VCE 10/14/2025 Board Special Meeting Agenda Page 1 of 3 Special Meeting of the Valley Clean Energy Alliance
Board of Directors
Tuesday, October 14, 2025 at 3:30 p.m.
City of Woodland Council Chambers
300 First Street, Woodland, California 95695
Board Members will be attending in-person and public participation will be in-person and available via Zoom Webinar (video/teleconference). VCE will, to the best of its ability, provide hybrid and remote options for VCE meeting participants and to the public; however, VCE cannot guarantee these options will be available due to technical limitations outside of our control. For assurance of public comment, VCE encourages in-person and written public comments to be submitted as described below when possible. VCE, to the best of its abilities, will provide participation via the Zoom platform.
Accommodations for Persons with disabilities: Individuals who need special assistance or a disability-related modification or accommodation to participate in this meeting, or who have a disability and wish to request an alternative format for the meeting materials, should contact Alisa Lembke, VCE Board Clerk/Administrative Analyst, as soon as possible and preferably at least two (2) working days before the meeting at (530) 446-2754 or [email protected].
If you have anything that you wish to be distributed to the Board and included in the official record, please hand it to a member of VCEA staff who will distribute the information to the Board members and other staff.
Please note that the numerical order of items is for convenience of reference. Items may be taken out of order on the request of any Board member with the concurrence of the Board. Staff recommendations are advisory to the Board. The Board may take any action it deems appropriate on any item on the agenda even if it varies from the staff recommendation.
Members of the public who wish to listen to the Board of Director’s meeting may do so with the video/teleconferencing call-in number and meeting ID code. Video / teleconference information below to join meeting:
Join meeting via Zoom:
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Meeting ID: 875 440 9715
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One tap mobile:
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1 VCE 10/14/2025 Board Special Meeting Agenda Page 2 of 3 Or Dial:
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Meeting ID: 875 4400 9715
Public comments may be submitted electronically or during the meeting. Instructions on how to submit your public comments can be found in the PUBLIC PARTICIPATION note at the end of this agenda.
Board Members: Bapu Vaitla (City of Davis, Chair), Jesse Loren (City of Winters, Vice Chair), Lucas Frerichs (Yolo County), Tom Stallard (City of Woodland), Sheila Allen (Yolo County), Donna Neville (City of Davis), Tania Garcia-Cadena (City of Woodland), Richard Casavecchia (City of Winters)
Alternate Board Members: Angel Barajas (Yolo County), Mayra Vega (City of Woodland), Linda Deos (City of Davis), Albert Vallecillo (City of Winters) 3:30 p.m. Call to Order
1. Welcome and Approval of the Agenda
2. Public Comment: This item is reserved for persons wishing to address the Board on any VCE-related matters that are not otherwise on this meeting agenda or are listed on the Consent portion of the agenda. Public comments on matters listed on the agenda shall be heard at the time the matter is called. As with all public comment, members of the public who wish to address the Board are customarily limited to two minutes per speaker, electronically submitted comments should be limited to approximately 300 words.
Comments that are longer than 300 words will only be read for two minutes. All electronically submitted comments, whether read in their entirety or not, will be posted to the VCE website within 24 hours of the conclusion of the meeting. See below under PUBLIC PARTICIPATION on how to provide your public comment.
CONSENT AGENDA
3. Approve September 11, 2025 Board meeting Minutes.
4. Receive 2025 long range calendar.
5. Receive Treasurer’s report August 31, 2025.
6. Receive legislative update provided by Pacific Policy Group.
7. Receive September 2025 regulatory update dated October 1, 2025 provided by Keyes & Fox.
8. Receive Community Advisory Committee September 25, 2025 meeting summary.
9. Receive Customer Participation update (Quarter 3 2025).
10. Receive Enterprise Risk Management update (Bi-annual). (Action)
REGULAR AGENDA
11. Approve Agreement for Residential Dynamic Pricing Pilot Program with U.C. Davis and Panasonic. (Action)
12. Approve Large Load Rate Setting policy. (Discussion/Action)
13. Approve adoption of VCE’s Strategic Plan Major update. (Discussion/Action)
14. End of Session Legislative update provided by Pacific Policy Group. (Information) 2 VCE 10/14/2025 Board Special Meeting Agenda Page 3 of 3
15. Board Member and Staff Announcements: Action items and reports from members of the Board, including announcements, AB1234 reporting of meetings attended by Board Members of VCE expense, questions to be referred to staff, future agenda items, and reports on meetings and information which would be of interest to the Board or the public.
16. Adjournment/Announcement: The Board will adjourn their regular meeting to Thursday, November 13, 2025 at the City of Woodland Council Chambers located at 300 First Street, Woodland, California 95695.
PUBLIC PARTICIPATION: Public Comments: Public participation for this meeting will be done electronically via e-mail and during the meeting as described below.
Public participation via e-mail: If you have anything that you wish to be distributed to the Board and included in the official record, please e-mail it to VCE staff at [email protected] . If information is received by 3:00 p.m. on the day of the Board meeting it will be e-mailed to the Board members and other staff prior to the meeting. If it is received after 3:00 p.m. the information will be distributed after the meeting, but within 24 hours of the conclusion of the meeting. Written public comments that do not exceed 300 words will be read by the VCE Board Clerk, or other assigned VCE staff, to the Board and the public during the meeting subject to the usual time limit for public comments [two (2) minutes].
General written public comments will be read during Item 2, Public Comment. Written public comment on individual agenda items should include the item number in the “Subject” line for the e-mail and the Clerk will read the comment during the item. All written comments received will be posted to the VCE website.
Verbal public participation during the meeting:
1) If attending in person, please complete a Comment Card and return it to the Board Clerk.
2) If attending remotely via Zoom, there are two (2) ways for the public to provide verbal comments:
A. If you are attending by computer, activate the “participants” icon at the bottom of your screen, then raise your hand (hand clap icon) under “reactions”. When called upon, you will be “unmuted” to allow to speak.
B. If you are attending by phone only, you will need to press *9 to raise your hand.
When called upon, press *6 to unmute your microphone.
VCE staff will acknowledge that you have a public comment to make during the item and will call upon you to make your verbal comment.
Public records that relate to any item on the open session agenda for a regular or special Board meeting are available for public review on the VCE website. Records that are distributed to the Board by VCE staff less than 72 hours prior to the meeting will be posted to the VCE website at the same time they are distributed to all members, or a majority of the members of the Board. Questions regarding VCE public records related to the meeting should be directed to Board Clerk Alisa Lembke at (530) 446-2750 or [email protected]. The Valley Clean Energy website is located at:
https://valleycleanenergy.org/board-meetings/.
3 Item 3
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 3
TO: Board of Directors
FROM: Alisa Lembke, Board Clerk / Administrative Analyst SUBJECT: Approval September 11, 2025 meeting Minutes
DATE: October 14, 2025
RECOMMENDATION
Receive, review and approve the attached September 11, 2025 meeting Minutes.
Attachment: September 11, 2025 meeting Minutes
4 VCEA Minutes September 11, 2025 Board Meeting Page 1 of 3
MINUTES OF THE VALLEY CLEAN ENERGY ALLIANCE
BOARD OF DIRECTORS MEETING
THURSDAY, SEPTEMBER 11, 2025
The Board of Directors of the Valley Clean Energy Alliance duly noticed their regular meeting for Thursday, September 11, 2025 at 5:30 p.m. to be held at City of Woodland Council Chambers located at 300 First Street, Woodland, California 95695. Board Chair Bapu Vaitla established that there was a quorum present and the meeting began at 5:31 p.m.
Board Members Present: Bapu Vaitla (Chair), Tom Stallard, Lucas Frerichs, Tania Garcia-Cadena, Shiela Allen, Donna Neville, Richard Casavecchia Members Absent: Jesse Loren (Vice Chair, attended remotely) Welcome,
Approval of the
Agenda
Board Secretary Alisa Lembke informed those that Vice Chair Jesse Loren was attending remotely, and Director Loren was informed that she could not vote on any items. Motion made by Director Stallard to approve the September 11, 2025 regular meeting Agenda, seconded by Director Garcia-Cadena. Motion passed with Director Loren absent.
Public Comment –
General and
Consent Items
Director Vaitla opened up the public comment period on general and consent items. There were no written or verbal public comments.
Approval of
Consent Agenda /
Resolution 2025-
009
Motion made by Director Frerichs to approve the Consent agenda items, seconded by Director Allen. Motion passed with Director Loren absent. The following items were:
3. approved June 12, 2025 Board meeting Minutes;
4. received 2025 long range calendar;
5. received Treasurer’s reports: A) May 31, 2025, B) June 30, 2025 and C) July 31, 2025;
6. received July/August 2025 regulatory update dated September 3, 2025 provided by Keyes & Fox;
7. received Community Advisory Committee meeting summaries: 1) June 26, 2025 meeting and Strategic Plan Update Workshop; 2) July 24, 2025 meeting; and, 3) August 28, 2025 meeting
8. received Customer participation updated (2nd Quarter 2025);
9. accepted and attested to the accuracy of Valley Clean Energy’s 2024 Power Content Label; and,
5 VCEA Minutes September 11, 2025 Board Meeting Page 2 of 3
10. approved VCE Capitalization Policy as Resolution 2025-009.
Item 11: Receive
AgFIT (Dynamic
Pricing) Pilot
Program update.
(Information)
VCE Staff Rebecca Kuczynski provided an AgFIT (Dynamic Pricing) Pilot Program update. The Board and Staff discussed: goals and results of the pilot program, savings to those agriculture customers who participated, future and or current programs similar, and rate schedules and differentials.
There were no verbal or written public comments.
Item 12: Board
Member and Staff
Announcements.
VCE Chief Executive Officer Mitch Sears informed those present that VCE Staff has connected with the individual VCE jurisdictions to introduce VCE’s Electric Advisor Service. The goal is to work with each jurisdiction individually to reach their electric objectives and goals.
Mr. Sears informed those present that “Prepay” transactions recognized an approximate $200,000 savings for the month of July 2025 and over the next ten (10) years VCE anticipates saving approximately $14 million.
Mr. Sears provided a brief status of the Power Charge Indifferent Adjustment (PCIA) proceeding and anticipate the 2026 PCIA will be higher than 2025. PCIA projections are being incorporated into VCE’s 2026 preliminary budget.
Mr. Sears informed those present that he took a trip with U.C. Davis to Japan and presented information on dynamic pricing because of VCE’s experience with the AgFIT Pilot Program.
Mr. Sears announced that VCE will have a booth at two local events this coming weekend: Woodland Farmers Market on Saturday (9/13/25) and Winters Farmers Market on Sunday (9/14/25).
Lastly, Mr. Sears informed those present that VCE Staff are working on a large electric load policy, currently being reviewed by the Community Advisory Committee (CAC), and, are monitoring legislative bills.
The Board had no announcements. There were no written or verbal public comments.
6 VCEA Minutes September 11, 2025 Board Meeting Page 3 of 3 Item 13:
Announcement /
Adjournment
Chair Vaitla announced that the Board’s next scheduled regular meeting is on Thursday, October 9, 2025 at 5:30 p.m. at the City of Davis Community Chambers located at 23 Russell Boulevard, Davis, California 95616. The Board adjourned their regular meeting at 6:00 p.m. to reconvene into the Strategic Plan Workshop after a brief break.
RECONVENED AS STRATEGIC PLAN UPDATE WORKSHOP
Item 1: Public
Comment.
Chair Vaitla began the Strategic Plan Update Workshop at 6:05 p.m. There were no written or verbal public comments.
Item 2: Strategic
Plan Update
Workshop
VCE Chief Executive Officer Mitch Sears introduced this item. VCE Staff provided the background of the Major Update to the Strategic Plan (SP), highlighting the proposed general and administrative updates and Goal 2 (power supply resources) updates; and, the input received from holding two other public workshops and the results of the Customer survey. The Board and Staff discussed and provided input on: affordability, generation energy rates and rate independence, Customer needs, reliability, renewable energy and RECs (Renewable Energy Certificates), carbon free resources, compliance of California’s RPS (Renewable Portfolio Standard), defining success of reaching VCE’s goals, local energy, SP goal flexibility, and municipalization.
After hearing the Board’s input, VCE Staff will revise the Major Update to the Strategic Plan and present a draft Major Update to the Board at their next meeting.
Item 3:
Adjournment of
Workshop
The meeting was adjourned at 7:45 p.m.
Alisa M. Lembke
VCEA Board Secretary
7 Item 4
VALLEY CLEAN ENERGY ALLIANCE
Staff Report - Item 4
____________________________________________________________________________________ TO: Board of Directors
FROM: Alisa Lembke, Board Clerk/Administrative Analyst
SUBJECT: Board and Community Advisory Committee 2025 Long-Range Calendar DATE: October 14, 2025
Recommendation
Receive and file the 2025 Board and Community Advisory Committee long-range calendar listing proposed meeting topics. Please note that meeting locations and topics may change.
Attachment: 2025 Board and CAC long range calendar
8 10/7/2025
VALLEY CLEAN ENERGY
2025 Meeting Dates and Proposed Topics
Board and Community Advisory Committee (CAC)
(Note: Meeting locations and Topics are subject to change)
MEETING DATE TOPICS ACTION
January 9, 2025
(Cancelled)
Board
(Woodland)
• This meeting was cancelled.
January 23, 2025
NO QUORUM, ITEMS
MOVED TO FEBRUARY
27, 2025 MEETING
Advisory
Committee
(Woodland)
• 2025 CAC Task Group (s) formation (Annual) (R)
• Customer Participation Update (4th Quarter 2024) (O)
• 2024 Year in review: Customer Care & Marketing (Placeholder) (R)
• Strategic Plan (O)
• Discussion/Action
• Discuss/Action
• Information
• Discussion/Action
February 13, 2025 Board
(Davis)
• Oaths of Office for Board Members (Annual - new Members only) (R)
• Election of Officers for 2025 (Annual) (R)
• Customer Participation Update (4th Quarter 2024) (O)
• Receive CAC Year-end Task Group Reports (O)
• 2024 Year-end review: Customer Care & Marketing (O)
• Update to VCE Employee Handbook (Placeholder) (R)
(historically Jan.)
• Prepay (Placeholder) (O)
• Annual Strategic Plan Report (R) (historically Jan.)
• Action
• Nominations
• Information
• Information
• Information
• Action
• Action
• Information/Discussion
• Discussion/Action
February 27, 2025 Advisory
Committee
(Davis)
• 2025 CAC Task Group (s) formation (Annual) (R)
• Customer Participation Update (4th Quarter 2024) (O)
• 2024 Year-end review: Customer Care & Marketing
(Placeholder) (R)
• Strategic Plan (O)
• Discussion/Action
• Information
• Information
• Discussion/Action
March 13, 2025 Board
(Woodland)
• This meeting was cancelled.
March 27, 2025 Advisory
Committee
(Woodland)
• Approval of 2025 CAC Task Group “Charges” (R) (historically in Jan.)
• Senate Bill 540 (Pathways Initiative & Regional Organization) • Action
• Information/Discussion
9 *No meeting unless an urgent matter needs to be addressed April 10, 2025 Board
(Davis)
• Receive Enterprise Risk Management Report (Bi-Annual) (R) • Customer Participation update (1st Quarter 2025) (O)
• Calendar Year 2024 Audited Financial Statements (James Marta & Co.) (placeholder) (R)
• Load Management Standards Update (O)
• Power Charge Indifference Adjustment (PCIA) / Rates Workshop (placeholder) (O)
• VCE Grant activity update (O)
• Information
• Information
• Action
• Information
• Information
• Information
April 24, 2025 Advisory
Committee
(Davis)
• Load Management Standards Update (O)
• 2024 Net Margin Allocation (R)
• Senate Bill 540 (Pathways Initiative & Regional Organization) • Customer Participation update (1st Quarter 2025) (O)
• Introduction to Strategic Plan Major Update Roadmap/Timeline • Information
• Discussion/Action
• Discussion/Action
• Information
• Information
April 28 - 30, 2025 CalCCA Annual
Conference
(Irvine)
VCE Staff and some Board and CAC members attending
May 8, 2025
CANCELLED
Board
(Woodland)
• Meeting cancelled.
May 22, 2025 Advisory
Committee /
Strategic Plan
Workshop
(Esparto)
• Strategic Plan Workshop: Focus: Financial Strength/Rates and Procurement & Power Supply
• Information/Discussion
June 12, 2025 Board
(Davis)
• Re/Appointment of Members to Community Advisory
Committee (Annual) (R)
• Mid-Year 2025 Financial Update (R)
• 2024 Net Margin Allocation (R)
• Summer Preparedness outlook (O)
• Recap of CalCCA April 2025 Annual Conference (O)
• Action
• Information
• Discussion/Action
• Information
• Information
June 26, 2025 Advisory
Committee /
Strategic Plan
Workshop
(UCANR -
Davis)
• Summer Preparedness outlook (O)
• Strategic Plan Workshop: Focus: Customers & Community and Decarbonization and Grid Innovation
• Information
• Information/Discussion
10 *No meeting unless an urgent matter needs to be addressed July 10, 2025 Board
Woodland
• Meeting cancelled.
July 24, 2025 Advisory
Committee
(Woodland)
• Review preliminary draft Strategic Plan Major Update and Survey Plan (O)
• Power Portfolio Update (O)
• Information/Discussion
• Information
August 14, 2025 Board
(Davis)
• NO MEETING*
August 28, 2025 Advisory
Committee
(Davis)
• Review draft Strategic Plan Major update / Seeking
recommendation to the Board
• Large Load Tariff Design
• Customer Participation Update (2nd Quarter 2025) (O)
• Discussion/Action
• Discussion/Action
• Information
September 11, 2025 Board
(Woodland)
• Certification of 2024 Power Content Label (Annual) (R) • Capitalization Policy (placeholder) (O)
• Customer Participation Update (2nd Quarter 2025) (O)
• AgFIT Pilot Program Update (O)
• Strategic Plan Major Update Workshop (O)
• Action
• Information/Discussion
• Information
• Information
• Discussion/Action
September 25, 2025 Advisory
Committee
(Woodland)
• Large Load Rate Setting Policy • Discussion/Action
October 9, 2025
Cancelled and
rescheduled to:
Tuesday, October 14th
at 3:30 p.m.
Board
(Davis)
(Woodland)
• Enterprise Risk Management Update (Annual) (R)
• Customer Participation Update (3rd Quarter 2025) (O)
• Legislative End of Session Update (O)
• Adoption of Strategic Plan Major Update (placeholder) (O) • Large Load Rate Setting Policy (O)
• Residential Dynamic Pricing Pilot Program
• Discussion/Action
• Information
• Information
• Discussion/Action
• Discussion/Action
• Discussion/Action
October 23, 2025 Advisory
Committee
(Davis)
• 2024 Power Content Label Outreach (O)
• Customer Participation Update (3rd Quarter 2025) (O)
• Legislative End of Session Update (O)
• 2026 Legislative & Regulatory Platform
• Review Phase 2 of EV Rebate Program (“Charge Your Ride”) / Seeking recommendation to the Board (placeholder)
• Discussion of forming local energy Task Group.
• Information
• Information
• Information
• Action
• Discussion/Action
• Discussion
November 13, 2025 Board
(Woodland)
• 2026 Preliminary Operating Budget (R)
• Contract Renewals (R) (placeholder)
• Adoption of Strategic Plan Major Update (placeholder) (O) • Information/Discussion
• Discussion/Action
• Discussion/Action
11 *No meeting unless an urgent matter needs to be addressed • Phase 2 of EV Rebate Program (“Charge Your Ride”) (O) (placeholder)
• Discussion/Action
November 27, 2025
November 20, 2025
(rescheduled to
November 20 due to
Thanksgiving holiday
on Nov. 27
th)
Advisory
Committee
(Woodland)
• Review CAC Draft 2025 Task Group Year-end Reports (R) • GHG Free Attributes (R) (placeholder)
• Discussion/Action
• Discussion/Action
December 11, 2025 Board
(Davis)
• Approve 2026 Operating Budget (Annual) and 2026 Customer Rates (R)
• Receive VCE Grant/Program Annual Report (R)
• 2026 Legislative & Regulatory Platform (R)
• GHG Free Attributes (R) (placeholder)
• Contract Renewals (R) (placeholder)
• Discussion/Action
• Information
• Discussion/Action
• Discussion/Action
• Action
December 25, 2025
December 18, 2025
(rescheduled to
December 18 due to
Christmas holiday on
Dec. 25th)
Advisory
Committee
(Davis)
• Approve 2025 Task Group Year-end Reports (R)
• Power Portfolio Update (R)
• Election of Officers for 2026 (Annual) (R)
• Discussion/Action
• Information
• Nominations
January 8, 2026 Board
(Woodland)
• Oaths of Office for Board Members (Annual - new Members only) (R)
• Election of Officers for 2026 (Annual) (R)
• Customer Participation Update (4th Quarter 2025) (O)
• 2025 Year in review: Customer Care & Marketing (R)
• Receive 2025 Task Group Year-end Reports (R)
• Action
• Nominations
• Information
• Information
• Information
January 22, 2026 Advisory
Committee
(Woodland)
• Rates/Budget 2026 Update (O)
• Customer Participation Update (4th Quarter 2025) (O)
• 2026 CAC Task Group(s) formation (Annual) (R)
• Information
• Information
• Discuss/Action
PLEASE NOTE: April 28-30, 2025: CalCCA Annual Conference in Irvine, California
CAC PROPOSED FUTURE TOPICS
Topics and Discussion dates may change as needed
ESTIMATED MEETING DATE(S)
12 Item 5
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 5
______________________________________________________________________________ TO: Board of Directors
FROM: Edward Burnham, Chief Financial Officer / Treasurer Mitch Sears, Chief Executive Officer
SUBJECT: Monthly Treasurer’s Report (Informational Item) – August 31, 2025 DATE: October 14, 2025
RECOMMENDATION:
Accept the Treasurer’s report on VCE’s cash, investments, debt, and unaudited financial statements (with comparative year to date information) and Actual vs. Budget year to date for the month ending August 31, 2025.
BACKGROUND & DISCUSSION:
The attached financial statements are prepared in a form to satisfy the debt covenants with River City Bank pursuant to the Line of Credit and are required to be prepared monthly.
The Financial Statements include the following reports:
• Statement of Net Position
• Statement of Revenues, Expenditures and Changes in Net Position • Statement of Cash Flows
In addition, Staff is reporting the Actual vs. Budget variances year to date ending August 31, 2025.
Financial Statements for the period August 1, 2025 – August 31, 2025 In the Statement of Net Position, VCE, as of August 31, 2025, has a total of $69,875,218 in its checking, money market and lockbox accounts, $1,100,000 restricted assets for the Debt Service Reserve account, and $1,800,000 restricted assets related to supplier deposits. On August 31, 2025, VCE’s net position was $83,624,556.
In the Statement of Revenues, Expenditures, and Changes in Net Position, VCE recorded $9,987,924 of revenue (net of allowance for doubtful accounts), of which $9,942,526 was billed in, and $5,097,749 represents estimated unbilled revenue. The cost of electricity for the August revenue totaled $7,822,465 For August, VCE’s gross margin was approximately 23% and the net income totaled $1,962,732. The year-to-date change in net position was $20,360,844.
13 Item 5
In the Statement of Cash Flows, VCE cash flows from operations were $3,012,086 due to August cash receipts of revenues being more than the monthly cash operating expenses.
Bank Account Balances (as of 03/31/2025):
Operating Account: $ 37,311,151
Insured Cash Sweep Account: $ 32,921,424
Debt Service Account: $ 1,100,000
CAISO Operational Account: $ 6,191,967
Total Cash on Deposit $ 77,524,542
Note: VCE receives 4.45% interest earnings for the average balance on the ICS account and CAISO operational account equal to the Local Agency Investment Fund (LAIF) state investments rate. August 2025 earnings were $141,835.
VCE’s Outstanding Loan Balances (as of 08/31/2025):
Valley Clean Energy Alliance has available at the financial institution a line of credit totaling $11,000,000 with $7,000,000 withdrawal limit, which expires on April 15, 2026. The related debt outstanding at the close of business on August 31, 2025 was $0. VCE has issued, but undrawn, letters of credit for a total of $3,897,000 for regulatory and power purchase requirements.
Actual vs. Budget Variances for the year to date ending August 31, 2025 Below are the financial statement line items with variances >$50,000 and 5% • Electric Revenue – ($11,164,138) and -16% – Unfavorable variance mainly driven by lower load than forecasted by residential and agriculture customers due to mild winter and summer temperatures. • Purchased Power – $7,481,017 and 17% – Favorable mainly due to renewable energy credit sales in Q1 and lower load than forecasted by residential and agriculture customers due to mild winter and summer temperatures.
• Labor & Benefits $309,610 and 22% – Favorable Variance due to vacancy for additional budgeted positions. Recruitments are in progress and expected to be filled in Q4. • Programs $1,504,525 – Favorable Variance due to timing differences in AgFIT closeout, current year program activities, and member agency support services. • Wholesale Energy Support $55,331 – Favorable Variance due to the IRP process being delayed by CPUC.
• Financial Consultant $88,150 – Favorable variance due to the timing of the investment-grade credit rating fees expected in Q4.
Attachments:
1) Financial Statements (Unaudited) August 1, 2025 to August 31, 2025 (with comparative year to date information.)
2) Actual vs. Budget for the year to date ending August 31, 2025 14 VALLEY CLEAN ENERGY ALLIANCE
FINANCIAL STATEMENTS
(UNAUDITED)
FOR THE PERIOD OF AUGUST 1 TO AUGUST 31, 2025
PREPARED ON OCTOBER 6, 2025
15 2
ASSETS
Current assets:
Cash and cash equivalents 69,875,218
Accounts receivable, net of allowance 11,431,932
Accrued revenue 5,097,749
Prepaid expenses 281,564
Inventory - Renewable Energy Credits -
Other current assets and deposits 7,998,851
Total current assets 94,685,314
Restricted assets:
Debt service reserve fund 1,100,000
Total restricted assets 1,100,000
TOTAL ASSETS $ 95,785,314
LIABILITIES
Current liabilities:
Accounts payable 277,189
Accrued payroll 135,229
Interest payable -
Due to member agencies -
Accrued cost of electricity 7,802,748
Other accrued liabilities 2,113,913
Security deposits - energy supplies 1,800,000
User taxes and energy surcharges 31,680
TOTAL LIABILITIES $ 12,160,759
NET POSITION
Net position:
Local Programs Reserve 1,085,585
Restricted 1,100,000
Unrestricted 81,438,971
TOTAL NET POSITION $ 83,624,556
VALLEY CLEAN ENERGY ALLIANCE
STATEMENT OF NET POSITION
AUGUST 31, 2025
(UNAUDITED)
16 3
FOR THE
PERIOD ENDING
AUGUST 31, 2025 YEAR TO DATE
OPERATING REVENUE
Electricity sales, net $ 9,987,924 $ 58,521,791
Other revenue - $ 26,530
TOTAL OPERATING REVENUES 9,987,924 58,548,321
OPERATING EXPENSES
Cost of electricity 7,822,465 35,716,983
Contract services 165,032 1,733,625
Staff compensation 126,603 1,140,566
General, administration, and other 52,928 618,846
TOTAL OPERATING EXPENSES 8,167,028 39,210,020
TOTAL OPERATING INCOME (LOSS) 1,820,897 19,338,301
NONOPERATING REVENUES (EXPENSES)
Interest income 141,835 1,022,543
Interest and related expenses - -
Other Non Operating Revenues - -
TOTAL NONOPERATING REVENUES (EXPENSES) 141,835 1,022,543 CHANGE IN NET POSITION 1,962,732 20,360,844
Net position at beginning of period 81,661,824 63,263,712 Net position at end of period $ 83,624,556 $ 83,624,556 (WITH COMPARATIVE YEAR TO DATE INFORMATION)
(UNAUDITED)
VALLEY CLEAN ENERGY ALLIANCE
STATEMENT OF REVENUES, EXPENDITURES AND
AUGUST 31, 2025
17 4
FOR THE
PERIOD ENDING
AUGUST 31, 2025 YEAR TO DATE
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from electricity sales $ 10,589,281 $ 54,770,313 Payments received from other revenue sources - 26,530
Receipts for security deposits with energy suppliers - - Payments to purchase electricity (7,276,395) (32,369,580) Payments for contract services, general, and adminstration (174,198) (3,006,081) Payments for member agency services - -
Payments for staff compensation (126,603) (1,140,566)
Return of security deposits to energy suppliers - -
Other cash payments - -
Net cash provided (used) by operating activities 3,012,086 18,280,617
CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES
Principal payments of Debt - -
Interest and related expenses - -
Other Non Operating Revenue - -
Net cash provided (used) by non-capital financing activities - -
CASH FLOWS FROM CAPITAL AND RELATED FINANCING ACTIVITIES Acquisition of nondepreciable assets
Acquisition of capital assets
Net cash provided (used) by capital and related financing activities
CASH FLOWS FROM INVESTING ACTIVITIES
Interest income 141,835 1,022,543
Net cash provided (used) by investing activities 141,835 1,022,543 NET CHANGE IN CASH AND CASH EQUIVALENTS 3,153,921 19,303,159 Cash and cash equivalents at beginning of period 65,092,913 70,311,489 Cash and cash equivalents at end of period 68,246,834 89,614,648 Cash and cash equivalents included in:
Cash and cash equivalents 69,875,218 69,875,218
Restricted assets 1,100,000 1,100,000
Cash and cash equivalents at end of period $ 70,975,218 $ 70,975,218
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
AUGUST 31, 2025
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
18 5
FOR THE
PERIOD ENDING
AUGUST 31, 2025 YEAR TO DATE
Operating Income (Loss) $ 1,820,897 $ 19,338,301
Depreciation expense
Increase (decrease) for uncollectible accounts 99,200 576,800 (Increase) decrease in net accounts receivable 694,039 (3,731,578) (Increase) decrease in accrued revenue (173,505) (1,648,452) (Increase) decrease in prepaid expenses (37,471) (174)
(Increase) decrease in inventory - renewable energy credits - - (Increase) decrease in other assets and deposits 19,600 (181,368) Increase (decrease) in accounts payable 24,162 (472,243) Increase (decrease) in accrued payroll (14,457) (16,245) Increase (decrease) in due to member agencies - -
Increase (decrease) in accrued cost of electricity 546,070 3,347,403 Increase (decrease) in other accrued liabilities - -
Increase (decrease) security deposits with energy suppliers - - Increase (decrease) in user taxes and energy surcharges - - Increase (decrease) in security deposits from energy suppliers 64,146 1,085,522 Increase (decrease) in user taxes due to other governments (30,595) (17,350) Increase (decrease) in advances from public purpose programs - - Net cash provided (used) by operating activities $ 3,012,085 $ 18,280,616 (UNAUDITED)
AUGUST 31, 2025
RECONCILIATION OF OPERATING INCOME TO NET CASH
PROVIDED (USED) BY OPERATING ACTIVITIES
Adjustments to reconcile operating income to net cash provided (used) by
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
(WITH YEAR TO DATE INFORMATION)
19 VALLEY CLEAN ENERGY
2025 YTD ACTUAL VS. BUDGET
FOR THE YEAR TO DATE ENDING 08/31/2025
Description YTD
Actuals
YTD
Budget
YTD
Variance
% over
/-under
Total Revenues $ 59,570,862 $ 70,735,000 $ (11,164,138) -16% Electric Revenue $ 58,521,790 $ 69,600,000 $ (11,078,210) -16% Interest Revenues $ 1,022,542 $ 655,000 $ 367,542 56%
Reimbursable Revenues $ 26,530 $ 480,000 $ (453,470) -94% Purchased Power $ 35,716,983 $ 43,198,000 $ (7,481,017) -17% Purchased Power Base $ 35,716,983 $ 41,142,000 $ (5,425,017) -13% Purchased Power Contingency 5% $ - $ 2,056,000 $ (631,317) -31% Labor & Benefits $ 1,090,390 $ 1,400,000 $ (309,610) -22% Salaries & Wages/Benefits $ 830,293 $ 1,152,000 $ (321,707) -28% Contract Labor $ 156,893 $ 128,000 $ 28,893 23%
Human Resources & Payroll $ 103,204 $ 120,000 $ (16,796) -14% Office Supplies & Other Expenses $ 208,547 $ 343,900 $ (135,353) -39% Technology Costs $ 65,583 $ 32,400 $ 33,183 102%
Office Supplies $ 4,109 $ 8,000 $ (3,891) -49%
Travel $ 9,132 $ 23,500 $ (14,368) -61%
CalCCA Dues $ 128,660 $ 128,000 $ 660 1%
CC Power $ - $ 144,000 $ (144,000) -100%
Memberships $ 1,064 $ 8,000 $ (6,936) -87%
Contractual Services $ 1,566,452 $ 1,795,200 $ (228,748) -13% Other Contract Services (e.g. IRP) $ - $ 48,000 $ (48,000) -100% Don Dame $ 4,409 $ 14,400 $ (9,992) -69%
Wholesale Energy Services (TEA) $ 520,669 $ 576,000 $ (55,331) -10% 2030 100% Renewable & Storage $ - $ 20,000 $ (20,000) -100% Customer Support Call Center $ 669,964 $ 644,000 $ 25,964 4% Operating Services $ 104,314 $ 80,000 $ 24,314 30%
Commercial Legal Support $ 17,325 $ 16,000 $ 1,325 8%
Legal General Counsel $ 15,488 $ 56,000 $ (40,513) -72% Regulatory Counsel $ 129,205 $ 136,000 $ (6,795) -5%
Joint CCA Regulatory counsel $ - $ 12,800 $ (12,800) -100% Legislative - (Lobbyist) $ 44,000 $ 46,000 $ (2,000) -4% Accounting Services $ - $ 2,000 $ (2,000) -100%
Financial Consultant $ 850 $ 89,000 $ (88,150) -99%
Audit Fees $ 60,230 $ 55,000 $ 5,230 10%
Marketing $ 121,599 $ 248,000 $ (126,401) -51%
Marketing Collateral $ 121,569 $ 216,000 $ (94,431) -44% Community Engagement Activities & Sponsorships $ 30 $ 32,000 $ (31,970) -100% Programs $ 51,475 $ 1,556,000 $ (1,504,525) -97%
Program Costs (Rebates, Incentives, etc.) $ 145,010 $ 600,000 $ (454,990) -76% Member Agency Advisory Services $ - $ 104,000 $ (104,000) -100% AG Fit $ (93,535) $ 840,000 $ (933,535) -111%
PIPP Program $ - $ 12,000 $ (12,000) -100%
Rents & Leases $ 28,803 $ 32,800 $ (3,997) -12%
Hunt Boyer Mansion $ 28,803 $ 16,800 $ 12,003 71%
Lease Improvement $ - $ 16,000 $ (16,000) -100%
Other A&G $ 347,619 $ 545,200 $ (197,581) -36%
Development - New Members $ - $ 16,800 $ (16,800) -100% Strategic Plan Implementation $ 46,929 $ 51,200 $ (4,271) -8% Strategic Plan Update & Community Focus Group $ 58,971 $ 80,000 $ (21,029) -26% PG&E Data Fees $ 198,648 $ 200,000 $ (1,352) -1%
Insurance $ 43,071 $ 64,000 $ (20,929) -33%
Banking Fees $ - $ 133,200 $ (133,200) -100%
Miscellaneous Operating Expenses $ 10,079 $ 8,000 $ 2,079 26% Contingency $ - $ 160,000 $ (160,000) -100%
0 0
TOTAL OPERATING EXPENSES $ 39,141,947 $ 49,287,100 $ (10,145,153) -21% Interest on RCB Term loan $ - $ - $ - 100%
NET INCOME $ 21,447,900 20,428,915 $
20 Item 6
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 6
To: Board of Directors
From: Mark Fenstermaker, Pacific Policy Group
Subject: Legislative Update – Pacific Policy Group
Date: October 14, 2025
______________________________________________________________________________ Pacific Policy Group, VCE’s lobby services consultant, continues to work with Staff and the Community Advisory Committee’s Legislative - Regulatory Task Group (LRTG), which continues to meet and discuss legislative matters. Below is a summary:
The Legislature concluded its 2025 regular session on September 13, 2025, a day later than previously planned. Governor Newsom, Senate Pro Tem McGuire, Assembly Speaker Rivas, and their respective staffs negotiated a package of climate and energy bills through the night of September 9 and into the morning of September 10 that required the Legislature to extend its session by an extra day. The six-bill package, which the Governor signed into law on September 19, 2025, includes two bills aimed at making electricity more affordable – AB 825 (Petrie-Norris) and SB254 (Becker).
Throughout the session, VCE kept a close eye on SB 540 (Becker), the bill proposing to allow California to join a new regional organization (RO), as proposed by the Pathways Initiative. In the final negotiations, AB 825 was amended to replace SB 540 and the bill to push this policy proposal through. The bill includes 13 individual provisions of what the RO must provide in terms of safeguards that the CAISO must show are satisfied in a public meeting as well as to the Legislature through committee hearings. Part of the process approval includes an authorization from the CPUC and California may not join the new RO until 2028. VCE did not take a position on SB 540/AB 825. CalCCA and several individual CCAs supported SB 540/AB 825.
VCE had previously taken an “oppose unless amended” position on AB 825 based on some of its previously proposed language. While the bill included provisions that VCE may have found useful, such as authorizing the public financing of transmission projects, the bill included a proposal to create a new taskforce, comprised of representatives from statewide agencies, to review and make recommendations on the effectiveness of demand side programs, including those funded solely by VCE ratepayers. CalCCA and many other CCAs took a similar “oppose unless amended” on AB 825. When most of the content of AB 825 were merged into SB 254 by Senator Josh Becker, the provision opposed by VCE and other CCAs was not included. 21 Item 6
2 A bit more about SB 254 illustrates the focus on wildfire prevention and remediation this year.
Before the flames had been extinguished, rumors had started that Southern California Edison (SCE) caused the devastating Eaton Fire that destroyed much of the City of Altadena. A key concern in Sacramento with the prospect that SCE had started the Eaton Fire is that the Wildfire Fund, the insurance pool shared by the three investor-owned utilities, would be depleted. Ensuring the survival of the Wildfire Fund became a primary focus of energy affordability. Therefore, SB 254’s chief provision is an extension to 2045 and recapitalization of the Wildfire Fund. The second round of funding will come in at $18 billion, split evenly between shareholders and ratepayers. In addition, SB 254 requires the IOUs to invest another $6 billion in wildfire resilience projects (undergrounding, insulating, etc.) without a return on equity. The bill also creates Transmission Infrastructure Accelerator within the Governor’s Office of Business and Economic Development with to create a financing and development strategy for eligible transmission projects. These projects can be funded with public financing instruments.
CalCCA and several individual CCAs supported SB 254.
The remaining bills in the end-of-session package include AB 1207 (Irwin) extending the Cap and Trade Program (now named Cap and Invest), SB 840 (Limon) amending the expenditure plan for the Greenhouse Gas Reduction Fund, SB 237 (Grayson) to boost domestic petroleum supply chains, and SB 352 (Reyes) codifying the Department of Justice’s Bureau of Environmental Justice.
VCE staff, the LRTG and PPG examined many other bills during the session, details of some of those bills are as follows.
1. AB 706 (Aguiar-Curry) Forest Organic Residue, Energy, and Safety Transformation and Wildfire Prevention Fund Act.
Summary: Existing law establishes in the Natural Resources Agency the Department of Forestry and Fire Protection (CAL FIRE), and makes CAL FIRE responsible for, among other things, fire protection and prevention, as provided. Existing law establishes the State Board of Forestry and Fire Protection in CAL FIRE to represent the state’s interest in the acquisition and management of state forests and requires the board to maintain an adequate forest policy. The former Governor, Edmund G. Brown, Jr., issued Executive Order No. B-52-18 that, among other things, established a Forest Management Task Force, now known as the Wildfire and Forest Resilience Task Force, involving specified state agencies to create the action plan for wildfire and forest resilience. The executive order also established a Joint Institute for Wood Products Innovation, to be located within the state board. Under existing law, the Public Utilities Commission (PUC) has regulatory authority over public utilities, including electrical corporations. The California Renewables Portfolio Standard Program requires every electrical corporation to file with the PUC a standard tariff for electricity generated by an electric generation facility, as defined, that qualifies for the tariff, is owned and operated by a retail customer of the electrical corporation, and is located within the service territory of, and developed to sell electricity to, the electrical corporation. The PUC refers to this requirement as the renewable feed-in tariff. The renewable feed-in tariff law, in part, requires the PUC to direct the electrical corporations, collectively, to procure at least 250 megawatts of cumulative rated generating capacity from developers of bioenergy projects that commence operation on or after June 1, 2013. Pursuant to this requirement, the PUC has established and revised the Bioenergy Market Adjusting Tariff (BioMAT) program. On March 18, 2016, the PUC issued Resolution E-4770 to order investor-22 Item 6
3 owned utilities to each hold a solicitation for contract with facilities that can use biofuel from high hazard zones to address an Emergency Proclamation using the Bioenergy Renewable Auction Mechanism (BioRAM) program. This bill would establish the fire fuel reduction program to support sufficient procurement, transport, and beneficial use of forest biomass waste to reduce fuel for wildfires by up to 15,000,000 bone-dry tons of forest biomass waste per year.
The bill would establish the FOREST and Wildfire Prevention Fund in the State Treasury, and would continuously appropriate the fund to the Natural Resources Agency for this program, as specified. By continuously appropriating moneys in the fund to the agency, the bill would make an appropriation. The bill would require the fire fuel reduction program to grant funding priority to BioRAM and BioMAT fleets in operation on or before January 1, 2031.
Additional Information
• Next Hearing: The author held the bill in Senate Natural Resources & Water Committee and may resume the effort next session.
• VCE did not take an official position.
• CalCCA supports AB 706.
• Bill language: AB 706
2. SB 283 (Laird) Energy Storage Systems
Summary: Existing law, the California Building Standards Law, establishes the California Building Standards Commission (commission) within the Government Operations Agency and sets forth its powers and duties, including approval and adoption of building standards and codification of those standards into the California Building Standards Code. Existing law requires the State Fire Marshal, before the next triennial edition of the California Building Standards Code adopted after January 1, 2025, to propose to the commission updates to the fire standards relating to requirements for lithium-based battery systems, as provided. This bill would require the commission and the Office of the State Fire Marshal to review and consider the most recently published edition of the National Fire Protection Association (NFPA) 855, Standard for the Installation of Stationary Energy Storage Systems, for incorporation into the next update of the California Building Standards Code adopted after July 1, 2026.
Additional Information
• Next Hearing: The bill is on the Governor’s desk awaiting his signature or veto. • VCE did not take an official position.
• CalCCA supports SB 283.
• Bill language: SB 283
3. SB 541 (Becker) Load Shifting
Summary: This bill would require the Energy Commission, in consultation with specified entities, to analyze the cost-effectiveness of specific load flexibility programs and other types of load-shifting interventions and identify both the approximate amount of load shifting and the cost-effectiveness of each type of load-shifting intervention in the next update to the biennial integrated energy policy report after January 1, 2027, as provided. The bill would require the Energy Commission, as part of each integrated energy policy report, to estimate each retail supplier’s load-shifting potential, giving consideration to certain factors, as specified. The bill would require the Energy Commission, on or before July 1, 2028, and biennially thereafter, to 23 Item 6
4 analyze and publish the amount of load shifting that each retail supplier achieved in the prior calendar year.
Additional Information
• Next Hearing: The bill is on the Governor’s desk awaiting his signature or veto. • VCE did not take an official position.
• CalCCA opposes SB 541.
• Bill language: SB 541
24 Item 7
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 7
To: Board of Directors
From: Keyes & Fox, Regulatory Consultant
Subject: Regulatory Monitoring Report – Keyes & Fox
Date: October 14, 2025
______________________________________________________________________________ Please find attached Keyes & Fox’s September 2025 Regulatory Memorandum dated October 1, 2025 an informational summary of the key California regulatory and compliance-related updates from the California Public Utilities Commission (CPUC).
Attachment: Keyes & Fox Regulatory Memorandum dated October 1, 2025 25 1
Valley Clean Energy Alliance
Regulatory Monitoring Report
To: Valley Clean Energy Alliance (VCE) Board of Directors From: Sheridan Pauker, Partner, Keyes & Fox LLP
Jason Hoyle, Director of Research, EQ Research, LLC
Subject: Monthly Regulatory Update
Date: October 1, 2025
Keyes & Fox LLP and EQ Research LLC are pleased to provide VCE’s Board of Directors with this informational memo describing key California regulatory and compliance-related updates from the California Public Utilities Commission (CPUC) over the past month.
IRP Rulemaking (2025)
Background: This new proceeding governs the biennial Integrated Resource Plan (IRP) process, including load serving entity (LSE) procurement requirements, the establishment of a variety of state- and LSE-level load and procurement forecasts, greenhouse gas (GHG) reduction targets, ongoing reliability obligations, and the Commission’s oversight of the IOUs’ bundled procurement plans. This proceeding continues the work of R.20-05-003 and will be the primary forum for most future CPUC work on the Reliable and Clean Power Procurement Program framework (RCPPP).
Recent Developments: On September 24, the CPUC issued Draft Resolution E-5426 to replace the IRP Filing Citation Program established in Resolution E-5080. On September 30, an ALJ Ruling requested comments on the proposed Transmission Project Portfolio for 2026-2027 and the proposed statewide incremental procurement of 1,500 MW in each year from 2029 through 2032.
Analysis: The Draft Resolution slightly expands the Commission’s enforcement and penalty authority to include any mandatory filing deadlines and reporting requirements in the procurement and planning tracks. The program authorizes the Commission to develop a tool to encourage compliance and discourage violations related to procurement reporting and filing deadlines. The Ruling’s proposed incremental procurement is driven by a combination of accelerating load growth from data centers and electrification accompanied by delays and extension requests for procurement of long lead-time resources.
Next Steps: Comments on the Ruling are due October 22 and reply comments are due October 31. The Draft Resolution may be heard as early as the October 30 Commission meeting. Comments on the Draft Resolution are due October 14.
A scoping memo and ruling and a ruling providing the requirements for the next IRP is expected soon.
Additional Information: Ruling (Sep. 30, 2025); Draft Resolution E-5426 (Sep. 24, 2025); Ruling on prehearing conference (Aug. 28, 2025); OIR (Jul. 2, 2025); Docket No. R.25-06-019.
IRP Rulemaking (2020)
Background: This proceeding governs the biennial Integrated Resource Plan (IRP) process, including load serving entity (LSE) procurement requirements, the establishment of a variety of state- and LSE-level load and procurement forecasts, greenhouse gas (GHG) reduction targets, and ongoing reliability obligations. This proceeding will consider a Staff Proposal on the RCPPP, and remaining work on the RCPPP will occur in the new IRP rulemaking, R.25-06-019.
Recent Developments: On September 18, the CPUC adopted D.25-09-007 granting and expanding on SCE’s Petition for Modification by eliminating the future use of “bridge” contracts for mid-term reliability procurement compliance.
Analysis: The Decision eliminates the use of short-term bridge contracts for long lead-time (LLT) and Diablo Canyon replacement resource procurement after the adoption of the Decision. The remaining procurement compliance options are use of a 10-year (i.e., long-term contract) contract for up to three years, demonstrating that month-ahead resource adequacy requirements are met for all months in which their procurement is delayed, and the existing “good faith efforts” demonstration. Bridge contracts that were used prior to September 18, 2025 are still valid as a means of showing alternative compliance for past procurement online date requirements.
Next Steps: Further guidance on compliance and enforcement related to the Decision, including but not limited to the “good faith efforts” showing requirements, will be provided in a Staff Proposal in the new IRP proceeding. Information about the 2025 IRP filing is expected soon.
26 2
Additional Information: D.25-09-007 (Sep. 26, 2025); RCPPP Staff Proposal and Summary Slides (Jul. 15, 2025); Proposed Decision (Aug. 13, 2025); ACPC Motion (Jul. 21, 2025); Amended Scoping Memo and Ruling (Correction/Clarification) (Apr. 18, 2024); Docket No. R.20-05-003.
Demand Flexibility
Background: This rulemaking was opened to update the CPUC’s rate design principles and guidance for advancing demand flexibility, and to modify, consolidate, or eliminate existing dynamic rate pilots. Phase 1-Track A established an income-graduated fixed charge (IGFC) for residential rates for all investor-owned electric utilities in accordance with Assembly Bill 205 (Stats. 2022, ch. 61). Phase 1-Track B first adopted rate design and demand flexibility principles and then expanded VCE’s AgFIT Pilot throughout PG&E distribution territory.
Recent Developments: September 29, SDG&E filed an Application for Rehearing of D.25-08-049 requesting the Decision be repealed and the proceeding re-opened for further development of the record, including consideration of the costs of implementing the required rate designs.
Analysis: SDG&E’s request for rehearing is based in part on several scoped issues that were not addressed in D.25-08- 049 which previously closed the proceeding. Specifically, scoping issue 4 addresses the systems and process by which bundled and unbundled customers will access dynamic electricity price information, how LSEs are authorized to provide access, how customers may optimize their pre-scheduled energy use, the costs of dynamic pricing access, and the management and oversight of the systems and processes enabling access to dynamic pricing. Additionally, scoping issues 5 and 6 address how the CPUC will support the implementation of amendments to the CEC's Load Management Standards and whether the Commission should expand any of the existing dynamic rate pilots as a near-term solution to benefit system reliability, respectively.
Next Steps: Responses to the Application for Rehearing are due October 14.
Additional Information: Application for Rehearing (Sep. 29, 2025); D.25-08-049 (Aug. 29. 2025); PG&E AL 7627-E (Jun. 27, 2025); PG&E AL 7592-E (May 7, 2025); Final Evaluation of VCE’s AgFIT Pilot (Apr. 25, 2025); D.24-01-032 (Jan. 26, 2024); Phase 1 Scoping Memo and Ruling (Nov. 2, 2022); OIR (Jul. 22, 2022); Docket No. R.22-07-005.
PCIA/ERRA Reform
Background: This Rulemaking considers updates and reforms to the Energy Resource and Recovery Account (ERRA) and Power Charge Indifference Adjustment (PCIA) rules and processes with the objectives of improving existing rules, mitigating rate volatility, and ensuring indifference among bundled and departing customers. The proceeding includes an expedited Track 1 to revise the resource adequacy (RA) market-price benchmark (MPB) calculation methodology and for the revised methodology to be used in the October 2025 MPBs, and Track 2 will consider broader issues.
Recent Developments: No recent developments.
Analysis: N/A
Next Steps: The Decision’s changes to the RA MPB will be implemented in the Fall Update this October. A scoping memo for Track 2 is expected.
Additional Information: Applications for Rehearing of CalCCA and Ava/SJCE (Jul. 30, 2025); D.25-06-049 (Jun. 27, 2025); Scoping Memo (Apr. 8, 2025); ALJ Ruling (Mar. 21, 2025); Ruling & Staff Report on RA MPB (Feb. 26, 2025); OIR (Feb. 26, 2025); Docket No. R.25-02-005.
Climate Credit OIR
Background: This rulemaking will explore potential approaches to maximize the effectiveness at supporting customer affordability of cap-and-trade program proceeds returned to electric consumers via the state Climate Credit.
Recent Developments: Comments on the OIR were filed by 16 parties on September 26. Common themes in most comments included a focus on using climate credit funds to support affordability and incorporating the recently enacted AB 1207 which extends the State’s cap-and-trade program through 2045 and includes provisions that adjust the allocations of proceeds and increase the amount of funds returned directly to electric ratepayers. CalCCA’s comments recommended incorporating the provisions of AB 1207 and the development of a standardized tool or rubric to evaluate and compare bill impacts of party proposals.
Analysis: The incorporation of AB 1207 provisions will increase the amount of residential ratepayer climate credit refunds and provide those refunds in up to the four highest billed months of the year to maximize the affordability benefits.
Next Steps: Reply comments are due October 13.
Additional Information: OIR (Aug. 20, 2025); Docket No. R.25-07-013.
RA Rulemaking (2025-2026)
Background: This proceeding considers resource adequacy (RA) requirements for LSEs and will address the 2025 and 2026 RA compliance years, local RA procurement obligations for the 2025-2028 compliance years, and further 27 3
development of the 24-hour Slice-of-Day (SOD) framework. Track 3 is focused on remaining RA capacity issues, including what planning reserve margin (PRM) the Commission should require for LSE RA procurement obligations.
Recent Developments: The CPUC announced it will hold a public workshop on Unforced Capacity accreditation for storage and dispatchable thermal resources on November 3 and a public workshop on Long-Duration Energy Storage and Pumped Storage Hydro accreditation on November 4.
Analysis: N/A
Next Steps: Public workshops will be held on November 3 and 4.
Additional Information: Application for Rehearing (Jul. 28, 2025); 2023 RA Report (Aug. 21, 2025); D.25-06-048 (Jun. 27, 2025); CalCCA Analysis (Apr. 25, 2025); Scoping Memo and Ruling (Dec. 18, 2023); OIR (Oct. 16, 2023); Docket No. R.23-10-011.
PG&E 2027 Phase 1 GRC
Background: Phase 1 General Rate Case (GRC) proceedings determine PG&E’s overall revenue requirement and classification of costs by function for a set period (in this case, 2027-2030).
Recent Developments: On September 25, an ALJ Ruling scheduled two virtual public participation hearings for October 22 and 23, and an in-person public hearing for November 7 in Fresno.
Analysis: N/A
Next Steps: Public hearings will be held in October and November 2025. Intervenor testimony is due in February 2026.
Additional Information: Ruling (Sep. 25, 2025); Scoping Memo and Ruling (Jul. 31, 2025); Application (May 16, 2025); Docket No. A.25-05-009.
PG&E 2023 Phase 2 GRC
Background: Phase 2 General Rate Case (GRC) proceedings determine PG&E’s marginal cost of service and revenue requirement allocation among customer classes for a set period (in this case, 2023-2026).
Recent Developments: No recent developments.
Analysis: N/A
Next Steps: The schedule is suspended and PG&E is required to propose a modified schedule by October 1.
Additional Information: Ruling (Aug.18, 2025); Request for scoping amendment (Jun. 12, 2025); PG&E AL 7588-E (May 2, 2025); Scoping Memo (Mar. 21, 2025); Application (Sep. 30. 2024); Docket No. A.24-09-014.
PG&E 2026 ERRA Forecast
Background: The annual Energy Resource and Recovery Account (ERRA) forecast proceedings establish the amount of the Power Charge Indifference Adjustment (PCIA) and other non-bypassable charges (NBCs) for the following year, as well as fuel and purchased power costs associated with serving bundled customers that utilities may recover in rates.
Recent Developments: PG&E filed rebuttal testimony on September 23. That testimony substantially revises PG&E’s proposed Resource Adequacy (RA) valuation methodology for PCIA ratemaking purposes. On September 24, the ALJ issued a Ruling scheduling an evidentiary hearing for October 7.
Analysis: N/A.
Next Steps: A Joint Case Management Statement is due September 30, an evidentiary hearing will be held on October 7, and the Fall Update will be submitted on October 15. As in past years, Energy Division is expected to release updated Market Price Benchmarks on October 1.
Additional Information: Ruling (Sep. 24, 2025); Scoping Memo and Ruling (Jul. 31, 2025); PG&E AL 7663-E (Jul. 30, 2025); PG&E 2026 ERRA Forecast Application (May 15, 2025); Docket No. A.25-05-011.
PG&E 2024 ERRA Compliance
Background: The annual ERRA Compliance proceeding reviews the utility’s compliance with CPUC-approved standards for generation-procurement and cost recovery activity occurring in the prior year, such as energy resource contract administration, least-cost dispatch, fuel procurement, and balancing account entries.
Recent Developments: Intervenor testimony was filed September 15.
Analysis: N/A
Next Steps: A status conference on the need for evidentiary hearings is set for November 14, and briefs are due in early 2026.
Additional Information: Scoping Memo and Ruling (May 2, 2025); Joint Prehearing Conference Statement (Apr. 16, 2025); Ruling (Mar. 27, 2025); PG&E 2024 ERRA Compliance Application (Feb. 28, 2025); Docket No. A.25-02-013. 28 4
Provider of Last Resort Rulemaking
Background: A Provider of Last Resort (POLR) is the utility or other entity that has the obligation to serve all customers (PG&E currently serves in this role for VCE’s service area). Phase 1 of this proceeding concluded in April 2024 and addressed POLR service requirements, cost recovery, and options to maintain GHG emission reductions in the event of an unplanned customer migration to the POLR. Phase 2 builds on Phase 1 to set the requirements and application process for non-IOU entities to serve as the POLR. Phase 3 will address specific issues not resolved in Phase 1 or 2.
Recent Developments: On September 19, CalCCA submitted the Joint CCAs’ Financial Monitoring and Reporting Guidelines Advice Letter pursuant to Resolution E-5406 (VCE AL 24-E).
Analysis: The Advice Letter provides the final guidelines for CCA financial monitoring and reporting as set forth in Resolution E-5406.
Next Steps: A ruling on the need for legal briefs in Phase 2 is expected in 2025 and resolution of the Threshold Questions is expected 2025, after which the primary topic areas will be addressed.
Additional Information: Joint CCA AL (VCE AL 24-E) (Sep. 19, 2025); (Final Resolution E-5406 (Jul. 29, 2025); ALJ Ruling (May 28, 2025); PG&E AL 7596-E and 7596-E-A (May 12 & 28, 2025); Scoping Memo and Ruling (Oct. 24, 2024); ALJ Ruling (Aug. 6, 2024); D.24-04-009 / Appendix (Apr. 22, 2024); OIR (Mar. 25, 2021); Docket No. R.21-03- 011.
City and County of San Francisco Municipalization
Background: The City and County of San Francisco (SF or City) filed this Petition for a determination by the CPUC of just compensation for acquisition by the City of PG&E property (PG&E distribution system within SF transmission assets needed for operational control, a substation and related assets) pursuant to Public Utilities Code §1401-1421. Briefing was filed in August of 2022.
Recent Developments: On September 26, the CPUC issued a Proposed Decision establishing methods and standards for just compensation and valuation. The Proposed Decision would establish principles to assess just compensation but does not select a specific valuation method for PG&E’s property, land, and rights and will leave the parties free to put forward their interpretation and valuation approach within the guidelines.
Analysis: The Proposed Decision would adopt Staff’s proposed principles of just compensation, including finding that ratepayers remain “unharmed” and in the same financial position after the proposed acquisition, and maintaining the same level of “safety, reliability, wildfire mitigation, public benefits, etc.” for PG&E’s remaining customers. The Proposed Decision would also find that PG&E may be entitled to business and physical severance damages. If adopted, the Proposed Decision would require parties to submit appraisals using three separate valuation methods and show how their proposed just compensation award is consistent with law, precedent, is accurate and avoids double-counting.
Next Steps: The Proposed Decision may be heard as early as the October 30 Commission meeting. Comments on the Proposed Decision are due October 16 and reply comments are due October 21. The City’s amended testimony is due in Q4 2025, followed by PG&E opening testimony in Q1 2026, City rebuttal testimony in Q2 2026, and hearings in Q3 2026. Briefs and reply briefs are due in 3Q 2026, and a decision on valuation is expected in Q1 2027.
Additional Information: Proposed Decision (Sep. 26, 2025); PG&E Motion to Enforce (Aug. 26, 2025); PG&E Motion to Compel (Aug. 21, 2025); Amended Scoping Memo (Jul. 1, 2025); Petition (Jul. 27, 2021); Docket No. P.21-07-012.
Distribution Interconnection Rules
Background: This rulemaking will review and refine distribution-level interconnection rules under Electric Rule 21, particularly those for distributed energy resources for PG&E, SCE, SDG&E and the small and multijurisdictional electric utilities.
Recent Developments: No recent developments.
Analysis: N/A
Next Steps: Comments on the OIR are due October 20 and reply comments are due November 10.
Additional Information: OIR (Jul. 25, 2025); Docket No. R.25-08-004.
PG&E Billing System Modernization
Background: This proceeding addresses PG&E’s plan to upgrade its legacy billing system, some portions of which date back to the mid-1990s. PG&E proposed a three-stage upgrade that would ultimately be complete in Q4 2029 and cost an estimated $761.3 million.
Recent Developments: On September 11, an ALJ Ruling rescheduled the evidentiary hearing to November 17-20 to allow additional time for continued settlement discussions.
Analysis: Issues related to CCA concerns such as bill presentation, improvements to billing data access and quality, CCA service fees, and others will be covered during the evidentiary hearings.
Next Steps: The evidentiary hearing will be held November 17-20. Opening briefs are due December 17 and reply briefs are due January 20. A proposed decision is expected in Q1 2026. 29 5
Additional Information: Ruling (Sep. 11, 2025); Joint Case Management Statement (Aug. 20, 2025); D.25-08-008 (Aug. 19, 2025); Joint CCA Testimony (Jun. 30, 2025); Scoping Memo (Mar. 27, 2025); Application (Oct. 23, 2024); Docket No. A.24-10-014.
RPS Rulemaking
Background: This proceeding addresses ongoing Renewables Portfolio Standard (RPS) requirements, including legislative mandates, and other matters related to the purchase of renewable energy. This proceeding is the forum for review of VCE’s RPS Procurement Plan and RPS Compliance reports.
Recent Developments: No recent developments.
Analysis: N/A
Next Steps: A proposed decision on Draft RPS Plans is expected in Q4 2025.
Additional Information: VCE RPS Compliance Report (Aug.1, 2025); VCE 2025 Draft RPS Plan (Jun. 30, 2025); Ruling on 2025 RPS Plans (Apr. 17, 2025); Notice of RPS Plan Approval (Apr. 3, 2025); VCE Final 2024 RPS Procurement Plan (Jan. 22, 2025); D.24-12-035 (Dec. 24, 2024); Scoping Memo and Ruling (May 9, 2024); OIR (Feb. 1, 2024); Docket No. R.24-01-017.
PG&E 2026 Cost of Capital
Background: Cost of capital proceedings are held every three years to establish a utility’s return on equity (ROE) and overall rate of return (ROR). The Commission established a uniform cost of capital mechanism for the large investor-owned utilities that includes a review 3-year cycle and provides for formula-based interim adjustments based on a bond market index.
Recent Developments: The evidentiary hearing was held in early September.
Analysis: N/A
Next Steps: Reply briefs are due October 3, and a proposed decision is expected in November.
Additional Information: Scoping Memo and Ruling (Jul. 16, 2025); ALJ Ruling (May 29, 2025); Application (Mar. 20, 2025); Docket No. A.25-03-010.
Building Decarbonization
Background: This proceeding explores reduction of greenhouse gas (GHG) emissions associated with energy use in buildings. The current Phase 4 will consider whether modifications to electric line extension rules would assist under-resourced customers, electric baseline allowance modifications to encourage building decarbonization, and new programmatic approaches to building decarbonization.
Recent Developments: No recent developments.
Analysis: N/A
Next Steps: N/A
Additional Information: PG&E AL 7642-E (Jul. 15, 2025); D.25-06-034 (Jun. 20, 2025); PG&E AL 5074-G/7615-E (Jun. 5, 2025); Scoping Memo and Ruling (Jul. 1, 2024); OIR (Feb. 8, 2019); Docket No. R.19-01-011.
EV Rates & Infrastructure
Background: This rulemaking is the successor to R.18-12-006 and will focus on issues related to 1) timely energization of electric vehicle (EV) charging, 2) transportation electrification grid planning to support charging infrastructure deployment, 3) deployment of behind-the-meter (BTM) charging infrastructure to support state goals, 4) vehicle-grid integration (VGI), and 5) ongoing transportation electrification policy development and collaboration.
Recent Developments: On September 15, PG&E submitted its 2025 Mid-Term Report.
Analysis: N/A
Next Steps: N/A
Additional Information: PG&E Mid-Term Report (Sep. 15, 2025); Joint Report on the CPUC’s Submetering and Telematics Workshop (Jun. 16, 2025); Joint Report on the Vehicle-Grid Integration Workshop (Jun. 16, 2025); Scoping Memo and Ruling (Apr. 12, 2024); OIR (Dec. 20, 2023); Docket No. R.23-12-008.
Utility Safety Culture Assessments
Background: This rulemaking will define safety culture concepts and determine how the safety culture of PG&E and other utilities in California will be assessed and evaluated. The CPUC’s Office of Energy Infrastructure Safety will conduct annual wildfire safety-specific assessments of investor-owned utilities as required by AB 1054, and an independent third-party evaluator will conduct safety culture assessments every five years per SB 901. Phase 1 of this proceeding focused on developing safety culture assessments for the large electric and natural gas IOUs, and Phase 2 will develop safety culture assessments for small multi-jurisdiction utilities (SMJUs) and the gas storage operators. 30 6
Recent Developments: No recent developments.
Analysis: N/A
Next Steps: PG&E’s first third-party evaluation is scheduled for August 1, 2028. Annual reports are due August 1 of each year between third-party evaluations.
Additional Information: Scoping Memo and Ruling (Aug. 26, 2025); D.25-01-031 (Jan. 23, 2025); OIR (Oct. 7, 2021); Docket No. R.21-10-001.
Diablo Canyon 2026 Rates & VPF
Background: During the period of extended operations for the Diablo Canyon Nuclear Plant, PG&E submits an annual application forecasting its costs, market revenues from CAISO, net costs allocated to ratepayers of each large IOU, and its plan for use of volumetric performance fees (VPFs) in the upcoming calendar year.
Recent Developments: Evidentiary hearings were held on September 9 – 10.
Analysis: N/A
Next Steps: Opening briefs are due October 1, and reply briefs are due October 22. A proposed decision is expected in Q3.
Additional Information: ALJ Ruling (Aug. 29, 2025); Scoping Ruling and Memo (Jul. 2, 2025); Application (Mar. 28, 2025); Docket No. A.25-03-015.
Disconnections and Reconnections
Background: This proceeding addresses approaches to the disconnection and reconnection of electric customers with a focus on improving energy access and cost containment.
Recent Developments: No recent developments.
Analysis: N/A
Next Steps: Heat-based disconnection threshold proposals must be implemented by May 1, 2026.
Additional Information: D.25-06-012 (Jun. 17, 2025); Phase 2 Scoping Memo (Jul. 15, 2022); OIR (Jul. 20, 2018); Docket No. R.18-07-005.
Other Dockets
The following table identifies other tracked dockets that are closed or inactive.
Docket Name Status
R.19-09-009 Microgrids
D.24-11-004 adopting implementation rules for multi-property microgrid tariffs and closing the proceeding was issued November 18. Proceeding reopened for pending Application for Rehearing and Petition for Modification.
R.23-03-007 Wildfire Fund NBC
2024-2026
The 90-day Notice (Sep. 9) would set the 2026 Wildfire NBC at $5.88/MWh - a slight decrease from the 2025 WF NBC charge of $5.95/MWh.
A.22-05-002
Demand Response
Programs (2023-
2027)
D.24-04-006, issued April 24, 2024, ended the Demand Response Auction Mechanism (DRAM) pilot programs of PG&E, SCE, and SDG&E and closed the proceeding. Proceeding reopened by Petition for Modification (PFM) (Feb. 2025), which would be denied by a Proposed Decision for Oct. 9 meeting.
A.21-06-021 PG&E 2023 Phase
1 GRC
This proceeding is inactive, but it remains open to provide further guidance on metrics relevant to auditor reports, to consider revising the energization cost recovery mechanism, and to establish reporting requirements for reviewing the reasonableness of PG&E’s interim rate recovery in its next GRC.
A.22-02-015 PG&E 2021 ERRA
Compliance
This proceeding was closed in June 2025 with issuance of D.25-06-045, but was reopened in response to an August 2025 Application for Rehearing. 31 Item 8
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 8
TO: Board of Directors
FROM: Alisa Lembke, Board Clerk / Administrative Analyst SUBJECT: Summary of Community Advisory Committee’s (CAC) September 25, 2025 Meeting
DATE: October 14, 2025
This report summarizes the Community Advisory Committee’s meeting held in person and via Zoom webinar on September 25, 2025.
Thursday, September 25, 2025 Meeting:
A. Further discussion and seeking recommendation on Large Electric Load Policy: The CAC reviewed, discussed and provided feedback on the draft Large Electric Load Policy. CAC made a motion to add language to the Policy to request that the applicant provide their interconnection status and made the recommendation to the Board to adopt the updated Large Electric Load Policy. (7-0-0).
32 Item 9
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 9
TO: Board of Directors
FROM: Rebecca Kuczynski, Chief Customer Officer
SUBJECT: Quarterly Customer Participation Update (Information) DATE: October 14, 2025
RECOMMENDATION
Receive the attached quarterly Customer Participation update reflecting the time period of July 1, 2025 through September 30, 2025 (Quarter 3 2025).
Attachment: Quarterly Report - Customer Participation update 33 Item 9 – Customer Participation Update
Status Date: 10/01/2025 1
% of Load Opted Out
Davis Woodland Winters Yolo Co Total Residential Commercial Industrial Ag NEM Non-NEM VCEA customers 28,474 20,575 2,617 10,849 62,515 54,470 6,102 11 1,932 15,245 47,270 Eligible customers 29,873 24,148 3,093 12,489 69,603 60,629 6,787 11 2,176 17,167 52,436 Participation Rate 95% 85% 85% 87% 90% 90% 90% 100% 89% 89% 90% Davis Woodland Winters Yolo Co Total Residential Commercial Industrial Ag Total % of Load Opted Out 7% 10% 13% 11% 10% 10% 10% 0% 11% 10% % of Load Opted Up 3% 1% 0% 1% 1% 1% 3% 0% 0% 1%
34 Item 9 – Customer Participation Update
Status Date: 10/01/2025 2
0 100
200
300
400
500
Qtr3 Qtr4 Qtr1 Qtr2 Qtr3 Qtr4 Qtr1 Qtr2 Qtr3
2023 2024 2025
Quarterly Opt-Outs
DAVIS UNINC YOLO WINTERS WOODLAND
0 50
100
150
200
Qtr3 Qtr4 Qtr1 Qtr2 Qtr3 Qtr4 Qtr1 Qtr2 Qtr3
2023 2024 2025
Quarterly Opt-Ups
DAVIS UNINC YOLO WINTERS WOODLAND
35 Item 9 – Customer Participation Update
Status Date: 10/01/2025 3
These pie charts are based on total opt-ups and opt-outs since launch. The percentages in the charts are the percentages of those opt-ups and opt-outs by TOT (town or territory).
Davis, 63%
Unincorp. Yolo,
16%
Woodland, 18%
Winters, 2%
557 Opt-Ups
Davis, 21%
Unincorp. Yolo,
25%
Woodland, 47%
Winters,
6%
12,664 Opt-Outs
36 Item 10
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 10
______________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Chief Executive Officer
Edward Burnham, Chief Financial Officer
SUBJECT: Bi-annual Enterprise Risk Management Report
DATE: October 14, 2025
RECOMMENDATION
Accept the Bi-annual Enterprise Risk Management Report – September 2025.
BACKGROUND & DISCUSSION
In 2018, the Board approved VCE’s Enterprise Risk Management (ERM) Policy. The policy is centered on risk management best practices and policies for the energy sector. In summary, the VCE ERM policy contains the following sections:
• Introduction: This section introduces the value of ERM as a structured approach to managing risk and uncertainty. It lays out the objectives of VCE’s ERM function, providing the framework for evaluating and managing risk in the organization’s decision-making process. • ERM Roles and Responsibilities: The ERM roles are consistent with the Board-approved Wholesale Power Procurement & Risk Management Policy. The Enterprise Risk Oversight Committee (EROC) has primary responsibility for the implementation of ERM. The policy lays out the scope of the EROC’s risk management authority.
• Business Practices: This section identifies the steps of risk management and the basic process associated with each step. The intent is to provide a high-level framework. Specific tools and techniques for implementing enterprise risk management will be recommended by the portfolio manager following approval of the policy.
• Management Reporting and Metrics: The policy defines an enterprise risk report that will be provided bi-annually to the Board.
Staff has used the consistent framework described in the ERM policy to identify various risks and related mitigations, and to ensure effective mitigation and communication across all levels of the organization. The attached ERM bi-annual report describes the activities that have taken place since 37 Item 10
September 2024 and the actions VCE is and will be taking to manage the top risks that have been identified.
Prior to this report, staff most recently presented the bi-annual update to the Board in March 2025, describing progress on the ERM plan since inception. Bi-annual updates are provided in March and September of each year.
ATTACHMENT
1. Bi-annual Enterprise Risk Management Report – September 2025 38 Valley Clean Energy
Enterprise Risk
Management Report
September 2025
39 1
Executive Summary
Introduction and Background
In 2018, the Valley Clean Energy (VCE) Board adopted an Enterprise Risk Management (ERM) framework based on the best industry practices structure developed by SMUD. The objective was to provide the Board with insight into risks that could impact the ability to execute VCE's mission and build credibility and sustain confidence in VCE's governance. In addition, the framework and reports are designed to enhance the understanding of significant risks to VCE, develop the capacity for continuous monitoring, provide for periodic reporting of risks, and establish a platform for responding to changing risk circumstances. This report is the 2nd of VCE's biannual risk reports for 2025; the prior ERM biannual Report was issued in March 2025.
ERM is a strategic approach to risk management that supports the achievement of organizational objectives through the management of integrated impacts of risks as an interrelated risk portfolio. ERM is a coordinated effort by management to treat all risks effectively, thereby reducing the overall cost of risk to the organization. The Executive Officer has charged functional leaders to oversee the treatment of known major risk categories and provide a risk overview to the Enterprise Risk Oversight Committee (EROC).
ERM Philosophy
VCE's ERM philosophy includes the following principles:
1. Identify, assess, prudently manage, monitor, and report on a variety of business-critical risks;
2. Provide enterprise risk context and linkage to existing core business processes to improve the allocation of limited resources; ERM Approach
Staff has applied a multi-perspective approach to evaluate and estimate the trade-off between risk and cost of mitigation across VCE business functions. This approach addresses the following issues:
• Roles and responsibilities
40 2
• Definitions and language
• Risk heat map and risk exposure inventory
• Risk exposure monitoring, updating, and reporting
• Integration of ERM with key business processes
• Integration of risk awareness within corporate culture • This framework supports the Board in exercising its overall responsibility to:
o Regulate opportunities and risks for VCE;
o Develop a better understanding of appropriate opportunities and risks for VCE; o Promote active management of risk exposure down to acceptable levels; and o Assist VCE in its achievement of business plan objectives and operational performance.
Summary of Activities through September of 2025
From an implementation perspective, progress continues on multiple fronts. Significant effort has been invested in creating an enterprise risk register. Risks to VCE have been identified, categorized, and rated. Existing risk controls and risk treatment measures implemented/proposed have also been identified. The risk register provides VCE's management with a consolidated view of risks being faced by VCE, the potential impact of those risks, mitigation actions, and assessment of short-term risk trends (i.e., higher/lower/steady).
Staff is using a consistent framework to identify various risks and related mitigations, and to ensure effective communication across all levels of the organization. In doing so, staff has completed the following developmental tasks:
1. Established the Executive Officer as Chief Risk Officer and Chief Financial Officer as risk process owner, focusing on day-to-day monitoring and coordination.
2. Developed ERM framework and tools
3. Conducted a risk survey
4. Developed VCE's top risk portfolio
5. Surveyed staff and management for ongoing risk input
6. Held monthly EROC meetings
41 3
Key Steps Taken Since the Last Biannual Update
Some actionable steps that VCE has taken since the last Board update in March 2025 include:
1. Have actively engaged from a regulatory and legislative standpoint, supporting regulatory statewide proceedings and settlements, meeting with key CPUC staff, and continuing progress on the annual VCE legislative platform.
2. Maintained 2025 VCE Rate Credits starting January 1 to 5% for all customers and 10% to CARE/FERA customers.
3. Executed Energy Prepayment Bond for 14% fixed power cost savings to further stabilize VCE’s financial standing, building reserves, and support affordability measures.
4. Executed Renewable Energy Credit Optimization approach for 2025 to balance emission reduction with cost-competitive customer rates.
5. Actively updating our strategic plan as a key step toward achieving our goal, ensuring alignment with evolving priorities, stakeholder input, and long-term organizational objectives Key Risks
Key risks are those risks that, given VCE's current position, could negatively impact VCE's business model, future performance or prospects, solvency, liquidity, reputation, or prevent it from delivering on its local control commitment. These key risks are updated on an ongoing basis and look forward over a 5-year horizon to identify the:
• Nature and extent of risks facing VCE
• Likelihood and velocity of the risks and potential impacts • VCE's ability to reduce or control such risks
Key Priorities for Risk Management in 2025:
1. Maintain the operational risk management process
2. Provide regular updates to the Board
3. Continue to take specific actions to mitigate risks as outlined in this document
4. Begin to develop contingency plans for unexpected and emergent events Risk Portfolio
Top 5 Risks for VCE:
42 4
1. 2026 PCIA Increases (net revenue reductions)
2. Rate Affordability and Stabilization
3. Legislative & Regulatory Policy Risk
4. Resource Adequacy (Planning Reserve Margin)
5. Commodity procurement
The following tables outline current risks (Table 1) and summarize VCE's response plan for it’s top identified risks (Table 2).
Table 1: Risk Description/Level
Risk Description
Current
Residual
Risk
Target
Residual
Risk
Power Charge
Indifference
Adjustment (PCIA)
The PCIA rate for 2025 remained neutral for the time being due to increased resource adequacy and renewable energy credit market price benchmarks (MPB). The CPUC has reviewed the market price benchmark formula that is forecasted to generate higher long-term PCIA rates and opened an additional proceeding to continue to look at other MPDs/formulas in the PCIA proceedings.
Resource Adequacy
(RA)
Although the supply of RA in the western US is tightening, the regulatory slice of the day framework and markets have stabilized at reasonable cost levels.
Commodity
Procurement
The 2025/2026 market is experiencing fluctuations associated with commodity prices, including energy prices, resource adequacy, and other components of the energy portfolio.
Regulatory & Policy
risk
Risk of additional regulatory requirements increasing complexity and cost of operations for VCE. Recently, the CPUC has taken positions and policy changes that have resulted in cost shifts from the IOUs to the CCA community.
43 5
Risk Description
Current
Residual
Risk
Target
Residual
Risk
Capital
availability/cashflow
Capital / Cashflow Risk has remained low through VCE’s rate, auto rate adjustment, and reserve policies. Staff will be proposing additional revisions to rates and reserve policies to meet, obtain, and maintain credit rating agency requirements.
Economic Uncertainty
The risks from the ongoing geopolitical climate increases the chances of impacting natural gas prices, the general economy, and the renewable sector specifically through tax reform, trade agreements, war(s), and import tariffs.
Rate structure
The risk of rate design for cost of service has been reduced with an updated rate policy and additional implementation of the "Base Green” rate option.
VCE rate stabilization funds are anticipated to be used in 2026 with changing PCIA and PG&E generation rates.
Cyber security & data
privacy
Risk of a data breach as a result of a cyber breach or physical attack.
Financial Markets
Volatility
Swings in global energy markets, financial markets, and currencies due to current geopolitical events (e.g. Ukraine and trade tariffs) have created challenges that impact VCE's power costs.
Changing customer
expectations
Risk that customer's changing expectations as a result of innovation may result in reduced customer revenue and loyalty.
Opt-out rate
The risk of higher than expected opt-out has normalized despite PG&E’s increases in both electricity transmission and distribution and gas rates. VCE implementation of "Base Green" product option should minimize opt-outs.
Business model Ability to quickly identify and respond to business risks that have the potential to impact the ability to achieve VCE goals.
44 6
Risk Description
Current
Residual
Risk
Target
Residual
Risk
Media & Community Risk of unfavorable public communications or events; spillover customer dissatisfaction related to PG&E's PSPS events and affordability.
Unknown risks Business and utilities attempt to identify and adapt to known risks but some potential events outside of VCE's control could have a debilitating impact on utilities in general and VCE in particular. Load Serving Entities, like VCE, are facing new operational, financial, and reliability challenges from unknown impacts from large loads, such as increased demand volatility, potential grid congestion, higher procurement costs, and the need for enhanced infrastructure and forecasting capabilities.
High Risk
High/Moderate Risk
Low/Moderate Risk
Low Risk
///
45 7
Table 2: Summary of VCE top risk response plan
Risk Event Response Trend1 Plan Trigger/Control Owner
PCIA
Monitor risk &
actively engage
and respond
1) Continue direct involvement
with CalCCA task groups to seek
favorable rulings and
settlements in the PCIA, ERRA,
and other filings.
2) Work towards the potential
long-term goal of attaining an
option for a PCIA buy-out and
sunset date.
The 2026 PG&E PCIA
forecast is expected to
increase due to RA
Benchmark proceeding.
VCE will continue to
monitor Energy Resource
Recovery Account (ERRA)
and PCIA proceeding.
Director of
Finance
Commodity
Procurement
Reduce &
manage risk
1) Continue to pursue long-term power purchase
agreements to reduce the
average cost of power in future
years
2) Pursue regulatory and
legislative avenues in
addressing the extreme swings
in pricing.
3) Take an active role in
regulatory proceedings at the
CPUC, including appeals on
various regulations that impact
the cost of electricity, along
with support from the CalCCA
Regulatory Committee
Execution of PPA
contracts
Regulatory rulings that
affect commodity
procurement cost
Monitor impacts and
market conditions
resulting from slice of
day resource adequacy
requirements.
Director of
Power
Procurement
1 Current trend of risk for VCE- increasing , no change or decreasing 46 8
Risk Event Response Trend1 Plan Trigger/Control Owner
Regulatory &
Policy risk
Monitor risk &
actively engage
and respond
1) Take an active role in
legislative sessions (contract
with lobbyist and engage Board
members for support /
opposition on bills) along with
support from CalCCA legislative
committee
2) Follow and continue to
update the annual VCE
Legislative Platform
3) Take an active role in
regulatory proceedings at the
CPUC, including appeals, on
various regulations that impact
VCE and CC's that increase cost
or bureaucracy without any
significant safety or cost
benefits to VCE and its
customers along with support
from CalCCA Regulatory
Committee
Weekly CalCCA
Regulatory and
Legislative Committee
meetings
Regulatory rulings
Legislative actions
Executive
Officer
Capital
Availability /
Cash Flow
Monitor risk &
actively engage
and respond
1) Continue towards conserving
cash, reducing debt, and
lowering cash requirements.
2) Evaluate reserve policy
changes.
3) Work towards the 2028 goal
of securing an investment-grade credit rating.
VCE Line of credit
agreements & extension
to 2026.
VCE is working with
Financial Advisor (PFM)
to establish VCE’s initial
investment grade credit
rating by 2028.
Director of
Finance
47 9
Risk Event Response Trend1 Plan Trigger/Control Owner
Implement VCE Rate
adjustment and
Collections Policy
Resource
Adequacy
Reduce &
manage risk
1) Take an active role in
regulatory proceedings at
the CPUC, including
appeals, on various
regulations that impact the
cost of electricity along with
support from the CalCCA
Regulatory Committee.
2) Monitor and participate in
CalCCA activities related to
regional developments in
RA.
3) Continue to develop
portfolio of resources that
satisfy various future RA
program scenarios.
Execution of PPA
contracts
Regulatory rulings that
affect RA cost, including
non-compliance penalty
structure
Annual review of VCE
PPA RA resources
Director of
Power
Procurement
48 10
Risk Event Response Trend1 Plan Trigger/Control Owner
Rate Structure Reduce &
manage risk
1) Monitor and update Board
based on analyst forecasts for
ERRA proceeding.
2) Identify and mitigate risks
outside of VCE control to limit
impacts and frequency of rate
changes.
3) Review and update rates for
rate adjustment policy.
Economic outlook and
Rate forecasts
Monitor Regulatory
proceedings that impact
PCIA, RA, and ERRA.
Monitor cash short-term
and long-term impacts to
reserve funds, credit
lines, commercial
negotiations, and PPA
covenants.
Director of
Finance
49 Item 11
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 11
TO: Board of Directors
FROM: Mitch Sears, Chief Executive Officer
Rebecca Kuczynski, Chief Customer Officer
SUBJECT: VCE Participation in Smart Home Energy and Load Flexibility Pilot (Action) DATE: October 14, 2025
RECOMMENDATION
Approve a resolution authorizing Valley Clean Energy’s participation in the Smart Home Energy and Load Flexibility (SHELF) Pilot with UC Davis and Panasonic.
BACKGROUND AND ANALYSIS
In July 2024, UC Davis’ California Lighting and Technology Center (CLTC), in partnership with VCE and Panasonic, submitted a grant application to the California Energy Commission (CEC) for GFO-23-309:
Virtual Power Plant Approaches for Demand Flexibility. The grant application (which was not ultimately funded by the CEC) built upon two previous pilots: (1) VCE’s AgFIT dynamic pricing pilot and (2) a CLTC pilot that leveraged funding and partnerships with Panasonic and the Sacramento Municipal Utilities District (SMUD) that tested smart home technology, demand flexibility and residential control strategies under normal day-to-day home schedules and activities.
Building on this work, the project scope for GFO-23-309 proposed deployment and evaluation of a residential load management pool comprised of approximately 50 households for the purposes of providing aggregated load shift/shed resources in response to utility and grid operator requests and dynamic pricing signals. The load available for shift and/or shed would have been provided by smart heat pump water heaters, smart heat pump space conditioning, electric vehicle (EV) chargers and behind-the-meter (BTM) battery energy storage systems. The scope of work included enrolling participating households in VCE’s currently active, CPUC-approved, Hourly Flex Pricing (HFP) Pilot1 .
VCE’s role in GFO-23-309 would have been to leverage HFP enrollments for GFO-23-309, for customer recruitment, education, and any additional tasks associated with HFP Pilot administration.
Though the GFO-23-309 grant application was not funded by the CEC, there was still an appetite on the part of the three partners to continue with the work. To that end, VCE, Panasonic, and the CLTC recently executed a non-binding Memorandum of Understanding (MOU) (Attachment 3), detailing a 1 The CPUC approved funds for program participation for VCE (“CCA Incentives”) based on customer enrollments in HFP in its January 25, 2024, Decision 24-01-032.
50 Item 11
2 similar project scope to GFO-23-309 but scaled back to 25 homes, with an opportunity for more funding upon successful enrollment of 25 homes. This work is to be funded by Panasonic while each of the partners would retain their general roles as defined in the grant application. VCE’s role would continue to be customer recruitment, education, and any additional tasks associated with HFP Pilot administration.
Staff believes that participating with CLTC and Panasonic in this Pilot could be advantageous for VCE customers, as it would provide additional incentives to residential customers that could be recruited into the HFP Pilot. VCE’s financial commitment over the 2-3 year pilot is limited to in-kind staff time estimated at less than 0.25 FTE that will be partially compensated through pilot funding.
This Pilot is consistent with several objectives proposed in the Strategic Plan 2025 Major Update, including:
• (Proposed) Objective 2.3: Identify and pursue cost-effective, local distributed energy resources, including both front-of-meter renewable + storage resources for VCE’s renewable energy supply portfolio, as well as behind-the-meter renewable + storage aggregations (VPPs) to help reduce RA requirements.
• (Proposed) Objective 3.5: Develop and implement customer programs and initiatives that prioritize decarbonization, community resiliency, rate affordability, and customer savings, including focused efforts on low-income and medically vulnerable customers.
Partnering on the Pilot will also help VCE assess the value of expanding efforts to enroll residential customers in Hourly Flex Pricing.
FISCAL IMPACT
Fiscal impact is limited to in-kind staff time estimated at less than 0.25 FTE that will be partially compensated through pilot funding. Additionally, CPUC-approved funds for the HFP Pilot could be leveraged to offset staff time.
Attachments:
1. Resolution 2025-XXX
2. Evaluation of Smart Home Load Flexibility under Varying Utility Programs and Household Operations Proposal for CEC Grant GFO-23-309
3. Memorandum of Understanding (MOU) between VCE, CLTC, and Panasonic 51 Item 11
VALLEY CLEAN ENERGY ALLIANCE
RESOLUTION NO. 2025-___
RESOLUTION OF THE BOARD OF DIRECTORS OF VALLEY CLEAN
ENERGY ALLIANCE AUTHORIZING THE CHIEF EXECUTIVE OFFICER TO
EXECUTE AN AGREEMENT TO PARTICIPATE IN THE SMART HOME
ENERGY AND LOAD FLEXIBILITY (SHELF) PILOT.
WHEREAS, Valley Clean Energy Alliance (“VCE”) was formed as a community choice aggregation agency (“CCA”) on November 16, 2016, under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Yolo, and the Cities of Davis and Woodland, to reduce greenhouse gas emissions, provide electricity, carry out programs to reduce energy consumption, develop local jobs in renewable energy, and promote energy security and rate stability in all of the member jurisdictions. The City of Winters, located in Yolo County, was added as a member of VCE and a party to the JPA in December of 2019; and WHEREAS, On January 25, 2024, the California Public Utilities Commission issued decision 24-01-032 authorizing the expansion of the “Agricultural Flexible Irrigation Technology (AgFIT)” dynamic rate pilot program into the Hourly Flex Pricing (HFP) Pilots, including the expansion of eligibility to residential customers with funding for VCE Pilot implementation; and WHEREAS, the California Lighting and Technology Center at the University of California, Davis (CLTC), submitted a grant application on July 1, 2024, to the California Energy Commission’s (CEC) GFO-23- 309, in partnership with Valley Clean Energy and Panasonic, to establish a testbed of homes in Yolo County to test smart home appliances and load shift in response to dynamic pricing signals in residential homes through enrollment in the HFP Pilots; and WHEREAS, the GFO-23-309 grant application was not funded by the CEC; and WHEREAS, CLTC and Panasonic executed a Memorandum of Understanding solidifying a modified scope of work similar to the scope submitted in GFO-23-309.
NOW, THEREFORE, the Board of Directors of Valley Clean Energy authorizes the CEO or their designee to take all actions necessary to execute agreements to participate in the “Smart Home Energy and Load Flexibility (SHELF)” Pilot with CLTC and Panasonic as partners, with a scope of work similar to the scope submitted in GFO-23-309.
PASSED, APPROVED AND ADOPTED, at a regular meeting of Valley Clean Energy , held on the ______ day of _______________ 2025, by the following vote:
AYES:
NOES:
ABSENT:
ABSTAIN:
___________________________________
Bapu Vaitla, VCE Chair
__________________________________
Alisa M. Lembke, VCE Board Secretary
52 Evaluation of Smart Home Load Flexibility
under Varying Utility Programs
and Household Operations
A laboratory and field study.
Abstract
In response to the success of the Panasonic partnership, the joint research completed to date and significant interest of new organizations, UC Davis proposes an expansion of its smart home research to address two important topics: 1) continuation and expansion of research at the Sacramento area SHFT to further develop customer nudging and HEMS control features and 2) deployment of a new smart home RTP field testbed in Yolo County to study load flexibility technologies, their deployment, and customer participation under RTP programs.
Ryan Allen, Cori Jackson, Keith Graeber
Corresponding researcher: Keith Graeber, [email protected] 53
Table of Contents
Introduction ............................................................................................................................................ 2 General Research Description ................................................................................................................ 3 Topic 1: Smart Home RTP Testbed – Yolo County, CA ................................................................... 3 Partner Roles and Responsibilities................................................................................................. 5 Technical Specifications................................................................................................................ 6 Research Activities ........................................................................................................................ 9 Proposed Topic Budget and Schedule.......................................................................................... 11 Topic 2: Smart Home Field Testbed – Sacramento, CA.................................................................. 14 Research Activities ...................................................................................................................... 15 Proposed Topic Budget and Schedule.......................................................................................... 17 Appendix A: Expanded Pilot 2............................................................................................................. 18 Appendix B: VCE Ag-FIT ................................................................................................................... 19 Appendix C: Load Limiting ................................................................................................................. 22 54
Introduction
The California Lighting Technology Center at UC Davis (CLTC at UCD), leveraging funding and partnerships with NEDO, Panasonic, and SMUD, has established a Smart Home Laboratory (SHL) at its facilities in Davis, CA. The Smart Home Laboratory is a dynamic testbed used for evaluating emerging residential energy and load flexibility technologies and strategies. It includes a set of residential living spaces, which can be modified to accommodate smart home appliances and devices and is equipped with environmental sensors to monitor and automatically control selected devices based on programmed constraints. The SHL also includes device-specific instrumentation and data visualization tools to report performance in real-time.
In parallel, CLTC developed, deployed, and now manages in partnership with SMUD, a Smart Home Field Testbed (SHFT) of eight single-family homes in the Sacramento area that is used to understand smart home technology, demand flexibility and residential control strategies in-situ under normal day-to-day home schedules and activities. The SHFT is outfitted with environmental sensors, device controls and a range of smart home technologies, allowing for data collection on technology performance including energy and demand flexibility use and savings. The SHFT also provides research opportunities on human factors, occupant behaviors and user attitudes associated with smart home technology, related utility programs and other strategies such as nudging and messaging.
During a previous field study at the SHFT, partners such as SMUD, PG&E, Valley Clean Energy (VCE) and the California Energy Commission (CEC) provided feedback about the home energy management system (HEMS) functionality they wish to prioritize as part of future HEMS research.
These partners, as well as CLTC, are interested in technologies and strategies for automatically shifting and/or shedding residential load to improve grid reliability, reduce peak demand, enable residential energy resiliency and lower costs for customers. • SMUD wants to automatically shift at least 1 kW of residential load, excluding air conditioning (AC) and implement BESS in a variety of home types to understand the cost and reliability of load shifting while pursuing their net zero goals for 2030. • PG&E has approval from the CPUC to implement a residential real time pricing (RTP) pilot and is interested in understanding the reliability of residential load scheduling based on RTP signals (see Appendix A for more information).
• VCE also plans to implement residential RTP and wishes to evaluate the load shift benefits of using a HEMS to automate appliance operation and inform customers about current and upcoming energy prices (see Appendix B for more information). • PG&E and VCE want to identify the best technologies for inclusion in RTP programs and understand how they can be used successfully when operating in response to a dynamic pricing signal.
• All partners wish to quantify the availability, reliability, potential costs and cumulative benefits of using residential, site-level, BESS as a utility program resource to reduce their resource adequacy (RA) costs, which currently range between $180/kw-yr and $360/kw-yr.
• CEC wants to determine the availability and magnitude of shiftable, residential load during evening, peak, summer hours (7 PM to 9 PM, typically) associated with electric water heaters, heat pump AC, dishwashers and electric clothes dryers. • CEC is also interested in testing the communications reliability of smart, electric, water 55
heaters so that they may be considered as part of future regulatory updates to California’s Load Management Standards.
General Research Description
In response to the success of the Panasonic partnership, the joint research completed to date and significant interest of new organizations, UC Davis proposes an expansion of its smart home research to address two important topics: 1) continuation and expansion of research at the Sacramento area SHFT to further develop customer nudging and HEMS control features and 2) deployment of a new smart home RTP field testbed in Yolo County to study load flexibility technologies, their deployment, utility program structures and customer participation under RTP programs with and without nudging.
Topic 1: Smart Home RTP Testbed – Yolo County, CA
CLTC, in collaboration with PG&E, VCE and Panasonic (collectively called “Team”) proposes to deploy and evaluate a residential load management pool composed of approximately 50 households for the purposes of providing aggregated load shift/shed resources in response to utility/grid operator requests and real-time pricing signals. The total, aggregated load available for shift and/or shed is planned at 400 kW provided by smart heat pump water heaters, smart heat pump space conditioning, electric vehicle (EV) chargers and behind-the-meter, (BTM) battery energy storage systems (BESS).
The Team plans to enroll participating households in PG&E’s RTP pilot rate called Hourly Flex Pricing, which will be dispatched by GridX, a utility rate design and PG&E program partner.
Currently, automated reductions of residential loads like water heating and space conditioning are not eligible loads to be counted for use in resource adequacy programs. This means that utilities cannot count the value of the load reduced by automatically shifting the operation of these appliances as an option for meeting their energy generation targets. Therefore, the inclusion of these devices as part of this research will serve to quantify their overall contribution in terms of kW-hours for future use.
For this research, “availability” means determining when appliances are typically “ON” so that utilities can plan for controlling them as part of a load management program or as an alternative to traditional energy generation (solar, etc.). This data is not currently available to the utilities or the public for planning purposes. “Feasibility” means quantifying the magnitude of energy use that can reasonably be shifted as part of that same program. So, for example, just because a HP product may be “ON” for a certain number of hours per day, if those hours do not align with the time of day needed by the utility, the feasibility of using them as part of a utility program is reduced. This type of study is critical in pilot programs. Individual technologies like HP appliances must be tracked and measured in many households before the utility can determine a value to use in their energy planning activities.
If these technologies are determined to contribute a significant amount of energy at a certain time of day or season, then they can be used to meet project targets. Currently, our study will help the utilities to quantify the value of these technologies. That is the intent of the HFP pilot, as well. The utilities are trying to understand how different residential devices can contribute to overall load flexibility and resource adequacy programs.
In California, barriers to use of residential, demand-side load aggregation combined with dynamic pricing exist as technical and programmatic knowledge gaps in several important areas. First, California community choice aggregators like VCE have yet to attempt enrollment and automated dispatch of RTP to their residential customers in partnership with the IOUs. This approach is untested, 56
and its demonstrated value as a demand-side resource is yet to be fully determined and documented 1,5. The Smart Home RTP Testbed will provide a clear method to test and learn how to expand RTP rates to more customer segments and end uses to support grid reliability and ensure adequate electric power during times greatest need2. In addition, this project will inform PG&E, VCE and other interested load-serving entities (LSEs) on methods, challenges, and solutions for implementing automated RTP to achieve cost-effective shift DR prior to the January 2027 deadline contained in the Load Management Standards for hourly RTP to be available to all customer classes3.
Secondly, most IOUs and CCAs have limited to no experience with co-design and implementation of dynamic rates and programs for the residential sector using a shared pricing server like GridX that can serve customers from both groups simultaneously.
Last, the actual value of demand-side, BTM programs and technologies lacks real-world data to support claims4. All types of stakeholders, from individual customers to aggregators to LSE’s, have yet to invest in the research, development, or demonstration for DR combined with residential end-use automation and RTP necessary to collect and validate energy use, demand, and related savings of this approach. While California represents the largest portion of DR operating today, these DR programs focus on supply-side DR services and event-based load reductions.
This research will provide insights on RTP rate design, customer recruitment, two-way communications between utilities and customers through Panasonic as an ASP, the load reduction value of specific residential end-uses in real-world applications, and coordination between community members, technology providers, CCAs and IOUs5.
The overall EP2 pilot program/project is funded at tens of millions of dollars by the California Public Utilities Commission. No single entity, other than the utility itself, can run a study that focuses on the entire pilot. Therefore, this research project proposed by CLTC is designed to help answer a subset of questions with information needed by the utilities to inform future residential RTP load management programs. CLTC’s mission is aligned with the goals of the pilot program, and we believe that the research proposed is also aligned with Panasonic’s interests to understand RTP programs, load management and methods for deploying load management strategies and technologies in Japan.
Learning from both the pilot and the subset of research contributed by this project are critical for helping Panasonic understand its role in future US programs as well as its role in forthcoming Japanese RTP / energy programs.
Given the breadth of potential research areas and opportunities associated with such a project, CLTC and its partners propose to address the following specific research questions:
1. What is the composition of the smart technology stack (combination of smart home devices and DERs) that provides the most cost savings for customers when those 1 Existing valuation of RTP and residential VPPs in California are based on modeling not measured performance. 2 PG&E Advice Letter 7223-E submitted to CPUC March 25, 2024. 3 California Load Management Standards.
4 LBNL, “California Demand Response Potential Study, Phase 3”. 5 Each of these RTP and DR goals and objectives will help California to meet its statutory energy and demand flexibility goals including its goal to achieve 7,000 MW of demand flexibility by 2030 per Senate Bill 846 (Statutes of 2023). 57
customers are enrolled in RTP? Are there existing incentives or potential for new incentives that benefit the customer and the utility when considering specific, smart home technologies?
2. What are the typical load profiles for residential HP water heater, HP space conditioning, and other appliances in a SF and/or multi-family home?
3. Can residential load aggregation of select technologies be reliable6 enough to reduce a utility’s resource adequacy (RA) burden? Can we confidently justify, based on project results, a capacity factor for residential load shift/shed?
4. What is the potential of residential load shift/shed at the service territory and state level assuming estimates are based on measured field data?
Partner Roles and Responsibilities
• GridX, on behalf of PG&E and VCE, will program and dispatch a customized HFP signal reflecting LSE-specific prices as well as transmit event-based signals that indicate grid operator needs in real-time.
• VCE will assist with participant recruitment and rate enrollment, as needed, and conduct project performance evaluations supporting the utility business perspective. • CLTC will complete recruitment and enrollment activities required by UC; survey, design and manage technology installations at each participating home; and test, in its laboratory, basic functionality and ensure connectivity among smart appliances, EV charges, BESS, intermediate software or HEMS necessary for integration between BTM loads and the price server. CLTC will also equip each home with necessary monitoring equipment, collect performance data develop load profiles and quantify load shift/shed for each event and over time in relation to the RTP.
• Panasonic will serve as the automation service provider (ASP) by providing the necessary integration solution for ensuring each home load responds as designed to the RTP and event signals. Integration may be provided in the form of a hardware and/or software solution such as a HEMS, directly between the GridX server and each appliance using custom programming and APIs, or a combination of measures.
VCE must serve as the initial point of contact for the individual customers in their service territory.
They will give CLTC access to a set of customers who are most likely to qualify for inclusion in this study and they will facilitate meetings between CLTC and selected customers. In addition, VCE will create and distribute program materials on this study like flyers and surveys to help CLTC to engage 6 Load shift reliability is defined by the percent of the enrolled loads participating in the load shift event and how many hours that load shift remains in place. In a recent meeting, SMUD mentioned that 60-80 percent of enrolled customers participate in thermostat program load shift events. After one hour, up to five percent of people manually override control settings to nullify the load shift. After two hours, up to an additional five percent of participants nullify the load shift, followed by an additional five to 15 percent of participants opting out after hour three. By hour four, SMUD reports that 20-60 percent of people ended their participation in a load shift event; however, SMUD requires at least four hours of uninterrupted load shift to count the load for its market programs. 58
with the customers interested in participating.
Based on the initial pool of participants provided by VCE, CLTC will identify those of interest, call them and visit their home as needed to verify technologies identified in the surveys. Once CLTC identifies the best DERs to implement in the homes and provides the customer with a research use agreement, the customer can agree to participate and CLTC will enroll the participant by executing research use agreements (RUA) between UC and the participant. These RUAs are required to conduct a study on property not owned by the University. VCE will enroll the participant in any rate programs needed to execute the study.
Technical Specifications
This Smart Home RTP Testbed implementation is composed of three discrete technical elements: 1) the communication systems necessary for two-way exchange between LSEs, enabling technologies and residential participants; 2) the forecasted RTP prices and RTP signal; and 3) the enabling technologies and BTM DERs installed in each household.
Figure 1. Residential distributed energy resource (DER) bi-directional communication network from the HEMS to the ASP aggregator network, GridX, public internet, PG&E’s distribution control center, and CAISO.
In addition to evaluating the business case for residential load shifting from the VCE’s utility perspective and Panasonic as an ASP, this research will evaluate the availability and feasibility of using heat pump water heater, heat pump HVAC, EV chargers and BESS technologies in both single and/or multi-family buildings located in VCE service territory and controlled in response to PG&E/VCE’s upcoming Hourly Flex Pricing signal, which is slated for customer launch in 2025. See Appendix A for more information on the Hourly Flex Pricing pilot (previously called Expanded Pilot 2 or EP2) including a depiction of the planned system architecture.
Specific smart appliances and residential distributed energy resources (DERs) of interest include:
• Solar photovoltaic generation (site-level)
• Battery energy storage systems (site-level)
• Heat pump water heaters
• Heat pump HVAC
• EV chargers and control systems (uni- or bi-directional) 59
Home Energy Management Systems
The ideal home energy management system (HEMS) is “an intelligent network control system that can integrate all power generation, power consumption, and energy storage equipment in the home for control and management, …, change the power consumption habits of the user, reduce the user’s electricity bill, and realize two-way communication with the grid, two-way energy flow, etc.” The HEMS in this project will connect the DERs and smart appliances (heat pump water heaters, heat pump HVAC, EV chargers and BESS), and implement state changes wirelessly, provide two-way communication with a secondary ASP device/cloud software and/or act directly implement the load shift for each of the DERs and smart appliances and inform the appliance users of the load shift plan before and during the event via audio or visual messaging.
Using a HEMS device provided by the ASP, smart technologies will be programmed for automated response and/or operation based on hourly prices, which will be provided by the HFP pilot. In addition, certain households in low-income, disadvantaged and/or high-fire risk communities may qualify for non-Panasonic BESS, which can be used to replace grid-provided electricity during the costliest hours of the day, LSE peak periods or unscheduled, emergency events, as well as deliver additional capacity back to the grid when available.
The Smart Home RTP Testbed will target a subset of EP2 participants enrolled with VCE. The EP2 enrollment goal is 50 MW of flexible load provided by participation from 500 – 1000 residential customers. The Smart Home RTP Testbed is aligned with this goal, and the Team expects to enroll 5- 10% of EP2 participants in its to achieve 400 kW of load-modifying flexibility during PG&E and VCE’s annual peak hour(s). Community members currently on rate plans EV2-A and E-ELEC will be eligible for the Smart Home RTP Testbed (and EP2 pilot) per D. 24-01-032.
Dynamic Rate and Price Signal
Dynamic electricity rates are the gold standard for realizing load flexibility opportunities7. For this project, dynamic electricity pricing will be provided by PG&E as part of the “Expanded Pilot 2” (EP2) authorized in January 2024 by the CPUC under Decision 24-01-032. The dynamic rate, called Hourly Flex Pricing (HFP), will provide eligible PG&E and VCE residential customers with time-varying hourly prices that reflect forecasted demand, associated cost, and imbedded carbon intensity of grid-supplied electricity. Higher hourly prices will reflect the need for households to conserve electricity in support of local and system electric reliability. Hourly Flex Pricing will encourage households to schedule their loads during the most cost-effective hours of the day. The EP2 pilot is authorized to provide summer reliability benefits through December 2027. Today RTP is available on the PG&E website here Current Hourly Flex Pricing starting in November 1st, of 2024.
To support this CPUC decision, the Team will utilize Gridx, a tariff design expert, to produce a non-binding, rolling, seven-day forecast of electricity prices under a new rate, called Hourly Flex Pricing (HFP). HFP will provide a dynamic rate similar to the hourly pricing signal provided by VCE in its original RTP pilot designed for agricultural customers (AgFit). AgFit used dynamic generation and distribution rate components, customer subscriptions, and transactive buy/sell options based on the CPUC Energy Division (ED) Staff’s CalFUSE framework. PG&E’s EP2 dynamic rate, HFP, contains 7 CEC, Commission Report, “Senate Bill 846 Load-Shift Goal Report”, page 27, May 2023. 60
the same dynamic rate components and customer subscription as the VCE Ag Pilot but does not have the transactive elements. Participating households will connect to the GridX signal to receive price forecasts either directly, via local management, or from aggregated management signals from third-party automated service provider (ASP), Panasonic, via WIFI/LTE to the secure receivers at the participant’s home.
A draft of the GridX API specification may be found here: Calculate API GridX Docs.
Automation Service Provider
Automation service providers (ASPs) receive utility program funds to automate customer devices and respond to dynamic pricing signals, with specific rates depending on the program and the amount of load managed. Incentives are often based on kW-yr magnitude of customer loads managed. ASP incentive rates reflect the program complexity, enrollment difficulty and anticipated customer availability associated with program participation. Higher incentives are used to encourage program participation. When higher incentives are available, ASPs are more motivated to seek out and enroll participants, thereby increasing program adoption. Lower rates reflect a program with less complex program requirements, a larger eligible customer base, and therefore higher levels of expected customer participation. Other ASP payment methods include annual flat rate payments based on the magnitude of annual customer load managed and rates that vary based on the customer sector or customer response frequency. Exact rates vary among utilities and programs. Additional information on ASP incentive and payment structures may be found on the CPUC website for each approved program utilizing one or more ASPs. CLTC can research and document current and expected rates for ASP incentives to help Panasonic create a business case for ASP services in California.
Enabling Technologies
Smart appliances, BESS and EVs are all widely available DERs will the potential to deliver automated load management for residential customers. From the utility perspective, all are considered BTM, demand-side resources capable of contributing to, but not formally accounted for, as part resource adequacy programs. Therefore, consistent reductions in BTM energy use over time may contribute to resource adequacy credits for the utility, which could ultimately be used to invest in shift DR, RTP and associated incentives passed on to ratepayers. In addition, demand potential studies estimate that when these technologies are augmented by universally applied dynamic pricing, they could contribute up to 3.5 GWh of load shift8
.
Laboratory evaluation is necessary to determine and verify basic functionality, connectivity and controllability of any appliance, device or system proposed for use in a customer’s home.
Technologies must be tested for compatibility with ASP aggregation software/systems. A minimum set of requirements will be developed for each technology type. Eligible technologies will then be made available for home installation and the results of each evaluation can be shared with participating ASPs to improve installation and commissioning efficiency.
A general list of performance criteria includes, but is not limited to, the following:
1. Appliance includes native WiFi or central control hub connection capabilities to view data 8 LBNL, “The California Demand Response Potential Study, Phase 4: Report on Shed and Shift Resources Through 2050,” May 2024.
61
from a remote source. The appliance should have a functional API that can be queried to collect data and transmit change of state commands to the appliance.
2. Space conditioning and water heating appliances must provide temperature setpoint control accessed via its API.
3. ASP must provide hardware and software services that enables connection to the GridX price server via its API to gather and interpret pricing signals at least one day ahead and hourly to generate load shift schedules and logical sequence of events that can be sent to a HEMS or directly to an appliance in the customer’s home.
4. CLTC will verify connection of the ASP hardware/software to the price server and/or VCE as prices, schedules and similar information is sent to the HEMS by recording the information received by the HEMS. CLTC will also evaluate the repeatability and reliability of the ASP to receive and send information.
5. CLTC requires that a HEMS be able to connect to the DERs and smart appliances (heat pump water heaters, heat pump HVAC, EV chargers and BESS), and implement control commands wirelessly, provide two-way communication between the signal provider (ASP hardware/software or GridX server directly) and the home appliance/system, and inform the appliance users of the load shift plan before and during the event via audio or visual messaging.
In addition, PG&E and VCE have yet to determine the specific residential appliances that will be eligible or incentivized under the RTP pilot. They do expect to include customers with existing BESS and EVs; and the laboratory research on smart home appliances proposed herein is designed to support these utilities during pilot planning over the next 6-12 months. Similarly, PG&E and VCE have yet to determine the communication and commissioning logic needed to make these loads responsive to the Hourly Flex Pricing signal. Therefore, this research, its questions and their outcomes all focus on advancing performance and market adoption of residential load flexibility solutions that provide value to local utilities, customers and manufacturers.
Research Activities
UC Davis will survey local utilities customers (VCE and PG&E) to gather appliance information and determine a typical single-family home and multi-family home appliance configuration. CLTC will then select approximately 50 homes to form the new RTP Field Testbed in Yolo County (VCE+PG&E service territory). The economic strata of selected customers, building types such as single family, duplex and multi-family homes, and occupancy arrangements such as rental versus owner-occupied dwellings will be determined in advance of site selection.
Following participant selection and enrollment, CLTC will deploy power measurement equipment to collect individual load profiles and operating schedules of major appliances at each test site. Collection of baseline information will then be followed by procurement, installation and evaluation of emerging smart home appliances/devices appropriate for use with dynamic utility tariffs. Activities will also include continued engagement with utility leadership and partner R&D teams to understand potential benefits of smart appliances combined with HEMS for relevant programs and customers.
CLTC will verify connection of HEMS to the appliances, monitor energy consumption of loads to ensure load shift, monitor HEMS notifications to appliance users, and survey appliance users before, 62
during and after the project. CLTC will also evaluate the repeatability and reliability of the HEMS to change the state of the DERs and smart appliances and messaging to ensure load shift effectiveness and communication with load users.
Additional research questions to be addressed include:
• How much load can be shifted with a BESS in the average California home in VCE and PG&E territory?
• What is the process for connecting a BESS and HEMS to an RTP server? • Does inclusion of local BESS make residential load shift participation more reliable in both magnitude and frequency as compared to homes without local BESS? • What are the costs, permits and other implications of implementing a BESS in a single-family home and/or multi-family building? • How prevalent are heat-pump water heaters, heat-pump HVAC and EVs in the average California home in VCE and PG&E territory?
• What are the necessary connectivity and integration requirements for heat pump water heaters, heat-pump HVAC and EV chargers to operate in conjunction with a HEMS, BESS and an RTP signal such as Hourly Flex Pricing?
• Are automation service providers necessary for connecting, maintaining or managing any part of a residential system enrolled in RTP programs? What is their role, if any, and what value do they provide to the utility and/or customers? Task 1: Enroll and Survey Participants
UC Davis will identify and enroll approximately 50 households to form the RTP Field Testbed in Yolo County. UC Davis will determine, in advance, the household characteristics of interest and use this information as the basis for participant selection. Following enrollment, UC Davis will survey testbed participants to gather appliance information and determine the typical single- family home and/or multi family home appliance configurations for this demographic. • Deliverable: RTP Field Testbed Participant memo
Task 2: Laboratory Evaluation of Select Technologies
UC Davis will complete laboratory evaluations of battery energy storage technologies, heat- pump water heaters, heat pump HVAC, EV chargers and other selected smart home technology to determine those that are feasible and ready for field testing. Technologies will include emerging products and engineering prototypes provided by partner organizations. Work will include BESS and smart appliance installation and testing to verify functionality in response to dynamic residential rates and pricing signals such as the Hourly Flex Pricing, which will be deployed through the GridX and integrated at each home by the ASP. UC Davis will document a preliminary installation procedure for certain tested devices to help streamline the field demonstration to be conducted in Task 4. • Deliverable: Lab Evaluation Memo, Preliminary Installation Procedure(s) 63
Task 3: Field Installation and Operations Planning
UC Davis will develop load shift operating plans for residential single and/or multifamily buildings equipped with smart appliances, HEMS and energy storage operating under Hourly Flex Pricing. UC Davis will collaborate with utility partners, customers and other stakeholders to ensure operating plans and schedules reflect viable load shed and savings opportunities for both the customer and the utility.
Outcomes will include a step-by-step programming/commissioning guide for technology providers, installers and customers that will help these groups to establish appliance operating plans that best suit their needs while ensuring they receive the financial benefits available with RTP. • Deliverable: Load Shift Operations Memo, Smart Home Programming Guide for RTP Customers
Task 4: Field Study
UC Davis will deploy a field study of at least 50 homes enrolled in PG&E/VCE Hourly Flex Pricing.
UC Davis will install power meters to quantify potential for residential electricity load shift at each home. Once the baseline is determined, UC Davis will procure some equipment (power measurement hardware, internet routers, and EV chargers), and oversee the installation of this equipment and donated smart appliances/devices (heat pump water heaters and heat pump HVAC), along with a HEMS plus donated DERs like BESS (up to 25 homes) to demonstrate load shift operation and quantify the savings potential in residential single-family homes and multifamily buildings. The field study will support development of the programming guide (Task 3) and provide experience and data necessary for determining the costs and benefits of using various smart home technologies for homes enrolled in RTP.
• Deliverables: Available Shiftable Load Memo, Load Shift Feature/Device Results Memo (for each feature incrementally).
Task 5: Final Reports
UC Davis will document research activities and outcomes in a final project report and provide recommended next steps for continued research. Work will include presentations and meetings with project stakeholders to share research findings and, potentially, engage new partners.
Research outcomes and lessons learned will be valuable for informing and improving future RTP deployments in California and elsewhere.
• Deliverable: Final Report and Presentations
Proposed Topic Budget and Schedule
• Duration: 3.0 years
• Proposed start date: January - March 2025
• Total Budget Request: $2,682,000 + $12,000 per additional home above 50 homes • Includes $600,000 for smart home technologies, installation, maintenance and monitoring over three years: $12,000 per home: up to $5,200 equipment ($1,800 for measurement equipment hardware/install and up to $3400 for smart appliances but 64
others smart appliances can be evaluated if donated), $600 customer incentives, $1,450 home site internet and other routine maintenance costs for sensors and data collection devices, $4,750 CLTC staff labor and/or installation contractor costs over the duration of project to install and maintain each home/field site. • Includes $140,000 for Valley Clean Energy labor to support project enrollment and research.
• ASP services/functionality/equipment provided by Panasonic or up to $250,000 additional funding to contract with 3rd party ASP. Cost of 3rd party ASP to be determined based on final customer and appliance inventory. • Panasonic: Requested Equipment/In-Kind Support
• EverVolt BESS equipment (hardware and software with functional API) – at least 25 for first 50 homes, then more if Panasonic elects
• SmartBox equipment – at least 25 units, more if Panasonic elects • Solar photovoltaic generation – Qty TBD by Panasonic
• Daiken: Additional Requested Equipment/In-kind Support • Heat pump water heaters (Daikin) – 15 for first 50 homes (15 annually, 2 years), then more if desired by Daiken and Panasonic
• Heat pump HVAC (Daikin) – 15 for first 50 homes (15 annually, 2 years), then more if desired by Daiken and Panasonic: Equipment + Installation estimated at $150,000. • Daiken project support: $300,000.
• 1st payment due at project launch: $100,000
• 2nd payment at 12-month milestone: $100,000
• Final payment 24-month milestone: $100,000
TOPIC 1: RTP Field Testbed
Research Activity Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Task 1: Enroll & Survey Participants
Task 2: Lab Evaluation of Select Technologies
Task 3: Field Installation & Operations Planning
Task 4: Field Study
Task 5: Final Reports, Project Management
Annual Research Budget - Base only
Annual Research Budget - Base + Expanded HP + Partner Match $ 1,142,822 $ 1,652,652 $ 627,047 2027
$ 847,822 $ 1,377,652 $ 457,047
2025 2026
65
Match Funding
• Total Match Funding: $290,000
• Valley Clean Energy is providing $140,000 in match funding in the form of in-kind services to support participant recruitment and utility billing and support. • PG&E is providing approximately $150,000 in match funding in the form of in-kind services to support deployment of the HFP signal, utility bill data analysis and related support.
• CLTC expects to leverage additional utility funding provided by the following programs:
• Hourly Flex Pricing – ASP incentives of at least $42 kW-yr of managed enrollment • Energy Savings Assistance – incentives for purchase and installation of smart home appliances for CARE and FERA rate customers.
Research Activity
Funding
Request
Partner
Match/In-kind
Task 1: Enroll & Survey Participants $ 102,863
Task 2: Lab Evaluation of Select Technologies $ 808,468 Task 3: Field Installation & Operations Planning $ 346,645 Task 4: Field Study $ 1,182,807
Task 5: Final Reports, Project Management $ 241,738
Annual Base Research Budget $ 2,682,522
Additional Funding: Daiken HP/CLTC scope $ 300,000
Additional Funding: Daiken, Materials and install* $ 150,000 Additional Funding: VCE In-Kind Support $ - $ 140,000
Additional Funding: PG&E In-Kind Support $ - $ 150,000
Total Annual Funding Request: Base + HP Expansion $ 1,142,822 $ 1,652,652 $ 627,047 $ 3,132,522 $ 290,000 $ 50,000 $ 50,000 $ 50,000
$ 100,000 $ 100,000 $ 100,000
$ 75,000 $ 75,000 $ -
$ 70,000 $ 50,000 $ 20,000
$ 847,822 $ 1,377,652 $ 457,047
$ 259,984 $ 86,661 $ -
$ - $ 887,105 $ 295,702
$ 80,740 $ 80,499 $ 80,499
$ 102,863 $ - $ -
$ 404,234 $ 323,387 $ 80,847
2025 2026 2027
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Topic 2: Smart Home Field Testbed – Sacramento, CA
The SMUD project provided the first evidence that specific residential appliances may be useful and “reliable” as a load-shift resource for energy planning purposes. The sample size and duration of the data collected in that study, while very promising, does not provide the level of rigor required for the IOUs to rely on the data for system-wide planning purposes. Therefore, we are proposing a larger study group to validate some of the original SMUD findings and continue to quantify and refine the value of these resources for use in future utility programs and tariff design. This research is important for the utilities and the product manufacturers because should specific residential appliances be found “reliable” and “available”, then the utilities can use them as a lower-cost alternative to traditional energy generation and manufacturers know that the demand and subsequent sales of these appliances will grow and be sustained in the IOU markets.
SMUD has expressed interest in understanding the benefit of using a HEMS to nudge homeowners to avoid electricity use under their new critical peak pricing (CPP) rate structure rather than using phone and/or email notifications. SMUD also expressed interest in exploring the load limiting HEMS feature developed by CLTC as part of its prior research at the SHFT. See Appendix C for more details. CLTC hypothesizes that the load limiting feature is the next step required for effective load management after load shifting itself, because once loads are shifted out of a specific time period, these loads are likely to be reenergized at full power later in the day causing a large spike in electricity demand (Figure 1). Large spikes can be costly to customers in terms of demand charges, regardless of the energy price for the time period.
Figure 1. Example of loads shifted away from the peak price period and set to begin at 8 PM without load limiting (left), which causes an unnecessary spike in demand, and an example of the same loads shifted to start at 8 PM, but limited to not exceed 130 kW, which reduces the spike by staggering the start times of individual loads over several hours (right)9.
SMUD also provided feedback that they only offer load shifting in an opt-in arrangement, rather than an opt-out arrangement, which is also the arrangement previously implemented for the thermostat, dishwasher, clothes washer and clothes dryers tested previously at the SHFT. Opt-in nudges are nudges where the user is notified about an upcoming opportunity to shift load, and the user can choose 9 https://www.energyhub.com/resource/webinar-recording-future-of-vpps-cross-der/ 67
to participate by postponing appliance use or continue to use their appliance as usual. Opt-out nudges are nudges where the user is told that the load will be shifted automatically (dishwasher is automatically set to delay mode, for example) and the user must manually start their appliance/load to operate and override the shift/delay. It is hypothesized that the acceptance and reliability of load shifting will increase with the opt-out control style rather than the opt-in because the decision has already been made in advance and the user will not take additional actions to override the system.
Seven of eight homes in the SHFT are interested in participating in a study with this control type.
SMUD also expressed interest in understanding the difference in effectiveness between the two approaches.
In response to SMUD and other partner feedback, UC Davis proposes to continue studying the eight SMUD homes, and possibly expand the testbed to include up to 20 homes, in order to evaluate refined controls features and determine when and why nudges are accepted by homeowners enrolled in alternative utility plans such as SMUD’s CPP electricity rate. See Appendix C more information about CPP. Desired research outcomes focus on advancing performance and market adoption of residential load shifting related to CPP demand events and different nudge/automated load shift approaches to existing and new smart appliances/devices.
New smart appliances/devices of interest include:
• Lighting (dimming)
• Lighting + TVs (dimming).
• EV Charging (delay)
• TVs (dimming)
• Ceiling fans (fan speed and on/off control)
• Kitchen ventilation fans (fan speed & on/off)
• Bathroom/Laundry ventilation fans (fan speed and on/off) • Windows (open/close)
• Plugged in device (ideal time for use, and on/off)
• Cooking range (delay)
Research Activities
UC Davis will continue to engage with the existing SHFT and SMUD customers to gather additional data and insights on their residential load profiles. This research will include identification, procurement, installation and evaluation of new emerging smart home appliances/devices as appropriate for the SMUD testbed including enrollment of up to 12 additional households. Activities will also include continued engagement/support of utility leadership and R&D teams to understand potential benefits of smart appliances combined with HEMS for relevant programs and customers.
Research questions for this topic include:
68
• How much more load shift is achieved when homes have a Critical Peak Pricing (CPP) electricity rate structure in place than with the standard TOU or flat electricity rate structures?
• Does load shift engagement increase or decrease when nudges are presented visually and audibly on a screen near the appliance as compared to SMUD’s standard communication methods using email and text?
• What is the incremental load shift acceptance benefit for residential loads when comparing SMUDs standard opt-in and CPP communications to opt-out messages displayed on a speaker/display on or near the smart appliance being load shifted? • What is the incremental load shift acceptance benefit for residential loads when comparing opt-out nudges to opt-in nudges displayed on a speaker/display on or near the smart appliance being load shifted?
• What is the acceptance rate and total load shift effectiveness of a systemic, residential, load limiting control feature compared to periodic financial incentives/nudges? • What is the acceptance rate and total load shift effectiveness between various messaging formats such as nudges reporting relative cost savings (% savings) compared to absolute cost savings ($ savings)?
Task 1: Field Test and Technology Planning
UC Davis will evaluate new smart appliances/devices in its smart home laboratory, then develop and/or evaluate refined load shifting and nudging features to determine the best suite of products and control strategies for field deployment. The goal is to identify the products and communication strategies with the most potential for use (magnitude and frequency of shifted load) as part of residential load shifting for customers operating under time-varying utility pricing programs such as SMUD’s CPP.
• Deliverable: Laboratory Evaluation Memo
Task 2: Stakeholder Review
UC Davis will invite stakeholders to review the new features, functionality and deployment methodology at CLTC’s SHL in order to gather additional insights and feedback before finalizing the second cohort of smart home technologies and control strategies for field deployment at the SHFT. • Deliverable: Stakeholder Feature Review Memo(s)
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Task 3: Field Deployment and Analysis
UC Davis will install and evaluate new smart home technologies and control strategies at its SHFT to quantify their residential load shifting potential. New technologies may include lighting, TVs, ceiling fans, kitchen ventilation fans, bathroom/laundry ventilation fans and cooking ranges. UC Davis will analyze the acceptance of load shifting nudges, collect data and report on findings. Results will be shared with SMUD and other interested parties to gather further development support and ongoing testbed participant engagement.
• Deliverable: Available Shiftable Load Memo, Load Shift Feature/Device Results Memo (for each feature incrementally)
Task 4: Final Report
UC Davis will document research activities and outcomes in a final project report and provide recommended next steps for continued research. Work will include presentations and meetings with project stakeholders to share research findings and, potentially, engage new partners. • Deliverable: Final Report and Presentations
Proposed Topic Budget and Schedule
• Total Budget: $1,200,000
• Duration: 3.0 years
• Start Date: January - March 2025
2025 2026 2027
Research Activity Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Task 1: Field Test & Technology Planning
Task 2: Stakeholder Review
Task 3: Field Deployment & Analysis
Task 4: Final Reports
Annual Research Budget $400,000 $600,000 $200,000
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Appendix A: Expanded Pilot 2
Dynamic electricity rates are the gold standard for realizing load flexibility opportunities10. Dynamic electricity pricing will be provided by PG&E as part of the “Expanded Pilot 2” (EP2) authorized in January 2024 by the CPUC under Decision 24-01-032. The dynamic rate, called Hourly Flex Pricing (HFP), will provide eligible PG&E and VCE residential customers with time-varying hourly prices formatted to meet the OpenADR 3.0 communication standard. Pricing will reflect forecasted demand, associated cost, and imbedded carbon intensity of grid- supplied electricity.
Figure A1. Expanded Pilot 2 system architecture.
Higher hourly prices will encourage households to conserve electricity in support of local and system electric reliability by scheduling their loads during the most cost-effective hours of the day. The rate will be formatted and delivered according to the OpenADR 3.0 communication standard. The EP2 pilot is authorized to provide summer reliability benefits through December 2027. A copy of the CPUC’s final decision regarding EP2 implementation is provided as Attachment A.
This project will target a subset of EP2 participants located in Yolo County including both bundled (PG&E) and unbundled customers (VCE). The EP2 enrollment goal is 50 MW of flexible load provided by participation from 500 – 1000 residential customers. For this research, the team expects to enroll 50 EP2 participants to achieve to demonstrate load-modifying flexibility over the course of one year.
10 CEC, Commission Report, “Senate Bill 846 Load-Shift Goal Report”, page 27, May 2023. 71
Appendix B: VCE Ag-FIT
As California continues its leadership role in building and transportation decarbonization by aggressively pursuing energy efficiency and electrification programs to meet its climate goals11, the addition of electrically powered appliances to replace gas equivalents will have a serious impact on the State’s overall electricity needs. Consequently, the residential market sector is under immense pressure to electrify, and manufacturers have responded with modern electric appliances such as heat-pump water heaters and induction cooktops to replace natural gas units. As part of this transition, there is an opportunity to incorporate secondary features that will further improve electric appliance performance and user experience. For example, smart appliances, which provide access to local and/or cloud-hosted appliance-control applications (apps) and operating data, are becoming more common.
While smart appliance apps are primarily focused on providing users with additional amenities, they can also deliver energy efficiency and load management benefits by considering and responding to utility and/or grid- level signals such as dynamic energy pricing, carbon intensity, peak demand forecasts, or Energy Emergency Alerts.
Valley Clean Energy (VCE) is a Community Choice Aggregator (CCA) serving Yolo County, California. They are a recognized leader in the development of dynamic energy pricing tariffs and accompanying customer tools and resources focused on reducing energy use during critical days and times. With the support of the California Public Utility Commission (CPUC), VCE has implemented a successful, four-million-dollar, multi-year dynamic pricing pilot project called Ag-FIT for agricultural customers12. VCE is working in partnership with Polaris Energy Services and TeMix to generate the hourly dynamic pricing tariff used in this pilot. The pilot’s primary objective is to quantify the load shift potential of agricultural irrigation pumps controlled via a web-based scheduling app13. The app allows agricultural customers to easily understand electricity prices seven days in advance for each hour of the day to schedule their pumping based on their specific operational needs. Due to the success of implementing a dynamic pricing tariff with the Ag-FIT pilot, CPUC is considering VCE’s request to pursue implementing a dynamic pricing tariff pilot demonstration project for their residential customers.
VCE has found that the market value of Resource Adequacy (RA) load shift associated price for the PG&E service territory is $180/kW-yr14 during their agricultural pump program. Power data collected from the eight single-family homes indicates that 2 kW of load on average is available throughout the year to be controlled by a HEMS in single family homes. Assuming that 10 percent of all single-family homes in California implement a HEMS system and all controllable loads are shifted, then the average available load shift is approximately 1.6 GW for a RA cost savings of $281 million annually, based on 7.8 million single family homes15. An analysis of the summer power consumption in the 8 11 Goals such as those detailed in the 2022 Scoping Plan to Achieve Carbon Neutrality (updated and released in November 2022 as required by California AB 32).
12 https://valleycleanenergy.org/wp-content/uploads/Item-12-Amendment-to-2022-Budget-AgFIT-9-8-22.pdf 13 https://valleycleanenergy.org/programs/a-flexible-irrigation-pilot-program-for-agriculture/ 14 Current Market Price Benchmark established by the CPUC for RA costs in PG&E service territory 15 https://www.infoplease.com/us/census/california/housing-statistics 72
homes also indicates that 3 kW of load on average is available to be controlled by a HEMS in single family homes.
The benefit of implementing a dynamic pricing tariff and shifting load starts when electricity is purchased. The California Public Utility Commission requires utilities to ensure they will have enough capacity to serve their customers regardless of conditions. This is known as resource adequacy. In order to estimate their power requirements, CCA’s and IOU’s use a conservative forecast combined with a margin of safety16. Customer load shifts out of peak hours allow the CCA or IOU to purchase less reserve power thus saving money for their customers and the company.
Dynamic pricing allows load serving entities such as Community Choice Aggregators and investor-owned utilities to provide hourly market-based price signals to customers. The customers have the choice to respond to those prices and shift electricity usage into more favorable times of the day.
Prices are based on the wholesale generation and distribution prices established by the local ISO – CAISO in this case. The prices are a proxy for grid system conditions and are generally lower when more intermittent renewable resources are producing and higher during ramp and overnight hours when these resources are less available. By responding to these price signals the customer makes a rational economic decision which benefits the grid and reduces reliance on fossil fueled powerplants.
Access to this pricing information allows the customer to make more informed decisions about operational profiles based on their need and cost-effectiveness.
Approximately 3 Megawatts (MW) of load are currently enrolled in VCE’s AG-Fit pilot with participants shifting about 40 percent of their electricity usage out of summer peak periods (Figure C1)17. The current average system RA price for the PG&E service territory of $180/kw- yr., the avoided RA market value of 1 MW of load shift is approximately $180,000/yr18. The avoided net RA market value of load shift associated with the VCE AgFIT pilot is approximately $362,000/yr, assuming a 67% capacity factor is applied to the total 3MW of enrolled load (3MW x 0.67 x $180,000/MW-yr).
16 https://www.caiso.com/Documents/Resource-Adequacy-Fact-Sheet.pdf 17 https://www.wintersexpress.com/news/local/valley-clean-energy-receives-award-for-agfit-pilot-program/ article_c821c1b8-e988-566a-8ee8-09dced18d685.html. 18 Current Market Price Benchmark established by the CPUC for RA costs in PG&E service territory. 73
Figure B1. – VCE AgFIT Pilot – Mid-Term Report
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Appendix C: Load Limiting
Load limiting is a control approach where the total power consumed by the home is limited to a defined amount, for example 4000 Watts on-peak (5 PM to 8 PM). The homeowner could be nudged so that when they are close to or try to exceed the 4000 W limit, they are shown their current power draw (W) and the demand associated with their current request so that they can decide how best to proceed. For example, if a household is running its air conditioner and television, and then they try to start their clothes dryer, they must choose to eliminate concurrent use of one of the three appliances in order to meet the 4000 W cap. This type of nudging provides households with the information needed for prioritizing their appliance use and ensuring they do not exceed demand limits. SMUD has expressed interest in this type of feature, which could eliminate the need for expensive upgrades to the distribution network as well as customer’s electrical panel. Using SMUD’s motivation as a design constraint, the home could be limited to power draw of just less than that allowed by the home’s current electrical panel. If the electrical panel is rated at 120 Amps, for example, then a HEMS would limit the home’s total power consumption to 90 percent of that or 12,960 W.
SMUD has devised the Critical Peak Pricing (CPP) rate structure to increase the cost of electricity by 50 cents during specific CPP events. Events may be up to four hours long, and cumulatively occur up to 50 hours total during the year. SMUD has expressed how important it is to collect data from existing homes during the summer of 2025, with and without nudges, in order to educate the homeowner prior to CPP implementation in 2026. Seven of the eight existing SHFT homes have expressed interest in participating in the CPP rate structure.
In response to SMUD’s interest and the forthcoming deployment of RTP and CPP across California, CLTC recommends testing new device categories in its SHFT to determine cost effectiveness and acceptability. This information will be valuable to other organizations and governments preparing for RTP adoption in the future:
• Lights (nudge to dim) – Lighting accounts for up to 20 percent of the electrical load in homes based on the data from the phase 1 SHFT study. Lighting gets power from the same circuits at receptacles and fans so at a minimum, additional devices (like smart light switches) should be installed to determine their frequency of use and potential for shiftable. All eight homes are interested in nudging related to dimming the lights and three of the eight homes are interested in automated lighting controls. Smart switches allow for monitoring and controlling the lights on/off and dimming setpoints through an API. • Lights + TVs (nudge to dim) – Combining TV diming and lighting dimming could be a large reliable power reduction in homes. Seven of the eight homes are interested in nudging related to dimming their TVs.
• EV Charging (nudge to delay) – EV charging is a very high-power activity. Preventing any of this load from occurring during peak would be beneficial. Six of the eight homes are interested in nudging related to EV charging and two are interested in automated charging controls. Smart EV chargers or control switches allows for monitoring and controlling EV charging on/off operation through an API.
• TVs (Nudge to dim) – Entertainment accounts for up to 40 percent of the electrical load in homes based on the data from the SHFT field study. Smart TVs can be dimmed to save up to 70 Watts and every home has two TVs on average. One of the TVs is often being used. • Ceiling fans (fan speed & fan on/off control) – Ceiling fans are part of the same electrical 75
circuit as lighting which makes their operation times difficult to monitor. Additional devices (like smart light switches) should be installed to determine their frequency of use and potential for shiftable load. In addition to potential shiftable load, homeowners could be nudges about when to use their ceiling fan in combination with opening windows to improve air quality in the home. All eight homes are interested in nudging related to fan use for improving air quality and two of the eight homes are interested in automated control.
• Kitchen ventilation fans (fan speed & fan on/off) – Kitchen ventilation fans are generally found to be range hood fans used to exhaust smoke, steam and heat generated during cooking on the stove. Smart range hood fans can be controlled with on/off control and different speeds through an API. See the description for ceiling fans for recommended controls. • Bathroom/Laundry ventilation fans (fan speed & fan on/off) – Bathroom ventilation fans are similar to kitchen ventilation fans in that they steam and heat, but in this case the steam and heat is generated by hot water in showers. Smart light switches can be used for on/off control and different fan speeds through an API. See the description for ceiling fans for recommended controls.
• Windows (open/close) – Opening windows can be beneficial for pre-cooling a home and for improving air quality by bringing in fresh air or keeping the windows closed when outdoor air quality is poor. There are smart window actuators that can retrofit sliding windows in homes to automate window opening and closing. All eight homes are interested in nudging related to opening/closing windows to improve air quality in their homes and three of the eight homes are interested in automated
• Plugged in device (ideal use time of day & on/off) – Plugged in devices are part of the same electrical circuit as lighting and fans. Smart plug load controller enables on/off control of these plug loads at a low cost. Understanding the acceptance of nudges or automated control of these plugs could be a valuable way to shift load in homes. All eight homes are interested in nudging related to plug loads and one of the eight homes are interested in automated control. • Cooking range (nudge delay) – Cooking with an electric range is a very high-power activity. Preventing any of this load from occurring during peak would be beneficial.
Seven of the eight homes are interested in nudging related to cooking and two are interested in automated cooking load shift controls. Smart ranges or control switches allow for monitoring and controlling cooking on/off operation through an API. 76 77
78 79
March 17, 2025
Digitally signed by Denise Ehlen Date: 2025.04.02 18:52:51 -07'00' 80 Item 12
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 12
TO: Board of Directors
FROM: Mitch Sears, Chief Executive Officer
SUBJECT: Large Electric Load Customer Service Policy
DATE: October 14, 2025
RECOMMENDATION
Adopt Resolution establishing Large Electric Load Customer Service Policy.
BACKGROUND
Valley Clean Energy’s (VCE) mission is to provide clean electricity, product choice, and greenhouse gas emission reductions --- all with local control at lower prices. Given this mission, VCE desires to efficiently and effectively serve the power supply needs of all existing and new customer electric loads within Member service areas. Significant added load expansion/integration required by new and/or existing customers may necessitate non-standard tariff1 arrangements to clearly address and mitigate associated power supply costs, operational impacts and to specify other related power service provisions.
VCE’s existing Industrial and Agricultural customers comprise about 10-20% of VCE’s overall load and varies seasonally. VCE’s current total customer annual retail power sales are in the 700,000 MWh range or about 80 aMW2
. July is typically VCE’s peak service month with total energy loads near 125 aMW. Prospective new large load additions, especially from energy intensive establishments, could range 10-20 aMW on the lower end, to over 500 aMW or more at the higher end for data centers and the like. Such new loads could thus increase total VCE annual loads by about 20% at the lower range, to quintupling, or more, at the upper range. These potential incremental load additions could have significant impacts on VCE’s existing customer base, power generation/resource adequacy requirements and power system operations. 1 A CCA tariff is a rate structure or formula charged by a CCA for electricity generation services that recover the cost of electricity, fixed costs, and establishment of reserves. Tariffs are not just billing formats but are often used by Load Serving Entities like CCA’s and IOU’s as a tool to influence consumption behavior and operational decisions (e.g. Time of Use, Dynamic Rates, etc.). 2 An average megawatt (aMW) is calculated by taking total energy load during a given time period divided by the total hours during the same time period, and shows what the resultant energy load would have been if it were constant or “flat” during each hour of the given period. 81 Item 12
2 VCE’s proposed Large Electric Load (LEL) Customer Service Policy helps to provide staff with a framework and direction to evaluate and address impacts associated with large new load additions and, as warranted, to serve such loads pursuant to a negotiated Power Service Contract (PSC) between VCE and new LEL customers.
ANALYSIS & DISCUSSION
VCE currently has no established policy to evaluate and provide service to new large electric loads that may have significant cost/benefit and operational implications on VCE’s existing customer base and power resource portfolio. Further, LEL customers may have unique service needs that could require special contract terms and power procurement/hedging flexibility, or to integrate/manage customer provided generation. Moreover, VCE may need to devise special credit and or contract terms to mitigate impacts on existing customers and assure potential associated operational and financial risks have been addressed in a manner consistent with VCE Board approved policies and procedures, as well as review by VCE’s Energy Risk Oversight Committee (EROC).
To this end, staff have developed a draft Large Electric Load (LEL) Customer Service Policy for consideration by the Board which includes the following elements:
1. Defining a LEL based on energy load greater than 20,000 MWh or peak demand equal to or exceeding 2MW during any contiguous 12-month period.
2. LEL customers must notify VCE of intent to add/increase load prior to facilities construction or establishing LEL service.
3. Provisions to conduct a Business and Power Supply Impact Study (IS) to evaluate how new LEL customers may affect existing customers, power supply portfolio and composition, and identify and recommend any needed mitigation measures.
4. Determination to serve LEL under an existing tariff structure or by way of a negotiated PSC.
5. Requiring prospective LEL customers to provide periodic interconnection, load size, service start date, and related updates to VCE staff.
6. LEL sales are to recover the associated full and reasonable revenue requirement incurred by VCE to serve such LEL, including contributions to A&G overhead costs and financial operating reserves.
7. PSCs are to comply with applicable VCE Board approved policies and procedures.
8. VCE’s Chief Executive Officer, or his/her designee, shall have the authority to negotiate PSCs in consultation with General and or Special Counsel.
9. PSCs must be approved by the VCE Board of Directors.
Note, due to existing large load customers and pending/proposed large loads, several CCA’s in California have adopted similar LEL policies (e.g. Silicon Valley Clean Energy), which have been used to successfully provide electrical generation services to these types of customers. 82 Item 12
3 Power Sales Contract
A PSC is a key element in the proposed Policy and may be required to serve new LELs. PSC terms and conditions will likely vary based on load size and characteristics, together with provisions to address factors including interpretability, power supply renewable content, ability to forward hedge, supply price and load levels, self-provided generation (if any), contract duration, credit support, default provisions, and the like. PSC terms and conditions for a new 5 MW LEL, for example, would likely vary substantially from a new 100 or 500 MW LEL. Other PSC elements may address issues identified in any associated IS undertaken by VCE.
Key Topics/Issues
The following key topics have been identified by staff and the CAC over the course of developing the draft Policy. Each topic includes a brief staff response. The topics are listed in no particular order of emphasis.
1. LEL Size Impacts – the relative impacts associated with LEL size and why the proposed policy indicated a 2MW threshold.
• The 2 MW threshold is a place holder and could be adjusted; VCE’s largest current customers consume below the 2 MW level. The proposed Policy would allow staff to incorporate a new LEL via a standard tariff if special terms and conditions were not deemed applicable. Staff also indicated that new load impacts may be influenced by the size of new loads relative to existing total customer loads, and as new loads were to become a larger percentage of existing loads, impacts may vary accordingly.
2. LEL Load Characteristics – how load shape might impact VCE operations and economics. • LEL load shapes and load factors are important considerations and would be considered as part of an Impact Study. And if a PSC is utilized as enabled under the proposed Policy, specific terms and conditions would be included to address and acknowledge load shape and load factor impacts.
3. Cost of Serving LEL – how service cost might be established. • The proposed Policy provides for conducting an Impact Study to estimate LEL costs and impacts with a general rule of thumb of using the greater of marginal cost (MC) or average cost (AC) as a basis for service charges, as well as mitigating other potential concerns such as minimum energy deliveries, minimum contract term and appropriate credit support. LEL additions have the potential to increase or decrease average VCE costs.
4. Policy does not specify PSC development process - the proposed Policy does not specify particular PSC negotiation timelines or service terms.
• Due to the unknown nature of potential large loads, the proposed Policy leaves timelines and service terms to negotiation under a PSC. The proposed policy was primarily designed to: 1) optionally assess whether a PSC is needed; 2) investigate operational and economic impacts via an Impact Study (if warranted); and 3) utilize a 83 Item 12
4 PSC to specify service terms and conditions which both mitigate identified impacts and meet customer service needs. Each PSC would likely be unique and PSC development timelines could vary subject to size, impacts, credit support requirements, operational complexity and the like.
5. Impact on Resources Availability – if a new load were sufficiently large, it might impact overall regional power resource availability and cost.
• This would likely be a function of ultimate new load size, load shape/factor, whether the LEL unilaterally intended to self- provide all/some needed resources, and load interrupt ability to perhaps provide intermittent grid support. Staff also notes that any region-wide and/or grid level resource impacts would likely be similar regardless of whether load service is attained by either VCE or bundled service from the local IOU.
6. Connection Timelines – the likely determining factor of any new load addition would be connection time to attain physical grid access.
• Depending on the range and size of facilities needed (existing or to be constructed), such lead times could be months to years, especially if transmission line extensions and or new substations are required.
7. Administrative & General (A&G) Costs – A&G cost associated with new large loads. • These tend to be fixed overhead costs which generally do not vary appreciably with energy sales volumes. Dilution of A&G costs may occur with new load additions and thus benefit all retail customers. Note also that A&G is a very small component of overall VCE electric service costs which are primarily driven by power supply, resource adequacy mandates and regulatory compliance costs.
8. Impact on Financial Reserves - how VCE’s financial reserve levels might be affected by a new LEL.
• As retail loads and total operating costs increase, there is generally a proportional need to increase reserve balances. Increasing reserve amounts could be collected proportionately from all customers or perhaps be collected/assigned in some manner from/to the new LEL. Staff anticipates this issue would be an integral part of an Impact Study and then subsequently addressed in specific PSC terms and conditions. Noting that a new LEL customer may provide other operational attributes and or credit support mechanisms partially or fully offsetting reserve additions.
9. Are new loads “good” or “bad” – questions were raised at the CAC meetings about whether new loads would be beneficial to VCE.
• Staff responded that overall new customer reputation, load characteristics, financial solidity, and credit arrangements would combine with PSC contract terms to help mitigate any potential “bads” and enhance potential “goods.” Key PSC objectives would include addressing contract duration as well as what might happen if a new 84 Item 12
5 LEL were to terminate prematurely for some reason. Again, these issues should be identified and addressed in each specific PSC. In general, customers are both essential and beneficial contributors to business success in that they are the revenue source which fund all VCE costs.
10. Impact on VCE Portfolio – how VCE’s power portfolio goals might be impacted by a LEL. • There could be significant portfolio impacts. If, say, the new LEL wanted its supply based on meeting only minimum RPS requirements, for example, which could result in VCE becoming less “green.” Alternatively, if the new LEL desired to be, say, 100% renewable, VCE’s environmental impact could become more “green.” Portfolio composition would likely be addressed in an Impact Study and in the PSC.
11. Other Spinoff Impacts – many other factors could be affected by large load additions including traffic, local jobs, land and water use.
• Staff agrees there could be other local/regional issues. However, other agencies would be addressing these types of potential impacts and VCE expects to limit its approach to identifying and mitigating specific power supply related matters within the context of the PSC. Other local/regional issues should be addressed by the appropriate and responsible governmental and regulatory agencies.
12. Risk of Non-Performance - questions of added business risk associated with serving large new loads and what might result if a new large load were to terminate service prematurely or not otherwise fulfill its PSC obligations.
• Staff recognizes that this is a key issue and anticipates that identifying/addressing LEL risks would be one of the major topics of the Impact Study and the terms of a PSC. A PSC would include much more detailed language regarding the responsibilities and obligations of the parties versus alternatively utilizing some form of standard tariff service.
Staff notes that in addition to the general risks outlined above there can be significant benefits from adding new loads including: dilution of fixed cost to all customers; possible improvement of overall RPS portfolio; ability to reduce risk via added contract and resource diversity, and possible “green” programs expansion funded with commensurately higher revenue levels. Each new LEL likely has its internal goals and objectives, but the new customer might also be open to developing “model” energy production and use protocols benefiting all customers. Opportunities of this nature would be explored as part of an Impact Study and any subsequent PSC development.
COMMUNITY ADVISORY COMMITTEE (CAC) REVIEW
VCE staff and consultant reviewed VCE’s proposed LEL Policy with the CAC on August 28, 2025 and September 25, 2025. Staff discussed the potential usefulness of such Policy to provide flexibility and guidance when providing new service to large customers together with conducting an Impact Study, if deemed necessary, to outline potential large load service issues and mitigating measures which could be incorporated within a PSC. The general CAC discussion outlined potential benefits and burdens 85 Item 12
6 associated with large new loads. Many of the topics listed in the section above were identified and discussed during these two meetings. After considering staff analysis and Committee discussion, the CAC suggested that: 1) the proposed Policy indicate that any new LEL customer and/or PSC would need to comply with all applicable VCE Board-approved policies and procedures; and 2) the proposed Policy require the LEL customer to provide periodic interconnection construction/completion updates and projected service commencement and load size timelines to VCE. Both suggestions have been incorporated within the proposed Policy.
The CAC recommended the proposed Policy be considered for approval by the Board at the October 2025 Board meeting.
FISCAL IMPACT
There are no direct fiscal impacts. New large electric load fiscal impacts are to be evaluated and addressed on a case-by-case basis if/when such prospective customers notice intention of becoming a VCE LEL customer.
ATTACHMENTS
1. Large Electric Load Customer Service Policy
2. Resolution 2025-XXX adopting VCE’s Large Electric Load Customer Service Policy 86 Item 12
Draft 9-27-2025
VALLEY CLEAN ENERGY ALLIANCE
LARGE ELECTRIC LOAD CUSTOMER SERVICE POLICY
Valley Clean Energy Alliance’s (VCE) mission is to provide clean electricity, product choice, and greenhouse gas emission reductions --- all with local control at lower prices. VCE has adopted this Large Electric Load Customer Service Policy (Policy) to assure consistency with its mission while providing efficiency and value when offering retail power supply to Large Electric Load (LEL) Customers.
The purpose of this Policy is to provide guidance to LEL Customers regarding VCE electric service pursuant to defined commercial terms, and to provide transparent guidelines to VCE staff in evaluating and providing such service to existing and new LEL Customers. This Policy may be revised from time to time by the VCE Board.
LARGE ELECTRIC LOAD POLICY :
1) A LEL Customer is an existing or new customer that has historically, or is projected to consume and/or add greater than 20,000 MWh energy use or incur a 2 MW or greater peak demand during any contiguous 12-month period.
2) Prospective and existing LEL Customers are required to contact VCE’s business office at 1(855)699- 8232 prior to facilities construction for new load service and or increasing existing load service above the threshold levels described in Paragraph 1 above. 3) For LEL additions, VCE, at its sole discretion, may require a Business and Power Supply Impact Study (IS) to estimate reasonable costs and operational implications of serving such LEL, together with identifying associated administrative, economic, reliability and or regulatory compliance effects on VCE or VCE’s customer base, including, but not limited to, procurement composition requirements such as Renewables Portfolio Standards and Integrated Resource Planning processes. If an IS is conducted, VCE will manage or oversee such IS, the funding for which will be provided by VCE, the LEL entity, or some combination of both, to be outlined in a letter agreement between VCE and the LEL.
4) VCE shall analyze the feasibility and implications of new load service to the LEL and form of such service (e.g., whether the prospective LEL is to be served under an existing tariff arrangement or may require a separately negotiated Power Sales Contract (PSC) between VCE and the LEL entity). If a PSC is required, such PSC shall identify and formalize commercial terms of service including power supply charges, resource adequacy obligations, local and system capacity obligations, contract duration, credit provisions, current and future regulatory requirements and other factors pertinent to VCE and the LEL. Such PSC may include flexibility for the LEL to self-provide and or self-procure, all or a portion of its power supply requirements. 5) VCE shall require prospective LEL customers to provide periodic updates regarding applicable interconnection studies, interconnection facilities construction schedule(s), projected 87 Item 12
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interconnection facilities completion date(s), projected power service start date, projected initial and longer-term load phase-in schedule, and other information pertinent to establishing VCE power supply service to the LEL customer. VCE staff shall maintain a current file of all updates provided by each new LEL customer.
6) LEL PSCs are intended to recover reasonable costs incurred by VCE associated with serving such LEL including a reasonable contribution to VCE’s administrative and general costs and financial operating reserves, while complying with applicable law, VCE’s Implementation Plan, Board rates and rate adjustments, approved business, operating and risk management policies and the goals of controlling transaction costs and protecting VCE’s customers. 7) LEL PSCs are intended to identify and mitigate potential operational and cost risks to VCE, VCE’s existing customer base, and the LEL customer, in a manner consistent with VCE’s risk management policies and procedures. Each new PSC shall comply, as applicable, with all existing Board-approved VCE policies and procedures. Successful consummation of a PSC is a prerequisite for any LEL to obtain power supply services from VCE.
8) VCE’s Chief Executive Officer, or his/her designee, shall have the authority to negotiate PSCs in consultation with VCE’s General or Special Counsel, as applicable. VCE’s Enterprise Risk Oversight Committee (EROC) shall review and recommend approval of any PSC prior to consideration by the Board of Directors.
9) PSCs must be approved by the VCE Board of Directors. 88 Item 12
VALLEY CLEAN ENERGY ALLIANCE
RESOLUTION NO. 2025-___
RESOLUTION OF THE BOARD OF DIRECTORS OF VALLEY CLEAN
ENERGY ALLIANCE ADOPTING A LARGE ELECTRIC LOAD
CUSTOMER SERVICE POLICY
WHEREAS, Valley Clean Energy Alliance (“VCE”) was formed as a community choice aggregation agency (“CCA”) on November 16, 2016, under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Yolo, and the Cities of Davis and Woodland, to reduce greenhouse gas emissions, provide electricity, carry out programs to reduce energy consumption, develop local jobs in renewable energy, and promote energy security and rate stability in all of the member jurisdictions. The City of Winters, located in Yolo County, was added as a member of VCE and a party to the JPA in December of 2019; and
WHEREAS, commercial, agricultural and industrial customers comprise a significant share of VCE’s electric load; and
WHEREAS, existing VCE commercial, agricultural and industrial customers may from time to time consider significant expansion of electric power service; and WHEREAS, new commercial, agricultural and industrial customers may from time to time consider locating within VCE’s service area and thereby add significant power load to VCE’s existing electric service obligations; and
WHEREAS, VCE seeks to provide clean electricity and superior service that meet customer needs and expectations, at rates that are competitive and contribute positively to VCE’s financial position; and
WHEREAS, new large electric loads may impact existing customers and VCE business operations; and
WHEREAS, new large electric loads may have specific and or unique characteristics which may require special contract terms and conditions to be established and clarified for the benefit of existing customers, new large load customers and VCE; and WHEREAS, new large electric loads may require an impact study to assess potential impacts on VCE’s existing customers, resource portfolio and business operations to assess risks and recommend mitigation measures prior to commencing new electric service; and WHEREAS, VCE seeks to establish a Large Electric Load Customer Service Policy to establish guidelines and clarify that new large electric load service may require conducting an impact study, identifying reasonable mitigation measures, and other terms and considerations which may be memorialized in a negotiated Power Service Contract. 89 - 2 -
82499.04009\30842720.1
NOW, THEREFORE, the Board of Directors of Valley Clean Energy resolves as follows:
1. The Board hereby establishes VCE’s Large Electric Load Customer Service Policy which provides guidance to VCE staff and potential large electric load customers on the addition and integration of such loads within VCE’s retail power supply service, and which may be implemented utilizing a negotiated Power Sales Contract.
2. Any Power Sales Contract developed pursuant to this Policy must be approved by the Board of Directors prior to implementation.
PASSED, APPROVED AND ADOPTED, at a special meeting of Valley Clean Energy, held on the ______ day of _______________ 2025, by the following vote:
AYES:
NOES:
ABSENT:
ABSTAIN:
___________________________________
Bapu Vaitla, VCE Chair
__________________________________
Alisa M. Lembke, VCE Board Secretary
Attachment: Large Electric Load Customer Service Policy 90 Item 13
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 13
TO: Board of Directors
FROM: Mitch Sears, Chief Executive Officer
Edward Burnham, Chief Financial Officer
SUBJECT: VCE 2026-2029 Strategic Plan Major Update
DATE: October 14, 2025
RECOMMENDATION
Approve adoption of VCE’s 2026-2029 Strategic Plan Major Update
OVERVIEW
Valley Clean Energy (VCE) has undertaken a comprehensive and inclusive process to develop its 2026– 2029 Strategic Plan Major Update. This effort builds on the organization’s rolling strategic planning framework and reflects a commitment to aligning long-term goals with evolving community needs, regulatory landscapes, and energy market dynamics.
Key steps taken include:
• Strategic Planning Framework: VCE followed its Board-adopted Strategic Plan Guidelines, which emphasize a balanced, multi-year approach with annual reviews and periodic major updates. • Stakeholder Engagement: VCE formed a Strategic Plan Task Group within the Community Advisory Committee (CAC) and conducted two public workshops focused on financial strength, procurement, community engagement, and decarbonization. A customer survey was also distributed to over 45,000 contacts, gathering both quantitative and qualitative feedback. • Draft Development and Iteration: Staff developed an initial draft in early 2025, incorporating feedback from the CAC, public workshops, and survey results. Key themes included affordability, local distributed energy resources, and support for vulnerable customers. • Plan Refinement: Based on input, objectives were revised to emphasize cost-effective renewable energy strategies, rate competitiveness, and community resilience. Notably, Goal 2 was updated to reflect current renewable energy projections, project costs, and enable VCE to develop strategies for local distributed energy resources, as described under Objective 2.3. • Board and CAC Review: Draft versions were reviewed by the CAC in July and August 2025, with a final Board workshop in September 2025.
The purpose of this report is to provide an overview of the staff recommended 2026-2029 Strategic Plan Major Update for Board consideration.
91 Item 13
2 BACKGROUND
The purpose of the Strategic Plan (Plan) is to focus VCE on achieving better energy outcomes for its customers and communities by guiding the organization’s actions. The Strategic Plan is aligned with VCE’s mission and vision and guides the organization’s efforts over a multi-year time horizon. The Plan is the basis for developing annual organization goals, staff work plans, annual budgets, key decisions, and priorities. The Plan also informs the development of VCE’s compliance documents, including the Integrated Resource Plan (IRP), a document that sets out a 10-year roadmap for energy procurement that is typically updated on a 2-year basis.
Current Plan categories and key goals include:
Past Strategic Plan Actions
At the October 13, 2022, Board Meeting, Staff provided an update on the 2021-2023 Strategic Plan and introduced the concept of a rolling strategic plan. At the July 13, 2023, Board Meeting, the Board adopted the Strategic Plan Guidelines to ensure a balanced and comprehensive approach that aligns the strategic plan with VCE’s multi-year time horizon and achieves the benefits of timely updates associated with the “rolling” approach. At the September 14, 2023, Board Meeting, the Board approved a minor update to the 2021-2023 strategic plan and extended the plan through the end of 2025.
The Board staff reports can be found here:
Item 12 - VCE Three-Year Strategic Plan Guidelines (valleycleanenergy.org) Item 17 - VCE Strategic Plan Minor Update and Extension (valleycleanenergy.org) The Board received Item 17 describing the 2026-2029 VCE Strategic Plan major update process and timeline at the February 13, 2025 meeting.
2026-2029 Plan - Major Update
The purpose of a Major Plan update is to conduct a more detailed review/update of the Plan, including a review of VCE’s Vision/Mission and existing goals and objectives. Major Plan updates include •Goal: Maintain and grow a strong financial foundation and manage costs to achieve long-term organizational health. FINANCAL STRENGTH
•Goal: Manage power supply resources to consistently exceed California’s Renewable Portfolio Standard (RPS) while working toward a resource portfolio that is 100% carbon neutral by 2030.
PROCUREMENT AND POWER SUPPLY
•Goal: Prioritize VCE’s community benefits and increase customer satisfaction and retention. CUSTOMERS AND COMMUNITY
•Goal: Promote and deploy local decarbonization and grid innovation programs to improve grid stability, reliability, community energy resilience, and safety.
DECARBONIZATION AND GRID
INNOVATION
•Goal: Strongly advocate for public policies that support VCE’s Vision/Mission. STATEWIDE ISSUES: REGULATORY AND
LEGISLATIVE AFFAIRS
•Goal: Analyze and implement an optimal long-term organizational, management, and information technology structure at VCE.
ORGANIZATION, WORKPLACE, AND
TECHNOLOGY
92 Item 13
3 comprehensive reviews of the goals/objectives and incorporate workshops at various levels of the organization, including community stakeholder engagement. Major Plan updates incorporate those enumerated in the Minor Update that feature plan adjustments associated with changing legislative, regulatory, customer, economic, etc. requirements, as well as notation of plan milestones achieved.
Key activities in a Major Update include:
• Identify changes in the overall CCA environment (economics, policy, technology, etc.) and describe their relevance for VCE
• Review key organizational fundamentals (Mission, Vision, and Strategic Plan Goals) • Long-term adjustments based on strategic factors
As outlined in the strategic plan guidelines, Staff will continue to review and update the Plan on an annual basis to ensure that VCE remains on track and makes course corrections as necessary.
ANALYSIS
As part of the update process, the CAC formed the Strategic Plan Task Group to review and provide feedback. Over the course of developing the proposed 2026-2029 Strategic Plan Update, Staff incorporated comments and input from the Strategic Plan Task Group, CAC, workshop participants from the public, and results from customer surveys. The general themes and several specific points are outlined below. VCE held three workshops and a customer survey was conducted to support the development of the Major update. The initial two workshops were hosted by the CAC with the third hosted by the Board:
• May 22, 2025 Workshop – Focused on Goal 1: Financial Strength and Rates and Goal 2:
Procurement & Power Supply
• June 26, 2025 Workshop – Focused on Goal 3: Customers and Community and Goal 4:
Decarbonization and Grid Innovation
• September 25, 2025 – General workshop hosted by the VCE Board Workshop & Survey Feedback
Over the course of the two CAC hosted workshops comments and feedback from the CAC and a limited number of participants from the public were gathered. The Strategic Plan Survey was distributed via email to VCE’s customer list of 45,117 contacts and included a raffle for prizes from local vendors to encourage engagement. The survey was distributed on May 16, 2025, with a follow-up email sent to recipients who did not open the initial email on May 20, 2025. The survey aimed to gather input from VCE’s customers and stakeholders to help shape the direction for the 2025 Strategic Plan revisions.
The open rate (the percentage of recipients who opened the email) was almost 13%, which is on the low side of the industry average. The survey yielded a mix of feedback, with a large number of participants choosing to provide written comments that ranged from positive to negative. VCE asked survey participants what they think VCE’s Strategic Plan priorities should be, and participants ranked their top choices:
• #1 (46%): 100% clean or renewable electricity
• #2: (41%): Giving discounts to customers
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4 • #3: (39%): Customer-benefiting programs
• #4: (38%): Building financial reserves
Qualitative feedback was varied, but several themes emerged, including affordability/high rates; the need for more education so customers are familiar with VCE; and the desire for VCE to be municipalized in Yolo County.
Generally, these include added emphasis on:
• Affordability
• Energy resilience
• Incorporating additional local distributed energy resources into VCE’s resource mix • Affirming commitment and focus on low-income and other vulnerable customers.
Feedback Incorporation into the recommended 2026-2029 Strategic Plan Major Update The examples below and other sections of the draft Initial Plan Update have been modified to reflect the input and feedback received during the Workshops and the survey. • Affordability – An emphasis has been generally incorporated in the Goals and Objectives of the attached draft Update.
o e.g. Objective 1.4: Manage customer rates to optimize VCE’s financial goals while maintaining rate affordability and competitiveness with PG&E. • Grid Resiliency - Reinforcing local partnerships and efforts to support grid resiliency. o Objective 4.2: Work with member jurisdictions (e.g., city and school district planning staff) to help plan and implement local energy resilience, decarbonization and electrification initiatives and where practical, powered by local supply resources. • Emphasis on incorporating additional local distributed energy resources into VCE’s resource mix.
o e.g. Objective 2.3: Develop strategies to identify and pursue cost-effective, local distributed energy resources. Strategies could include, but are not limited to, an allocation of resource portfolio investment in cost-effective local energy and storage resources even though such local investment may affect achievement of overall resource portfolio goals.
• Re-emphasize commitment and focus on low-income and other vulnerable customers. o e.g Objective 3.5: Develop and implement customer programs and initiatives that prioritize decarbonization, community resiliency, rate affordability, and customer savings, including focused efforts on low-income and medically vulnerable customers.
At the August 28, 2025 CAC meeting, Staff presented the draft 2026-2029 strategic plan major update for their input and recommendation.
94 Item 13
5 Community Advisory Committee Recommendation
The CAC recommended approval of the 2026-2029 strategic plan update with no recommended changes.
Based on the final Board Workshop feedback, Staff have made additional minor updates to the recommended 2026-2029 Strategic Plan Major Update, including the following:
• Goal 2 was updated with additional resiliency language • Goal 6 updated for VCE growth, development, and effectiveness • Objective 6.3 updated to prioritize possible load growth and expansion • Addition of Appendix I for definitions of renewable and carbon fee electricity
CONCLUSION
Staff believe the recommended 2026-2029 Strategic Plan Major Update represents a balanced approach to moving the organization forward with setting reasonable goals for the near-term based on the input from VCE’s stakeholders. Staff seek approval of the attached 2026-2029 Strategic Plan Major Update.
ATTACHMENTS
1. 2026-2029 Strategic Plan Major Update – Clean
2. 2026-2029 Strategic Plan Major Update – Redlined
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Approved [Enter Date]
Valley Clean Energy
Strategic Plan
2026-2029 Major Update
Approved [Enter Date]
VCE MISSION
Deliver cost-competitive affordable clean electricity, product choice, price stability, energy efficiency, and greenhouse gas emission reductions.
VCE VISION
Valley Clean Energy Alliance (VCE) is a joint-powers authority working to implement a state- authorized Community Choice Energy (CCE) program. Participating VCE governmentsinclude the City of Davis, the City of Woodland, the City of Winters, and County of Yolo. The purpose of VCE is to enable the participating jurisdictions to determine the sources, modes of production and costs of the electricity they procure for the residential, commercial, governmental, agricultural and industrial users in the VCE territory. PG&E continues to deliver the electricity procured by VCE and performs billing, metering, and other electric distribution utility functions and services. Customers within the participating jurisdictions have the choice not to participate in the VCE program.
Near-Term Vision (Launch)
The near-term vision was essential for the launch of VCE to provide electricity users with greater choice over the sources and prices of the electricity they use, by:
• Offering basic electricity service with higher renewable electricity content, at a rate competitive with PG&E;
• Developing and offering additional low-carbon or local generation options at modest price differentials;
• Establishing an energy planning framework for developing local energy efficiency programs and local energy resources and infrastructure; and • Accomplishing the goals enumerated above while accumulating reserve funds for future VCE energy programs and mitigation of future energy costs and risks.
Long -Term Vision
The long-term vision for VCE is to continuously improve the electricity choices available to VCE customers, while expanding local energy-related economic opportunities, by:
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• Causing the deployment of new renewable and low carbon energy sources; • Evaluating and adopting best practices of the electricity service industry for planning and operational management;
• Substantially increasing the renewable electricity content of basic electricity service, with the ultimate goal of achieving zero carbon emissions electricity;
• Developing and managing customized programs for energy efficiency, on-site electricity production and storage;
• Accelerating deployment of local energy resources to increase localized investment, employment, innovation and resilience;
• Working to achieve the climate action goals of participating jurisdictions to shape a sustainable energy future;
• Saving money for ratepayers on their energy bills; and • Remaining open to the participation of additional jurisdictions.
STRATEGIC PLAN
The VCE Strategic Plan is focused on achieving better energy outcomes for its customers, communities and member jurisdictions by guiding the organization’s actions. The Plan and major update map a route to VCE’s goals and allow for course correction as new information and learning occurs. The energy sector in California is in a transformational period and VCE allows local energy priorities and needs to be heard and ultimately acted upon.
This plan helps VCE build a strong foundation from which to identify and guide strategic actions, being mindful of the longer-term aspirations of the Agency. The Plan is designed to be reviewed periodically to ensure that VCE remains on track and course corrects if necessary.
VCE’s major strategic plan update continues to focus on developing a cost-effective clean resource portfolio to combat the effects of climate change while balancing affordability. Since the initial strategic plan, VCE has grown its renewable power portfolio while recognizing that cost pressures – many of which are outside of VCE’s control – have increased the cost of electricity XX% over the last X years. During this time, VCE has actually lowered generation rates relative to the IOU, and this plan continues to put an emphasis on making affordability a priority in VCE’s decision-making. At the same time, the increasing severity of climate-related weather extremes and system disruptions has elevated concerns about energy resilience — ensuring continuous electric service especially for vulnerable customers during climate-driven utility grid outages.
METHODOLOGY AND ORGANIZATION
VCE’s initial strategic plan was based on the experience of the Agency’s first two years in operation as well as current energy market conditions. The original Plan incorporated a strengths/weaknesses/opportunities/threats (SWOT) analysis which was completed in 2019, and detailed feedback from the Board of Directors, Community Advisory Committee (CAC) members and VCE staff. This 2025 Plan update continues to cover six topical categories which are most relevant to VCE’s operations. Within each category, the Plan specifies a set of aspirational goals and follows with strategies to achieve or make progress toward those goals during the planning period of 2026- 2026. Subsequent, Strategic Plan major updates will occur every four years.
Strategic Plan Update Schedule
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Minor
Update
Major
Update
Minor
Update
Major
Update
Minor
Update
Major
Update
2021-2023 Plan Extension Strategic Plan Strategic Plan
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VCE’s STRATEGIC GOALS
A) FINANCIAL STRENGTH
A successful CCA program requires disciplined financial strategies and policies. VCE is committed to managing its financial resources responsibly and setting a standard of transparency and accountability, ensuring efficiency and strong stewardship of the agency’s financial resources. At VCE, our commitment to financial and operational excellence will ensure that all processes and operations are clearly defined and efficiently designed to align people, systems, and policies to maximize productivity and improve efficiency. Adhering to these policies and actively examining and assessing risk will help earn a high credit rating and a healthy position from which to deliver customer and community value.
Goal 1: Maintain and grow a strong financial foundation and manage costs to achieve long-term organizational health.
1.1. Objective: Develop a model to maintain reserve policies to fund VCE’s mission, vision, and goals.
1.2. Objective: Maintain investment-grade credit rating.
1.3. Objective: Commit to fiscal efficiencies to build a program foundation from which to deliver customer and community value.
1.4 Objective: Manage customer rates to optimize VCE’s financial goals while maintaining rate affordability and competitiveness with PG&E.
1.5 Objective: Develop a long range financial model for financial health and rate stability.
1.6 Objective: Develop a long term cash reserve and community investment strategy for reserve management.
B) PROCUREMENT AND POWER SUPPLY
Navigating the world of wholesale power markets and state-mandated power mix and reliability requirements while fulfilling our commitment to sourcing low/no-carbon electricity requires a constant search for the right resources to meet sustainability and value proposition goals. The threat of losing load, either to Direct Access or the investor-owned utility (IOU) presents challenges and opportunities to enhance product offerings to meet VCE’s decarbonization goals and our customers’ own environmental goals while considering financial and risk impacts. VCE is committed to providing carbon free electricity through a balanced approach that considers cost, risk, long-term value and best fit in meeting community goals while exceeding California’s RPS mandates. 98 4
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Goal 2: Manage power supply resources to consistently exceed California’s Renewable Portfolio Standard (RPS) while working toward a resilient resource portfolio that is 100% Carbon Free and a minimum of 90% Renewable by 2030.
2.1 Objective: Continue to identify and pursue cost effective local renewable energy and storage resources.
2.2 Objective: Through strategic procurement acquire sufficient clean energy and renewable resources including storage and other resource adequacy products to achieve VCE’s greenhouse gas reduction targets and regulatory requirements.
2.3 Develop strategies to identify and pursue cost-effective, local distributed energy resources. Strategies could include, but are not limited to, an allocation of resource portfolio investment in cost-effective local energy and storage resources even though such local investment may affect achievement of overall resource portfolio goals.
2.4 Evaluate and pursue opportunities for shared investment and procurement strategies with other CCAs.
2.6 Objective: Optimize the hedging strategy to mitigate risk in accordance with the energy risk guidelines and procurement plan.
C) CUSTOMERS AND COMMUNITY
VCE is a customer- and community-focused organization. We use all available channels and platforms to cultivate relationships with, and bring customer value to, all segments of the communities we serve – including those that have been historically underserved/under-resourced. These channels include leveraging existing outlets established by our member agencies, partnering with commercial customers to enhance their community presence, and re-engaging with those who have opted out. Partnerships with commercial and agricultural customers are particularly important to building VCE’s brand in a region rooted in food production and innovation. Focusing on affordability for customers wherever possible will help us to continue to build a loyal and satisfied customer base. Communicating our competitive rates and product and service benefits in clear and accessible ways will strengthen customer loyalty and enhance our financial standing, enabling us to better serve our communities.
Goal 3: Enhance and amplify VCE’s community benefits and increase customer satisfaction and retention.
3.1 Objective: Develop and implement engagement strategies to increase awareness of, and participation in, local control of VCE’s energy supply and programs with a particular focus on engaging disadvantaged and historically marginalized communities.
3.2 Objective: Develop and implement programs and initiatives to better support community goals, including supporting member agency achievement of energy-sector emissions reduction targets.
3.3 Objective: Design and implement a strategy to more effectively engage local business and agricultural customers.
3.4 Objective: Build awareness and trust of the VCE brand through direct engagement with customers, communities and organizations in VCE’s service territory.
3.5 Objective: Develop and implement customer programs and initiatives that prioritize decarbonization, community resiliency, energy efficiency, building weatherization, rate affordability, and customer savings, including focused efforts on low-income and medically vulnerable customers.
3.6 Objective: Measure and increase customer satisfaction, using tools such as surveys and focus groups, while maintaining an overall participation rate of no less than 90%.
3.7 Objective: Develop a roadmap to integrate and address the concerns and priorities of emerging and historically marginalized communities in the design and implementation of VCE's services and programs.
3.8 Objective: Consider affordability when making rates, services, and program design decisions. 99 5
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D) DECARBONIZATION AND ENERGY SERVICE RESILIENCE
One of the key factors driving the formation of VCE was to address climate change and improve local resiliency.
We will play a vital role in this decades-long endeavor, with the ongoing support of our community and our Board.
In addition to providing carbon-free electricity, we are reinvesting in our region and expanding our toolset for furthering emissions reductions and energy resiliency by launching decarbonization and grid innovation programs.
These programs represent the next stage in VCE’s maturity and are the mechanism by which VCE will further engage our communities to achieve our mission. We will leverage partnerships, prioritize innovation and use data science to manage and influence carbon-free energy use. We will embody the entrepreneurial and innovative spirit of the community in which we live and work, the spirit of Yolo County, to bend the carbon curve downwards and improve the lives of our community members while maintaining rate affordability.
Goal 4. Promote and deploy local decarbonization and energy resilience programs to improve grid stability, reliability, and safety.
4.1 Objective: Work with a variety of local, regional and state partners, to develop strategies and initiatives to pressure state policy makers to remove barriers to technical feasibility and economic viability of local renewable and storage resources, both FOM and BTM.
4.2 Objective: Work with member jurisdictions (e.g., city and school district planning staff) to help plan and implement local energy resilience, decarbonization and electrification initiatives and where practical, powered by local supply resources.
4.3 Objective: Increase participation in VCE’s UltraGreen 100% renewable product.
4.4. Objective: Identify external funding sources to support decarbonization, community energy resilience and grid-related programs and initiatives.
4.5 Objective: Identify and pursue cost effective, local distributed energy (e.g., behind the meter opportunities) resources to help meet reliability needs.
E) STATEWIDE ISSUES: REGULATORY AND LEGISLATIVE AFFAIRS The regulatory and legislative processes wield critical influence over VCE’s ability to serve our customers and fulfill our core goals and mission. Working with CalCCA and other operating CCAs, VCE will actively engage with the regulatory and legislative communities in order to advance a positive narrative on the value of CCA, manage operational risk, protect the interests of our customers, enhance our ability to mitigate greenhouse gas emissions, and help build a regulatory framework that supports innovation and customer choice in an equitable and cost-effective manner while preserving reliability and universal access.
Goal 5. Strongly advocate for public policies that support VCE’s Vision/Mission.
5.1 Objective: Work with CalCCA and other partners to proactively engage State regulators, legislators, and other State authorities in developing policy that furthers VCE’s mission and facilitates our contributions to decarbonization, grid reliability, energy resiliency, affordability, local programs and social equity.
5.2 Objective: Work with partners and policy makers at the local, regional and state levels to remove barriers to the technical feasibility and economic viability of local solar+storage and other renewable resources, for both in front of the meter and behind the meter installations.
5.3 Objective: Work with statewide allies to develop utility cost reduction solutions, including promotion of local energy resources to enhance climate resilience, reduce cost impacts of grid outages, and reduce needs for transmission investment.
5.4 Objective: Develop relationships with and provide energy education for community stakeholder organizations that foster support for VCE‘s mission and vision.
5.5 Objective: Optimize regulatory compliance activities. 100
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F) ORGANIZATIONAL GROWTH, DEVELOPMENT AND EFFECTIVENESS Human capital is a successful organization’s greatest asset, and at VCE we’ve built a highly talented and dedicated team that will ensure the success and effectiveness of our organization. Building, valuing, and nurturing this team’s talent will require an adaptive culture that supports creativity, open communication, and the free flow of ideas to spur mission-focused innovation. We will provide an infrastructure within VCE that supports and cultivates our employees through professional and personal development, recognizes and rewards their contributions to achieving our mission, and offers opportunities that position our people, as well as VCE, for success. In attracting and maintaining skilled employees, VCE will continue to provide a rewarding workplace experience.
VCE will develop a decision support system that will enable it to nimbly assess and react to potential load growth and expansion opportunities as they arise. In addition, VCE will assess opportunities for shared services with other CCAs to optimize function and efficiency of service.
We also take customer information, privacy, and security seriously. Our systems and processes follow best practices and industry standards. Performance metrics are in place to ensure resiliency and high system availability on standard and mobile platforms. Periodic upgrades to IT resources will ensure continued adherence to these high standards. This strategic plan provides the approach that VCE is taking to address the challenges of delivering IT services in a dynamic environment with new regulations and continuous advancements in science and technology.
Goal 6: Analyze and implement optimal long-term organizational growth, development, and the effectiveness VCE’s services for current and future customers.
6.1 Objective: Develop a roadmap using non-ratepayer funds to evaluate and guide future steps toward formation of a local Publicly Owned Utility (POU).
6.2 Objective: Evaluate and pursue opportunities for shared services with other CCAs for certain functions.
6.3 Objective: . Actively engage with potential growth opportunities and expansion members under the new member policy.
6.4 Objective: Identify optimal management, staffing and contracting structure of VCE in the near and long term; factors include balance of internal staff vs. consultant support services.
6.5 Objective: Promote diversity, equity and inclusion in leadership, hiring, promotion, and contracting policies.
6.6 Objective: Develop a performance reward system that promotes health, wellness, and a productive workplace.
6.7 Objective: Create an innovation-focused culture that rewards based on active participation, proactive problem solving, new customer-focused initiatives, and creative use of partnerships and member agencies.
6.8 Objective: Deploy a modernized Enterprise Resource Planning (ERP) approach that enables knowledge management, dashboard analytics, and collaboration through robust use of live data and information resources.
6.9 Objective: Develop a quality management system (QMS) to improve effectiveness and efficiency continuously to meet customer and regulatory requirements.
TIMING, MEASUREMENT AND UPDATES
VCE’s Strategic Plan is a living document that will be revisited and updated regularly. At a minimum, staff will review and update the Plan on an annual basis, including goals, objectives and metrics. In addition, staff will establish an implementation timeline and appropriate reporting format to use in reporting performance against the Plan’s goals and objectives to VCE leadership and Board. The reports, commencing in 2021, will show metrics, 101
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status and mitigations where appropriate. Consolidated summary reporting on the status of all high-priority enterprise goals and objectives will be reported out as follows:
• Quarterly Report to VCE Management
Staff will report quarterly to the Executive Officer on the status of goals, objectives and metrics for which they are responsible.
• Annual Report to Board and CAC
Staff will report annually to the Board and CAC on the status of goals, objectives and metrics, and will recommend any mitigations or amendments as may be necessary for Board approval. 102
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APPENDIX I
DEFINITIONS
Renewable Electricity
Includes “biomass, solar thermal, photovoltaic, wind, geothermal, fuel cells using renewable fuels, small hydroelectric generation of 30 megawatts or less, digester gas, municipal solid waste conversion, landfill gas, ocean wave, ocean thermal, or tidal current”, [(Public Resources Code § 25741), Renewables Portfolio Standard (RPS). (Public Utilities Code § 399.11 et seq.)] Renewable electricity is assumed to be free of GHG emissions.
Carbon Free Electricity -Any electricity that meets the definition of renewable electricity above plus other sources considered zero emission. These zero emission sources now in California include existing large hydro (greater than 30 MW) and existing nuclear. New technologies not now included in the zero-emission category can be added in the future. Carbon Free power uses no fossil fuel generation. See https://focus.senate.ca.gov/sb100/faqs for FAQs on existing large hydro and existing nuclear and their inclusion in SB 100. The percent of the power that must meet RPS is governed by SB 100 (De Leon, 2018) and shall be equal to or greater than 60% for 2030 and beyond.
By 2045 all electricity in California is to be Carbon Free. 103
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Valley Clean Energy
Strategic Plan
Last Approved update by VCE Board August 16,2023
2026-2029 Major Update (Staff Recommended Draft)
VCE MISSION
Deliver cost-competitive affordable clean electricity, product choice, price stability, energy efficiency, and greenhouse gas emission reductions.
VCE VISION
Valley Clean Energy Alliance (VCE) is a joint-powers authority working to implement a state- authorized Community Choice Energy (CCE) program. Participating VCE governmentsinclude the City of Davis, the City of Woodland, the City of Winters, and County of Yolo. The purpose of VCE is to enable the participating jurisdictions to determine the sources, modes of production and costs of the electricity they procure for the residential, commercial, governmental, agricultural and industrial users in the VCE territory. PG&E continues to deliver the electricity procured by VCE and performs billing, metering, and other electric distribution utility functions and services. Customers within the participating jurisdictions have the choice not to participate in the VCE program.
Near-Term1 Vision (Launch)
The near-term vision was essential for the launch of for VCE is to provide electricity users with greater choice over the sources and prices of the electricity they use, by:
• Offering basic electricity service with higher renewable electricity content, at a rate competitive with PG&E;
• Developing and offering additional low-carbon or local generation options at modest price differentials;
• Establishing an energy planning framework for developing local energy efficiency programs and local energy resources and infrastructure; and • Accomplishing the goals enumerated above while accumulating reserve funds for future VCE energy programs and mitigation of future energy costs and risks.
Long -Term Vision
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The future long-term vision for VCE is to continuously improve the electricity choices available to VCE customers, while expanding local energy-related economic opportunities, by:
• Causing the deployment of new renewable and low carbon energy sources; • Evaluating and adopting best practices of the electricity service industry for planning and operational management;
• Substantially increasing the renewable electricity content of basic electricity service, with the ultimate goal of achieving zero carbon emissions electricity;
• Developing and managing customized programs for energy efficiency, on-site electricity production and storage;
• Accelerating deployment of local energy resources to increase localized investment, employment, innovation and resilience;
• Working to achieve the climate action goals of participating jurisdictions to shape a sustainable energy future;
• Saving money for ratepayers on their energy bills; and • Remaining open to the participation of additional jurisdictions. 1 Launch Phase and First Year
STRATEGIC PLAN
The VCE Strategic Plan is focused on achieving better energy outcomes for its customers, and communities and member jurisdictions by guiding the organization’s actions. The Plan and majorminor update map a route to VCE’s goals and allows for course correction as new information and learning occurs. The energy sector in California is in a transformational period and VCE allows local energy priorities and needs to be heard and ultimately acted upon.
This plan helps VCE build a strong foundation from which to identify and guide strategic actions, being mindful of the longer-term aspirations of the Agency. The Plan is designed to be reviewed periodically to ensure that VCE remains on track and course corrects if necessary.
VCE’s major strategic plan update continues to focus on developing a cost-effective clean resource portfolio to combat the effects of climate change while balancing affordability. Since the initial strategic plan, VCE has grown its renewable power portfolio while recognizing that cost pressures – many of which are outside of VCE’s control – have increased the cost of electricity XX% over the last X years. During this time, VCE has actually lowered generation rates relative to the IOU, and this plan continues to put an emphasis on making affordability a priority in VCE’s decision-making. At the same time, the increasing severity of climate-related weather extremes and system disruptions has elevated concerns about energy resilience — ensuring continuous electric service especially for vulnerable customers during climate-driven utility grid outages. As VCE drafts this major strategic plan update, climate scientists are pointing to likely 3-degree C global warming, with severe impacts occurring more rapidly than was anticipated just a few years ago. At the same time, electricity customers in IOU service areas are experiencing an energy affordability crisis, driven mainly by escalating delivery charges. This plan therefore increases VCE’s emphasis on climate resilience (ensuring continuous electric service during heat extremes and utility grid outages) and affordability (engaging with our CCA allies to focus state policy makers on measures to reduce major cost drivers, rather than cutting needed services like low-income bill relief and energy efficiency).
METHODOLOGY AND ORGANIZATION
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VCE’s initial strategic plan was based on the experience of the Agency’s first two years in operation as well as current energy market conditions. The original Plan incorporated a strengths/weaknesses/opportunities/threats (SWOT) analysis which was completed in 2019, and detailed feedback from the Board of Directors, Community Advisory Committee (CAC) members and VCE staff. This 2025 Plan update continues to cover six topical categories which are most relevant to VCE’s operations. Within each category, the Plan specifies a set of aspirational goals and follows with strategies to achieve or make progress toward those goals during the planning period of 2026- 2026. Subsequent, Strategic Plan major updates will occur every four years.
Strategic Plan Update Schedule
VCE’s STRATEGIC GOALS
A) FINANCIAL STRENGTH
A successful CCA program requires disciplined financial strategies and policies. VCE is committed to managing its financial resources responsibly and setting a standard of transparency and accountability, ensuring efficiency and strong stewardship of the agency’s financial resources. At VCE, our commitment to financial and operational excellence will ensure that all processes and operations are clearly defined and efficiently designed to align people, systems, and policies to maximize productivity and improve efficiency. Adhering to these policies and actively examining and assessing risk will help earn a high credit rating and a healthy position from which to deliver customer and community value.
Goal 1: Maintain and grow a strong financial foundation and manage costs to achieve long-term organizational health.
1.1. Objective: Maintain consistently healthyDevelop a cash model to maintain reserves policies to fund VCE’s mission, vision, and goals.
1.2. Objective: Achieve an Maintain investment-grade credit rating by end of 2028.
1.3. Objective: Commit to fiscal efficiencies to build a program foundation from which to deliver customer and community value.
1.4 Objective: Manage customer rates to optimize VCE’s financial goals while maintaining rate affordability and competitiveness with PG&E andlowering customer costs .
1.5 Objective: Develop a long range financial model for financial health and rate stability.
1.6 Objective: Develop a long term cash reserve and community investment strategy for reserve management.
B) PROCUREMENT AND POWER SUPPLY
Navigating the world of wholesale power markets and state-mandated power mix and reliability requirements while fulfilling our commitment to sourcing low/no-carbon electricity requires a constant search for the right resources to meet sustainability and value proposition goals. The threat of losing load, either to Direct Access or the investor-owned utility (IOU) presents new challenges and opportunities to enhance product offerings to meet VCE’s decarbonization goals and our customers’ own environmental goals while considering financial and risk impacts. VCE is committed to providing carbon free electricity through a balanced approach that considers cost, risk, long-term value and best fit in meeting community goals while exceeding California’s RPS mandates. 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Minor
Update
Major
Update
Minor
Update
Major
Update
Minor
Update
Major
Update
2021-2023 Plan Extension Strategic Plan Strategic Plan
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Goal 2: Manage power supply resources to consistently exceed California’s Renewable Portfolio Standard (RPS) while working toward a resilient resource portfolio that is 100% Carbon Free and a minimum of 90% 100% Rrenewable by 2030.
2.1 Objective: Continue to identify and pursue cost effective local renewable energy and storage resources.
2.2 Objective: Through strategic procurement Aacquire sufficient carbon neutralclean energy and bundled energy and renewable resources including storage and other resource adequacy products to achieve VCE’s greenhouse gas reduction targets and regulatory requirements.
2.3 Objective: Deploy storage and other strategies to achieve renewable, carbon neutral, resource adequacy, and resiliency objectives.
2.3 Objective: Identify and pursue cost effective, local distributed energy (e.g., behind the meter rooftop solar+storage) resources to help meet reliability needs. Develop strategies to identify and pursue cost-effective, local distributed energy resources. Strategies could include, but are not limited to, an allocation of resource portfolio investment in cost-effective local energy and storage resources even though such local investment may affect achievement of overall resource portfolio goals. Identify and pursue cost-effective, local distributed energy resources, including both front-of-meter solar+storage resources for VCE’s renewable energy supply portfolio, as well as behind-the-meter solar+storage aggregations (VPPs) to help reduce RA requirements.
2.4 Evaluate and pursue opportunities for shared investment and procurement strategies with other CCAs.
2.2 Objective: Study and present options for achieving a 100% carbon neutral resource portfolio as well as 100% carbon free resource portfolio (carbon free hour by hour) by 2030.2[LK — Upon rereading, perhaps 2.5 is not needed (redundant) given the changes to the goal statement and the text of 2.3 and 2.4.]
2.5 Develop strategies to cost-effectively achieve the intent of the 100% renewable target while incorporating both utility-scale, front of meter, resources as well as behind the meter resourcesminimum
2.6 Objective: Optimize the hedging strategy to mitigate risk in accordance with the energy risk guidelines and procurement plan.
C) CUSTOMERS AND COMMUNITY
VCE is a customer- and community- focused organization. We will use all available channels and platforms to cultivate relationships with, and bring customer value to, all segments of the communities we serve – including those that have been historically underserved/under- resourced. These channels include leveraging existing outlets established by our member agencies, partnering with commercial customers to enhance their community presence, and re-engaging with those who have opted out. Partnerships with commercial and agricultural customers are particularly important to building VCE’s brand in a region rooted in food production and innovation. Focusing on affordability for customers wherever possible will help us to continue to build a loyal and satisfied customer base. Communicating our competitive rates and product and service benefits in clear and accessible ways will strengthen customer loyalty and enhance our financial standing, enabling us to better serve our communities while ensuring rate affordability.
Goal 3: Enhance and amplify Prioritize enhancing and marketing VCE’s community benefits, and increase customer satisfaction and retention.
3.1 Objective: Develop and implement engagement strategies to increase awareness of, and participation in, local control of VCE’s energy supply and programs with a particular focus on engaging disadvantaged and historically marginalized communities.
2 Carbon neutral electricity is net zero carbon electricity that may include the use of carbon credits and/or higher production of carbon free electricity that averages out to provide a carbon free portfolio over a period of time whereas carbon free hour-by-hour means all electricity consumed by VCE customers will be from carbon free and/or renewable resources. 107
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3.2 Objective: Develop and implement programs and initiatives to better support community goals, including supporting member agency achievement of energy-sector emissions reduction targets.
3.3 Objective: Design and implement a strategy to more effectively engage local business and agricultural customers.
3.4 Objective: Build awareness and trust of the VCE brand through direct engagement with customers, communities and organizations in VCE’s service territory.
3.5 Objective: Develop and implement customer programs and initiatives that prioritize decarbonization, community resiliency, energy efficiency, building weatherization, rate affordability, and customer savings, including focused efforts on low-income and medically vulnerable customers. .
3.6 Objective: Measure and increase customer satisfaction, using tools such as surveys and focus groups, while maintaining an overall participation rate of no less than 90%.
3.7 Objective: Develop a roadmap to integrate and address the concerns and priorities of emerging and historically marginalized communities in the design and implementation of VCE's services and programs.
3.63.8Objective: Consider affordability when making rates, services, and program design decisions.
3.7 Objective: Develop and implement customer programs and initiatives that prioritize decarbonization, community resiliency and customer savings.
3.8 Objective: Measure and increase customer satisfaction, using tools such as surveys and focus groups, while maintaining an overall participation rate of no less than 90%.
3.9 Objective: Integrate and address the concerns and priorities of emerging and historically marginalized communities in the design and implementation of VCE's services and programs.
D) DECARBONIZATION AND ENERGY SERVICE RESILIENCEGRID INNOVATION One of the key factors driving the formation of VCE was to address climate change and improve local resiliency.
We will play a vital role in this decades-long endeavor, with the ongoing support of our community and our Board.
In addition to providing carbon-free electricity, we are reinvesting in our region and expanding our toolset for furthering emissions reductions and energy resiliency by launching decarbonization and grid innovation programs.
These programs represent the next stage in VCE’s maturity and are the mechanism by which VCE will further engage our communities to achieve our mission. We will leverage partnerships, prioritize innovation and use data science to manage and influence carbon-free energy use. We will embody the entrepreneurial and innovative spirit of the community in which we live and work, the spirit of Yolo County, to bend the carbon curve downwards and improve the lives of our community members while maintaining rate affordability.
Goal 4. Promote and deploy local decarbonization and grid innovationenergy resilience programs to improve grid stability, reliability, community energy resilience, and safety.
4.1 Objective: Working with a variety of local, regional and state partners, to develop strategies and initiatives to pressure state policy makers to remove barriers to technical feasibility and economic viability of local renewable and storage resources, both FOM and BTM. Working with a variety of local, regional and state partners, to develop strategies and initiatives to pressure state policy makers to remove barriers to technical feasibility and economic viability of local solar+storage resources, both FOM and BTM. a grid innovation roadmap for VCE’s service territory that supports community energy resilience and reliability.
4.2 Objective: Work with member jurisdictions (e.g., city and school district planning staff) to help plan and implement local energy resilience, decarbonization and electrification initiatives and where practical, powered by local supply resources.Work with member jurisdictions (e.g., city and school district planning staff) to help plan and implement local energy resilience, decarbonization and electrification initiatives powered by local supply resources. Develop a VCE decarbonization roadmap to guide near and long-term program decisions and offerings.
4.3 Objective: Increase participation in VCE’s UltraGreen 100% renewable product. 108
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4.4. Objective: Identify external funding sources to support decarbonization, community energy resilience and grid-related programs and initiatives.
4.5 Objective: Identify and pursue cost effective, local distributed energy (e.g., behind the meter opportunities) resources to help meet reliability needs.
E) STATEWIDE ISSUES: REGULATORY AND LEGISLATIVE AFFAIRS The regulatory and legislative processes wield critical influence over VCE’s ability to serve our customers and fulfill our core goals and mission. Working with CalCCA and other operating CCAs, VCE will actively engage with the regulatory and legislative communities in order to advance a positive narrative on the value of CCA, manage operational risk, protect the interests of our customers, enhance our ability to mitigate greenhouse gas emissions, and help build a regulatory framework that supports innovation and customer choice in an equitable and cost-effective manner while preserving reliability and universal access.
Goal 5. Strongly advocate for public policies that support VCE’s Vision/Mission.
5.1 Work with a variety of local, regional and state partners, to develop strategies and initiatives to pressure state policy makers to remove barriers to technical feasibility and economic viability of local solar+storage resources, both FOM and BTM.
5.2 As state’s search for affordability solutions proceeds, work with statewide allies to oppose false solutions (e.g., cutting energy efficiency or low-income assistance) and promote the benefits of local energy resources, including climate resilience (reducing cost impacts of outages) and reducing transmission needs.
5.13 Objective: Work with CalCCA and other partners to proactively engage State regulators, legislators, and other State authorities in developing policy that furthers VCE’s mission and facilitates our contributions to decarbonization, grid reliability, energy resiliency, affordability, local programs and social equity.
5.21 Objective: Work with partners and policy makers at the a variety of local, regional and state levels partners, to develop strategies and initiatives to pressure state policy makers to remove barriers to the technical feasibility and economic viability of local solar+storage and other renewable resources, for both in front of the meter and behind the meter installationsFOM and BTM.
5.32 Objective: As state’s search for affordability solutions proceeds, Wwork with statewide allies to develop utility cost reduction rate affordability oppose false solutions, including promotion of local energy resources to enhance climate resilience, reduce cost impacts of grid outages, and reduce needs for transmission investment. (e.g., cutting energy efficiency or low-income assistance) that and promote the benefits of local energy resources, including climate resilience (reducing cost impacts of outages), while and reducing transmission needs.
5.42 Objective: Develop relationships with and provide energy education for community stakeholder organizations that foster support for VCE‘s mission and vision.
5.53 Objective: Optimize regulatory compliance activities.
F) ORGANIZATIONAL GROWTH, DEVELOPMENT AND EFFECTIVENESS, WORKPLACE, AND TECHNOLOGY Human capital is a successful organization’s greatest asset, and at VCE we’ve built a highly talented and dedicated team that will ensure the success and prosperity effectivenewss of our organization. Contracting with Sacramento Municipal Utility District (SMUD) to deliver high quality services and personnel support during launch and early operations has allowed VCE to realize these objectives from the outset. Over the period of this strategic plan, VCE will explore transition from a contract dependent organization to one that balances the values and efficiencies of development and retention of high-quality in-house staff supported by high-quality outside services. Building, valuing, and nurturing this team’s talent will require an start-up adaptive culture that supports creativity, open communication, and the free flow of ideas to spur mission-focused innovation. We will provide an infrastructure within VCE that supports and cultivates our employees through professional and personal development, 109
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recognizes and rewards their contributions to achieving our mission, and offers opportunities that position our people, as well as VCE, for success. In attracting and maintaining skilled employees, VCE will continue to provide a rewarding workplace experience.
VCE will develop a decision support system that will enable it to nimbly assess and react to potential load growth and expansion opportunities as they arise. In addition, VCE will assess opportunities for shared services with other CCAs to optimize function and efficiency of service.
We also take customer information, privacy, and security seriously. Our systems and processes follow best practices and industry standards. Performance metrics are in place to ensure resiliency and high system availability on standard and mobile platforms. Periodic upgrades to IT resources will ensure continued adherence to these high standards. This strategic plan provides the approach that VCE is taking to address the challenges of delivering IT services in a dynamic environment with new regulations and continuous advancements in science and technology.
Goal 6: Analyze and implement optimal long-term organizational, management growth, and development, and the effectiveness information technology structure at VCE’s services for current and future customers.
6.1 Objective: Develop a roadmap using non-ratepayer funds to evaluate and guide future steps toward formation of a local Publicly Owned Utility (POU).
6.2 Objective: Evaluate and pursue opportunities for shared services with other CCAs for certain functions.
6.3 Objective: Develop an evaluation framework to guide future expansion opportunities beyond the existing service territory. Actively engage with potential growth opportunities and expansion members under the new member policy.
6.4 Objective: Identify optimal management, staffing and contracting structure of VCE in the near and long term; factors include balance of internal staff vs. consultant support services, transition of leadership positions to permanent internal employees.
6.5 Objective: Promote diversity, equity and inclusion in leadership, hiring, promotion, and contracting policies.
6.6 Objective: Support Develop a performance reward system that promotes health, wellness, and a productive workplace.
6.7 Objective: Create an innovation-focused culture that rewards based on active proactive participation, proactive problem solving, new ideascustomer-focused initiatives, and creative use of partnerships and member agencies.
6.8 Objective: Deploy a modernized IT infrastructure Enterprise Resource Planning (ERP) approach that enables knowledge management, dashboard analytics, and collaboration through robust use of live data and information resources.
6.86.9 Objective: Develop a quality management system (QMS) to improve effectiveness and efficiency continuously to meet customer and regulatory requirements.
TIMING, MEASUREMENT AND UPDATES
VCE’s Strategic Plan is a living document that will be revisited and updated regularly. At a minimum, staff will review and update the Plan on an annual basis, including goals, objectives and metrics. In addition, staff will establish an implementation timeline and appropriate reporting format to use in reporting performance against the Plan’s goals and objectives to VCE leadership and Board. The reports, commencing in 2021, will show metrics, status and mitigations where appropriate. Consolidated summary reporting on the status of all high-priority enterprise goals and objectives will be reported out as follows:
• Quarterly Report to VCE Management
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Staff will report quarterly to the Executive Officer on the status of goals, objectives and metrics for which they are responsible.
• Annual Report to Board and CAC
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APPENDIX I
DEFINITIONS
Renewable Electricity
Includes “biomass, solar thermal, photovoltaic, wind, geothermal, fuel cells using renewable fuels, small hydroelectric generation of 30 megawatts or less, digester gas, municipal solid waste conversion, landfill gas, ocean wave, ocean thermal, or tidal current”, [(Public Resources Code § 25741), Renewables Portfolio Standard (RPS). (Public Utilities Code § 399.11 et seq.)] Renewable electricity is assumed to be free of GHG emissions.
Carbon Free Electricity -Any electricity that meets the definition of renewable electricity above plus other sources considered zero emission. These zero emission sources now in California include existing large hydro (greater than 30 MW) and existing nuclear. New technologies not now included in the zero-emission category can be added in the future. Carbon Free power uses no fossil fuel generation. See https://focus.senate.ca.gov/sb100/faqs for FAQs on existing large hydro and existing nuclear and their inclusion in SB 100. The percent of the power that must meet RPS is governed by SB 100 (De Leon, 2018) and shall be equal to or greater than 60% for 2030 and beyond.
By 2045 all electricity in California is to be Carbon Free. 112