VCE 7/13/23 Board Meeting Agenda Page 1 of 4
Meeting of the Valley Clean Energy Alliance
Board of Directors
Thursday, July 13, 2023 at 5:30 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.
Meetings are accessible to people 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, VCEA Board Clerk/Administrative Analyst, 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:
a. From a PC, Mac, iPad, iPhone, or Android device with high-speed internet. (If your device does not have audio, please also join by phone.) https://us02web.zoom.us/j/87375897379
Meeting ID: 873 75897379
b. By phone
One tap mobile:
+1-669-900-9128,, 87375897379# US
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1 VCE 7/13/23 Board Meeting Agenda Page 2 of 4
Dial:
+1-669-900-9128 US
+1-669-444-9171 US
Meeting ID: 873 7589 7379
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: Tom Stallard (Chair, City of Woodland), Gary Sandy (Vice Chair, Yolo County), Jesse Loren (City of Winters), Will Arnold (City of Davis), Mayra Vega (City of Woodland), Lucas Frerichs (Yolo County), Richard Casavecchia (City of Winters), Bapu Vaitla (City of Davis) Alternate Board Members: Angel Barajas (Yolo County), Tania Garcia-Cadena (City of Woodland), Albert Vallecillo (City of Winters), Donna Neville (City of Davis) 5:30 p.m. Call to Order
1. Welcome.
2. Recognition of Service to VCE:
a. Community Advisory Committee Members Gerry Braun, Christine Shewmaker, and Kristin Jacobs
b. Chad Rinde, past VCE Treasurer
3. 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
4. Approve June 15, 2023 Board Special meeting Minutes.
5. Receive 2023 Long Range Calendar.
6. Receive financial update May 31, 2023 (unaudited) financial statements.
7. Receive Legislative update provided by Pacific Policy Group.
8. Receive July 5, 2023 Regulatory update provided by Keyes & Fox.
9. Receive Community Advisory Committee June 22, 2023 meeting summary.
10. Receive quarterly Customer Participation update.
11. Approve submittal of an extension request for the SACOG Electrify Yolo Grant. (Action)
12. Consider adoption of Strategic Plan Guidelines for minor and major Plan updates. (Action)
2 VCE 7/13/23 Board Meeting Agenda Page 3 of 4
REGULAR AGENDA
13. Consider appointment to jurisdiction seat (city of Woodland) on Community Advisory Committee. (Action)
14. Consider modifying VCE’s procurement goal of 80% renewable power supply by 2030. (Discussion/Action)
15. Consider approval of allocation of 2022 net margin (Customer Dividend and Programs Allocation). (Discussion/Action)
16. Receive update on CalCCA “Best Practices”. (Information)
17. 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 VCEA 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.
18. Adjournment/Announcement: The Board will adjourn into Closed Session. The Board’s August 10, 2023 meeting has been cancelled. The Board’s next regular meeting is scheduled for Thursday, September 14, 2023 at 5:30 p.m. at the City of Woodland Council Chambers located at 300 First Street, Woodland, California 95695.
CLOSED SESSION
Public comment on the closed session item only will be read at this time.
19. Public Employee Performance Evaluation (§ 54957)
Agency-designated evaluators: Tom Stallard (VCE Board Member) and Lucas Frerichs (VCE Board Member)
Unrepresented Employee: Executive Officer
20. Conference with Labor Negotiators Pursuant to Government Code Section 54957.6 Agency-designated Negotiators: Tom Stallard (VCE Board Member) and Lucas Frerichs (VCE Board Member)
Unrepresented Employee: Executive Officer
- Report out from Closed Session.
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 3 VCE 7/13/23 Board Meeting Agenda Page 4 of 4
the e-mail and the Clerk will read the comment during the item. Items read cannot exceed 300 words or approximately two (2) minutes in length. 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/.
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].
4 Item 4
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 4
TO: Board of Directors
FROM: Alisa Lembke, Board Clerk / Administrative Analyst SUBJECT: Approval of Minutes from June 15, 2023 Special meeting DATE: July 13, 2023
RECOMMENDATION
Receive, review and approve the attached June 15, 2023 Special meeting Minutes.
5 VCEA Minutes June 15, 2023 Board Special Meeting Page 1 of 3
MINUTES OF THE VALLEY CLEAN ENERGY ALLIANCE
BOARD OF DIRECTORS SPECIAL MEETING
THURSDAY, JUNE 15, 2023
The Board of Directors of the Valley Clean Energy Alliance duly noticed their special meeting scheduled for Thursday, June 15, 2023 at 6:00 p.m., with a 5 p.m. 5-Year Anniversary reception open to the public, to be held at City of Davis Veterans Community Center, located at 203 East 14th Street, Davis, California 95616. VCE Director Jesse Loren established that there was a quorum present and began the meeting at 6:08 p.m.
Board Members Present: Jesse Loren, Will Arnold, Lucas Frerichs, Mayra Vega (departed at 6:46 p.m.), Richard Casavecchia, Bapu Vaitla, Angel Barajas (alternate Yolo County)
Members Absent: Tom Stallard, Gary Sandy
Public Comment
– General and
Consent
Director Loren opened the floor for public comment on both the agenda and Consent agenda items. Cathy Diepenbrock from Sacramento Municipal Unified District (SMUD) congratulated VCE for celebrating its 5- Year anniversary. There were no written public comments.
Approval of
Consent Agenda /
Resolution 2023-
007 and
Resolution 2023-
008
Motion made by Frerichs to approve the consent agenda items, seconded by Director Arnold. Motion passed with Tom Stallard and Gary Sandy absent. The following items were:
3. Approved April 13, 2023 Board meeting Minutes;
4. Received 2023 Long Range Calendar;
5. Received financial updates: A) January 31, 2023; B) February 28, 2023; C) March 31, 2023; and, D) April 30, 2023 (unaudited) financial statements.
6. Received Legislative update provided by Pacific Policy Group;
7. Received May 2023 Regulatory update dated June 7, 2023 provided by Keyes & Fox;
8. Received Community Advisory Committee April 27, 2023 meeting summary and copy of Task Group Charges: 1) Programs & Outreach and 2) Strategic Plan;
9. Received final Calendar Year 2022 Financial Audit Report;
10. Ratified VCE’s positions on legislative bills: A) AB 50 (Interconnection) - Support and B) AB 1373 (Central Procurement. Resource Adequacy) Oppose Unless Amended and Neutral (updated position).
6 VCEA Minutes June 15, 2023 Board Special Meeting Page 2 of 3
11. Approved Amendment #2 to contract with Polaris Inc. for implementation of the AgFIT (Flexible Irrigation Technology) dynamic pricing pilot program as Resolution 2023-007;
12. Approved contract with Yolo County for the Electrification Retrofit Rebate Outreach Program (ERR)) as Resolution 2023-008; and,
13. Approve Phase 1 extension of VCE’s Electric Vehicle Rebate Pilot Program and received input from CAC on Phase 2 program design elements.
Item 14: Consider
reappointment /
appointment(s)
to jurisdiction
seats on
Community
Advisory
Committee.
(Action)
VCE Executive Officer Mitch Sears introduced this item. Carl Linvill, applicant for CAC city of Davis seat, spoke and expressed his interested in being appointed to represent the city of Davis. There were no written public comments.
Directors Vaitla and Arnold recommended to the Board to appoint Carl Linvill to the vacant city of Davis jurisdiction seat. Directors Loren and Casavecchia recommended to the Board that Jennifer Rindahl be reappointed to the city of Winters seat.
Motion made by Director Vaitla to:
1. Reappoint Jennifer Rindahl to the city of Winters jurisdiction seat to the Community Advisory Committee (CAC) Member for a three (3) year term to expire 2026 (Class 2); and,
2. Appoint Carl Linvill to the vacant city of Davis jurisdiction seat for a three (3) year term to expire 2026 (Class 2).
This motion was seconded by Director Casavecchia.
Motion passed by the following vote:
AYES: Loren, Arnold, Frerichs, Vega, Casavecchia, Vaitla, Barajas (alt.) NOES: None
ABSENT: Stallard, Sandy
ABSTAIN: None
Motion made by Director Casavecchia to:
3. direct Staff to continue to solicit candidates for vacant city of Woodland and unincorporated Yolo County jurisdiction seats. This motion was seconded by Director Vega.
Motion passed by the following vote:
AYES: Loren, Arnold, Frerichs, Vega, Casavecchia, Vaitla, Barajas (alt.) NOES: None
ABSENT: Stallard, Sandy
ABSTAIN: None
7 VCEA Minutes June 15, 2023 Board Special Meeting Page 3 of 3 Item 15: Mid-Year
2023 Financial
update.
(Information)
VCE Staff Edward Burnham provided a mid-year 2023 financial update.
There were no questions by the Board. Mr. Sears explained a little more information about the power price and power purchase agreements on forecasting on slide 8.
There were no verbal or written public comments.
Item 16: Recap of
CalCCA May 2023
Annual
Conference.
(Information)
Mr. Sears provided a brief recap of the CalCCA 2023 Annual Conference held in San Diego which was attended by VCE Board Members, a CAC Member and Staff. Staff in attendance provided highlights of the Annual Conference. Directors Vega, Casavecchia, and Frerichs provided their comments about attending the conference.
(Mayra Vega departed at 6:46 p.m.)
There were no verbal or written public comments.
Item 17: Board
Member and
Staff
Announcements
Director Frerichs reported that he attended the CalCCA Annual Conference in San Diego, paid for with VCE monies.
Announcement
and Adjournment
Director Loren announced that the Board has scheduled their regular meeting for Thursday, July 13, 2023 at the City of Woodland Council Chambers, located at 300 First Street, Woodland, California 95695.
The meeting was adjourned at 6:48 p.m.
Alisa M. Lembke
VCEA Board Secretary
8 Item 5
VALLEY CLEAN ENERGY ALLIANCE
Staff Report - Item 5
____________________________________________________________________________________ TO: Board of Directors
FROM: Alisa Lembke, Board Clerk/Administrative Analyst
SUBJECT: Board and Community Advisory Committee 2023 Long-Range Calendar DATE: July 13, 2023
Recommendation
Receive and file the 2023 Board and Community Advisory Committee long-range calendar listing proposed meeting topics.
9 7/6/23
VALLEY CLEAN ENERGY
2023 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 12, 2023
Special Meeting
scheduled for
January 19, 2023
(3rd Thursday)
(REMOTE)
Board • Oaths of Office for Board Members (Annual - new Members only)
• Election of Officers for 2023 (Annual)
• Brown Act / AB 2449 – New Legislation on Teleconferencing Meetings
• 2022 Year End Review: Customer Care and Marketing
• Support Legislation to extend sunset (BioMAT program) • Long-term Power Portfolio Update
• Quarterly Customer Participation Update
• Action
• Nominations
• Discussion/Action
• Information
• Action
• Information
• Information
January 26, 2023
(REMOTE)
Advisory
Committee
• Legislative Summary/Update (Pacific Policy Group)
• 2023 Customer Rate update
• Forecasting Customer Ag Energy using hydrological conditions (research results) presentation
• Task Group Formation
• Quarterly Customer Participation Update
• Information
• Information
• Information
• Discussion/Action
• Information
February 9, 2023
(IN PERSON)
Board
(Davis)
• Legislative & Regulatory Updates
• Update on 2023 PCIA and Rates
• Update on SACOG Grant – Electrify Yolo
• Strategic Plan Update (Annual)
• Enterprise Risk Oversight Committee (EROC) proposed
modifications
• Information
• Information
• Information
• Information
• Discussion/Action
February 23, 2023
(Remote)
Advisory
Committee
• Strategic Plan update (Annual)
• Update on 2023 PCIA and Rates
• Information/Discussion
• Information
March 9, 2023
(IN PERSON)
Board
(Woodland)
• Meeting cancelled due to lack of agenda items.
10 March 23, 2023
(IN PERSON)
Advisory
Committee
(Woodland)
• Meeting cancelled due to lack of agenda items.
April 13, 2023 Board
(Davis)
• Update on SACOG Grant – Electrify Yolo
• Calendar Year 2023 Audited Financial Statements (James Marta & Co.)
• Receive Enterprise Risk Management Report (Bi-Annual
• SMUD: Amendment(s) to update Agreement
• Information
• Action
• Information
• Discussion/Action
April 27, 2023 Advisory
Committee
(Davis)
• Customer Participation Update
• EV Rebates Program
• Information
• Information/Discussion/Action
May 11, 2023 Board
(Woodland)
• Meeting cancelled.
May 25, 2023 Advisory
Committee
(Woodland)
• Meeting cancelled due to schedule conflict.
June 8, 2023 Meeting
Cancelled
5-Year Anniversary
Celebration and
Special Board
meeting:
June 15, 2023
Board
(Davis)
Veterans
Memorial
Center
• Re/Appointment of Members to Community Advisory
Committee (Annual)
• Customer Participation Update
• EV Rebates Program
• Mid-Year 2023 Financial Update
• VCE’s 5-Year Anniversary
• Action
• Information
• Discussion/Action
• Information
• Information
June 22, 2023 Advisory
Committee
(Davis)
• Customer Dividend and Programs Allocation
• Strategic Plan update (Guidelines)
• Power Procurement / Renewable Portfolio Standard Update • 80% Renewable by 2030 Policy. (placeholder)
• Discussion
• Discussion
• Information
• Discussion/Action
July 13, 2023 Board
(Woodland)
• Status of SACOG Grant – Electrify Yolo
• Customer Participation Update
• Customer Dividend and Programs Allocation
• Strategic Plan update (Guidelines)
• Power Portfolio Renewable Content (placeholder)
• 80% Renewable by 2030 Policy. (placeholder)
• Information/Discussion/Action
• Information
• Discussion/Action
• Discussion/Action
• Information/Discussion
• Discussion/Action
11 July 27, 2023 Advisory
Committee
(Woodland)
August 10, 2023 Board
(Davis)
August 24, 2023 Advisory
Committee
(Davis)
• Customer Participation Update
• Strategic Plan Draft
• Information
• Discussion/Action
September 14, 2023 Board
(Woodland)
• Certification of Standard and UltraGreen Products / 2022 Power Content Label (Annual)
• Strategic Plan Draft
• Action
• Discussion/Action
September 28, 2023 Advisory
Committee
(Woodland)
• Legislative End of Session update
• Update on 3-Year Programs Plan and 2024 program concepts • Information
• Discussion/Action
October 12, 2023 Board
(Davis)
• Update on SACOG Grant – Electrify Yolo
• Update on 2024 draft Operating Budget
• Customer Participation Update
• Strategic Plan final Draft
• Update on Programs Plan and 2024 program concepts
• Status of SACOG Grant – Electrify Yolo
• Legislative End of Session update
• Information
• Information
• Information
• Information/Discussion
• Discussion/Action
• Information/Discussion
• Information
October 26, 2023 Advisory
Committee
(Davis)
• Update on Power Content Label Customer Mailer
• Customer Participation Update
• Review CAC Task Group Year-end Reports
• Draft 2024 Legislative Platform
• Review CAC Charge (placeholder)
• Information
• Information
• Discussion
• Discussion/Action
• Discussion/Action
November 9, 2023 Board
(Woodland)
• Power Procurement / Renewable Portfolio Standard Update • 2024 Operating Budget Update
• 2024 Legislative Platform
• Information
• Information/Discussion
• Discussion/Action
12 November 23, 2023
November 16, 2023
(rescheduled to
November 16th due to
the Thanksgiving
holiday on Nov. 23rd.)
Advisory
Committee
(Woodland)
• GHG Free Attributes • Information
December 14, 2023 Board
(Davis)
• Approve 2024 Operating Budget (Annual) and 2024 Customer Rates
• GHG Free Attributes
• Receive CAC Year-end Task Group Reports
• Election of Officers for 2024 (Annual)
• Discussion/Action
• Action
• Discussion
• Nominations
December 28, 2023
(rescheduled to
December 21, 2023)
Advisory
Committee
(Davis)
• 2024 CAC Task Group(s) formation (Annual)
• Election of Officers for 2024 (Annual)
• Discussion/Action
• Nominations
January 11, 2024 Board
(Woodland)
• Oaths of Office for Board Members (Annual - new Members only)
• Election of Officers for 2024 (Annual)
• 2023 Year End Review: Customer Care and Marketing
• Action
• Nominations
• Information
January 25, 2024 Advisory
Committee
(Woodland)
• Legislative Summary/Update (Pacific Policy Group) • Information Notes: 1. CalCCA Annual Meeting held on May 17 - 19, 2023 (San Diego).
CAC PROPOSED FUTURE TOPICS
Topics and Discussion dates may change as needed
ESTIMATED MEETING DATE(S)
Improving Resiliency during Power Outages Possibly August 2023 for “kick off” meeting Strategic Plan (Annual Report) to Board and CAC February 2024 Self Generation Incentive Program (SGIP)
Agri-voltaics (for information only)
Net Energy Metering (NEM) 3.0 (Information/Discussion/Action - As needed) Legislative Items (as needed)
Strategic Plan additional updates (as needed)
SACOG Update (as needed)
13 Item 6
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 6
______________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Executive Director
Edward Burnham, Finance and Operations Director
SUBJECT: Financial Update – May 31, 2023 (unaudited) financial statements (with comparative year to date information) and Actual vs. Budget year to date ending May 31, 2023
DATE: July 15, 2023
RECOMMENDATION:
Accept the following Financial Statements (unaudited) for the period of May 1, 2023 to May 31, 2023 (with comparative year to date information) and Actual vs. Budget year to date ending May 31, 2023.
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 May 31, 2023.
Financial Statements for the period May 1, 2023 – May 31, 2023 In the Statement of Net Position, VCE, as of May 31, 2023, has a total of $4,759,144 in its checking, money market and lockbox accounts, $1,100,000 restricted assets for the Debt Service Reserve account, $1,800,000 restricted assets related to supplier deposits, and $3,428,260 restricted assets for the Power Purchases Reserve account. VCE has incurred obligations from Member agencies and owes as of May 31, 2023 a total of $7,385. VCE member obligations are incurred monthly due to staffing, accounting, and legal services.
14 Item 6
The term loan with River City Bank includes a current portion of $312,007 and long-term portion of 181,284. On May 31, 2022, VCE’s net position is $15,295,724.
In the Statement of Revenues, Expenditures, and Changes in Net Position, VCE recorded $ 6,839,195 of revenue (net of allowance for doubtful accounts), of which $6,666,069 was billed in May, and $5,076,213 represent estimated unbilled revenue. The cost of electricity for the May revenue totaled $5,454,972.
For May, VCE’s gross margin was approximate 20% and net income totaled $607,584. The year-to-date change in net position was $493,218.
In the Statement of Cash Flows, VCE cash flows from operations were $974,249 due to May cash receipts of revenues being more than the monthly cash operating expenses.
Actual vs. Budget Variances for the year to date ending May 31, 2023 Below are the financial statement line items with variances >$50,000 and 5% • Electric Revenue – ($4,828,307) and -13% – Unfavorable variance revenue model error on the timing of rate change isolated to January-2023 and retail load variance lower than forecasted due to mild winter and spring. • Purchased Power – ($2,243,400) and -8% – Unfavorable variance due to gas prices driving short-term power market increases.
• Wholesale Energy Services – ($358,667) and 129% unfavorable variance related to the transition of services to TEA starting in Q123 budgeted for Q223.
• Credit Support Services (SMUD) – $65,529 and 30% favorable variance related to lower retail load than forecasted due to mild winter and summer.
• Operational Support Services (SMUD) – ($97,557) and 368% unfavorable variance related to Percentage of Income Payment Plan (PIPP) program implementation, bill presentment, and base green rate implementation. • Strategic Plan Implementation – $60,270 or 100% favorable variance due to timing difference. • Contingency – ($100,00) and (100%) – favorable variance to budget is due to not having a need yet to utilize the contingency funds set aside in the budget.
Attachments:
1) Financial Statements (Unaudited) May 1, 2023 to May 31, 2023 (with comparative year to date information.)
2) Actual vs. Budget for the year to date ending May 31, 2023 15 VALLEY CLEAN ENERGY ALLIANCE
FINANCIAL STATEMENTS
(UNAUDITED)
FOR THE PERIOD OF MAY 1 TO MAY 31, 2023
PREPARED ON JULY 7, 2023
16 2
ASSETS
Current assets:
Cash in Yolo County Treasury
Cash and cash equivalents $ 4,759,144
Accounts receivable, net of allowance 9,609,435
Accrued revenue 5,076,213
Prepaid expenses 32,705
Other current assets and deposits 2,227,703
Total current assets 21,705,200
Restricted assets:
Debt service reserve fund 1,100,000
Power purchase reserve fund 3,428,260
Total restricted assets 4,528,260
Noncurrent assets:
Total noncurrent assets -
TOTAL ASSETS $ 26,233,460
LIABILITIES
Current liabilities:
Accounts payable $ 504,328
Accrued payroll 102,538
Interest payable 1,516
Due to member agencies 7,385
Accrued cost of electricity 6,325,427
Other accrued liabilities 1,079,330
Security deposits - energy supplies 1,800,000
User taxes and energy surcharges 16,337
Limited Term Loan 312,007
Total current liabilities 10,148,868
Noncurrent liabilities
Term Loan- RCB 181,284
Total noncurrent liabilities 181,284
TOTAL LIABILITIES $ 10,330,152
NET POSITION
Net position:
Local Programs Reserve 224,500
Restricted 4,528,260
Unrestricted 11,150,548
TOTAL NET POSITION $ 15,903,308
(UNAUDITED)
VALLEY CLEAN ENERGY ALLIANCE
STATEMENT OF NET POSITION
MAY 31, 2023
17 3
FOR THE PERIOD
ENDING
MAY 31, 2023 YEAR TO DATE
OPERATING REVENUE
Electricity sales, net $ 6,839,195 $ 32,039,693
Other revenue 3,375 $ 627,844
TOTAL OPERATING REVENUES 6,842,570 $ 32,667,537
OPERATING EXPENSES
Cost of electricity 5,454,972 $ 28,938,400
Contract services 200,703 $ 1,641,485
Staff compensation 126,864 $ 639,799
General, administration, and other 471,873 $ 1,027,481
TOTAL OPERATING EXPENSES 6,254,412 $ 32,247,165
TOTAL OPERATING INCOME (LOSS) 588,158 $ 420,372
NONOPERATING REVENUES (EXPENSES)
Interest income 20,942 $ 81,037
Interest and related expenses (1,516) $ (8,635)
TOTAL NONOPERATING REVENUES (EXPENSES) 19,426 $ 72,402
CHANGE IN NET POSITION 607,584 $ 492,774
Net position at beginning of period 15,295,724 $ 15,410,534 Net position at end of period $ 15,903,308 $ 15,903,308 (UNAUDITED)
CHANGES IN NET POSITION
FOR THE PERIOD OF MAY 1, 2023 TO MAY 31, 2023
(WITH COMPARATIVE YEAR TO DATE INFORMATION)
VALLEY CLEAN ENERGY ALLIANCE
STATEMENT OF REVENUES, EXPENDITURES AND
18 4
FOR THE
PERIOD ENDING
MAY 31, 2023 YEAR TO DATE
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from electricity sales $ 6,148,720 $ 31,409,297 Payments received from other revenue sources 3,375 627,844 Payments to purchase electricity (4,238,750) (27,221,998) Payments for contract services, general, and adminstration (1,250,231) (2,727,265) Payments for staff compensation (116,569) (653,546)
Net cash provided (used) by operating activities 974,249 (365,668)
CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES
Principal payments of Debt (44,067) (37,677)
Interest and related expenses (1,599) (9,367)
Net cash provided (used) by non-capital financing activities (45,666) (47,044)
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 20,942 81,037
Net cash provided (used) by investing activities 20,942 81,037 NET CHANGE IN CASH AND CASH EQUIVALENTS 949,525 1,627,521 Cash and cash equivalents at beginning of period 8,337,879 40,660,016 Cash and cash equivalents at end of period $ 9,287,404 $ 42,287,537 Cash and cash equivalents included in:
Cash and cash equivalents 4,759,144 21,055,445
Restricted assets 4,528,260 21,232,092
Cash and cash equivalents at end of period $ 9,287,404 $ 42,287,537 (WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
FOR THE PERIOD OF MAY 1 TO MAY 31, 2023
19 5
FOR THE
PERIOD ENDING
MAY 31, 2023 YEAR TO DATE
Operating Income (Loss) $ 588,158 $ 420,372
(Increase) decrease in net accounts receivable 134,644.40 1,047,949 (Increase) decrease in accrued revenue (787,303) (1,645,816) (Increase) decrease in prepaid expenses 15,342 (32,705) Increase (decrease) in accounts payable (157,833) 104,799 Increase (decrease) in accrued payroll 10,295 (13,747)
Increase (decrease) in due to member agencies 651 (199,059) Increase (decrease) in accrued cost of electricity 1,216,222 1,716,402 Increase (decrease) in other accrued liabilities (435,815) 68,666 Increase (decrease) in user taxes and energy surcharges (37,816) (32,529) Net cash provided (used) by operating activities $ 974,249 $ 1,593,528 FOR THE PERIOD OF MAY 1 TO MAY 31, 2023
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
RECONCILIATION OF OPERATING INCOME TO NET CASH
PROVIDED (USED) BY OPERATING ACTIVITIES
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
20 VALLEY CLEAN ENERGY
2023 YTD ACTUAL VS. BUDGET
FOR THE YEAR TO DATE ENDING 05/31/23
Description YTD
Actuals
YTD
Budget
YTD
Variance
%
over/-under
Electric Revenue $ 32,039,693 $ 36,868,000 $ (4,828,307) -13% Other Revenues - Programs $ 627,844 $ 275,000 $ 352,844 128% Interest Revenues $ 81,037 $ 17,500 $ 63,537 363%
Purchased Power $ 28,938,400 $ 26,695,000 $ 2,243,400 8% Purchased Power Base $ 28,938,400 $ 25,423,000 $ 3,515,400 14% Purchased Power Contingency 2% $ - $ 1,272,000 $ (1,272,000) -100% Labor & Benefits $ 625,094 $ 601,000 $ 24,094 4%
Salaries & Wages/Benefits $ 499,444 $ 500,000 $ (556) 0% Contract Labor (SMUD Staff Aug) $ - $ 12,500 $ (12,500) -100% Human Resources & Payroll $ 125,650 $ 88,500 $ 37,150 42% Office Supplies & Other Expenses $ 125,998 $ 86,000 $ 39,998 47% Technology Costs $ 15,440 $ 15,500 $ (60) 0%
Office Supplies $ 6,131 $ 1,000 $ 5,131 513%
Travel $ 8,083 $ 2,500 $ 5,583 223%
CalCCA Dues $ 53,760 $ 55,500 $ (1,740) -3%
CC Power $ 41,029 $ 10,500 $ 30,529 291%
Memberships $ 1,555 $ 1,000 $ 555 56%
Contractual Services $ 1,549,000 $ 1,272,500 $ 276,500 22% Other Contract Services $ - $ 11,000 $ (11,000) -100%
Don Dame $ 1,897 $ 4,500 $ (2,603) -58%
SMUD - Credit Support $ 150,071 $ 215,600 $ (65,529) -30% SMUD - Wholesale Energy Services $ 777,567 $ 418,900 $ 358,667 86% SMUD - Call Center $ 343,619 $ 346,000 $ (2,381) -1%
SMUD - Operating Services $ 124,057 $ 26,500 $ 97,557 368% Commercial Legal Support $ 8,100 $ 12,500 $ (4,400) -35% Legal General Counsel $ 18,112 $ 68,000 $ (49,888) -73% Regulatory Counsel $ 46,653 $ 87,500 $ (40,848) -47%
Joint CCA Regulatory counsel $ 7,525 $ 14,000 $ (6,475) -46% Legislative - (Lobbyist) $ 27,500 $ 27,500 $ - 0%
Accounting Services $ 7,939 $ 12,000 $ (4,061) -34%
Financial Consultant $ - $ 17,500 $ (17,500) -100%
Audit Fees $ 35,960 $ 11,000 $ 24,960 227%
Marketing $ 129,960 $ 110,000 $ 19,960 18%
Marketing Collateral $ 125,281 $ 105,000 $ 20,281 19%
Community Engagement Activities & Sponsorships $ 5,000 4,679 $ (321) $ -6% Programs $ 688,523 $ 347,500 $ 341,023 98%
Program Costs $ - $ - $ - 100%
Programs - EV $ 62,123 $ 63,000 $ (877) -1%
Programs - AgFIT $ 617,428 $ 275,000 $ 342,428 125%
Programs - Heat Pump $ 8,972 $ 9,500 $ (528) -6%
Rents & Leases $ 4,938 $ 11,000 $ (6,062) -55%
Hunt Boyer Mansion $ 4,938 $ 11,000 $ (6,062) -55%
Other A&G $ 184,680 $ 262,650 $ (77,970) -30%
Development - New Members $ - $ 10,500 $ (10,500) -100% Strategic Plan Implementation $ (270) $ 60,000 $ (60,270) -100% PG&E Data Fees $ 87,507 $ 115,000 $ (27,493) -24%
Insurance $ 14,700 $ 4,750 $ 9,950 209%
Banking Fees $ 82,743 $ 72,400 $ 10,343 14%
Miscellaneous Operating Expenses $ 127 $ 3,000 $ (2,873) -96% Contingency $ - $ 100,000 $ (100,000) -100%
TOTAL OPERATING EXPENSES 32,246,720 $ 29,488,650 $ 2,758,070 $ 9% Interest on RCB loan $ 8,635 $ 9,400 $ (765) -8%
Interest Expense - Bridge Loan $ - $ 15,000 $ (15,000) -100% NET INCOME 493,218 $ 7,647,450 $ (7,507,076) $ -98%
21 Item 7
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 7
To: Board of Directors
From: Mark Fenstermaker, Pacific Policy Group
Subject: Legislative Update – Pacific Policy Group
Date: July 15, 2023
______________________________________________________________________________ Staff, VCE’s lobby services consultant at Pacific Policy Group, and the Community Advisory Committee’s Legislative - Regulatory Task Group continue to meet and discuss legislative matters. Below is a summary of recent activities in the California Legislature and Administration.
July is the month that those working in Sacramento collectively catch a breath as the Legislature recesses for four weeks. The Legislature adjourns for Summer Recess on July 14, which is also the deadline for bills to pass policy committees in the second house, reconvenes on August 14. The legislative session will then sprint through five final weeks until the Legislature adjourns on September 14 for the Interim Recess.
It has certainly been an eventful last few weeks and a break from the chaos is needed, as budget negotiations took most of the air out of the room in June and into July. The Legislature and Governor Newsome finalized negotiations to cover the state’s $31.5 billion deficit without tapping into any of the state’s reserves, but the Governor’s Infrastructure Trailer Bill Package created most of the excitement. This package included reforms to CEQA to expedite certain infrastructure projects, including transmission projects which prompted CalCCA to support the proposal. The main sticking point in the proposal was whether or not to include the Delta Conveyance Project; ultimately it was kept out. On the dollar side of the budget, it appears that the funding proposed early in the session that could fund an expansion of AgFIT did not make the final deal, but staff and Pacific Policy Group are digging into that further and thinking through alternative strategies.
Closer to VCE’s priorities, the energy trailer bill that would authorize DWR to take on central procurement, amongst other proposals, has stalled for the time being. VCE, other CCAs, and CalCCA consistently advocated for fixes to the proposed trailer bill to ensure that CCAs’ ability to procure resources was not harmed. Senator Dodd played an important role in this advocacy and VCE has appreciated his representation. The central procurement policy could still be moved this year, either in yet another budget trailer bill, or in AB 1373 (Garcia). CCAs, including VCE, continue to advocate for amendments in AB 1373, further clarifying the authorization of central procurement for the Investor-Owned Utilities. AB 1373 is an urgency measure and thus does not need to follow the legislative deadlines that other bills must meet. Thus, it does not 22 Item 7
2 have to be passed by the Senate Energy, Utilities, and Communications Committee by the July 14 deadline and could be moved any time before session ends. As an urgency measure it requires a two-thirds vote and would go into effect immediately upon the Governor’s signature.
VCE staff, the LRTG and PPG are currently engaged in the following bills:
1. AB 1373 (Garcia) – Central Procurement
Summary: This bill would establish the Department of Water Resources (DWR) as the Central Procurement Entity (CPE) for the state. Further, the bill requires the PUC, by September 1, 2024, and biennially thereafter, to determine if there is a need for the procurement of additional offshore wind and geothermal energy resources and would authorize the PUC to then request DWR to centrally procure offshore wind and geothermal energy. In addition, this bill would require that the portfolio of resources required by the PUC for LSEs to procure ensures a reliable electricity supply that also provides optimal integration of resource diversity in a cost-effective manner, as specified.
AB 1373 in its previous form represented the Governor’s energy trailer bill proposal that presented significant challenges for CCAs, mainly 1. a CPE that could procure any resource and could also be an IOU; 2. authorized PUC to enforce an LSE’s integrated resource plan (IRP); and
3. assess an additional penalty on an LSE that fails to achieve its RA target without exemption.
AB 1373 was amended based on input from CCAs to define DWR as the CPE and limit the CPE to only procure offshore wind and geothermal resources, limits the PUC’s authority related to LSE procurement based on its IRP, and aligning potential RA penalties with capacity payments into the Strategic Reliability Reserve. While these amendments do not alleviate all of the concerns raised by CCAs they substantially move the bill in the right direction.
CalCCA has engaged in negotiations with the author’s office, as well as with the Governor’s Office and Senate budget leadership as it relates to the Governor’s trailer bill, and discussions are ongoing.
CalCCA took an oppose unless amended position, as did VCE and other CCAs, and VCE staff and board members met with Assemblymember Aguiar-Curry’s chief of staff and contacted Senator Dodd to push for CCA amendments.
Taking a neutral position on AB 1373 seems the most prudent tactic at this time.
Additional Information
• Next Hearing: The bill will be heard next in Senate Energy, Utilities & Communications. • VCE has taken a Neutral position
• Bill language: AB 1373
2. AB 50 (Wood) – Customer Energization
Summary: This bill would require the CPUC to determine what timely service means for IOUs to energize customers by Jan. 1, 2025. Previously, the bill stated that until the CPUC determines what timely service means, AB 50 would set a deadline of 90 days of delivering power to new connections and 30 days to upgrade existing connections. The bill was amended and replaced 23 Item 7
3 this language with a new provision that replaces the interim timelines for IOUs with an interim performance metric requirement for underperforming IOUs. The bill also promotes more efficient distribution planning by requiring large electric corporations to evaluate and update as necessary their distribution processes and meet regularly with county government staff to discuss the status of electrical capacity. Lastly, the bill requires IOUs to report on capacity constraints.
The issue of interconnection and energization have been a hot topic in the Legislature this year.
Interconnection is the process of the utility connecting new generation into the transmission and distribution system while energization is the process of the utility connecting a new or upgraded home or business to the grid so that it can receive electricity. There have been numerous stories of IOU delay for both interconnection and energization, mostly in the PG&E service territory. VCE’s service territory has experienced its share of energization delays, most notably the carpet recycling business that waited two years to be energized by PG&E.
AB 50 is authored by Asm. Wood of the North Coast, one of the most prominent instances of delayed energization came out of Humboldt County as PG&E informed the county it would not connect any new projects in the southern part of the county. Both Senator Dodd and Asm.
Aguiar-Curry are co-authors of the measure.
Supporting AB 50 is consistent with Provision 2b of the VCE Legislative Platform to support legislation that reforms the utility regulatory and business model so that IOUs deliver greater benefits to ratepayers, and increase safety and reliability.
Additional Information
• Next Hearing: The bill will be heard next in Senate Appropriations • VCE has taken a Support position.
• Bill language: AB 50
24 Item 8
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 8
To: Board of Directors
From: Keyes & Fox, Regulatory Consultant
Subject: Regulatory Monitoring Report – Keyes & Fox
Date: July 13, 2023
______________________________________________________________________________ Please find attached Keyes & Fox’s June 2023 Regulatory Memorandum dated July 5, 2023 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 July 5, 2023. 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
Tim Lindl, Partner, Keyes & Fox LLP
Jason Hoyle, Principal Analyst, EQ Research, LLC
Subject: Monthly Regulatory Update
Date: July 5, 2023
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.
RA Rulemaking (2023-2024)
Background: This proceeding considers resource adequacy (RA) requirements for LSEs and introduced the Central Procurement Entity (CPE) to ensure grid reliability and sufficient capacity. The proceeding is divided into an implementation track and a reform track.
Recent Developments: On June 7, the CAISO sent a letter advising the CPUC that it will release Reliability Demand Response Resources (RDRR) resource bids into the market for economic dispatch sooner in order to help avoid or mitigate grid emergencies, and that it will begin operationalizing this process upon approval of the now-approved (not yet issued) May 25 Proposed Decision. This action coupled with the establishment of a proxy demand response bid cap of $500/MWh is expected to increase the amount of demand response bidding into the CAISO market and provide additional resources for LSEs to draw upon meet their RA requirements. At its June 29 meeting, the CPUC approved a Revised Proposed Decision adopting Local Capacity Requirements for 2024 – 2026 and Flexible Capacity Requirements for 2024, refining the Resource Adequacy program scoped as Phase 3 of the Implementation Track, and closing the proceeding. The Decision includes a new requirement that a CCA that has had system RA deficiencies within the prior two calendar years must first be in RA compliance for two calendar years prior to submitting an implementation plan to expand the CCA’s territory.
Analysis: The revisions to the initial Proposed Decision provided that the application of RA deficiencies to the two-year expansion pause will begin with the 2024 year-ahead RA filing due on October 31, 2023, and the September 2023 month-ahead RA filing, and added exceptions for technical or procedural defects and deficiencies less than 1% of the LSE’s requirements. The Decision did not incorporate VCE’s comments suggesting an exception from the two-year expansion pause where the RA deficiency was beyond the commercially reasonable control of the LSE. Also, the Decision eliminates the need for the monthly incremental local and flexible true-up process, ultimately streamlining and simplifying the RA forecasting process for LSEs such as VCE.
Next Steps: The Decision closed the proceeding. The next RA docket is expected to be opened within the next few months.
Additional Information: Revised Proposed Decision (June 27, 2023); D.23-04-010 on Reform Track Phase 2 (Apr. 7, 2023); D.22-12-028 (Dec. 19, 2022); Amended Scoping Memo and Ruling (Sep. 2, 2022); Docket No. R.21-10-002.
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 territory). Phase 1 of this proceeding will address 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 will build on the 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 June 9, the CPUC accepted PG&E’s AL 6939-E on CCA Financial Security Requirements (FSR) in accordance with D.18-05-022. On June 19, the Assigned Commissioner issued an Amended Scoping Ruling and Memo clarifying that no evidentiary hearing is needed for Phase 1 of this proceeding and granting the Joint Parties’ request to file briefs.
Analysis: The January 6 Staff Proposal included topics such as financial monitoring of CCAs, cost recovery associated with customers returning to POLR service, and the Load-Serving Entity deregistration process related to procurement 26 2
requirements. These topics present potential financial review and monitoring standards for VCE as well as potential new costs related to providing POLR financial security. The FSR method used in AL 6939-E will be replaced with the new approach being developed in this proceeding. Based on the Joint Case Management Statement, there is broad support for modifying the CCA FSR and Re-Entry Fees to: use the Resource Adequacy Market Price Benchmark (MPB) as proposed by the IOUs and CalCCA, use the IOU system average generation rates for residential and non-residential customers in FSR calculations as proposed by the IOUs and CalCCA, and to account for a potential mass involuntary return to POLR via CCA customers' CAM and DR RA allocations as proposed by CalCCA. Regarding the Staff Proposal, there is broad opposition to nearly all the continuity of service approaches, but support (with modifications indicated) among parties for adoption of the financial monitoring and trigger metrics in the Staff Proposal.
Next Steps: Opening briefs are due July 10, and reply briefs are due July 31. A proposed decision on FSR calculations is expected in October 2023.
Additional Information: Amended Scoping Ruling and Memo (June 19, 2023); Joint Case Management Statement – Appendix (May 26, 2023); PG&E AL 6939-E (May 10, 2023); ALJ email Ruling (Mar. 17, 2023); ALJ Ruling and Staff Proposal (Jan. 6, 2023); Scoping Memo and Ruling (Sep. 16, 2021); OIR (Mar. 25, 2021); Docket No. R.21-03-011.
RPS Rulemaking
Background: This proceeding addresses ongoing Renewables Portfolio Standard (RPS) requirements, aspects of the new Voluntary Allocation/Market Offer (VAMO) process, and other tariffs for the purchase of renewable energy.
Recent Developments: On June 12, the ALJ issued a Ruling regarding the motions for leave to file the confidential version of Final 2022 RPS Procurement Plans under seal and for approval of redactions applied to public versions. In the Ruling, 21 retail sellers’ motions for leave to file confidential material under seal were at least partly denied. VCE was one of 10 retail sellers whose motions to file under seal complied with the confidentiality requirements and were granted without modification.
Analysis: The ACR on 2023 RPS Procurement Plans provides guidance for the content of Retail Sellers’ Draft 2023 RPS Plans but made no significant changes to VCE’s obligations. The ACR did include a new section for transmission reporting that applies to electric companies that own transmission assets.
Next Steps: Draft 2023 RPS Procurement Plans are due July 17, and a motion to update draft plans is due August 15. A Decision approving Final 2022 RPS Procurement Plans and a Ruling on 2023 RPS Procurement plans is expected soon.
Additional Information: Ruling (June 12, 2023); Assigned Commissioner's Ruling (May 5, 2023); VCE’s Amended Final 2022 RPS Procurement Plan (May 2, 2023); D.22-11-021 (Nov. 18, 2022); Scoping Memo (Apr. 6, 2022); Docket No.
R.18-07-003.
PG&E 2023 Phase 1 GRC
Background: Phase 1 General Rate Case (GRC) proceedings set PG&E’s revenue requirement, including functionalizing costs into categories such as electric distribution or generation, and impact the costs recovered through rates from customers (e.g., bundled, unbundled, or both) for a set period (in this case, 2023-2026). Phase 2 GRC proceedings determine cost allocation among customer classes (e.g., Residential, Agricultural) and rate design issues. The proceeding is divided into two tracks. Track 1 addresses most matters, including PG&E’s requested revenue requirement together with safety and environmental and social justice issues. Track 2 addresses the narrower matters of the reasonableness of the 2019-2021 actual costs recorded in the named memorandum accounts and balancing accounts and, to the extent relevant, safety and environmental and social justice.
Recent Developments: On June 23, PG&E submitted AL 6968-E updating its electric rates, effective July 1. If this Advice Letter is approved, PG&E’s revenue requirement will increase by a total of $1,209 million, or 7.5%, and its rate for CCAs will increase by $0.015/kWh, or 10.4%.
Analysis: N/A.
Next Steps: In Track 1, a proposed decision is expected in Q2 2023. The Track 2 schedule is currently held in abeyance per an email ruling issued December 13.
Additional Information: PG&E AL 6968-E (June 23, 2023); D.23-01-005 (Appendix 1 - Settlement Agreement) (Jan. 17, 2023); PG&E’s Amended Application (Mar. 10, 2022); PG&E Affordability Metrics Report (Feb. 23, 2022); PG&E Application (Jun. 30, 2021); Docket No. A.21-06-021.
PG&E 2024 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 nonbypassable 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.
27 3
Recent Developments: On June 16, CalCCA filed a Protest of PG&E 2024 ERRA Forecast Application.
Analysis: PG&E’s preliminary ERRA forecast indicates the possibility of a decrease in the PCIA rates (or an increase in the PCIA credit) paid by CCA customers across most vintages in 2024, but that forecast is expected to change significantly by the Fall Update (including likely increases to forecasted PCIA rates), based primarily on changes to brown power prices.
Next Steps: A scoping memo and procedural schedule are expected to be issued within the next few months.
Additional Information: CalCCA Protest (June 16, 2023); PG&E 2024 ERRA Forecast Application (May 15, 2023); Docket No. A.23-05-012.
PG&E 2019 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. Phase 1 of the proceeding was resolved with issuance of D.21-07-013. Phase 2 is ongoing and is addressing issues related to the 2019 Public Safety Power Shutoff (PSPS) events.
Recent Developments: On July 3, the CPUC issued D.23-06-054 which address the first scoped issue, the methodology for calculation of a utility’s unrealized volumetric sales and unrealized revenues resulting from Public Safety Power Shutoff (PSPS) events, and closes the proceeding without addressing the second scoped issue of whether it is appropriate for the utilities to return the revenue requirement calculated by the adopted methodology for the PSPS events that occurred in 2019 on the basis of the Commission’s decision in the PSPS OII proceeding establishes that there can be no recovery of the revenue requirement equal to the unrealized volumetric sales and unrealized revenue resulting from the 2019 PSPS events since that remedy is reserved for PSPS events occurring after the date of the PSPS OSII decision.
Analysis: The costs of unrealized revenue resulting from PSPS events in 2019 will be allocated to ratepayers rather than utility shareholders. However, with this matter resolved, the long-delayed 2020, 2021, and 2022 ERRA Compliance proceedings may now move forward.
Next Steps: The proceeding is closed.
Additional Information: D.23-06-054 (July 3, 2023); D.23-03-017 extending statutory deadline (Mar. 21, 2023); Proposed Decision (Dec. 19, 2022); D.22-07-009 extending statutory deadline (Jul. 18, 2022); Ruling amending schedule (Apr. 6, 2022); Joint Case Management Statement (Feb. 25, 2022); D.21-07-013 resolving Phase 1 (Jul. 16, 2021); PG&E’s Application and Testimony (Feb. 28, 2020); Docket No. A.20-02-009.
PG&E 2020 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. Phase 1 of this proceeding concluded in April 2022 with issuance of D.22-04-041 approving a settlement agreement. Phase 2 issues related to unrealized sales and revenues resulting from PG&E’s Public Safety Power Shutoff (PSPS) events in 2020 are under consideration.
Recent Developments: No recent developments in the past month.
Analysis: N/A
Next Steps: Phase 2 is expected to begin soon since the Commission recently resolved issues related to the establishment of a common accounting methodology for PSPS events in Phase 2 of the 2019 ERRA Compliance proceeding (see above).
Additional Information: D.22-08-009 extending statutory deadline (Aug. 11, 2022); Scoping Memo and Ruling (Jun. 21, 2021); Application (Mar, 1, 2021); Docket No. A.21-03-008.
PG&E 2021 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: No recent developments in the past month.
Analysis: N/A
Next Steps: The target date for a Proposed Decision is Q3 2023.
Additional Information: ALJ Ruling on schedule (Jan. 6, 2023); Assigned Commissioner’s Scoping Memo and Ruling (Aug. 9, 2022); PG&E 2021 ERRA Compliance Application (Feb. 28, 2022); Docket No. A.22-02-015. 28 4
PG&E 2022 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: No recent developments in the past month.
Analysis: N/A
Next Steps: Intervenor testimony is due September 22, and settlement discussions are scheduled for November.
Additional Information: Scoping Memo and Ruling (Jun. 2, 2023); PG&E 2022 ERRA Compliance Application and Notice of Availability (Feb. 28, 2023); Docket No. A.23-02-018.
PCIA Rulemaking
Background: The Power Charge Indifference Adjustment (PCIA) is a nonbypassable charge levied on electric bills of customers who have departed from IOU service, such as CCA customers, to compensate IOUs for resources procured on behalf of former customers prior to their departure. The new Voluntary Allocation/Market Offer process was authorized in D.21-05-030. Phase 2 issues related to PCIA data access and voluntary allocations in market-price benchmark (MPB) calculations were resolved in D.22-07-008. Currently, the proceeding is evaluating the calculation of the MPB charges.
Recent Developments: On June 13, the CPUC issued D.23-06-006 modifying the calculation of the PCIA by (a) establishing a new MPB and an allocation mechanism to address the “greenhouse gas-free” incremental value of large hydroelectric energy resources above fossil fuel resources, and (b) revising the calculation of the Energy Index MPB to improve accuracy and transparency. The Decision also closed the proceeding.
Analysis: The Decision adds some additional value to greenhouse gas-free resources and enhances the MPB calculations without fundamentally modifying the MPB mechanism.
Next Steps: The proceeding is closed.
Additional Information: D.23-06-006 (June 13, 2023); ALJ Ruling (Mar. 3, 2023); D.22-01-023 on Phase 2 (Jan. 27, 2021); D.18-09-013 Track 1 Decision approving PG&E Settlement Agreement (Sep. 20, 2018); Docket No. R.17-06- 026.
Transportation Electrification
Background: This rulemaking implements transportation electrification (TE) programs, tariffs, and policies. D.22-11-040 established a $1 billion rebate program for behind-the-meter EV charging equipment, focused on medium-duty/heavy-duty vehicles and disadvantaged communities and a $25 million pilot program for innovative, equity-focused TE programs administered by CCAs and community-based organizations.
Recent Developments: On June 7, SCE filed a Motion for Clarification of D.22-11-040 and D.22-08-024 regarding whether procured electric vehicle supply equipment (EVSE) must comply with the ISO 151118 communication standard for all transportation electrification programs or if the requirement only applies to future programs.
Analysis: N/A
Next Steps: Under D.22-11-040, the program administrator contract must be filed by September 30, 2023.
Additional Information: SCE’s Motion for Clarification (June 7, 2023); SCE’s Petition for Modification (May 25, 2023); VCE’s Annual Vehicle-Grid Integration Report (Mar. 15, 2023); D.22-11-040 (Nov. 21, 2022); Ruling entering Staff Proposal on Transportation Electrification Framework to record (Feb. 25, 2022); Docket No. R.18-12-006.
Demand Flexibility
Background: This rulemaking was opened to update the CPUC’s rate design principles and guidance for advancing demand flexibility, and the proceeding may also modify, consolidate, or eliminate existing dynamic rate pilots. VCE is a party to this proceeding as its scope relates to the AgFIT Pilot. Phase 1-Track A will establish an income-graduated fixed charge 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 will consider expansion of the AgFIT Pilot.
Recent Developments: On June 19, the ALJ issued a Ruling requesting comments on the implementation pathway for income-graduated fixed charges (IGFCs). The ALJ plans to issue a proposed decision in Q1 2024 to establish a pathway for implementing IGFCs over several years to allow the Commission to gain experience from the first version of IGFCs and conduct research and solicit stakeholder input before providing design guidance for the next version of IGFCs. The earliest that the first version of IGFCs could be implemented in rates is likely at the end of 2026.
Analysis: The gradual move towards IGFCs will provide additional time for consideration and analysis prior to full implementation of this novel approach to aligning the structure of retail electric rates with utility cost structures while 29 5
recognizing the importance of access to affordable electricity and ensuring that the changes to rate structures does not disproportionately harm large numbers of ratepayers.
Next Steps: Comments on the Ruling are due July 21, and reply comments are due August 11. A workshop on expanding existing pilots, including AgFIT, and an opportunity for the filing of post-workshop comments is expected to be scheduled in 2023.
Additional Information: Ruling (June 19, 2023); D.23-04-040 on electric rate design principles (May 3, 2023); D.23-04- 008 (Apr. 14, 2023); CalCCA Reply Comments on Scoping Memo (Jan. 4, 2023); Phase 1 Scoping Memo and Ruling (Nov. 2, 2022); VCE and Polaris Ex Parte Notice (Oct. 10, 2022); OIR (Jul. 22, 2022); Docket No. R.22-07-005.
Commercial EV Real-Time Pricing Pilot
Background: This proceeding approved PG&E’s proposed commercial EV rate pilot featuring day-ahead hourly real-time pricing. This pilot includes real-time pricing for both imports from and exports to the grid by commercial EVs.
Recent Developments: On June 9, the CPUC issued a Proposed Decision on PG&E’s Petition for Modification of D.21- 11-017 which mostly denies PG&E’s requests related to utility expenditures, finding that the proposed modifications are unnecessary and that D.21-11-017 provides sufficient flexibility to address PG&E’s concerns. The Proposed Decision also modified OP6 of D.21-11-017 to provide PG&E more time to determine if the initial customer enablement tools budget is sufficient to complete development of the tools.
Analysis: N/A
Next Steps: The Proposed Decision may be heard as early as the July 13 Commission meeting. Opt-in enrollment for the real-time pricing export compensation pilot now begins in February 2024. The proceeding was previously closed but reopened to address PG&E’s Petition which requests additional budget flexibility and authorization for billing system, program management changes, and extends the timeframe for implementation by about four months.
Additional Information: Proposed Decision (June 9, 2023); Letter granting extension (Apr. 26, 2023); PG&E AL 6850-E (Jan. 30, 2023); PG&E Petition for Modification (Nov. 4, 2022); D.22-10-024 (Export Compensation Settlement) (Oct. 26, 2022); Corrected MGCC Study (Mar. 17, 2022); Application & Testimony (Oct. 23, 2020); Docket No. A.20-10- 011.
Microgrids
Background: This proceeding was opened to implement the requirements of SB 1339 (Stern, 2018), regarding the commercialization of microgrids for distribution customers of the large IOUs. The initial three tracks have concluded, and Track 4 and Track 5 address the establishment of a Microgrid Incentive Program, potential contributions that microgrids can make to mitigating capacity shortages in the near-term, the development of a multi-property microgrid framework, and examination of the value of resiliency from microgrids.
Recent Developments: On June 9, the CPUC released Draft Resolution M-4868 on Approval of the Equity and Access (E&A) Grant Program.
Analysis: N/A
Next Steps: The Draft Resolution is scheduled to be heard at the July 13 Commission meeting. In Track 4, an ALJ Ruling providing an Energy Division Staff Proposal for a Microgrid Multi-Property Tariff was expected in October 2022 but has been delayed. In Track 5, a staff proposal on Definitions, Metrics, Tools, and Methods and Informing Grid Planning was expected in Q1 2023. An ALJ Ruling establishing 2023 scheduling & activities was expected in Q1 2023 but has been delayed. The Joint Application for Rehearing is pending.
Additional Information: Draft Resolution M-4868 (June 9, 2023); Joint Application for Rehearing (May 15, 2023); D.23- 04-034 on Microgrid Incentive Program Implementation (Apr. 14, 2023); Scoping Memo (Dec. 17, 2021); Docket No.
R.19-09-009.
PG&E Asset Transfer
Background: This proceeding addresses PG&E’s Application to transfer its non-nuclear generating assets to a new subsidiary, Pacific Generation, and sell up to 49.9% of its equity interest to third-party investors.
Recent Developments: On June 8, PG&E filed a Motion for Official Notice of a May 31 FERC Order in Docket No. EC23- 38-000 approving PG&E’s proposed transaction for the transfer of its generating assets.
Analysis: FERC’s determination is limited to the first step of the transaction (the transfer of the generation assets to Pacific Generation); it does not address the Minority Interest Sale. The FERC order also makes clear that in approving the transaction, FERC relied upon representations from PG&E regarding the transaction’s likely impact on its credit metrics, stating: "If . . . as a consequence of the Proposed Transaction, PG&E does experience an increase to its cost of debt, a degradation of its credit metrics, or changes to its capital structure, such changes would represent material changes in circumstances that depart from the facts or representations that the Commission relied upon in authorizing the Proposed Transaction triggering the need for a filing by PG&E" (P 41). Note that parties like TURN have taken on these issues in testimony (e.g., commenting on potential changes to PG&E's credit outlook as a 30 6
result of the proposed transaction). If such changes occur, this may trigger reconsideration of FERC's approval of the first step of the transaction.
Next Steps: Rebuttal testimony is due July 7 (note that the CPUC must separately approve the proposed transaction for PG&E to move forward with it; FERC approval for both stages of the transaction is an independent requirement).
Evidentiary hearings are scheduled August 21-22, 24-25, and 28, and opening briefs are due September 18.
Additional Information: PG&E Notice (June 8, 2023); ALJ Ruling (Mar. 30, 2023); Scoping Memo and Ruling (Jan. 20, 2023); PG&E Application (Sep. 28, 2022); Docket No. A.22-09-018.
Demand Response Programs (2023-2027)
Background: This proceeding addresses the IOUs’ Demand Response (DR) Portfolio Applications required under D.17- 12-003 for the years 2023-2027.
Recent Developments: No recent developments in the past month.
Analysis: N/A
Next Steps: Opening briefs are due September 30, and a proposed decision is expected in January 2024. Reply briefs on Phase 2 are due July 21, and a proposed decision is expected in October 2023 for the 2024-2027 DR Program.
Additional Information: Resolution E-5267 on ELRP (May 23, 2023); ALJ Ruling on DRAM (Mar. 3, 2023); ALJ Ruling on ELRP (Mar. 2, 2023); Assigned Commissioner’s Ruling (Jan. 27, 2023); D.23-01-006 (Jan. 13, 2023); Scoping Memo and Ruling (Dec. 19, 2022); D.22-12-009 (Dec. 6, 2022); Ruling consolidating Applications (May 25, 2022); PG&E Application (May 2, 2022); Docket No. A.22-05-002.
Wildfire Fund NBC 2024-2026
Background: This rulemaking will set the Wildfire Fund nonbypassable (NBC) charge for the years 2024 through 2026.
This charge was established by Assembly Bill 1054 (Stats. 2019, ch. 79), and is a per-kilowatt-hour charge set annually based on the Fund’s revenue requirement request from the Department of Water Resources (DWR).
Recent Developments: No recent developments in the past month.
Analysis: N/A
Next Steps: The 90-day Notice on the 2024 Wildfire NBC from the DWR followed by a Ruling seeking comment from parties is expected in September, and then a Proposed Decision in November followed by a Final Decision in December.
Additional Information: Scoping Memo and Ruling (May 22, 2023); Order Instituting Rulemaking (Mar. 21, 2023); Docket No. R.23-03-007.
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.
Recent Developments: No recent developments in the past month.
Analysis: N/A
Next Steps: Reply comments on the ALJ Ruling are due July 14.
Additional Information: ALJ Ruling (May 8, 2023); Draft Resolution SPD-3 (Sep. 16, 2022); ALJ Ruling (Sep. 13, 2022); Scoping Ruling with procedural schedule (April 28, 2022); Order Instituting Rulemaking (Oct. 7, 2021); Docket No.
R.21-10-001.
IRP Rulemaking
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.
Recent Developments: No recent developments in the past month.
Analysis: N/A
Next Steps: The IRP stakeholder process will re-start in Q2 2023.
Additional Information: Petition for Modification (May 30, 2023); D.23-02-040 on Procurement (Feb. 28, 2023); ALJ Ruling & Reliable and Clean Power Procurement Program: Staff Options Paper (Sep. 8, 2022); Scoping Memo (Sep. 24, 2020); Docket No. R.20-05-003.
31 7
Building Decarbonization
Background: This proceeding explores reduction of greenhouse gas (GHG) emissions associated with energy use in buildings. D.20-03-027 established the Building Initiative for Low-Emissions Development and the Technology and Equipment for Clean Heating program. D.21-11-002 adopted guiding principles for layering building decarbonization incentives, adopted incentives to help wildfire victims rebuild all-electric, and directed the IOUs to study bill impacts from electrification.
Recent Developments: No recent developments in the past month.
Analysis: N/A
Next Steps: There is no current procedural schedule for this proceeding.
Additional Information: D.23-02-005 (Feb. 3, 2023); D.21-11-002 (Appendices A-E) Decision on Building Decarbonization Phase II (Nov. 9, 2021); D.20-03-027 Establishing Building Decarbonization Pilot Programs (Apr. 6, 2020); OIR (Feb. 8, 2019); Docket No. R.19-01-011.
Other Dockets
The following table identifies other tracked dockets that are closed or inactive.
Docket Name Status
I.15-08-019
Investigation into
PG&E Organization,
Culture, and
Governance
This proceeding was opened as part of an investigation into whether PG&E’s organizational culture and governance prioritize safety, and currently serves to monitor the progress of PG&E in improving its safety culture. On May 19, the CPUC issued D.23-05-009 adopting the Safety Policy Division’s Modified Staff Report and closing the proceeding.
A.20-06-011 PG&E
Regionalization Plan
D.22-06-028 closed the proceeding. PG&E will continue to convene quarterly “town hall” meetings in each region and conduct broader meetings with the Regionalization Stakeholder Group. Town Hall Report Q1 2023 (May 12, 2023) and Quarterly Regionalization Report for Q1 2023 (May 15, 2023). 32 Item 9
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 9
TO: Board of Directors
FROM: Alisa Lembke, Board Clerk / Administrative Analyst SUBJECT: Community Advisory Committee June 22, 2023 Meeting DATE: July 13, 2023
This report summarizes the Community Advisory Committee’s meeting held in person and via Zoom webinar on Thursday, June 22, 2023. The CAC congratulated Jennifer Rindahl for being reappointed to represent the City of Winters and welcomed Carl Linvill, representing the City of Davis, to the CAC. Staff informed those present that Kristin Jacobs, Member-at-Large, has resigned from the CAC due to her moving out of VCE’s service territory.
A. Power Procurement / Renewable Portfolio Standard (Information only, no staff report). VCE Staff Gordon Samuel provided an update on VCE’s power procurement 2022 targets with actuals; and, provided status update on the Resurgence Solar 1, Willy 9 Chap 2 (formerly Willow springs Solar), and “compliance period 4”. The CAC discussed: impacts on load, market rates, and reasons for development delays.
B. Considered recommendation to the Board on VCE’s 80% Renewable by 2030 goal. Mr.
Samuel introduced Jim Himelic of First Principles Advisory (FPA) who attended the meeting remotely. Mr. Himelic analyzed the cost impacts of increasing VCE’s renewable portfolio content; and, updated technology cost assumptions including the incorporation of the Inflation Reduction Act (IRA) to compose portfolio modeling scenarios. Mr. Samuel reviewed and compared the four (4) portfolio modeling scenarios. Staff and the CAC discussed: what power resources are considered renewable; how much “local” resources does VCE currently have in their portfolio; differences between the four portfolio modeling scenarios; benefits of local resources; procurement strategy; ELCC (effective load carrying capacity) value of different resources; and, “local” resources. After a thorough discussion, the CAC voted to make a recommendation to the Board to increase the current 80% renewable procurement goal by 2030 to 100% renewable by 2030; substitute the 25% renewable local component goal with a goal of 25% of future storage amounts to be from local installations; and, when VCE solicits for power procurement Request for Proposals (RFP), included is a local preference (Yolo County and adjacent to), in VCE’s evaluation criteria. (7-0-0) C. Considered recommendation to the Board on allocation of 2022 net margin. VCE Staff Edward Burnham provided an overview of the background of the audited 2022 net margin; the current 2022 net margin allocation; and, Staff’s recommendation on allocation. Staff and the CAC discussed: cash reserves, target of 180 days in cash reserves, the effects on VCE’s programs, and rates. The CAC voted to make a 33 Item 9
recommendation to the Board to approve the following allocation of the $5.3 million in 2022 Audited Net Margin as follows: $712,500 to the Local Programs Reserve (LPR); $0 to dividends; and the balance of $4,611,000 to cash reserves to reach cash reserve targets. (7-0-0)
D. Considered recommendation to the Board on Strategic Plan Guidelines for Plan updates. Mr. Burnham informed those present that Staff have been working with the Strategic Plan Task Group to draft guidelines to update the approach and timeline for extending the 2021-2023 Strategic Plan beyond the current end of the planning period (end of 2023) and develop a process for future plans. Mr. Burnham gave a brief background on the Strategic Plan; presented an updated approach and timeline; and, reviewed Staff’s recommendation. The CAC voted to make a recommendation to the Board to approve the Strategic Plan Guidelines. (7-0-0) E. Discussion of meeting schedule and topics listed on the CAC 2023 long range calendar.
The CAC reviewed remaining meeting dates, topics scheduled and those listed at the bottom of the calendar as “proposed topics”. Past CAC Member Christine Shewmaker provided written public comment on this item, which was read into the record and posted to the website. The CAC discussed: bringing forth new topics if it would benefit the CAC and topics listed in future “proposed topics”; having shorter meetings; spreading out topics amongst the monthly meetings rather than cancelling meetings.
Staff encouraged members to share their topic ideas with the Chair, Vice Chair and Staff.
Staff will continue to work with the Chair and Vice Chair on preparing agenda and will discuss what could be brought forth for a July 27, 2023 meeting. 34 Item 10
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 10
TO: Board of Directors
FROM: Rebecca Boyles, Director of Customer Care & Marketing SUBJECT: Quarterly Customer Participation Update (Information) DATE: July 13, 2023
RECOMMENDATION
Receive and review the attached quarterly Customer Participation update reflecting the time period through June 30, 2023.
35 Item 10 – Customer Participation Update
Status Date: 7/03/23 1
% of Load Opted Out
Davis Woodland Winters Yolo Co Total Residential Commercial Industrial Ag NEM Non-NEM VCEA customers 27,685 20,009 2,498 10,708 60,900 53,065 5,922 7 1,906 12,201 48,699 Eligible customers 29,114 23,364 2,906 12,364 67,748 58,950 6,614 7 2,177 13,762 53,986 Participation Rate 95% 86% 86% 87% 90% 90% 90% 100% 88% 89% 90% Davis Woodland Winters Yolo Co Total Residential Commercial Industrial Ag Total % of Load Opted Out 5% 14% 14% 13% 10% 10% 10% 0% 12% 10% % of Load Opted Up 1% 0% 0% 1% 1% 1% 3% 0% 0% 1%
36 Item 10 – Customer Participation Update
Status Date: 7/03/23 2
0 100
200
300
400
500
Qtr2 Qtr3 Qtr4 Qtr1 Qtr2 Qtr3 Qtr4 Qtr1 Qtr2
2021 2022 2023
Quarterly Opt-Outs
Davis Unincorp. Yolo Woodland Winters
0 50
100
150
200
Qtr2 Qtr3 Qtr4 Qtr1 Qtr2 Qtr3 Qtr4 Qtr1 Qtr2
2021 2022 2023
Quarterly Opt-Ups
Davis Unincorp. Yolo Woodland Winters
37 Item 10 – Customer Participation Update
Status Date: 7/03/23 3
Davis
69%
Unincorp. Yolo
14%
Woodland
15%
Winters
2%
533 Opt-Ups
Davis
22%
Unincorp. Yolo
27%
Woodland
46%
Winters
5%
10,844 Opt-Outs
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).
38 1
Item 11
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 11
TO: VCE Board of Directors
FROM: Mitch Sears, Executive Officer
SUBJECT: SACOG Grant Update and Extension Request
DATE: July 13, 2023
RECOMMENDATION
Approve Electrify Yolo grant extension request to SACOG.
BACKGROUND and ANALYSIS
In 2018 VCE joined with the cities of Davis and Woodland and Yolo County to apply for a $2.9 million grant from the Sacramento Council of Governments (SACOG). The purpose of the grant is to install electric vehicle charging infrastructure in Yolo County. The proposal was successful, and the grant was approved by the SACOG board of directors on December 20, 2018. The project is titled Electrify Yolo.
After grant approval by the SACOG board of directors, a fund exchange agreement was approved between the City of Davis and SACOG. This helped streamline grant reporting and payment processing. The project deadline was established through the fund exchange process as December 31, 2023.
The Electrify Yolo team members include the cities of Winters, Woodland, Davis, the County of Yolo County, and VCE.
UPDATE
COVID delayed the implementation of Electrify Yolo significantly. The project participants are all making progress—charger locations have been identified, sites have been developed in preparation for installations, and chargers have been installed at several locations. However, progress was slowed significantly by COVID, and more time is needed to complete Electrify Yolo.
Winters and Woodland are expected to complete their projects by year-end. Yolo County and Davis have larger projects that require more time and resources to complete. Therefore, Valley Clean Energy and the project partners are requesting a project extension of one year, with a new project end date of December 31, 2024.
39 Item 12
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 12
TO: Board of Directors
FROM: Edward Burnham, Director of Finance & Internal Operations Mitch Sears, Executive Director
SUBJECT: Approve and Adopt Strategic Plan Guidelines
DATE: July 13, 2023
RECOMMENDATIONS
Approve the attached resolution adopting the Strategic Plan Update Guidelines for VCE.
OVERVIEW
The purpose of this report is to present an updated approach and timeline for extending the 2021-2023 Strategic Plan beyond the current end of the planning period (end of 2023) and a process for developing future plans as described in the attached strategic plan guidelines.
BACKGROUND
The Board ratified the VCE Three-Year Strategic Plan (Plan) for 2021-2023 at it’s November 12, 2020 meeting (VCE-Strategic-Plan-Final.pdf (valleycleanenergy.org). 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 updated on a 2-year basis.
The initial Strategic Plan covered a fixed period from 2021 to 2023. Based on Board feedback on the approach for extending the Strategic Plan beyond the end of 2023, Staff presented an action plan to adopt one-year extensions each year so that the Plan would always be 1+ years from expiration to maintain a three-year outlook starting in 2023. Upon further consideration and feedback from Community Advisory Committee Strategic Plan Task Group, Staff recommends extending the 2021-23 plan through 2025 and include a minor update as part of that process. After that, Staff recommends that the Strategic Plan be updated every four years so that it does not fall on years that also require updates to VCE’s Integrated Resource Plan (IRP). In addition, Staff will review and report annually to the Board and CAC on the status of goals, objectives and metrics. Staff believes this modified approach balances the advantages of keeping the Plan up to date and providing the value of longer-term planning while not overburdening the organization with redundant activities. 40 Item 12
2 Staff and the Community Advisory Committee Strategic Plan Task Group have developed the attached strategic plan guidelines to provide a framework for sustaining VCE’s strategic plan. At the June 22, 2023 CAC meeting, Staff presented the draft strategic plan update guidelines for their input.
Community Advisory Committee Recommendation
The CAC recommended approval of the draft strategic plan update guidelines with no recommended changes.
CONCLUSION
If adopted by the Board, the proposed Strategic Plan Update Guidelines represent a balanced, comprehensive approach to align the strategic plan with VCE’s multi-year time horizon and provide consistent update benefits associated with the “rolling” approach. If the Board approves the strategic plan guidelines, Staff will put the proposed timeline for extending the existing strategic plan with a minor update as outlined in the guidelines into motion.
Attachments
1. Draft Strategic Plan Update Guidelines
2. Resolution adopting Strategic Plan Update Guidelines 41 Strategic Plan Update Guidelines
Purpose
The Strategic Plan Update Guidelines provide a framework for carrying out Major and Minor Plan Updates and reporting on the progress of VCE towards its strategic goals.
Overview of VCE’s Strategic Plan
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 workplans, 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 updated on a 2-year basis.
The Plan maps a route to VCE’s goals and allows for course correction as new information and learning occur. 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 action, being mindful of the longer-term aspirations. The Plan is reviewed annually to ensure that the Plan remains on track and course corrects when necessary.
Background of the Initial Strategic Plan (2021-2023)
The Board ratified the initial VCE Three-Year Strategic Plan (Plan) for 2021-2023 at the November 12, 2020 meeting (VCE-Strategic-Plan). VCE’s initial strategic Plan was based on the experience of the Agency’s first two years (2019-2020) in operation as well as current energy market conditions, 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. The Plan covers 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 from 2021-2023.
Strategic Plan Definitions
Categories – Plan categories are key areas of focus or priorities that VCE has chosen to act as VCE’s foundational pillars for Plan development to achieve its long-term vision.
Goals - Plan goals are aspirational ambitions outlined for each category to provide guidance through the end of the Plan.
Objectives - Plan objectives are high-level and measurable outcomes outlining what VCE wants to achieve within the plan goal.
Strategies – Plan Strategies are where VCE aligns their efforts in order to achieve the desired outcomes that will bring about the achievement of the organization’s goals and objectives. 42 Strategic Plan Categories and Goals (2021-2025)
Background of the Strategic Plan Guidelines
The initial Strategic Plan covered a fixed period from 2021 to 2023. Based on Board feedback on the approach for extending the Strategic Plan beyond the end of 2023, Staff presented an action plan to adopt one-year extensions each year so that the Plan is always 1+ years from expiration to maintain a three-year outlook starting in 2023. Upon further consideration and feedback from Community Advisory Committee Strategic Plan Task Group, Staff recommends extending the 2021-23 plan through 2025 and include a minor update as part of that process. After that, as shown in the table below, Staff recommends Strategic Plan updates every four years to set the cadence for future updates to fall on years that do not require updates to VCE’s Integrated Resource Plan (IRP). In addition, Staff will review and report annually to the Board and CAC on the status of goals, objectives and metrics.
Strategic Plan Update Schedule
Key Objectives of Strategic Plan Minor Updates
Minor Update – The purpose would be a relatively high-level review/update to existing goals and objectives performed by Staff to incorporate plan adjustments associated with changing legislative, regulatory, customer, economic, etc. requirements, as well as plan milestones achieved. Key activities would include:
• Evaluate Strategic Plan to update and re-align strategic goals and objectives where necessary. • Short-term adjustments based on changed external/internal requirements and recent accomplishments.
•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
2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033
Minor
Update
Major
Update
Minor
Update
Major
Update
Minor
Update
Major
Update
IRP WORK IRP WORK IRP WORK IRP WORK IRP WORK
Extension of 2021-2023 Plan Strategic Plan Strategic Plan 43 Guidelines for Strategic Plan Minor Update
• VCE Staff
o Identify changes in the overall CCA environment (economics, policy, technology, etc.) and describe their relevance for VCE
o Review existing goals and objectives to identify and recommend adjustments Goal assessment using SWOT analysis as necessary
o Staff should propose recommendations to Executive Officer for minor updates. ▪ Recommendations should provide annual and long-term budget requirements • Community Advisory Committee
o Review and recommend revisions to strategic Plan minor updates. o Work with Staff to develop Strategic Plan goals and strategies • Board
o Review and approval of minor update revisions.
Timeline of Strategic Plan Minor Update
Key Objectives of Strategic Plan Major Updates
Major Update – The purpose would be a more detailed review/update of the Plan, including a review of VCE’s Vision/Mission and existing goals and objectives. Major Plan updates would be comprehensive reviews incorporating workshops at various levels of the organization, including community stakeholder engagement. The baseline activities would incorporate those enumerated in the Minor Update above (i.e. incorporate plan adjustments associated with changing legislative, regulatory, customer, economic, etc. requirements, as well as plan milestones achieved). Key activities in a Major Update would include:
• Identify changes in the overall CCA environment (economics, policy, technology, etc.) and describe their relevance for VCE (also listed as VCE Staff activity below) • Review key organizational fundamentals (Mission, Vision, and Strategic Plan Goals) January
Staff Minor
Update Kick-off
Meeting
March
Staff Strategic
Workshop
May
Staff Preliminary
report to
Executive Officer
July
Finalize Staff
Minor Update
August
CAC Presentation
and Feedback
September
Board Presentation
and Feedback
November
Board Adoption
44 • Long-term adjustments based on strategic and customer requirements Guidelines for Strategic Plan Major Update
• VCE Staff
o Identify changes in the overall CCA environment (economics, policy, technology, etc.) and describe their relevance for VCE
o Review existing goals and objectives to identify and recommend adjustments Goal assessment using SWOT analysis as necessary
o Staff should propose recommendations to Executive Officer for Major updates. ▪ Recommendations should provide annual and long-term budget requirements o Identify, solicit, and include input from key stakeholders ▪ Surveys and/or community engagement should include initial staff recommendations to narrow the focus for annual updates. • Community Advisory Committee
o Review and recommend strategic plan goals and objectives o Formation of Strategic Plan Task Group
• CAC Strategic Plan Task Group
o Work with Staff to develop Strategic Plan goals and objectives o Provide input and feedback to Staff on the draft Strategic Plan to present to the CAC and Board
o Provide summaries and updates at monthly CAC meetings on Task Group activities. • Board
o Provide feedback to Staff on aspirational goals.
o Review and approval of the strategic Plan.
Timeline of Strategic Plan Major Update
January
Form CAC Task
Group
March
Survey /
Community
Feedback Review
June
Community
Stakeholder
Outreach
July
CAC Task Group
Review
August
CAC Review
September
Board Workshop
November
Board Adoption
45 Continuous improvement and reporting for Strategic Plan Update VCE’s Strategic Plan is a living document that will be revisited and updated regularly. Staff will perform minor updates that review and update the Plan on an bi-annual basis, including goals, objectives and metrics. VCE staff will report annually key metrics, status and mitigations where appropriate annually to the Board and CAC. 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.
46 Item 12
VALLEY CLEAN ENERGY ALLIANCE
RESOLUTION NO. 2023- ____
A RESOLUTION OF THE BOARD OF DIRECTORS OF VALLEY CLEAN ENERGY ALLIANCE
ADOPTING STRATEGIC PLAN UPDATE GUIDELINES
WHEREAS, The 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 section 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, the Board approved the Three year Strategic Plan for 2021-2023 on October 8, 2020, to establish goals and guide VCE’s activities over the next three years.
NOW, THEREFORE, the Board of Directors of Valley Clean Energy Alliance hereby adopts Strategic Plan Update Guidelines (Exhibit A) to establish an approach and timeline for updating and extending the 2021-2023 Strategic Plan beyond the current end of the planning period (end of 2023) and a process for developing future plans as described in the attached strategic plan guidelines.
PASSED, APPROVED AND ADOPTED, at a regular meeting of the Valley Clean Energy Alliance, held on the ____ day of _______ 2023, by the following vote:
AYES:
NOES:
ABSENT:
ABSTAIN:
_____________________________________
Tom Stallard, VCE Chair
__________________________________
Alisa M. Lembke, VCE Board Secretary
Attachment: Exhibit A – Strategic Plan Update Guidelines 47 Item 12
EXHIBIT A
STRATEGIC PLAN UPDATE GUIDELINES
48 Item 13
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 13
TO: Board of Directors
FROM: Mitch Sears, Executive Officer
Gordon Samuel, Assistant General Manager & Director of Power Resources Alisa Lembke, VCE Board Clerk/Administrative Analyst
SUBJECT: Consider Appointment to Jurisdiction seat on Community Advisory Committee DATE: July 13, 2023
RECOMMENDATION
1. Consider candidate for appointment to vacant City of Woodland seat for a three (3) year term to expire June 2026 (Class 2); and
2. Continue to solicit candidates for vacant At-Large and unincorporated Yolo County jurisdiction seats.
BACKGROUND/ANALYSIS
The Board at their September 9, 2021 meeting, adopted a revised Community Advisory Committee (CAC) structure with eleven total members: eight jurisdictional members (two per jurisdiction) and three additional seats for At-large members intended to fill specific subject matter expertise/experience areas.
At the Board’s June 15, 2023 Special meeting, the Board was informed that Class 2 appointments expired in June 2023 and in March 2023 Staff received a resignation from the Member appointed to represent the City of Woodland. After consideration, the Board reappointed Jennifer Rindahl to the City of Winters jurisdiction seat; appointed Carl Linvill to the vacant City of Davis jurisdiction seat; and directed staff to continue the solicitation of candidates for the other vacant seats in Class 2: City of Woodland and unincorporated Yolo County. As directed, VCE continued to solicit and advertise for applicants.
VCE has received one application for the City of Woodland seat. No other applications have been received and no applications are on file.
Staff reviewed the application from Diccon Westworth, a resident of Woodland and VCE customer. In summary: Mr. Westworth is interested in community outreach and meeting the needs of local residents, businesses, and the local government community with focus on incentivizing others to lessen dependency on fossils fuels and replace with renewable energy sourcing. He has experience in 49 Item 13
2 sustainability within the veterinary profession by promoting sustainability through awareness, education and community.
Consistent with past practice, staff provided the application to the jurisdiction Board Members (City of Woodland), for their review and consideration for recommendation to the Board for appointment.
In addition, VCE received CAC At-Large member Kristin Jacobs’ resignation due to them moving out of VCE’s service area. This leaves a vacant At-Large seat within Class 3, term expiring June 2024.
CONCLUSION
Staff recommends the Board consider:
1. Appointment of Diccon Westworth to the vacant City of Woodland seat for a three (3) year term to expire June 2026 (Class 2); and
2. Continue to solicit candidates for vacant unincorporated Yolo County jurisdiction (Class 2) and At-Large (Class 3) seats until filled.
Below is a listing of the other “classes” and expiration terms:
CLASS 3 – term expires in June 2024
At-Large – Lorenzo Kristov
At-Large – Keith Taylor
At-Large – Vacant
CLASS 1 - term expires in June 2025:
Winters Rep. – David Springer
Woodland Rep. – Mark Aulman
Davis Rep. – Rahul Athalye
Yolo County Rep. – Cynthia Rodriguez
Attachment
1. CAC City of Woodland Application
50 51
52 53
6/15/2025
54 Item 14
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 14
____________________________________________________________________________________ TO: Board of Directors
FROM: Gordon Samuel, Assistant General Manager & Director of Power Services SUBJECT: Consider increasing VCE’s Existing 80% Renewable by 2030 Goal DATE: July 13, 2023
RECOMMENDATIONS
1. Receive presentation and provide feedback on VCE’s power portfolio content goals.
2. Increase the current 80% renewable goal by 2030 to 100% renewable by 2030 and substitute the 25% renewable local component goal with a goal of 25% of future storage amounts to be from local installations.
3. When conducting solicitations state a preference for locally sited resources.
BACKGROUND
Prior to VCE’s launch in June 2018, the Board adopted a goal for VCE’s power content to target 80% renewables by 2030. The goal also set a requirement that 25% of this amount should be from local resources. At the time this was a very ambitious goal, and some may still consider this to be a stretch or at least a sufficient target. Others may believe this goal does not go far enough. Since this goal was adopted, VCE has entered into several long-term power purchase agreements (PPAs) and has been working towards fulfilling these goals.
Guiding Documents – Carbon Neutral Study and 2022 Integrated Resource Plan In the second half of 2021 and early 2022, staff completed a 100% carbon neutral by 2030 study (CNx2030) which considered not only being carbon neutral but also 100% renewable (100% Carbon Free Portfolio Study (Final). In 2022, VCE submitted its integrated resource plan (IRP) to the California Public Utilities Commission (CPUC) (Integrated Resource Plan (IRP) filed 11/1/2022). This IRP also studied various portfolios from 2023-2035 with the primary focus to be at or below a specific emissions target in an effort to reduce greenhouse gases (GHG) at the lowest cost. As a result of VCE’s procurement and study efforts, a reasonable roadmap is beginning to emerge which presents an opportunity to revisit the current power content goal adopted in 2018.
During the November 17, 2022 Community Advisory Committee (CAC) meeting, the Committee voted unanimously to recommend that the Board modify the existing goal. The CAC recommended that the Board approve a new goal which is 100% renewable by 2030 with 25% of the content sourced from local resources. A key point expressed by several CAC members who spoke in support of increasing the goal believed that it provides a reasonable target for VCE to aspire towards. Unfortunately, in November 2022, Staff did not have the supporting analysis of the advantages/disadvantages associated 55 2
with the CAC proposed modification of the current portfolio goal – specifically the 25% local component. Staff reported this CAC recommendation to the Board in late 2022 and received direction from the Board to return in mid-2023 with an analysis of setting a more aggressive 2030 renewable target.
Based on that direction, staff engaged the portfolio modeling services of First Principles Advisory (FPA), the firm that performed the portfolio modeling for VCE’s 2022 IRP. FPA’s familiarity with the VCE portfolio was a logical reason to have them conduct this additional modeling. At the February 2023 Board meeting, the Board approved a contract with FPA for the additional modeling with a commitment from staff to bring the results and recommendation to the CAC in June and the Board in July 2023.
VCE Current Renewable Portfolio
VCE’s has signed seven renewable PPA consisting of photovoltaic (PV), hybrid (PV + storage) and geothermal. These PPAs account for approximately 680 annual GWHs or approximately 70% of VCE’s retail load (2030).
Table 1 – VCE’s Executed Long-Term Renewable PPAs
Long Term PPAs Actual or Expected COD Capacity*
Resurgence Solar I 7/7/2023 (active) 90 MW PV, 75 MW BESS (250,000 MWhs)
Aquamarine Solar 9/22/2021 (active) 50 MW PV (130,000 MWhs) Putah Creek Energy Farm 10/15/2022 (active) 3 MW PV, 3 MW BESS (7,600 MWhs) Gibson Solar 6/1/2025 13 MW PV, 13 MW BESS (50,000 MWhs) Willy 9 Chap 2** 12/31/2023 72 MW PV, 36 MW BESS (210,000 MWhs)
Ormat Geothermal Varies by project, but as early as
2025 4.63 MW (35,380 MWhs)
Fish Lake Geothermal June 2024 0.42 MW (3,460 MWhs)
* All Battery Energy Storage Systems (BESS) are 4-hour duration, except the Gibson Solar project is a 5-hour battery system. Approx annual MWhs shown.
** Formerly Willow Springs Solar 3. Name changed at the request of the CAISO.
ANALYSIS
Staff, working with FPA, identified seven scenarios to model. Four assuming a future natural gas price curve that would be considering a P50 curve and three at a higher price P95 curve1. For the purposes of this report, staff elected to focus on the results associated with the P50 analysis. Note: if natural gas prices are more in-line with the P95 assumption this does have a material cost impact on the portfolio depending on the type of renewable resources selected.
1 P50 and P95 represent the confidence level of a cost not being exceeded. A P50 value has a 50% probability that it will be exceeded, whereas, a P95 only has a 5% probability of being exceeded. 56 3
Table 2 – Four Scenarios Modeled Based on P50 NG Curve
Scenario NG Price 2030 RPS
Target
Local RPS
Target
1.a (current goal) P50 80% 25%
1.b P50 100% 25%
1.c P50 100% -
1.d P50 80% -
Scenario 1.a can be considered the base case or business as usual (BAU). This scenario is the current VCE goal. Scenario 1.b increases the renewable percentage to 100% by 2030 as well as maintains the current 25% local renewable component. Scenario 1.c increases the renewable percentage to 100% but only considers the two existing local PPAs that VCE has executed (Putah Creek and Gibson2).
Finally, Scenario 1.d maintains the current 80% renewable by 2030 and only considers the two existing local PPAs that VCE has executed (Putah Creek and Gibson). The purpose of identifying these four scenarios was to establish a range of potential cost outcomes.
The portfolios from each of the scenarios are slightly different but the primary choice of eligible renewable technologies does not vary (note: the modeling does allow for the selection of other technologies such as biomass, off-shore wind, etc but only selects resources that are the best fit for the portfolio). Table 3 below identifies the incremental capacity additions (additions above what VCE has already contracted) for each scenario.
Table 3 – Cumulative Incremental Capacity Additions
As shown the local hybrid renewable resources are assumed to be PV + storage as that is the most realistic resource available in Yolo County as the county does not have significant geothermal or wind resources and the local biomass resources have proven to be quite costly. Unfortunately, PV land 2 These two local projects represent approximately 8% of VCE’s renewable portfolio. 57 4
usage is significant which can have impacts on prime agricultural land which presents policy trade-offs and can be difficult to permit. To achieve the current 25% local goal, the amount of new local capacity would be between 65 MW and 84 MW. Although this amount is technically feasible, based on direct experience staff observes that it will be difficult to permit locally, the costs will be at a premium compared to installation in other regions of the State, and it installs a technology that VCE otherwise would not select as the portfolio would benefit from additional diversification (e.g. wind).
Scenario Costs
Table 4 below identifies the net present value (NPV) cost trade-offs between each scenario. All scenarios are measured off Scenario 1.a (BAU scenario). Scenario 1.b is $23.5 million more than the BAU case, similarly Scenario 1.c is $33.4 million cheaper than the BAU case (or nearly $57 million cheaper than Scenario 1.b). Scenario 1.d is the lowest cost of all cases. An important point to highlight is the incremental cost to go from 80% (1.d) to 100% (1.c) renewable is not unreasonable and staff believes this is something the Board should consider. It is clear from the model runs that portfolio costs are amplified when factoring in additional local resources.
Table 4 – Scenario Cost Comparisons
Goals / Policies of other Load Serving Entities (LSEs) in California – Including CCAs Although each LSE’s situation is different, it is important to understand what other LSE’s have committed to. Numerous LSEs do have “aspirational” goals of achieving 100% renewable and clean power by 2030. Many LSEs intentionally include the term “clean” in their goals as this allows some flexibility to meet some of the content with resources such as large hydro or nuclear (both are defined as GHG-free or clean but neither qualify as renewable per the CPUC definition). For reference, Attachment 1 identifies the policies of many LSEs in California.
Strategic Plan
VCE’s current Strategic Plan contains the following 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.” By definition, California RPS renewable energy is also carbon free. Therefore, technically VCE would be exceeding its strategic plan goal by modifying to a 100% renewable goal by 2030. In addition, aspects of the strategic plan are currently being reviewed so any new goals can be incorporated into the latest version.
Scenario NG Price
2030 RPS
Target
Local RPS
Target
2024-2035
NPV
(2022 $M)
Delta
(2022 $M)
1.a P50 80% 25% 619.6 0
1.b P50 100% 25% 643.1 23.5
1.c P50 100% - 586.1 -33.4
1.d P50 80% - 575.7 -43.9
58 5
Community Advisory Committee Feedback
Staff presented this topic to the CAC in June. The topic generated a robust discussion of the pros and cons of increasing the goal to 100% as well as the local component modification. The CAC was supportive of Staff’s recommendation and further requested a slight enhancement of the recommendation. The CAC proposed (and staff supports), that when VCE conducts solicitations it states there is a preference for locally sited resources. In addition, the CAC believes the definition of “local” to be expanded to include Yolo County and the adjacent counties.
CONCLUSION
Staff is seeking Board feedback on modifying the existing power portfolio goal. Staff findings based on the scenario analysis:
1) With the current portfolio trajectory staff believes achieving 100% renewable is a reasonable and fiscally sound goal for the Board to consider.
2) Staff also believes the 25% local component should be revisited for two reasons:
a. The primary local renewable resource is solar (PV). From the modeling, additional solar is not a resource VCE needs as VCE needs to diversify to other renewable technologies to achieve a more balanced renewable portfolio.
b. The cost to achieve the 25% local requirement should be considered as this decision is discussed. It is substantially more costly to VCE’s customers to meet this component of the goal by 2030 and beyond. Based on the analysis, savings of up to $33M may accrue over the next 10 years vs. BAU (see Table 4).
3) Stand-alone storage resources, which enable the installation of more intermittent renewable resources in California (e.g. solar, wind), is a resource that could be considered for Yolo County. a. Permitting stand-alone storage is likely to prove to be more stream-lined as the footprint of the underlying disturbed land is much smaller than solar. b. VCE, as well as the grid, need storage.
Attachments
1. California LSE’s renewable goals
2. Study Results from First Principles Advisory (redacted) 59 6
Attachment 1
Renewable Energy Goals of CCAs and other electric utilities in California (as of May 2023) LSE Name Goal Summary
IOUs
PG&E net-zero energy system by 2040
SCE RPS
SDG&E RPS
Regional/Municipal Districts
IID (Imperial Irrigation
District) RPS
LDWP 80%/90% RPS by 2030, 100% carbon-free by 2035
SMUD zero carbon emission power supply by 2030
CCAs
Apple Valley Choice
Energy RPS
Central Coast
Community Energy 100% clean and renewable energy by 2030 City of Palmdale RPS
City of Pomona RPS
City of Santa Barbara 75% renewable / 100% carbon-free by 2030 (default rate) Clean Energy Alliance 100% renewable by 2035
Clean Power Alliance RPS
CleanPowerSF 100% renewable electricity by 2025, and 100% renewable energy (0% fossil fuels) by 2040
Desert Community
Energy RPS plus 100% carbon-free product as default for customers in Palm Springs East Bay Community
Energy
100% net-zero carbon annually by 2030, 100% clean energy on a net annual basis by 2030, exceed state RPS by 20% per year
King City Community
Power RPS
Lancaster Choice
Energy RPS
Marin Clean Energy 60% minimum renewable, default rate at 98.3% renewable as of 2021 (including large hydro)
Orange County Power
Authority RPS
Peninsula Clean Energy 100% renewable by 2025, including hourly matching (i.e., time-coincident basis) Pico Rivera Innovative
Municipal Energy 50% renewables (default rate)
Pioneer Community
Energy RPS
60 7
Rancho Mirage Energy
Authority RPS
Redwood Coast Energy
Authority
100% clean and renewable by 2025, plus 100% local renewable energy by 2030 (local resources located within the Humboldt Local Capacity Area) San Diego Community
Power
75% in 2027, 85% in 2030, and 100% in 2035 renewable; 15% new storage in Member Agencies' territories by 2035; 600MW of new utility scale projects within San Diego and Imperial Counties by 2035
San Jacinto Power RPS
San Jose Clean Energy 100% carbon neutral and renewable (annual basis) by 2030, with 0% fossil fuel by 2050
Silicon Valley Clean
Energy Authority
50% - 52% renewable currently, 60% - 62% renewable in 2030; 100% of energy needs with carbon-free electricity on annual basis, longer-term goal of carbon-free on 24x7 basis
Sonoma Clean Power Board policy of 50% renewable by 2020; Internal goal of 100% hourly marginal emissions mitigation by 2026 and 80% Winter Night Reliability by 2030 Valley Clean Energy
Alliance. 80% renewable by 2030
61 8
Attachment 2 – Study Results from First Principles Advisory (redacted) 62 VCE Modeling Results
Spring 2023 VCE Spring 2023 Modeling Exercise
63 Contents
• Executive Summary
• Key Recommendations
• Financial Summary
• Local Project Assumptions
• Detailed Breakdown of Model Results for Scenario 1.a
• System Buildout / Annual Generation / Resource Adequacy / ELCCs • Hourly Dispatch
• Market Participation
• Portfolio Costs
• RPS
• Sensitivity Case: Scenario 3 (capped market transactions) • Procurement Implications
• Recommendations
• Technology Breakeven Prices
• Potential Next Steps
• Key Modeling Inputs / Assumptions
• VCE load
• RA forecast / NG forecast / LMP forecast
• Technology cost curves / ELCC curves
• Model Related Info (description of process, key assumptions, Gridpath comparison to MATCH) 64 Executive Summary
• VCE’s current baseline scenario (i.e., 80% RPS energy by 2030 with a 25% local carveout) increases the NPV of the portfolio by $20-64M across the 2024-2035 planning horizon • Estimated cost premium is dependent on multiple variables, including (but not limited to) the price of NG and VCE’s risk management policy regarding market transactions
• Increasing the RPS target to 100% and keeping the 25% local carveout will result in an additional NPV expense of $14-24M relative to the baseline scenario
• Assuming solar-storage hybrid projects is the only available technology that can be built in Yolo County, VCE’s portfolio heavily is concentrated in solar and 4-hr storage and has limited ability to diversify its supply with other technologies
• Onshore wind, geothermal, and storage greater than 4 hours of duration constitute a greater share of contracted supply for the scenarios where the local constraint is not active • Combined, the recently passed IRA legislation and the current strained market conditions for li-ion based storage projects have significantly increased the opportunity cost associated with VCE’s local generation policy
• Li-ion costs have increased 15-25% whereas cost of alternatives have decreased 20-30% • Despite current high RA-only prices, VCE will be better off if they wait for market conditions for li-ion storage to settle and not lock in high price long-term (i.e. 10yr+) contracts • Note interconnection and project constructions delays increase the complexity of the near-term procurement strategy 65 Key Recommendations
• 100% (annual) RPS target by 2030 is economically feasible • Policy would not add significant costs to the portfolio • Allowing stand-alone storage projects located in Yolo County to qualify can help reduce the associated cost premium
• Path dependency matters -> need to know the end destination and what’s allowed; update as you go
• A clearly defined RPS / GHG policy and risk management policy is necessary to ensure portfolio is heading in the desired direction
• Understanding of current PPA market is critical
• Run an all-source solicitation annually to obtain timely information on technology costs • Execute agreements when favorable prices of desired technologies present themselves • Curtailment risk is only partially accounted for in current modeling approach • A site-by-site assessment should be taken in future modeling exercises • Benefits of customer programs should be fully explored to contain costs and increase flexibility • Updated TEA load forecast assumes VCE grows its annual load by 35% while increasing its peak demand by only 18% 66 Financial Summary
• In the P50 NG scenario, increasing VCE’s 2030 RPS target and keeping the 25% local requirement results in an additional charge of $23.5M in present value relative to VCE’s current policy (e.g., 80% RPS with a 25% carve out) • If VCE increases their 2030 RPS target to 100% but doesn’t require any additional local projects results in a cost savings of $33.4M • In the P95 NG scenario, the local premium is $21.6M
Index Natural
Gas Price
RPS 2030
Target
Local RPS
Requirement
Local Hybrid
Capacity
(MW)
2024-2035
NPV
(2022 $M)
Delta
(2022 $M)
1.A P50 80% 25% 65 619.6 0
1.B P50 100% 25% 84 643.1 23.5
1.C P50 100% n/a 0 586.1 -33.4
1.D P50 80% n/a 0 575.7 -43.9
2.A P95 80% 25% 65 591.6 0
2.B P95 100% 25% 84 613.2 21.6
2.C P95 100% n/a 0 527.4 -64.3
*Scenario 2.D not run in GridPath because model doesn’t bind on RPS constraint in scenario 2.C 67 Local Project Characteristics
• 1MW-4MWh of storage for every 1 MW
of solar
• Solar capacity factor: 33%
• Battery roundtrip efficiency: 86%
• Local hybrid project is ~40% more
expensive than latest technology costs
curves posted in CPUC’s latest Inputs and
Assumptions (I&A) document
Year 80% RPS
Target
100% RPS
Target
2028 22.5 30
2030 45 60
2032 55 72
2035 65 84
Cumulative Capacity (MW)
Year 2028 2030 2032 2035
Energy Price ($/MWh) 54 50 50 45
Capacity Price ($/kW-m) 10.75 9.50 8.00 7.00
“All-in Price”
($/MWh)
100 90 84 75
Non-Local Hybrid All-in
Price ($/MWh)
70 64 60 54
68 Detailed Results of Scenario 1.a
69 Scenario 1.A: System Buildout (nameplate)
• Solar (stand-alone or hybrid) makes up 73% (60%) of
nameplate capacity in 2030 (2035)
• Hybrid storage makes up 67% (54%) of nameplate
capacity in 2030 (2035)
• Hybrid storage is 4 hours in duration
• Dashboard File:
• MW
• Portfolio Summary I: columns B:H
• Portfolio Summary II: columns D:J
• MWh
• Portfolio Summary I: columns L:R
• Portfolio Summary II: columns P:V
70 Scenario 1.A: Generation (contracted)
• Solar (stand-alone or hybrid) makes up
75% (65%) of contracted generation in
2030 (2035)
• Curtailment risk of VER resources only
partially addressed in this analysis;
additional analysis warranted
• Dashboard File:
• MWh
• Portfolio Summary I: columns V:AB
• Portfolio Summary II: columns AB:AH
71 Scenario 1.A: ELCC – Resource Adequacy
• Solar (stand-alone or hybrid)
makes up 63% (47%) of firm
capacity in 2030 (2035)
• The more local capacity built into
the portfolio, the less opportunity
for other technologies types to be
added
• Model calls on longer duration
storage in part to benefit from
larger ELCCs to satisfy the RA
constraint
• Dashboard File:
• Worktab: RA Constraint
• Firm ELCC: columns N:T
• Breakdown of ELCCs: columns AI:AL
• Adjust cell AF1
2030 2035
72 Scenario 1.A: Hourly Dispatch (2024)
Jan Apr
Jul Oct
• The gap between the white
line (busbar_load) and the
black line (total_supply)
represents market activity
• Purchases are when load
is greater than supply
• Sales are when supply is
greater than load
Dashboard File:
Worktab:
dispatch_tech_total
Pivot Table: columns CP:DF
Note: be sure to refresh
table when updating year of
interest on
meet_load_constraint tab
73 Scenario 1.A: Hourly Dispatch (2030)
Jan Apr
Jul Oct
• VCE is a net buy during the
early morning hours
throughout the year
• VCE is a net seller for the day
and most of the evening in
non-winter months
• Max sales are during
morning and afternoon
peaks
Dashboard File:
Worktab:
dispatch_tech_total
Pivot Table: columns CP:DF
Note: be sure to refresh
table when updating year of
interest on
meet_load_constraint tab
74 Scenario 1.A: Hourly Dispatch (2035)
Jan Apr
Jul Oct
• VCE is a net buyer during the
early morning hours
throughout the year
• VCE remains being a net seller
but reduces its long position
in the middle of the day with
addition of more storage
• Excess sales unrealistic (see
market constrained scenario)
Dashboard File:
Worktab:
dispatch_tech_total
Pivot Table: columns CP:DF
Note: be sure to refresh
table when updating year of
interest on
meet_load_constraint tab
75 Scenario 1.A: Market Participation
• In the unconstrained case, VCE
converts from a net buy to a net
seller in 2026 due to favorable unit
economics of candidate projects
reflected in the latest technology
cost assumptions
• Winter months have the greatest
dependency on the market
• Revision of regional modeling
warranted to reflect the impacts of
the IRA on candidate resources
• Dashboard File:
• Worktab: market_participation
• Annual Sales and Purchases: columns B:D
• Annual sales revenue and purchase
expense: columns: columns B:D
76 Scenario 1.A: Market Participation (cont)
• VCE has open positions in the early
morning hours across the entire
planning horizon
• VCE coverage over the later evening
periods improves over time
• VCE has adequate coverage over the
afternoon peak period across the
entire planning horizon
• Average hourly open positions with
the market differ greatly depending
on the month
• VCE’s long position in the middle of
the day gradually improves over time
• Dashboard File:
• Worktab: market_participation
• Avg hourly net sales and LMPs by
month-year: columns AY:AX
• Avg hourly net sales by year: columns
BE:BK
2030 2035
77 Scenario 1.A: Market Participation (cont)
• The percentage of hours in the year in which
VCE is short (i.e. purchasing energy from the
market) decreases from 50% and levels off at
around 37%
• The percentage of hours in the year in which
VCE is long (i.e. sells energy into the market)
ranges from 37%-48%
• Although VCE becomes less dependent on
market purchases over time (as reflected by
purchases as a % of annual load), the agency
still gets ~15% of its load from the market in
2035
• VCE sales increase year over year primarily
due to the favorable economics now being
reflected in the IRA-adjusted technology cost
curves, which makes most candidate
resources NPV positive under current LMP
pricing profiles*
• Dashboard File
• Worktab: market participation
• Columns: CM:CP
*Note: First Principles Advisory re-ran the optimization of VCE’s portfolio to reflect the IRA-adjusted cost curves released by the CPUC in early June; these costs curves were not used to determine the PSP developed by the CPUC’s RESOLVE model during the 2022 IRP cycle 78 Scenario 1.A: Costs
• Total costs of the portfolio represent the
aggregate of baseline, candidate and market
• Baseline costs reflect fixed PPA charges for
contracted projects
• Candidate costs reflect forecasted PPA charges from
incremental projects that would be added to the
portfolio
• Market reflects the net costs of load and total
supply settling in the market
• Note congestion is NOT accounted for in this analysis • Total costs are normalized to busbar load and
shown in black (secondary y-axis)
• Net market transactions flips from a net cost to
net benefit in 2026, likely reflecting an
unrealistic assumption that VCE will be able to
secure PPAs and favorable prices relative to
other retail providers
• The impact of this effect on the portfolio costs
increases over time and should be addressed in
subsequent studies
• Dashboard File:
• Worktab: NPV
• Costs information: columns H:N
79 Scenario 1.A:
Renewable Portfolio Standard (RPS)
• For the baseline case of 80% RPS by
2030, there is no incremental cost in
the model to satisfy this constraint
• The 100% by 2030 constraint in
scenario 1.B also doesn’t bind
• VCE far exceeds its total RPS target in
2030 and beyond
• Additional projects are added to the
portfolio in order to satisfy the RA
constraint
• The model is constrained to ensure
that a minimum of 25% of the RPS
constraint is met with generation
from local projects
• Dashboard File:
• Worktab: RPS
• Costs information: columns P:V
80 Sensitivity Case: Capped Market Transactions
81 Sensitivity Case: Market Transactions Policy
• Given VCE’s large concentration in hybrid
projects, the agency will be in a position
to engage in extensive market sales
throughout most of the year
• VCE should define a risk management
policy that defines the maximum allowed
market purchases and sales in any given
hour or slice of day
• Without this risk management policy
defined, future portfolio optimization
exercises will likely result in procurement
decisions that are not in alignment with
prudent scheduling practices
• There is significant variations in costs
depending on what gets assumed in the
model
Mkt sales
uncapped
Mkt sales
capped at 50 MW
82 Financial Summary: Market Transactions
• When capping market sales to 50 MW in any given hour, the cost premium in increasing VCE’s 2030 RPS target and keeping the 25% local requirement results in an additional charge of $13.5M in present value relative to VCE’s current policy (e.g., 80% RPS with a 25% carve out) • If VCE increases their 2030 RPS target to 100% but doesn’t require any additional local projects results in a cost savings of $19.4M • The NPV of the base case increases by $85.8M in scenario 3, an increase of 13%. This reflects the importance of VCE defining its risk management policy for how it wants to handle its net exposure with the market Index Natural Gas
Price
RPS 2030
Target
Local RPS
Requirement
Market Policy Local Hybrid
Capacity
(MW)
2024-2035 NPV
(2022 $M)
Delta
(2022 $M)
1.A P50 80% 25% Uncapped 65 619.6 0
1.B P50 100% 25% Uncapped 84 643.1 23.5
1.C P50 100% n/a Uncapped 0 586.1 -33.4
3.A P50 80% 25% Capped (50 MW) 65 705.4 0
3.B P50 100% 25% Capped (50 MW) 84 719.0 13.5
3.C P50 100% n/a Capped (50 MW) 0 686.1 -19.4
+$85.8M in costs
when capping sales
83 Procurement Implications
84 Procurement Recommendations (redacted)
85 Technology Breakeven Prices (redacted)
• Breakeven price is the levelized
PPA price that results in an NPV of
zero based on the levelized
benefits of energy and RA*
• Listed prices are the average
breakevens for 2024-2026
• Dashboard File:
• Worktab: Breakeven Prices
• Storage: Column A; rows 123-140
• Non-Storage: Column N; rows 178-214
*Breakeven prices do not include any benefit assumed from PCC1 attributes 86 Potential Next Steps
87 Topics for Additional Investigation
• Incorporate Slice-of-Day (SOD) into optimization logic used by the model • This study assumed ELCC values, per the methodology utilized in Commission’s IRP cycle • Conduct an all-source solicitation (to collect current market prices for PPAs) and re-optimize portfolio with these costs to determine least cost solution to fill VCE’s near term open position • Optimize the portfolio using nodal prices rather than systemwide zonal prices • This feature will provide a more accurate assessment of curtailment volumes for both baseline and candidate resources
• Direct integration of GHG accounting; 24/7 GHG-free modeling • Integrate CPUC’s Clean System Power GHG accounting methodology (or other logic) into the model to estimate what the incremental costs would be for VCE
• Develop Stochastic Optimization
• This functionality for the handling of uncertainty in key variables within the model when selecting candidate resources
• Currently the model conducts deterministic studies of multiple scenarios to estimate the impacts of uncertainty in future conditions
88 Key Modeling Inputs / Methodologies
89 VCE Load
• TEA provided VCE and First Principles Advisory
with an updated net retail forecast across the
entire planning horizon of 2024-2035
• Forecast is NET of BTM solar production
• Updated forecast reflects higher (35% vs 18%)
load growth across the planning horizon of 2024-
2035; this is primarily due to building and
transportation electrification
• Comparatively, the increase in annual peak demand is
18%
• The implicit assumption in the forecast is that
VCE will avoid sharp increases in its peak demand
either passively (from natural customer behavior)
or actively (from customer programs)
• Minimizing increases in peak demand is critical is critical because this impacts the amount of RA VCE will be
responsible for procuring
• The RA constraint is the most binding constraint in the model (i.e., this is what forces VCE to go out and contract for additional resources to be in compliance)
*Note: load in dashboard file represents busbar load (i.e. retail load grossed up for T&D losses) 90 VCE Load Profile
• Customer programs / rate design will be key drivers in shaping VCE’s load shape • Further out on the horizon, winter peak morning leads begin to present similar risks summer peak afternoon loads Jan
Apr
Jul
Oct
91 RA Forecast (redacted)
92 NG Profile (redacted)
• Customer programs / rate design will be key drivers in shaping VCE’s load shape • Further out on the horizon, winter peak morning leads begin to present similar risks summer peak afternoon loads 93 Plexos LMP Profiles (P50) (redacted)
• Prices in the late evening / early morning increase
• Even with increasing load, prices in the middle of remain suppressed Jan
Apr
Jul
Oct
94 Plexos LMP Profiles (P95) (redacted)
• Prices in the middle of the day are elevated in the winter months but muted in remaining parts of the year Jan
Apr
Jul
Oct
95 Technology Cost Curves
• First Principles Advisory has taken the cost curves from the CPUC’s latest Inputs and Assumptions document which can be found here. • The impacts of the Inflation Reduction Act (IRA) has been applied to all resource types through 2048
• The CPUC applied additional cost modifications to solar, onshore wind, and Li-ion batteries to reflect contemporaneous stressed market conditions
• First Principles Advisory assumed an additional 20% of tax incentives for Li-Ion storage (bringing the ITC up to 50%) for the low-cost battery cost curve
96 Technology Cost Curves: Overall
• Total levelized fixed costs include
both CAPX and fixed O&M charges
• IRA has increased the cost
competitiveness of clean, firm
resources (e.g., geothermal,
biomass, and non li-ion based
storage)
• RA Only curve represents internal
forecast of annual price for RA only
contracts
97 Technology Cost Curves: Solar
• IRA enables solar project to now also
have access to the Production Tax
Credit (PTC) which is a tax credit of
$25/MWh
• Given the more favorable economics
of the PTC over the Investment Tax
Credit (ITC), the prevailing notion is
that developers will opt for the PTC
• CPUC assumes developers meet
prevailing wage and apprenticeship
rules to qualify for “Bonus” incentive
Updated
Original
98 Technology Cost Curves: Wind
• IRA extended availability of PTC,
which was originally scheduled to
expire in 2026 for onshore wind
• CPUC assumes offshore wind will take
ITC; thus no changes from IRA until
post 2035; CPUC also increased the
cost slightly from last IRP cycle
• CPUC assumes developers meet
prevailing wage and apprenticeship
rules to qualify for “Bonus” incentive
Updated
Original
99 Technology Cost Curves: Storage
• Although stand-alone storage now
qualifies for ITC, the CPUC adjustments
to account for strained market
conditions for li-ion storage result in an
overall cost increase for lithium-based
storage projects
• Flow batteries see a substantive affect
from the IRA tax incentives as does long
duration energy storage (LDES)
technology, which represents iron air
batteries
• CPUC assumes developers meet
prevailing wage and apprenticeship rules
to qualify for “Bonus” incentive
Updated
Original
100
Technology Cost Curves: Clean, Firm
• Under the IRA, geothermal and
biomass now qualify for the 30%
ITC, previously this was 10%
• CPUC assumes developers meet
prevailing wage and
apprenticeship rules to qualify for
“Bonus” incentive
Updated
Original
101
ELCC Factors
102
Modeling Process
Production Cost Modeling
(Plexos)
• IRP Buildout (IRP)
•NG Forecast (TEA)
•GHG Forecast (CEC)
• PCC1 Forecast (TEA)
•Adjusted Net Load / Multiple
Weather Years (FPA/CPUC/CEC)
Portfolio Optimization
(GridPath)
• LMP Profiles (Plexos)
• RA Forecast (TEA)
• PCC1 Forecast (TEA)
• VCE Policy (VCE)
• Step 1: Generate regional WECC prices for 2024, 2026, 2028, 2030, 2032, and 2035 using zonal Plexos model based on CalCCA and First Principles Advisory databases
• Step 2: Along with LMP profiles, apply other market forecasts to VCE portfolio to identify optimal buildout of incremental contracts to determine least cost solution that satisfies the agencies policy goals and regulatory requirements 103
Key Modeling Assumptions
• Typical Week temporal resolution
• 168 continuous hours selected for each calendar month • 2016 dispatch intervals in each calendar year
• 3 adjusted net load weather years modeled in Plexos for each calendar year
• High, med, low
• Average of the 3 runs are applied downstream
• All dollar values are reported in real terms (2022$)
• All time periods are listed in pacific standard time (PST) 104
GridPath vs Match
Differences
Topic VCE PCE
Fundamental Model Plexos WECC zonal
db
Ascend’s
PowerSIMM*
Planning Horizon 2024-2035 2025
Functionality CEM, PCM, PEM PEM
Support /
Development
GridPath is
supported by 3rd
party (Blue Marble)
MATCH is
unsupported
VER profiles n/a Generates profiles
Primary objective
function
Dispatching units in
most economic
manner
Matching hourly
supply to load
RPS Policy Annual 24/7/365
Similarities
Open-source
Month-Hour; Day of
Week Dispatch
Stochastic weather inputs
Deterministic
Scenario analysis
105
Item 15
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 15
TO: Board of Directors
FROM: Edward Burnham, Director of Finance & Internal Operations SUBJECT: Allocation of 2022 Net Margin
DATE: July 13, 2023
RECOMMENDATION
Adopt a resolution approving the allocation of the $5.3M 2022 Audited Net Margin between cash reserves and local program reserve (LPR) as follows:
1. $4,611,000 to cash reserves to reach cash reserve targets for this fiscal year;
2. Balance of 2022 net margin of $712,500 to the Local Programs Reserve (LPR).
OVERVIEW
This staff report presents options related to the allocation of VCE’s audited net margin for 2022.
VCE’s audited financial statements can be found here. Taking into account the Board adopted Dividend Program policy (2019), as well as available and forecast cash reserves, Staff analyzed options outlined below for VCE’s 2022 net margin of $5.3 million. Based on this analysis, Staff concluded that the following allocation met VCE’s policy objectives while providing the greatest material net benefit:
• Minimum allocation of $217,000 to the Local Programs Reserve • Minimum allocation of $4,611,500 to cash reserves
• Discretionary Allocation (After Cash Reserves) of $495,000
BACKGROUND AND ANALYSIS
The Board adopted the VCE Rate Structure and Dividend Program Guidelines on June 17, 2019, to guide the allocation of the audited net margin for each year. The guidelines can be found here.
Key test of the Dividend Program:
• Basic Test: A minimum 5% net margin must be achieved before considering allocation of net margin above 5% to Cash Reserves, Local Program Reserves, and/or Cash Dividends Based on audited 2022 Financial Statements, VCE achieved a 6.14% net margin, meeting the basic Dividend Program test. Therefore, the Board must consider how to allocate the net margin above 5%. As noted when the Board adopted the Dividend Program Policy in June 2019, a 5% minimum net margin is in the lower range of typical net margin goals for the utility sector and most other industries.
106
Item 15
Dividend Program Formula
The adopted Dividend Program formula recommends allocating the net margin as follows:
• Net margin less than or equal to 5% is to be allocated as follows:
o At least 5% of the first 5% of net margin goes to VCE’s Local Programs Reserve for program implementation
o The balance goes to cash reserves
• Net margin above 5% is to be allocated as follows:
o At least 50% to cash reserves until reserves targets are met o Remainder allocated amongst dividends and Local Program Reserve (Board discretion)
Staff applied the Dividend Program formula above to VCE’s 2022 audited net margin. The following table summarizes the analysis.
Table 1 – 2022 Audited Net Margin Summary
As shown in Table 1, applying the basic Dividen Program formula results in $495.5K of discretionary funds.
///
///
Description
Audited 2022
Results
Electricty Sales 86,662,000
Operating Expense 80,897,000
Operating Margin 5,765,000
Prinipal Debt Payments 441,000
Adjusted Net Margin less prinicpal Debt Payments 5,324,000 Adjusted Net Margin Pectentage 6.14%
Allocation Amount <=5% 4,333,000
Allocation Amount > 5% 991,000
Aloocation of Net Margin up to 5% Perectage
Allocation
Amount
Cash Reserves Allocation 95% 4,116,000 Minimum
Local Programs Allocation 5% 217,000 Minimum
Aloocation of Net Margin above 5% Perectage
Allocation
Amount
Allocation to Cash Reserves 50% 495,500 Minimum
Discretionary Allocation (After Cash Reserves) 50% 495,500 Maximum 107
Item 15
Allocation Scenarios
Staff analzyed three basic scenarios related to the allocation of discretionay funds to help inform its recommendation and the Board decision.
Scenario 1: Additional Programs Funds (Staff Recommended) Scenario 2: Additional Cash Reserves
Scenario 3: Customer Dividends
Based on the cash reserve forecast in the coming years, Staff is recommending the Board allocate the discretionary allocation of the full $495.5K to local programs. Key factors in staff’s analysis of these options include:
• Cash Reserves Option. This amount of additional cash reserves would not have a material effect in obtaining VCE’s initial investment grade credit rating • Dividend Option. Available funds for dividends would provide less than a 1% discount (3approx. $1.50/month reduction in the average residential customer bill); small impact on customer bills. Note: VCE currently provides a ~2.5%/$1M annually in discounts to 25% of customers (CARE and FERA)
• Local Programs Option – Recommended. Additional program funds are needed to execute VCE’s adopted VCE’s 3-Year Programs Plan; staff believes this provides the largest positive material impact related to the available discretionary revenues.
Note: In the near future, there is an increased likelihood that the dividend can be implemented as additional VCE power purchase agreements become operational, regulatory factors improve, and additional cash reserves are built for financial stability.
Discretionary Allocation (After Cash Reserves) 50% 495,000 Maximum Cash Reserves 0% -
Local Programs (Targeted 2024 Spend) 100% 495,500
Customer Dividends (Targeted 2024 Spend) 0% -
Discretionary Allocation (After Cash Reserves) 50% 495,000 Maximum Cash Reserves 100% 495,500
Local Programs (Targeted 2024 Spend) 0% -
Customer Dividends (Targeted 2024 Spend) 0% -
Discretionary Allocation (After Cash Reserves) 50% 495,000 Maximum Cash Reserves 0% -
Local Programs (Targeted 2024 Spend) 0% -
Customer Dividends (Targeted 2024 Spend) 100% 495,500
108
Item 15
For reference, if the Board decided to institute a small dividend this year rather than the $0 recommended by Staff, the effects would be:
• Each 1% dividend would be a reduction of $800,000 in cash reserves and reduce days cash on hand going forward by approximately five days
Notes: (1) a 1% dividend would be approximately $1.50/month reduction in the average residential customer bill and an approximately $3.75/month reduction in the average small commercial customer bill; (2) anecdotal information from other CCAs indicate that these levels of customer dividends/discounts while helpful in communicating a CCA’s value do not have significant effects on customer retention or new customer recruitment.
Community Advisory Committee (CAC) Consideration
The staff recommendation was presented to the CAC at its June 22, 2023 meeting. The CAC unanimously supported the staff recommendation.
CONCLUSION
Based on the factors outlined above, staff believes its recommendation for VCE’s 2022 audited $5.3M net margin is fiscally prudent and results in the most significant material impact.
ATTACHMENTS:
1. Resolution – Allocation of 2022 Net Margin
109
Item 15
VALLEY CLEAN ENERGY ALLIANCE
RESOLUTION NO. 2023 - ___
A RESOLUTION OF THE BOARD OF DIRECTORS OF VALLEY CLEAN ENERGY ALLIANCE
APPROVING THE RECOMMENDED ALLOCATION OF NET MARGIN FOR THE AUDITED YEAR ENDED DECEMBER 31, 2022
WHEREAS, Valley Clean Energy (“VCE”) was formed as a community choice aggregation agency (“CCA”) on November 16, 2016, under the Joint Exercise of Power Act, California Government Code section 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, the Board adopted a Rate Structure & Dividend Program Guidelines (Dividend Program) on June 17, 2019, to be effective starting at the beginning of the following fiscal year on July 1, 2019; and
WHEREAS, the Dividend Program specifies how audited positive Net Margin for each fiscal year can be allocated amongst cash reserves, customer dividends, and local program reserve (LPR), at the Board’s discretion; and
WHEREAS, VCE staff analyzed the allocation options for Board consideration based on the final, audited Net Margin for the year ended December 31, 2022.
NOW, THEREFORE, the Board of Directors of Valley Clean Energy resolves as follows:
1. For the audited year ended December 31, 2022, allocate the Net Margin of $5.324 million as follows: $712,500 to local program reserve, $0 to cash dividends, and the $4.611 million balance to cash reserves.
PASSED, APPROVED AND ADOPTED, at a regular meeting of Valley Clean Energy, held on the ____ day of _______________, 2023, by the following vote:
AYES:
NOES:
ABSENT:
ABSTAIN:
_____________________________________
Tom Stallard, VCE Chair
__________________________________
Alisa M. Lembke, VCE Board Secretary
110