SECTION 12 – LIST OF ADDITIONAL DOCUMENTATION SUBMITTED FOR CONSIDERATION
In the space below, please provide a list of additional information submitted for consideration.
Attached is the current draft schedule for the project from the feasibility phase through licensing,
conceptual design and final design.
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SECTION 13 – AUTHORIZED SIGNERS FORM
Community/Grantee Name:Chugach Electric Association, Inc.
Regular Election is held:Annually in May Date:January 18, 2022
Authorized Grant Signer(s):
Printed Name Title Term Signature
Arthur Miller Exec. VP, Regulatory and
External Affairs
N/A
Lee Thibert CEO N/A
I authorize the above person(s) to sign Grant Documents:
(Must be authorized by the highest ranking organization/community/municipal official)
Printed Name Title Term Signature
Lee Thibert CEO N/A
Grantee Contact Information:
Mailing Address:PO Box 196300, Anchorage, AK 99519-6300
Phone Number:(907) 762-4747
Fax Number:(907) 562-0027
Email Address:Lee.thibert@chugachelectric.com
Federal Tax ID #:92-0014224
Please submit an updated form whenever there is a change to the above information.
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Page 1 of 6
Memorandum of Agreement
AEA/Chugach Dixon Diversion Award
Memorandum of Agreement
Between Alaska Energy Authority & Chugach Electric Association. Inc.
Regarding the Management of a Dixon Diversion Feasibility Project Award
1. Parties. This Memorandum of Agreement (“MOA”) is made and entered into between the
Alaska Energy Authority ("AEA"), a corporation of the State of Alaska, and Chugach Electric
Association, Inc. ("Chugach"), an Alaska not-for-profit cooperative electric utility, relating to the
proposed conveyance of state awarded funding from AEA via the renewable energy fund to
Chugach, on behalf of the Bradley Lake Management Committee (BPMC), for the Dixon
Diversion Feasibility Project (“Project”) as authorized by BPMC Resolution 21-03, provided as
Exhibit A.
2. Terms and Conditions.
a. AEA’s Role and Responsibilities. AEA will manage the renewable energy funds
awarded to Chugach for the same purpose described in the Dixon Diversion Feasibility
Project funding application as submitted by Chugach to AEA on January 18, 2022 (see
Exhibit B), with tasks re-focused on determining initial feasibility of the Project. The
Project tasks, as determined by the members of the BPMC, shall focus primarily on
refining engineered cost estimates and designs, and determining the gross water flows.
The cost estimate and estimate of water flow values will refine the economic value of the
Project prior to decisions to advance to further required studies, permitting, and
construction which will be determined at the discretion of the members of the BPMC.
The funds will be used to reimburse AEA competitively procured contractors for
engineering and environmental studies. The funds will offset expenses agreed to by the
BPMC and that otherwise would have been paid by the utilities participating in the
BPMC. AEA will provide progress reports, project accounting statements and technical
reports at least quarterly to the BPMC. AEA will be responsible for any reporting
obligations related to the project and use of funds.
b. Chugach’s Role and Responsibilities. Chugach will provide AEA via this MOA
permission to use the awarded renewable energy funds for the Dixon Diversion
Feasibility Project engineering and environmental studies. Chugach will review AEA’s
DocuSign Envelope ID: CA8DBD68-0378-45F3-82D2-7BAE1A7A88A1
Page 2 of 6
Memorandum of Agreement
AEA/Chugach Dixon Diversion Award
progress reports, accounting statements, and technical reports provided through the
BPMC meetings. Based on the feasibility project findings reported to the BPMC,
Chugach, in conjunction with the other members of the BPMC, will discuss whether
potential future advancement of the Project, if any, should be pursued.
3. General Provisions.
a. Termination. This MOA may be terminated by providing 30-days prior written notice to
any Party at any time without liability to the other Parties. If terminated, any remaining
awarded funds would be available to Chugach in the usual manner that Renewable
Energy Fund awards are provided to recipients.
b. Amendments. This MOA may be amended by written mutual agreement of the Parties.
c. Governing Law/Jurisdiction/Venue. This MOA, for all purposes, shall be construed in
accordance with the laws of Alaska without regard to conflicts of law principles. Any
action or proceeding by any of the Parties arising under or relating to this MOA shall be
brought only in a state or federal court located in Anchorage, Alaska. The parties hereby
irrevocably submit to the exclusive jurisdiction of such courts and waive the defense of
inconvenient forum to the maintenance of any such action or proceeding in such venue.
d. Reasonable Best Efforts. The Parties will use their reasonable best efforts to effectuate
the intent and purpose of this MOA.
e. No Third-Party Beneficiaries. Nothing herein is intended or shall be construed to
confer upon any person or entity other than the Parties and their successors or assigns,
any rights or remedies under or by reason of this MOA.
f. No Assignment. Neither this MOA, nor any rights or obligations hereunder may be
assigned, delegated or conveyed by any Party without the prior written consent of the
other Parties.
g. Indemnification. AEA shall indemnify, hold harmless, and defend Chugach against any
and all losses, damages, liabilities, claims, actions, judgments, settlements, penalties,
fines, costs, or expenses of whatever kind, including reasonable attorneys’ fees, that are
incurred by Chugach arising out of or related to any negligent or more culpable act or
omission of AEA or its personnel in connection with the performance of its obligations
under this Agreement.
h. Costs and Expenses. Except as otherwise agreed herein, each Party shall be responsible
for its own costs and expenses associated with pursuing the proposed transactions
described in this MOA, including without limitation (i) the performance of its obligations
DocuSign Envelope ID: CA8DBD68-0378-45F3-82D2-7BAE1A7A88A1
Page 3 of 6
Memorandum of Agreement
AEA/Chugach Dixon Diversion Award
under this MOA, (ii) pursuing any approvals necessary to effectuate this MOA, and/or
(iii) resolving any disputes between the Parties that arise out of this MOA.
i. Term of Agreement. This MOA will be deemed to be successfully ended upon the
expenditure of all, or a portion thereof, the $2 million in funds assigned, at the discretion
of the AEA project manager in consultation with Chugach and other members of the
BPMC; or the decision of AEA, Chugach, and/or the BPMC to cease continued work on
the Project as effectuated by the termination of this MOA via written notice as stated in
Section 3(a) of this MOA.
4. Contact Information
Curtis Thayer
813 W Northern Lights Blvd.
Anchorage, AK 99503
Tel: (907) 771-3000
cthayer@akenergyauthority.org
Arthur Miller
Chugach Electric Association, Inc.
5601 Electron Drive
Anchorage, AK 99518
Tel: (907) 762-4758
arthur_miller@chugachelectric.com
5. Counterparts. This MOA may be executed manually or by electronic signature in counterparts,
each of which shall be deemed an original, but all of which together shall be deemed one and the
same agreement. A signed copy of this MOA delivered by fax, email or other means of
electronic transmission, shall be deemed to have the same effect as delivery of an original signed
copy of this MOA.
DocuSign Envelope ID: CA8DBD68-0378-45F3-82D2-7BAE1A7A88A1
Page 4 of 6
Memorandum of Agreement
AEA/Chugach Dixon Diversion Award
IN WITNESS WHEREOF, the Parties hereto have executed this MOA as of the last date set forth
below.
Alaska Energy Authority
By: _________________________________ Date: ___________________
Name: Curtis Thayer
Title: Executive Director
Chugach Electric Association, Inc.
By: _________________________________ Date: ___________________
Name: Arthur Miller
Title: Chief Executive Officer
Attachments:
• Exhibit A: BPMC Resolution 21-03
• Exhibit B: Renewable Energy Fund Application – Dixon Diversion Feasibility Project
03/07/23
DocuSign Envelope ID: CA8DBD68-0378-45F3-82D2-7BAE1A7A88A1
3/7/2023
Page 5 of 6
Memorandum of Agreement
AEA/Chugach Dixon Diversion Award
Exhibit A – BPMC Resolution 21-03
DocuSign Envelope ID: CA8DBD68-0378-45F3-82D2-7BAE1A7A88A1
Page 6 of 6
Memorandum of Agreement
AEA/Chugach Dixon Diversion Award
Exhibit B: Renewable Energy Fund Application – Dixon Diversion Feasibility Project
DocuSign Envelope ID: CA8DBD68-0378-45F3-82D2-7BAE1A7A88A1
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: BPMC THROUGH: Curtis Thayer, Executive Director FROM: Jim Mendenhall, P.E., Director of Owned Assets DATE: January 12, 2026 SUBJECT: Cook Inlet Power Link (CIPLINK) Update
1) Environmental Review and 2026 Marine Survey Planning AEA issued a Task Order to HDR to advance environmental permitting and marine survey planning to support the summer 2026 field season. HDR and Stantec are coordinating to ensure that the marine survey data collected in summer 2026 will be sufficient to:
• Define the HVDC cable route and landfall locations
• Reduce technical uncertainty for cable suppliers
• Enable accurate OEM pricing and risk allocation during procurement The 2026 marine survey scope of work emphasizes early geophysical characterization and will include:
• High resolution bathymetry and geophysical surveys
• Limited grab sampling to characterize seafloor conditions
• Survey corridors wider than the final cable route to account for cable spacing, water depth, cable recovery, and installation tolerances
• Daily survey data delivery to allow adaptive field adjustments At cable landfalls, the team is evaluating HDD versus open cut trenching based on thermal performance, constructability, and soil conditions. Lidar and desktop studies are being considered to support design and permitting. AEA is pursuing an ASCE Nationwide Permit approach for survey activities. Informal ESA consultation is underway with beluga whale consideration addressed through low impact survey methods. The expected agency review period is 8-12 weeks with permits targeted to be in hand by April 2026. Geotechnical drilling is not planned for the 2026 marine season. One onshore borehole per landfall location is anticipated later in the year. 2) Major Equipment Procurement Strategy (HVDC Converters and Cable) Stantec is supporting AEA to develop the procurement strategy and solicitation documents for long lead HVDC equipment. These components are expected to have multiyear lead times and represent a critical path for the project. Future contract packages will include HVDC converters (near-term), HVDC submarine cable (near-term), overhead AC transmission, substations and terminations (later).
Alaska Energy Authority Page 2 of 2
AEA intends to issue RFIs and prequalification packages to cable and converter suppliers in early 2026 to gauge market interest and capability, understand delivery schedule, and inform the supplier arrangement type. Recent market information indicates that the cable market is more open than converters, though still constrained. Converter OEMs require a preferred supplier or negotiated arrangement before committing engineering resources. Firm pricing is typically available only after 30% design is complete. Stantec’s current task order includes preparation of procurement documents for OEM delivery, under which the OEM would design, manufacture, and install the equipment. Stantec’s procurement planning will include the development of budgetary pricing, delivery schedules, technical assumptions, and a 10-year O&M cost projection for major equipment. 3) System Configuration AEA has convened meetings with Stantec and EPS to focus on AC system constraints, reliability standards, and implications for overall project cost and configuration. Items discussed include:
• Existing 115 kV lines between Soldotna and Bernice Lake including their capacity and thermal limits Note: Summer operating conditions constrain available line capacity.
• VSC-based HVDC systems perform better than LCC-based systems in weak AC networks; however, they still require sufficient system strength and OEM-specific control tuning to manage oscillations and ensure stable operation. CIPLink is designed as a VSC system. Based on the discussions, AEA is considering the option of terminating the HVDC system at Soldotna instead of Nikiski. This configuration supports an initial 100 MW installation while preserving the ability to expand system capacity in the future. 4) Financial Status and DOE Coordination AEA has secured $64.2 million in combined state appropriations and Bradley Lake bond proceeds and continues to pursue additional funding to close project funding requirements of $142.3 million. Project expenditures through June 30, 2025, totaling $1,150,569.80 have been reimbursed by DOE. An additional $271,692 has been incurred thorough September 30, 2025. Following execution of Budget Period 2 (BP2) negotiations, AEA will submit an invoice for work completed from July 1, 2025, to date. AEA is actively collaborating with DOE to finalize the BP2 scope and budget. As part of these discussions, DOE has requested that BP2 reflects credits associated with work eliminated following the cancellation of Community Benefit Plan (CBP) requirements. AEA is developing a revised BP2 budget that reallocates previously dedicated CBP funds to other eligible project activities, subject to DOE review and approval.
MEMORANDUM TO: Bradley Project Management Committee Through: Curtis Thayer, Executive Director FROM: Ryan McLaughlin, PE, Senior Infrastructure Engineer DATE: January 16, 2026 RE: Bradley Lake Expansion Project Update Design and licensing efforts are ongoing, with submittal of the FERC Draft License Amendment Application (DLAA) anticipated in early February 2026. The DLAA will include a 16’ pool raise. AEA will be hosting a workshop with the utilities on January 22nd to compare different raise configurations, and operational changes that will have to occur for those scenarios to avoid spilling water in average, low, and high water years. Invitations have been sent to O&D committee members and can be forwarded to interested parties at the utilities. AEA will also be holding a construction sequencing & scheduling workshop on January 27th to review and refresh the overall project schedule. Interested O&D members or utilities can reach out for an invitation. AEA is considering pursuing a Construction Manager / General Contractor (CM/GC) project delivery strategy for the Bradley Lake Expansion Project. This would involve bringing on a construction contractor early in the design phase to provide preconstruction services including constructability reviews, scheduling, logistics planning, and risk identification and mitigation. The Bradley Lake Expansion Project is a remote and complex project that would benefit from early contractor involvement. CMGC would increase upfront project cost but improve cost certainty. AEA responded and submitted to FERC, 61 comments from the Board of Consultants (BOC) following BOC meeting 2 discussing Probable Maximum Flood (PMF) and Seismic Hazard studies at Bradley. During the PMF study, it was discovered that the drainage area into Bradley Lake is much larger than calculated during the 1982 study resulting in a 44% larger PMF. Although the spillway was constructed with excess capacity, the new PMF would put the flood peak 2.5’ over the dam crest, into the parapet wall. In the absence of a pool raise, it is very likely FERC would require modifications to the dam or spillway during relicensing. Purchase of the 3-phase transformer is working through AEA procurement. This item has a 2-year lead time and is expected to cost around $500,000. The design for remaining power upgrades is 90% complete and that procurement is targeted for July 1, 2026. 2026 subsurface investigation plan is coming together, which will target 2 deep boreholes along the tunnel alignment. This drilling will take place in late June / early July. An onsite BOC meeting will be scheduled to overlap the drilling investigations.
An updated construction cost estimate is expected by the end of January 2026. Design progressed significantly in 2025, and the updated estimate will reflect the design submitted in the DLAA and current and anticipated market conditions. AEA is reviewing and will be soon publishing the following study reports: Wildlife Habitat Evaluation, Vegetation Mapping, Bradley Wetlands Report, and Bradley Lake Shoreline Erosion.
Battle Glacier 10/02/2025
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
TO: BPMC
THROUGH: Curtis Thayer, Executive Director
FROM: Jim Mendenhall, P.E., Director of Owned Assets
DATE: January 12, 2026
SUBJECT: Transmission Upgrades – Sterling to Quartz Creek & Soldotna to Sterling
The Sterling Substation to Quartz Creek Transmission Line (SQ Line)
• Overall length of the SQ Line is 39 miles. The project is broken into three phases, each of
the projects needs to have approximately a 40-day outage of the transmission line.
o Phase 1 -The section is the 8 miles between Sterling and Johns Road was
completed during the winter of 2024/2025. Field conditions for Phase 1 were
difficult due to the warm weather and required ground matting to support the
equipment. The section was as completed and energized to 115kV on February
28, 2025
o Phase 2 – Upgrade 17 miles through the Kenai National Wildlife Refuge. This
section will be constructed in the winter 2026/2027.
o Phase 3 (previously 3 & 4) – Upgrade 14 miles from The Russian River to the
Quartz Creek Substation (CEA). This section will be constructed during the winter
2028/2029
• $88,085,000 - Total estimate cost for SQ line upgrades
• $14,200,000 – Phase 1 cost
• $73,885,000 – Remaining work to be completed
The Soldotna to Sterling Substation Transmission Line (SS Line)
• This section is owned by HEA.
• This project was planned to be constructed in the 2025/2026 winter. However, the
project was put on hold due to the extremely high steel quotes for the structures and
piling. In addition, the delivery window of the steel components did not fit with the
anticipated construction window.
• The original planned cost of the SS Line upgrades was $24.4M, the revised cost estimate
with contingency is $36.1M.
• With the SS line being postponed, the construction schedule has no work is planned for
this winter.
• The SS line upgrades are tentatively scheduled for winter of 2028/2029
• $36,135,000 -Total cost for SS upgrades
$124,220,000 – Total estimated cost of transmission upgrades. Note: Does not include
substation upgrades.
Project Map
SQ Line Upgrade to 230kV by ProjectsSQ P1 SQ P2 SQ P3 & P4 SS TotalsFY 2024 5,550,000$ 200,000$ 400,000$ -$ 6,150,000$ FY 2025 8,650,000$ 900,000$ 50,000$ 55,000$ 9,655,000$ FY 2026 -$ 17,650,000$ 525,000$ 15,000$ 18,190,000$ FY 2027 -$ 18,500,000$ 6,060,000$ 15,000$ 24,575,000$ FY 2028 - Preliminary Schedule -$ -$ 29,600,000$ 14,000,000$ 43,600,000$ FY 2029 - Preliminary Schedule -$ -$ -$ 22,050,000$ 22,050,000$ Line Upgrades for Upgrade Soldotna to Quartz Creek 14,200,000$ 37,250,000$ 36,635,000$ Subtotal for SQ Upgrades 88,085,000$ Subtotal for SS Upgrades 36,135,000$ Total estimate for transmission upgrades124,220,000$ Substation Upgrades Soldotna23,905,648$ Sterling9,395,500$ Quartz Creek16,403,807$ Substation Upgrade Totals49,704,955$ 49,704,955$ Total 173,924,955$ Completed to Date (14,200,000)$ To be completed 159,724,955$ Completed
Financing AEA’s Large Capital Projects
Curtis W. ThayerExecutive Director
BPMC MeetingJanuary 16, 2026
ALASKA ENERGY AUTHORITY
1
BPMC | January 16, 2026 2
Dixon Diversion
Expand the Bradley Lake Hydroelectric facility by diverting water from the Dixon Glacier into Bradley Lake, increasing energy output by approximately 180,000 MWh/year and displacing 1.5 billion cubic feet of natural gas annually. Project components include a diversion dam, a 4.7-mile tunnel, reservoir modifications, and access road construction.
Project status as of January 2026: Fiscal Year 2026 funding secured, environmental studies in progress; FERC feedback under review; Board of Consultants meeting October 2025; design work and permitting activities ongoing.
Cook Inlet PowerLink
±100 kV High Voltage Direct Current transmission system connecting the Bernice Lake and Beluga substations across Cook Inlet, designed for transfer bidirectionally of up to 200 megawatts to improve grid stability, redundancy, and renewable integration.
Project status as of January 2026:Cook Inlet PowerLink has completed its Preliminary Engineering Design Basis Report and environmental routing studies. The project now advancing into detailed design, permitting, and procurement, with early vendor engagement confirming feasibility and alignment with DOE GRIP program timelines
Large Capital Projects
3
AEA has secured initial
funding for both projects,
which are actively
progressing through early
development. However,
substantial capital investment
is still required to fully
execute each initiative.
Funding Status Overview
Cook Inlet PowerLink
Total cost: $413MM
Funds raised to date: $270.7MM
Funds still needed: $142.3MM
Dixon Diversion
Total cost: $361.7MM
Funds raised to date: $19.7MM
Funds still needed: $342MM
BPMC | January 16, 2026
4
$3,600,000 $6,850,000 $13,084,000
$99,280,000 $86,391,000
$106,521,000
$9,352,000
2025 2026 2027 2028 2029 2030 2031
$618,243 $881,757
$63,825,000 $63,825,000
$100,330,977 $99,565,091
$41,896,396 $42,057,536
$-
2024 2025 2026 2027 2028 2029 2030 2031 2032
Dixon Diversion ($342,000,000)
Start of Construction: May 2027
Commissioning: December 2030
Target Date to Secure Funding: Q3 2026
Cook Inlet PowerLink ($413,000,000)
Start of Construction: January 2029
Commissioning: April 2032
Target Date to Secure Funding: Q3 2026
Construction Cost Timeline
BPMC | January 16, 2026
5
1.USDA RUS – System Borrower program
2.USDA RUS – Project Specific loans
3.Tax exempt bonds (Bradley Lake Expansion Project only)
4.DOE EDF Tribal Program
5.DOE EDF Title 17
6.NRUCFC, taxable bonds
Potential Financial Partners
5BPMC | January 16, 2026
6
Next Steps
6
Current Funding Expires: July 2027 Finance Completion: Fall 2026
JAN 30 APR 16 JULY 30 AUG/SEPT ~SEPT 30
Update
AEA Board Meeting
Update
AEA Board Meeting
Approve Term
Sheet
AEA Board Meeting
Approve Term
Sheet
BPMC & Utilities
Board Meetings
Resolution
Approving
Financing Option
AEA Special
Board Meeting
Bradley Lake Expansion Project Timeline
BPMC | January 16, 2026
Bradley Lake Operators Report Page 1
Bradley Lake Operator Report
BPMC
January 16, 2026
Unit Statistics:
Generation Unit 1 (MWhrs) Unit 2 (MWhrs) Total (MWhrs)
Nov. 2025
Dec. 2025
Jan. *2026
24,556
24,957
4,616
25,442
25,832
7,282
49,999
50,789
11,898
Hydraulics Avg. Lake Level
(ft.)
Bradley Fishwater
(ac ft.)
Battle Creek MIF
(ac ft.)
Nov. 2025
Dec. 2025
Jan. *2026
1,162
1,149
1,138
1,062
2,000
650
0
0
0
Battle Creek Inflows to Bradley
(ac ft.)
Nov. 2025
Dec. 2025
Jan. *2026
0
0
0
*Lake Level – 1,156.7’ As of Jan. 8, 2026
Activities
• Forced Outages – None to report.
• Dam/Spillway – Completed the monthly safety inspection.
• Battle Creek Diversion- Secured for winter.
• Safety – There have been no lost time or reportable accidents for the months of November,
December and as of to date. Conducted a safety meeting on Dec 10, 2025. Next safety meeting is
January 14, 2026.
• Fire System- Yukon Fire personnel are working toward completion of the Control Room/
Generator Halon Fire System upgrade to a KIDDE SUPPRESION AGENT. Estimate completion by
January 30, 2026
• John Heberling formally of D Hittle Engineering (retired) has agreed to update the Estimated
Long-term Repair and Replacement Cost Report. He will start his review early in 2026.
Contractors/ Visitors
• HEA – Larry Jorgensen Safety Meeting.
• Yucon Fire – Fire System replacement.
Bradley Lake Operators Report Page 2
Bradley Lake, Dec. 28, 2025. Lake Elevation 1142.7
Bradley Lake Operators Report Page 3
Goat on the Power Tunnel Road Tail Race of the Powerhouse
Ice Tunnel at the Fish Water Valves
Bradley Lake Operators Report Page 4
Fire System Demolition
Removing the Halon Bottles Stripping the Alarm Pannels
New Fire System Control Pannels Rewired
Bradley Lake Operators Report Page 5
New Kidde Fire Bottles for Control Room
Alaska Energy Authority
Bradley Lake
Budget to Actual Expenses
07/01/2025 to 10/31/2025
Page 1 of 12
FY24 FY24 FY25 FY25 FY26 FY26
BUDGET ACTUALS BUDGET ACTUALS BUDGET ACTUALS
Install New Bradley Microwave System 518,000 45,215 - - - -
Brush Hog for Front End Loader 150,000 - - 111,087 - -
JLG All Terrain Fork Lift- New Purchase 190,000 213,942 - - - -
Replace BL#5 2009 F150 Crew Cab Pickup 45,000 - - 48,995 - -
Warehouse Heaters x2 (Replace) 5,000 - - - - -
ISO Shipping Containers x2 (Replace) 40,000 30,700 - - - -
Polaris Side by Side (Replace) - - 65,000 62,645 - -
Crew Quarters Remodel - - 85,000 84,873 - -
New Circuit Breaker - Generator #2 - - - 60,988 - -
Contex HD Ultra X 3690 Color Scanner - - - 12,620 - -
Replace DC Station Service Batteries - - - - 130,000 -
Replace Needle Valve Position Arm Bushings - - - - 95,000 -
Replace ION Meters - - - - 120,000 -
AC unit in powerhouse server room - - - - 38,000 -
Powerhouse Control Rm and Office Flooring - - - - 28,000 -
Approach Path Indicator Lights (Replace) - - - - 40,000 -
Limitorque Actuators on fish water valve (Replace) - - - - 35,000 -
Domestic water tank, controls, and filtration system (Replace) - - - - 35,000 -
Total Non R&C Capital Purchases 948,000 289,857 150,000 381,209 521,000 -
BRADLEY LAKE
CAPITAL PURCHASES NOT FUNDED BY R&C FUND
ALASKA ENERGY AUTHORITY
BRADLEY LAKE HYDROELECTRIC PROJECT
SCHEDULE A
FOR THE PERIOD 07/01/2025 TO 10/31/2025
BRADLEY LAKE NON-R&C CAPITAL PURCHASES
Page 2 of 12
ALASKA ENERGY AUTHORITY
BRADLEY LAKE HYDROELECTRIC PROJECT
BRADLEY LAKE OPERATIONS & MAINTENANCE
BUDGET TO ACTUAL EXPENSES
SCHEDULE B
FOR THE PERIOD 07/01/2025 TO 10/31/2025
FY 26 FY 25
FY26 Approved
Budget
BUDGET %
07/01/2025 -
10/31/2025 HEA Actual CEA Actual AEA Actual Total Actual
(Over) Under
Budget to Date
FY25 Approved
Budget FY25 Actual
Summary by expense type
Staff Professional Services (Direct) 360,000 120,000 - - 126,229 126,229 (6,229) 312,585 501,917
Labor & Benefits 1,497,414 499,138 338,310 10,586 84,711 433,607 65,531 2,054,317 1,435,363
Travel 40,300 13,433 119 115 2,445 2,679 10,754 51,500 57,509
Training 55,000 18,333 250 - - 250 18,083 55,000 7,211
Contractual 1,392,497 464,166 366,507 - 74,102 440,609 23,557 1,243,010 1,118,636
Consulting-Administrative 155,000 51,667 - - 19,262 19,262 32,404 315,000 46,433
Supplies & Materials 342,000 114,000 34,373 677 - 35,050 78,950 378,500 296,310
Other Costs 77,518 25,839 13,062 9,655 - 22,717 3,122 112,718 95,087
Equipment, Furniture & Machinery 20,000 6,667 7,645 - - 7,645 (979) 35,000 19,940
Administrative Costs 2,549,839 849,946 23,304 - 527,507 550,810 299,136 1,978,224 2,088,063
Indirect Costs 1,543,116 514,372 423,333 - - 423,333 91,039 1,480,105 1,340,986
O&M 4% Allocation to Battle Creek (321,307) (107,102) - - - - (107,102) (320,638) -
Total Bradley Lake Budget 7,711,376 2,570,459 1,206,904 21,033 834,256 2,062,193 508,266 7,695,321 7,007,455
FERC 535 - Operation Supervision & Engineering
Operations Sup/Eng
Bradley Lake Operating
Labor & Benefits 109,196 36,399 37,131 - - 37,131 (732) 105,451 99,743
Travel 5,000 1,667 - - - - 1,667 5,000 668
Training 5,000 1,667 - - - - 1,667 5,000 -
Contractual 3,000 1,000 - - - - 1,000 3,000 407
Supplies & Materials 25,000 8,333 939 - - 939 7,394 4,000 -
Indirect Costs 157,071 52,357 51,531 - - 51,531 826 155,698 139,723
Bradley Lake Operating Total 304,267 101,422 89,600 - - 89,600 11,822 278,149 240,542
FERC 535 - Operation Supervision & Engineering Total 304,267 101,422 89,600 - - 89,600 11,822 278,149 240,542
FERC 537 - Hydraulic Expenses
Hydraulic Expenses
Bradley Lake Operating
Labor & Benefits 81,895 27,298 27,957 - - 27,957 (658) 95,262 79,042
Contractual 15,000 5,000 - - - - 5,000 - -
Supplies & Materials 10,000 3,333 1,310 - - 1,310 2,023 4,000 1,729
Indirect Costs 113,127 37,709 35,906 - - 35,906 1,803 109,250 108,693
Bradley Lake Operating Total 220,022 73,341 65,173 - - 65,173 8,168 208,512 189,464
FERC 537 - Hydraulic Expenses Total 220,022 73,341 65,173 - - 65,173 8,168 208,512 189,464
FERC 538 - Electric Expenses
Electric Expenses
Bradley Lake Operating
Labor & Benefits 235,187 78,396 73,075 - - 73,075 5,321 218,044 227,478
Travel 7,000 2,333 12 - - 12 2,322 7,000 293
Training 30,000 10,000 250 - - 250 9,750 30,000 3,990
Contractual 18,000 6,000 12,133 - - 12,133 (6,133) 10,000 5,255
Supplies & Materials 23,500 7,833 1,244 - - 1,244 6,589 18,500 5,970
Indirect Costs 280,431 93,477 85,068 - - 85,068 8,409 262,004 268,318
Bradley Lake Operating Total 594,118 198,039 171,782 - - 171,782 26,258 545,548 511,305
FERC 538 - Electric Expenses Total 594,118 198,039 171,782 - - 171,782 26,258 545,548 511,305
FERC 539 - Misc. Hydraulic Power Generation Expenses
Misc Hydro Power Exp
Bradley Lake Operating
Labor & Benefits 130,567 43,522 21,923 - - 21,923 21,600 107,742 78,868
Training 20,000 6,667 - - - - 6,667 20,000 -
Contractual 606,317 202,106 246,624 - - 246,624 (44,519) 385,067 410,619
Supplies & Materials 30,000 10,000 6,810 - - 6,810 3,190 25,000 45,819
Equipment, Furniture & Machinery - - - - - - - - 2,563
Indirect Costs 122,323 40,774 31,158 - - 31,158 9,616 114,320 111,127 Bradley Lake Operating Total 909,207 303,069 306,516 - - 306,516 (3,447) 652,129 648,997
BRADLEY CIRCUITS/RADIO TO BERNICE LK
Other Costs 35,695 11,898 11,423 - - 11,423 476 35,695 34,268
BRADLEY CIRCUITS/RADIO TO BERNICE LK Total 35,695 11,898 11,423 - - 11,423 476 35,695 34,268
BRADLEY CIRCUITS BERNICE LK TO ANCH
Other Costs 29,773 9,924 - 9,655 - 9,655 269 29,773 28,985
BRADLEY CIRCUITS BERNICE LK TO ANCH Total 29,773 9,924 - 9,655 - 9,655 269 29,773 28,985
LOWER BRADLEY CIRCUITS/RADIO TO BARGE DOCK
Other Costs 10,000 3,333 1,639 - - 1,639 1,694 45,000 24,085
LOWER BRADLEY CIRCUITS/RADIO TO BARGE DOCK Total 10,000 3,333 1,639 - - 1,639 1,694 45,000 24,085
FERC 539 - Misc. Hydraulic Power Generation Expenses Total 984,675 328,225 319,577 9,655 - 329,233 (1,008) 762,597 736,335
FERC 541 - Maintenance Supervision & Engineering
Maint Supervision/Eng
Bradley Lake Operating
Labor & Benefits 117,056 39,019 39,051 - - 39,051 (32) 110,451 104,197
Indirect Costs 157,071 52,357 51,531 - - 51,531 826 155,698 139,723
Bradley Lake Operating Total 274,127 91,376 90,582 - - 90,582 794 266,149 243,920
FERC 541 - Maintenance Supervision & Engineering Total 274,127 91,376 90,582 - - 90,582 794 266,149 243,920
FERC 542 - Maintenance of Structures
Maintenance of Structures
Bradley Lake Operating
Labor & Benefits 84,789 28,263 19,763 - - 19,763 8,500 89,710 67,928
Contractual 35,000 11,667 2,249 - - 2,249 9,417 126,000 103,435
Supplies & Materials 44,000 14,667 6,675 - - 6,675 7,992 70,000 40,551
Equipment, Furniture & Machinery 20,000 6,667 7,645 - - 7,645 (979) 20,000 14,623
Indirect Costs 115,838 38,613 27,946 - - 27,946 10,666 102,350 94,601
Bradley Lake Operating Total 299,627 99,876 64,278 - - 64,278 35,598 408,060 321,138
FERC 542 - Maintenance of Structures Total 299,627 99,876 64,278 - - 64,278 35,598 408,060 321,138
FERC 543 - Maintenance of Reservoirs, Dams & Waterways
Maint Res, Dams, WWays
Bradley Lake Operating
Labor & Benefits 17,992 5,997 1,056 - - 1,056 4,942 51,783 13,050
Page 3 of 12
ALASKA ENERGY AUTHORITY
BRADLEY LAKE HYDROELECTRIC PROJECT
BRADLEY LAKE OPERATIONS & MAINTENANCE
BUDGET TO ACTUAL EXPENSES
SCHEDULE B
FOR THE PERIOD 07/01/2025 TO 10/31/2025
FY 26 FY 25
FY26 Approved
Budget
BUDGET %
07/01/2025 -
10/31/2025 HEA Actual CEA Actual AEA Actual Total Actual
(Over) Under
Budget to Date
FY25 Approved
Budget FY25 Actual
Contractual 6,500 2,167 10,430 - - 10,430 (8,263) 39,500 41,306
Supplies & Materials 20,000 6,667 283 - - 283 6,384 85,000 63,338
Equipment, Furniture & Machinery - - - - - - - 15,000 -
Indirect Costs 22,556 7,519 1,637 - - 1,637 5,882 58,650 16,000 Bradley Lake Operating Total 67,048 22,349 13,405 - - 13,405 8,944 249,933 133,694
BRADLEY POWER TUNNEL MAINT (Dam)
Contractual 15,000 5,000 - - - - 5,000 15,000 -
BRADLEY POWER TUNNEL MAINT (Dam) Total 15,000 5,000 - - - - 5,000 15,000 -
FERC 543 - Maintenance of Reservoirs, Dams & Waterways Total 82,048 27,349 13,405 - - 13,405 13,944 264,933 133,694
FERC 544 - Maintenance of Electric Plant
Maintenance of Elec Plant
Bradley Lake Operating
Labor & Benefits 336,995 112,332 77,372 - - 77,372 34,960 309,110 261,477
Travel 4,500 1,500 108 - - 108 1,392 4,500 530
Contractual 24,000 8,000 28,507 - - 28,507 (20,507) 75,000 60,276
Supplies & Materials 40,000 13,333 4,075 - - 4,075 9,258 40,000 35,276
Indirect Costs 461,361 153,787 110,149 - - 110,149 43,638 423,178 367,649
Bradley Lake Operating Total 866,856 288,952 220,211 - - 220,211 68,741 851,788 725,208
FERC 544 - Maintenance of Electric Plant Total 866,856 288,952 220,211 - - 220,211 68,741 851,788 725,208
FERC 545 - Maintenance of Misc. Hydraulic Plant
Maint of Misc Hydr Plant
Bradley Lake Operating
Labor & Benefits 82,339 27,446 20,304 - - 20,304 7,142 69,297 68,096
Contractual 45,000 15,000 36,250 - - 36,250 (21,250) 45,000 38,420
Supplies & Materials 68,000 22,667 12,914 - - 12,914 9,753 68,000 56,391
Indirect Costs 113,337 37,779 28,408 - - 28,408 9,371 98,957 95,152
Bradley Lake Operating Total 308,677 102,892 97,876 - - 97,876 5,016 281,254 258,059
FERC 545 - Maintenance of Misc. Hydraulic Plant Total 308,677 102,892 97,876 - - 97,876 5,016 281,254 258,059
FERC 556 - System Control & Load Dispatching
System Cntl & Load Disp
Bradley Lake Operating
Labor & Benefits 20,174 6,725 16,863 - - 16,863 (10,139) 20,174 25,978
Contractual 143,500 47,833 16,978 - - 16,978 30,855 103,500 49,188
Supplies & Materials 12,000 4,000 - - - - 4,000 12,000 854
Bradley Lake Operating Total 175,674 58,558 33,842 - - 33,842 24,716 135,674 76,020
Snow Measurement
Bradley Lake Operating
Contractual 10,000 3,333 - - - - 3,333 10,000 9,600
Bradley Lake Operating Total 10,000 3,333 - - - - 3,333 10,000 9,600
Seismic Service
Bradley Lake Operating
Contractual 66,498 22,166 - - 19,458 19,458 2,708 64,868 62,273
Bradley Lake Operating Total 66,498 22,166 - - 19,458 19,458 2,708 64,868 62,273
Streamguaging Serv
Bradley Lake Operating
Contractual 221,682 73,894 - - 54,644 54,644 19,250 216,275 269,784
Bradley Lake Operating Total 221,682 73,894 - - 54,644 54,644 19,250 216,275 269,784
Permits
Bradley Lake Operating
Other Costs 350 117 - - - - 117 350 240
Bradley Lake Operating Total 350 117 - - - - 117 350 240
FERC 556 - System Control & Load Dispatching Total 474,204 158,068 33,842 - 74,102 107,943 50,125 427,167 417,917
FERC 562 - Station Expenses
Station ExpensesBradley Lake Operating
Labor & Benefits 99,812 33,271 3,817 10,586 - 14,402 18,868 96,612 135,584
Travel 1,800 600 - 115 - 115 485 2,500 773
Contractual 103,000 34,333 13,335 - - 13,335 20,998 79,800 32,843
Supplies & Materials 45,000 15,000 123 677 - 799 14,201 23,000 25,534
Other Costs 1,700 567 - - - - 567 1,900 1,536 Bradley Lake Operating Total 251,312 83,771 17,274 11,378 - 28,652 55,119 203,812 196,269
FERC 562 - Station Expenses Total 251,312 83,771 17,274 11,378 - 28,652 55,119 203,812 196,269
FERC 570 - Maintenance of Station Equipment
Maintenance of Station Equip
Bradley Lake Operating
Bradley Lake Operating Total - - - - - - - - -
FERC 570 - Maintenance of Station Equipment Total - - - - - - - - -
FERC 571 - Maintenance of Overhead Lines
Maint of OH Lines
Bradley Lake Operating
Labor & Benefits 32,574 10,858 - - - - 10,858 36,500 23,486
Contractual 80,000 26,667 - - - - 26,667 70,000 35,229
Supplies & Materials 20,000 6,667 - - - - 6,667 20,000 11,965 Bradley Lake Operating Total 132,574 44,191 - - - - 44,191 126,500 70,681
FERC 571 - Maintenance of Overhead Lines Total 132,574 44,191 - - - - 44,191 126,500 70,681
FERC 920 & 930 - Administrative Expense
AEA Bradley Fixed Admin Fees
Bradley Lake Operating
Staff Professional Services (Direct) 360,000 120,000 - - 126,229 126,229 (6,229) 312,585 501,917
Travel - - - - 2,445 2,445 (2,445) - 53,177
Training - - - - - - - - 3,221
Consulting-Administrative - - - - 629 629 (629) - 2,153
Supplies & Materials - - - - - - - - 8,882
Other Costs - - - - - - - - 5,972
Equipment, Furniture & Machinery - - - - - - - - 2,754
Administrative Costs 240,000 80,000 - - - - 80,000 172,500 455,441
Page 4 of 12
ALASKA ENERGY AUTHORITY
BRADLEY LAKE HYDROELECTRIC PROJECT
BRADLEY LAKE OPERATIONS & MAINTENANCE
BUDGET TO ACTUAL EXPENSES
SCHEDULE B
FOR THE PERIOD 07/01/2025 TO 10/31/2025
FY 26 FY 25
FY26 Approved
Budget
BUDGET %
07/01/2025 -
10/31/2025 HEA Actual CEA Actual AEA Actual Total Actual
(Over) Under
Budget to Date
FY25 Approved
Budget FY25 Actual
Bradley Lake Operating Total 600,000 200,000 - - 129,303 129,303 70,697 485,085 1,033,515
Operating Committee Exp-Audit
Bradley Lake Operating
Administrative Costs 45,000 15,000 - - - - 15,000 41,000 38,534
Bradley Lake Operating Total 45,000 15,000 - - - - 15,000 41,000 38,534
Operating Committee Exp-Legal
Bradley Lake Operating
Administrative Costs 80,000 26,667 - - 39,443 39,443 (12,776) 80,000 125,918
Bradley Lake Operating Total 80,000 26,667 - - 39,443 39,443 (12,776) 80,000 125,918
Misc Admin
Bradley Lake Operating
Administrative Costs 13,000 4,333 - - 248 248 4,085 13,000 14,634
Bradley Lake Operating Total 13,000 4,333 - - 248 248 4,085 13,000 14,634
Professional Consultants
Bradley Lake Operating
Labor & Benefits 148,836 49,612 - - 84,711 84,711 (35,099) 744,181 250,437
Travel 22,000 7,333 - - - - 7,333 32,500 2,068
Supplies & Materials 4,500 1,500 - - - - 1,500 9,000 -
Bradley Lake Operating Total 175,336 58,445 - - 84,711 84,711 (26,266) 785,681 252,505
FERC 920 & 930 - Administrative Expense Total 913,336 304,445 - - 253,705 253,705 50,740 1,404,766 1,465,107
FERC 924 & 925 - Insurance Premiums
Insurance Premiums
Bradley Lake OperatingAdministrative Costs 1,581,839 527,280 23,304 - 487,816 511,119 16,160 1,371,724 1,164,007
Bradley Lake Operating Total 1,581,839 527,280 23,304 - 487,816 511,119 16,160 1,371,724 1,164,007
FERC 924 & 925 - Insurance Premiums Total 1,581,839 527,280 23,304 - 487,816 511,119 16,160 1,371,724 1,164,007
FERC 923 - Outside Services Employed
Outside Services Employed
Bradley Lake Operating
Consulting-Administrative 155,000 51,667 - - 18,634 18,634 33,033 315,000 44,280
Bradley Lake Operating Total 155,000 51,667 - - 18,634 18,634 33,033 315,000 44,280
FERC 923 - Outside Services Employed Total 155,000 51,667 - - 18,634 18,634 33,033 315,000 44,280
FERC 928 - Regulatory Commission Expenses
FERC Admin Fees
Bradley Lake Operating
Administrative Costs 170,000 56,667 - - - - 56,667 180,000 213,420 Bradley Lake Operating Total 170,000 56,667 - - - - 56,667 180,000 213,420
FERC Related Prof Services
BRADLEY FERC PART 12 INSPECTION
Administrative Costs 300,000 100,000 - - - - 100,000 - -
BRADLEY FERC PART 12 INSPECTION Total 300,000 100,000 - - - - 100,000 - -
BRADLEY CONTRACTUAL ENGINEER-FERC LICENSE ISSUES
Administrative Costs 120,000 40,000 - - - - 40,000 120,000 76,109
BRADLEY CONTRACTUAL ENGINEER-FERC LICENSE ISSUES Total 120,000 40,000 - - - - 40,000 120,000 76,109
FERC 928 - Regulatory Commission Expenses Total 590,000 196,667 - - - - 196,667 300,000 289,529
O&M 4% Allocation to Battle Creek (321,307) (107,102) - - - - (107,102) (320,638) -
Total Bradley Lake Budget 7,711,376 2,570,459 1,206,904 21,033 834,256 2,062,193 508,266 7,695,321 7,007,455
- - - - - - - - -
Page 5 of 12
Actual Projected Actual Projected Actual Projected
@ 6/30/24 TO REPAY Budget @ 6/30/25 TO REPAY Budget @ 6/30/26 TO REPAY Budget
Description Expense @6/30/24 FY24 Expense @6/30/25 FY25 Expense @6/30/26 FY26
R&C FUND PROJECTS
Governor - 4,052,070 - - 4,052,070 - - 4,052,070 -
Replace RFLS - 251,093 - - 251,093 - - 251,093 -
Replace Runners - 1,946,733 - - 1,946,733 - - 1,946,733 -
Replace cable from dam to power house - 2,321,923 - - 2,321,923 - - 2,321,923 -
Replace power system stabilizer - 619,205 - - 619,205 - - 619,205 -
Replace two RTUs - 86,905 - - 86,905 - - 86,905 -
Culvert Repairs - 675,967 - - 675,967 - - 675,967 -
Tower Repair for Jack Frost Heaves - 887,597 - - 887,597 - - 887,597 -
Replace Plant and SCADA Controls - 1,344,683 - - 1,344,683 - - 1,344,683 -
Vibration Monitoring System - 490 - - 490 - - 490 -
Fire Alarm System Replacement 33,942 171,339 1,338,000 - 171,339 1,307,299 120,000 291,339 1,471,407
Battle Creek Diversion - 1,170,000 - - 1,170,000 - - 1,170,000 -
Bradley Replace Electro-Mechanical Relays - 1,277,197 - - 1,277,197 - - 1,277,197 -
Fishwater Screen Debris Removal - 312,236 - - 312,236 - - 312,236 -
Turbine Nozzle Repair - 1,428,861 - - 1,428,861 - - 1,428,861 -
SVC replacement Daves Creek | Soldotna - 8,517,991 - - 8,517,991 - - 8,517,991 -
Equipment Storage Shed - 510,550 - - 510,550 - - 510,550 -
Emerson Operating System Upgrade - 622,665 - - 622,665 - - 622,665 -
Generator #2 Replacement - 953,213 - - 953,213 - - 953,213 -
Road Grader - 342,330 - - 342,330 - - 342,330 -
Battle Creek Construction - 3,739,591 - - 3,739,591 - - 3,739,591 -
Battle Creek Cash Call-Expended - 750,000 - - 750,000 - - 750,000 -
Battle Creek Cash Call-Paid by Utilities - (750,000) - - (750,000) - - (750,000) -
Needle Repairs - 1,482,791 - - 1,482,791 - - 1,482,791 -
Construct Additional Residence 805,515 1,000,284 910,000 75,156 1,075,440 - - 1,075,440 -
Bradley Lake Expansion Project**176,092 1,384,822 252,000 774,357 2,159,179 839,270 46,387 2,205,566 -
Needle Valve Rebuild 198,086 198,086 1,579,535 1,504,127 1,702,213 1,719,535 - 1,702,213 -
Barge Dock Rehabilitation - - - 401 401 600,000 - 401 600,000
Critical Spare (2) Nozzle Assemblies - - - - - - - - 400,000
Change out turbine nozzles units #1 and #2 - - - - - - - - 1,021,000
1,213,635 35,298,622 4,079,535 2,354,041 37,652,663 4,466,103 166,387 37,819,050 3,492,407
Current Year R&C Repayment (3,338,646) (2,580,808) (2,580,808)
Adjust balance to $5 million - - -
Interest in Fund Applied to Repayment (246,205) (157,748) (34,063)
Net Transfer from Revenue Fund (3,584,851) (2,738,556) (2,614,871)
Cumulative Prior Years R&C Repayments (31,677,137) (33,746,653) (35,082,970)
Due to (from) Utilities 1,515,335 1,402,238 2,614,871
Adjust Due to R&C Actual - - -
(30,161,802) (32,344,414) (32,468,100)
NET DUE TO R&C FUND 1,551,969 2,569,693 2,736,080
R&C FUND CASH FLOW PROJECTION
Beginning Investment Balance 4,370,333 6,177,000 6,186,586
Disbursements-current year -Accrual - - -
Disbursements-prior year accrued (789,379) (1,213,635) (2,354,041)
Utilities' R&C Refund (988,805) (1,515,335) (1,402,238)
Net other cash inflow(outflow) - - -
Current year interest earnings 246,205 157,748 34,063
Participants Contributions to R&C Fund 3,338,646 2,580,808 2,580,808
Ending Investment Balance 6,177,000 6,186,586 5,045,178
Accrued Due to (from) Utilities (1,515,335) (1,402,238) (2,614,871)
R&C payable back to the revenue fund - - -
Accrued R&C vendor Payable at Year End (1,213,635) (2,354,041) (166,387)
PROJECTED NET DUE + ENDING INVESTMENT BALANCE 5,000,000 5,000,000 5,000,000
Bradley Lake Expansion Project
Budget Commited Encumbered Actuals Variance
Bradley Lake R&C Fund 2,300,000 22,280 64,372 2,205,566 7,781
REF Grant (CEA) 1,000,000 - 315,640 684,360 -
State Hydro Development 5,000,000 20,000 251,743 4,728,108 149
State Railbelt 1,379,700 - 760,304 619,396 -
Bond Series 11 Interest 6,000,000 - 1,411,800 142,567 4,445,633
Bradley Lake Dixon Diversion 4,000,000 193,936 3,504,887 292,756 8,420
Total Project Cost at 10/31/25 19,679,700 236,216 6,308,746 8,672,754 4,461,984
4th 1,321,709
3rd 247,054 4th 247,054
2nd 197,345 3rd 197,345 4th 197,345
1st 303,409 2nd 303,409 3rd 303,409
1st 588,510 2nd 588,510
1st 41,597
2,069,516 1,336,318 303,409
BRADLEY LAKE HYDROELECTRIC PROJECT
R&C FUND DISBURSEMENTS AND REPAYMENTS
SCHEDULE D
FOR THE PERIOD 07/01/2025 T0 10/31/2025
ALASKA ENERGY AUTHORITY
Page 6 of 12
FY24 FY24 FY25 FY25 FY26 FY26
BUDGET ACTUALS BUDGET ACTUALS BUDGET ACTUALS
Battle Creek Associated Costs 15,000 - - - - -
Survey and Monument DNR Lease 150,000 88,651 5,000 2,621 5,000 -
Total Non R&C Capital Purchases 165,000 88,651 5,000 2,621 5,000 -
BATTLE CREEK
CAPITAL PURCHASES NOT FUNDED BY R&C FUND
ALASKA ENERGY AUTHORITY
BRADLEY LAKE HYDROELECTRIC PROJECT
BATTLE CREEK NON-R&C CAPITAL PURCHASES
SCHEDULE E
FOR THE PERIOD 07/01/2025 TO 10/31/2025
Page 7 of 12
BATTLE CREEK OPERATIONS & MAINTENANCE
BUDGET TO ACTUAL EXPENSES
SCHEDULE F
FOR THE PERIOD 07/01/2025 TO 10/31/2025
FY 26 FY 25
FY26 Approved
Budget
BUDGET %
07/01/2025 -
10/31/2025 HEA Actual CEA Actual AEA Actual Total Actual
(Over) Under
Budget to Date
FY25 Approved
Budget FY25 Actual
Summary by expense type
Staff Professional Services (Direct) 50,000 16,667 - - 10,363 10,363 6,304 50,000 46,192
Labor & Benefits 10,000 3,333 14,096 441 3,530 18,067 (14,734) 10,000 59,807
Travel - - 5 5 102 112 (112) - 3,322
Training - - 10 - - 10 (10) - 300
Contractual 333,477 111,159 15,271 - 92,871 108,142 3,017 201,300 243,987
Consulting-Administrative - - - - 803 803 (803) - 1,935
Supplies & Materials 5,000 1,667 1,432 28 - 1,460 206 5,000 12,346
Other Costs - - 544 402 - 947 (947) - 3,962
Equipment, Furniture & Machinery - - 319 - - 319 (319) - 831
Administrative Costs 14,000 4,667 971 - 21,979 22,950 (18,284) 14,000 93,093
Indirect Costs - - 17,639 - - 17,639 (17,639) - 55,874
O&M 4% Allocation to Battle Creek 321,307 107,102 - - - - 107,102 320,638 -
Total Battle Creek Budget 733,784 244,595 50,288 876 129,647 180,811 63,784 600,938 521,650
FERC 535 - Operation Supervision & Engineering
Operations Sup/Eng
Battle Creek Operating
Labor & Benefits 1,500 500 1,547 - - 1,547 (1,047) 1,500 4,156
Travel - - - - - - - - 28
Contractual - - - - - - - - 17
Supplies & Materials 1,000 333 39 - - 39 294 1,000 -
Indirect Costs - - 2,147 - - 2,147 (2,147) - 5,822
Battle Creek Operating Total 2,500 833 3,733 - - 3,733 (2,900) 2,500 10,023
FERC 535 - Operation Supervision & Engineering Total 2,500 833 3,733 - - 3,733 (2,900) 2,500 10,023
FERC 537 - Hydraulic Expenses
Hydraulic Expenses
Battle Creek Operating
Labor & Benefits 1,500 500 1,165 - - 1,165 (665) 1,500 3,293
Contractual 277,177 92,392 - - 89,783 89,783 2,609 145,000 141,077
Supplies & Materials 1,000 333 55 - - 55 279 1,000 72
Indirect Costs - - 1,496 - - 1,496 (1,496) - 4,529
Battle Creek Operating Total 279,677 93,226 2,716 - 89,783 92,499 727 147,500 148,972
FERC 537 - Hydraulic Expenses Total 279,677 93,226 2,716 - 89,783 92,499 727 147,500 148,972
FERC 538 - Electric Expenses
Electric Expenses
Battle Creek Operating
Labor & Benefits 1,500 500 3,045 - - 3,045 (2,545) 1,500 9,478
Travel - - 0 - - 0 (0) - 12
Training - - 10 - - 10 (10) - 166
Contractual - - 506 - - 506 (506) - 219
Supplies & Materials 1,000 333 52 - - 52 281 1,000 249
Indirect Costs - - 3,545 - - 3,545 (3,545) - 11,180
Battle Creek Operating Total 2,500 833 7,158 - - 7,158 (6,324) 2,500 21,304
FERC 538 - Electric Expenses Total 2,500 833 7,158 - - 7,158 (6,324) 2,500 21,304
FERC 539 - Misc. Hydraulic Power Generation Expenses
Misc Hydro Power Exp
Battle Creek Operating
Labor & Benefits 1,500 500 913 - - 913 (413) 1,500 3,286
Contractual - - 10,276 - - 10,276 (10,276) - 17,109
Supplies & Materials 1,000 333 284 - - 284 50 1,000 1,909
Other Costs - - 544 402 - 947 (947) - 3,639
Equipment, Furniture & Machinery - - - - - - - - 107
Indirect Costs - - 1,298 - - 1,298 (1,298) - 4,630
Battle Creek Operating Total 2,500 833 13,316 402 - 13,718 (12,885) 2,500 30,681
FERC 539 - Misc. Hydraulic Power Generation Expenses Total 2,500 833 13,316 402 - 13,718 (12,885) 2,500 30,681
FERC 541 - Maintenance Supervision & Engineering
Maint Supervision/Eng
Battle Creek Operating
Labor & Benefits 2,500 833 1,627 - - 1,627 (794) 2,500 4,342
Indirect Costs - - 2,147 - - 2,147 (2,147) - 5,822
Battle Creek Operating Total 2,500 833 3,774 - - 3,774 (2,941) 2,500 10,163
FERC 541 - Maintenance Supervision & Engineering Total 2,500 833 3,774 - - 3,774 (2,941) 2,500 10,163
FERC 542 - Maintenance of Structures
Maintenance of Structures
Battle Creek Operating
Labor & Benefits 1,500 500 823 - - 823 (323) 1,500 2,830
Contractual - - 94 - - 94 (94) - 4,310
Supplies & Materials 1,000 333 278 - - 278 55 1,000 1,690 Equipment, Furniture & Machinery - - 319 - - 319 (319) - 609
Indirect Costs - - 1,164 - - 1,164 (1,164) - 3,942
Battle Creek Operating Total 2,500 833 2,678 - - 2,678 (1,845) 2,500 13,381
FERC 542 - Maintenance of Structures Total 2,500 833 2,678 - - 2,678 (1,845) 2,500 13,381
FERC 543 - Maintenance of Reservoirs, Dams & Waterways
Maint Res, Dams, WWays
Battle Creek Operating
Labor & Benefits - - 44 - - 44 (44) - 544
Contractual - - 435 - - 435 (435) - 1,721
Supplies & Materials - - 12 - - 12 (12) - 2,639
Indirect Costs - - 68 - - 68 (68) - 667
Battle Creek Operating Total - - 559 - - 559 (559) - 5,571
FERC 543 - Maintenance of Reservoirs, Dams & Waterways Total - - 559 - - 559 (559) - 5,571
FERC 544 - Maintenance of Electric Plant
Maintenance of Elec Plant
Battle Creek Operating
Labor & Benefits - - 3,224 - - 3,224 (3,224) - 10,895
Travel - - 4 - - 4 (4) - 22
ALASKA ENERGY AUTHORITY
BRADLEY LAKE HYDROELECTRIC PROJECT
Page 8 of 12
BATTLE CREEK OPERATIONS & MAINTENANCE
BUDGET TO ACTUAL EXPENSES
SCHEDULE F
FOR THE PERIOD 07/01/2025 TO 10/31/2025
FY 26 FY 25
FY26 Approved
Budget
BUDGET %
07/01/2025 -
10/31/2025 HEA Actual CEA Actual AEA Actual Total Actual
(Over) Under
Budget to Date
FY25 Approved
Budget FY25 Actual
ALASKA ENERGY AUTHORITY
BRADLEY LAKE HYDROELECTRIC PROJECT
Contractual - - 1,188 - - 1,188 (1,188) - 2,511
Supplies & Materials - - 170 - - 170 (170) - 1,470
Indirect Costs - - 4,590 - - 4,590 (4,590) - 15,319
Battle Creek Operating Total - - 9,175 - - 9,175 (9,175) - 30,217
FERC 544 - Maintenance of Electric Plant Total - - 9,175 - - 9,175 (9,175) - 30,217
FERC 545 - Maintenance of Misc. Hydraulic Plant
Maint of Misc Hydr Plant
Battle Creek Operating
Labor & Benefits - - 846 - - 846 (846) - 2,837
Contractual - - 1,510 - - 1,510 (1,510) - 1,601
Supplies & Materials - - 538 - - 538 (538) - 2,350
Indirect Costs - - 1,184 - - 1,184 (1,184) - 3,965
Battle Creek Operating Total - - 4,078 - - 4,078 (4,078) - 10,752
FERC 545 - Maintenance of Misc. Hydraulic Plant Total - - 4,078 - - 4,078 (4,078) - 10,752
FERC 556 - System Control & Load Dispatching
System Cntl & Load Disp
Bradley Lake Operating
Bradley Lake Operating Total - - - - - - - - -
Battle Creek Operating
Labor & Benefits - - 703 - - 703 (703) - 1,082
Contractual - - 707 - - 707 (707) - 2,049
Supplies & Materials - - - - - - - - 36 Battle Creek Operating Total - - 1,410 - - 1,410 (1,410) - 3,167
Snow Measurement
Battle Creek Operating
Contractual - - - - - - - - 400
Battle Creek Operating Total - - - - - - - - 400
Seismic Service
Battle Creek Operating
Contractual - - - - 811 811 (811) - 2,595
Battle Creek Operating Total - - - - 811 811 (811) - 2,595
Streamguaging Serv
Battle Creek Operating
Contractual 56,300 18,767 - - 2,277 2,277 16,490 56,300 67,541
Battle Creek Operating Total 56,300 18,767 - - 2,277 2,277 16,490 56,300 67,541
Permits
Battle Creek Operating
Other Costs - - - - - - - - 10
Battle Creek Operating Total - - - - - - - - 10
FERC 556 - System Control & Load Dispatching Total 56,300 18,767 1,410 - 3,088 4,498 14,269 56,300 73,713
FERC 562 - Station ExpensesStation Expenses
Battle Creek Operating
Labor & Benefits - - 159 441 - 600 (600) - 5,649
Travel - - - 5 - 5 (5) - 32
Contractual - - 556 - - 556 (556) - 1,368
Supplies & Materials - - 5 28 - 33 (33) - 1,064
Other Costs - - - - - - - - 64
Battle Creek Operating Total - - 720 474 - 1,194 (1,194) - 8,178
FERC 562 - Station Expenses Total - - 720 474 - 1,194 (1,194) - 8,178
FERC 571 - Maintenance of Overhead Lines
Maint of OH Lines
Battle Creek Operating
Labor & Benefits - - - - - - - - 979 Contractual - - - - - - - - 1,468
Supplies & Materials - - - - - - - - 499
Battle Creek Operating Total - - - - - - - - 2,945
FERC 571 - Maintenance of Overhead Lines Total - - - - - - - - 2,945
FERC 920 & 930 - Administrative Expense
AEA Bradley Fixed Admin Fees
Battle Creek Operating
Staff Professional Services (Direct) 50,000 16,667 - - 10,363 10,363 6,304 50,000 46,192
Travel - - - - 102 102 (102) - 3,142
Training - - - - - - - - 134
Consulting-Administrative - - - - 26 26 (26) - 90
Supplies & Materials - - - - - - - - 370
Other Costs - - - - - - - - 249 Equipment, Furniture & Machinery - - - - - - - - 115
Administrative Costs - - - - - - - - 18,977
Battle Creek Operating Total 50,000 16,667 - - 10,491 10,491 6,176 50,000 69,268
Operating Committee Exp-Audit
Battle Creek Operating
Administrative Costs - - - - - - - - 1,606
Battle Creek Operating Total - - - - - - - - 1,606
Operating Committee Exp-Legal
Battle Creek OperatingAdministrative Costs 5,000 1,667 - - 1,643 1,643 23 5,000 5,247
Battle Creek Operating Total 5,000 1,667 - - 1,643 1,643 23 5,000 5,247
Operat Committee Exp-Arbitrage
Battle Creek Operating
Administrative Costs 2,500 833 - - - - 833 2,500 1,690
Battle Creek Operating Total 2,500 833 - - - - 833 2,500 1,690
Trust & Account Fees
Battle Creek Operating
Administrative Costs 5,500 1,833 - - - - 1,833 5,500 4,400 Battle Creek Operating Total 5,500 1,833 - - - - 1,833 5,500 4,400
Page 9 of 12
BATTLE CREEK OPERATIONS & MAINTENANCE
BUDGET TO ACTUAL EXPENSES
SCHEDULE F
FOR THE PERIOD 07/01/2025 TO 10/31/2025
FY 26 FY 25
FY26 Approved
Budget
BUDGET %
07/01/2025 -
10/31/2025 HEA Actual CEA Actual AEA Actual Total Actual
(Over) Under
Budget to Date
FY25 Approved
Budget FY25 Actual
ALASKA ENERGY AUTHORITY
BRADLEY LAKE HYDROELECTRIC PROJECT
Misc Admin
Battle Creek Operating
Administrative Costs 1,000 333 - - 10 10 323 1,000 610
Battle Creek Operating Total 1,000 333 - - 10 10 323 1,000 610
Professional ConsultantsBattle Creek Operating
Labor & Benefits - - - - 3,530 3,530 (3,530) - 10,435
Travel - - - - - - - - 86
Battle Creek Operating Total - - - - 3,530 3,530 (3,530) - 10,521
FERC 920 & 930 - Administrative Expense Total 64,000 21,333 - - 15,674 15,674 5,659 64,000 93,341
FERC 924 & 925 - Insurance Premiums
Insurance Premiums
Battle Creek Operating
Administrative Costs - - 971 - 20,326 21,297 (21,297) - 48,500
Battle Creek Operating Total - - 971 - 20,326 21,297 (21,297) - 48,500
FERC 924 & 925 - Insurance Premiums Total - - 971 - 20,326 21,297 (21,297) - 48,500
FERC 923 - Outside Services Employed
Outside Services Employed
Battle Creek Operating
Consulting-Administrative - - - - 776 776 (776) - 1,845
Battle Creek Operating Total - - - - 776 776 (776) - 1,845
FERC 923 - Outside Services Employed Total - - - - 776 776 (776) - 1,845
FERC 928 - Regulatory Commission Expenses
FERC Admin Fees
Battle Creek Operating
Administrative Costs - - - - - - - - 8,893
Battle Creek Operating Total - - - - - - - - 8,893
FERC Related Prof Services
Battle Creek Operating
Administrative Costs - - - - - - - - 3,171
Battle Creek Operating Total - - - - - - - - 3,171
FERC 928 - Regulatory Commission Expenses Total - - - - - - - - 12,064
O&M Allocation to Battle Creek 321,307 107,102 - - - - 107,102 320,638 -
Total Battle Creek Budget 733,784 244,595 50,288 876 129,647 180,811 63,784 600,938 521,650
- - - - - - - - -
Page 10 of 12
FY 26 FY 25
FY26 Approved
Budget
BUDGET %
07/01/2025 -
10/31/2025 HEA Actual CEA Actual AEA Actual Total Actual
(Over) Under
Budget to Date
FY25 Approved
Budget FY25 Actual
Summary by expense type
Staff Professional Services (Direct)10,000 3,333 - - 995 995 2,338 40,000 7,086
Labor & Benefits 50,000 16,667 - - - - 16,667 50,000 47,722
Travel - - - - - - - - 63
Contractual 150,000 50,000 4,269 - - 4,269 45,731 150,000 58,795
Permitting 36,878 12,293 - - - - 12,293 36,878 72,223
Supplies & Materials 20,000 6,667 - - - - 6,667 20,000 52
Administrative Costs 7,000 2,333 - - - - 2,333 47,000 5,059
Total SSQ Line Budget 273,878 91,293 4,269 - 995 5,264 86,029 343,878 190,998
FERC 556 - System Control & Load Dispatching
Permits
SSQ Line Operating
Permitting 36,878 12,293 - - - - 12,293 36,878 72,223
SSQ Line Operating Total 36,878 12,293 - - - - 12,293 36,878 72,223
FERC 556 - System Control & Load Dispatching Total 36,878 12,293 - - - - 12,293 36,878 72,223
FERC 570 - Maintenance of Station Equipment
Maintenance of Station Equip
SSQ Line Operating
SSQ Line Operating Total - - - - - - - - -
FERC 570 - Maintenance of Station Equipment Total - - - - - - - - -
FERC 571 - Maintenance of Overhead Lines
Maint of OH Lines
SSQ Line Operating
Labor & Benefits 50,000 16,667 - - - - 16,667 50,000 47,722
Contractual 150,000 50,000 4,269 - - 4,269 45,731 150,000 58,795
Supplies & Materials 20,000 6,667 - - - - 6,667 20,000 -
SSQ Line Operating Total 220,000 73,333 4,269 - - 4,269 69,065 220,000 106,517
FERC 571 - Maintenance of Overhead Lines Total 220,000 73,333 4,269 - - 4,269 69,065 220,000 106,517
FERC 920 & 930 - Administrative Expense
AEA Bradley Fixed Admin Fees
SSQ Line Operating
Staff Professional Services (Direct)10,000 3,333 - - 995 995 2,338 40,000 7,086
Travel - - - - - - - - 63
Supplies & Materials - - - - - - - - 52
Administrative Costs - - - - - - - 20,000 3,059
SSQ Line Operating Total 10,000 3,333 - - 995 995 2,338 60,000 10,259
Trust & Account Fees
SSQ Line Operating
Administrative Costs 2,000 667 - - - - 667 2,000 2,000
SSQ Line Operating Total 2,000 667 - - - - 667 2,000 2,000
FERC 920 & 930 - Administrative Expense Total 12,000 4,000 - - 995 995 3,005 62,000 12,259
FERC 928 - Regulatory Commission Expenses
FERC Related Prof Services
BRADLEY CONTRACTUAL ENGINEER-FERC LICENSE ISSUES
Administrative Costs 5,000 1,667 - - - - 1,667 25,000 -
BRADLEY CONTRACTUAL ENGINEER-FERC LICENSE ISSUES Total 5,000 1,667 - - - - 1,667 25,000 -
FERC 928 - Regulatory Commission Expenses Total 5,000 1,667 - - - - 1,667 25,000 -
Total SSQ Line Budget 273,878 91,293 4,269 - 995 5,264 86,029 343,878 190,998
- - - - - - - - -
ALASKA ENERGY AUTHORITY
SSQ LINE OPERATIONS & MAINTENANCE
SCHEDULE I
BUDGET TO ACTUAL EXPENSES
FOR THE PERIOD 07/01/2025 TO 10/31/2025
BRADLEY LAKE HYDROELECTRIC PROJECT
Page 11 of 12
Source
Construction
Funds at
11/30/22
Investment
Expenses
Calculated
Capital Reserve at
11/30/22
Released from
Capital Reserve
Total Available
Funding
Required Project Work Bond Series 11 Funding 166,013,134 (157,250) (12,454,346) 1,151,865 154,553,403
BESS Required Project Work Bond Series 11 Funded
Capital Projects Total Funding Project Budget Committed Encumbered
Total Actual
Costs
(Over) / Under
Project Budget
(Over) / Under
Total Funding
BRADLEY HEA BESS Preliminary Study 75,000 - 22,473 958 51,569
Oscillation Dampening Service - CEA 16,072,398 - - 1,120,458 14,951,940
Oscillation Dampening Service - MEA 3,870,839 - - 269,848 3,600,991
Total BESS Capital Projects 24,093,691 20,018,236 - 22,473 1,391,264 18,604,499 22,679,954
Transmission Required Project Work Bond Series 11
Funded Capital Projects Total Funding Project Budget Committed Encumbered
Total Actual
Costs
(Over) / Under
Project Budget
(Over) / Under
Total Funding
SSQ Line Sterling-Qtz Ck 230kV Construction - - 37,746 13,710,910 (13,748,656)
Soldotna-Sterling 230kV Construction - - - 987,565 (987,565)
BRADLEY Required Project Work Support - - - 170,052 (170,052)
Bradley RPW - Bond Series 11 - - - 49,375 (49,375)
Total Transmission Capital Projects 80,459,712 - - 37,746 14,917,901 (14,955,647) 65,504,065
GRIP 3 Round 1 Required Project Work Bond Series 11
Funded Projects - HVDC Line Total Funding Project Budget Committed Encumbered
Total Actual
Costs
(Over) / Under
Project Budget
(Over) / Under
Total Funding
Allocate from BESS AEA Resolution 24-12 30,000,000 - - - 30,000,000
Allocate from Transmission AEA Resolution 24-02 20,000,000 - - - 20,000,000
Total Grip 3 Round 1 Capital Projects 50,000,000 50,000,000 - - - 50,000,000 50,000,000
Total Required Project Work 154,553,403 70,018,236 - 60,219 16,309,165 53,648,852 138,184,018
10/31/25
APPENDIX ACAPITAL PROJECTS FUNDED BY SERIES 11 BOND PROCEEDS
BRADLEY LAKE HYDROELECTRIC PROJECT
ALASKA ENERGY AUTHORITY
50,000,000 50,000,000
65,504,065 80,459,712
24,093,691 22,679,954
Page 12 of 12
Bradley Operation and Dispatch Committee Report
January 16th, 2026
Meeting Dates:
December 19, 2025
Notable Discussions and Items:
□ Discussion on Dixon Diversion
Water Tracking & Lake Level:
□ As of January 1st, 2026, Bradley Lake contained approximately 146,598 MWh of energy.
Committee Assignments:
□ CEA continues work to address SCADA challenges to allow HEA wheeling capacity as
defined in the existing Bradley agreement.
□ BPMC approved - CEA & HEA investigating appropriate relay settings - $15k spend limit.
• HEA and CEA are working on the development of work scope for best practice analysis.
Next Meeting:
January 23rd, 2025 @ 10am