Board of Directors Regular Meeting Agenda
Wharfinger Building, Bay Room (downstairs)
1 Marina Way, Eureka, CA 95501
Thursday, January 22 2026
3:30 PM
Meeting Information
Meeting Reports and Comments
Pursuant to Government Code section 54957.5, all writings or documents relating to any item on this agenda which have been provided to a majority of the Board, including those received less than 72 hours prior to the Board’s meeting, will be made available to the public at redwoodenergy.org.
Speakers wishing to distribute materials to the Board at the meeting must provide 13 copies to the Board Clerk.
How to Participate
This is a hybrid in-person and virtual meeting. As a courtesy, the public may participate remotely through the Zoom platform. RCEA cannot guarantee uninterrupted teleconference access. When technical difficulties arise, the meeting will continue unless otherwise required by law, such as when a Board member attends the meeting remotely pursuant to certain Brown Act provisions. The only way to guarantee that the Board receives your comment is to attend the meeting in person or submit your comment in writing before the meeting.
To participate in the meeting online, go to https://us02web.zoom.us/j/81972368051.
To participate by phone, call (669) 900-6833 or (253) 215-8782. Enter webinar ID: 819 7236 8051.
To speak during the public comment periods, raise your hand in the online Zoom webinar, or press star (*) 9 on your phone to raise your hand. Staff will ask you to unmute your phone or computer when it is your turn. You will have 3 minutes to speak.
Email written comments to [email protected]. Identify the agenda item number in the subject line. Comments will be included in the meeting record but not read aloud during the meeting.
Accessibility
Need help with accessibility? Any member of the public needing special accommodation to participate in this meeting or access the meeting materials should email [email protected] or call (707) 269-1700 at least 3 business days before the meeting. Assistive listening devices are available. 1 January 22, 2026
RCEA Board of Directors Meeting Agenda
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Open Session (Call to Order)
1. Roll Call | Remote Director Participation
2. Board Appointments
2.1. Election of Officers and Community Advisory Committee Liaison Appointments Select the RCEA Board Chair and Vice Chair to serve through January 2027 and authorize them as signers on RCEA bank accounts.
Appoint a Board Liaison, and an alternate liaison if desired, to the Community Advisory Committee to serve through January 2027.
2.2. Board Finance Committee Member Assignment
Determine whether the standing Finance Committee should continue its work.
Appoint up to five Directors to serve on the standing Finance Committee for one-year terms ending on February 28, 2027.
3. Reports from Member Entities
4. Oral & Written Communications
This time is provided for people to address the Board or submit written communications on matters not on the agenda. At the conclusion of all oral communications, the Board may respond to statements. Any request that requires Board action will be set by the Board for a future agenda or referred to staff.
5. Consent Calendar
All matters in the Consent Calendar section are considered routine by the Board and are enacted in one motion. There is no separate discussion of any of these items; if discussion is required, that item is removed from the Consent Calendar and considered separately. At the end of the reading of the Consent Calendar, Board members or members of the public can request that an item be removed for separate discussion.
5.1. Approve Minutes of November 24, 2025, Board Meeting.
5.2. Approve Disbursement Reports for October and November 2025, and Financial Reports for this Fiscal Year Through November 2025.
5.3. Receive Federal Activity Report.
5.4. Approve the 2026 RCEA Board of Directors Meeting Calendar.
5.5. Provide Suggestions for This and Future Policy Platform Updates, and Accept 2026 RCEA Policy Platform.
6. Items Removed from Consent Calendar
Items removed from the Consent Calendar section will be heard under this section. 2 January 22, 2026
RCEA Board of Directors Meeting Agenda
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7. Staff Reports
7.1. Executive Director’s Report (Information only)
Community Choice Energy (CCE) Business
Items under this section of the agenda relate to CCE-specific business matters that fall under RCEA’s CCE voting provisions, with only CCE-participating jurisdictions voting on these matters with weighted voting as established in the RCEA joint powers agreement.
8. CCE Business Consent Calendar
All matters in the Community Choice Energy Business Consent Calendar section are considered routine by the CCE-participating jurisdiction Board members and are enacted in one motion. There is no separate discussion of any of these items. If discussion is required, that item is removed from the Consent Calendar section and considered separately. At the end of the reading of the CCE Business Consent Calendar, any Board member or members of the public can request that an item be removed for separate discussion.
8.1. Adopt Resolution 2026-1 Adopting the Updated Energy Risk Management Policy.
9. Items Removed from CCE Business Calendar
10. Old CCE Business
10.1. Power Charge Indifference Adjustment Update (Information only)
10.2. Energy Risk Management Semi-Annual Report
Accept Energy Risk Management Semi-Annual Report and provide feedback to staff on information presented to inform any further analysis or future Board actions.
11. New CCE Business – None.
End of CCE Business | Resume RCEA General Business
12. Old Business
12.1. Community Advisory Committee Member Appointments and Recruitment Reappoint Ethan Lawton, Benjamin Fordham, and Dennis Leonardi to the Community Advisory Committee for Two-Year Terms Ending on March 31, 2028.
Recruit up to 5 members for an ad hoc CAC at-large subcommittee to review applications and nominate candidates at the February 26, 2026, RCEA Board meeting.
13. New Business
13.1. Presentation on Northern Rural Energy Network 2028-31 Business Plan Approve submission of the 2028-2031 Northern Rural Energy Network Business Plan Application to the California Public Utilities Commission.
13.2. Baker Tilly engagement for tax credit for RCAM and EV charging stations 3 January 22, 2026
RCEA Board of Directors Meeting Agenda
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1. Approve an amendment to Baker Tilly Advisory Group, LP Master Service Agreement to increase the not-to-exceed amount by $31,000 for a total not-to-exceed of $80,500.
2. Approve scope of work 2 with Baker Tilly for the preparation and filing of Investment Tax Credit documents for the Redwood Coast Airport Microgrid project
13.3. PG&E Local Government Partnership Contract to Provide Energy Efficiency Services Change Order
Approve a Change Order to the PG&E Local Government Partnership Contract to extend the term through 2027, increase the budget by $799,992, and make amendments to the program design and authorize the Executive Director to execute all applicable documents after review and approval of RCEA General Counsel.
13.4. Discuss Regional Climate Action Plan Implementation Discuss Regional Climate Action Plan implementation and provide direction to staff to further explore RCEA serving as the Regional Climate Committee and adding a position for a Regional Climate Manager.
14. Future Agenda Items
Any request that requires Board action will be set by the Board for a future agenda or referred to staff.
15. Closed Session
15.1. Real Property Negotiations Pursuant to Government Code § 54956.8 in re: APN 001-135- 007; RCEA negotiator: Executive Director; Owner’s negotiating party: Wells Commercial; Under negotiation: price and terms.
15.2. Conference with Legal Counsel: Deciding whether to initiate litigation, pursuant to Government Code Section 54956.9(d)(4).
15.3. Public Employee Performance Evaluation, pursuant to Government Code § 54957:
Executive Director.
15.4. Conference with Labor Negotiator, pursuant to Government Code § 54956.7. RCEA designated representative, Board Chair; Unrepresented employee, Executive Director.
16. Reconvene to Open Session
17. Closed Session Report
18. Adjournment
Next Regular Meeting
Thursday, February 26, 2026 | 3:30 PM
Wharfinger Building Bay Room (downstairs), 1 Marina Way, Eureka, CA 95501 Online and phone participation is available via Zoom.
4
Staff Report
Agenda Item # 1.1
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Eileen Verbeck, Deputy Executive Director
Subject Revised Member Teleconference Participation Rules Background
When emergency Brown Act meeting law changes went into effect in 2020 due to the COVID-19 public health emergency, the RCEA Board of Directors, Community Advisory Committee (CAC) and the subcommittees of those bodies met online via teleconference using the Zoom platform with no physical, public meeting location. Since the pandemic, the Brown Act has been amended to codify modern teleconference meeting practices both during and outside of declared states of emergency. SB 707 (Durazo, 2025) sets out the latest Brown Act revisions which were signed into law on October 3, 3025.
Summary
RCEA Board Directors may attend up to two meetings per year from a remote location without making the location accessible to the public for the following, revised, “just cause” reasons:
1. Childcare or caregiving to child, parent, grandparent, grandchild, sibling, spouse, domestic partner;
2. Contagious illness that prevents in person attendance;
3. Mental or physical need not subject to reasonable accommodation provisions;
4. Travel while on official business of RCEA or another state or local agency;
5. Immunocompromised child, parent, grandparent, grandchild, sibling, spouse, or domestic partner that requires remote participation;
6. Physical or family medical emergency; or
7. Military service obligations.
A vote is not necessary to request remote attendance for just cause, including for medical emergency remote attendance per SB 707 revisions. A brief description, protecting the Director’s (or family member’s) medical privacy, must be provided and the Director must publicly disclose whether anyone 18 years of age or older is present in the room at the remote location, and the general nature of the individual’s relationship with the Director.
In February, staff will recommend Board adoption of a revised Teleconferencing Policy capturing the latest Brown Act revisions and provide the Board an opportunity to pass a resolution enabling remote meeting participation for members who must travel at least 20 miles to the Wharfinger Building. 5
Staff Recommendation
None. Information only.
Required Distribution Information
The Revised Ralph M. Brown Act
Link to California Government Code Sections 54950 - 549631, revised October 3, 2025, by SB 707 (Durazo, 2025).
Redwood Coast Energy Authority List of Physical Meeting Locations Body Date Time Location
Board of Directors 4th Thursday of each
month 3:30 p.m. Wharfinger Building, 1 Marina Way, Eureka, CA 95501 Community Advisory
Committee
2nd Tuesday of odd-numbered months 6 p.m.
Jefferson Community Center
Auditorium, 1000 B Street, Eureka,
CA 95501
Finance Committee As needed, dates TBD TBD RCEA Offices, 633 Third Street, Eureka, CA 95501
1 The Revised Ralph M. Brown Act, California Code, GOV 54950.5 - 54963:
https://leginfo.legislature.ca.gov/faces/codes_displayText.xhtml?lawCode=GOV&division=2.&title=5.&part=1.&chapt er=9.&article=
6
Staff Report
Agenda Item # 2.1
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Lori Taketa, Clerk of the Board
Subject Election of Officers and Community Advisory Committee Liaison Appointments Background
Election of Officers
Following its Operating Guidelines, the RCEA Board selects a Chair and Vice Chair annually at its January meeting by simple majority vote. The Chair’s responsibilities include:
• Conducting monthly and special meetings
• Attending monthly agenda review meetings
• Check signing and disbursement authority, including electronic funds disbursement.
The Vice Chair assumes these responsibilities when the Chair is unable to perform them.
Both Chair and Vice Chair are asked to complete the appropriate signature forms for RCEA’s banking institution soon after the January meeting, and to be available to sign checks periodically when authorized staff are not available.
Community Advisory Committee Liaison Appointment
RCEA‘s Community Advisory Committee (CAC) was established by the Board to support RCEA public engagement efforts and provide the Board with decision-making support and input.
The Board’s Operating Guidelines state that the Board will appoint at least one RCEA Board member as a CAC liaison that will attend CAC meetings but will not vote. The role of the Board liaison as outlined in the CAC Charter is to:
• Contribute content knowledge and Board perspective at CAC meetings, • Encourage participation and help create a civil, collaborative environment, • Communicate committee recommendations and perspectives to the Board, and • Participate as a non-voting member.
Director Sarah Schaefer was the 2025 Board liaison. Director Natalie Arroyo served as alternate Board liaison last year.
7
Staff Recommendation
Select the RCEA Board Chair and Vice Chair to serve through January 2027 and authorize them as signers on RCEA bank accounts.
Appoint a Board Liaison, and an alternate liaison if desired, to the Community Advisory Committee to serve through January 2027.
Attachments
None.
8
Staff Report
Agenda Item #2.2
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Eileen Verbeck, Deputy Executive Director
Subject Board Finance Committee Member Assignment
Summary
The first Board meeting of the year presents an opportunity to review the Board’s standing Committee and appoint members as needed. As part of any committee discussion and review, the Board may choose to disband the body if it is no longer needed.
Finance Committee (standing)
In January 2019, the Board created a standing Finance Committee to meet as needed to work with staff and advise the Board on matters relating to audit, finance and the budget. This body met twice in 2025 to review draft fiscal year budget and mid-year budget adjustments. Because this is a standing committee it is subject to all Brown Act open meeting requirements.
The Board Finance Committee is comprised of up to five (5) Board Directors. Current Finance Committee members are Committee Chair Michael Gerace, Scott Bauer, Skip Jorgensen, Jason Ramos and Frank Wilson. Member terms are for one year ending on February 28 to allow for mid-year budget adjustment consideration.
Staff Recommendation
Determine whether the standing Finance Committee should continue its work.
Appoint up to five Directors to serve on the standing Finance Committee for one-year terms ending on February 28, 2027.
Attachments
None.
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10 Board of Directors Meeting Draft Minutes
Wharfinger Building, Bay Room (downstairs)
1 Marina Way, Eureka, CA 95501
Monday, November 24 2025
3:30 PM
Attendance
Present
Natalie Arroyo Scott Bauer, Chair Skip Jorgensen
Elise Scafani Sarah Schaefer Frank Wilson
Sheri Woo, Vice Chair
Absent
Carlos Diaz Michael Gerace
Jason Ramos Jack Tuttle
Staff and Others Present
Name Title
Ken Beals IT Technician
Lori Biondini Business Planning & Finance Director
Elizabeth Burks Executive Director
Brytann Busick Community Strategies Manager
Faith Carlson Regulatory & Legislative Policy Manager
Ronnie Chaussé Interim Finance Manager, Acting Board Clerk Nancy Diamond RCEA Legal Counsel
Richard Engel Power Resources Director
Kristy Siino Human Resources Manager
Eileen Verbeck Deputy Executive Director
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Staff and Others Present (continued)
Nathan Hightower Ignite Energy, California Condor, LLC (project company) Tyler Noble Managing Director, Municipal Capital Markets Group, Inc.
Blake Sweeney Sr. Research Manager, ReconMR
Christian Riepe Sr. Vice President, Insights & Analytics, ReconMR Open Session
Chair Bauer called a meeting of the Board of Directors of the Redwood Coast Energy Authority to order at the above location and date at 3:34 p.m. Notice of this meeting was posted on November 21, 2025.
Consent Calendar
4.1. Approve Minutes of October 23, 2025, Board Meeting.
4.2. Accept Disbursement Report for September 2025, and Financial Reports for This Fiscal Year Through September 2025.
4.3. Receive Federal Activity Report.
4.4. Approve Task Order Services Through December 2026 with each Northern Rural Energy Network Implementing Partner Under Their Respective NREN Program Implementation Agreements and Authorize the Executive Director to Execute All Applicable Documents for the Following Not-to-Exceed Amounts:
4.5. $1,000,000 with Lake Area Planning Council
4.6. $1,000,000 with Mendocino Council of Governments
4.7. $5,700,000 with Sierra Business Council.
4.8. Cancel the Regular RCEA Board Meeting of December 22, 2025, at 3:30 p.m.
4.9. Authorize the Executive Director to Select the Energy Efficiency Kit Service Vendor(s) that Best Meet the Needs of RCEA and NREN for Service Contract(s) for a Not to Exceed Value of $290,000 and, Upon the Review and Approval by RCEA Legal Counsel, Authorize the Executive Director to Execute All Applicable Documents.
Director Wilson requested item 4.5 be removed from the Consent Calendar for clarification.
M/S: Arroyo, Jorgenson: Approve all Consent Calendar items except 4.5.
The motion passed with a unanimous vote. Ayes: Arroyo, Bauer, Jorgensen, Scafani, Schaefer, Wilson, Woo. Noes: None. Absent: Diaz, Gerace, Ramos, Tuttle. Abstain: None.
Staff provided clarifying details for the December Board meeting cancellation.
M/S: Wilson, Woo: Approve Consent Calendar item 4.5.
The motion passed with a unanimous vote. Ayes: Arroyo, Bauer, Jorgensen, Scafani, Schaefer, Wilson, Woo. Noes: None. Absent: Diaz, Gerace, Ramos, Tuttle. Abstain: None. 12 11/24/25
RCEA Board of Directors DRAFT Minutes
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Old Business
9.1. Diablo Canyon Power Plant Nuclear Allocation for 2026 Director Engel reported on the Board’s request to reconsider whether RCEA should accept another year’s worth of carbon-free credits from continued operation of the Diablo Canyon nuclear power plant.
All California load-serving entity customers are required to help pay for the plant’s operation, which was extended due to growing energy demand and lagging renewable energy development to supply that demand. The directors verified that the Energy Risk Management Policy reflects a prohibition on procuring energy from nuclear power plants, and that it had been revised to say the Board will reconsider accepting the carbon free credits from Diablo Canyon each year they are offered to RCEA. The RCEA Policy Platform also includes opposition to policies extending the life of the Diablo Canyon Nuclear Power Plant. RCEA’s financial position is more positive than when the Board first considered accepting the allocation last year. The directors will consider potential uses for last year’s carbon-free attribute credits at a future meeting. Some directors expressed opposition to Diablo Canyon’s continued operation given the spent fuel’s extremely long-lived hazardousness and the geological risk of the waste storage location. Staff will report on opportunities for the Board to comment on the facility’s license renewal at a future meeting. There was no public comment on this item.
M/S: Arroyo, Scafani: Accept the 2026 nuclear allocation, making a short-term exception to the RCEA Energy Risk Management Policy’s prohibition on nuclear power procurement, as allowed for in the Energy Risk Management Policy.
The motion passed with a show of hands vote. Ayes: Arroyo, Jorgensen, Scafani, Wilson, Woo. Noes: Bauer, Schaefer. Absent: Diaz, Gerace, Ramos, Tuttle. Abstain: None.
New Business
10.1. Flycatcher Local Distributed Energy Resources Energy Storage Services Agreements Located at the Site of the Formerly Operational Fairhaven Biomass Plant Power Resources Director Engel described the Flycatcher battery storage project. The project was one of two shortlisted respondents to the Local Distributed Energy Storage request for offers issued in 2024 to increase local grid reliability and capacity. The directors discussed the potential to expand the project’s storage capacity, the short construction timeframe to take advantage of disappearing federal energy storage incentives, and capacity at the project’s substation to put energy on the grid. There was no public comment on this item.
M/S: Schaefer, Scafani: Approve Resolution 2025-7 Approving the Form of and Authorizing Execution of the Energy Storage Service Agreements with California Condor, LLC.
The motion passed with a unanimous vote. Ayes: Arroyo, Jorgensen, Scafani, Wilson, Woo, Bauer, Schaefer. Noes: None. Absent: Diaz, Gerace, Ramos, Tuttle. Abstain: None.
10.2. Northern Rural Energy Network 2028 Business Cycle Implementation Plan – Inclusion of Yolo County
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Executive Director Burks reported on customer program work performed to date by the fledgling NREN program across rural Northern California. Yolo County expressed interest in joining NREN. NREN’s governing partners proposed requesting additional funds for the 2028-2031 business cycle to cover Yolo County Sustainability Office staff implementing NREN programs in their service area as well as RCEA’s corresponding administrative costs. The directors discussed how the California Public Utilities Commission is favoring consolidation of Regional Energy Networks (RENs) over creation of new RENs and how the NREN’s budget could include outreach to entities in other parts of rural Northern California about joining NREN. There was no public comment on this item.
M/S: Jorgenson, Arroyo: Approve the Inclusion of Yolo County as a Participant in the NREN 2028-2031 Business Plan.
The motion passed with a unanimous vote. Ayes: Arroyo, Bauer, Jorgensen, Scafani, Schaefer, Wilson, Woo. Noes: None. Absent: Diaz, Gerace, Ramos, Tuttle. Abstain: None.
10.3. RCEA and Desert Community Energy Joint Pre-Payment of Power Purchase Agreement Advisory Service
Municipal Capital Markets Group Managing Director Tyler Noble described how municipal utility districts and Community Choice Aggregators can take advantage of their ability to pay in advance for existing power purchase agreements with tax-exempt municipal bonds, partner with taxable investment companies, and gain electricity cost savings for their customers from the difference in interest rates for taxable corporate and tax-exempt municipal debt. The directors clarified safeguards for RCEA ratepayer funds and expressed concern over using CCA governmental status to create profit for large corporations and their shareholders. Mr. Noble explained that the impetus behind the enabling legislation was to provide some relief to CCA and municipal utility district customers facing high energy bills. The group considered how governmental bonds offer some stability to investor portfolios. There was no public comment on this item.
M/S: Arroyo, Wilson: Authorize Executive Director to take necessary steps to pursue an energy pre-payment transaction including:
1. Develop and execute an agreement with John Norman and Tyler Noble of Municipal Capital Markets Group, Inc. jointly with Desert Community Energy for advisory and related services in support of an energy prepayment transaction for the two CCAs at a total shared cost not to exceed $350,000, and
2. Select and negotiate an agreement with Project Participant Legal Counsel at a total shared cost not to exceed $300,000, all contingent upon successful execution of an energy pre-payment transaction.
The motion passed with the following vote. Ayes: Arroyo, Jorgensen, Scafani, Wilson, Woo, Bauer. Noes: Schaefer. Absent: Diaz, Gerace, Ramos, Tuttle. Abstain: None.
10.4. ReconMR Presentation on RCEA Brand Awareness Survey Results 14 11/24/25
RCEA Board of Directors DRAFT Minutes
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Executive Director Burks described staff’s motivation for undertaking a brand awareness survey. The survey’s results can give RCEA’s staff and Board a more comprehensive understanding of customer needs and priorities to better focus programs and policy decision making. ReconMR Senior Research Manager Blake Sweeney presented the brand awareness survey’s high-response rate results. The general community had relatively low awareness of what RCEA is, but relatively high regard for the agency among those who are aware of RCEA. Customer priorities are electricity reliability and lower cost first, followed by values aligning with RCEA’s mission: local, renewable energy generation and use. Staff will consider the survey’s results when planning outreach efforts, programs and messaging .
There were no public comments on this agenda item.
Staff Reports
11.1. Executive Director’s Report
Executive Director Burks described staff outreach efforts for the past and coming months. Six Regional Resilience Planning and Implementation Grant-funded battery trailers were delivered and distributed to remote Humboldt County fire stations. The CADEMO offshore wind project loan funds have not yet been disbursed but the loan committee was scheduled to meet soon. Executive Director Burks anticipated a lengthy January Board meeting due to the December meeting cancellation.
Closed Session
There were no public comments on the closed session items. The RCEA Board of Directors convened in closed session at 5:34 p.m.
13.1. Real Property Negotiations Pursuant to Government Code § 54956.8 in re: APN 001-135- 007; RCEA negotiator: Executive Director; Owner’s negotiating party: Wells Commercial; Under negotiation: price and terms.
13.2 Public Employee Performance Evaluation, pursuant to Government Code § 54957:
Executive Director.
Reconvene Open Session
The Board of Directors reconvened in open session at 6:50 p.m. Chair Bauer stated that there was nothing to report from the closed session.
Adjournment
Chair Bauer adjourned the meeting at 6:50 p.m.
Ronnie Chaussé
Acting Board Clerk
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16
Staff Report
Agenda Item # 5.2
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Lori Biondini, Business Planning and Finance Director Subject Profit & Loss, Balance Sheet and Monthly Disbursements Reports Summary
The attached Disbursements Report lists RCEA’s checks, debits and electronic payments made during the period identified on the report. The Business Planning and Finance Director certifies that the disbursements were drawn in payment of demands conforming to RCEA’s adopted Financial Policy and budget.
The Financial Reports (Profit & Loss Budget vs. Actual and Balance Sheet) are presented to keep the Board apprised of current agency receipts and spending relative to budget line items.
Alignment with RCEA’s Strategic Plan
Agency financial tracking and reporting are necessary administrative functions supporting RCEA strategic plan goal implementation.
Financial Impact
The disbursements presented were drawn in payment of demands included within the adopted budget.
Staff Recommendation
Approve Disbursement Reports for October and November 2025, and Financial Reports for This Fiscal Year Through November 2025.
Attachments
1. Disbursements Report for October 1 through October 31, 2025
2. Profit & Loss Budget vs. Actual Report, July 2025 through October 2025
3. Balance Sheet as of October 31, 2025
4. Disbursements Report for November 1 through November 30, 2025
5. Profit & Loss Budget vs. Actual Report, July 2025 through November 2025
6. Balance Sheet as of November 30, 2025
17 Accrual Basis Redwood Coast Energy Authority
Disbursements Report
As of October 31, 2025
Type Date Num Name Memo Amount
Bill Pmt -Check 10/06/2025 ACH The Energy Authority CISO100125-SEPT25 -128,174.79 Liability Check 10/10/2025 ACH Ascensus 10/10/25 Payroll -15,182.53 Liability Check 10/10/2025 ACH Ascensus 10/10/25 Payroll -13,352.78 Liability Check 10/10/2025 ACH EDD 10/10/25 Payroll -9,163.25 Liability Check 10/10/2025 ACH Internal Revenue Service 10/10/25 Payroll -39,663.33 Bill Pmt -Check 10/10/2025 ACH CA Community Power FY 2025-26 Phase 2 Projects -137,389.20 Bill Pmt -Check 10/10/2025 ACH CalCCA Operational Member dues Q2 FY 25/26 -32,958.75 Bill Pmt -Check 10/10/2025 ACH Leapfrog Power, Inc Sept 2025 RA Invoice -36,740.00 Bill Pmt -Check 10/10/2025 ACH PG&E Voluntary Allocation May 2025 Forecast Price- VA -140,841.48 Bill Pmt -Check 10/10/2025 ACH Sonoma Clean Power Authority Sept 2025 Flex RA sale - Monthly -261,000.00 Bill Pmt -Check 10/10/2025 ACH Valley Clean Energy Alliance Sept 2025 MTR RA Swap -24,991.00 Bill Pmt -Check 10/10/2025 ACH Viridity Energy Solutions, Inc. Sept 2025 Tierra Buena RA -16,172.00 Bill Pmt -Check 10/10/2025 ACH Tesla Motors Final Payment - RCAM EPC contract -376,938.53 Check 10/10/2025 21474 NEM Customer NEM Transistional Cash Out 2025 -372.27 Check 10/10/2025 21475 CCE Customer CCE EV Rebate EV65 -2,000.00 Check 10/10/2025 21476 NREN Customer NREN Equipment Res Rebate 250826-3043 -100.00 Check 10/10/2025 21477 NREN Customer NREN Equipment Res Rebate 250902-3061 -100.00 Check 10/10/2025 21478 NREN Customer NREN Equipment Res Rebate 250902-3058 -100.00 Check 10/10/2025 21479 NREN Customer NREN Equipment Res Rebate 250820-3015 -700.00 Check 10/10/2025 21480 NREN Customer NREN Equipment Res Rebate 250831-3056 -550.00 Check 10/10/2025 21481 NREN Customer NREN Equipment Res Rebate -850.00 Bill Pmt -Check 10/10/2025 21482 Arcata Chamber of Commerce Membership dues 2025 -440.00 Bill Pmt -Check 10/10/2025 21483 Arcata Police Department Livescan screening: Rolling Fee x 1 -35.00 Bill Pmt -Check 10/10/2025 21484 AT&T RCAM Internet Router/Data -812.97 Bill Pmt -Check 10/10/2025 21485 AT&T Long Distance Phone charges 09/25 - 10/24/2025 -97.51 Bill Pmt -Check 10/10/2025 21486 Baker Tilly US, LLP VOID: services - period ending 09/30/25 0.00 Bill Pmt -Check 10/10/2025 21487 Bidwell Consulting Services, Inc. Deferred Compensation Plan Management -400.00 Bill Pmt -Check 10/10/2025 21488 Bohn, Juliette Sept 2025 Reimbursement & Mileage -114.59 Bill Pmt -Check 10/10/2025 21489 Braun Blaising & Wynne, P.C. Aug 2025 Regulatory & Legal Services -8,374.12 Bill Pmt -Check 10/10/2025 21490 Burks, E. Per Diem x 2 -242.00 Bill Pmt -Check 10/10/2025 21491 Busick, B. Sept 2025 Mileage & Purchase Reimb -145.11 Bill Pmt -Check 10/10/2025 21492 California Air Resources Board AB 32 Fee FY 2022-2023 -1,921.00 Bill Pmt -Check 10/10/2025 21493 City of Eureka-Water 917 & 633 3rd. St. 07/28/25-08/26/25 -417.48 Bill Pmt -Check 10/10/2025 21494 CPH Sponsored Programs Foundation RCAM Task Orders -10,368.00 Bill Pmt -Check 10/10/2025 21495 Developed Employment Services, LLC. 805 3rd St. Yard work -117.50 Bill Pmt -Check 10/10/2025 21496 Donald Dame CCE Consulting services- Sept 2025 -407.75 Bill Pmt -Check 10/10/2025 21497 Donnelly, S. Per Diem Meals: NREN Mtg Truckee -110.00 Bill Pmt -Check 10/10/2025 21498 EAN Services, LLC Car rental Sept 2025:CalCCA Leg Com Fall Mtg -110.12 Bill Pmt -Check 10/10/2025 21499 Energy Resources Integration, LLC Sept 2025 NREN Commercial Needs Assesment -29,057.75 Bill Pmt -Check 10/10/2025 21500 Engel, R. Per Diem Meals: CC Power Forum R. Engel -132.00 Bill Pmt -Check 10/10/2025 21501 Humboldt Bay Coffee Co. Sept Coffee 917 & 633 3rd St. -93.65 Bill Pmt -Check 10/10/2025 21502 Humboldt HyCycle Oct 2025: 5 E-Bike Vouchers -2,200.00 Bill Pmt -Check 10/10/2025 21503 Hunter Rayl Foster Solar Ribbon Cutting Event Photography -500.00 Bill Pmt -Check 10/10/2025 21504 Kullmann, S. Per Diem Meals: NREN Mtg Truckee -110.00 Bill Pmt -Check 10/10/2025 21505 Law Offices of Nancy Diamond Sept 2025 Legal Services -10,276.00 Bill Pmt -Check 10/10/2025 21506 Mission Linen & Uniform Service Sept & Oct 2025 Janitorial supplies -158.98 Bill Pmt -Check 10/10/2025 21507 North Coast Cleaning Services, Inc. Sept 2025 Office Cleaning Services -1,090.00 Bill Pmt -Check 10/10/2025 21508 Optimum Business-633 633 3rd St: Phone & Internet 09/28-010/27/2025 -1,101.77
18 Accrual Basis Redwood Coast Energy Authority
Disbursements Report
As of October 31, 2025
Type Date Num Name Memo Amount
Bill Pmt -Check 10/10/2025 21509 Reider, S Mileage Reimbursement-Sept/Oct 2025 -54.18 Bill Pmt -Check 10/10/2025 21510 Revolution Bicycles, Inc. Oct 2025: 1 E-Bike Voucher -400.00 Bill Pmt -Check 10/10/2025 21511 Scrapper's Edge 24x36" corrugated plastic sign -44.65 Bill Pmt -Check 10/10/2025 21512 Shred Aware Shredding services - Sept 2025 -68.95 Bill Pmt -Check 10/10/2025 21513 Smith, S. Per Diem Meals: NREN Mtg Truckee -110.00 Bill Pmt -Check 10/10/2025 21514 Special District Risk Managment P&L Additional Insured Certs and added property -269.56 Bill Pmt -Check 10/10/2025 21515 Sport & Cycle VOID: Sept 2025 E-Bike Voucher 0.00 Bill Pmt -Check 10/10/2025 21516 Terry, P. Per Diem Meals: NREN Mtg Truckee -110.00 Bill Pmt -Check 10/10/2025 21517 Times Printing Company CCE Customer Late Notices -710.67 Bill Pmt -Check 10/10/2025 21518 Ubeo Business Services 633+ 917 3rd St Printer Charges: 09/06-10/05/25 -266.33 Bill Pmt -Check 10/10/2025 21519 Yakovleva, Vera A. Reimbursement: CalCCA Leg Com Fall Mtg -59.09 Bill Pmt -Check 10/10/2025 21520 Baker Tilly US, LLP Accounting Services - period ending 09/30/25 -36,120.00 Bill Pmt -Check 10/10/2025 21521 Sport & Cycle Sept 2025 E-Bike Voucher -600.00 Paycheck 10/10/2025 ACH Employees Payroll -95,905.62
Bill Pmt -Check 10/14/2025 ACH The Energy Authority CISO100825 -111,258.44 Bill Pmt -Check 10/15/2025 ACH The Energy Authority Monthly TEA Invoice #TEA92025 Sept 2025 -390,592.81 Bill Pmt -Check 10/17/2025 ACH Mendocino Council of Governments NREN Quarterly Payment -104,483.02 Check 10/17/2025 ACH VISA- Commercial Card Statement Date 9/30/25 -16,643.78 Bill Pmt -Check 10/20/2025 ACH The Energy Authority CISO101525 -36,661.90 Check 10/21/2025 Debit Columbia Bank Service Charge -248.12 Check 10/21/2025 Debit Columbia Bank Service Charge -245.11 Liability Check 10/24/2025 ACH Ascensus 10/24/25 Payroll -14,793.34 Liability Check 10/24/2025 ACH CICCS Coalition for Controlling Insurance Nov 2025 Premiums -66.98 Liability Check 10/24/2025 ACH EDD 10/24/25 Payroll -8,995.46 Liability Check 10/24/2025 ACH Internal Revenue Service 10/24/25 Premiums -38,887.33 Liability Check 10/24/2025 ACH Keenan Nov 2025 Premiums -50,033.79 Liability Check 10/24/2025 ACH Principal Life Insurance Company Nov 2025 Premiums -129.88 Liability Check 10/24/2025 ACH Ascensus 10/24/25 Payroll -13,163.97 Bill Pmt -Check 10/24/2025 ACH CalPine Corporation Sept 2025 Data Management Costs -68,146.44 Bill Pmt -Check 10/24/2025 ACH Dynapower Company LLC Replacement air filters for RCAM -740.17 Bill Pmt -Check 10/24/2025 ACH EDPR CA Solar Park LLC II Sept 2025 Contract Energy -334,720.83 Bill Pmt -Check 10/24/2025 ACH Humboldt Sawmill Co. Sept 2025 Electricity Generation -831,970.47 Liability Check 10/24/2025 21522 Ameritas Life Insurance Corp. - Dental Nov 2025 Premiums -2,878.04 Liability Check 10/24/2025 21523 Ameritas Life Insurance Corp.- Vision Nov 2025 Premiums -511.92 Bill Pmt -Check 10/24/2025 21524 AM Conservation Group, Inc. NREN Res Kits: Various addresses Qty 34 -3,556.19 Bill Pmt -Check 10/24/2025 21525 Amazon.com Monthly billing - Oct 2025 -821.39 Bill Pmt -Check 10/24/2025 21526 Arcata Technology Center Site Host Reimbursement 07/01-09/30/2025 -516.15 Bill Pmt -Check 10/24/2025 21527 AT&T RCAM 10/07-11/06/25 data backup -331.95 Bill Pmt -Check 10/24/2025 21528 Bithell, M. Mileage Reimbursement-Sept/Oct 2025 -126.08 Bill Pmt -Check 10/24/2025 21529 Blue Lake Rancheria Site Host Reimbursement 07/01-09/30/2025 -2,461.36 Bill Pmt -Check 10/24/2025 21530 Carter Properties 917 3rd Street Office Lease - NOV 2025 -2,450.00 Bill Pmt -Check 10/24/2025 21531 City of Arcata Site Host Reimbursement 07/01-09/30/2025 -1,815.76 Bill Pmt -Check 10/24/2025 21532 City of Blue Lake Site Host Reimbursement 07/01-09/30/2025 -870.08 Bill Pmt -Check 10/24/2025 21533 City of Eureka - REVNet Site Host Reimbursement 07/01-09/30/2025 -1,231.51 Bill Pmt -Check 10/24/2025 21534 City of Trinidad Site Host Reimbursement 07/01-09/30/2025 -970.03 Bill Pmt -Check 10/24/2025 21535 CPH Sponsored Programs Foundation RCAM Task Orders -6,558.00 Bill Pmt -Check 10/24/2025 21536 CSDA 2026 Membership Dues -2,381.00 Bill Pmt -Check 10/24/2025 21537 Department of Justice Customer 165251, Fingerprinting Fee -49.00
19 Accrual Basis Redwood Coast Energy Authority
Disbursements Report
As of October 31, 2025
Type Date Num Name Memo Amount
Bill Pmt -Check 10/24/2025 21538 Humboldt Bay Coffee Co. Office Coffee- 633 3rd St. -59.10 Bill Pmt -Check 10/24/2025 21539 Humboldt HyCycle Oct 2025: 5 E-Bike Vouchers -3,200.00 Bill Pmt -Check 10/24/2025 21540 Mission Linen & Uniform Service Oct. 2025 Janitorial Services -159.16 Bill Pmt -Check 10/24/2025 21541 North Coast Unified Air Quality Site Host Reimbursement 07/01-09/30/2025 -807.41 Bill Pmt -Check 10/24/2025 21542 NYLEX.net, Inc. Onsite network support services - Nov 2025 -5,759.00 Bill Pmt -Check 10/24/2025 21543 Open Door Community Health Center Site Host Reimbursement 07/01-09/30/2025 -509.29 Bill Pmt -Check 10/24/2025 21544 Pacific Paper Company Office supplies -66.01 Bill Pmt -Check 10/24/2025 21545 PG&E- EV Sept 2025 EV Accounts -1,981.17 Bill Pmt -Check 10/24/2025 21642 PG&E-Office Utility 09/05-10/03/2025 utilities for 917 3rd Street -288.21 Bill Pmt -Check 10/24/2025 21643 Premier Financial Group, Inc. Advisory Fee for Q4 2025 -7,119.85 Bill Pmt -Check 10/24/2025 21644 Ramirez, M. Per Diem Meals: Customer Connections Conf. -218.00 Bill Pmt -Check 10/24/2025 21645 Rise Energy Electrical maintenance of RCAM site -1,875.00 Bill Pmt -Check 10/24/2025 21646 Rodriguez, Louis Mileage reimbursement - Sept 2025 -53.20 Bill Pmt -Check 10/24/2025 21647 St. Joseph Hospital, Eureka Site Host Reimbursement 07/01-09/30/2025 -6,293.36 Bill Pmt -Check 10/24/2025 21648 Terry, P. Per Diem Meals: CalREN In-Person Mtg -227.00 Bill Pmt -Check 10/24/2025 21649 Times Printing Company Oct. 2025 CCE Customer mailers -3,111.29 Bill Pmt -Check 10/24/2025 21650 Westside Community Improvement Assn. Venue Rental: 9/9/25 CAC mtgs -225.00 Bill Pmt -Check 10/24/2025 21651 Wex Health, Inc Monthly COBRA Payment -23.88 Bill Pmt -Check 10/24/2025 21652 John Winzler Office Lease - 633 3rd St. -8,144.97 Check 10/24/2025 21653 NREN Customer NREN Equip Rebate -Res 250825-3039 -350.00 Check 10/24/2025 21654 NREN Customer NREN Equip Rebate -Res 2250818-3003 -600.00 Check 10/24/2025 21655 NREN Customer NREN Equip Rebate -Res 250930-3178 -100.00 Check 10/24/2025 21656 NREN Customer NREN Equip Rebate -Res 250912-3096 -50.00 Check 10/24/2025 21657 NREN Customer NREN Equip Rebate -Res 251016-3243 -450.00 Check 10/24/2025 21658 NREN Customer NREN Equip Rebate -Res 250911-3094 -400.00 Check 10/24/2025 21659 NREN Customer NREN Equip Rebate -Res 250902-3059 -250.00 Check 10/24/2025 21660 NREN Customer NREN Equip Rebate -Res 251007-3208 -100.00 Check 10/24/2025 21661 NREN Customer NREN Heat Pump Rebate -Res 250930-3176 -576.00 Check 10/24/2025 21662 NREN Customer NREN Heat Pump Rebate -Res 250908-3069 -800.00 Check 10/24/2025 21663 CCE Customer CCE EV Rebate- EV75 -2,000.00 Check 10/24/2025 21664 CCE Customer CCE EV Rebate- EV74 -2,000.00 Check 10/24/2025 21665 CCE Customer CCE EV Rebate- EV71 -2,000.00 Check 10/24/2025 21666 NEM Customer NEM Transistional Payout 2025 -429.52 Check 10/24/2025 21667 NEM Customer NEM Transistional Payout 2025 -299.78 Check 10/24/2025 21668-707 NEM Customers NEM Cash Outs 2025 -14,809.27 Paycheck 10/24/2025 ACH Employees Payroll -94,034.99
Bill Pmt -Check 10/27/2025 ACH CA Dept. of Tax & Fee Administration Electrical Energy Surcharge Return Q3 2025 -37,081.00 Liability Check 10/31/2025 ACH Colonial Life Oct 2025 Premums -3,134.52 TOTAL -3,689,788.54
20 Redwood Coast Energy Authority
Profit & Loss Budget vs. Actual
July through October 2025
Jul - Oct 25 Budget % of Budget
Ordinary Income/Expense
Income
5 REVENUE EARNED
Total 5000 · Revenue - government agencies 4,481,233.17 11,331,517.00 39.55% Total 5100 · Revenue - program related 451,666.48 77,000.00 586.58% Total 5300 · Revenue - Interest Earned 403,299.56
Total 5400 · Revenue-nongovernment agencies 177,551.39 296,090.00 59.97% Total 5500 · Revenue - Electricity Sales 24,509,841.25 71,539,945.00 34.26% Total 5 REVENUE EARNED 30,023,591.85 83,244,552.00 36.07% Total Income 30,023,591.85 83,244,552.00 36.07%
Gross Profit 30,023,591.85 83,244,552.00 36.07%
Expense
Total 6 WHOLESALE POWER SUPPLY 14,751,388.99 57,617,586.00 25.6% Total 7 PERSONNEL EXPENSES 1,617,781.85 6,404,096.00 25.26% Total 8.1 FACILITIES AND OPERATIONS 585,729.50 2,171,607.00 26.97% Total 8.2 COMMUNICATIONS AND OUTREACH 102,662.10 363,250.00 28.26%
8.4 PROFESSIONAL & PROGRAM SRVS
8400 · Regulatory 57,950.14 150,000.00 38.63%
Total 8410 · Contracts - Program Related Ser 2,563,449.53 3,610,716.00 71.0% 8420 · Accounting 106,083.36 228,000.00 46.53%
8430 · Legal 120,336.37 249,000.00 48.33%
8450 · Wholesale Services - TEA 307,951.44 896,946.00 34.33% 8460 · Procurement Credit - TEA 45,391.43 572,390.00 7.93% 8470 · Data Management - Calpine 272,998.21 808,002.00 33.79% 8480 · Customer Billing - PG&E 87,466.05 256,634.00 34.08% Total 8.4 PROFESSIONAL & PROGRAM SRVS 3,561,626.53 6,771,688.00 52.6% Total 8.6 INCENTIVES & REBATES 120,205.45 1,622,655.00 7.41% Total 9 NON OPERATING COSTS 27,088.52 129,200.00 20.97% Total Expense 20,766,482.94 75,080,082.00 27.66%
Net Ordinary Income 9,257,108.91 8,164,470.00 113.38%
Net Income 9,257,108.91 8,164,470.00 113.38%
21 Redwood Coast Energy Authority
Balance Sheet
As of October 31, 2025
Oct 31, 25
ASSETS
Current Assets
Checking/Savings
1010 · Petty Cash 300.00
1060 · Umpqua Checking Acct 0560 14,009.85
1071 · Umpqua Deposit Cntrol Acct 8215 5,325,099.20
1075 · Umpqua Reserve Account 2300 25,071,464.55
1077 · JP Morgan Chase Act 74999 399,967.48
1078 · CA CLASS Reserve Fund 0001 13,150,319.14
Total Checking/Savings 43,961,160.22
Total Accounts Receivable 2,749,690.21
Other Current Assets
1101 · Allowance for Doubtful Accounts -9,001,745.57
1103 · Electricity Receivable 18,111,793.85
1120 · Inventory Asset 21,822.24
1205 · Prepaid Insurance 6,007.82
1210 · Retentions Receivable 80,090.51
Total Other Current Assets 9,217,968.85
Total Current Assets 55,928,819.28
Total Fixed Assets 10,530,172.03
Total Other Assets 795,144.36
TOTAL ASSETS 67,254,135.67
LIABILITIES & EQUITY
Liabilities
Current Liabilities
Total Accounts Payable 5,743,892.53
Credit Cards
Total 2009 · Umpqua CC BL Acct 1901 13,030.68
Total Credit Cards 13,030.68
Other Current Liabilities
2002 · Deposits Refundable 1,049,170.01
2011 · NEM Escrow Liability 416,197.33
2013 · Unearned Revenue 5,030,325.63
Total 2100 · Payroll Liabilities 208,800.82
Total 2200 · Accrued Expenses 13,156.59
Total Other Current Liabilities 6,717,650.38
Total Current Liabilities 12,474,573.59
Total Long Term Liabilities 5,792,647.80
Total Liabilities 18,267,221.39
Equity
3900 · Fund Balance 39,729,805.37
Net Income 9,257,108.91
Total Equity 48,986,914.28
TOTAL LIABILITIES & EQUITY 67,254,135.67
22 Accrual Basis Redwood Coast Energy Authority
Disbursements Report
As of November 30, 2025
Type Date Num Name Memo Amount
Bill Pmt -Check 11/03/2025 ACH The Energy Authority CISO102925-OCT25 -33,429.38 Bill Pmt -Check 11/05/2025 WIRE PG&E Voluntary Allocation June 2025 Forecast Price- VA -151,242.52 Liability Check 11/07/2025 ACH Ascensus 11/07/2025 Payroll -14,814.89 Liability Check 11/07/2025 ACH Ascensus 11/07/2025 Payroll -13,183.70 Liability Check 11/07/2025 ACH EDD 11/07/2025 Payroll -8,957.57 Liability Check 11/07/2025 ACH Internal Revenue Service 11/07/2025 Payroll -38,716.53 Bill Pmt -Check 11/07/2025 ACH PG&E-Office Utility 09/13-10/11/2025 utilities for 633 3rd Street -1,058.23 Bill Pmt -Check 11/07/2025 ACH Sol Systems LLC CA PCC3 2025-Qty 80,000 -700,000.00 Bill Pmt -Check 11/07/2025 ACH Sonoma Clean Power Authority Oct 2025 - Flex RA -261,000.00 Bill Pmt -Check 11/07/2025 ACH Valley Clean Energy Alliance MTR RA Swap Oct 2025 -24,991.00 Bill Pmt -Check 11/07/2025 ACH Viridity Energy Solutions, Inc. Tierra Buena RA - Oct 2025 -16,224.00 Bill Pmt -Check 11/07/2025 WIRE PG&E Voluntary Allocation July 2025 Forecast Price- VA -157,867.84 Bill Pmt -Check 11/07/2025 WIRE Sierra Business Council NREN Q3 & Q4 2025 payment -649,662.17 Check 11/07/2025 21708 CCE Customer Rebate CCE EV- EV82 -2,000.00 Check 11/07/2025 21709 CCE Customer Rebate CCE EV- EV53 -2,000.00 Check 11/07/2025 21710 CCE Customer Rebate CCE EV- EV81 -2,000.00 Check 11/07/2025 21711 CCE Customer Rebate CCE EV- EV77 -2,000.00 Check 11/07/2025 21712 CCE Customer VOID: Rebate CCE EV- EV78 0.00 Check 11/07/2025 21713 CCE Customer Rebate CCE EV- EV69 -2,000.00 Check 11/07/2025 21714 NREN Customer Rebate NREN Equip Res x 2 -450.00 Check 11/07/2025 21715 NREN Customer Rebate NREN Equip Res -100.00 Check 11/07/2025 21716 NREN Customer Rebate NREN Equip Res -550.00 Check 11/07/2025 21717 NREN Customer Rebate NREN Equip Res -250.00 Check 11/07/2025 21718 NREN Customer Rebate NREN Equip Res -350.00 Check 11/07/2025 21719 NREN Customer Rebate NREN Equip Res -400.00 Check 11/07/2025 21720 NREN Customer Rebate NREN Equip Res -400.00 Check 11/07/2025 21721 NREN Customer Rebate NREN Equip Res -450.00 Check 11/07/2025 21722 NREN Customer Rebate NREN Equip Res -150.00 Check 11/07/2025 21723 NREN Customer Rebate NREN Equip Res -50.00 Check 11/07/2025 21724 NREN Customer Rebate NREN Equip Res -450.00 Bill Pmt -Check 11/07/2025 21725 American Public Power Association CCA Associate Membership 12/9/25-12/8/26 -1,625.00 Bill Pmt -Check 11/07/2025 21726 Ascensus 07/01/2024-09/30/2025 Recordkeeping Fee -1,139.50 Bill Pmt -Check 11/07/2025 21727 Braun Blaising & Wynne, P.C. Regulatory and Legal Services -Sept 2025 -7,724.82 Bill Pmt -Check 11/07/2025 21728 City of Arcata Sept 2025 Excessive Electricity Use Tax -1,271.18 Bill Pmt -Check 11/07/2025 21729 CPH Sponsored Programs Foundation Sept 2025 RCAM Task Orders -8,708.00 Bill Pmt -Check 11/07/2025 21730 Adventures Edge Oct 2025 E-Bike Vouchers -1,200.00 Bill Pmt -Check 11/07/2025 21731 AT&T RCAM Router 09/19-10/18/25 -163.00 Bill Pmt -Check 11/07/2025 21732 Burks, E. VOID: CA Planning Per Diem & NREN Mtg Reimb. 0.00 Bill Pmt -Check 11/07/2025 21733 Busick, B. Oct 2025 Mileage Reimb -261.31 Bill Pmt -Check 11/07/2025 21734 Chargepoint Qty 32, Commercial cloud plans- 11/2027 -21,920.00 Bill Pmt -Check 11/07/2025 21735 City of Arcata Sept 2025 Utility User Tax -15,470.45 Bill Pmt -Check 11/07/2025 21736 City of Eureka - Wharfinger&NEM Venue Rental: staff mtg 12/04/2025 -370.00 Bill Pmt -Check 11/07/2025 21737 Donald Dame CCE Consulting services- Oct 2025 -218.75 Bill Pmt -Check 11/07/2025 21738 Donnelly, S. Reimbursement NREN Mtg Truckee -241.06 Bill Pmt -Check 11/07/2025 21739 EAN Services, LLC Car rental- various -498.39 Bill Pmt -Check 11/07/2025 21740 Engel, R. Reimbursement- Fuel: CC Power Forum -111.01 Bill Pmt -Check 11/07/2025 21741 Frontier Energy, Inc. Sept 2025 NREN Admin Services -28,508.25 Bill Pmt -Check 11/07/2025 21742 Gwynn, J. Per Diem Meals: CalCCA Procurement Mtg -161.00
23 Accrual Basis Redwood Coast Energy Authority
Disbursements Report
As of November 30, 2025
Type Date Num Name Memo Amount
Bill Pmt -Check 11/07/2025 21743 Humboldt Fence Co. Gate repair- RCAM Baasgaard Ave -885.00 Bill Pmt -Check 11/07/2025 21744 iPROMOTEu.com, Inc Oct 2025 Marketing Materials -1,218.60 Bill Pmt -Check 11/07/2025 21745 Kilowatt Engineering, Inc. NMEC Program Support Services -Sept 2025 -2,230.00 Bill Pmt -Check 11/07/2025 21746 Kullmann, S. Mileage Reimbursement: NREN Mtg Truckee -136.08 Bill Pmt -Check 11/07/2025 21747 NewGen Strategies and Solutions, LLC Cost of Service & Rate Design thru 10/15/25 -13,255.00 Bill Pmt -Check 11/07/2025 21748 Newport Group Participant Fees Deferred Comp 10/01/25-12/31/25 -1,105.42 Bill Pmt -Check 11/07/2025 21749 North Coast Cleaning Services, Inc. Oct 2025 Office Janitorial Services -1,090.00 Bill Pmt -Check 11/07/2025 21750 NYLEX.net, Inc. HPE Networking Instant On Switch & Labor -2,956.65 Bill Pmt -Check 11/07/2025 21751 ReconMR RCEA Brand Awareness Research Services -25,000.00 Bill Pmt -Check 11/07/2025 21752 Revolution Bicycles, Inc. Oct 2025 E-Bike Vouchers -800.00 Bill Pmt -Check 11/07/2025 21753 Rodriguez, Louis Mileage reimbursement - Oct 2025 -40.60 Bill Pmt -Check 11/07/2025 21754 Stephens Electrical, Inc Sept & Oct 2025 RRGP Design-Build Svcs -104,500.00 Bill Pmt -Check 11/07/2025 21755 Taketa, L. Reimbursment - various- L. Taketa -52.77 Bill Pmt -Check 11/07/2025 21756 TELUS Health (US) Ltd. Cust #: 420995 Contract #: 420995-C-421011 -2,324.56 Bill Pmt -Check 11/07/2025 21757 Terry, P. Reimbursement: Lodging CalREN In-Person Mtg -520.25 Bill Pmt -Check 11/07/2025 21758 Wired Impact, LLC Amplify Plan for 12 months -3,948.00 Bill Pmt -Check 11/07/2025 21759 Woodley Island Ship Shop Oct 2025 E-Bike vouchers -1,350.00 Bill Pmt -Check 11/07/2025 21760 Yakovleva, Vera A. Per Diem- CalCCA Procurement Mtg -161.00 Bill Pmt -Check 11/07/2025 21761 AM Conservation Group, Inc. Drop-ship RES kits for NREN -6,759.50 Bill Pmt -Check 11/07/2025 21762 Burks, E. Reimbursement: Lodging CC PowerForum -596.64 Check 11/07/2025 21763 CCE Customer Rebate CCE EV- EV78 -2,000.00 Paycheck 11/07/2025 ACH Employees Payroll -93,471.28
Bill Pmt -Check 11/10/2025 ACH The Energy Authority CISO110525 -57,661.08 Bill Pmt -Check 11/12/2025 21764 Fidelity National Title Initial Deposit 718 Third St. Eureka, CA 95501 -38,000.00 Bill Pmt -Check 11/17/2025 ACH The Energy Authority CISO111225-OCT25 -63,751.83 Bill Pmt -Check 11/17/2025 ACH The Energy Authority Monthly TEA Invoice #TEA102025 Oct 2025 -2,304,274.97 Check 11/17/2025 ACH VISA- Commercial Card Statement Date 10/30/25 BL Acct 1901 -13,030.68 Bill Pmt -Check 11/19/2025 21765 RDS Solar Pumps Final pmt 6 Sun Titan L-30 Power Trailers -150,816.96 Check 11/20/2025 Debit Columbia Bank Service Charge -168.27 Check 11/20/2025 Debit Columbia Bank Service Charge -278.30 Liability Check 11/21/2025 ACH Ascensus 11/21/25 Payroll -14,787.12 Liability Check 11/21/2025 ACH CICCS Coalition for Controlling Insurance Dec 2025 Premiums -66.98 Liability Check 11/21/2025 ACH EDD 11/21/25 Payroll -8,685.02 Liability Check 11/21/2025 ACH Internal Revenue Service 11/21/25 Payroll -38,372.31 Liability Check 11/21/2025 ACH Keenan December 2025 Premiums -50,033.79 Liability Check 11/21/2025 ACH Principal Life Insurance Company 11/21/25 Payroll -129.88 Liability Check 11/21/2025 ACH Ascensus 11/21/25 Payroll -16,113.79 Bill Pmt -Check 11/21/2025 ACH CalPine Corporation Oct 2025 Data Management Costs -68,316.52 Bill Pmt -Check 11/21/2025 ACH EDPR CA Solar Park LLC II Oct 2025-Contract Energy -707,941.93 Bill Pmt -Check 11/21/2025 ACH Humboldt Sawmill Co. Oct 2025 Electricity Generation -602,335.36 Bill Pmt -Check 11/21/2025 ACH Leapfrog Power, Inc Oct 2025 RA Invoice -36,740.00 Liability Check 11/21/2025 ACH Colonial Life Nov 2025 Premiums -3,268.60 Liability Check 11/21/2025 21766 Ameritas Life Insurance Corp. - Dental December 2025 Premiums -2,878.04 Liability Check 11/21/2025 21767 Ameritas Life Insurance Corp.- Vision December 2025 Premiums -511.92 Check 11/21/2025 21768-89 NEM Customers NEM Closeout 2025 -5,609.54 Check 11/21/2025 21790 NEM Customer VOID: NEM Closeout 2025 0.00 Check 11/21/2025 21791 NEM Customer NEM Closeout 2025 -321.28 Check 11/21/2025 21792 CCE Customer CCE EV Rebate: EV69 -2,000.00
24 Accrual Basis Redwood Coast Energy Authority
Disbursements Report
As of November 30, 2025
Type Date Num Name Memo Amount
Check 11/21/2025 21793 CCE Customer CCE EV Rebate: EV83 -2,000.00 Check 11/21/2025 21794 CCE Customer CCE EV Rebate: EV72 -2,000.00 Check 11/21/2025 21795 CCE Customer CCE EV Rebate: EV76 -2,000.00 Check 11/21/2025 21796 CCE Customer CCE EV Rebate: EV80 -2,000.00 Check 11/21/2025 21797 NREN Customer Rebate NREN Equipment Res -100.00 Check 11/21/2025 21798 NREN Customer Rebate NREN Equipment Res -150.00 Check 11/21/2025 21799 NREN Customer Rebate NREN Equipment Res -450.00 Check 11/21/2025 21800 NREN Customer Rebate NREN Equipment Res -100.00 Check 11/21/2025 21801 NREN Customer Rebate NREN Equipment Res -150.00 Check 11/21/2025 21802 NREN Customer Rebate NREN Equipment Res -250.00 Check 11/21/2025 21803 NREN Customer Rebate NREN Equipment Res -450.00 Check 11/21/2025 21804 NREN Customer Rebate NREN Equipment Res -450.00 Check 11/21/2025 21805 NREN Customer Rebate NREN Equipment Res -100.00 Check 11/21/2025 21806 NREN Customer Rebate NREN Equipment Res -500.00 Check 11/21/2025 21807 NREN Customer Rebate NREN Equipment Res -50.00 Check 11/21/2025 21808 NREN Customer Rebate NREN Equipment Res -250.00 Check 11/21/2025 21809 NEM Customer NEM Closeout 2025 -204.91 Bill Pmt -Check 11/21/2025 21810 Adventures Edge Nov 2025 E-Bike rebate Invoices -2,000.00 Bill Pmt -Check 11/21/2025 21811 AM Conservation Group, Inc. Nov 2025 RES Kits -1,673.51 Bill Pmt -Check 11/21/2025 21812 Amazon.com Monthly billing - Nov 2025 -928.63 Bill Pmt -Check 11/21/2025 21813 AT&T RCAM Internet/Data charges -991.96 Bill Pmt -Check 11/21/2025 21814 AT&T Long Distance Phone charges 10/25 - 11/24/2025 -111.85 Bill Pmt -Check 11/21/2025 21815 Atkins Drafting Proposed Office Design & Construction Asst. -2,920.00 Bill Pmt -Check 11/21/2025 21816 Bidwell Consulting Services, Inc. Annual administration for 2025 -1,000.00 Bill Pmt -Check 11/21/2025 21817 Bohn, Juliette Oct 2025 Mileage -54.88 Bill Pmt -Check 11/21/2025 21818 Carter Properties 917 3rd Street Office Lease - Dec 2025 -2,450.00 Bill Pmt -Check 11/21/2025 21819 City of Arcata VOID: August 2025 0.00 Bill Pmt -Check 11/21/2025 21820 City of Eureka-Other BCL Training: Biondini, Burks, Verbeck -4,200.00 Bill Pmt -Check 11/21/2025 21821 City of Eureka-Water 917 & 633 3rd. St. 09/28/25-10/26/25 -473.16 Bill Pmt -Check 11/21/2025 21822 Dell USA Office Supplies -2,373.25 Bill Pmt -Check 11/21/2025 21823 Developed Employment Services, LLC. 805 3rd St. Yard work -83.18 Bill Pmt -Check 11/21/2025 21824 Energy Resources Integration, LLC NREN Commercial Needs Assess -41,723.50 Bill Pmt -Check 11/21/2025 21825 Humboldt Bay Coffee Co. Office Coffee- 633 3rd St. -59.10 Bill Pmt -Check 11/21/2025 21826 Humboldt HyCycle Nov 2025: 4 E-Bike Vouchers -1,800.00 Bill Pmt -Check 11/21/2025 21827 Kilowatt Engineering, Inc. NMEC Program Support Services Oct 2025 -5,457.50 Bill Pmt -Check 11/21/2025 21828 Kullmann, S. Purchase Reimbursement -84.79 Bill Pmt -Check 11/21/2025 21829 Lake County/City Area Planning Council NREN Advanced Payment: Task Orders 1-7 -153,030.86 Bill Pmt -Check 11/21/2025 21830 Law Offices of Nancy Diamond Oct 2025 Legal Services -13,974.25 Bill Pmt -Check 11/21/2025 21831 Mission Linen & Uniform Service Nov 2025 Office Janitorial Services -238.18 Bill Pmt -Check 11/21/2025 21832 NYLEX.net, Inc. Onsite network support - Dec 2025 -4,909.00 Bill Pmt -Check 11/21/2025 21833 Optimum Business-633 633 3rd St: Phone & Internet 11/1/25-11/30/25 -1,210.41 Bill Pmt -Check 11/21/2025 21834 Pacific Paper Company Office supplies -52.91 Bill Pmt -Check 11/21/2025 21835 PG&E- EV Oct 2025 EV Usage -2,009.38 Bill Pmt -Check 11/21/2025 21836 PG&E-Office Utility 10/05-11/03/2025 utilities for 917 3rd Street -469.59 Bill Pmt -Check 11/21/2025 21837 PG&E - ACV- 6674-0 ACV site utilities 09/01/25- 10/31/25 -584.50 Bill Pmt -Check 11/21/2025 21838 PG&E CCA Sept 2025 CCE Charges -21,828.87 Bill Pmt -Check 11/21/2025 21839 Ramirez, M. Reimbursement: Customer Connections Conf. -53.46 Bill Pmt -Check 11/21/2025 21840 Reider, S Mileage Reimbursement-Nov 2025 -19.74
25 Accrual Basis Redwood Coast Energy Authority
Disbursements Report
As of November 30, 2025
Type Date Num Name Memo Amount
Bill Pmt -Check 11/21/2025 21841 Sharepoint Maven, Inc. Sharepoint Config. Phase 1 50% final payment -2,800.00 Bill Pmt -Check 11/21/2025 21842 Times Printing Company Nov 2025 CCE Customer mailers -1,314.68 Bill Pmt -Check 11/21/2025 21843 Ubeo Business Services 633+ 917 3rd St Printer Charges: 10/06-11/05/25 -329.27 Bill Pmt -Check 11/21/2025 21844 USDN LGSEC Membership 11/1/25-10/31/26 -3,090.00 Bill Pmt -Check 11/21/2025 21845 Wex Health, Inc Monthly COBRA Payment -23.88 Bill Pmt -Check 11/21/2025 21846 John Winzler Office Lease - 633 3rd St. -8,144.97 Bill Pmt -Check 11/21/2025 21847 City of Arcata Aug 2025 Utility User Tax -14,320.39 Bill Pmt -Check 11/21/2025 21848 City of Arcata Aug 2025 Excessive Electricity Use Tax -1,020.72 Paycheck 11/21/2025 ACH Employees Payroll -91,693.00
Bill Pmt -Check 11/24/2025 ACH The Energy Authority CISO111925 -3,994.83 TOTAL -7,029,538.18
26 Redwood Coast Energy Authority
Profit & Loss Budget vs. Actual
July through November 2025
Jul - Nov 25 Budget % of Budget
Ordinary Income/Expense
Income
5 REVENUE EARNED
Total 5000 · Revenue - government agencies 4,481,233.17 11,331,517.00 39.55% Total 5100 · Revenue - program related 460,899.17 77,000.00 598.57% Total 5300 · Revenue - Interest Earned 515,236.74
Total 5400 · Revenue-nongovernment agencies 230,193.89 296,090.00 77.75% Total 5500 · Revenue - Electricity Sales 29,737,667.05 71,539,945.00 41.57% Total 5 REVENUE EARNED 35,425,230.02 83,244,552.00 42.56% Total Income 35,425,230.02 83,244,552.00 42.56%
Gross Profit 35,425,230.02 83,244,552.00 42.56%
Expense
Total 6 WHOLESALE POWER SUPPLY 19,540,598.57 57,617,586.00 33.91% Total 7 PERSONNEL EXPENSES 2,031,106.00 6,404,096.00 31.72% Total 8.1 FACILITIES AND OPERATIONS 648,756.96 2,171,607.00 29.88% Total 8.2 COMMUNICATIONS AND OUTREACH 140,576.16 363,250.00 38.7%
8.4 PROFESSIONAL & PROGRAM SRVS
8400 · Regulatory 58,805.14 150,000.00 39.2%
Total 8410 · Contracts - Program Related Ser 2,991,459.08 3,610,716.00 82.85% 8420 · Accounting 114,037.11 228,000.00 50.02%
8430 · Legal 128,631.26 249,000.00 51.66%
8450 · Wholesale Services - TEA 429,555.29 896,946.00 47.89% 8460 · Procurement Credit - TEA 55,357.64 572,390.00 9.67% 8470 · Data Management - Calpine 341,143.59 808,002.00 42.22% 8480 · Customer Billing - PG&E 109,290.16 256,634.00 42.59% Total 8.4 PROFESSIONAL & PROGRAM SRVS 4,228,279.27 6,771,688.00 62.44% Total 8.6 INCENTIVES & REBATES 155,487.53 1,622,655.00 9.58% Total 9 NON OPERATING COSTS 27,535.09 129,200.00 21.31% Total Expense 26,772,339.58 75,080,082.00 35.66%
Net Ordinary Income 8,652,890.44 8,164,470.00 105.98%
Net Income 8,652,890.44 8,164,470.00 105.98%
27 Redwood Coast Energy Authority
Balance Sheet
As of November 30, 2025
Nov 30, 25
ASSETS
Current Assets
Checking/Savings
1010 · Petty Cash 300.00
1060 · Umpqua Checking Acct 0560 1,827,084.33
1071 · Umpqua Deposit Cntrol Acct 8215 3,100,899.77
1075 · Umpqua Reserve Account 2300 26,068,168.65
1077 · JP Morgan Chase Act 74999 386,207.84
1078 · CA CLASS Reserve Fund 0001 13,193,965.58
Total Checking/Savings 44,576,626.17
Total Accounts Receivable 208,403.27
Other Current Assets
1101 · Allowance for Doubtful Accounts -9,054,791.85
1103 · Electricity Receivable 18,651,764.50
1120 · Inventory Asset 21,822.24
1205 · Prepaid Insurance 4,301.31
1210 · Retentions Receivable 80,090.51
Total Other Current Assets 9,703,186.71
Total Current Assets 54,488,216.15
Total Fixed Assets 10,592,590.63
Total Other Assets 795,217.98
TOTAL ASSETS 65,876,024.76
LIABILITIES & EQUITY
Liabilities
Current Liabilities
Total Accounts Payable 4,963,773.02
Total Credit Cards 13,854.69
Other Current Liabilities
2002 · Deposits Refundable 1,049,170.01
2011 · NEM Escrow Liability 410,061.60
2013 · Unearned Revenue 5,030,325.63
Total 2100 · Payroll Liabilities 208,800.82
Total 2200 · Accrued Expenses 24,695.38
Total Other Current Liabilities 6,723,053.44
Total Current Liabilities 11,700,681.15
Total Long Term Liabilities 5,792,647.80
Total Liabilities 17,493,328.95
Equity
3900 · Fund Balance 39,729,805.37
Net Income 8,652,890.44
Total Equity 48,382,695.81
TOTAL LIABILITIES & EQUITY 65,876,024.76
28
Staff Report
Agenda Item # 5.3
Information
Agenda Date January 22, 2026
To RCEA Board of Directors
Prepared by Kyle Groben, Regulatory and Legislative Policy Intern Subject Federal Activity Update
Summary
After considering several options for effective federal level engagement, RCEA recently became a member of Local Energy Aggregation Network (LEAN Energy). LEAN is a non-profit organization founded in 2011 that focuses on the success and advancement of CCA programs across the nation through support, resources, and expertise. Their core services consist of outreach, CCA market analysis, regulatory and legislative affairs, federal engagement, and market development.
RCEA staff are using LEAN’s CCA Monthly Federal Report to prepare Federal Activity Updates beginning with this month’s update. LEAN’s monthly reports increase staff capacity and reduce redundant work across CCAs.
The attached report covers the calendar month of December, rather than the period between Board meetings like past staff-generated reports. The report has been edited slightly by staff to remove any information that is now out-of-date and to include summaries of LEAN filings.
Alignment with RCEA’s Strategic Plan
Staff will continue to track Federal actions and identify those that may impact RCEA’s ability to deliver on the goals and strategies in the RCEA strategic plan.
Financial Impact
LEAN Annual Membership is $15,000. Additional options to enhance federal engagement were assessed and LEAN was determined to be the most fiscally prudent of all options.
Staff Recommendation
Receive federal activity report.
Attachments
LEAN CCA Monthly Federal Report
29
Agenda Item # 5.3 – Attachment 1
Summary
Congress spent the first three weeks of December engaged in a full legislative schedule with several developments relevant to Community Choice Aggregators (CCAs). The House held two weeks of floor action on permitting reform, where they passed measures that could directly impact permitting timeline certainty for energy infrastructure projects from which CCAs procure power: the SPEED Act, ePermit Act, and PERMIT Act.
The Senate had worked towards a five bill “minibus” containing funding for Defense, Labor, Commerce, Interior, Transportation, and associated agencies, but failed to bring it up for a vote before the holiday recess, leaving the funding levels unresolved. Congress returned in January with just one month before the Jan. 30 deadline to fund the government, including key energy efficiency programs of interest to CCAs. Funding was passed January 15.
The Administration took significant action against wind power by pausing permits for five different east coast offshore wind projects, creating potential uncertainty for power procurement and long-term resource planning for CCAs. The Department of Health and Human Services also released LIHEAP funds that had been delayed due to the government shutdown, providing critical support for customer affordability programs that many CCA communities rely on to serve vulnerable populations. Beyond this, FERC issued their first orders on co-location of large loads, a growing issue with implications for grid reliability, resource adequacy, and energy affordability relevant to CCAs.
LEAN Federal Advocacy Highlights
On Dec. 5, LEAN filed reply comments to the Federal Energy Regulatory Commission’s proceeding on Interconnection of Large Loads to the Interstate Transmission System. LEAN’s comments explain what CCAs are and express CCA’s interest in the proceeding, and stating that a beneficial approach that carefully considers the appropriate role of federal standards could result in data centers reducing system costs, adding flexibility and capacity, and enhancing the overall grid, while missing the full scope of this opportunity could result in additional grid strain, increasing costs, and reliability impacts.
On Dec. 19, LEAN filed comments to the Sustainable Energy and Environment Coalition (SEEC) Thriving Economy Project Request for Information (RFI). LEAN’s response outlines the barriers to delivering reliable, clean, and affordable energy, priority areas for Congress to accelerate grid modernization, ways for communities to play a larger role in energy development, and ways to improve energy financing.
Congressional Actions
House Passes the SPEED Act After Late Changes
On Dec. 18, the House passed the “Standardizing Permitting and Expediting Economic Development (SPEED) Act” (H.R. 4776) by a vote of 221-196, with 11 Democrats joining nearly all Republicans in voting for the bill. The bipartisan vote came after changes were made to the bill’s permit certainty language, following objections raised by Freedom Caucus Members. House GOP leaders altered the procedural rule to uphold project cancellations made during the Trump administration—an amendment that had been expected to fail on the floor. The House Rules Committee had originally provided for votes on three amendments to the bill which would a) remove the compromise “permitting certainty” language that restricts the president from revoking approved permits from energy 30
projects, b) exempt offshore wind from the expedited permitting process outlined in the bill, and c) exempt projects the government has already paused or remanded from the benefits of the bill, all of which were rejected during the floor vote.
Additional Permitting Reform Bills Pass the House
The House considered several additional permitting reform bills in December. On Dec. 9, the House approved the “ePermit Act” (H.R. 4503) and the “Studying NEPA’s Impact on Projects Act” (H.R. 573).
H.R. 4503 creates requirements for digitizing environmental reviews conducted under the National Environmental Policy Act (NEPA) in order to reduce the processing time for federal permitting. H.R. 573 would require the White House Council on Environmental Quality to publish an annual report outlining NEPA project litigation, as well as its impact on the paperwork burden and wait times for infrastructure projects. Another bill, the “Promoting Efficient Review for Modern Infrastructure Today (PERMIT) Act” (H.R. 3898) was approved on Dec. 11. This bill eases permitting under the Clean Water Act by limiting state authority to block projects, would add limits for environmental lawsuits and would restrict the Environmental Protection Agency's ability to veto Army Corps of Engineers permits.
House Passes Power Plant Reliability Act
On Dec. 16, the House passed the “Power Plant Reliability Act” (H.R. 3632), which aims to keep coal-fired power plants running past their scheduled retirement date. The bill, sponsored by Rep. Morgan Griffith (R-VA), would grant the Federal Energy Regulatory Commission (FERC) authority to require utilities to keep coal-fired power plants operating for up to ten years past their retirement date and exempt them from environmental regulations if their retirement poses a threat to grid reliability. H.R. 3632 would also require utilities to provide at least 5 years’ notice to FERC before retiring a power plant. The bill passed the House 222-202, with some moderate Democrats joining Republicans.
Permitting Reform Stalled in the Senate
Permitting reform talks have stalled in the Senate following President Trump’s pause on wind projects currently under construction, leaving the future of comprehensive permitting reform uncertain as Congress returns in 2026. Sens. Sheldon Whitehouse (D-RI) and Martin Heinrich (D-NM), ranking members of the Environment and Public Works Committee and Energy and Natural Resources Committees, respectively, released a joint statement saying the “attacks on renewable energy projects must stop” if bipartisan talks on permitting reform are to continue. This follows reports from early December that indicated bipartisan permitting reform negotiations led by Senate Environment and Public Works (EPW) Committee Chairwoman Shelley Moore Capito (R-WV) and Ranking Member Sheldon Whitehouse (D-RI), had slowed due to disagreements over transmission language, among other things.
Administrative Actions
LIHEAP Funding Released
The Department of Health and Human Services (HHS) released funding for the Low Income Home Energy Assistance Program (LIHEAP) on Nov. 28. LIHEAP, which provides low-income and senior households with financial assistance for paying energy bills, saw $3.7 billion released, representing about 90% of last year’s total LIHEAP funding for the period through Jan. 20. Both House and Senate FY26 proposals would provide more than $4 billion. Although HHS has released the funds, states must have their plan approved before they receive funds. According to a spokesperson at HHS, funds are 31
expected to be available shortly after they are processed; however, utilities may not be reimbursed for a couple of months.
Trump Signs Executive Order on State AI Laws
On Dec. 11, President Trump signed an executive order aimed at impeding state legislation that regulates artificial intelligence (AI). The order would establish an “AI Litigation Taskforce” in the Justice Department to challenge state AI laws, and it directs Commerce Secretary Howard Lutnick to evaluate state AI laws and specify conditions of funding under the Broadband Equity Access and Deployment program. It also orders David Sacks, Trump’s AI and crypto czar, and Michael Kratsios, the Assistant to the Director of the Office of Science and Technology Policy, to create a legislative recommendation for a uniform federal AI policy that would preempt state laws. The order is likely to be challenged in court.
FERC Issues Co-Location Orders for PJM
On Dec. 18, the Federal Energy Regulatory Commission (FERC) unanimously ordered PJM Interconnection to establish rules facilitating service to large load customers that are co-located with generating facilities. FERC directed PJM to revise its tariff, offering several pathways to safely and reliably co-locate large loads and power generators. One such pathway is to prevent generators from removing power from the grid to supply large load customers, unless the generator and the large load customers finance transmission upgrades that will allow replacement power to be brought from distant sources. The order also describes a pathway for “interim, non-firm transmission service” that would allow a large load to connect to a co-located power plant before reliability upgrades are made, if the large load customer accepts load flexibility terms for when the grid is strained. The order is the first indication of the leanings of new Commissioners on the data center issue and comes as FERC weighs broader principles on large load integration proposed by Energy Secretary Chris Wright.
Trump Administration Pauses Wind Projects
On Dec. 22, the Trump administration ordered a halt to five offshore wind projects currently under construction. The Interior Department stated that the project pauses are necessary due to national security concerns identified by the Department of War in classified reports. This pause applies to the Vineyard Wind 1, Revolution Wind, Coastal Virginia Offshore Wind, Sunrise Wind and Empire Wind 1 projects, which were set to be completed in the next two years. Following the freeze order, Dominion Energy filed a lawsuit asking the federal court to block the Administration order; a hearing on the case has been set for Jan. 16. The developers of Revolution Wind and Empire Wind have since filed a lawsuit to block Administration’s order; however, hearings have not yet been set. 32
Staff Report
Agenda Item #5.4
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Lori Taketa, Clerk of the Board
Subject 2026 Board Meeting Calendar
Summary
In November 2018, the RCEA Board agreed to meet on the fourth Thursday of each month at 3:30 p.m.
The attached proposed 2026 meeting calendar follows this meeting schedule.
The proposed November and December 2026 meetings are on the third Thursday to adjust for holidays.
Staff Recommendation
Approve the 2026 RCEA Board of Directors meeting calendar.
Attachments
1. Proposed 2026 RCEA Board of Directors meeting calendar 33 Redwood Coast Energy Authority
Board of Directors
2026 REGULAR MEETING SCHEDULE
Meetings begin at 3:30 p.m. at the Wharfinger Building downstairs Bay Room, 1 Marina Way, Eureka, CA 95501.
February 26 (4th Thursday)
March 26 (4th Thursday)
April 23 (4th Thursday)
May 28 (4th Thursday)
June 25 (4th Thursday)
July 23 (4th Thursday)
August 27 (4th Thursday)
September 24 (4th Thursday)
October 22 (4th Thursday)
November 19 (3rd Thursday, due to the holiday)
December 17 (3rd Thursday, due to the holiday)
January 28, 2027 (4th Thursday)
RCEA Board of Directors meetings are conducted in-person and online via Zoom pending any declared States of Emergency preventing the safe, in-person meeting of the Board and public. Meeting recordings are also aired on Access Humboldt/Optimum Cable Channel 10 on Saturdays and Sundays at 2 p.m. and archived on Internet Archive, https://archive.org/.
34
Staff Report
Agenda Item # 5.5
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Faith Carlson, Regulatory and Legislative Policy Manager Kyle Groben, Regulatory and Legislative Policy Intern
Subject 2026 Policy Platform Update
Background
On March 24, 2022, the RCEA Board of Directors adopted the RCEA 2022 Policy Platform (Platform), which is brought to the Board periodically (typically annually) for updates. The purpose of the Platform is to deliver on RCEA’s RePower Humboldt goals and maintain the operation of RCEA’s various programs.
The Platform allows RCEA to be nimbler in adopting positions on regulatory and legislative matters in a timely manner without full Board approval if the position is aligned with the Board-approved platform.
This Platform also helps inform RCEA’s regulatory activities to ensure staff engagement aligns with the Board’s priorities and RCEA’s goals.
The 2025 Policy Platform and Draft 2026 Policy Platform support the following overarching policy priorities:
• To maintain local control to preserve the ability to self-procure its power resources, and to self-determine rates and the energy programs RCEA offers to its residents, businesses, and communities it serves, through the mechanisms of local governance; • To restructure the electric utility sector to allow for increased government ownership of energy infrastructure;
• To ensure cost effective reliable energy service and programming; • To support community resilience;
• To increase the utilization of energy resources that mitigate climate change and support climate adaptation plans;
• To support the development of local renewable energy resources; • To provide equitable and just economic, resilience, and climate benefits to the local community; • To maintain an efficient, transparent governance structure and operations that preserve Board approved programs.
Summary
RCEA staff reviewed the 2025 Policy Platform and suggested revisions which are redlined in the attached document.
Below are the substantive changes:
35
Location in
Document
Summary of Change
Throughout document Syntax changes removing Support/Oppose Policy to describe final outcome of policy.
Procedures Combined Regulatory and Legislative procedures into one item. Recent changes to Policy Platform removed requirements for Board approval for Legislative items. Language added related to RCEA’s Racial Justice Plan.
1. Local
Governance
and Statutory
Authority
Addition of language surrounding local resource development.
Consolidated with former Local Economic Development and Environmental Objectives Section.
2. Restructuring
the Electricity
Utility Sector
Combination of item related to agency and IOU collaboration and item related to data access.
3. Reliability Language surrounding outages broadened to cover a broader range of outage types.
4. Community
Resilience
Language surrounding funding for community resilience broadened to cover a larger range of events. Language related to local resource development removed and relocated to section related to Governance and Statutory Authority.
5. Climate Action No Change.
6. Energy
Generation
Sources
Language related to local resource development and CCA procurement removed and relocated to section related to Governance and Statutory Authority. Section related to wind energy moved from former Local Economic Development and Environmental Objectives Section.
7. Environmental
Justice and
Equity
RCEA’s Racial Justice Plan moved to Procedures section. Section related to disaster response removed and added as a subsection to this portion.
8. Programs Bullets slightly rearranged for readability.
Based on feedback from the CAC, staff has included additional changes related to consistency of language around tribal governments, as well as footnotes with additional context for selected items where necessary.
Alignment with RCEA’s Strategic Plan
The Platform was developed to allow RCEA to efficiently engage in regulatory and legislative development that will support RCEA’s ability to implement strategies in RePower Humboldt and achieve the objectives articulated in RCEA’s Mission Statement.
Equity Impacts
The Platform contains a section on “Environmental Justice” which includes “engag[ing] in policy that directly or indirectly impact the ability of rural, low-income, and underserved communities to have affordable, reliable and clean energy.”
This section also includes support for policies that “enable all communities […] to participate in the decarbonization of the state’s electrical grid, building stock, and the transportation sector in a cost-effective manner,” and support “for metrics and cost effectiveness rules that do not create a disadvantage in serving equity customers.”
36
Financial Impact
Budgeted staff time, legal expenses and Cal CCA membership dues.
Staff Recommendation
1. Provide suggestions for this and future Policy Platform updates.
2. Approve 2026 RCEA Policy Platform.
Attachments
1. Redwood Coast Energy Authority Draft 2026 Policy Platform redlined.
2. Redwood Coast Energy Authority Draft 2026 Policy Platform clean 37 1
2026 Policy Platform
REDWOOD COAST ENERGY AUTHORITY
2026 POLICY PLATFORM
INTRODUCTION
Redwood Coast Energy Authority (“RCEA”) is a joint powers authority of the cities of Arcata, Blue Lake, Eureka, Ferndale, Fortuna, Rio Dell, Trinidad, the Yurok Tribe, Blue Lake Rancheria, County of Humboldt, and the Humboldt Bay Municipal Water District. The mission of RCEA is to develop and implement sustainable energy initiatives that reduce energy demand, increase energy efficiency, and advance the use of clean, efficient, and renewable resources available in the region for the benefit of the member agencies and their constituents.
This Policy Platform serves as a guide for regulatory and legislative engagement based on principles set forth in RCEA’s RePower Humboldt 2019 Update
AVENUES AND EXAMPLES OF ADVOCACY
Legislation and regulation are two distinct, but related, policy tools. Legislation sets principles of public policy, while regulation implements these principles and brings legislation into effect.
Examples of RCEA legislative advocacy include submitting letters in support or opposition of specific bills, as well as meeting with legislators in the California State Senate, the California State Assembly, U.S.
House of Representatives, and U.S. Senate.
Most of RCEA’s regulatory engagement takes place through the California Public Utilities Commission, the primary State agency responsible for executing legislation and issuing regulations pertinent to Community Choice Aggregation (“CCA”) and Regional Energy Network (“REN”) operations. However, RCEA’s operations are also impacted by other state and federal agencies including but not limited to the California Energy Commission, the California Independent System Operator, the California Air Resources Board, the California Department of Water Resources, the Federal Energy Regulatory Commission, and the federal Bureau of Ocean Energy Management. Examples of advocacy in this sphere include meeting with agency staff, agency decision-makers, and submitting comments in response to regulations.
PROCEDURES
RCEA regulatory and legislative engagement is conducted at the staff level under the authority of the Executive Director in a manner consistent with RCEA’s mission, this policy platform, RCEA’s strategic plan, RCEA’s Racial Justice Plan, and any applicable RCEA plans and policies.
Issues not addressed in the platform will continue to be brought to the Board on a case-by-case basis. To keep the Board apprised of advocacy activities, staff will notify the full Board of positions taken by RCEA through periodic reports to the Board summarizing policy engagement. This platform will be brought to the RCEA Board on an annual basis for review and input. 38 2
2026 Policy Platform
Policy Priorities
1. Local Governance and Statutory Authority
a. Ensure jurisdictions and tribal governments can form or become members of a CCA or REN. b. Protect local governments and CCA rate-setting, programming, or procurement autonomy. c. Empower CCA and REN ability to effectively and affordably serve their customers. d. Support CCA and REN customer engagement and operational transparency. e. Enable CCAs and RENs to collaborate with their member jurisdictions on local energy resources and projects to advance environmental objectives.
f. Support the development of energy generation projects that align with Board-adopted strategic plan goals and RCEA’s energy risk policy, as long as local development and siting criteria are consistent with city and county land use authority, other local and state regulatory requirements, and informed by input from local communities including but not limited to tribal governments.
2. Restructuring the Electricity Utility Sector
a. Reduce reliance on Investor-Owned Utilities (“IOUs”):
i. Support governments’ ability to fund or own electric infrastructure, including transmission and distribution infrastructure.
ii. Stabilize, remove, or reduce costs associated with leaving IOU service, such as the Power Charge Indifference Adjustment or costs associated with maintaining a Provider of Last Resort.
b. Where IOU service is retained:
i. Reform the utility regulatory and business model to transform IOUs into entities that solely provide transmission and distribution services. ii. Discourage new gas infrastructure and retire or repurpose existing gas infrastructure, while recognizing and addressing social inequities that retirement of such infrastructure may cause.
1 iii. Reform the utility regulatory and business model to ensure IOUs deliver effective service to ratepayers, increase safety and reliability, and reduce costs. iv. Foster greater collaboration and data sharing among CCAs, RENs, tribes, state and local governments, and IOUs, particularly in local planning efforts related to energy resources, load planning, and programs.
c. Oppose direct access electric service expansion.
2 3. Reliability
a. Outage Events
i. Reduce duration and frequency of power outages and improve grid reliability. ii. Increase transparency surrounding outage events.
1 For instance, low income households that utilize gas appliances may be disproportionally disadvantaged by gas infrastructure retirement due to appliance replacement and operating costs. 2 https://www.cpuc.ca.gov/consumer-support/consumer-programs-and-services/electrical-energy-and-energy-efficiency/community-choice-aggregation-and-direct-access-/direct-access 39 3
2026 Policy Platform
iii. Create standards and thresholds for outage events.3
iv. Support equitable treatment of non-utility owned generation during shutoff events and during related island operation of sections of the grid. b. Resource Adequacy (“RA”)
i. Reform the RA program to improve system reliability cost-effectively. ii. Remove barriers to demand response, microgrids, and behind the meter resources to provide RA or other demand-reduction value.
c. Allow for reliable customer access to the grid and connection of new resources and loads through transmission and distribution development and maintenance
4. Community Resilience
a. Support funding programs to increase community resilience to electric service disruptions. b. Increase the development of community-level resources distributed energy resources that reduce the need for new transmission and distribution infrastructure.
5. Climate Action
a. Increase resources for climate change mitigation and adaptation and support initiatives that will strengthen climate change mitigation and adaptation efforts.
6. Energy Generation Sources
a. Support development of local and regional sources of renewable energy, including efforts to establish Humboldt Bay as the primary west coast hub for the offshore wind industry. b. Advocate for permanent waste solutions for nuclear plants and oppose policies that extend the life of Diablo Canyon Nuclear Power Plant.
7. Environmental Justice and Equity
a. Engage in policy developments that impact the ability of rural, low-income, and underserved communities to have affordable, reliable, and clean energy. b. Enable all communities, including emerging and historically marginalized communities, and individuals, regardless of race, color, national origin, religion, sexual orientation, sex, gender identity, age, disability, or socioeconomic status, in California to participate in the decarbonization of the state’s electric grid, building stock, and the transportation sector in a cost-effective manner.
c. Advocate for metrics and cost effectiveness rules that do not create a disadvantage in serving equity customers.
d. Support and advocate for policies that allow tribal governments to be recognized by the California Public Utilities Commission (CPUC) as public agencies for the purpose of being eligible to be direct recipients of CPUC program funding.
e. Oppose the shifting of marginal costs of interconnecting and serving large new industrial or commercial loads such as data centers to other rate classes such as residential and small commercial customers.
f. Alleviate residential and commercial financial hardship caused by public health emergencies or 3 For example, RCEA has proposed equity metrics for outage frequencies and impacts. 40 4
2026 Policy Platform
natural disasters.
8. Programs
a. Protect CCA and REN autonomy to administer Board approved programs, including but not limited to:
i. Integrated demand side management (including but not limited to microgrids, distributed energy resources, demand response, energy efficiency, electrification, distributed generation and storage, vehicle-to-grid storage) ii. Low-carbon transportation (including but not limited to advanced fuel deployment, fuel efficiency, fueling infrastructure)
iii. Energy generation and utility services (including but not limited to rates and tariffs, transmission and distribution infrastructure)
b. Avoid interruptions, gaps, or reductions in program funding. c. Protect Public Purpose Program support for energy efficiency and equity programs.4 d. Treat non-regulated fuels, such as propane and firewood, comparably with natural gas in allowing for electrification incentives.
4 Public Purpose Program covers CARE, ESA, FERA, and more programs. https://liob.cpuc.ca.gov/wp-content/uploads/sites/14/2024/03/Item-09b_Joint-IOU-Presentation-Programs-Update_PPP-Surcharge.pdf 41 1
2026 2025 Policy Platform
REDWOOD COAST ENERGY AUTHORITY
2026 POLICY PLATFORM
INTRODUCTION
Redwood Coast Energy Authority (“RCEA”) is a joint- powers authority of the cities of Arcata, Blue Lake, Eureka, Ferndale, Fortuna, Rio Dell, Trinidad, the Yurok Tribe, Blue Lake Rancheria, County of Humboldt, and the Humboldt Bay Municipal Water District. The mission of RCEA is to develop and implement sustainable energy initiatives that reduce energy demand, increase energy efficiency, and advance the use of clean, efficient, and renewable resources available in the region for the benefit of the member agencies and their constituents.
This Policy Platform serves as a guide for regulatory and legislative engagement based on principles set forth in RCEA’s RePower Humboldt strategic plan. To review RCEA’s strategic plan, please see RePower Humboldt 2019 Update
AVENUES AND EXAMPLES OF ADVOCACY
Legislation and regulation are two distinct, but related, policy tools. Legislation sets principles of public policy, while regulation implements these principles and brings legislation into effect.
Examples of RCEA legislative advocacy include submitting letters in support or opposition of specific bills, as well as meeting with legislators in the California State Senate, the California State Assembly, U.S.
House of Representatives, and U.S. Senate.
Most of RCEA’s regulatory engagement takes place through the California Public Utilities Commission, the primary State agency responsible for executing legislation and issuing regulations pertinent to Community Choice Aggregation (“CCA”) and Regional Energy Network (“REN”) operations. However, RCEA’s operations are also impacted by other state and federal agencies including but not limited to the California Energy Commission, the California Independent System Operator, the California Air Resources Board, the California Department of Water Resources, the Federal Energy Regulatory Commission, and the federal Bureau of Ocean Energy Management. Examples of advocacy in this sphere include meeting with agency staff, agency decision-makers, and submitting comments in response to regulations.
Regulatory Engagement: PROCEDURES
RCEA regulatory and legislative engagement at the CPUC and other agencies is conducted at the staff level under the authority of the Executive Director in a manner consistent with RCEA’s mission, this policy platform, RCEA’s strategic plan, RCEA’s Racial Justice Plan, and any applicable RCEA plans and policies.
Legislative Advocacy: The RCEA Executive Director, or their designee, is authorized to adopt positions on legislative matters in a timely manner without Board approval if the position is aligned with the issue areas described below.
42 2
2026 2025 Policy Platform
To keep the Board apprised of advocacy activities, staff will notify the full Board of any legislative positions taken by RCEA through periodic reports to the Board summarizing legislative engagement.
While the platform attempts to address a full range of issues of interest to RCEA, it is not intended to limit RCEA’s engagement in other issues that may impact RCEA in a positive or negative way.
Issues not addressed in the platform will continue to be brought to the Board on a case-by-case basis. To keep the Board apprised of advocacy activities, staff will notify the full Board of positions taken by RCEA through periodic reports to the Board summarizing policy engagement. This platform will be brought to the RCEA Board on an annual basis for review and input.
Policy Priorities
This platform will be brought to the RCEA Board on an annual basis for review and input.
ISSUE AREAS
1. Local Governance and Statutory Authority RCEA will:
a. Oppose policies that limitEnsure jurisdictions and tribal governments can form or become members of a CCA or REN.
a.b. Protect local governments orand CCA rate-setting, programming, or procurement autonomy. b.c. Oppose policies that limitEmpower CCA and REN ability to effectively and affordably serve their customers.
d. Support policies that allowCCA and REN customer engagement and operational transparency.
c.e. Enable CCAs and RENs to engagecollaborate with their customers and promote transparency in their operations. member jurisdictions on local energy resources and projects to advance environmental objectives.
d. Support policies that make it easier for jurisdictions to form or become members of a CCA or REN and oppose regulations and legislation that restrict such ability. e. Support policies that allow for tribal governments to be full participation in CCAs. f. Support the development of energy generation projects that align with Board-adopted strategic plan goals and RCEA’s energy risk policy, as long as local development and siting criteria are consistent with city and county land use authority, other local and state regulatory requirements, and informed by input from local communities including but not limited to tribal governments.
2. Restructuring the Electricity Utility Sector RCEA will:
a. Support policies that reduceReduce reliance on Investor-Owned Utilities (“IOUs”), such as ”):
i. Polices that supportSupport governments’ ability to fund or own electric infrastructure, including transmission and distribution infrastructure. ii. Policies that stabilizeStabilize, remove, or reduce costs associated with leaving IOU 43 3
2026 2025 Policy Platform
service, such as the Power Charge Indifference Adjustment or costs associated with maintaining a Provider of Last Resort.
b. Where IOU service is retained, advocate for: :
i. Reforms toReform the utility regulatory and business model to transform IOUs into entities that solely provide transmission and distribution services. ii. Efforts to discourageDiscourage new gas infrastructure and retire or repurpose existing gas infrastructure. , while recognizing and addressing social inequities that retirement of such infrastructure may cause.1
iii. Reforms toReform the utility regulatory and business model to ensure IOUs deliver effective service to ratepayers, increase safety and reliability, and reduce costs. iv. GreaterFoster greater collaboration to occur betweenand data sharing among CCAs, RENs, tribes, state and local governments, and IOUs, particularly in local planning efforts related to energy resources, load planning, and programs. v. Increased data access to IOU data, such as customer program enrollment, meter data, and load planning data.
c. Oppose policies that expand direct access. electric service expansion.2
3. Reliability RCEA will:
a. Support policies that reduceOutage Events
a. Reduce duration and frequency of power outages and improve grid i. reliability, such as Public Safety Power Shut-Offs (“PSPS”). . i. Support policies that increase the notification and transparency requirements on IOUs as they implement a PSPS. ii. Support policies that create standards for PSPS implementation and impose penalties on IOUs that execute PSPS below those standards.
ii. iii. Support policies that call for Increase transparency surrounding outage events. iii. Create standards and thresholds for outage events.3 iv. Support equitable treatment of non-utility owned generation during PSPSshutoff events and during related islandedisland operation of sections of the grid. b. b. Resource Adequacy (“RA”)
i. Support reforms toReform the RA program to improve system reliability at a reasonable cost to ratepayers. -effectively.
ii. Advocate for and support efforts to removeRemove barriers to demand response, microgrids, and behind the meter resources to provide RA or other demandreductiondemand-reduction value.
c. c. Advocate for transmission and distribution development and maintenance to allowAllow for reliable customer access to the grid and connection of new resources and loads. through transmission and distribution development and maintenance 1 For instance, low income households that utilize gas appliances may be disproportionally disadvantaged by gas infrastructure retirement due to appliance replacement and operating costs. 2 https://www.cpuc.ca.gov/consumer-support/consumer-programs-and-services/electrical-energy-and-energy-efficiency/community-choice-aggregation-and-direct-access-/direct-access 3 For example, RCEA has proposed equity metrics for outage frequencies and impacts. 44 4
2026 2025 Policy Platform
4. Emergency and Disaster
Response RCEA will
a. Support policies to alleviate residential and commercial financial hardship caused by public health emergencies or natural disasters that could disrupt electricity service or restrict customer access to clean energy and transportation opportunities.
5.4.Community Resilience RCEA will:
a. Advocate for and support Support funding for programs implemented by local governments, CCAs, and RENs to increase community resilience to wildfires, PSPS events and other potentialelectric service disruptions.
b. Support policies that reduce barriers to microgrid development by CCAs and other local entities including tribes and local governments.
c. Support policies that expand the ability of non-IOU entities to develop microgrids (e.g., ensuring CCA access to ratepayer funds to develop microgrids).
d.b.Support policies that increaseIncrease the development of community -level resources and distributed energy resources that reduce the need for new transmission and distribution infrastructure.
6.5.Climate Action RCEA will:
a. Support policies that increaseIncrease resources for climate change mitigation and adaptation and support initiatives that will strengthen climate change mitigation and adaptation efforts.
7.6.Energy Generation Sources RCEA will:
a. Support policies that expand opportunities for, or reduce barriers to the development of resources that align with Board-adopted strategic plan goals and our energy risk policy, as long as local development and siting criteria are consistent with city and county land use authority, other local and state regulatory requirements, and informed by input from tribal governments. b. Oppose policies that require CCAs to purchase specific energy products, thus limiting the ability of CCAs to meet local energy needs in a cost-effective manner and in conflict with their local procurement and rate setting authority.
a. Support development of local and regional sources of renewable energy, including efforts to establish Humboldt Bay as the primary west coast hub for the offshore wind industry. c.b. Advocate for permanent waste solutions for nuclear plants and oppose policies that extend the life of Diablo Canyon Nuclear Power Plant.
8.7.Environmental Justice RCEA will: and Equity
a. Advocate for policies that align with RCEA’s Racial Justice Plan. b.a. Engage in policy developments that directly or indirectly impact the ability of rural, lowincomelow-income, and underserved communities to have affordable, reliable, and clean energy.
c.b. Support policies that enableEnable all communities, including emerging and historically marginalized communities, and individuals, regardless of race, color, national origin, religion, 45 5
2026 2025 Policy Platform
sexual orientation, sex, gender identity, age, disability, or socioeconomic status, in California to participate in the decarbonization of the state’s electric grid, building stock, and the transportation sector in a cost-effective manner.
d.c. Advocate for metrics and cost effectiveness rules that do not create a disadvantage in serving equity customers.
e.d. Support and advocate for policies that allow Ttribal Nations governments to be recognized by the California Public Utilities Commission (CPUC) as public agencies for the purpose of being eligible to be direct recipients of CPUC program funding.
e. RCEA Oppose the shifting of marginal costs of interconnecting and serving large new industrial or commercial loads such as data centers to other rate classes such as residential and small commercial customers.
f. Alleviate residential and commercial financial hardship caused by public health emergencies or natural disasters.
9.8.Programs
RCEA will support policies that:
a. a. Protect CCA and REN autonomy to administer Board approved programs, including but not limited to:
i. Integrated demand side management (including but not limited to microgrids, distributed energy resources, demand response, energy efficiency, electrification, distributed generation and storage, vehicle-to-grid storage) ii. Low-carbon transportation (including but not limited to advanced fuel deployment, fuel efficiency, fueling infrastructure)
iii. Energy generation and utility services (including but not limited to rates and tariffs, transmission and distribution infrastructure)
b. Avoid interruptions, gaps, or reductions in program funding. a.c. Protect Public Purpose Program support for energy efficiency and equity programs. 4 b.d.Treat non-regulated fuels, such as propane and firewood, comparably with natural gas in allowing for electrification incentives.
4 Public Purpose Program covers CARE, ESA, FERA, and more programs. https://liob.cpuc.ca.gov/wp-content/uploads/sites/14/2024/03/Item-09b_Joint-IOU-Presentation-Programs-Update_PPP-Surcharge.pdf 46
Staff Report
Agenda Item # 7.1
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Elizabeth Burks, Executive Director
Subject Executive Director’s Report
Summary
Executive Director Elizabeth Burks will provide updates on topics as needed. These updates include but are not limited to the following.
RCEA Updates
GRID Alternatives Electric Vehicle Discounted Charing Pilot RCEA is partnering with the non-profit Grid Alternatives, to implement a pilot program for discounted charging rates at RCEA’s public charging stations. GRID Alternatives is providing approximately $20,000 for this pilot. The program will provide discounted charging rates at public charging stations on our Renewable Energy Vehicle Network (REVNet). Income-qualified EV drivers with an active RCEA residential electric account (in good standing) will receive a 40% discount rate on all REVNet stations.
This pilot is intended to address the lack of charging infrastructure available at multifamily rental housing and pass on savings that would otherwise be realized through home charging at discounted rates (through CARE/FERA) to eligible drivers charging at a REVNet charging station.
CADEMO Offshore Wind Project
In December, with approval of the ad hoc subcommittee for the CADEMO loan agreement, RCEA made a loan to the CADEMO project. This loan has already been repaid in full, including payments for interest and associated administrative fees. The CADEMO team has expressed deep gratitude for the assistance.
Supporting our Community Program Marketing Initiative
The Supporting Our Community Program is a community engagement and marketing initiative that can provide sponsorships for specific community events when they increase awareness of RCEA programs and customer services. In RCEA’s FY 2025-26 budget $25,000 was approved for this purpose. The goal is to strategically invest these dollars where they create visibility, improve brand recognition, and educate community members about RCEA’s services, programs, and energy-related resources. 47
Priorities for sponsorships would be given to efforts aligned with RCEA’s mission and those that help us connect with hard-to-reach or underserved segments of our community. Considerations for sponsorships would include efforts that:
• Advance STEM education and workforce development, particularly in the trades, clean energy, and environmental sciences.
• Accelerate greenhouse gas reduction and climate solutions. • Host key community events in Humboldt County, especially those that provide RCEA opportunities to educate residents about energy services and community programs. • Promote basic needs and community resilience
2025 Call Log Summary
In 2025 RCEA answered more than 1,300 calls from CCA customers. The following are the highest call volume categories that made up 60% of total calls for the year:
• Collections (17%)
• Billing Inquiry (16%)
• Net Energy Metering (NEM) (15%)
• Opt Out Inquiry (12%)
Opt out Inquiries were at their highest volume in January but weren't the top category in any single month. Over the year we received 156 opt out inquiries. After speaking with RCEA staff, only half of those ultimately opted out. February saw the highest volume of opt outs submitted (13).
Community Activity Summary
See attached.
Board Member Travel Opportunities
Board members are encouraged to participate in the upcoming conferences where there will be a chance to gain deeper understanding of the issues and opportunities related to RCEA business. Upcoming opportunities include:
• CalCCA Conference May 12-14, 2026 in Sacramento, CA
• CivicWell Policymakers Conference March 12-15, 2026, in Yosemite National Park (RCEA has one complimentary registration for this conference.)
• CCEC Forum June 24-25, 2026 in Los Angeles, CA
PG&E Base Services Charge
PG&E will implement the Base Services Charge (this was formally referred to as graduated fixed income charge) on customer bills beginning March 2026, as mandated by Assembly Bill 205 and approved by the CPUC. This is not a new fee but a restructuring that separates certain costs into a distinct line item on PG&E’s portion of the bill. It will not appear on RCEA’s portion.
The Base Services Charge is intended to transparently allocate costs related to grid access, metering, public purpose programs, and customer service/billing. Customer communications from PG&E are 48
underway: on bill messaging began December 1, 2025, PG&E’s web portal banner will run for about 90 days, and PG&E is sending physical mailers to customers beginning this month.
Customers who don’t qualify for CARE or FERA and are low-energy users may be negatively impacted.
For instance, these low-usage customers could see a significant increase in their bills—from $75 to $91, a 21% jump—because this fee is fixed rather than based on usage.
There are three tiers:
• Tier 1 – $6/month: Residential customers enrolled in CARE. • Tier 2 – $12/month: Residential customers enrolled in FERA or living in deed restricted affordable housing (DHR) as listed by the California Housing Partnership (CHP). • Tier 3 – $24/month: All other residential customers.
Reduced charges for CARE and FERA customers are designed to allocate costs more equitably among customers.
Staff Recommendation
None. Information only.
Attachments
1. November – December 2025 Community Outreach and Events Summary 49 COMMUNITY OUTREACH & EVENT SUMMARY
4 66
Community Events
Presentations were conducted at the Healy Senior Center, Trinidad Chamber of Commerce, Rotary Club of Eureka, and the Rotary Club of SW Eureka.
Presentations
A total of 37 presentations were conducted, 26 events were staffed, and 3 workshops were held were held in 14 communities in the county. There were over 2,700 interactive engagements with the community.
2025 Summary of Events & Presentations
Staffed a table at the Rio Dell Community Resource Center where participants appreciated receiving information and program handouts.
January 2026
1 50
Staff Report
Agenda Item # 8.1
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Richard Engel, Director of Power Resources
Subject Energy Risk Management Policy Update
Background
Section 8 of RCEA’s Energy Risk Management Policy (ERMP) directs the RCEA Risk Management Team to review the policy at least annually and submit any proposed amendments to the Board for approval. It also directs staff to notify the Board when appendices to the ERMP are being updated. The policy was initially adopted by the Board in December 2016 and was last revised in December 2024. An addendum to the ERMP was approved by the Board in June 2025.
Summary
The attached draft of the ERMP has been updated by staff in consultation with The Energy Authority and includes the following notable changes:
• Section 1.1 – clarifies which CCA policies are subject to full Board vote. • Section 2.1 – references RCEA’s Reserve Policy objectives. • Section 2.2 – standardizes wording across the different risk types and updates mitigation measures.
• Section 3.10 – clarifies authority to terminate long-term contracts; addresses PPA prepayment transactions.
• Section 3.4 – removes the New Transaction Approval Form (Appendix B) and adds the risk assessment called for in the form to the body of the policy. • Section 4.3 – incorporates addendum 2025-A that adjusted the staff makeup of the Risk Management Team; clarifies additional process in the event the Executive Director exercises their veto power.
• Section 4.4.3 – adds invoicing and settlements to the Power Manager’s back-office responsibilities.
• Section 5 – clarifies that authority to terminate transactions is subject to the same delegation of authority as executing transactions; updates policy list that procurement must align with. • Appendix D – adjusts fixed price energy hedging targets according to recent pricing trends in CA reflective of increased solar and battery adoption; references RCEA’s Reserve Policy objectives; 51
revises clean energy procurement goals consistent with Board actions; clarifies discussion on Portfolio Content Category 2 and 3 renewables.
The Risk Management Team has approved the updated policy and recommends adoption by the Board] Equity Impacts
Not applicable.
Alignment with RCEA’s Strategic Plan
Not applicable. The Energy Risk Management Policy is an operational document.
Financial Impact
RCEA’s Energy Risk Management Policy protects the organization from financial risk that could be incurred through its CCE program. The proposed changes promote best practices that mitigate financial risk to the organization inherent in participating in energy markets as a load-serving entity.
Staff Recommendation
Adopt Resolution 2026-1 Adopting the Updated Energy Risk Management Policy.
Attachments
1. Resolution 2026 – 1 Adopting the Updated Energy Risk Management Policy
2. Exhibit A: Redlined RCEA Energy Risk Management Policy 52 RESOLUTION NO. 2026-1
OF THE BOARD OF DIRECTORS
OF THE REDWOOD COAST ENERGY AUTHORITY
ADOPTING THE UPDATED ENERGY RISK MANAGEMENT POLICY
WHEREAS, the Redwood Coast Energy Authority (RCEA) operates a community choice energy program on behalf of participating jurisdictions in Humboldt County; and WHEREAS, the Board of RCEA adopted an Energy Risk Management Policy (Risk Policy) in December 2016 to establish rigorous risk management practices in power procurement and to increase the likelihood of achieving its community choice energy program goals by specifying management responsibilities, organizational structures, risk management standards, and operating controls and limits necessary to properly identify and manage RCEA’s exposure to risk; and
WHEREAS, the Risk Policy calls for RCEA’s Risk Management Team to annually review the policy and recommend any needed Risk Policy updates to the RCEA Board of Directors for adoption; and
WHEREAS, certain updates to the Risk Management Policy are needed to address market, regulatory and other changes that have taken place since the last Policy update.
NOW, THEREFORE, BE IT RESOLVED, that the Board of the Redwood Coast Energy Authority hereby adopts an updated Energy Risk Management Policy as set forth in Exhibit A with deletion of language as shown by strike through and addition of language as shown by underlining, attached hereto and incorporated herein.
Adopted this 22nd day of January 2026.
ATTEST:
RCEA Board Chair Clerk of the Board, RCEA
Date: _________________________ Date:
53 CLERK'S CERTIFICATE
I hereby certify that the foregoing is a true and correct copy of Resolution No. 2026-1 passed and adopted at a regular meeting of the Redwood Coast Energy Authority, County of Humboldt, State of California, held on the 22nd day of January 2026, by the following vote:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
Clerk of the Board, Redwood Coast Energy Authority
54 EXHIBIT A
REDWOOD COAST ENERGY AUTHORITY
REDLINED ENERGY RISK MANAGEMENT POLICY
55 Energy Risk
Management Policy
Adopted December 12, 2016, Resolution 2016‐6
Last Revised December 17, 2024January 22, 2026, Resolution 2024‐142026‐1
56 1
Table of Contents
Section 1: POLICY OVERVIEW ....................................................................................................................... 3
1.1 Background and Purpose .................................................................................................................... 3
1.2 Scope ................................................................................................................................................... 4
1.3 Energy Risk Management Objective ................................................................................................... 4
1.4 Policy Administration .......................................................................................................................... 4 Section 2: GOALS AND RISK EXPOSURES ...................................................................................................... 5
2.1 Policy Goals ......................................................................................................................................... 5
2.2 Risk Exposures ..................................................................................................................................... 5
2.2.1 Customer Opt-Out Risk ................................................................................................................ 6
2.2.2 Market Risk .................................................................................................................................. 6
2.2.3 Regulatory Risk ............................................................................................................................. 6
2.2.4 Volumetric Risk ............................................................................................................................ 7
2.2.5 Model Risk .................................................................................................................................... 8
2.2.6 Operational Risk ........................................................................................................................... 8
2.2.7 Counterparty Credit Risk .............................................................................................................. 8
2.2.8 Reputation Risk ............................................................................................................................ 9
2.3 Risk Measurement Methodology........................................................................................................ 9 Section 3: BUSINESS PRACTICES ................................................................................................................... 9
3.1 General Conduct ................................................................................................................................. 9
3.2 Trading for Personal Accounts ............................................................................................................ 9
3.3 Adherence to Statutory Requirements ............................................................................................. 10
3.4 Transaction Type, Regions and Markets ........................................................................................... 11
3.5 Counterparty Suitability .................................................................................................................... 11
3.6 System of Record .............................................................................................................................. 11
3.7 Transaction Valuation ....................................................................................................................... 11
3.8 Stress Testing .................................................................................................................................... 11
3.9 Trading Practices ............................................................................................................................... 12
3.10 Long-Term Transactions .................................................................................................................. 12 Section 4: ORGANIZATIONAL STRUCTURE AND RESPONSIBILITIES ........................................................... 12 57 2
4.1 Risk Management Organizational Structure ..................................................................................... 12
4.2 Board of Directors ............................................................................................................................. 13
4.3 Risk Management Team (RMT) ......................................................................................................... 13
4.4 Power Manager ................................................................................................................................. 14
4.4.1 Power Manager - Front Office ............................................................................................ 14
4.4.2 Power Manager – Middle/Back Office ................................................................................ 15 Section 5: DELEGATION OF AUTHORITY .................................................................................................... 15
5.1 Monitoring, Reporting and Instances of Exceeding Risk Limits ........................................................ 16 Section 6: CREDIT POLICY ........................................................................................................................... 17
6.1 Credit Limit and Monitoring .............................................................................................................. 17 Section 7: POSITION TRACKING AND MANAGEMENT REPORTING ........................................................... 18 Section 8: POLICY REVISION PROCESS ....................................................................................................... 19
8.1 Acknowledgement of Policy .............................................................................................................. 19
8.2 Policy Interpretations ........................................................................................................................ 19 Appendix A: AUTHORIZED TRANSACTION TYPES OR PRODUCTS ............................................................... 20 Appendix B: NEW TRANSACTION APPROVAL FORM.................................................................................. 21 Appendix C: DEFINITIONS .......................................................................................................................... 22 Appendix D: ENERGY RISK HEDGING STRATEGY ........................................................................................ 25 Introduction ............................................................................................................................................ 25 Governance ............................................................................................................................................. 25 Hedging Program Goals .......................................................................................................................... 25 Prohibited Generation Sources ............................................................................................................... 26 Hedging Targets and Strategies .............................................................................................................. 27 Compliance & Goal Driven Procurement ................................................................................................ 30 Hedge Program Metrics .......................................................................................................................... 33 Reporting Requirements ......................................................................................................................... 34 Appendix E: ACKNOWLEDGMENT OF ENERGY RISK MANAGEMENT POLICY ............................................. 35 Section 1: POLICY OVERVIEW ....................................................................................................................... 5
1.1 Background and Purpose .................................................................................................................... 5
1.2 Scope ................................................................................................................................................... 6 58 3
1.3 Energy Risk Management Objective ................................................................................................... 6
1.4 Policy Administration .......................................................................................................................... 7 Section 2: GOALS AND RISK EXPOSURES ...................................................................................................... 7
2.1 Policy Goals ......................................................................................................................................... 7
2.2 Risk Exposures ..................................................................................................................................... 8
2.2.1 Customer Opt-Out Risk ................................................................................................................ 8
2.2.2 Market Risk .................................................................................................................................. 9
2.2.3 Regulatory Risk ............................................................................................................................. 9
2.2.4 Volumetric Risk .......................................................................................................................... 10
2.2.5 Model Risk .................................................................................................................................. 11
2.2.6 Operational Risk ......................................................................................................................... 11
2.2.7 Counterparty Credit Risk ............................................................................................................ 12
2.2.8 Reputation Risk .......................................................................................................................... 12
2.3 Risk Measurement Methodology...................................................................................................... 12 Section 3: BUSINESS PRACTICES ................................................................................................................. 13
3.1 General Conduct ............................................................................................................................... 13
3.2 Trading for Personal Accounts .......................................................................................................... 13
3.3 Adherence to Statutory Requirements ............................................................................................. 13
3.4 Transaction Type, Regions and Markets ........................................................................................... 14
3.5 Counterparty Suitability .................................................................................................................... 15
3.6 System of Record .............................................................................................................................. 15
3.7 Transaction Valuation ....................................................................................................................... 15
3.8 Stress Testing .................................................................................................................................... 15
3.9 Trading Practices ............................................................................................................................... 15
3.10 Long-Term Transactions .................................................................................................................. 16 Section 4: ORGANIZATIONAL STRUCTURE AND RESPONSIBILITIES ........................................................... 16
4.1 Risk Management Organizational Structure ..................................................................................... 16
4.2 Board of Directors ............................................................................................................................. 17
4.3 Risk Management Team (RMT) ......................................................................................................... 17
4.4 Power Manager ................................................................................................................................. 18 59 4
4.4.1 Power Manager - Front Office ............................................................................................ 19
4.4.2 Power Manager – Middle/Back Office ................................................................................ 19 Section 5: DELEGATION OF AUTHORITY .................................................................................................... 20
5.1 Monitoring, Reporting and Instances of Exceeding Risk Limits ........................................................ 21 Section 6: CREDIT POLICY ........................................................................................................................... 21
6.1 Credit Limit and Monitoring .............................................................................................................. 22 Section 7: POSITION TRACKING AND MANAGEMENT REPORTING ........................................................... 22 Section 8: POLICY REVISION PROCESS ....................................................................................................... 23
8.1 Acknowledgement of Policy .............................................................................................................. 23
8.2 Policy Interpretations ........................................................................................................................ 23 Appendix A: AUTHORIZED TRANSACTION TYPES OR PRODUCTS ............................................................... 24 Appendix B: DEFINITIONS .......................................................................................................................... 25 Appendix C: ENERGY RISK HEDGING STRATEGY ........................................................................................ 29 Introduction ............................................................................................................................................ 29 Governance ............................................................................................................................................. 29 Hedging Program Goals .......................................................................................................................... 29 Prohibited Generation Sources ............................................................................................................... 30 Hedging Targets and Strategies .............................................................................................................. 31 Compliance & Goal Driven Procurement ................................................................................................ 34 Hedge Program Metrics .......................................................................................................................... 38 Reporting Requirements ......................................................................................................................... 39 Appendix D: ACKNOWLEDGMENT OF ENERGY RISK MANAGEMENT POLICY ............................................. 40
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Section 1: POLICY OVERVIEW
1.1 Background and Purpose
The Redwood Coast Energy Authority (“RCEA”) is a public joint powers agency located within the geographic boundaries of Humboldt County. Member agencies of RCEA include the seven (7) incorporated cities located in Humboldt County, the County of Humboldt, the Yurok Tribe, the Blue Lake Rancheria, and the Humboldt Bay Municipal Water District. RCEA members enumerated below administer and participate in a community choice aggregation (“CCA,” also sometimes referred to as community choice energy or “CCE”) program. The CCA program allows its members to procure exert local control over the electricity supplies and utilize ratepayer revenue to implement local programs that meet the goals of portfolio made available to the community. Electricity procured to serve customers continues to be delivered over Pacific Gas & Electric Company’s (“PG&E’sE”) transmission and distribution system.
Presently, RCEA’s CCA Members1
include the following local government entities:
Unincorporated Humboldt County
City of Arcata
City of Blue Lake
City of Eureka
City of Ferndale
City of Fortuna
City of Trinidad
City of Rio Dell
Providing retail electric generation service to customers enrolled in the CCA program exposes RCEA to risks such as retail load uncertainty (due to weather, customer opt-out, and other factors), energy market price, counterparty credit, PG&E generation and Power Charge Indifference Adjustment (“PCIA”) rate competitiveness and other regulatory risks.
This Energy Risk Management Policy (“Policy”) establishes RCEA’s Energy Risk Management Program (“Risk Program”) including functions and procedures to manage the risks associated with power procurement activities.
1 The Humboldt Bay Municipal Water District, the Yurok Tribe, and the Blue Lake Rancheria do not participate in CCA governance, per California Public Utilities Code Section 331.1 that limits CCA formation to counties and cities.
However, in June 2025 the RCEA Board of Directors approved changes to their operating guidelines (https://redwoodenergy.org/wp-content/uploads/sites/850/2025/07/Board-Operating-Guidelines-250626.pdf) to make the following CCA-related topics subject to full Board vote, given their potential impact on the organization as a whole: setting of CCA program objectives, determination of CCA power content targets, and CCA procurement strategy and procedures. Previously these topics were voted on only by the RCEA Board members representing the County and the cities.
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To help RCEA increase the likelihood of achieving its goals, the purpose of this Policy is to specify management responsibilities, organizational structures, risk management standards, and operating controls and limits necessary to identify and manage RCEA’s exposure to risk.
The RCEA Board of Directors (“Board”) approves wholesale power procurement risk related policies, including delegations of authority and limits to the Executive Director, RCEA staff and, as warranted, third-party service providers. The Board understands and acknowledges that energy trading activities necessarily involve risk, and a key Board objective is to quantify and balance value and risk within RCEA’s resource portfolio without engaging in speculative trading activity. Within the guidelines of this policy, the Board recognizes that expertise must be employed in managing RCEA’s resource portfolio, so staff and third-party service providers may exercise reasonable discretion in making commercial trading decisions.
1.2 Scope
Unless otherwise explicitly stated in this Policy, or other policies approved by the Board, this Policy applies to all power procurement and related business activities that may impact RCEA’s risk profile.
RCEA’s Procurement Policy2
, which broadly directs RCEA’s procurement activities, explicitly states that power procurement to serve RCEA’s electric customers is governed by this Energy Risk Management Policy. This Policy documents the framework for staff and The Energy Authority3 (“TEA”) to:
Identify and quantify risk
Develop and execute procurement strategies
Create a framework of controls and oversight
Monitor, measure, and report on the effectiveness of the Risk Program To ensure successful operation of the CCA, RCEA partners with experienced contractors to provide energy-related services. For power procurement, RCEA partners with TEA, who currently executes the preponderance of front- (transacting), middle- (monitoring) and back-office (settlement) related activities on RCEA’s behalf. In providing these services, TEA observes the policies outlined in this document. TEA maintains its own risk policies and procedures, following industry practices of segregation of duties, which will also govern activities executed on RCEA’s behalf.
1.3 Energy Risk Management Objective
The objective of the Energy Risk Management Policy is to provide a framework for conducting procurement activities that maximize the probability of RCEA meeting its Policy goals listed in Section
2.1. 2
https://redwoodenergy.org/wp-content/uploads/sites/850/2024/12/Purchasing-and-Procurement-Policy.pdfpdfhttps://redwoodenergy.org/wp-content/uploads/2024/10/RCEA-Purchasing-and-Procurement-Policy-1.pdf 3 The Energy Authority is RCEA’s current portfolio manager and scheduling coordinator for its load and long-termwholesale power contracts. 62 7
Pursuant to this Policy, RCEA will identify and measure the magnitude of the known risks to which it is exposed and that contribute to the potential for not meeting identified goals, and manage them accordingly.
1.4 Policy Administration
This Policy document is reviewed and approved by the RCEA Board of Directors (“Board”). The Risk Management Team (“RMT”) and Board must approve amendments to this Policy, except for the appendices, which may be amended with approval of only the RMT. The RMT must give notice to the Board of any amendment it makes to an appendix or a reference policy or procedure document.
Section 2: GOALS AND RISK EXPOSURES
2.1 Policy Goals
To help ensure long term viability for the CCA, RCEA outlines the following Policy goals with respect to its Risk Program. These goals establish metrics for modeling and measuring risk exposures of the CCA. RCEA targets to fund financial reserves with the following objectives as set forth by its Reserve Policy4:
o EstablishMaintain long-term business sustainabilityRCEA financial independence and rate stability,
o Build collateral for power procurement activities
o Establish and maintain an investment grade Meet RCEA strategic objectives, o Secure favorable commercial terms with vendors and power providers, o Support RCEA’s pursuit of, and maintenance upon receiving, a credit rating, o DevelopProvide a source of funds for investment in power resourcesunanticipated expenditures, and
o Make cash available for other local programsoperational needs as approved by the Board.
o Stabilize retail electricity rates and dampen year-to-year variability in procurement costs o Reduce the fee for the credit facility provided by TEA as part of the services it delivers to RCEA
RCEA aims to meet its strategic objectives as found in the RePower Humboldt Comprehensive Action Plan for Energy5
The goals outlined above are incorporated into RCEA’s financial and analytic models used to evaluate risk exposures. The goals listed above are not intended to be a comprehensive list of goals for the CCA. 4 https://redwoodenergy.org/wp-content/uploads/sites/850/2025/01/Reserve-Policy.pdf 5 https://redwoodenergy.org/wp-content/uploads/sites/850/2024/12/RePower-Humboldt-CAPE2025/09/REpower-2019-Strategic-Plan-Update250919.pdf 63 8
Rather, the above reflect a subset of Risk Program goals that are critical to long-term business viability for the CCA.
For the purpose of this Policy, risk exposure is assessed on all transactions (energy, environmental attributes, capacity, etc.) executed by TEA on behalf of RCEA, or by RCEA on its own behalf, as well as the risk exposure of open positions and the impacts of these uncertainties on the CCA’s load and financial obligations.
2.2 Risk Exposures
The CCA program faces a range of risks including:
Customer opt-out risk
Market risk
Regulatory risk
Volumetric risk
Model risk
Operational risk
Counterparty credit risk
Reputation risk
2.2.1 Customer Opt‐Out Risk
Customer opt-out risk is a significant CCA risk. It includes any conditions or events that create uncertainty in the CCA’s customer base, thereby increasing the potential for the CCA to not meet its Policy goals. Opt-out risk can take the form of individual customers leaving the program, or entire member communities choosing to no longer participate. In addition, RCEA can lose customers by choosing to return them to bundled PG&E service if they repeatedly fail to pay their bills. This Policy addresses this risk and other risk types listed below. These risks are not all inclusive but are identified as the risk factors driving the success of the CCA.
The most relevant measures of the success of this Policy in mitigatingRCEA manages opt-out risk includeby:
RetailMaintaining retail rate competitiveness with PG&E;6 Financial reserve level for retail rate stabilization; PercentageProviding outstanding customer service;
Operating a key account management program and maintaining relationships with the local community;
6 Since CCA program launch, RCEA has set its retail generation rates as a set percentage discount below the corresponding PG&E generation rates. The amount of this percentage discount has been adjusted on some occasions by the RCEA Board as financial conditions have changed. To maintain this rate discount as PG&E generation rates are changed on short notice multiple times a year, the Board has authorized staff to adjust rates in response to PG&E rate changes without needing to seek Board approval in each instance. 64 9
Maintaining financial reserves compliant with RCEA’s Reserve Policy to stabilize retail rates as needed;
Tracking percentage of customer opt-outs by customer count and by load; PercentageTracking percentage of customers and customer load returned to PG&E for non-payment.
Mitigation measures for customer opt-out risk are included under Section 2.2.4 Volumetric Risk.
2.2.2 Market Risk
Market risk is the uncertainty of RCEA’s financial performance due to variable commodity market prices (market price risk) and uncertain price relationships (basis risk). Variability in market prices creates uncertainty in RCEA’s procurement costs and can materially impact RCEA’s financial position. Market risk is managed by regular measurement, execution of approved procurement, and Congestion Revenue Right (CRR) strategies and the limit structure set forth in this Policy, as well asRCEA manages market risk by:
Routinely monitor and reportAdhering to the energy hedging strategy described in Appendix C of this Policy and regularly reviewing and adapting the strategy to changing market conditions; Routine monitoring and reporting of actual and projected financial results including probability-based and stressed financial results assuming a range of market and retail rate scenarios (both RCEA and PG&E);
Structure procurement strategies with the objective function to maintain a favorable retail rate savings relative to PG&E.
Procuring contracts with positive net present value to the extent possible.
2.2.3 Regulatory Risk
Although CCAs hold a significant share of retail customer load in the state of California, they remain a comparatively new legal entity and are subject to an evolving legal and regulatory landscape.
Additionally, CCAs are in direct competition with California’s Investor-Owned Utilities (“IOUs”), which are able to recover costs of stranded investments: generation assets and power purchase agreements previously procured to serve loads that subsequently depart the IOU and obtain generation through a CCA. The stranded costs of these legacy power supplies are allocated to departing CCA loads through regulatory proceedings at the California Public Utilities Commission (“CPUC”) which are not always transparent to the CCA communityCCAs and their customers. The service model and regulatory landscape results in retail rate competitiveness risks that are unique to CCAs. In addition, CCAs are subject to many of the same state-level regulatory policies that govern other load-serving entities, including the Renewable Portfolio Standard, Resource Adequacy Program, and Integrated Resource Planning process and procurement mandates.
To manageRCEA manages regulatory risk, RCEA by:
Regularly monitors, analyzesRegular monitoring, analysis, and engagesengagement in legislative and regulatory rulemakings and proceedings impacting CCAs, either directly or through the California Community Choice Association (“CalCCA”);
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EnsuresEnsuring timely submission of regulatory filings, compliance filings and data request responses, and tracking changing requirements associated with these submissions; EnsuresEnsuring timely procurement and project progress reporting, and to the extent feasible and prudent, conducting proactivetimely procurement, in response to procurement mandates; EngagesEngaging subject matter expertise as needed to ensure itRCEA is conducting business in a manner consistent with State regulations and industry best practices.
2.2.4 Volumetric Risk
Volumetric risk is the uncertainty of RCEA’s financial performance due to variability in 1) the quantity of retail load served by RCEA, 2) the bill payments actually collected from customers, and 3) generation from RCEA’s contracted power resources. Retail load and customer debt uncertainty results from unanticipated large customer additions or departures, customer opt-outs, weather deviation from normal, unforeseen increased adoption of behind the meter generation, as well as local, state and national socioeconomic conditions. Volumetric risks can also occur on the wholesale procurement side, including risk of curtailed variable energy resources under contract to RCEA, unplanned disconnection of generating resources under contract to RCEA during utility maintenance or islanding of the local grid in response to Public Safety Power Shutoff events, and the unknown volumetric delivery of resources procured through PG&E’s various PCIA Allocation processes. VolumetricRCEA manages volumetric risk is managed by taking steps to:
ForecastUtilizing tools to forecast PG&E generation and PCIA rates, and variability therein; Quantify variability in procurement timing and costs; DevelopDeveloping risk-adjustment metrics for forecasted loads and forecasted delivered volumes to support future procurement decisions;
MonitorMonitoring and adjustadjusting for non-regulatory factors driving volumetric uncertainty (e.g. weather);
Adopt a formal Adhering to the energy risk hedging strategy (included as an appendix to described in Appendix C of this Policy);
Implement a key accounts program and maintain strong relationships with the local communityregularly reviewing and adapting the strategy to changing market conditions; MonitorMonitoring trends in customer onsite generation, local, regional, and national economic shifts, and other factors that affect electricity customer volume and composition; TrackTracking and attemptattempting to collect customer debt, and returnreturning uncollectable accounts back to PG&E, pursuant to RCEA’s Community Choice Energy Terms and Conditions7
;
PursuePursuing strategies to minimize or mitigate generation disconnections and curtailments, including co-locating storage with variable renewable energy resources and working with PG&E toward management of planned transmission outages and accommodation of third-party generators while the local grid is operated in island mode; 7 https://redwoodenergy.org/wp-content/uploads/sites/850/2024/12/CCE-Terms-and-Conditions.pdfservice-terms-conditions/ 66 11
EngageEngaging PG&E, CAISO and the IOUCPUC to conduct transmission and distribution updates and technical advances to better interconnect emerging distributed generation resources and new customer loads;
ExploreExploring strategies for serving direct access loads.
2.2.5 Model Risk
Model risk is the uncertainty of RCEA’s financial performance due to potentially inaccurate or incomplete characterization of a transaction or power supply portfolio elements due to fundamental deficiencies in models, inputs, and/or information systems. ModelRCEA manages model risk management includes::by:
TEA’s Risk Management Committee approvesapproving, and RCEA’s RMT ratifiesratifying, financial and risk models;
Ongoing review ofReviewing model inputs and outputs as part of controls frameworkon a regular basis, including scheduledrecurring true-ups of data actuals and data cross-validation between RCEA and TEA;
Comparison betweenComparing multiple independent data sources as available and valuablerelevant;
Ongoing RCEA and TEA staff education and participation in CCA industry forums; Ongoing update and improvement of models as additional information and expertise is acquired.
2.2.6 Operational Risk
Operational risk is the uncertainty of RCEA’s financial performance due to weaknesses in the quality, scope, content, or execution of human resources, technical resources, and/or operating procedures within RCEA. Operational risk can also be exacerbated by fraudulent actions by employees or third parties, inadequate or ineffective controls, or unforeseen changes in our relationship with the incumbent utility. Operational risk is managed throughPG&E. RCEA manages operational risk by:
The Adhering to the controls set forth in this Policy; The RMT oversight ofoverseeing procurement activity;
Timely and effective management reporting;
Staff resources, expertiseHiring competent staff and/or consultants and providing adequate training resources, reinforcing a culture of compliance; OngoingConducting recurring and timely internal and external financial and operational audits; Enforcement ofEnforcing RCEA’s CCA termsCCE Terms and conditionsConditions, including customer debt collection;
Adhering to data security requirements in RCEA’s Information SecurityCustomer Confidentiality Policy8 and the CPUC’s Customer Data Privacy Decision 12-08-045. 8 https://redwoodenergy.org/wp-content/uploads/sites/850/2024/12/Customer-Confidentiality-Policy.pdf 67 12
2.2.7 Counterparty Credit Risk
Counterparty credit risk is the potential that a Counterpartycounterparty will fail to perform or meet its obligations in accordance with terms agreed to under contract. To control exposure toRCEA manages counterparty credit risk RCEAby:
AdheresAdhering to the limit controls set forth in the Credit Policy described in Section 6; RequiresAssessing credit risk of potential counterparties in the process of selecting offers to shortlist in response to RCEA’s power procurement solicitations; Requiring counterparties to post performance assurance in an acceptable form as part of long-term agreements; EnsuresEnsuring terms under which the performance assurance is drawn on, retained or returned to the counterparty are clearly defined and adhered to.
2.2.8 Reputation Risk
Reputation risk is the potential that the CCA’sRCEA’s reputation is harmed, causing customers to opt-out of the CCA’sCCA service and migrate backreturn to PG&E. To manageRCEA manages reputational risk RCEAby:
ImplementsImplementing and adheresadhering to this Energy Risk Management Policy; Establishes and adheresAdhering to industry best practices including both those adopted by otherand implementing lessons learned relevant to CCAs, as well as those adopted by and traditional municipal electric utilities;
MaintainsMaintaining a Community Advisory Committee (CAC) to support RCEA’s public engagement efforts and to provide decision-making support and input to the RCEA Board; ConsultsConsulting with general counsel and outside expert legal counsel on procurement processes and best practices as a public agency with respect to transparency and public participation;
ConductsConducting marketing and outreach activities that enhance RCEA’s reputation in the community, including monitoring and responding constructively to discussion of RCEA in traditional media and social media.;
Conducting periodic brand awareness studies to learn how the community perceives RCEA and what misconceptions they may have that need to be addressed.
2.3 Risk Measurement Methodology
A vital element in RCEA’s Energy Risk Management Policy is to routinely identify, measure, and communicate risk. To effectively communicate risk, all risk management activities must be monitored on a frequent basis using risk measurement methodologies that quantify the risks associated with RCEA’s procurement-related business activities and performance relative to goals.
Risk measurement of RCEA’s position uses a method that calculates projected procurement costs and portfolio value on an annual basis at various probabilities and that further provides a comparison of projected RCEA retail rates to those of PG&E. The rate comparison will be adjusted for actual and 68 13
projected PCIA and Franchise Fee charges. Risk measurement methodologies will be re-evaluated on a periodic basis to ensure RCEA and TEA adjust their methods to reflect the evolving regulatory and competitivemarket landscape. The implementation of these methods will be overseen and validated by TEA and ratified by the RMT.
Section 3: BUSINESS PRACTICES
3.1 General Conduct
It is the policy of RCEA that all personnel, including the Board, management, and agents, adhere to standards of integrity, ethics, conflicts of interest, compliance with statutory law and regulations and other applicable RCEA standards of personal conduct while employed by or affiliated with RCEA.
3.2 Trading for Personal Accounts
All RCEA Directors, management, employees, and agents participating in any transaction or activity within the coverage of this Policy are obligated to give notice in writing to RCEA of any interest such person has in any counterparty that seeks to do business with RCEA, and to identify any real or potential conflict of interest such person has or may have with regard to any contract or transaction with RCEA.
Further, all such persons are prohibited from personally participating in any transaction or similar activity that is within the coverage of this Policy and that is directly or indirectly related to the trading of electricity, capacity and/or environmental attributes as a commodity. The Risk Management Team voting members are further required by RCEA’s Conflict of Interest CodePolicy9 to file a Fair Political
Practices Commission Statement of Economic Interests form disclosing personal energy- and agency-related financial holdings annually.
If there is any doubt as to whether a prohibited condition exists, then it is the employee’s responsibility to discuss the possible prohibited condition with her/histheir manager or supervisor.
3.3 Adherence to Statutory Requirements
Compliance is required with rules promulgated by the state of California, California Public Utilities CommissionCPUC, California Energy Commission, California Air Resources Board, California Independent System Operator, Federal Energy Regulatory Commission ((“FERC),”), Commodity Futures Trading Commission ((“CFTC),”), Federal Trade Commission, and other regulatory agencies is required.
Congress, FERC and CFTC have enacted laws, regulations and rules that prohibit, among other things, any action or course of conduct that actually or potentially operates as a fraud or deceit upon any person in connection with the purchase or sale of electric energy or transmission services. These laws also prohibit any person or entity from making any untrue statement of fact or omitting to state a material fact where the omission would make a statement misleading. Violation of these laws can lead to both civil and criminal actions against the individual involved, as well as RCEA. This Policy is intended to comply with these laws, regulations, and rules and to avoid improper conduct on the part of anyone 9 https://redwoodenergy.org/wp-content/uploads/sites/850/2024/12/Conflict-of-Interest-Code-2024.pdf 69 14
employed by RCEA. These procedures may be modified from time to time by legal requirements, auditor recommendations, RMT requests, and other considerations.
In the event of an investigation or inquiry by a regulatory agency, RCEA will provide legal counsel to employees. However, RCEA will not appoint legal counsel to an employee if RCEA’s General Counsel and Executive Director determine that the employee was not acting in good faith within the scope of employment.
RCEA employees are prohibited from working for another power supplier, CCA, or utility in a related position while they are simultaneously employed by RCEA unless an exception is authorized by the Board. For clarity, this prohibition is not intended to prevent RCEA staff from performing non-CCA activities on behalf of RCEA in the normal course of its business. or participating in joint procurement activities with other CCAs. Participation by RCEA staff in power procurement activities of the California Community Power (CC Power) joint powers agency is permitted, as this procurement is done for the ultimate benefit of RCEA and CC Power’s other participating CCAs.
In addition, power purchase agreements and materials submitted in response to RCEA solicitations will be subject to disclosure in accordance with the California Public Records Act (Ca. Government Code section 6250 et seq.) and language reflecting this requirement will be included in RCEA solicitations and agreements. RCEA will withhold from public disclosure only those portions of solicitation materials and agreements which are exempt from disclosure under state law.
3.4 Transaction Type, Regions and Markets
Authorized transaction types, regions and markets are listed in Appendix A to this Policy. These transaction types, regions and markets are and shall continue to be focused on supporting RCEA’s financial policies, including the approved procurementenergy hedging strategy in Appendix DC. New or non-standard transaction types may provide RCEA with additional flexibility and opportunity but may also introduce new risks. Therefore, transaction types, regions, and markets not included in Appendix A, or transactions within already approved transaction types that are substantially different from any prior transaction executed by RCEA, must be approved by the RMT prior to execution using the process defined below.
When seeking approval for a new or non-standard transaction type, region, and/or market, a New Transaction Approval Form, as shown in Appendix B, should be drafted describingthe RMT shall discuss all known significant elements of the proposed transaction and addressingaddress all items listed in that form. below. The discussion shall be captured in meeting minutes and if approved, the transaction type shall be added to Appendix A upon the next revision of this Policy. Product description, including the purpose, function, expected impact on net revenues and/or benefit to RCEA.
Identification of the in-house or external expertise that will be relied upon to manage and support the new or non-standard transaction, including Middle Office workflows. Assessment of the transaction’s risks, including material legal, tax or regulatory issues, and how these risks will be managed by the limit structure.
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Proposed valuation and accounting methodologies.
Proposed reporting requirements, including any changes to existing procedures necessary to support the new product.
It is the responsibility of TEA’s Front Office to ensure that relevant departments have reviewed the proposed transaction and that material issues are resolved prior to submittal to the RMT for approval. If approved, Appendix A to the Policy will be updated to reflect the new transaction type.
3.5 Counterparty Suitability
TEA’s counterparty credit limits and approval processes will govern counterparty suitability for all transactions executed by TEA on behalf of RCEA. TEA will provide a credit review and recommendation, consistent with the credit policies described in Section 6, for any counterparty with whom RCEA contracts directly.
3.6 System of Record
TEA’s Middle Office will maintain a set of records for all transactions executed in association with RCEA procurement activities. The records will be maintained in US dollars and transactions will be separately recorded and categorized by type of transaction. This system of record shall be auditable.
3.7 Transaction Valuation
Transaction valuation and reporting of positions shall be based on objective, market-observed prices.
Open positions should be valued (marked-to-market) daily, based on consistent valuation methods, and data sources. Whenever possible, mark-to-market valuations should be based on independent, publicly available market information and data sources.
3.8 Stress Testing
In addition to limiting and measuring risk using the methods described herein, stress testing shall also be used to examine performance of the RCEA portfolio under adverse conditions. Stress testing is used to understand the potential variability in RCEA’s projected procurement costs, retail rates and resulting retail ratereserve impacts and competitive positioning, associated with low probability events. The TEA Middle Office will perform stress-testing of the portfolio as needed and distribute results. The Risk Management Team will provide guidance to TEATEA will consult with the RMT and RCEA staff as needed regarding what parameters should be stress tested and to what degree.
3.9 Trading Practices
The approved scope of market participation by RCEA is limited to those activities required to capture reasonably expected value and cost stability from RCEA’s resource portfolio without engaging in speculative or unauthorized trading activities. Staff and TEA may exercise some discretion on trade timing and volumes subject to exigent conditions (such as unusual weather, periods of illiquidity, load/generation deviations, and/or power system circumstances). RCEA procurement practices are intended to prohibit the acquisition of unwarranted or additional exposure to price and volume risk beyond that projected and associatedmodeled within the efficient utilization and optimization of RCEA’s 71 16
optimized resource portfolio. If any questions arise as to whether a particular transaction constitutes speculation, the RMT shall review the transaction(s) to determine whether the transaction would constitute speculation and document its finding in the meeting minutes.
3.10 Long‐Term Transactions
Procurement of products to be delivered for a term of 10 years or longer will normally be conducted by RCEA staff with advisory support from TEA, and result in direct bilateral contracts between RCEA and the seller. Such procurement will typically be performed competitively, by issuing solicitations with RCEA Board approval and using transparent and consistent evaluation criteria to select preferred offers for shortlisting and contract negotiation. Any contracts negotiated through this process will be taken to the RCEA Board for review and approval. , in accordance with Section 5 of this Policy. Similarly, termination of any long-term agreement in accordance with the contractual terms therein shall be subject to RCEA Board approval.
At times long-term procurement needs to be completed quickly for regulatory compliance purposes and normal competitive procurement cannot be performed in a timely manner. Examples of circumstances where this might occur include seller termination of existing contracts needed for compliance, previously contracted projects failing to meet development milestones, opportunities arising to procure products needed for compliance through amendment of existing contracts, or regulators issuing procurement orders that create a tight market where procurement options for compliance are very limited. In such instances, RCEA staff may in consultation with RCEA’s general counsel enter into direct bilateral negotiations with a seller identified as offering a product that meets the compliance need at a reasonable price. RCEA staff will consult with TEA staff to determine whether the offered price is consistent with market prices for said product, or negotiate as needed with the seller to arrive at such a price. RCEA Board approval will be required for such bilaterally procured long-term contracts, with staff providing a written explanation of the procurement method that was utilized.
RCEA may from time to time enter into agreements to restructure or prepay selected long-term power purchase agreements in order to achieve cost savings. Such arrangements will be subject to the delegation of authority limits identified in Section 5 of this policy.
Section 4: ORGANIZATIONAL STRUCTURE AND RESPONSIBILITIES
4.1 Risk Management Organizational Structure
Below is a high-level organization chart describing RCEA’s risk management governance. 72 17
4.2 Board of Directors
The RCEA Board of Directors has the responsibility to review and approve this Policy, including the composition of the Risk Management Team. With this approval, the Board assumes responsibility for understanding the risks RCEA is exposed to due to CCA program activity and how the policies outlined in this document help RCEA manage the associated risks. The Board of Directors is also responsible for:
Determining RCEA’s strategic direction
Understanding the procurement strategy employed
Approving risk exposures beyond the RMT’s authority
4.3 Risk Management Team (RMT)
The RMT is responsible for implementing, maintaining and overseeing compliance ofwith this Policy.
The voting members of the RMT shall be RCEA staff members as outlined in this Policy. Additionally, an independent outside third-party representative, and TEA’s account director assigned to RCEA, will serve as non-voting members. Each voting member will be assigned one vote. The current voting members of the RMT are:
Executive Director
Deputy Executive Director
Director of Power Resources
Director of Infrastructure Planning and Operations
Director of Business Planning and Finance
The primary goal of the RMT is to ensure that the procurement activities of RCEA are executed within the guidelines of this Policy and are consistent with Board directives. The RMT is also responsible to consider and propose recommendations to this Policy when conditions dictate.
Board of Directors
Executive
Director
Director of
Power
Resources
Deputy
Executive
Director
Director of Business
Planning & Finance
TEA Account
Director
(non-voting)
Independent
Outside
Representative
(non-voting)
Board of Directors
Executive
Director
Director of
Power
Resources
Director of
Infrastructure
Planning &
Operations
Director of Business
Planning & Finance
TEA Client
Services Manager
(non-voting)
Independent
Outside
Representative
(non-voting)
Risk Management Team
73 18
Pursuant to direction from the Board of Directors and the limitations specified by this Policy, the RMT and the Executive Director maintain full authority over all procurement activities for RCEA. This authority includes, but is not limited to, taking any or all actions necessary to ensure compliance with this Policy.
The RMT is responsible for overseeing implementation of this Policy, procurement strategies, and the adoption of new product types. The RMT is also responsible for ensuring procurement strategies are consistent with RCEA’s strategic objectives and for reviewing financial results. The RMT shall meet at least quarterly and record business in meeting minutes that will be approved by the RMT. No decision of the RMT is valid unless a majority of voting members has stated approval with a quorum of voting members participating in the vote, including the Executive Director. A quorum consists of a simple majority of RMT voting members, i.e. three of the four voting members. All decisions by the RMT, other than those made by common consent, shall be made by simple majority vote of the RMT members with the Executive Director having veto authority. Any Executive Director veto of a decision approved by the other three voting RMT members shall be presented to the RCEA Board of Directors at the Board’s next scheduled meeting. When urgency requires, the RMT can review and vote by email on procurement decisions outside of its regular scheduled meetings, with the non-voting RMT members kept informed of the vote and any discussion preceding it.
The RMT maintains the authority and responsibility to:
Approve and ensure that all procurement strategies are consistent with this Policy; Determine if changes in procurement strategies are warranted; Approve new transaction types, regions, markets and delivery points; Understand financial and risk models used by TEA;
Understand counterparty credit review models and methods for setting and monitoring credit limits;
Receive and review reports as described in this Policy; Meet to review actual and projected financial results and potential risks; Authorize individual transactions that exceed the Executive Director’s authority as indicated in Section 5 below;
Escalate to the Board of Directors with any risks beyond the RMT’s authority; Review summaries of limit violations (see Section 5.1); Review the effectiveness of RCEA's energy risk measurement methods; Maintain this Policy;
Monitor regulatory and legislative activities.
4.4 Power Manager
RCEA has partnered with TEA as its Power Manager. TEA, as outlined in its Riskthis Policy, maintains a strong segregation of duties, also referred to as "separation of function" that is fundamental to manage and control the risks outlined in this Policy. The Power Manager will provide education to the RMT on the risk and credit models, methods, and processes that it uses to fulfill its obligations under this Policy.
Individuals responsible for legally binding RCEA to a transaction will not also perform confirmation, or 74 19
settlement functions. With this in mind, TEA’s responsibilities are divided into front-middle-back office activities, as described below.
4.4.1 Power Manager ‐ Front Office
The Power Manager’s Front Office has overall responsibility for (1) managing all commodity and transmission activities related to procuring and delivering resources needed to serve RCEA's load, (2) the analysis of fundamentals affecting load and supply factors that determine RCEA's net position, and (3) transacting within the limits of this Policy, and associated policies, to balance loads and resources, and maximize the value of RCEA's assets through the exercise of approved optimization strategies.
Other duties associated with the Power Manager’s Front Office include:
a. Assist in the development and analysis of risk management hedging products and strategies, and bring recommendations to the RMT
b. Prepare each month a monthlyan operating plan for the prompt months that gives direction to the day-ahead and real-time trading and scheduling staff regarding the bidding and scheduling of RCEA's resource portfolio in the CAISO market
c. Develop, price, negotiate and execute all approved transactions within TEA’s delegation of authority
d. Forecast day-ahead and monitor / forecast same-day loads e. Keep accurate records of all executed transactions
4.4.2 Power Manager – Middle/Back Office
The Power Manager Middle Office provides independent market and credit risk oversight. The Power Manager Middle Office is functionally and organizationally separate from the Front Office. The Power Manager Back Office provides support with a wide range of administrative activities necessary to execute and settle transactions and to support the risk control efforts (e.g. transaction entry and/or checking, data collection, billing, etc.) consistent with this Policy. The Power Manager Back Office is also functionally and organizationally separate from the Front Office.
The Power Manager’s Middle and Back Offices have primary responsibility for trading control and for ensuring agreement with counterparties regarding the terms of all trades, including forward trading.
The Power Manager’s Middle and Back Offices have the primary responsibility to:
a. Estimate and publish daily forward monthly power and natural gas price curves for a minimum of the balance of the current year through the next calendar year b. Calculate and maintain the net forward power positions of RCEA c. Ensure that RCEA adheres to all risk policies and procedures of both RCEA and the Power Manager in letter and in intent
d. Maintain the overall financial security of transactions undertaken by the Power Manager on behalf of RCEA
e. Implement and enforce credit policies and limits
f. Handle confirmation of all transactions and reconciling differences with the trading counterparties
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g. Review trade tickets for adherence to approved limits h. Ensure all trades have been entered into the appropriate system of record i. Ensure that both pre-schedule and actual delivery volumes and prices are entered into the physical database
j. Carry out month-end checkout of all transactions each month k. Review models and methodologies and recommending RMT approval l. Provide supporting documentation for power supply audits m. Prepare and issue invoices for review and payment by RCEA n. Validate PPA settlement data from counterparties for invoicing Section 5: DELEGATION OF AUTHORITY
By adopting this Policy, the RCEA Board is explicitly delegating operational control and oversight to the RMT and Power Manager, as outlined through this Policy. Specifically, to facilitate daily operations of the CCA, the Board is delegating transaction execution and termination authorities shown in the table below.
Position
Maturity
Limit Term Limit
Energy Transaction
Volume Limit
(MWh)
Capacity
Transaction Value
Limit
RCEA Board of Directors Any transaction that exceeds the Risk Management Team limits Risk Management Team 42 Months 36 Months 500,000 $18,000,000 Executive Director 39 Months 30 Months 375,000 $12,000,000 TEA 36 months 24 Months 250,000 $6,000,000
These authorities will be applied to wholesale power activity executed outside of the California Independent System Operator (“CAISO”) markets. These limits provide both RCEA and TEA needed authorities to manage risks as they arise. Transactions falling outside the delegations above require Board approval prior to execution. or termination. Activity within CAISO markets is excluded from this table due to the nature of the markets, where prices for activity may not be known until after transactions are committed.
In the event that the Executive Director assigns a designee to whom to delegate Executive Director level authority, the designee must be RCEA staff in the Director or Acting Director classification. The designation must be made in writing with a well-definedan end date. The designation notice must be sent to the Power Manager and a copy of the designation will be kept in RCEA files.
All procurement executed under the delegation above, must align with RCEA’s underlying risk exposure (load requirements, locational and temporal) that is being hedged consistent with the approved 76 21
Guidelines for the Redwood Coast Energy Authority Community Energy Program Launch-Period Strategy and Targets,10 any subsequent procurement strategies or financial management policies authorized by the Board, and the Energy Risk Hedging Strategy (Appendix D to this policy).Energy Risk Hedging Strategy in Appendix C, RCEA’s most recent Integrated Resource Plan, and any other Board-approved procurement strategies.
5.1 Monitoring, Reporting and Instances of Exceeding Risk Limits The TEA Middle Office is responsible for monitoring, and reporting compliance with, all limits within this Policy. If a limit or control is violated, the TEA Middle Office will send notification to the trader responsible for the violation and the RMT. The RMT will discuss the cause and potential remediation of the exceedance to determine next steps for curing the exceedance. RCEA Power Resources staff are also responsible for monitoring transactions reported by TEA and bringing to the RMT’s attention any violations of limits within this Policy that have not been noted by TEA.
Section 6: CREDIT POLICY
Transactions are executed on RCEA’s behalf by TEA through TEA agreements, and with this activity RCEA is exposed to pass-through credit risk. As RCEA builds its own counterparty master trading agreements, transactions executed through RCEA agreements will carry direct credit risk. For activity on TEA and/or RCEA agreements, RCEA will adopt a scaling methodology to adjust TEA’s credit limits to RCEA’s risk tolerance. TEA shall assist RCEA in setting its own risk tolerance and defining the scaling methodology, based on TEA’s credit risk processes. For scaling with RCEA counterparties, where an agreement exists between RCEA and an entity, the RMT will approve changes to credit limits, otherwise TEA will automatically scale the TEA limit to the RCEA risk tolerance.
All procurement activities executed by TEA on behalf of RCEA, using TEA’s counterparty agreements, will be subject to the credit policies and procedures outlined in TEA’s Energy Risk Management Policy. TEA’s credit policy requires that all counterparties be evaluated for creditworthiness by the TEA Middle Office prior to execution of any transaction and no less than annually thereafter. Additionally, counterparties shall be reviewed if a change has occurred, or perceived to have occurred, in market conditions or in a company’s management or financial condition. This evaluation, including any recommended increase or decrease to a credit limit, shall be documented in writing and includes all information supporting such evaluation in a credit file for the counterparty. A credit limit for a counterparty will not be recommended or approved without first confirming the counterparty’s senior unsecured or corporate credit rating from one of the nationally recognized rating agencies and/or performing a credit review or analysis of the counterparty’s or guarantor’s financial statements. The TEA credit analysis shall include, at a minimum, current audited financial statements or other supplementary data that indicates financial 10 https://redwoodenergy.org/wp-content/uploads/sites/850/2024/12/Community-Energy-Program-Launch-Strategy.pdf 77 22
strength commensurate with an investment grade rating. Trade and banking references, and any other pertinent information, may also be used in the review process.
Counterparties that do not qualify for a credit limit or wish to enter into a transaction exceeding their credit limit must post an acceptable form of credit support or prepayment prior to the execution of any transaction. A counterparty to TEA may choose to provide a guarantee from a third party, provided the third party satisfies the criteria for a credit limit as outlined in TEA’s Energy Risk Management Policy.
For direct transactions with counterparties, RCEA generally does not accept guarantees as credit support. Exceptions may be made for counterparties that have an established history of doing business with RCEA, or where the guarantee is provided by a guarantor deemed highly trustworthy by RCEA.
6.1 Credit Limit and Monitoring
The TEA Middle Office will establish continuous monitoring of the current credit exposure for each Counterparty with whom TEA transacts on behalf of RCEA and include such information in the Current Counterparty Credit Risk Report. This report will be made available, reviewed, and communicated to the RMT pursuant to the reporting requirements outlined in Section 7.
Section 7: POSITION TRACKING AND MANAGEMENT REPORTING
Minimum reporting requirements are shown below. The reports outlined below are made available to RMT members by TEA:
Daily Financial Model Forecast
Latest projected financial performance, marked to current market prices, and shown relative to financial goals.
Monthly Net Position Report
Forward net position report that is presented monthly to the RMT. Daily Credit Report
This report shows how credit exposure for the transactions that TEA executes on behalf of RCEA passes through TEA to RCEA.
Monthly Risk Analysis
Cash flow at risk and stress testing of the financial forecast relative to financial goals. Recurring Board Risk Report
Update on activities and projected financial performance that is presented at minimum semiannually at RCEA Board meetings.
Unrealized Position Details
Current Projected Power Supply Costs Compared to Budget 78 23
Cash Flow at Risk
Renewable and Carbon-Free Fuel Generation Portfolio Content Section 8: POLICY REVISION PROCESS
RCEA’s Energy Risk Management Policy will evolve over time as market and business factors change. At least on an annual basis, the RMT will review this Policy and associated procedures to determine if they should be amended, supplemented, or updated to account for changing business and/or regulatory requirements. If an amendment isrevisions are warranted, the revised Policy amendment will be submitted to the RCEA Board for approval. Changes to appendices to this Policy may be approved and implemented by the RMT, with notification of the RCEA Board as indicated in Section 1.4.
8.1 Acknowledgement of Policy
Any RCEA employee participating in any activity or transaction within the scope of this Policy shall sign, at time of hire and upon any Policy revision, a statement approved by the RMT that such employee:
Has read RCEA’s Energy Risk Management Policy
Understands the terms and agreements of said Policy
Will comply with said Policy
Understands that any violation of said Policy shall be subject to employee discipline up to and including termination of employment.
See Appendix ED for a statement form.
8.2 Policy Interpretations
Questions about the interpretation of any matters of this Policy should be referred to the RMT.
All legal matters stemming from this Policy will be referred to RCEA’s General Counsel. 79 24
Appendix A: AUTHORIZED TRANSACTION TYPES OR PRODUCTS
All transaction types listed below must be executed within the limits set forth in this Policy. (The following transaction types can be Nonstandard, as defined in this Policy, subject to RMT approval) Over the Counter Products
CAISO Market Products
o Day-ahead and Real-time Energy
o Congestion Revenue Rights
o Convergence
o Inter Scheduling Coordinator Transactions
o Tagging into and out of CAISO
o Ancillary Services
Physical Power Products
o Short and Long-Term Power
o Physical OTC Options
Physical Resource Adequacy Capacity
Physical Environmental Products
o Renewable Energy Credits
o Specified Source Power
o Carbon Allowances and Obligations
o Low Carbon Fuel Standard Credits
Transmission Access Charges
Energy Storage, including time-based arbitrage (selling stored energy into the grid during peakhigh-price hours and buying energy to store during off-peaklow-price hours) Any other products associated with energy generation, demand response, or other energy markets relevant to RCEA activities.
The point of delivery for all products must be at a location within the CAISO service area. 80 25
Appendix B: NEW TRANSACTION APPROVAL FORM
New or Non-Standard Transaction Approval Form
Prepared By:
Date:
New or Non-Standard Transaction Name:
Business Rationale and Risk Assessment:
Product description – including the purpose, function, expected impact on net revenues (i.e. increase, manage volatility, control variances, etc.) and/or benefit to RCEA Identification of the in-house or external expertise that will be relied upon to manage and support the new or non-standard transaction
Assessment of the transaction’s risks, including any material legal, tax or regulatory issues How the exposures to the risks above will be managed by the limit structure Proposed valuation methodology (including pricing model, where appropriate) Proposed reporting requirements, including any changes to existing procedures and system requirements necessary to support the new product
Proposed accounting methodology
Proposed Middle Office workflows/methodology, including systems Brief description of the responsibilities of various departments within RCEA who will have any manner of contact with the new or non-standard transaction Reviewed by:
Director of Power Resources Date
TEA Representative Date
Executive Director Date
81 26
Appendix C: DEFINITIONS
Back Office: That part of a trading organization which handles transaction accounting, confirmations, management reporting, and working capital management.
Bilateral Transaction: Any physical or financial transaction between two counterparties, neither of whom is an Exchange or market entity (e.g. CAISO).
Cash Flow at Risk: A probability-based measure of the extent to which future cash flows may deviate from expectations due to changes in load, generation and/or market prices of energy. (For RCEA, the most relevant Cash Flow at Risk metric is a measure of the potential for net revenues to deviate from the current forecast.)
CAISO: California Independent System Operator. CAISO operates a California bulk power transmission grid, administers the State’s wholesale electricity markets, and provides reliability planning and generation dispatch.
CCA: Community Choice Aggregator. CCAs allow local government agencies such as cities and/or counties to purchase and/or develop generation supplies on behalf of their residents, businesses, and municipal accounts.
CFTC: Commodity Futures Trading Commission. The CFTC is a U.S. federal agency that is responsible for regulating commodity futures and swap markets. Its goals include the promotion of competitive and efficient futures markets and the protection of investors against manipulation, abusive trade practices and fraud.
Commodity: A basic good used in commerce that is interchangeable with other goods of the same type.
Commodities are most often used as inputs in the production of other goods or services. The quality of a given commodity may differ slightly, but it is essentially uniform across producers. When they are traded on an exchange, commodities must also meet specified minimum standards, also known as a basis grade.
Confirmation Letter: A letter agreement between two counterparties that details the specific commercial terms (e.g., price, quantity and point of delivery) of a transaction.
Congestion Revenue Right: A point-to-point financial instrument in the Day-Ahead Energy Market that entitles the holder to receive compensation for or requires the holder to pay certain congestion related transmission charges that arise when the transmission system is congested.
Counterparty Credit Risk: The risk of financial loss resulting from a counterparty to a transaction failing to fulfill its obligations.
Day-ahead Market: The short-term forward market for efficiently allocating transmission capacity and facilitating purchases and sales of energy and scheduled bilateral transactions; conducted by an Organized Market prior to the operating day.
Delivery point: The point at which a commodity will be delivered and received.
Departing load: Load associated with a retail electricity consumer that elects to purchase generation services from an Energy Service Provider or Community Choice Aggregator rather than the local Investor Owned Utility.
82 27
FERC: Federal Energy Regulatory Commission. FERC is a federal agency that regulates the interstate transmission of electricity, natural gas and oil. FERC also reviews proposals to build liquefied natural gas terminals, interstate natural gas pipelines, as well as licenses hydroelectric generation projects.
Front Office: That part of a trading organization which solicits customer business, services existing customers, executes trades, and ensures the physical delivery of commodities.
Franchise Fee: A franchise fee is a percentage of gross receipts that an IOU pays cities and counties for the right to use public streets to provide gas and electric service. The franchise fee surcharge is a percentage of the transmission (transportation) and generation costs to customers choosing to buy their energy from third parties. IOUs collect the surcharges and pass them through to cities and counties.
Hedging Products: Capacity, energy, renewable energy credits, or other products related to a specific transaction.
Hedging Transaction: A transaction designed to reduce the exposure of a specific outstanding position or portfolio; “fully hedged” equates to complete elimination of the targeted risk and “partially hedged” implies a risk reduction of less than 100%.
Illiquidity: occurs when an asset cannot easily and quickly be sold or exchanged for cash without a substantial loss in value.
Investor Owned Utility (IOU): A business organization providing electrical and/or natural gas services to both retail and wholesale consumers and is managed as a private enterprise.
Limit structure: A set of constraints that are intended to limit procurement activities.
Limit violation: Any time a defined limit to transacting authority is violated.
Liquidity: efficiency or ease with which an asset can be transacted without affecting its market price.
Maturity Limit: timespan between when a transaction is approved and the end date for delivery of product under the transaction.
Middle Office: That part of a trading organization that measures and reports on market risks, develops risk management policies and monitors compliance with those policies, manages contract administration and credit, and keeps management and the Board informed on risk management issues.
Net Forward Position: A forecast of the anticipated electric demands of a load serving entity compared to existing resource (generation and/or power purchase agreements) commitments.
Nonstandard: Any product that is not commonly transacted among market participants in forward markets. The nonstandard attribute of the product could be a function of a number of factors such as volume, delivery period and/or term.
Opt-out Rate: Typically expressed as a percentage, the Opt-out Rate measures the portion of eligible customers of a CCA that have elected to remain a bundled service customer of the IOU rather than take generation services from the CCA.
PCIA: Power Cost Indifference Adjustment. The PCIA is intended to compensate IOUs for their stranded costs when a bundled customer departs and begins taking generation services from a CCA.
Prompt: period immediately following the current period, e.g. in February the prompt month is March. 83 28
Scheduling: The actions of the counterparties to a transaction, and/or their designated representatives, of notifying, requesting and confirming to each other the quantity and type of product to be delivered on a given day.
Separation of function: Also referred to as “segregation of duties,” part of a complete risk control framework. to ensure business integrity. Individuals responsible for legally binding the organization to a transaction should not also perform confirmation, clearance, or accounting functions.
Settlement: Settlement is the process by which counterparties agree on the dollar value and quantity of a commodity exchanged between them during a particular time interval.
Speculation: The act of trading an asset with the expectation of realizing financial gain resulting from a change in price in the asset being transacted. (See discussion in sections 1.1 and 3.9 that elaborates on discretion staff and third-party service providers are allowed in conducting trading activities.) Stranded cost: Generation costs that a load serving entity is allowed to collect from customers through retail rates but that will not be recovered if the generation is sold in wholesale electricity markets.
Stress testing: The process of simulating different financial outcomes to assess potential impacts on projected financial results. Stress testing typically evaluates the effect of negative events such as unfavorable changes in market prices, or non-delivery of contracted products to help inform what actions may be taken to lessen the negative consequences should such an event occur.
Term Limit: Timespan between the start and end dates of delivery of product under a transaction.
84 29
Appendix DC: ENERGY RISK HEDGING STRATEGY
Introduction
The Redwood Coast Energy Authority (RCEA) is routinely exposed to commodity price risk and volume variability risk in the normal conduct of serving the power supply requirements of its residential and business customersretail customer load as part of its CCA program.
This Energy Risk Hedging Strategy (Strategy) describes the strategy and framework that RCEA uses to hedge the power supply requirements of its customers during the current calendar year plus next two calendar years. The Strategy details procurement schedules, or where appropriate justifies the decision not to set schedules, for attaining wholesale, market-based products required to support the CCA program portfolio. Specific focus is on procurement of the following products:
Fixed Price Energy (also known as system power or energy hedges) Portfolio Content Category 1 Renewable Energy
Portfolio Content Category 2 Renewable Energy
Portfolio Content Category 3 Renewable Energy
Carbon Free Energy
Resource Adequacy Capacity
Congestion Revenue Rights
In addition to market-based transactions entered into pursuant to this Strategy, RCEA will also procure assets, enter into long-term power purchase agreements (PPAs) and resource adequacy (RA) contracts pursuant to statutory and regulatory requirements, including: the SB 350 mandate to procure a minimum of 65 percent of RPS-required energy from 10-year or longer PPAs or RCEA-owned resources beginning in Compliance Period 4; the CPUC’s November 2019 IRP Procurement Track Decision Requiring Electric System Reliability Procurement for 2021-2023; and the CPUC’s June 2021 Mid-Term Reliability Decision.and the CPUC’s procurement orders issued to LSEs in the Integrated Resource Planning proceeding. Additionally, RCEA may enter into voluntary long-term resource acquisitions pursuant to its Integrated Resource Plan and policy goals established by its Board of Directors. Long-term PPAs will count as hedges as described later in this Strategy.
Governance
This Strategy shall be updated, as necessary, from time to time and governed by the Energy Risk Management Policy (“Policy”) approved by the RCEA’s Board of Directors in December 2016 and reviewed annually with updates as needed (Risk Policy)..
Hedging Program Goals
The overall goals of the Strategy are to identify exposure to commodity prices, quantify the financial impact that variability in commodity prices, load requirements, and generation output may have on the ability of the RCEA to meet its financial program goals, and then manage the associated risk. 85 30
To help ensure long-term viability for the CCE, RCEA has outlined the following Policy Goals. These goals will establish metrics used for modeling and measuring risk exposures of the CCE program. RCEA will targetaims to maintain competitive retail rates with PG&E after adjusting for the PCIA and Franchise Fee, while ensuring RCEA’s revenue requirement is met. RCEA will targetis funding financial reserves in support of the following objectives per its Reserve Policy:
o EstablishMaintain long-term business sustainabilityRCEA financial independence and rate stability,
o Build collateral for power procurement activities
o Establish and maintain an investment grade Meet RCEA strategic objectives, o Secure favorable commercial terms with vendors and power providers, o Support RCEA’s pursuit of, and maintenance upon receiving, a credit rating, o DevelopProvide a source of funds for investment in local generation and customer programs
o Stabilize rates and buffer against year-to-year variability in procurement costs o Reduce monthly fee paid to TEA for provision of credit facilityunanticipated expenditures, and avoid or minimize buyer credit postings required by counterparties under long-term contracts
o Make cash available for other operational needs as approved by the Board. RCEA set an initial target to procure 40 percent of its power supply requirements from renewable energy and 80 percent of its power supply requirements from non-fossil fuel generation, with a goal of procuring 100 percent renewable power from local sources by 2030. This long-term goal was established in the RePower Humboldt study that formed the original impetus for developing RCEA’s CCA program. More recently, RCEA has set a goal to procure all energy from clean and renewable sources (though not necessarily local sources) by 2025. In 2024, the RCEA Board elected to delay the 2025 goal to 2026 to mitigate short-term financial challenges. Under this goal, RCEA may include a mix of RPS and carbon-free resources in its portfolio. RCEA is targeting 100 percent carbon-free and renewable energy on an annual basis from 2025 to 2029 and 100 percent renewable energy on an annual basis by 2030 and thereafter.
All hedging activities will be conducted to achieve results consistent with the above Policy Goals, the aforementioned compliance obligations and to meet the power supply requirements of RCEA’s customers. Any transaction that cannot be directly linked to a strategic goal or requirement of serving RCEA’s customers, or that does not serve to reduce risk as measured by the Cash Flow at Risk Metric described below, is prohibited.
Prohibited Generation Sources
In keeping with community values identified by RCEA in developing its CCA program, neither energy nor resource adequacy (RA) will be procured from the following generation sources:
86 31
Nuclear generation
Coal generation
Exceptions to this prohibition may be needed for occasional short-term transactions, such as procurement of replacement RA. Per current State policy on the extensionDuring extended operations of Diablo Canyon Nuclear Power Plant operations through 2030 with cost recovery via the Public Purpose Programs charge on ratepayer bills, RCEA expects to beis offered an allocation of its pro rata share of this power annually until plant closure. Each year during the extended operating period, RCEA staff will ask the Board to consider acceptingonly accept this allocation with ad hoc approval from the Board under short-term exceptions to the above policy.prohibition.
Hedging Targets and Strategies
The time horizon for the hedging program will be the prompt three (3) years. The energy hedging schedules described in the Fixed Price Energy section below provide a disciplined approach to procurement by mandating targeted hedge levels to be achieved by definite dates. This commonly utilized approach is intended to mitigate speculation of future wholesale market prices while also spreading procurement over a multi-year period. A key goal of the CCA program is to reduce energy price uncertainty for the upcoming operating year(s) by procuring at least 70 percent and up to 100 percent of its energy needs with fixed price contracts thereby mitigating exposure to unexpected price movement. RCEA and TEA will generally observe these adopted hedge schedules for each of the following energy and capacity products, to provide discipline on the minimum hedge level side and as protection for over-hedging on the maximum hedge level side. Changes in regulatory, load, and market dynamics may warrant occasional under- or over-hedging and subsequent remarketing of over-procured products.
RCEA currently does not have programmatic procedures assigned to Renewable Portfolio Standard, Carbon Free Energy, or Resource Adequacy products. Procurement of these products is primarily driven by RCEA Board-adopted goals and regulatory compliance requirements, which in many cases apply prescribed hedging schedules, as further described in the respective sections below.
Fixed Price Energy
A challenge in using renewable generating resources to meet the energy requirements of customers is that the generation profile of renewable resources often does not align with the consumption patterns of the residences and businesses consuming the electricity users. Fixed price energy products, including block energy, shaped energy and options, are used to manage the electricity commodity price risk that RCEA faces as a result of this uncertainty. Fixed price energy provides for the supplier to deliver a predetermined volume of energy, at a constant delivery rate, for a fixed price. Specific to RCEA’s customers, Fixedfixed price energy hedges are used to provide cost certainty and rate stability. 87 32
When assessing its requirements for fixed price energy, RCEA will forecast the monthly energy requirements of its customers during heavy and light load hours11 each month as well as the forecasted output from resources in its portfolio. Forecast load will be determined through use of an econometric model that forecasts both total energy usage and peak demand by customer load class. The model will useuses historical data to estimate relationships between energy consumption and economic, demographic and/or weather variables. The econometric model is refined as additional load data is acquired through program operation. Forecasted output from resources is based on generation forecasts provided by counterparties, which are risk-adjusted based on a variety of factors such as developmental delays, curtailment, underperformance, and other forecast and observed outcomes.
The targets below describe minimum and maximum percent hedge targets for identified future time periods. The definition of “Hedge %” in this context is the total fixed price megawatt hours (MWh) procured in the period divided by the total forecast load in MWh inclusive, as applicable, of the energy forecast to be provided by PPAs and other long-term resources within RCEA’s portfolio during respective time periods.
RCEA will observe the following schedule when hedging its Fixed Price Energy requirements:
Time Period Minimum Hedge % Maximum Hedge %
Prompt Month (Jan-March/Q1) 80% 115120%
Prompt Month (April-June/Q2) 70% 105110%
Prompt Month (July-Sep/Q3) 8075% 125115%
Prompt Month (Oct-Dec/Q4) 7080% 115120%
Prompt Calendar Year (PCY) 70% 100110%
PCY +1 50% 100%
PCY +2 30% 100%
The hedge schedule for the Prompt Month will be measured five calendar days prior to the first day of the particular month (e.g. on January 27, 20232026, RCEA will have hedged 80 to 115120 percent of its projected energy requirements during February 20232026, which is in Q1).
The hedge schedule for the Prompt Calendar Year (PCY), as well as subsequent two calendar years, will be measured ten calendar days prior to each new calendar year (e.g. on December 21, 20212026, RCEA will have hedged at least 70 percent of its forecast energy requirements for CY 20222027, 50 percent of its forecast energy requirements for CY 20232028, and 30 percent of its forecast energy requirements for CY 2024, and not more than 100% of its forecast energy requirements for any of these PCYs).2029.
Peak / Heavy Load Hour (HLH) Energy Minimum Hedge
The targets described above represent total fixed-price MWh procured compared to total MWh load forecasts. They are intentionally not prescriptive regarding diurnal periods (HLH/LLH or Peak/Off Peak) which allows flexibility in procurement strategy given rapidly evolving market dynamics. Historically Peak/HLH periods contain the most price risk. Accordingly, RCEA additionally requires HLH periods to 11 Heavy Load (on-peak) Hours in current wholesale energy markets are 6am to 10pm, Monday through Saturday, excluding New Years, Memorial Day, 4th of July, Labor Day, Thanksgiving and Christmas. All other hours during the year are considered Light Load (off-peak) Hours.
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be procured to a minimum 100% hedged level, using the same definition above, for Prompt Months.
This allows RCEA to weight hedge coverage within overall parameters toward diurnal periods of greatest risk, which vary seasonally, and are not always contained in “Peak” hours.
Summer Assessment
RCEA will complete a Summer Assessment of market risk and hedging plan within 30 days of CAISO’s issuance of their Summer Assessment each year. This work product will then be shared in draft form with the RCEA Risk Management Team and will include:
analysis of summer exposure,
fundamental analysis of market conditions,
hourly load/resource balance forecast for June-September, and recommendations on products and target hedge levels designed to mitigate peak hour and daily HLH exposure.
Although compliance with the Fixed Price Energy schedule above will be measured monthly, RCEA shall endeavor to complete all Q3 hedging prior to June 30 of each year, subject to and allowing for true-ups as load and generation profiles fluctuate throughout the summer season.
The purpose of these hedging transactions is to reduce variability of power supply costs by gradually increasing the amount of energy hedged as the date of consumption approaches. Time driven strategies avoid the inherent impossibility of trying to consistently and accurately “time the market” when making hedging decisions. Additionally, a load serving entity the size of RCEA needs to spread its procurement efforts over time to effectively manage the potential negative price impacts of procuring a large volume of energy over a short period of time in an illiquid market.
Hedging decisions to reach targets between the minimum and maximum hedge levels are based on price-driven or opportunistic strategies. The purpose of these strategies is to capitalize on market opportunities when conditions are favorable. RCEA bases its decision to execute opportunistic hedges on the impact to projected power supply costs and the resulting reduction in cash flow at risk (CFaR).
Opportunistic hedges may be executed when energy price levels are favorable to lowering the cost of power relative to CCA program goals and financial projections. Alternatively, opportunistic hedges can be executed in adverse market conditions relative to financial goals in order to reduce the potential negative impact of continued upward trending commodity prices relative to established goals.
In executing this strategy, fixed price energy hedges may be purchased, sold, or moved from one month to another for the purpose of maintaining hedge coverage that matches changes in forecasted electric load. This includes the ability of the RCEA to purchase standard products to hedge average loads over a defined time period and then later modify its portfolio by purchasing or selling more granular products to more precisely match load.
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Power Charge Indifference Adjustment
(PCIA) Exit Fee and Hedging with Fixed Price
Energy
Under the current PCIA construct, departing load
is responsible for costs associated with
procurement that the incumbent utility has
already done on behalf of that load. At the time of
departure, the applicable vintage portfolio12 then
serves as a hedge for the departing load in that as
market prices increase, the departing load
charges decrease, thereby reducing costs to CCA
customers relative to bundled customers.
Similarly, if market prices decrease, the departing
load charges increase, due to more of the vintage
portfolio being above market costs. PG&E’s 2017
Power Content Label provides the best estimate
of the percent of fixed price energy in PG&E’s
vintage portfolio associated with RCEA’s vintage
year of 2016 for the majority of its customer load.
One impact of the PCIA on RCEA is, therefore, the way it serves as a “lagging hedge” against energy price volatility. Increased market prices in one year will result in an all-else-equal lower PCIA in subsequent years, and vice versa, although the exact impact will depend on market-sensitive PG&E data that RCEA does not have access to. In lieu of better quantitiative data, hedging decisions will be made with the qualitative understanding that the PCIA may serve from a 5% to 20% “lagging hedge” on RCEA’s portfolio, dependent on market conditions and seasonality.
Compliance & Goal Driven Procurement
This section covers procurement undertaken primarily to meet compliance requirements set by regulatory authorities and/or to meet Board-adopted goals that underlie the purpose of RCEA’s existence as a local procurement agency.
Portfolio Content Category 1 Renewable Energy
RCEA has a compliance mandate to procure sufficient renewable energy to meet the state of California’s RPS requirements, based on multi-year compliance periods, as well as Board-adopted goals to procure a 100% renewable and carbon free energy portfolio byon an annual basis from 2025-2029 and a 100% local energy portfolio by 2030, subject to availability of sufficient local renewable energy resources.portfolio on an annual basis by 2030. These Board-adopted goals have resulted in RCEA’s 12 The vintage portfolio is generally all contracts and utility-owned generation that was procured while the departing load was still receiving bundled service.
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procurement significantly exceededexceeding state compliance mandates over most of the period RCEA has operated as a CCA.
In order to cost-effectively meet its GHG-reduction and renewable energy goals, RCEA intends to meetis meeting a growing share of its energy supply requirements with renewable energy, a large portion of which shall beis Portfolio Content Category (PCC) 1 renewable energy. PCC1 renewable energy is sourced from a renewable generator either located inside of California or from aRenewable Portfolio Standard (“RPS”) eligible generator that is directly interconnected to the California Independent System Operator (CAISO) or othera California Balancing Authority. For example, energy procured from local biomass generators is a source of PCC1 renewable energy.
RCEA’s eventual goal is to reach a steady state of procurement in which it meetsRCEA aims to meet the majority of its state-mandated and internal voluntary RPS requirements with long-term contracts. In this state, RCEA will executeRCEA does this by layering in PPAs over time and procuring new contracts when existing ones expire, based on an assumed average contract length of 15-20 years. Doing so will 1) allowallows RCEA to steadily reduce its exposure to renewable energy and energy market price risks in a fashion similar to the time-driven, programmatic hedging approach for fixed price energy and 2) ensureensures that RCEA is in a position to make strategic procurement decisions and commitments on a periodic basis. When available and economically feasible, RCEA will give preference to renewable generation located in either its Humboldt County service area or the Humboldt Local Capacity Area, as defined by CAISO.
RCEA has already procured several fixed-price long-term renewable contracts to support meeting RPS compliance mandates and Board-adopted goals, such that its long-term energy portfolio offsets energy price risk due to the corresponding decreased reliance on short-term energy procurement. As such, programmatic hedging targets for renewable and carbon free energy are a less effective hedging tool, and consequently do not provide incremental risk reduction given the complexities involved in establishing a growing long-term renewable portfolio.
As a result, RCEA staff undertake an annual assessment of the entirety of the CCA program’s renewable energy procurement activities with respect to both state compliance mandates and Board-adopted goals. This analysis, which includes qualitative and stochastic risk assessment, feeds into RCEA’s renewable procurement timelines as well as its annual RPS compliance filings. The analysis is updated on an ad hoc basis throughout the year as a function of changing market dynamics or new procurement mandates.
Portfolio Content Category 2 Renewable Energy
RCEA has the option to supplement its RPS portfolio with PCC2 renewable energy. PCC2 energy is sourced from renewable generators located outside the state ofnot directly connected to a California balancing authority and is “firmed and shaped” for reliable delivery into California. PCC2 purchases have historically been less expensive and shorter in term than PCC1, so they have provided a cost-effective and flexible method of augmenting RCEA’s renewable energy purchases to meet renewable portfolio content commitments to customers. However, recent changes tonarrowing of the price spread between PCC1 and PCC2 coupled with the greenhouse gas emissions accounting methodology via the California 91 36
Energy Commission’s Power Source Disclosure Program may reducefor imported power has reduced the economic benefit of the PCC2 product. PCC2 renewable energy is now ascribed the same carbon-intensity as “unspecified” system power unless matched one-to-one with carbon free energy. The procurement strategy of this product is thus dependent on the combined price of PCC2 and carbon free energy compared to the direct procurement of PCC1 energy, which receives a lower or zero carbon-intensity rating, dependent on fuel type. PCC2 purchases also require increased oversight of deliveries and compliance reporting, which further reduces the attractiveness of this product over PCC1 energy.
Portfolio Content Category 3 Renewable Energy
During most of the time it has operated as a CCA, RCEA has preferred procurement oftypically prefers the PCC1 and PCC2 products product over PCC3, or also known as unbundled renewable energy certificates, which is a lower value product due to its less strict chain of custody requirements. Given delays to long-term contracted projects, the recently increasing cost difference between (“RECs”), since PCC3 RECs and the PCC1 and PCC2 products, and difficulties in procuring enough of these productsdoes not provide energy to serve RCEA’s load and there is a limit on how many PCC3 RECs can be used to meet RPS and SB 350 requirements,. RCEA procures a limited quantity of PCC3 energy from carbon-free sources consistent with state lawRECs to hedge its RPS costs as needed for compliance costs...and economic purposes. RCEA’s Board has directed that any long-term contracts for PCC3 products shall be limited to emissions-free resources.
Carbon Free Energy
In pursuit of its GHG-reduction and non-fossil fuel portfolio objectives, RCEA shall augment its renewable energy purchases outlined above with energy purchases from carbon-free energy generating facilities, which are typically hydroelectric resources located in California that are too large to qualify as Eligible Renewable Resources (RPS resources (generally greater than 30 MW, with certain exceptions) or located outside of California. Similar to PCC2 renewable energy contracts, carbon-free energy purchases are typically short-term, most frequently one to three years in length. The majority of RCEA’s renewable energy is also carbon-free, which means that the analysis that drives RCEA’s renewable procurement decisions will also underliedetermine RCEA’s supplemental carbon free energy procurement. Due to this, RCEA staff intend to utilize the annual renewable procurement planning and analysis process to also plan for carbon free energy procurement rather than utilizing programmatic hedging targets. The purchase of carbon free energy is a voluntary goal set by the RCEA Board, who may elect to reduce the total quantity of carbon free energy included in RCEA’s portfolio as it seeks to balance multiple CCA program objectives, including financial targets for reserves and retail rates.
Although RCEA’s Energy Risk Management Policy generally prohibits procurement of carbon-free nuclear energy, the RCEA Board has made an exceptionexceptions to procureaccept allocations of energy from the Diablo Canyon nuclear power plant to be evaluatedPower Plant annually on an ad hoc basis, given that RCEA ratepayers are required to help pay for the extended operation of this facility to meet statewide electric reliability needs.
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Resource Adequacy Capacity
RCEA will use commercially reasonable efforts to comply with the filing requirements of the CAISO- and CPUC-administered Resource Adequacy (RA) program, currently:
90% of hourly System RA requirements and Flexible RA requirements procured prior to the year-ahead RA showing on October 31st of the year prior to the showing year. 100% of hourly System RA requirements and Flexible RA requirements procured prior to the month-ahead RA showings, due 45 calendar days prior to the first day of the showing month.
RA is typically transacted via contracts that vary in length from one month to three years, and it is currently bought and sold via a bilateral market, which can result in cost-effective contracting opportunities but is also sometimes fragmented and volatile. Due to the nature of RA markets, monthly products are often bundled with other products or “strips” of multiple months of RA, which may result in over-procurement for one or more months as a necessary condition to satisfy compliance requirements in one or more other months. Execution of long term PPAs can also lead to over-procurement of RA products for future years, and inclusion of a defined hedging matrix might require selling excess long-term RA to bring RCEA into hedging compliance, even though such action may not be in RCEA’s best business and operational interest. Lastly, compliance guardrails exist at the regulatory level which guide the RA procurement schedule for RCEA and all other LSEs.
Starting in the 2025 RA compliance year, the CPUC is implementingimplemented the Slice of Day framework, which transitionstransitioned RA compliance to be measured based on an hourly RA requirement for a modeled “highest load day” in each month... This has resulted in major changes to RA compliance requirements and RA markets, including accreditation of different technology types based on their hourly profiles and exceedance factors and requiring that generation capacity be shown by individual LSEs for energy charging sufficiency to be able to claim RA from energy storage resources.
Starting in the 2023 RA compliance year, procurement of local RA is solely the responsibility of the Central Procurement Entity (CPE) in PG&E’s service territory, the only territory in which RCEA serves load. Therefore, beyond 2022, RCEA no longer has had a regulatory obligation to procure or show local RA to the state agencies. Instead, RCEA has the option to self-show or sell its local RA capacity to the CPE to obtain some value for it. However, transacting local RA capacity with the CPE can limit RCEA’s ability to separately market the system or flex attributes of a given RA product when these attributes exceed RCEA’s compliance need, since the CPE refers to the volume of RA shown by RCEA in its compliance filings as the metric for compensating RCEA for local RA attributes.
Congestion Revenue Rights
RTO markets expose entities to financial basis risks between source and sink points that increase cashflow risks in a load serving entity’s portfolio. In order to manage this risk CAISO offers a financial product known as congestion revenue rights (CRRs) which can be allocated to an entity or purchased via the auction. RCEA uses both mechanisms to acquire necessary congestion hedges in on and off peak periods to reduce risk between generation or purchase locations and RCEA’s load point. As RCEA’s CRRs are used to manage a source-sink relationship consistent with utility hedging, exposure created by the CRR must be reasonably expected to have an offsetting effect on cashflow associated with the positions 93 38
that necessitated the CRR in the first place across the period. It is acknowledged however that due to discrepancies in granularity, these cashflows will never be fully symmetric.
TEA, acting as agent on behalf of RCEA, calculates a Total Dollar Stop-Loss designed to limit the amount of capital that could be consumed taking into consideration both realized and unrealized gains. For CRRs, TEA monitors a five percent outcome for CFaR for inclusion in the Total Dollar Stop-Loss value.
Once the Total Dollar Stop-Loss reaches the limit outlined in the Risk Management Policy all open position trading at TEA is ceased and positions are liquidated if needed.
CPUC Mandated Procurement
The 2018 and 2020 Integrated Resource Planning cycles resulted in all CPUC-jurisdictional LSEs, including RCEA, being mandated to procure a share of thenew capacity needed to help ensure the long-term reliability of the California power grid. This trend of mandating procurement may continuehas continued as California decarbonizes its electric grid while electrifying other sectors. RCEA will continuecontinues to meet allprocure pursuant to mandated capacity procurement requirements while attempting to procure low-cost resources that potentiallycan provide additional energy products aligned with RCEA’s procurement goals, such as local PCC1 energy.
Hedge Program Metrics
The success of the Energy Risk Hedging Strategy will be measured by realizing power supply costs in line with the budgeted power supply costs used to set customer rates, as well as by reducing RCEA’s exposure to commodity price risk. The following two metrics will be utilized to manage the Energy Risk Hedging Strategy:
Current projected power supply costs will be compared to budgeted power supply costs where budgeted costs will be based on the assumptions used at the time customer generation rates are set. Current power supply costs shall use all fixed price contracts executed as of the date of the report. All open positions will be marked to market and compared to the budgeted power supply costs.
Cash Flow at Risk (CFaR). CFaR represents a statistical view of what could happen to RCEA’s power supply costs and CRR portfolio assuming that no action is taken to manage its portfolio from the date of the analysis through the end of the period of time being analyzed. The potential CFaR will be calculated using a historical sampling methodology that considers on- and off-peak periods separately over the remaining life of the transactions. The CFaR calculation will consider potential variability in load and generation supply. The CFaR will be calculated by rank ordering the portfolio cost and measuring the difference between the 95th percentile and the expected power cost outcome.
These metrics will be reviewed when making price-driven or opportunistic hedging decisions to ensure that the transactions are consistent with the goals of the Energy Risk Hedging Strategy. These metrics will be updated and reported by TEA to RCEA on a monthly basis. 94 39
Reporting Requirements
The reports that are required to manage the hedge program and to ensure its success are listed in Section 7 of the Riskthis Policy.
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Appendix ED: ACKNOWLEDGMENT OF ENERGY RISK MANAGEMENT
POLICY
I, (print name and title of RCEA employee)
________________________________________________________________ hereby attest that I:
Have read RCEA’s Energy Risk Management Policy
Understand the terms and agreements of said Policy
Will comply with said Policy
Understand that any violation of said Policy shall be subject to employee discipline up to and including termination of employment.
___________________________________ ____________________________________ Employee signature Date
This form is to be completed and signed at time of hire and upon any Policy revision by any RCEA employee participating in any activity or transaction within the scope of RCEA’s Energy Risk Management Policy.
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Staff Report
Agenda Item # 10.1
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Faith Carlson, Regulatory and Legislative Policy Manager Subject Power Charge Indifference Adjustment Update
Background
The report provides an update on the Power Charge Indifference Adjustment (PCIA), explaining its background, recent changes, and impacts on Community Choice Aggregators (CCAs) and customers.
Defining the Power Charge Indifference Adjustment
Prior to the inception of CCAs, the Investor-Owned Utilities (IOUs) served electricity generation to all customers within their territory, and as such the IOUs built or contracted generation resources for all those customers.
As municipalities and CCAs were established within IOU territories, IOUs argued that they would not have taken up these procurement commitments had they known they would later not have to serve the load for these customers.
State law guarantees IOUs recovery of costs associated with generation contracts and resources, including where resources’ cost does not match the resources’ current value, also called “above market costs.” In addition, state law requires that IOU bundled customers remain financially indifferent to load departure as a result of the implementation of CCAs or municipalities. 1 As a result, the California Public
Utilities Commission (CPUC) issued a decision that departing load (i.e. CCA) customers must pay the above market costs for their share of IOU procurement commitments prior to their departure, or be credited in the event these costs are below market. This value is called the Power Charge Indifference Adjustment or PCIA.
1 Per AB 117, “The implementation of a community choice aggregation program shall not result in a shifting of costs between the customers of the community choice aggregator and the bundled service customers of an electrical corporation.” and per SB 350, “Bundled retail customers of an electrical corporation shall not experience any cost increase as a result of the implementation of a community choice aggregator program. The commission shall also ensure that departing load does not experience any cost increases as a result of an allocation of costs that were not incurred on behalf of the departing load.”
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As currently implemented, the PCIA is a $/kWh charge that appears on the IOU part of electric bills that varies depending on a customer’s vintage, which is marked by the date on which the customer or community “departed” IOU bundled service. Both bundled and unbundled customers pay a PCIA, but not everyone pays for the same resources.
How the PCIA Impacts CCA Rate Setting
CCA customers see their total generation costs as the CCA generation rate plus the PCIA. When comparing to IOU rates, in order to remain competitive, CCAs aim to keep their total generation rate plus the PCIA competitive with the IOU generation rate. The PCIA is a major cost variable in the CCA generation rate – one the CCA does not control.
Because the PCIA is set by the incumbent IOU, it creates a situation where a competitor sets a key component of CCA rates. If the PCIA is set too high, it can prevent a new CCA from launching, eliminating competition for the IOU. Similarly, in the case of an operational CCA, it can erase cost savings for CCA customers, making the program less competitive, or alternatively can drive the CCA to set its rates at an unsustainably low level to absorb the customer impact of the PCIA.
Furthermore, the PCIA can be a volatile value year over year, which can make forecasting difficult for CCAs. The PCIA calculation can be updated once annually to reflect changing forecasts and actual costs and revenues, electricity market conditions and changes in the load forecasts. The PCIA can also be updated periodically throughout the year as the CPUC approves changes in IOU cost recovery or updates rates to recover shortfalls in revenues. As a result of these updates, the cost for a CCA to compete changes, often in unpredictable ways. Factors such as actual loads being higher or lower than expected, regulatory changes, or unforeseen conditions in energy and capacity markets make cost-competitiveness a moving target for CCAs.
Recent and Proposed Updates to the PCIA and to PCIA Methodology The PCIA is annually calculated via CPUC approved methodology within IOU-specific Energy Resource Recovery Account (ERRA) proceedings, which set annual generation rates. Periodically, the CPUC will revisit both ERRA and PCIA methodology via various proceedings.
PCIA Methodology Changes
In February 2025 the CPUC issued Rulemaking 25-02-005: Order Instituting Rulemaking to Update and Reform Energy Resource Recovery Account and Power Charge Indifference Adjustment Policies and Processes. This rulemaking considers changes to the PCIA, as well as changes to rules and processes applicable to the ERRA. This proceeding has two tracks. Track One is already complete and explored changes to the calculation of the PCIA.
These changes largely relate to the calculation of a component in the PCIA called the Market Price Benchmark (MPB). The MPB is calculated by averaging qualified transactions of Renewable Energy Credits (RECs) in the Renewables Portfolio Standard (RPS) Program and Resource Adequacy (RA).
There is an MPB forecast for the following year, followed by a true-up one year later once actual values 98
come in. The forecast and true-up value is then compared against the cost of resources to establish the PCIA.
The key change to the MPB methodology was to move from a 1-calendar year average to a 3-calendar year average. This change does not result in the most accurate valuation for the cost of RPS or RA transactions. As an analogy, in the housing market, home values are based on recent transactions for similar homes recently sold, not pricing from 3 years ago. The inclusion of old figures drops the average.
This lowers the MPB, which affects the PCIA in an inverse relationship and drives the PCIA up.
This change occurred mid-cycle, resulting in inconsistent methodology between the forecast and true-up, leading to a wild swing in the PCIA due to likely retroactive ratemaking.
CCA Response
On December 1, 2025, CalCCA filed in the California Court of Appeal, Third Division, a Petition for Review of the CPUC’s Decisions 25-06-049 and 25-10-061, Case No. C105174. CalCCA requests the Court grant the Petition and reverse the Decisions on the grounds that: (1) the Decision violated the prohibition against retroactive ratemaking; and (2) the Decision’s retroactive application to 2025 was not supported by adequate findings or substantial evidence in the record.
The ERRA Proceedings and the PCIA
Energy Resource Recovery Accounts (ERRA) are how an IOU applies for generation cost recovery. The ERRA regulatory process includes two annual proceedings:
• ERRA Compliance which reviews IOU compliance in the past year regarding contract administration, least-cost dispatch of resources, utility-owned generation and fuel procurement, balancing accounts, and PCIA rates.
• ERRA Forecast which adopts a forecast IOU electric procurement cost revenue requirement and electricity sales for the coming year. This proceeding covers PCIA forecast rates and Bundled Procurement Plans (or how IOUs plan to manage their portfolio for bundled customers).
Key CCA issues include accuracy of account balances and rates, cost calculations in workpapers, and calculation of Market Price Benchmarks in order to ensure costs are attributed to the proper PCIA vintage and costs are attributed properly between bundled and unbundled customers.
In this year’s ERRA Forecast decision, PG&E has changed the methodology for pre-2019 Renewable Energy Credits (RECs). Essentially, PG&E is short on RPS this year and needs to pull from a bank of old RECs from before 2019. Many CCAs did not exist at this time. Those customers that were not in a CCA then but now are need credit for those REC purchases the IOU made before their community left to a CCA.
Imagine a CCA community is akin to a roommate in a larger household, or the PG&E territory. The household plans to host a dinner party and charge attendees a certain price, say $5, in exchange for attendance to cover the cost of ingredients. You as a roommate purchase ingredients for the dinner but opted to move out prior to the party’s date. When you attend that dinner party, the roommates then charge you again because you don’t live there, even though you’d already paid for some of the share. 99
In past years, credit for the use of pre-2019 RECs would be given via the PCIA. However, this year, at PG&E’s request, the CPUC ruled that these now-departed CCA customers do not need to be credited for the use of the RECs they paid for. Like the former roommate, they are effectively being double charged, in this case for the clean energy they consume.
In response, CalCCA has filed an Application for Rehearing of this decision to the CPUC related to both the REC-issue and the application of the new MPB methodology mid-cycle. The CPUC’s response to the Application is expected by February 4.
More Avenues for Change
Track Two of Rulemaking 25-02-005, which addresses both the ERRA and PCIA, is currently in early scoping. The CPUC appears open to discussions about consistent treatment of pre-2019 RECs across all IOUs. CalCCA is working with RCEA and other CCAs to identify additional proposals related to the PCIA and the ERRA, with multiple proposals under consideration. Note that whatever conclusions are drawn will only apply to future years and not this year.
CalCCA is also working with potential authors to introduce a bill that would ensure CCAs and other ratepayer advocates have access to all data underlying the PCIA charge, or any other value derived from the charge. As previously described, state law requires CCA customers to pay the PCIA to ensure IOU customers are not financially harmed when customers depart to a CCA. However, CCAs are not consistently given access to the data used to calculate the PCIA, by the IOUs or the CPUC itself.
Meanwhile, experience demonstrates that the calculation of the PCIA or related charges is not always accurate or without error.
CalCCA is proposing statutory changes to require transparency in how the PCIA is calculated consistent with existing protections for market sensitive information. Improving data access provides a quality check to ensure calculations will be accurate. Additionally, increased transparency will allow CCAs to more accurately forecast costs longer term and supports affordable, stable energy rates for the one-third of Californians served by CCAs.
Alignment with RCEA’s Strategic Plan
This staff report relates to the following strategies in Section 4.3 Rates & Tariffs:
4.3.1 Provide Community Choice Energy Program Customer Rate Savings. Provide customer rates that are affordable and price-competitive with customers’ other electric supply options.
4.3.3 Retain and/or Redirect Rate-Payer Dollars Back into Humboldt County. Work to maximize the amount of ratepayer dollars retained in Humboldt County when taking into consideration local power procurement, electricity rates, local program spending, and allocations toward building the reserve fund for RCEA’s Community Choice Energy program.
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Equity Impacts
If implemented correctly, the PCIA should result in indifference between bundled and unbundled customers. As implemented, these changes put CCAs at a significant disadvantage to IOUs, risking CCA viability.
Financial Impact
ESTIMATED COST TO FULL PG&E SERVICE TERRITORY: The ERRA decision adopts a net revenue requirement of $3.2 billion across PG&E’s entire territory.
Staff Recommendation
None – Information only.
Attachments
CalCCA Press Release Regarding Recent PCIA Developments 101
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CalCCA, CCAs Seek Rehearing of CPUC Decisions that Unfairly Burden CCA Customers » California Community Choice Association (CalCCA) file:///RCEADiskstation/...20Minutes/01%20January%202026/Documents/7.1%20-%202%20CalCCA%20ERRA%20Press%20Release.html[1/14/2026 6:21:20 PM] FOR IMMEDIATE RELEASE: January 12, 2025
Media Contact: Jackson McDonough
CalCCA, CCAs Seek Rehearing of CPUC Decisions that Unfairly Burden CCA Customers
Petitions target unfair cost shifts, retroactive ratemaking, and improper treatment of renewable energy credits
Sacramento, Calif. — The California Community Choice Association (CalCCA) today filed petitions asking the California Public Utilities Commission (CPUC) to reconsider its recent decisions approving Pacific Gas and Electric Company’s (PG&E) and Southern California Edison Company’s (SCE) 2026 Energy Resource Recovery Account (ERRA) forecast applications. CalCCA members San Diego Community Power (SDCP) and Clean Energy Alliance (CEA) earlier this month filed a similar rehearing request challenging the CPUC’s approval of San Diego Gas & Electric’s (SDG&E) ERRA forecast application.
Together, these three CPUC decisions unlawfully shift investor-owned utility (IOU) energy supply costs onto Community Choice Aggregation (CCA) customers to the benefit of bundled IOU customers. * The CPUC’s 103
CalCCA, CCAs Seek Rehearing of CPUC Decisions that Unfairly Burden CCA Customers » California Community Choice Association (CalCCA) file:///RCEADiskstation/...20Minutes/01%20January%202026/Documents/7.1%20-%202%20CalCCA%20ERRA%20Press%20Release.html[1/14/2026 6:21:20 PM] actions reflect a growing erosion of the statutory principle of “ratepayer indifference”— the requirement that neither bundled IOU customers nor unbundled CCA customers should be harmed by the existence of retail electric choice. The rehearing requests challenge the legality of the CPUC’s approach and seek to restore fair and lawful IOU cost recovery. “California law is clear: retail electric choice should not be used as a mechanism to shift costs from one group of customers to another,” said CalCCA CEO Beth Vaughan. “Unfortunately, the CPUC’s recent actions do exactly that, undermining the legal protections that exist to ensure a level playing field.”
CalCCA’s and SDCP/CEA’s rehearing requests challenge legal flaws in the CPUC’s decisions. In all three IOU cases, the Commission implemented a key pricing formula used to calculate Power Charge Indifference Adjustment (PCIA)—the fee charged to customers who have left an IOU for a CCA—after 2025 rates had already gone into effect. This kind of after-the-fact change—known as “retroactive ratemaking”—is illegal under California law because customers must be able to rely on stable, predictable rates. Find additional information on the PCIA here.
Additionally, in the PG&E and SCE service areas, CalCCA is challenging how the IOUs value Renewable Energy Credits purchased before 2019.
Although these credits were paid for by all customers—including ones that later left for CCA service—the IOUs now use them exclusively to benefit their bundled customers in meeting current clean energy requirements.
Under the CPUC’s approach, customers who left PG&E or SCE generation service to receive CCA service get no credit for the value of these RECs, despite having funded their purchase. This misallocation inflates PCIA charges for CCA customers while shielding IOU customers from the full costs of IOU-owned resources.
104
CalCCA, CCAs Seek Rehearing of CPUC Decisions that Unfairly Burden CCA Customers » California Community Choice Association (CalCCA) file:///RCEADiskstation/...20Minutes/01%20January%202026/Documents/7.1%20-%202%20CalCCA%20ERRA%20Press%20Release.html[1/14/2026 6:21:20 PM] CalCCA’s Application for Rehearing in PG&E’s 2026 ERRA Forecast proceeding (A.25-05-011) is available here. CalCCA’s Application for Rehearing in SCE’s 2026 ERRA Forecast proceeding (A.25-05-008) is available here. The Application for Rehearing filed by San Diego Community Power and Clean Energy Alliance in SDG&E’s 2026 ERRA Forecast (A.25-05-012) proceeding is available here.
Parties have 15 days to respond to the Applications for Rehearing.
CalCCA is urging the CPUC to correct these errors and reverse these unlawful decisions. The association will continue to advocate for fair, lawful, and transparent rate-setting that protects customers while advancing California’s clean energy goals.
* A bundled IOU customer receives all electricity services—generation, transmission, and distribution—from a single investor-owned utility (IOU), while a CCA customer receives electricity generation from a Community Choice Aggregation (CCA) program and the IOU’s distribution services. ###
About CalCCA
Launched in 2016, the California Community Choice Association (CalCCA) represents California’s community choice electricity providers before the state Legislature and at regulatory agencies, advocating for a level playing field and opposing policies that unfairly discriminate against CCAs and their customers. There are 25 operational CCA programs in California serving more than 15 million customers—over one-third of the state’s population—in 200+ cities and counties throughout the state. For more information about CalCCA, visit www.cal-cca.org.
105
CalCCA, CCAs Seek Rehearing of CPUC Decisions that Unfairly Burden CCA Customers » California Community Choice Association (CalCCA) file:///RCEADiskstation/...20Minutes/01%20January%202026/Documents/7.1%20-%202%20CalCCA%20ERRA%20Press%20Release.html[1/14/2026 6:21:20 PM]
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Power Charge Indifference
Adjustment
January 22, 2026
Faith Carls on
Regulatory and Legis lative Policy Manager
Goals for Attendees
Deeper Understanding of:
1. What the PCIA is;
2. How the PCIA affects Community Choice Aggregator rates;
3. Recent policy changes surrounding the PCIA;
4. Impacts of the changes and next steps.
The Power Charge Indifference
Adjustment (PCIA)
What is it?
What am I paying
for?
Why am I paying
it?
Purpose of the PCIA
$
Amount IOU*
paid for power
resources now
no longer
needed by
customers
who moved
over to CCA
service
*IOU = Investor-Owned utility (e.g., PG&E)
Current
market value
of the
resources IOU
procured for
departed
customers
Purpose of the PCIA $
Amount IOU*
paid for power
resources now
no longer
needed by
customers
who moved
over to CCA
service
*IOU = Investor-Owned utility (e.g., PG&E)
Current
market value
of the
resources IOU
procured for
departed
customers
PCIA amount
applied to CCA
customer bills to
make IOU whole
How the PCIA Appears on Bills Determining Your Savings
How the PCIA Appears on Bills Determining Your Savings
Generation Credit
How the PCIA Appears on Bills Determining Your Savings
Generation Credit
Power Charge
Indifference
Adjustment (PCIA)
How the PCIA affects CCA
rates
Recent Policy
Changes
PG&E Ratesetting and the PCIA
The Energy Resource Recovery Account (ERRA)
Sets generation rate by determinizing fuel and purchased power costs, recoverable by rates.
No rate of return, only actual cost recovery. ~$4 billion is normal ERRA Application for
PG&E
What are Market Price Benchmarks (MPBs)?
• MPBs are estimates of the per unit value of the
products in an IOU’s portfolio
–Energy
–Resource Adequacy
–Renewable Energy or Renewables Portfolio Standard
• MPBs are utilized to
–Estimate the value of resources in the PCIA
35 Changes to the PCIA Methodology
• In February 2025 the CPUC issued a new
rulemaking to address ERRA and PCIA
methodology across all IOUs.
–MPB methodology moved from a 1-calendar year
average to a 3-calendar year average.
–This change occurred mid-cycle, resulting in
inconsistent methodology between the forecast
and true-up, leading to a wild swing in the PCIA
due to likely retroactive ratemaking.
Bundled
Customers
Now-Departed
Customers/
CCA
Customers
Bundled
Customers
Now-Departed
Customers/
CCA
Customers
IOUs’ Pre-2019
Banked RECs
Costs Financial
Benefits
Changes within the ERRA Proceeding
All Bundled Pre-2019
Bundled
Customers
Now-Departed
Customers/
CCA
Customers
Bundled
Customers
Now-Departed
Customers/
CCA
Customers
IOUs’ Pre-2019
Banked RECs
Costs Financial
Benefits
Changes within the ERRA Proceeding
All Bundled Pre-2019
Impact of the Changes
2025 Gen 2026 Gen 2027 Gen
$178.96 $117.89 $125.77
-34% 7%
2025 PCIA 2026 PCIA 2027 PCIA
$11.10 $36.87 $15.97
232% -57%
$-
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
$160.00
$180.00
$200.00
2025 2026 2027
PG&E Gen Rate
$-
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
$40.00
2025 2026 2027
Vintage Year 2016 PCIA
What is RCEA
Doing?
Closing Thoughts
Staff Report
Agenda Item # 10.2
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by
Richard Engel, Power Resources Director
Lori Biondini, Business Planning and Finance Director
Jaclyn Harr, The Energy Authority Account Director – California Subject Energy Risk Management Semi-Annual Report
Background
In December 2016, the RCEA Board of Directors adopted an Energy Risk Management Policy, most recently revised in June 20251, to establish functions and procedures to manage the risks associated with the Community Choice Energy (CCE) program’s power procurement activities. In accordance with this policy, staff presents updates at minimum twice yearly on activities and financial performance to the Board during business meetings.
Summary
RCEA staff and the Energy Authority (TEA) California Account Director Jaclyn Harr will provide an energy risk management update. Staff requests Board feedback on the information presented, including potential future changes to the retail electricity generation rates that RCEA charges its customers. Per RCEA’s Community Choice Aggregation Implementation Plan2, RCEA provides a 60-day Board review period prior to any rate increases that change the differential between PG&E’s and RCEA’s rates, and customers must be notified via a mailer or bill insert, which takes advanced planning to implement.
Equity Impacts
Not applicable.
Alignment with RCEA’s Strategic Plan
1 Energy Risk Management Policy, June 2025 revision
https://redwoodenergy.org/wp-content/uploads/sites/850/2025/07/RCEA-Energy-Risk-Mgmt-Policy-June-2025.pdf 2 Community Choice Aggregation Implementation Plan https://redwoodenergy.org/wp-content/uploads/sites/850/2024/12/Community-Choice-Aggregation-Implementation-Plan.pdf 107
Not applicable.
Staff Recommendation
Accept Energy Risk Management Semi-Annual Report and provide feedback to staff on information presented to inform any further analysis or future Board actions.
Attachments
1. Energy Risk Management Semi-Annual Report slides will be presented at the meeting. 108
RCEA Energy Risk Management
Semi-Annual Report
Presentation to
RCEA Board of Directors
January 22, 2026
Discussion Topics
•Declining Load
•Customer Debt Related Risk
•Financial Outlook
•Near-term rate setting options
Declining Load
• RCEA has seen a roughly 19% decrease in annual load since 2021 • Residential customers make up 83% of our accounts, 47% of our load, and are seeing the sharpest rates of decline
• 45% of our load is Commercial & Industrial customers, and 8% Agricultural • Humboldt County has seen a 3.3% decrease in population since 2017 • Key accounts (users averaging over 1 million kWh/ year) that have been closed for 2 or more years total 5% of our 2024 load
• Opt-outs have been relatively flat over the past 5 years, and not a significant contributor to the declining load
Customer Debt Related Risk
• RCEA “Active” Account Debt Risk: $1,668,142
• RCEA Dropped Accounts (Active w/PG&E)- Estimated Outstanding Debt: $5,893
• All RCEA Closed Account Debt Sent to Collections: $7,252,024 Total: $8,946,059
Totals this quarter are in the estimated acceptable debt balances.
2025 Q4 Active Account Debt
(Accounts with Late Payment status over 60 days)
Total customer debt that has been sent to collections
To date, just over $200,000 of this
amount has been collected
Financial Outlook
Main driver: less retail revenue than forecasted in May 2025 • Numbers from the May ERRA filing informed fiscal year budget • Subsequent forecasts showed lower gen rates and higher PCIA would be implemented beginning of calendar year 2026
• PG&E released preliminary 2026 rates reflecting balancing account true ups. In comparison to the Fall Update, the gen rate decreased by 9% while the PCIA increased by 20%.
• Final 2026 rates came in slightly higher
Year-over-Year PG&E Gen Rates & RCEA PCIA
$178.96 $117.89 $125.77
-34% 7%
$11.10 $36.87 $15.97
232% -57%
$-
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
$160.00
$180.00
$200.00
2025 2026 2027
PG&E Gen Rate
$-
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
$40.00
2025 2026 2027
Vintage Year 2016 PCIA
Forecasted PG&E Generation Rate & PCIA
$-
$20
$40
$60
$80
$100
$120
$140
$160
$180
Jan-26
Feb-26
Mar-26
Apr-26
May-26
Jun-26
Jul-26
Aug-26
Sep-26
Oct-26
Nov-26
Dec-26
Jan-27
Feb-27
Mar-27
Apr-27
May-27
Jun-27
Jul-27
Aug-27
Sep-27
Oct-27
Nov-27
Dec-27
Jan-28
Feb-28
Mar-28
Apr-28
May-28
Jun-28
Jul-28
Aug-28
Sep-28
Oct-28
Nov-28
Dec-28
$/MWh
May 2025 Board Gen Rate Jan 2026 Board Gen Rate May 2025 Board PCIA Jan 2026 Board PCIA CCE Revenue Breakdown
Fiscal Year 2025-2026 Budgeted
Electricity Sales Revenue
$71,539,945
July through November Actuals ($3,240,000)
Increase in PCIA ($5,500,000)
Decrease in Generation Rates ($6,200,000)
Total Impact ($14,940,000)
Updated Fiscal Year 2025-2026 Forecasted
Electricity Sales Revenue
(per final ‘26 rates)
$56,600,000
Net CCE Revenue Forecast
Cash Projection assuming RCEA maintains rate discount relative to PG&E January 2026: $44.1 M
December 2026: $26.3M
December 2027: $13.2M
December 2028: $2.1M
Rate Change Scenarios
1) Business as usual (0.5% discount relative to PG&E’s generation rate) 2) At parity with PG&E (no discount)
3) 3% above PG&E
4) 5% above PG&E
5) Rate premium that results in 120 days cash on hand* at end of 2026 ($22,193,355) 6) Rate premium that results in 180 days cash on hand** at end of 2026 ($33,290,033) 7) Rate premium that results in 210 days cash on hand*** at end of 2026 ($38,838,371) *Minimum and **aspirational targets per RCEA’s reserve policy ***Current balance, minus non-CCE program operations
Assumed April 2026 implementation date for any changes
Business as usual (0.5% discount)
v
-$9.3M
Parity with PG&E (no discount)
v
-$9.1M
3% above PG&E
v
-$8.2M
5% above PG&E
v
-$7.5M
To maintain COH* at 120 days - 0.5% below PG&E
(same as current rate difference)
v
*COH = cash on hand
-$9.3M
To maintain COH at 180 days for 2026 – 18%
above PG&E
v
-$3.5M
To maintain COH at 210 days for 2026 –
33.2% above PG&E
v
+$1.1M
Scenario Comparison
(120 days COH) (180 days COH) (210 days COH)
Impact on
residential
bills
RCEA generation charges only
Impact on
small business
bills
RCEA generation charges only
What’s next?
•Cost of Service and Rate Setting
Study Results
•Acting on near-term options
THANK YOU
Appendix
Forward Energy Prices for RCEA
$-
$20
$40
$60
$80
$100
$120
Jan-26
Feb-26
Mar-26
Apr-26
May-26
Jun-26
Jul-26
Aug-26
Sep-26
Oct-26
Nov-26
Dec-26
Jan-27
Feb-27
Mar-27
Apr-27
May-27
Jun-27
Jul-27
Aug-27
Sep-27
Oct-27
Nov-27
Dec-27
Jan-28
Feb-28
Mar-28
Apr-28
May-28
Jun-28
Jul-28
Aug-28
Sep-28
Oct-28
Nov-28
Dec-28
$/MWh
May 2025 Board Forward On-Peak Jan 2026 Board Forward On-Peak May 2025 Board Forward Off-Peak Jan 2026 Board Forward Off-Peak Impact on residential and small business bills
Drop in generation portion of average monthly bill
with implementation of new rates in February Increased average monthly bills under the different scenarios considered
Residential Small Business
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Staff Report
Agenda Item # 12.1
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Lori Taketa, Clerk of the Board
Subject Community Advisory Committee Member Reappointments Background
RCEA‘s Board established the Community Advisory Committee (CAC) to support RCEA public engagement efforts and provide decision-making support and input. In their advisory and outreach capacities, CAC members helped educate Humboldt County residents about community choice aggregation and gathered community energy priority input during the CCE program’s launch period.
More recently the Committee gave staff input on Humboldt Sawmill Company’s annual biomass use reports and potential uses for the Sandrini Battery Storage Project’s Community Benefits Investment Fund.
CAC applicants and appointed members must commit to supporting RCEA’s mission and to align their advice with the long-term success of the agency. The CAC is a Brown Act, California open meeting law compliant body. CAC members are subject to all applicable conflict of interest laws. Appointees must complete a Fair Political Practices Commission Statement of Economic Interest, a public document disclosing the member’s personal financial interests.
Summary
Terms for five (5) of the CAC’s 14 seats will expire on March 31. Additionally, there are four (4) existing vacancies.
Directors Mike Wilson (County) and Skip Jorgenson (Ferndale) nominated currently seated members for reappointment. All three incumbent CAC members expressed interest in serving another term. Incumbent Ethan Lawton currently the CAC Chair has been serving as the Humboldt Bay Municipal Water District (HBMWD) appointee. However, at this month’s HBMWD Board meeting the HBMWD Board voted to discontinue RCEA membership, removing the CAC position. CAC Chair Lawton expressed interest in continuing and Director Mike Wilson (County) nominated him for the vacant County seat 3 position. 109
Proposed CAC Membership & Vacancies
Representing Jurisdiction Member Name Term Expiration
Arcata Norman Bell 03/31/2027
Blue Lake Kit Mann 03/31/2027
County 1 Luna Latimer 03/31/2027
Eureka Deborah Dukes 03/31/2027
Trinidad Richard Johnson 03/31/2027
County Seat 3 Benjamin Fordham 03/31/2028
Ferndale Dennis Leonardi 03/31/2028
County 2 Ethan Lawton 03/31/2028
At-Large Upcoming Vacancy 03/31/2028
At-Large Upcoming Vacancy 03/31/2028
Blue Lake Rancheria Vacancy 03/31 (2-year term)
Fortuna Vacancy 03/31 (2-year term)
Rio Dell Vacancy 03/31 (2-year term)
Yurok Vacancy 03/31 (2-year term)
The application period for the at-large vacancies closes on February 13, 2026. In the past, the Board formed an ad hoc CAC at-large application review subcommittee to review applications and nominate candidates for Board appointment.
Equity Impacts
CAC members have opportunities to further RCEA goals that benefit underserved population segments; promote racially-diverse inclusion in energy infrastructure or policy decision making; access to energy, energy efficiency services and freedom from pollution. Staff recommend considering these goals as well as Committee member diversity and inclusion when appointing members to fill these vacancies.
Alignment with RCEA’s Strategic Plan
The CAC supports RCEA public engagement efforts and decision-making for the successful implementation of agency strategic plan goals.
Financial Impact
Budgeted staff and program costs to facilitate meetings. 110
Staff Recommendation
Reappoint Ethan Lawton, Benjamin Fordham, and Dennis Leonardi to the Community Advisory Committee for Two-Year Terms Ending on March 31, 2028.
Recruit up to 5 Board members for an ad hoc CAC at-large recruitment subcommittee to review applications and nominate candidates at the February 26, 2026, RCEA Board meeting.
Attachments
None.
111
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left blank.
112
Staff Report
Agenda Item # 13.1
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Patricia Terry, Senior Portfolio Manager
Subject Northern Rural Energy Network (NREN) Update and Business Plan Background
On September 26, 2024, The California Public Utilities Commission (CPUC) issued Decision D.24-09- 031 that approved the Northern California Rural Regional Energy Network (also known as Northern Rural Energy Network or NREN) to deliver energy efficiency programs to underserved rural customers in 17 counties with the Redwood Coast Energy Authority (RCEA) as the lead portfolio administrator.
The NREN Partners include Lake Area Planning Council (LAPC), Mendocino Council of Governments (MCOG), and the Sierra Business Council (SBC) representing the Counties of Alpine, Amador, Butte, Calaveras, El Dorado, Lassen, Mariposa, Nevada, Plumas, Placer, Sierra, Sutter, Tuolumne, and Yuba.
The NREN program portfolio included seven programs:
• Residential Equity
• Residential Resource Acquisition
• Commercial Resource Acquisition
• Financing
• Public Equity
• Workforce, Education & Training, and
• Codes & Standards.
At the end of 2025, the Codes & Standards programs were absorbed into the Workforce, Education & Training program.
Pursuant to Ordering Paragraph 5 of CPUC D.21-05-031, each energy efficiency portfolio administrator must file an application for the eight-year business plan period and the four-year portfolio period beginning in 2028, on or before February 16, 2026.
On December 15, 2025, the Executive Director of the CPUC granted an extension to the business plan application deadline for all portfolio administrators to March 16, 2026. 113
Summary
NREN 2024-2025 Achievements
After the first full year of ramp up and implementation, NREN has launched services from the two residential programs in the portfolio and will be launching the remaining programs in 2026. NREN is already seeing impacts across Partner counties, particularly those that have not previously received any energy efficiency services from other agencies.
• Residential Equity Program: Provide energy efficiency education and outreach, energy efficiency kits, and phone-based assessments.
o 623 kits distributed (160 in Humboldt)
o 87 phone home efficiency assessments completed (52 in Humboldt) o 581 signed up for services (146 in Humboldt)
• Residential Resource Program (through Q3 of 2025):
o 312 energy efficient appliance and heat pump rebates processed] o 89,101 in rebates paid out
o Savings numbers are still being calculated and will be available on CEDARS. http://cedars.cpuc.ca.gov.
NREN intends to launch the remainder of the programs in 2026.
NREN 2028-2035 Business Plan
NREN’s current program cycle is 2024 to 2027. In March of 2026, RCEA intends to submit a Business Plan Application to the CPUC for 2028-2035. This Business Plan Application will include a strategic plan for 2028-2035 and program portfolio for 2028-2031. NREN partners are currently working on draft budgets and intend to request between $85-114 million for the four-year program portfolio budget.
Programs will be similar to those in the current portfolio, with the growth in customers served across all programs.
Proposed programs for the 2028-2031 portfolio include:
• Residential Equity: Provide outreach and education to underserved customers in rural northern California including Residential Energy Efficiency Kits, Workshops, and Energy advisor services. • Residential Direct Install:
o Rebate catalog: Rebates for energy efficient and electrification appliances and equipment. o Energy assessments: phone or home-based followed up by a report and optionally a Home Energy Score.
o Direct Installation: Assistance with contractor installation of energy efficient equipment or electrification upgrades.
o Technical Assistance: Support with accessing financing or connecting with technical expertise for upgrades.
• Non-Residential Direct Install: energy assessments, incentives, and technical support to small business, public, or agricultural customers looking to reduce energy usage and costs, and/or to decarbonize.
• Financing: Provides support to access energy efficiency financing. 114
• Public Equity: This program will provide support to local government agencies looking to understand and reduce energy usage and costs, decarbonize, or put together plans for addressing these needs in the future.
• Workforce, Education, and Training: This program works with community colleges, community-based organizations, tribes, and other training providers to create local training opportunities for the energy efficiency workforce.
NREN will add Yolo County as a service territory in the Business Plan Application and include a market characterization of other Northern California counties that could be added in the future including Colusa, Glenn, and Tehama. Yolo County brings their sustainability department’s many years of expertise and programs, including the Home Energy Score and Electric Advisor Program, to NREN’s team and service offerings.
At this time the Board is being asked to approve the submission of the 2028-2031 business cycle application. After submission, the NREN portfolio team will finalize the Business Plan with the CPUC over the next 1.5 years. Staff will keep the Board informed at key milestones during this process and the final Business Plan and associated agreements will come to the Board for approval.
Alignment with RCEA’s Strategic Plan
NREN’s programs support all 2.1 Integrated Demand Side Management Strategies and all 2.2 Energy Efficiency and Conservation Strategies of RePower Humboldt, RCEA’s Comprehensive Action Plan for Energy.
1 Equity Impacts
RENs in general, and NREN in particular, are designed to reach customers that otherwise are not being reached by existing ratepayer-funded programs. The NREN programs will ensure that hard-to-reach, disinvested, disadvantaged, and underserved rural customers are provided an equitable level of CPUC energy program service and support and are empowered to better manage their energy use and cost through increased awareness, support resources, a trained workforce and access to financing to improve their homes and businesses.
Financial Impact
NREN activities between 2024 and 2027 currently have approved funding of $3.3M and the upcoming Business Plan Application has potential bring an additional $85M- $114M portfolio wide for 2028-2031..
RCEA’s portion would be approximately 10% of those budgets for administrative costs and also include about $15-$20M in program implementation costs per 4-year cycle. These amounts will be incorporated into future fiscal year budgets.
1 Link to RePower Humboldt, RCEA’s Strategic Plan:
https://redwoodenergy.org/wp-content/uploads/sites/850/2025/09/REpower-2019-Strategic-Plan-250919.pdf 115
Staff Recommendation
Approve submission of the 2028-2031 Northern Rural Energy Network Business Plan Application to the California Public Utilities Commission.
Attachments
None.
116
02 Northern Rural Energy Network Program Portfolio for 2025-2027 NREN’s current program cycle ends on December 31, 2027
In March of 2026, RCEA will submit a Business Plan Application to the CPUC for 2028-2035:
• NREN intends to request approximately $65-$85M for the four-year program portfolio budget.
• Programs will be very similar to those in the current portfolio • NREN will add Yolo County and areas of Trinity County already served by RCEA’s LGP program as a service territory in the Business Plan Application. Yolo County brings their sustainability department’s many years of expertise and programs, including the Home Energy Score program, to NREN’s team and service offerings. • Also included is a market characterization of other Northern California counties that could be added in the future including Colusa, Glenn, Shasta, and Tehama.
Fig 1. NREN Territory
Existing NREN territory
Additional NREN territory (not
shown, Trinity County PG&E areas)
Counties in market study (not
shown, Shasta County PG&E
territory)
Pacific Power Territory (exploring
for 2031)
Liberty Power Territory (exploring)
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Staff Report
Agenda Item # 13.2
Information
Agenda Date January 22, 2026
To Board of Directors
Prepared by Eileen Verbeck, Deputy Executive Director
Lori Biondini, Director of Business Planning and Finance Subject Engagement with Baker Tilly for Investment Tax Credit Preparation for the Redwood Coast Airport Microgrid Project
Background
RCEA worked with a multi-talented team to design, permit, construct and commission the Redwood Coast Airport Microgrid (RCAM). RCAM is a local energy project that has become a model for the rest of the nation. RCAM is the first 100% renewable, front-of-the-meter, multi-customer microgrid in California.
It delivers clean, 100% dispatchable renewable power to Humboldt County utility customers and provides critical energy resilience for the California Redwood Coast – Humboldt County Airport and the U.S. Coast Guard Air Station. RCEA’s portion of the total cost to construct RCAM was $6,287,591 and was financed through a U.S. Department of Agriculture Rural Utilities Service loan.
The Inflation Reduction Act was signed into law in 2022 and allowed public agencies such as Redwood Coast Energy Authority to apply for tax incentives for renewable energy projects that include photovoltaic solar arrays and battery energy storage systems (BESS). In October of 2025, staff entered into a Master Service Agreement with Baker Tilly Advisory Group, LP, to provide an analysis on RCEA’s eligibility to claim an Investment Tax Credit (ITC) for the RCAM project.
In December 2025, staff received Baker Tilly’s findings which state that RCEA is eligible for an estimated $1,603,335 ITC. The deadline for filing the ITC documents is November 15, 2026.
Summary
Construction of RCAM was largely completed in late 2021, and the system began generating and delivering energy directly to the Airport buildings via a net-metered connection. However, the portion of the solar array and BESS that is connected to our regional electricity grid and acts as a microgrid has experienced persistent complications that caused the system to not perform as expected. RCEA has since been working with the vendor on potential solutions. During this time (late 2021 – 2025), RCEA would not approve completion of the final contract milestone nor release final payment to the vendor. In late 2025, after the successful installation of new equipment and significant testing, RCEA recorded a Notice of Completion with Humboldt County Recorder’s Office and issued final payment to the vendor. 117
Filing the Notice of Completion was the catalyst to start the process of assessing RCEA’s eligibility for an ITC for the project.
Staff recommends authorizing an amendment to the Master Service Agreement with Baker Tilly Advisory Group, LP, that will enable them to move ahead with preparing and filing the tax documentation for the RCAM Investment Tax Credit.
Alignment with RCEA’s Strategic Plan
RCEA’s pursuit of investment tax credits for the RCAM project directly advances multiple strategies identified in RCEA Strategic Plan:
• 1.3.5 Develop Local Energy Investment Programs. By developing local renewable energy projects and recovering some of the costs to build, RCEA is situated to reinvest those funds into the county.
• 2.1.7 Support and Deploy Micogrids. RCAM supports critical infrastructure and combines onsite generation, energy storage and advanced control systems to provide energy resiliency. • 4.3.1 Provide Community Choice Energy Program Customer Rate Savings. By applying for and receiving investment tax credits we can stabilize rates to our customers.
Financial Impact
RCEA entered into a Master Service Agreement with Baker Tilly Advisory Group, LP, for a total not-to-exceed of $49,500 and approved Scope of Work 1 for a cost of approximately $25,000 for analysis. The estimated cost for Scope of Work 2, to prepare and file documentation for the tax credit, is $55,500 for a total not to exceed $80,500. This cost will be included in the mid-year budget adjustment in February 2026 but eventually recovered through the estimated $1,603,335 ITC revenue. Please note that Baker Tilly Advisory Group, LP, is under the same parent company as Baker Tilly US, LLP, RCEA’s current independent financial auditor.
Staff Recommendation
1. Approve an amendment to Baker Tilly Advisory Group, LP Master Service Agreement to increase the not-to-exceed amount by $31,000 for a total not-to-exceed of $80,500.
2. Approve Scope of Work 2 with Baker Tilly for the preparation and filing of Investment Tax Credit documents for the Redwood Coast Airport Microgrid project.
Attachments
1. RCAM Investment Tax Credit eligibility memo
2. Baker Tilly Master Service Agreement and Scope of Work 1
3. Baker Tilly Proposed Scope of Work 2
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To: Redwood Coast Energy Authority
From: Baker Tilly Advisory Group, LP
Date: December 17, 2025
RE: RCEA Microgrid Preliminary ITC Eligibility Memorandum The Inflation Reduction Act (“IRA”) was signed into law on August 16, 2022, with a large component dedicated to the development of clean energy infrastructure. The IRA adapts the language of the Internal Revenue Code (“IRC”) to provide tax incentives to organizations that develop qualified renewable energy projects. Redwood Coast Energy Authority (“Client” or “RCEA”) recognizes that the photovoltaic (“PV”) solar array and battery energy storage system (“BESS”) facility they have constructed and commissioned in McKinleyville, CA 95519 (the “Project”, or “RCEA Microgrid”) may qualify for these energy-related incentives and has engaged Baker Tilly Advisory Group, LP (“Baker Tilly”) to help determine the eligibility for tax incentives, specifically the Investment Tax Credit (“ITC”) under IRC Section 48. Based on conversations and documentation provided by the Client to date, this memorandum summarizes our findings, assumptions, and discussion regarding the potential to claim an ITC for the Project. i. Executive Summary
Entity Name Redwood Coast Energy Authority
Energy Property Type Solar PV + BESS
Address / GPS Coordinates 3561 Boeing Ave, McKinleyville CA 95519 Project Size Solar – 2.5 MW DC, BESS – 2MW/8MWh
Estimated Begun Construction Date September 24, 2019
Estimated Placed in Service Date September 8, 2025
PIS Tax Year July 1, 2025 – June 30, 2026
Applicable Filing Date November 15, 2026
Base Credit Requirement Met Requirement Credit % Or Multiplier Eligible Energy Property per Section 48(a) Yes 6%
Domestic Content No 0%
Energy Community No 0%
Estimated Base Credit 6%
Increased Credit Amount Requirement (5x multiplier)
Max Net Output <1MW AC or3.4 MMBtu/hr No X5
Begun Construction prior to 1/29/23 - Safe Harbor Yes
Prevailing Wage and Apprenticeship Compliance
after 1/29/23 No -
Estimated ITC Credit Percentage 30%
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Estimated Credit Computation
Estimated Project Cost $6,287,591
Estimated Eligibility Percentage 85%1
Estimated Eligible Property Cost $5,344,453
Tax-exempt Financing Haircut $ 0.00
Estimated ITC Credit Value $1,603,335
a) Summary of Findings
• The Client has constructed a solar PV and energy storage project at 3651 Boeing Ave, McKinleyville, CA 95519. Based on documentation provided by the Client outlining the specific project development plan and property components, the Project is considered an “energy project” that consists of “energy property” under IRC Section 48(a)(3)(A)(i) as “equipment which uses solar energy to generate electricity” and under IRC Section 48(a)(3)(A)(ix) as an “energy storage technology” under IRC §48(c)(6). Hence, the Project is eligible for IRC Section 48 Investment Tax Credit. The Project has an estimated Beginning of Construction date on September 24, 2019, and an estimated Placed in Service date in September 8, 2025, thereby meeting the Beginning of Construction requirements for IRC Section 48(a)(2)(A)(i)(II). • As an energy project, the Project is eligible to receive an ITC equal to 6% of eligible expenses, subject to further bonuses. The Project meets the increased credit amount requirements through the begun construction safe harbor to receive a 5X multiplier. The Project does not meet the requirements of the Domestic Content bonus credit or Energy Community bonus credit. Therefore, the estimated credit rate for purposes of this document is 30%. • The ITC is earned when the Project is placed in service. The estimated cost of the Project is $6,287,591, of which $5,344,453 is estimated as IRC Section 48 ITC-eligible energy property.
Thus, the estimated ITC value at 30% of the eligible costs is $1,603,335. b) Other Considerations for Claiming the Tax Credit
Consider the ITC credit reduction due to tax-exempt financing when funding the Project It is possible that some of the Project costs may be funded through tax-exempt financing with a tax-exempt interest rate. Since the construction began before August 16, 2022, under IRC Section 48(a)(4) (via IRC Section 45(b)(3)), the credit will reduce by the lesser of 50% or the pro rata portion of tax-exempt financing.
For the analysis in this memorandum, it has been assumed that there was no tax-exempt financing for the Project. To provide an example, if 30% of the total cost was funded by tax exempt financing then the credit rate would be reduced by 30% leading to a revised credit rate of 21%. Therefore, if any tax-exempt financing is considered for the Project, the potential impact to the total tax credit available should be taken into account.
1 A detailed cost-allocation analysis has not been completed. Therefore, the exact eligible energy property cost is not available at this time. However, for purposes of this preliminary assessment, the eligible cost is estimated at 85% of the total project cost. This percentage reflects a conservative assumption informed by historical cost allocations and prior experience with similar energy projects. 120
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Excess benefit is not anticipated
The ITC cannot result in excess benefit to the Owner, as stated in Section 6417-2(c)(3)(ii). If a non-taxable entity uses tax-exempt income (e.g., state grants) to acquire clean energy property under Sections 30C, 45W, 48, 48C, or 48E, that grant money can be included in the property’s cost basis for purposes of determining the credit amount. However, in the event that outside funding received by the Client and the sum of that grant exceeds total cost of the property, the ITC credit is reduced so that the credit plus the grant amount together is capped at the actual cost of the property to prevent excess benefit.
The Project utilized grant funding. However, these are additional to RCEA Project costs detailed within this document. As such, no ITC value reduction is anticipated. It is recommended that a detailed cost segregation study, including evaluation of sources and uses of funds, be prepared to clearly define eligible Project costs including grant-funded costs; determine ITC value; and confirm that the total of grant funds and ITC value does not exceed Project cost.
ii. Project Description
The Project consists of a solar PV system combined with BESS located in Humboldt County, California.
The system includes 2.5 MW DC of solar PV capacity and a 2 MW / 8 MWh battery storage component.
The Client plans to primarily utilize the electricity generated from the photovoltaic system to offset its energy usage and enhance grid reliability through integrated storage. The project is expected to have begun construction in September 24, 2019 and has an estimated Placed in Service date of September 8, 2025. iii. IRC Section 48 Investment Tax Credit Summary
Requirements to obtain a Section 48 ITC include:
• The Project must begin construction by December 31, 2024 by meeting “begun construction” requirements;
• The property must qualify under IRC Section 48(a)(3) as “Energy Property”; • Depreciation must be allowable for the property;
• The property must meet any performance and quality standards prescribed by the IRS; and • ITC is earned when energy property is placed in service, which may occur within four years of beginning construction to show continuous construction. See Continuity Requirements for further information.
Impact of Tax-Exempt Financing on ITC Amount (Example)
ITC Rate % Estimated ITC Amount
Credit rate before tax-exempt financing implications 30% $1,603,335 Net credit rate (rate reduced by 30%) 21% $1,122,335
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a) Begun Construction Requirements
The Project has an estimated Beginning of Construction date of September 24, 2019 and thus meets the requirement to have begun construction prior to December 31, 2024. 5% Safe Harbor Test and Physical Work Test
To be eligible for the ITC, construction must begin prior to the date established for each type of property and be continuous until the project is placed in service (see below for definition of “continuous and “placed in service”). To demonstrate compliance with the begun construction requirement, a qualifying project must meet one of two tests as defined under IRS Notice 2013-29 and Notice 2022-61. • 5% Safe Harbor Test: Taxpayer must pay or incur at least 5% of the total eligible (energy property) costs of the energy project
o Incurred Defined: Treas. Reg. Section 1.461-1(a) defines incurred as when the below requirements have been satisfied:
▪ Establish the fact of liability;
▪ The amount of liability can be determined with reasonable accuracy; and ▪ Economic performance has occurred.
o Economic Performance: Treas. Reg. Section 1.461-4(d)(6) allows for economic performance to occur when payment is made if the taxpayer can reasonably expect the services or property to be provided within 3½ months after the date of payment. o As emphasized above, services or property are provided to a taxpayer when delivered, accepted, or title transfers.
o If different services or items of property are provided to a taxpayer under a single contract or agreement, economic performance occurs over the time each service or property is provided so long that one of the following is met:
▪ The separated line item exceeds 10% of the total contract price or; ▪ The cost of the separated services or property is treated on the taxpayer’s books and records as separate items.
• Physical Work of a Significant Nature (“Physical Work Test”): Begun construction is met under the physical work test when “physical work of significant work” begins. Per IRS Notice 2022-61, physical work performed both by the taxpayer and by others under a binding written contract are considered. Further, the Notice explicitly states the Physical Work Test focuses on the nature of work performed and not the amount or cost of work performed. o A binding written contract is defined within Treas. Reg. Section 1.168(k)-1(b)(4)(ii) and includes the following requirements:
▪ Enforceable under state law;
▪ Does not limit damages to an amount less than 5% of the total contract price; ▪ Cannot be subject to provisions within the control of either party; ▪ Contract is not an option to acquire or sell; and
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▪ Contract is not a supply agreement.
o Physical work performed offsite does not include work to produce property that is either in existing inventory or is normally held in inventory by the vendor. o Activities that are specifically excluded from meeting the physical work test include:
▪ Planning, designing, or securing financing;
▪ Conducting geologic mapping and modeling;
▪ Obtaining permits and licenses;
▪ Conducting geophysical, gravity, magnetic, seismic and resistivity surveys; ▪ Conducting environmental and engineering studies;
▪ Clearing a site;
▪ Conducting test drilling to determine soil condition; and ▪ Excavating to change the contour of the land (distinguished from excavation for footings and foundations).
Continuity Requirements
Once a project has met “Begun Construction”, the Project must demonstrate continuous construction or continuous efforts (continuity requirement) to establish the begun construction date. There is a continuity safe harbor that allows for any project which is placed in service by the end of a calendar year that is no more than four calendar years after the calendar year during which construction of the energy property began, is deemed to have satisfied the continuity requirement.
If a project is placed into service outside the four-year window, the facts and circumstances indicating continuous efforts to advance towards completion of an energy property, such as the factors listed below, are considered for meeting the continuity requirement.
• Paying or incurring additional amounts included in the total cost of the energy project; • Entering into binding written contracts for components or future work on construction of the energy project;
• Obtaining necessary permits; and
• Performing physical work of a significant nature.
b) Placed in Service
The investment tax credit is earned when an energy project is Placed in Service. Treas. Reg. Section 1.46- 3(d)(1)(ii) provides that property is placed in service for federal income tax purposes when it is placed in a condition or state of readiness and availability for a specifically assigned function.
The Internal Revenue Service and judicial system have generally looked to a number of factors to determine when property is placed in a condition or state of readiness and availability for a specifically assigned function, including:
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• Approval of required licenses and permits;
• Passage of control of the energy project to taxpayer; • Completion of critical tests;
• Synchronized with grid, pipeline, or utility; and
• Commencement of daily or regular operation.
These factors are not exclusive. They are used as guideposts to determine whether, looking at the totality of the facts and circumstances, a facility has been placed in service. It is important to note that while a facility must be ready and available to produce on a sustained and reliable basis, it need not have reached design capacity to be considered placed in service.
Eligibility Check
The Project has an estimated Beginning of Construction date of September 24, 2019 and thus meets the requirements to have begun construction prior to December 31, 2024. Also, the Project was expected to be Placed in Service on September 8, 2025 thus meeting the IRC § 48 Continuous Construction requirements as extended under IRS Notice 2021-41, which allows up to six years for projects that began construction in 2019.
c) Eligibility of the Project under IRC Section 48: Solar Energy Property Based on the information provided by the Client, we believe certain capital expenditures of the Project are eligible for the ITC as “energy property” under IRC Section 48(a)(3)(A)(i) as “equipment which uses solar energy to generate electricity”. Eligibility requirements of energy property as related to the project are summarized in IRC Section 48(a)(3) as follows:
Qualified Energy Property: Solar Energy Property
Generally, Section 48 allows for an energy credit for the energy percentage of the basis of each qualified property placed in service during the taxable year. The energy percentage will have a base percentage of 6% in the case of qualified property listed under Section 48(a)(2)(A)(i), and 2% for all other property. This percentage may be increased if certain additional requirements are met.
For purposes of this subpart, the term “energy property” means any property that is defined under Section 48(a)(3), including
equipment which uses solar energy to generate electricity, to heat or cool (or provide hot water for use in) a structure, or to provide solar process heat, excepting property used to generate energy for the purposes of heating a swimming pool. IRC Section 48(a)(3)(A)(i).
Eligibility Check
Based on information provided by the Client, the Project is eligible for the ITC based on Section 48(a)(3) definition of qualified energy property as qualified solar property. d) Eligibility of the Project under IRC Section 48: Energy Storage Energy Property 124
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Based on the information provided by Client, we believe certain capital expenditures of the Project are eligible for the ITC as “energy property” under IRC §48(c)(6) as systems that receive, store, and deliver energy for conversion to electricity, with a nameplate capacity of not less than 5 kilowatt hours. Eligibility requirements of energy property as related to the project are summarized in IRC §48(c)(6) as follows:
Qualified Energy Property: Energy Storage Technology
Generally, §48 allows for an energy credit for the energy percentage of the basis of each qualified property placed in service during the taxable year. The energy percentage will have a base percentage of 6% in the case of qualified property listed under §48(a)(2)(A)(i), and 2% for all other property. This percentage may be increased if certain additional requirements are met.
For purposes of this subpart, the term “energy property” means any property that is defined under §48(c)(6), including property (other than property primarily used in the transportation of goods or individuals and not for the production of electricity) which receives, stores, and delivers energy for conversion to electricity (or, in the case of hydrogen, which stores energy), and has a nameplate capacity of not less than 5 kilowatt hours per IRC §48(c)(6)(A)(i).
Eligibility Check
Based on information provided by the Client, the Project is eligible for the ITC based on Section 48(a)(3) definition of qualified energy property as qualified energy storage property. e) Energy Property – Eligible Costs
Historically, only costs “integral to the production of electricity” were eligible costs for purposes of the investment tax credit under IRC Section 48. See below for historical guidance on eligible costs. In addition to this historical guidance, IRC Section 48 provides that costs incurred in implementing solar energy equipment such as storage devices, power conditioning equipment, transfer equipment, and property solely related to the functioning of these items will be integral to the production of electricity as well.
The Project is also eligible to receive additional energy property basis for the qualified interconnection costs incurred, as the Project produces electricity and has a nameplate capacity of less than 5 megawatts.
Historical Guidance - 1603 Program
Guidance for the 1603 grant program, which was created as part of the American Recovery and Reinvestment Tax Act of 2009, is commonly used to assist with determining which costs are considered eligible energy property. The prior 1603 grant in lieu of tax credit guidance states, as it pertains to property which can be used as a basis for claiming a grant in lieu of tax credit, “Qualified property includes only tangible property that is both used as an integral part of the activity performed by qualified facility and located at the site of the qualified facility. Qualified property does not include a building but may include structural components of a building. Property is an integral part of a qualified facility if the property is used directly in the qualified facility, is essential to the completeness of the activity performed in that facility and is located at the site of the qualified facility.”
80/20 Rule for Eligible Costs
The Treasury Regulations, set forth in §1.48-14(a)(1) and (2), provide that retrofitted energy property may be originally placed in service even though it contains some used components of the unit of energy property.
The fair market value of the used components of the unit of energy property must not be more than 20 125
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percent of the total value of the unit of energy property. The total value being the total value of used components and new components of property combined. When the 80/20 Rule is met, any new costs paid or incurred for property that is an integral part of the energy property (as defined in §1.48-9(f)(3)(i)) may also be included in the basis of the unit of energy property for purposes of claiming the credit. If the fair market value of the used components exceeds 20 percent of the total value, no portion of the retrofitted property qualifies for the IRC §48 credit. In the case of an energy project, as defined in §1.48-13(d), the 80/20 Rule must be applied to each separate unit of energy property included in that project.
Dual Use Property
Under Treasury Regulation §1.48-14(b)(1), the term “dual use property” refers to property that uses energy derived from both qualifying sources (those defined in §1.48-9(a), including any qualified facility for which an election has been made under §1.48-14(f)(2)) and non-qualifying sources. The Final Regulations in §1.48-14(b)(2)(i) provide that dual use property qualifies as energy property if its use of energy from non-qualifying sources does not exceed 50 percent of its total energy input during an annual measuring period.
For property that meets this 50 to 100 percent qualifying-energy range, only a proportionate share of its basis is taken into account for purposes of computing the section 48 credit. If its use of energy from qualifying sources falls below 50 percent, the dual use property does not qualify for any credit. If its use of energy from qualifying sources falls below 50 percent, the dual use property does not qualify for any credit.
The percentage of qualifying source energy uses an annual measurement period which will be the 365-day (366-day for leap year) period from the day that the dual use property is placed in service. This measurement will establish the percentage. If during any measurement period during the 5-year tax credit recapture period that the qualifying source total energy drops below 50 percent, the tax credit recapture is triggered.
Interconnection Property
Guidance regarding the qualification of interconnection property is provided by IRC Section 48(a)(8) as follows:
In general, for purposes of determining the credit under sub Section (a), energy property shall include amounts paid or incurred by the taxpayer for qualified interconnection property in connection with the installation of energy property (as defined in paragraph (3)) which has a maximum net output of not greater than 5 megawatts (as measured in alternating current), to provide for the transmission or distribution of the electricity produced or stored by such property, and which are properly chargeable to the capital account of the taxpayer.
Qualified interconnection property
The term “qualified interconnection property” means, with respect to an energy project which is not a microgrid controller, any tangible property
• which is part of an addition, modification, or upgrade to a transmission or distribution system which is required at or beyond the point at which the energy project interconnects to such transmission or distribution system in order to accommodate such interconnection, • either
o which is constructed, reconstructed, or erected by the taxpayer, or o for which the cost with respect to the construction, reconstruction, or erection of such property is paid or incurred by such taxpayer, and
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• the original use of which, pursuant to an interconnection agreement, commences with a utility.
Interconnection Agreement
The term “interconnection agreement” means an agreement with a utility for the purposes of interconnecting the energy property owned by such taxpayer to the transmission or distribution system of such utility.
Utility
For purposes of this paragraph, the term “utility” means the owner or operator of an electrical transmission or distribution system which is subject to the regulatory authority of a State or political subdivision thereof, any agency or instrumentality of the United States, a public service or public utility commission or other similar body of any State or political subdivision thereof, or the governing or ratemaking body of an electric cooperative.
f) Investment Tax Credit Calculation
Applicable Percentage
Qualified energy property defined under IRC Section 48 is eligible for an ITC with a 6% base credit with the following bonus credits available:
• 5x credit multiplier if prevailing wage and apprenticeship requirements are met, construction has begun prior to January 29, 2023, or one-megawatt exception is met (30% value – 6% multiplied by 5).
• 2% (or 10% if 5x multiplier applies) bonus credit for projects that use domestic sourced steel and equipment.
• 2% (or 10% if 5x multiplier applies) bonus credit for projects located in an energy community.
The IRA established a new structure for calculating the investment tax credit. The IRA established base credit amounts with a multiplier for meeting applicable prevailing wage and apprenticeship requirements and multiple categories of adders including bonuses for domestic content and locating projects in energy communities.
The amount of investment tax credit is the eligible cost basis multiplied by the base credit with the credit multiplier and bonus credits. For example, a qualified energy project that meets prevailing wage and apprenticeship requirements, uses qualified domestically sourced content, and is located in a qualified energy community will be eligible for a tax credit valued at 50% of eligible costs.
Reduction in Credit for Financing via Tax-Exempt Bonds
The amount of investment tax credit determined with respect to any energy project for any taxable year shall be reduced by the lessor of 15% (in case of any property that began construction before August 16, 2022, 50%) or the pro rata portion of tax-exempt financing, as calculated below:
• The numerator of which is the sum, for the taxable year and all prior taxable years, of proceeds of an issue of any obligations the interest on which is exempt from tax under IRC Section 103, and which is used to provide financing for the energy project; and 127
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• The denominator of which is the aggregate number of additions to the capital account for the energy project for the taxable year and all prior taxable years.
ITC Recapture
Under IRC Section 50, investment tax credits will be recaptured if the asset ceases to be eligible ITC property. For example, if sold, disposed, or otherwise ceases to operate within five tax years from the point where the asset is placed in service, the tax credit may be subject to recapture. The amount of recapture phases down by 20% after each year the project is placed in service. For example, in year one if a recapture event were to occur, 100% of the credit value would be recaptured. In year two, 80% would be recaptured.
Depreciable Basis Reduction
Under IRC Section 48, the ITC reduces the depreciable basis of the energy property being claimed for such credit by a factor of 50% of the ITC credit. For example, if a 30% ITC is claimed on eligible energy property, the depreciable basis of such property must be reduced by 15% (50% of 30%) so the depreciable basis of the energy property is 85% of its original value.
g) Increased Credit Amount Requirements
The increased credit amount requirements, as defined within IRC Section 48(a)(9), are critical to maximizing the eligible credit. Meeting these requirements allows the taxpayer to claim a 5x multiplier of the base credit which, in the case of the credits being discussed in this report, increases the credit from 6% to 30% of eligible energy property. Similarly, the 5x multiplier applies to 2% bonus credits (Domestic Content bonus and Energy Community) to increase those bonus credits to 10% each.
A project meets the increased credit amount requirements if it is one of the following:
• A project with a maximum net output of less than 1 megawatt (as measured in alternating current) or thermal energy (the one-megawatt exception);
o In accordance to a qualified biogas project, Treas. Reg. Section 1.48-13(e)(5) would provide that 3.4 MMBtu/hour can be used as equivalent to the One-Megawatt Exception.
Taxpayers may convert the maximum net output of 3.4 mmBtu/hour into an equivalent maximum net volume flow in scf per hour using the appropriate high heat value conversion factors found in the Environmental Protection Agency (EPA) GHG Reporting Rule (GHGRR) at table C-1 to subpart C of part 98 (40 CFR part 98).Otherwise, taxpayers may calculate their own equivalent volumetric flow if the heat content of the gas is known. • A project the construction of which begins before the date that is 60 days after the Secretary publishes guidance with respect to the requirements of IRC Section 48(a)(10)(A) and (11), which corresponds to January 29, 2023 given the issuance of IRS Notice 2022-61 (the Beginning of Construction Exception); or
• A facility which satisfies the Prevailing Wage and Apprenticeship (PWA) requirements of IRC Section 48(a)(10)(A) and (11).
IRC Section 48(a)(10)(A) and (11) outline the PWA requirements as the following:
Prevailing wage requirements with respect to any energy project (defined below):
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• At risk of penalty and/or recapture of claimed credits, any laborers and mechanics employed by the taxpayer or any contractor or subcontractor must be paid wages at rates not less than the prevailing rates for construction, alteration, or repair of a similar character in the locality in which such project is located as most recently determined by the Secretary of Labor, in accordance with subchapter IV of chapter 31 of title 40, United States Code (wage rate requirements) for:
o The construction of the energy project; and
o Alterations or repairs of such energy project for the five-year period beginning on the date the project is originally placed in service.
Apprenticeship requirements with respect to any energy project:
• Labor hours
o At least the applicable percentage (defined below) of the total labor hours of the construction, alteration, or repair work (including such work performed by any contractor or subcontractor) be performed by qualified apprentices:
▪ 10% if construction begins before January 1, 2023
▪ 12.5% if construction begins after December 31, 2022, and before January 1, 2024 ▪ 15% if construction begins after December 31, 2023.
• Apprentice ratio
o The previous requirement is subject to any applicable requirements for apprentice-to-journey worker ratios of the Department of Labor or the applicable State apprenticeship agency. • Participation
o Each taxpayer, contractor, or subcontractor who employs four or more individuals to perform construction, alteration, or repair work with respect to the construction of an energy project shall employ one or more qualified apprentices to perform such work. o Exceptions
▪ Good faith effort:
• taxpayer shall be deemed to have satisfied the apprenticeship requirements with respect to an energy project if such taxpayer has requested qualified apprentices from a registered apprenticeship program; and
• such request has been denied, provided that such denial is not the result of a refusal by the taxpayer, or any contractors or subcontractors engaged in the performance of construction, alteration, or repair work with respect to such energy project to comply with the established standards and requirements of the registered apprenticeship program; or
• the registered apprenticeship program fails to respond to such request within five business days after the date on which such registered apprenticeship program received such request.
o Capacity or timing:
▪ The 5x multiplier on the base ITC credit shall be allowed without respect to prevailing wage and apprenticeship requirements if the energy project:
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• has a maximum net output of less than 1 megawatt of electrical (AC) or thermal energy; or
• construction began before January 29, 2023, 60 days after the Secretary published guidance with respect to the requirements.
Penalties for claiming the prevailing wage and apprenticeship multiplier with failure to meet such requirements may result in penalties ranging from $50 to $500 per labor hour short of such labor hour and/or participation requirements.
Labor hours is defined as the total number of hours devoted to the performance of construction, alteration, or repair work by any individual employed by the taxpayer or by any contractor or subcontractor, and excludes any hours worked by
• foremen,
• superintendents,
• owners, or
• persons employed in a bona fide executive, administrative, or professional capacity (within the meaning of those terms in part 541 of title 29, Code of Federal Regulations).
Qualified apprentice is defined as an individual who is employed by the taxpayer or by any contractor or subcontractor and who is participating in a registered apprenticeship program, as defined in Section 3131(e)(3)(B) (an apprenticeship registered under the Act of August 16, 1937 that meets the standards of subpart A of part 29 and part 30 of title 29, Code of Federal Regulations).
Eligibility Check
The Project has an estimated Beginning of Construction date of September 24, 2019 and thus meets PWA requirements through “Beginning of Construction Exception” to have begun construction prior to January 29, 2023. Thus, the base ITC energy percentage and any bonus percentages will be multiplied by five (5). h) Domestic Content Bonus Credit Requirements
The domestic content requirements are defined within IRC Section 48(a)(12). The general requirement is that 100% of structural steel used within a project and 40% of components for projects are required to be manufactured in the United States that begin construction before the end of 2025. IRS issued Notice 2023- 38 and Notice 2024-41 as preliminary guidance regarding domestic content requirements. The Notice outlines certification and record keeping requirements that will be further described in future proposed regulations issued by the U.S. Secretary of Treasury.
A taxpayer must certify to the Secretary (at such time, and in such form and manner, as the Secretary may prescribe) that any steel, iron, or manufactured product which is a component of such energy project (upon completion of construction) was produced in the United States (as determined under Section [2] 661 of title 49, Code of Federal Regulations [Buy America]).
• Structural Steel and iron
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o All manufacturing processes must take place in the United States, except metallurgical processes involving refinement of steel additives.
o The structural steel and iron requirements apply to all construction materials made primarily of steel or iron. These items include, but are not limited to, structural steel or iron, steel or iron beams and columns, running rail and contact rail. These requirements do not apply to steel or iron used as components or subcomponents of other manufactured products or rolling stock, or to bimetallic power rail incorporating steel or iron components. • Manufactured products
o Not less than 40% of the total costs of all manufactured products of the energy project are attributable to manufactured products (including components) which are mined, produced, or manufactured in the United States.
o For projects that begin construction after 12/31/2024 the required domestic content percentage increases from 40% as listed below:
▪ Beginning construction after 12/31/2024 and before 1/1/2026 – 45% of manufacturing costs required to be domestic.
▪ Beginning construction after 12/31/2025 and before 1/1/2027 – 50% of manufacturing costs required to be domestic.
▪ Beginning construction after 12/31/2026 – 55% of manufacturing costs required to be domestic.
Eligibility Check
The Project does not meet the requirements to be eligible for the Domestic Content bonus. i) Energy Community Bonus Credit Requirements
The Energy Community bonus credit allows for an additional 10% ITC value for qualifying facilities. The facility must qualify as either a brownfield site category, a statistical area category, or a coal closure category.
Energy communities are defined within IRC Section 45(b)(11)(B) as meeting any one of the qualifications below:
Brownfield Category
• Defined as meaning real property, the expansion, redevelopment, or reuse of which may be complicated by the presence or potential presence of a hazardous substance, pollutant, or contaminant, subject to various exclusions.
• The Safe Harbor rules for Brownfield sites are:
o Listed under EPA’s Cleanups in My Community webpage or similar webpages maintained by states, territories, or Indian tribes
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▪ An ASTM E1903 Phase II Environmental Site Assessment (phase II Assessment) has been completed which confirms the presence on the site of a hazardous substance as defined under 42 U.S.C. Section 9601(14), or a pollutant or contaminant as defined under 42 U.S.C. Section 9601(33);
▪ For projects with nameplate capacity not greater than 5MW, an ASTM E1903 Phase I Environmental Site Assessment (phase I Assessment) has been completed and identifies the presence or potential presence of a hazardous substance as defined under 42 U.S.C.
Section 9601(14) (hazardous substance), or a pollutant or contaminant as defined under 42 U.S.C. Section 9601(33) (pollutant or contaminant).
Eligibility Check
The approximate location of the Project is 3651 Boeing Ave, McKinleyville, CA 95519. The site is adjacent to a parcel listed as a Brownfield property by the United States Environmental Protection Agency. 2 As such,
there is reason to study Project parcels to determine potential to be considered eligible for the Energy Community bonus. Given the site’s general history and location near classified Brownfields, performance of a Phase 1 environmental review of the parcels associated with the Project may confirm qualification as an Energy Community and eligibility for the 10% Energy Community bonus. However, because additional due diligence and documentation is required to confirm applicability of the Brownfield designation, the bonus credit has not been assumed.
Statistical Area Category
• A metropolitan statistical area or non-metropolitan statistical area which o has (or, at any time during the period beginning after December 31, 2009, had) ▪ 0.17 percent or greater direct employment (fossil fuel employment); or ▪ 25 percent or greater local tax revenues (fossil fuel tax revenue). o related to the extraction, processing, transport, or storage of coal, oil, or natural gas (as determined by the Secretary); and
o has an unemployment rate at or above the national average unemployment rate for the previous year (as determined by the Secretary, with guidance released in May 2023).
Eligibility Check
The Project site is in Humboldt County, CA which is in the Eureka–Arcata–Fortuna Micropolitan Statistical Area. The MSA does not have 0.17 percent or greater direct employment in the fossil fuels industry or an unemployment rate that was determined to be higher than the national average for the previous year. Thus, the Project does not meet the requirements for the Statistical Area Category and is not eligible for the Energy Community bonus credit.
Coal Closure Category
• A census tract in which
2 U.S. EPA Brownfields database
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o a coal mine has closed after December 31, 1999;
o a coal-fired electric generating unit has been retired after December 31, 2009; or o is directly adjacent to any census tracts defined above.
IRS Notice 2023-29 indicates the nameplate capacity test or the footprint test will be used to determine the location of the project. The notice further explains that if the project location qualifies as an energy community at the Beginning of Construction date, the location will also qualify as an energy community at the Placed In-Service date. IRS Notice 2023-45 further clarifies the requirements for a brownfield site safe harbor. Additional energy communities are defined under IRS Notice 2024-30.
Eligibility Check
The Project site is in Census Tract 06-023-010400, which is not included in the lists of eligible Coal Closure census tracts according to IRS Notice 2023-29 Appendix C, IRS Notice 2023-47, Appendix 3, IRS Notice 2024-48, Appendix 2, IRS Notice 2025-31, Appendix 4, or other related guidance. Further, this census tract or tracts adjacent to it, do not appear to have any identified coal mine closures or coal-fired electric generating unit closure sites since the most recently updated list provided by the IRS. Thus, the Project does not qualify as an energy community due to coal closure category qualifier. 133
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iv. Monetization
a) Elective Payment
The Inflation Reduction Act of 2022 created IRC Section 6417 which allows an applicable entity to make an election to, with respect to any applicable credit determined with respect to such entity, be treated as making a payment against the tax imposed by subtitle A (for the taxable year with respect to which such credit was determined) equal to the amount of such credit (often referred to as “elective pay” or “direct pay”). The cash proceeds received for the credit are considered tax exempt income from a federal income tax perspective.
“Applicable Entity” Defined
The following are outlined as “applicable entities” per IRC Section 6417:
• any organization exempt from the tax imposed by subtitle A; • any State or political subdivision thereof;
• the Tennessee Valley Authority;
• an Indian tribal government (as defined in Section 30D(g)(9); • any Alaska Native Corporation (as defined in Section 3 of the Alaska Native Claims Settlement Act (43 U.S.C. 1602(m)); or
• any corporation operating on a cooperative basis which is engaged in furnishing electric energy to persons in rural areas.
b) Transferability
The Inflation Reduction Act of 2022 also created IRC §6418 which allows an eligible taxpayer, that is not described under §6417(d)(1)(A) (i.e., applicable entities), to make an election to transfer (sell) eligible credits to an unrelated taxpayer in exchange for cash. The cash proceeds received on the sale of the ITC are considered tax exempt income from a federal income tax perspective. The election to transfer credits is not an “all or nothing” election as portions of the credit earned in a year can transferred with the remaining portion consumed to offset shareholder tax liability. The sale of credits is limited to the taxable entity that placed the project in service, thus credits cannot be sold after being transferred or allocated to shareholders.
The ability to transfer credits applies to both the investment tax credit and production tax credit. Credits eligible to be transferred are the following:
• so much of the credit for alternative fuel vehicle refueling property allowed under §30C which, pursuant to subsection (d)(1) of such section, is treated as a credit listed in §38(b); • the renewable electricity production credit determined under §45(a); • the credit for carbon oxide sequestration determined under §45Q(a); 134
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• the zero-emission nuclear power production credit determined under §45U(a); • the clean hydrogen production credit determined under §45V(a); • the advanced manufacturing production credit determined under §45X(a); • the clean electricity production credit determined under §45Y(a); • the clean fuel production credit determined under §45Z(a); • the energy credit determined under §48;
• the qualifying advanced energy project credit determined under §48C; and • the clean electricity investment credit determined under §48E.
The election can be made by the due date (including extensions of time) for the federal tax return for the taxable year for which the credit is determined.
Further discussions with management and analysis will be completed to determine the value of credits that can be self-consumed by investors (if any), with the remaining being transferred for cash proceeds.
Eligibility Check
Under §6417, the Client, an applicable entity that completed the construction, reconstruction, or erection of the energy property or acquired the property and commenced the original use of such property, can elect to be treated as making a payment against the tax imposed by subtitle A equal to the amount of such credit.
The election can be made by the due date (including extensions of time) for the federal tax return for the taxable year for which the credit is determined.
v. Conclusion
a) Summary of Findings and Recommendations
Based on review of the information provided by the Client, the RCEA Microgrid Project is likely to be eligible for the ITC as “energy property” under IRC Section 48(a)(3)(A)(i) as “equipment which uses solar energy to generate electricity” and under IRC Section 48(a)(3)(A)(ix) as an “energy storage technology” under IRC §48(c)(6). The Project meets the increased credit amount requirements through the begun construction safe harbor. Further, the Project does not meet the requirements of the Domestic Content bonus credit or Energy Community bonus credit. Thus, the estimated value of the ITC is 30% of ITC-eligible costs.
Key considerations for the Client include (a) further due diligence to analyze and document potential qualification for the Energy Community bonus credit under the Brownfield designation, and (b) assessment of use of tax-exempt funding sources.
vi. Next Steps
• Substantiation of Beginning of Construction and Placed in Service dates; • Conduct Phase 1 environmental site assessment to evaluate potential Brownfield classification to further determine applicability of Energy Community bonus credit; 135
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• Perform a cost segregation study to determine the eligible basis of energy property and assess implication of tax exempt funding on credit rate (if any); and • Prepare tax credit documents for submission for filling in November 2026 with the ability to extend to May 15, 2027, including:
o Credit summary;
o Grouping, Beginning of Construction, and Placed in Service memorandums; o Cost segregation report;
o IRS-preregistration assistance;
o Tax filing forms; and
o 6417 Election Statement.
vii. Disclosures
Pursuant to the rules of professional conduct set forth in Circular 230, as promulgated by the United States Department of the Treasury, nothing contained in this communication was intended or written to be used by any taxpayer for the purpose of avoiding penalties that may be imposed on the taxpayer by the Internal Revenue Service, and it cannot be used by any taxpayer for such purpose. No one, without our express prior written permission, may use or refer to any tax advice in this communication in promoting, marketing, or recommending a partnership or other entity, investment plan or arrangement to any other party.
The accompanying credit estimates are based on information provided by management. Baker Tilly is not performing an audit of the Project or providing a formal opinion regarding the Project’s eligibility for the ITC.
There is no guarantee that the Project will qualify for the ITC.
This memorandum is a summary discussion and is limited to the facts described. It is not intended to be a formal opinion of tax consequences and does not contain a full description of all facts or a complete exposition and analysis of all relevant tax authorities.
The conclusions and recommendations contained in this memorandum are based on our understandings of the facts, assumptions, information, and documents referenced herein and current tax laws and published tax authorities in effect as of the date of this memorandum, which are subject to change. If the facts and assumptions are incorrect or change or the tax laws change, the conclusions and recommendations would likewise be subject to change.
This memorandum reflects our interpretation of the IRC, the Treasury Regulations promulgated thereunder, cases, public and private rulings, administrative announcements, and other tax authority in effect as of the date of our memorandum. If the tax authorities relied upon to issue our memorandum change, the conclusions and recommendations would likewise be subject to change. Baker Tilly Advisory Group, LP assumes no obligation and does not intend to update the memorandum for any future changes in tax law, regulations, or other interpretations.
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Baker Tilly
Master Services Agreement
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Baker Tilly Advisory Group, LP
205 N Michigan Ave
Chicago, IL 60601
tel +1 (312) 729 8000
bakertilly.com
Eileen Verbeck
Redwood Coast Energy Authority
633 3rd Street
Eureka, California 95501
United States
Dear Eileen Verbeck:
Baker Tilly Advisory Group, LP (“Baker Tilly”) is pleased to have the opportunity to present the following Master Services Agreement (“MSA”) to Redwood Coast Energy Authority (“Client”).
We look forward to discussing the details of this Master Services Agreement and welcome the opportunity to address any questions you may have as you review this document.
Sincerely,
Michelle Isenhouer Hanlin,
Baker Tilly Principal
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