Agenda packet — Valley Clean Energy Board of Directors, September 8, 2022

VCE 9/8/2022 Board Meeting Agenda Page 1 of 3
Regular Meeting of the Valley Clean Energy Alliance
Board of Directors
Thursday, September 8, 2022 at 5 p.m.

Via Video/Teleconference
Pursuant to Assembly Bill 361 (AB 361), legislative bodies may meet remotely without listing the location of each remote attendee, posting agendas at each remote location, or allowing the public to access each location, with the adoption of certain findings. The Board of Directors found that the local health official recommended measures to promote social distancing and authorized the continuation of remote meetings for the foreseeable future. Any interested member of the public who wishes to listen in should join this meeting via teleconferencing as set forth below.

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/82856824382
Meeting ID: 828 5682 4382
b. By phone
One tap mobile:
+1-669-900-4128,, 82856824382# US
+1-669-444-9171,, 82856824382# US
Dial:
+1-669-900-9128 US
+1-669-444-9171 US
Meeting ID: 828 5682 4382
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: Jesse Loren, (Chair/City of Winters), Tom Stallard (Vice Chair/City Woodland), Don Saylor (Yolo County), Dan Carson (City of Davis), Wade Cowan (City of Winters), Mayra Vega (City of Woodland), Gary Sandy (Yolo County), and Lucas Frerichs (City of Davis) 1 VCE 9/8/2022 Board Meeting Agenda Page 2 of 3
5:00 p.m. Call to Order

1. Welcome

2. Public Comment: This item is reserved for persons wishing to address the Board on any VCE-related matters that are not otherwise on this meeting agenda, or are listed on the Consent portion of the agenda. Public comments on matters listed on the regular agenda shall be heard at the time the matter is called. As with all public comment, members of the public who wish to address the Board are customarily limited to two minutes per speaker, electronically submitted comments should be limited to approximately 300 words. Comments that are longer than 300 words will only be read for two minutes. All electronically submitted comments, whether read in their entirety or not, will be posted to the VCE website within 24 hours of the conclusion of the meeting. See below under PUBLIC PARTICIPATION on how to provide your public comment.

CONSENT AGENDA

3. Renew authorization of remote public meetings as authorized by Assembly Bill 361.

4. Approve July 14, 2022 Board meeting Minutes.

5. Receive 2022 Long Range Calendar.

6. Receive Financial Updates – A) June 30, 2022 and B) July 31, 2022 (unaudited) financial statements.

7. Receive Legislative update.

8. Receive August 31, 2022 Regulatory update provided by Keyes & Fox.

9. Receive Community Advisory Committee August 25, 2022 meeting summary.

10. Receive Bi-annual Enterprise Risk Management Report.

11. Accept and attest the accuracy of Valley Clean Energy’s 2021 Power Content Label for the Standard Green and UltraGreen products.

12. Approve Amendment to 2022 Budget for Agricultural Flexible Irrigation Technology (AgFIT) Pilot Program.

13. Approve agreement with PFM Financial Advisors to provide financial advisor services.

14. Receive update on Wholesale Energy Services.

REGULAR AGENDA

15. Receive Mid-year update on 2022 Customer Rates. (Information)

16. Introduce and Receive input on a Rate Adjustment System Concept. (Information/Discussion)

17. Receive VCE Strategic Plan update. (Information)

18. Receive AgFIT Pilot Program implementation update. (Information)

19. 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.

20. Adjournment: The next regular meeting is scheduled for Thursday, October 13, 2022 at 5 p.m. via video/teleconference.

PUBLIC PARTICIPATION INSTRUCTIONS FOR VALLEY CLEAN ENERGY BOARD OF DIRECTORS SPECIAL MEETING ON THURSDAY, SEPTEMBER 8, 2022 AT 5:00 P.M.:

PUBLIC PARTICIPATION. Public participation for this meeting will be done electronically via e-mail and during the meeting as described below.
2 VCE 9/8/2022 Board Meeting Agenda Page 3 of 3
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.

Verbal public participation during the meeting: If participating during the meeting, there are two (2) ways for the public to provide verbal comments:
1) 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”. 2) If you are attending by phone only, you will need to press *9 to raise your hand. When called upon, please 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 Comments: If you wish to make a public comment at this meeting, please e-mail your public comment to [email protected] or notifying the host as described above. Written public comments that do not exceed 300 words will be read by the VCE Board Clerk, or other assigned VCE staff, to the Committee 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 3, Public Comment. Written public comment on individual agenda items should include the item number in the “Subject” line for the e-mail and the Clerk will read the comment during the item. Items read cannot exceed 300 words or approximately two (2) minutes in length. All written comments received will be posted to the VCE website. E-mail comments received after the item is called will be distributed to the Board and posted on the VCE website so long as they are received by the end of the meeting.

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]. 3 Item 3

VALLEY CLEAN ENERGY ALLIANCE
Staff Report - Item 3
____________________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Executive Officer
Alisa Lembke, Board Clerk/Administrative Analyst
SUBJECT: Renew Authorization to continue Remote Public Meetings as authorized by Assembly Bill 361
DATE: September 8, 2022
Recommendation
VCE Board renew authorization for remote (video/teleconference) meetings, including any standing or future committee(s) meetings and Community Advisory Committee meetings, by finding:

1. Pursuant to Assembly Bill 361 (AB 361), that the COVID-19 pandemic state of emergency is ongoing.

Background/Summary of AB 361
Pursuant to Government Code Section 54953(b)(3) legislative bodies may meet by “teleconference” only if the agenda lists each location a member remotely accesses a meeting from, the agenda is posted at all remote locations, and the public may access any of the remote locations. Additionally, a quorum of the legislative body must be within the legislative body’s jurisdiction.

Due to the COVID-19 pandemic, the Governor issued Executive Order N-29-20, suspending certain sections of the Brown Act. Pursuant to the Executive Order, legislative bodies no longer needed to list the location of each remote attendee, post agendas at each remote locations, or allow the public to access each location. Further, a quorum of the legislative body does not need to be within the legislative body’s jurisdiction. After several extensions, Executive Order N-29-20 expired on September 30, 2021.

On September 16, 2021, the Governor signed AB 361, which kept some of the provisions of Executive Order N-29-20. Pursuant to Government Code Section 54953(e), legislative bodies may meet remotely and do not need to list the location of each remote attendee, post agendas at each remote locations, or allow the public to access each location.
4 However, legislative bodies must first find either that: (1) the legislative body is meeting during a state of emergency and determine by majority vote that meeting in person would present an imminent risk to the health or safety of attendees; or (2) state or local health officials impose or recommend social distancing measures. Government Code Section 54953(e)(1). The legislative body must make the required findings every 30 days, until the end of the state of emergency or recommended or required social distancing. Government Code Section 54953(e)(3). On January 1, 2024, Government Code Section 54953(e) is repealed.

The recommended action is required by AB 361 to continue meeting remotely during a declared state of emergency. Since March 1, 2022, the Yolo County Health Officer is no longer expressly recommending social distancing, although she still encourages the use of facial coverings/masks indoors. The VCE Board retains discretion under AB 361 to independently determine that remote meetings should continue because meeting in person would present imminent risks to the health and safety of attendees. Staff recommends that the Board make a finding that holding meetings in person would present an imminent risk to the public for the following reasons:
• The facilities in which the VCE Board meet were not designed to prevent the spread of infection by promoting mask usage, social distancing (including between Board members), or by use of increased ventilation/air filtration or other sanitary measures. • Some staff, Board members, and community members who would otherwise participate in VCE meetings to participate in Board meetings, and some of these community members are likely at high risk for serious illness from COVID-19 and/or live with someone who is high risk.

Staff continues to monitor the situation as part of our emergency operations efforts and will return to the Board every thirty (30) days or as needed with additional recommendations related to the conduct of public meetings.
5 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 July 14, 2022 meeting DATE: September 8, 2022

RECOMMENDATION
Receive, review and approve the attached July 14, 2022 meeting Minutes.

6 VCEA Minutes July 14, 2022 Board Meeting via Webinar Page 1 of 5

MINUTES OF THE VALLEY CLEAN ENERGY ALLIANCE

BOARD OF DIRECTORS REGULAR MEETING
THURSDAY, JULY 14, 2022
The Board of Directors of the Valley Clean Energy Alliance duly noticed their regular meeting scheduled for Thursday, July 14, 2022 at 5:00 p.m., to be held via Zoom webinar. Chair Loren established that there was a quorum present and began the meeting at 5:03 p.m.

Board Members Present: Jesse Loren, Tom Stallard, Dan Carson, Lucas Frerichs (departed at 6:30 p.m.), Mayra Vega (arrived during closed session), Angel Barajas (Alternate Yolo County)
Members Absent: Don Saylor, Wade Cowan, Gary Sandy
Welcome Chair Loren welcomed everyone.

Approval of
Agenda
Chair Loren asked that the Board approve the agenda. Director Stallard made a motion to approve the July 14, 2022 agenda, seconded by Director Barajas.

Motion passed with Directors Saylor, Sandy and Cowan absent.

Public Comment –
General, Consent,
and Closed Session
There were no verbal or written public comments on general items, consent items or Closed Session at this time. Please see written public comment section on page 4, when a written public comment was acknowledged as received and recorded into the Minutes.

CLOSED SESSION Chair Loren announced that the Board will go into Closed Session. It is anticipated that there will be nothing to report out. The Board convened into Closed Session at 5:06 p.m. The Board reconvened into the regular Board meeting at 5:36 p.m.

Reconvened into
regular Board
meeting
Chair Loren announced that there was nothing to report out from Closed Session. VCE Executive Officer introduced VCE’s intern Scott Adler to the Board and those present.

Approval of
Consent Agenda /
Resolution 2022-
018 through
Resolution 2022-
020
Chair Loren announced that there is a correction to Item 11 – quarterly Customer Enrollment update on page 1, slide 1 of the report. Corrections will be made and the report will be distributed to the Board and posted to the website.

Motion made by Director Frerichs to approve the consent agenda items, seconded by Director Barajas. Motion passed with Directors Saylor, Sandy and Cowan absent. The following items were:

5. Authorized to continue remote public meetings as authorized by Assembly Bill 361;

6. Approved June 9, 2022 Board meeting Minutes;

7. Received 2022 Long Range Calendar;

8. Received Financial Updates – May 31, 2022 (unaudited) financial statements; 7 VCEA Minutes July 14, 2022 Board Meeting via Webinar Page 2 of 5

9. Received July 6, 2022 Regulatory update provided by Keyes & Fox;

10. Receive Community Advisory Committee June 23, 2022 meeting summary;

11. Received quarterly (April – June) Customer Enrollment update and will await update on page 1, slide 1 of the staff report;

12. Received update on SACOG Grant – Electrify Yolo Project;

13. Received memorandum on Donald Dame agreement for consulting services approving a 6 month extension and increasing the not to exceed amount;

14. Received copy of signed Amendment 4 to agreement with Jim Parks Consulting extending the contract to expire on December 31, 2022 and increasing the not to exceed amount;

15. Ratify signed agreement with First Principles Advisory for Integrated Resource Planning portfolio modeling services for a not to exceed amount of $33,750 terminating on December 1, 2022 as Resolution 2022-018;

16. Approved Amendment 5 to Keyes & Fox agreement to extend 18 months through December 31, 2023 and increase the not to exceed amount as Resolution 2022-019;

17. Adopted VCE Debt Policy as Resolution 2022-020; and,

18. Reappointed David Springer (Winters), Mark Aulman (Woodland), and Cynthia Rodriguez (Yolo County); and appointed Rahul Athalye to the City of Davis seat on the Community Advisory Committee, each for a three (3) year term to expire June 2025.

As mentioned above, there were no verbal or written public comments.

Item 19: Approve
Amendment 1 to
the Power
Purchase
Agreement (PPA)
with Resurgence
Solar I, LLC related
to price and terms.
(Action) Resolution
2022-021
VCE Staff Gordon Samuel informed those present that Amendment 1 reflects some adjustments to the terms of the Resurgence Solar power purchase agreement executed in January 2021. This project is for 90 Megawatt (MW) photovoltaic and 75 MW battery storage facility located in San Bernardino County for a 20 year PPA. There have been some uncharacteristic and unique challenges facing the entire renewable industry, which has put pressure on the pricing and schedule of this project and others. VCE worked with the developer NextEra Energy Resources to amend the PPA adjusting the price, schedule, development securities, and developer contribution to program (workforce development and local sustainability) funding. This project provides 1/3 of our renewable energy, resource adequacy and mid-term reliability to VCE’s portfolio.

There were no questions from the Board. There were no verbal or written public comments.

Director Stallard made a motion to adopt a resolution authorizing the Executive Officer to (1) execute Amendment 1 to the Resurgence Solar 1 Power Purchase Agreement (PPA) substantially in the form attached and (2) authorizes the Executive Officer, in consultation with General Counsel, to make minor changes to the PPA Amendment 1 so long as the term and price are not changed. This motion was seconded by Director Carson. The motion passed as Resolution 2022-021 by the following vote:
8 VCEA Minutes July 14, 2022 Board Meeting via Webinar Page 3 of 5 AYES: Loren, Stallard, Carson, Vega, Frerichs, Barajas
NOES: None
ABSENT: Saylor, Cowan, Sandy
ABSTAIN: None
Item 20: Consider
participating in CC
Power geothermal
projects: A) Ormat
Nevada Inc. and B)
Open Mountain
Energy, LLC
(Action) Resolution
2022-022 and
Resolution 2022-
023
Mr. Sears introduced this item. Mr. Samuel informed those present that in September 2021 CC Power solicited proposals for Firm Clean Resources (FCR), for example geothermal or biomass, with a minimum 80% capacity factor. CC Power ran an analytics model, conducted interviews and negotiated with developers on two (2) projects: Open Mountain Energy LLC (OME) and a portfolio of projects from Ormat Nevada, Inc. (Ormat). The California Public Utilities Commission (CPUC) adopted the Mid-term Reliability Procurement Order (MTR) in June 2021, which requires Load Serving Entities (LSE’s) to collectively procure 11,500 MW of new resources and some megawatts (4,500 MW) of obligation are subject to specific category requirements. The two projects being considered by the Board tonight would fulfill the need for FCR procurement category of the MTR Order. There were no verbal or written public comments.

Director Stallard made a motion to authorize the Executive Officer to execute on behalf of Valley Clean Energy as a member of CC Power the following agreements and any necessary ancillary documents for the geothermal projects with a delivery term of 20 years:
a. Ormat Nevada Inc. (Ormat) Portfolio of Geothermal Projects b. Open Mountain Energy LLC., Fish Lake Geothermal (OME) This motion was seconded by Director Frerichs. The motion passed as Resolution 2022-022 (Ormat Nevada Inc.) and Resolution 2022-023 (Open Mountain Energy, LLC) by the following vote:

AYES: Loren, Stallard, Carson, Vega, Frerichs, Barajas
NOES: None
ABSENT: Saylor, Cowan, Sandy
ABSTAIN: None
Public Comment -
General and
Consent
Chair Loren announced that there was a written public comment submitted late today from James Skeen referring to a comparison between VCE and SunRun.

Chair Loren wanted to acknowledge that a written public comment was received and have it documented in the Minutes. The written public comment stated that “I have received an offer from Sunrun to install additional PV on my home at no cost. I would be obligated to pay Sunrun $0.103/kWh which is less expensive than VCE. Thought you should know. Signed Jim Skeen (not a VCE customer).” This written public comment will be distributed to the Board and posted to the VCE website.

Item 21: Consider
proposed three-Mr. Sears introduced this item. VCE Staff Edward Burnham provided a summary, background and a recap of the updated Customer Rate/Product 9 VCEA Minutes July 14, 2022 Board Meeting via Webinar Page 4 of 5 tiered Customer
Rate Structure /
Product options.
(Action) Resolution
2022-024
Options – three tiers adding a third option called Base Green to the Standard Green (existing default) and UltraGreen (existing opt-up) options. If adopted, the three-tiered rate structure would be implemented in 2023 and incorporated into the 2023 Customer Rate Setting process. He noted that the differentiation of the Base Green option is that the rate is priced 0.5% below PG&E, renewable energy sources target 0-5% above CPUC Renewable Portfolio Standard (RPS) mandate, and ineligible to participate in customer dividend program and reduced access to customer program benefits. In addition, if approved, California Alternative Rates for Energy (CARE) and Family Electric Rates Assistance (FERA) customers would be automatically enrolled in the Base Green option.

The Board discussed funding sources to customers to pay their electric utility bills, and other options, such as a LED light bulb replacement program, to assist customers reduce electricity usage.

Verbal Public Comment: Christine Shewmaker stated that the CAC had several meetings where this item was discussed and looked at the item from several different perspectives. She thinks that as VCE moves forward, VCE should be flexible on the three various rate structures to help achieve goals outlined in VCE’s Strategic Plan.

There were no additional verbal public comments and there were no written public comments.

Motion made by Director Frerichs to:

1. Approve the attached resolution adopting a new three-tiered customer rate structure adding a new least cost “Base Green” option in 2023 to the existing “Standard Green” (default rate) and “UltraGreen” (existing 100% renewable rate) customer rate options;

2. Approve enrolling California Alternative Rates for Energy (CARE) and Family Electric Rates Assistance (FERA) customers in the Base Green option with Standard Green features as described in the staff report.

3. Direct staff incorporate recommendations 1 and 2 into the 2023 Customer Rate Setting process.

This motion was seconded by Director Barajas. Motion passed as Resolution 2022-024 by the following vote:

AYES: Loren, Stallard, Carson, Vega, Frerichs, Barajas
NOES: None
ABSENT: Saylor, Cowan, Sandy
ABSTAIN: None
10 VCEA Minutes July 14, 2022 Board Meeting via Webinar Page 5 of 5 Item 22: Receive
mid-year financials
update.
(Information)
Mr. Sears introduced this item. Mr. Burnham summarized 2022 budget development, 2022 financials update and additional factors, and multi-year forecast update. There were no verbal or written public comments.

Director Lucas Frerichs departed at 6:30 p.m.

Item 23: Approve
Amendment 2 and
VCE’s JPA updating
Exhibits. (Action).

Resolution 2022-
025
Mr. Sears introduced this item. He informed those present that the proposed Second Amendment to the Joint Powers Agreement (JPA) updates the annual energy use and voting shares exhibits (Exhibits C – Annual Energy and D – Voting Shares) to reflect annual changes in energy usage and creates a more streamlined process for updating Exhibits C and D. There were no verbal or written public comments.

Director Carson made a motion to adopt resolution approving Second Amendment to Valley Clean Energy Alliance Joint Exercise of Powers Agreement (JPA Agreement) and authorizing the Executive Officer, in consultation with legal counsel, to take necessary implementing actions.

This motion was seconded by Director Vega. Motion passed by the following vote:

AYES: Loren, Stallard, Carson, Vega, Barajas
NOES: None
ABSENT: Saylor, Cowan, Sandy, Frerichs
ABSTAIN: None
Item 24: Board
Member and Staff
Announcements
Director Carson wanted to thank Yvonne Hunter for all of her work and contributions to VCE and the Community Advisory Committee. Chair Loren also thanked Ms. Hunter for all of her contributions. There were no other Director announcements. Mr. Sears also thanked and is grateful for Ms. Hunter’s photos, expertise and guidance. Ms. Hunter thanked the Board and VCE for the gift of working with the communities and other CCAs prior to VCE’s launch and post launch for numerous years. It has been an honor to work with talented and dedicated Staff, Board and CAC members.

Chair Loren wanted to end the meeting honoring Yvonne Hunter for her great contributions, creativity, intelligence, her dedication and uplifting nature that she has brought to all of us at Valley Clean Energy.

Chair Loren announced that the Board’s August 11, 2022 meeting has been cancelled. The next regular meeting is scheduled for Thursday, September 8, 2022 at 5 p.m.

Adjournment Chair Loren adjourned the regular Board meeting at 6:39 p.m.

Alisa M. Lembke
VCEA Board Secretary
11 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 2022 Long-Range Calendar DATE: September 8, 2022
Recommendation
Receive and file the 2022 Board and Community Advisory Committee long-range calendar listing proposed meeting topics.

Please note that CalCCA’s Annual meeting has been scheduled (tentatively) for May 17-23, 2023 in San Diego.
12 8/26/2022

VALLEY CLEAN ENERGY
2022 Meeting Dates and Proposed Topics
Board and Community Advisory Committee (CAC)
(CAC: Topics and Discussion Dates may change as needed)

MEETING DATE TOPICS ACTION
January 13, 2022
Special Meeting
scheduled for
January 27, 2022
Board • Election of Officers for 2022 (Annual)
• Near-term Procurement Directives and Delegations for 2022 Power Procurement Activities
• Calendar Year Budget and 2022 VCE customer rates
• GHG Free Attributes
• 2022 Legislative Platform
• Receive CAC 2021 Calendar Year End Report (Annual)
• 2021 Year End Review: Customer Care and Marketing
• Action
• Action
• Action
• Action
• Action
• Information
• Information
January 27, 2022
January 20, 2022
Advisory
Committee
• 2022 Task Groups Tasks/Charge (Annual)
• Update on 2022 Power Charge Indifference Adjustment (PCIA) and Rates
• Carbon Neutral by 2030 Study
• CC Power long duration storage
• Draft Collections Policy
• Update on customer programs development (draft Heat Pump Pilot Program)
• Action
• Discussion/Action
• Discussion/Action
• Information
• Information/Discussion
• Information
February 10, 2022 Board • CC Power long duration storage • Update on customer programs development
• Update on 2022 PCIA and Rates
• Update on Time of Use (TOU)
• Update on SACOG Grant – Electrify Yolo
• Strategic Plan Update (Annual)
• Carbon Neutral Report
• Action
• Information
• Information
• Information
• Information
• Information
• Information/Discussion
February 24, 2022 Advisory
Committee
• Power Procurement / Renewable Portfolio Standard Update • Time of Use (TOU) and Bill Protection
• Final Draft Collections Policy
• Customer program concept (Heat Pump Pilot Program)
• 2022 Task Group – energy resiliency
• Information
• Discussion/Action
• Action
• Discussion/Action
• Discussion/Action
13 March 10, 2022 Board • Receive Enterprise Risk Management Report (Bi-Annual) • Collections Policy
• Presentment of customer program concept (Heat Pump Pilot Program)
• Time of Use (TOU) Bill Protection
• Ag FIT (Flexible Irrigation Technology) pilot program • Information
• Discussion/Action
• Action
• Discussion/Action
• Discussion/Action
March 24, 2022 Advisory
Committee

WOODLAND
• Customer program concept (draft EV Rebates Program)
• CC Power long duration storage project
• Overview of VCE Forecasting
• Information
• Information
• Information/Discussion
April 14, 2022 Board • Update on SACOG Grant – Electrify Yolo • 7/1/21 thru 12/31/21 Audited Financial Statements (James Marta & Co.)
• CC Power long duration storage project
• Information
• Action
• Discussion/Action
April 28, 2022 Advisory
Committee
• Program Concepts Development (EV Rebates Program)
• Update on Customer Dividend and Programs Allocation
• Forecasting – load and power costs
•
• Discussion/Action
• Information
• Information
• Discussion
May 12, 2022 Board • Update on Customer Dividend and Programs Allocation • Presentment of customer program concept (EV Rebates Program) • Appointment of At-Large Members to the CAC
• Information
• Action
• Action
May 26, 2022 Advisory
Committee
• Forecasting – financial modeling
• Draft Rate Structure
• Net Energy Metering (NEM) 3.0 Update
• Information
• Information/Discussion
• Information
June 9, 2022 Board • Opt-Out Fees
• Update on 3-Year Programs Plan
• Forecasting
• Draft Rate Structure
• Net Energy Metering (NEM) 3.0 Update
• Information
• Information
• Information
• Information/Discussion
• Information
June 23, 2022 Advisory
Committee
• Draft Rate Structure
• Update 3-Year Programs Plan
• Review CAC Charge (Annual)
• Discussion/Action
• Information/Discussion
• Discussion
July 14, 2022 Board • Re/Appointment of Members to Community Advisory Committee (Annual)
• Update on SACOG Grant – Electrify Yolo
• Action
• Information
14 • Draft Rate Structure
• Quarterly Customer Enrollment Update
• Discussion/Action
• Information
July 28, 2022

NO MEETING
Advisory
Committee
This meeting has been cancelled.

August 11, 2022

NO MEETING
Board This meeting has been cancelled.

August 25, 2022 Advisory
Committee
• Power Procurement / Renewable Portfolio Standard update • Mid-year 2022 rates update
• Quarterly Customer Enrollment Update
• Information
• Information
• Information
September 8, 2022 Board • Certification of Standard and UltraGreen Products (Annual) • Enterprise Risk Management Report (Bi-Annual)
• Mid-year 2022 rates review
• Action
• Information
• Information/Discussion
September 22, 2022 Advisory
Committee
• Legislative End of Session Update
• 2023 Draft Operating Budget
• Preliminary discussion of CAC Year End Evaluation
• Integrated Resource Plan / Public Workshop (IRP – update due 11/1/2022)
• Information
• Information
• Discussion
• Discussion/Action
October 13, 2022 Board • Update on SACOG Grant – Electrify Yolo • Update on 2023 draft Operating Budget
• Quarterly Customer Enrollment Update
• Integrated Resource Plan (IRP update due 11/1/22)
• Information
• Information
• Information
• Discussion/Action
October 27, 2022 Advisory
Committee
• Update on Power Content Label Customer Mailer
• Review Draft CAC Evaluation of Calendar Year End (Annual) • Review 2023 customer rate study/information
• Quarterly Customer Enrollment Update
• Information
• Information/Discussion
• Information/Discussion
• Information
November 10, 2022 Board • Certification of Power Content Label (Annual) • Preliminary 2023 customer rate options
• Preliminary 2023 Operating Budget (Annual)
• Action
• Information/Discussion
• Information
15 November 17, 2022
(rescheduled
November 24th
meeting due to the
Thanksgiving holiday)
Advisory
Committee
• Finalize CAC Evaluation of Calendar Year End (Annual) • Review Procurement Directives and Delegations (Annual) • GHG Free attributes
• Power Procurement / Renewable Portfolio Standard Update • ERRA Filings Update (PCIA and bundled rates) (Annual) • Preliminary 2023 customer rate options
• Discussion/Action
• Information
• Information
• Information
• Discussion
• Information/Discussion
December 8, 2022 Board • Approve 2023 Operating Budget (Annual) • 2023 Customer Rate Adoption
• Receive Enterprise Risk Management Report (Annual)
• Approve Procurement Directives and Delegations (Annual) • GHG Free attributes
• Update on SACOG Grant – Electrify Yolo
• Receive CAC 2022 Calendar Year End Report (Annual)
• Election of Officers for 2023 (Annual)
• Action
• Action
• Information
• Action
• Action
• Information
• Information
• Nominations
December 15, 2022
(rescheduled
December 22nd
meeting due to the
Christmas holiday)
Advisory
Committee
• 2023 CAC Task Group(s) formation (Annual)
• Review draft 2023 Legislative Platform
• Strategic Plan update (Annual)
• 2023 Customer Rates
• Election of Officers for 2023 (Annual)
• Discussion/Action
• Discussion/Action
• Information
• Information
• Nominations
January 12, 2023 Board • Oaths of Office for Board Members (Annual if new Members) • Update on SACOG Grant – Electrify Yolo
• Strategic Plan Update (Annual)
• 2023 Legislative Platform
• Approve Updated CAC Charge (tentative) (Annual)
• Quarterly Customer Enrollment Update
• Action
• Information
• Action
• Action
• Action
• Information
January 26, 2023 Advisory
Committee
• Quarterly Customer Enrollment Update • Information
Notes: 1. CalCCA Annual Meeting scheduled (tentatively) for May 17 - 19, 2023 (San Diego).

2. Currently all meetings are held remotely via Zoom video/teleconference, “location” is subject to change.

CAC PROPOSED FUTURE TOPICS
Topics and Discussion dates may change as needed

ESTIMATED MEETING DATE(S)
Net Energy Metering (NEM) 3.0 (Information/Discussion/Action) As needed Carbon Neutral by 2030 (types of energy, where procured, BTM, FOM, policy) (Discussion/Action) 2022 Quarter 4 16 Self Generation Incentive Program (SGIP) TBD
Forecasting Customer Ag Energy Using Hydrological Conditions (research results) (Information) TBD Legislative Items (as needed)
Strategic Plan additional updates (as needed)
Time of Use (TOU) (as needed)
SACOG Update (as needed)
17 Item 6A & 6B

VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 6A
______________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Executive Director
Edward Burnham, Finance and Operations Director
SUBJECT: Financial Update – June 30, 2022 (unaudited) financial statements (with comparative year to date information) and Actual vs. Budget year to date ending June 30, 2022
DATE: September 8, 2022
RECOMMENDATION:

Accept the following Financial Statements (unaudited) for the period of June 1, 2022 to June 30, 2022 (with comparative year to date information) and Actual vs. Budget year to date ending June 30, 2022.

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 June 30, 2022.

Financial Statements for the period June 1, 2022 – June 30, 2022 In the Statement of Net Position, VCEA, as of June 30, 2021, has a total of $5,129,922 in its checking, money market and lockbox accounts, $1,100,000 restricted assets for the Debt Service Reserve account, $1,998,276 restricted assets related to supplier deposits, and $1,011 restricted assets for the Power Purchases Reserve account. VCE has incurred obligations from Member agencies and owes as of June 30, 2021, $84,693. VCE member obligations are incurred monthly due to staffing, accounting, and legal services.
18 Item 6A & 6B
The term loan with River City Bank includes a current portion of $970,579. The line of credit with the County of Yolo has an outstanding balance of $3,000,000. On June 30, 2022, VCE’s net position is $10,759,456.

In the Statement of Revenues, Expenditures, and Changes in Net Position, VCEA recorded $ 9,666,691 of revenue (net of allowance for doubtful accounts), of which $9,268,140 was billed in June, and $4,554,979 represent estimated unbilled revenue. The cost of the electricity for the June revenue totaled $7,363,824. For June, VCEA’s gross margin was approximate 24% and net income totaled $1,902,966.

The year-to-date change in net position was $747,835.

In the Statement of Cash Flows, VCEA cash flows from operations were ($221,060) due to June cash receipts of revenues being less than the monthly cash operating expenses.

Actual vs. Budget Variances for the year to date ending June 30, 2022 Below are the financial statement line items with variances >$50,000 and 5% • Electric Revenue – ($1,973,537) and -6% – Unfavorable variance due to warmer weather than forecast during the winter months and heat storms in June.
• Other Revenues - Programs – $729,600 and 100% – favorable variance related to CPUC’s issued decision 21- 12-015 funding for VCE’s proposed “AgFIT” dynamic rate pilot offset by expenditures below. Please see September 8, 2022 companion Board Item 12 for 2022 Budget amendment request to include AgFIT revenues and expenditures for net zero 2022 budget impact.
• Purchased Power – ($458,983) and -2% – Unfavorable variance due to the weather that was warmer than forecast during the winter months, heat storms in June, and gas prices driving short-term power market increases.
• Programs – AgFIT – (730,866) and 100% unfavorable variance related to CPUC’s issued decision 21-12-015 funding for VCE’s proposed “AgFIT” dynamic rate pilot offset by revenues above. Please see September 8, 2022 companion Board Item 12 for 2022 Budget amendment request to include AgFIT revenues and expenditures for net zero 2022 budget impact.

Attachments:
1) Financial Statements (Unaudited) June 1, 2022 to June 30, 2022 (with comparative year to date information.)
2) Actual vs. Budget for the year to date ending June 30, 2022 19 VALLEY CLEAN ENERGY ALLIANCE

FINANCIAL STATEMENTS
(UNAUDITED)
FOR THE PERIOD OF JUNE 1 TO JUNE 30, 2022
PREPARED ON AUGUST 2, 2022
20 2
ASSETS
Current assets:

Cash and cash equivalents 5,129,922 $
Accounts receivable, net of allowance 11,323,590 Accrued revenue 4,554,980 Prepaid expenses 15,038 Other current assets and deposits 2,139,195 Total current assets 23,162,725 Restricted assets:

Debt service reserve fund 1,100,000
Power purchase reserve fund 1,011 Total restricted assets 1,101,011 TOTAL ASSETS $ 24,263,736

LIABILITIES
Current liabilities:

Accounts payable 431,887 $
Accrued payroll 58,207 Interest payable 2,128 Due to member agencies 84,693 Accrued cost of electricity 6,822,119 Other accrued liabilities 30,696 Security deposits - energy supplies 1,980,000
User taxes and energy surcharges 123,971 Limited Term Loan 970,579 Loan - County of Yolo 3,000,000 Total current liabilities 13,504,280 Total noncurrent liabilities - TOTAL LIABILITIES $ 13,504,280

NET POSITION
Restricted
Local Programs Reserve 224,500 Restricted 1,101,011 Unrestricted 9,433,945 TOTAL NET POSITION $ 10,759,456
(UNAUDITED)

VALLEY CLEAN ENERGY ALLIANCE

STATEMENT OF NET POSITION
JUNE 30, 2022

21 3

FOR THE PERIOD
ENDING
JUNE 30, 2022 YEAR TO DATE

OPERATING REVENUE
Electricity sales, net 9,666,691 $ 32,141,862 $
Other revenue 729,600 729,600 $
TOTAL OPERATING REVENUES 32,871,462 10,396,291 OPERATING EXPENSES Cost of electricity 7,363,824 29,684,921
Contract services 246,543 1,258,302 Staff compensation 129,401 648,549 General, administration, and other 752,713 1,248,783 TOTAL OPERATING EXPENSES 32,110,955 8,492,481 TOTAL OPERATING INCOME (LOSS) 760,507 1,903,810 NONOPERATING REVENUES (EXPENSES) Interest income 2,043 7,926 Interest and related expenses (2,887) (20,598) TOTAL NONOPERATING REVENUES (EXPENSES) (12,672) (844)
CHANGE IN NET POSITION 1,902,966 747,835
Net position at beginning of period 8,856,490 10,011,621 Net position at end of period $ 10,759,456 $ 10,759,456

VALLEY CLEAN ENERGY ALLIANCE

STATEMENT OF REVENUES, EXPENDITURES AND
(UNAUDITED)

CHANGES IN NET POSITION
FOR THE PERIOD OF JUNE 1, 2022 TO JUNE 30, 2022
(WITH COMPARATIVE YEAR TO DATE INFORMATION)
22 4

FOR THE

PERIOD ENDING
JUNE 30, 2022 YEAR TO DATE

CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from electricity sales 6,078,156 $ 26,074,438 $ Payments received from other revenue sources 729,600 729,600 Payments to purchase electricity (5,828,390) (28,110,776) Payments for contract services, general, and adminstration (933,532) (2,022,549) Payments for staff compensation (125,975) (654,251) Net cash provided (used) by operating activities (3,983,538) (221,060) CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES Principal payments of Debt (42,550) 2,817,553 Interest and related expenses (3,115) (18,141) Net cash provided (used) by non-capital financing activities 2,799,412 (45,665) CASH FLOWS FROM INVESTING ACTIVITIES Interest income 2,043 7,926 Net cash provided (used) by investing activities 7,926 2,043 NET CHANGE IN CASH AND CASH EQUIVALENTS (264,682) (1,320,234) Cash and cash equivalents at beginning of period 6,495,615 6,397,115 Cash and cash equivalents at end of period $ 6,088,653 6,230,933 $ Cash and cash equivalents included in:

Cash and cash equivalents 5,129,922 5,129,922 Restricted assets 1,101,011 1,101,021 Cash and cash equivalents at end of period $ 6,230,933 $ 6,230,943 (WITH YEAR TO DATE INFORMATION)
(UNAUDITED)

VALLEY CLEAN ENERGY ALLIANCE

STATEMENTS OF CASH FLOWS
FOR THE PERIOD OF JUNE 1 TO JUNE 31, 2022
23 5

FOR THE

PERIOD ENDING
JUNE 30, 2022 YEAR TO DATE
Operating Income (Loss) 1,903,810 $ 760,507 $
(Increase) decrease in net accounts receivable (2,951,030.00) (4,015,745.41) (Increase) decrease in accrued revenue (662,496) (2,786,786.74) (Increase) decrease in prepaid expenses 3,762 870,192.00 (Increase) decrease in other assets and deposits (140,919) (140,919.00) Increase (decrease) in accounts payable 26,420 (12,855.00) Increase (decrease) in accrued payroll 3,426 (5,702.00) Increase (decrease) in due to member agencies 20,963 (33,252.00) Increase (decrease) in accrued cost of electricity 1,535,434 1,489,950.00 Increase (decrease) in other accrued liabilities 14,579 (255,054.00) Increase (decrease) in user taxes and energy surcharges 24,991 5,208.10 Net cash provided (used) by operating activities $ (4,124,457) (221,060) $ FOR THE PERIOD OF JUNE 1 TO JUNE 31, 2022

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)
24 VALLEY CLEAN ENERGY
2022 YTD ACTUAL VS. BUDGET
FOR THE YEAR TO DATE ENDING 06/30/22
Description YTD
Actuals
YTD
Budget
YTD
Variance
%
over/-under
Electric Revenue $ 32,871,463 $ 34,845,000 $ (1,973,537) -6% Other Revenues - Programs $ 729,600 $ - $ 729,600 100%
Interest Revenues $ 8,251 $ 9,000 $ (749) -8%
Purchased Power $ 29,684,921 $ 29,219,900 $ 458,983 2%
Purchased Power Base $ 29,678,883 $ 28,658,700 $ 1,020,183 4% Purchased Power Contingency 2% $ - $ 561,200 $ (561,200) -100% Labor & Benefits $ 649,545 $ 653,400 $ (3,855) -1%
Salaries & Wages/Benefits $ 537,026 $ 544,800 $ (7,774) -1% Contract Labor (SMUD Staff Aug) $ - $ 23,400 $ (23,400) -100% Human Resources & Payroll $ 112,519 $ 85,200 $ 27,319 32% Office Supplies & Other Expenses $ 123,965 $ 103,000 $ 20,965 20% Technology Costs $ 34,264 $ 22,000 $ 12,264 56%
Office Supplies $ 5,934 $ 1,200 $ 4,734 395%
Travel $ - $ 3,000 $ (3,000) -100%
CalCCA Dues $ 55,875 $ 63,600 $ (7,725) -12%
CC Power $ 26,891 $ 12,000 $ 14,891 124%
Memberships $ 1,000 $ 1,200 $ (200) -17%
Contractual Services $ 1,175,098 $ 1,239,600 $ (64,502) -5% Other Contract Services $ - $ 12,600 $ (12,600) -100%
Don Dame $ 4,666 $ 4,800 $ (134) -3%
SMUD - Credit Support $ 238,274 $ 242,300 $ (4,026) -2% SMUD - Wholesale Energy Services $ 295,457 $ 292,800 $ 2,657 1% SMUD - Call Center $ 393,200 $ 395,500 $ (2,300) -1%
SMUD - Operating Services $ 22,664 $ 30,000 $ (7,336) -24% Commercial Legal Support $ - $ - $ - 100%
Legal General Counsel $ 56,561 $ 77,400 $ (20,839) -27% Regulatory Counsel $ 82,212 $ 99,600 $ (17,388) -17%
Joint CCA Regulatory counsel $ 192 $ 16,200 $ (16,008) -99% Legislative - (Lobbyist) $ 30,000 $ 30,000 $ - 0%
Accounting Services $ 6,505 $ 13,200 $ (6,695) -51%
Financial Consultant $ - $ 12,600 $ (12,600) -100%
Audit Fees $ 45,368 $ 12,600 $ 32,768 260%
Marketing $ 94,008 $ 123,000 $ (28,992) -24%
Marketing Collateral $ 94,008 $ 120,000 $ (25,992) -22% Community Engagement Activities & Sponsorships $ 3,000 - $ (3,000) $ -100% Programs $ 824,239 $ 87,000 $ 6,373 7%
Program Costs $ 93,373 $ 87,000 $ 6,373 7%
Programs - AgFIT $ 730,866 $ - $ 730,866 100%
Rents & Leases $ 12,800 $ 10,800 $ 2,000 19%
Hunt Boyer Mansion $ 12,800 $ 10,800 $ 2,000 19%
Other A&G $ 276,126 $ 175,400 $ 100,726 57%
Development - New Members $ - $ 12,600 $ (12,600) -100% Strategic Plan Implementation $ (90) $ 12,600 $ (12,690) -101% PG&E Data Fees $ 126,784 $ 138,000 $ (11,216) -8%
Insurance $ 7,560 $ 4,200 $ 3,360 80%
Banking Fees $ 141,872 $ 8,000 $ 133,872 1673%
Miscellaneous Operating Expenses $ 176 $ 600 $ 600 100% Contingency $ - $ 20,000 $ 20,000 100%
TOTAL OPERATING EXPENSES 32,840,878 $ 31,632,700 $ 512,298 $ 2% Interest on RCB loan $ 20,598 $ 18,400 $ 2,198 12%
Interest Expense - Bridge Loan $ - $ 31,200 $ (31,200) -100% NET INCOME 18,238 $ 3,171,700 $ (2,457,582) $ -77%
25 Item 6A & 6B

VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 6B
______________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Executive Director
Edward Burnham, Finance and Operations Director
SUBJECT: Financial Update – July 31, 2022 (unaudited) financial statements (with comparative year to date information) and Actual vs. Budget year to date ending July 31, 2022
DATE: September 8, 2022
RECOMMENDATION:

Accept the following Financial Statements (unaudited) for the period of July 1, 2022 to July 31, 2022 (with comparative year to date information) and Actual vs. Budget year to date ending July 31, 2022.

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.

Financial Statements for the period July 1, 2022 – July 31, 2022 In the Statement of Net Position, VCEA, as of July 31, 2021, has a total of $5,135,132 in its checking, money market and lockbox accounts, $1,100,000 restricted assets for the Debt Service Reserve account, $1,998,276 restricted assets related to supplier deposits, and $503,082 restricted assets for the Power Purchases Reserve account. VCE has incurred obligations from Member agencies and owes as of July 30, 2021, $62,026. VCE member obligations are incurred monthly due to staffing, accounting, and legal services.
26 Item 6A & 6B
The term loan with River City Bank includes a current portion of $927,800. The line of credit with the County of Yolo has an outstanding balance of $3,000,000. On July 31, 2022, VCE’s net position is $13,959,047.

In the Statement of Revenues, Expenditures, and Changes in Net Position, VCEA recorded $13,028,262 of revenue (net of allowance for doubtful accounts), of which $11,363,685 was billed in July, and $6,375,738 represent estimated unbilled revenue. The cost of electricity for the July revenue amount totaled $9,734,827. For July, VCEA’s gross margin was approximate 25% and net income totaled $3,199,591. The year-to-date change in net position was $3,947,426.

In the Statement of Cash Flows, VCEA cash flows from operations were $550,025 due to July cash receipts of revenues being more than the monthly cash operating expenses.

Actual vs. Budget Variances for the year to date ending July 31, 2022 Below are the financial statement line items with variances >$50,000 and 5% • Electric Revenue – ($2,099,575) and -4% – Unfavorable variance due to weather that was warmer than forecast during the winter months and heat storms in June & July. • Other Revenues - Programs – $999,846 and 100% – favorable variance related to CPUC’s issued decision 21- 12-015 funding for VCE’s proposed “AgFIT” dynamic rate pilot offset by expenditures below. Please see September 8, 2022, companion Board Item 12 for 2022 Budget amendment request to include AgFIT revenues and expenditures for net zero 2022 budget impact.
• Purchased Power – ($2,061,110) and -6% – Unfavorable variance due to warmer weather than forecast during the winter months, heat storms in June and July, and gas prices driving short-term power market increases. • Programs – AgFIT – (730,866) and 100% unfavorable variance related to CPUC’s issued decision 21-12-015 funding for VCE’s proposed “AgFIT” dynamic rate pilot offset by revenues above. Please see September 8, 2022 companion Board Item 12 for 2022 Budget amendment request to include AgFIT revenues and expenditures for net zero 2022 budget impact.

Attachments:
3) Financial Statements (Unaudited) July 1, 2022 to July 31, 2022 (with comparative year to date information.)
4) Actual vs. Budget for the year to date ending July 31, 2022 27 VALLEY CLEAN ENERGY ALLIANCE

FINANCIAL STATEMENTS
(UNAUDITED)
FOR THE PERIOD OF JULY 1 TO JULY 31, 2022
PREPARED ON September 2, 2022
28 2

ASSETS
Current assets:

Cash and cash equivalents 5,135,132 $
Accounts receivable, net of allowance 14,097,206 Accrued revenue 6,375,738 Prepaid expenses 32,799 Other current assets and deposits 2,139,195 Total current assets 27,780,070 Restricted assets:

Debt service reserve fund 1,100,000
Power purchase reserve fund 503,082 Total restricted assets 1,603,082 TOTAL ASSETS $ 29,383,152

LIABILITIES
Current liabilities:

Accounts payable 428,445 $
Accrued payroll 55,213 Interest payable 4,589 Due to member agencies 62,026 Accrued cost of electricity 8,730,424 Other accrued liabilities 39,319 Security deposits - energy supplies 1,980,000
User taxes and energy surcharges 149,912 Limited Term Loan 927,800 Loan - County of Yolo 3,000,000 Total current liabilities 15,377,728 Total noncurrent liabilities - TOTAL LIABILITIES $ 15,377,728

NET POSITION
Restricted
Local Programs Reserve 224,500 Restricted 1,603,082 Unrestricted 12,177,842 TOTAL NET POSITION $ 14,005,424 (UNAUDITED)

VALLEY CLEAN ENERGY ALLIANCE

STATEMENT OF NET POSITION
July 31, 2022
29 3

FOR THE PERIOD
ENDING
JULY 31, 2022 YEAR TO DATE

OPERATING REVENUE
Electricity sales, net 13,028,262 $ 45,899,724 $
Other revenue 270,246 999,846.00 TOTAL OPERATING REVENUES 46,899,570 13,298,508

OPERATING EXPENSES
Cost of electricity 9,734,827 39,419,748
Contract services 203,161 1,461,463 Staff compensation 81,805 730,354 General, administration, and other 30,321 1,279,104 TOTAL OPERATING EXPENSES 42,890,669 10,050,114 TOTAL OPERATING INCOME (LOSS) 4,008,901 3,248,394 NONOPERATING REVENUES (EXPENSES) Interest income 2,922 10,848 Interest and related expenses (5,348) (25,946) TOTAL NONOPERATING REVENUES (EXPENSES) (15,098) (2,426) CHANGE IN NET POSITION 3,245,968 3,993,803 Net position at beginning of period 10,759,456 10,011,621 Net position at end of period $ 14,005,424 $ 14,005,424 (WITH COMPARATIVE YEAR TO DATE INFORMATION)

VALLEY CLEAN ENERGY ALLIANCE

STATEMENT OF REVENUES, EXPENDITURES AND
(UNAUDITED)

CHANGES IN NET POSITION
FOR THE PERIOD OF JULY 1, 2022 TO JULY 31, 2022
30 4

FOR THE

PERIOD ENDING
JULY 31, 2022 YEAR TO DATE

CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from electricity sales 8,459,829 $ 34,534,267 $ Payments received from other revenue sources 270,246 999,846.00 Payments to purchase electricity (7,826,522) (35,937,298.00) Payments for contract services, general, and adminstration (268,729) (2,291,278.00) Payments for staff compensation (84,799) (739,050.00) Net cash provided (used) by operating activities (3,433,513) 550,025 CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES Principal payments of Debt (42,779) 2,774,774 Interest and related expenses (2,887) (24,143) Net cash provided (used) by non-capital financing activities 2,750,631 (45,666) CASH FLOWS FROM INVESTING ACTIVITIES Interest income 2,922 10,848 Net cash provided (used) by investing activities 2,922 10,848 NET CHANGE IN CASH AND CASH EQUIVALENTS 507,281 (812,953) Cash and cash equivalents at beginning of period 6,230,933 6,230,933 Cash and cash equivalents at end of period $ 6,088,653 6,738,214 $ Cash and cash equivalents included in:

Cash and cash equivalents 5,135,132 5,135,132 Restricted assets 1,603,082 1,603,082 Cash and cash equivalents at end of period $ 6,738,214 $ 6,738,214

VALLEY CLEAN ENERGY ALLIANCE

STATEMENTS OF CASH FLOWS
FOR THE PERIOD OF JULY 1 TO JULY 31, 2022
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
31 5

FOR THE

PERIOD ENDING
JULY 31, 2022 YEAR TO DATE
Operating Income (Loss) 3,248,394 $ 4,008,901 $
(Increase) decrease in net accounts receivable (2,773,616.00) (6,789,361.41) (Increase) decrease in accrued revenue (1,820,758) (4,607,544.74) (Increase) decrease in prepaid expenses (17,761) 852,431.00 (Increase) decrease in other assets and deposits - (140,919.00) Increase (decrease) in accounts payable (3,442) (16,297.00) Increase (decrease) in accrued payroll (2,994) (8,696.00) Increase (decrease) in due to member agencies (22,667) (55,919.00) Increase (decrease) in accrued cost of electricity 1,908,305 3,398,255.00 Increase (decrease) in other accrued liabilities 8,623 (246,431.00) Increase (decrease) in user taxes and energy surcharges 25,941 31,149.10 Net cash provided (used) by operating activities $ (3,574,432) 550,025 $

RECONCILIATION OF OPERATING INCOME TO NET

CASH PROVIDED (USED) BY OPERATING ACTIVITIES
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
FOR THE PERIOD OF JULY 1 TO JULY 31, 2022

VALLEY CLEAN ENERGY ALLIANCE

STATEMENTS OF CASH FLOWS
32 VALLEY CLEAN ENERGY
2022 YTD ACTUAL VS. BUDGET
FOR THE YEAR TO DATE ENDING 07/31/22
Description YTD
Actuals
YTD
Budget
YTD
Variance
%
over/-under
Electric Revenue $ 45,899,725 $ 47,999,300 $ (2,099,575) -4% Other Revenues - Programs $ 999,846 $ - $ 999,846 100%
Interest Revenues $ 11,173 $ 10,500 $ 673 6%
Purchased Power $ 39,419,748 $ 37,352,600 $ 2,061,110 6% Purchased Power Base $ 39,413,710 $ 37,135,700 $ 2,278,010 6% Purchased Power Contingency 2% $ - $ 216,900 $ (216,900) -100% Labor & Benefits $ 731,350 $ 761,300 $ (29,950) -4%
Salaries & Wages/Benefits $ 597,692 $ 635,600 $ (37,908) -6% Contract Labor (SMUD Staff Aug) $ - $ 26,300 $ (26,300) -100% Human Resources & Payroll $ 133,658 $ 99,400 $ 34,258 34% Office Supplies & Other Expenses $ 136,415 $ 119,400 $ 17,015 14% Technology Costs $ 36,514 $ 24,900 $ 11,614 47%
Office Supplies $ 6,426 $ 1,400 $ 5,026 359%
Travel $ - $ 3,500 $ (3,500) -100%
CalCCA Dues $ 65,583 $ 74,200 $ (8,617) -12%
CC Power $ 26,891 $ 14,000 $ 12,891 92%
Memberships $ 1,000 $ 1,400 $ (400) -29%
Contractual Services $ 1,393,738 $ 1,458,800 $ (65,062) -4% Other Contract Services $ - $ 14,700 $ (14,700) -100%
Don Dame $ 5,866 $ 5,700 $ 166 3%
SMUD - Credit Support $ 297,072 $ 280,100 $ 16,972 6%
SMUD - Wholesale Energy Services $ 345,534 $ 342,900 $ 2,634 1% SMUD - Call Center $ 462,343 $ 462,600 $ (257) 0%
SMUD - Operating Services $ 29,210 $ 35,100 $ (5,890) -17% Commercial Legal Support $ - $ - $ - 100%
Legal General Counsel $ 66,004 $ 90,300 $ (24,296) -27% Regulatory Counsel $ 97,174 $ 116,200 $ (19,026) -16%
Joint CCA Regulatory counsel $ 1,651 $ 18,900 $ (17,249) -91% Legislative - (Lobbyist) $ 35,000 $ 35,100 $ (100) 0%
Accounting Services $ 8,517 $ 15,400 $ (6,883) -45%
Financial Consultant $ - $ 14,700 $ (14,700) -100%
Audit Fees $ 45,368 $ 27,100 $ 18,268 67%
Marketing $ 112,624 $ 143,500 $ (30,876) -22%
Marketing Collateral $ 112,624 $ 140,000 $ (27,376) -20% Community Engagement Activities & Sponsorships $ 3,500 - $ (3,500) $ -100% Programs $ 828,211 $ 101,500 $ 726,711 716%
Program Costs $ 97,345 $ 101,500 $ (4,156) -4%
Programs - AgFIT $ 730,866 $ - $ 730,866 100%
Rents & Leases $ 14,400 $ 12,600 $ 1,800 14%
Hunt Boyer Mansion $ 14,400 $ 12,600 $ 1,800 14%
Other A&G $ 300,707 $ 207,700 $ 93,007 45%
Development - New Members $ - $ 14,700 $ (14,700) -100% Strategic Plan Implementation $ 1,324 $ 19,000 $ (17,676) -93% PG&E Data Fees $ 148,841 $ 161,000 $ (12,159) -8%
Insurance $ 8,670 $ 4,900 $ 3,770 77%
Banking Fees $ 141,872 $ 8,100 $ 133,772 1652%
Miscellaneous Operating Expenses $ 176 $ 600 $ 600 100% Contingency $ - $ 20,000 $ 20,000 100%
TOTAL OPERATING EXPENSES 42,937,369 $ 40,178,000 $ 2,794,355 $ 7% Interest on RCB loan $ 23,450 $ 21,200 $ 2,250 11%
Interest Expense - Bridge Loan $ 2,496 $ 41,600 $ (39,104) -94% NET INCOME 2,947,583 $ 7,769,000 $ (4,856,403) $ -63%
33 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: September 8, 2022
______________________________________________________________________________ Staff, VCE’s lobby services consultant at Pacific Policy Group, and the Community Advisory Committee’s Legislative - Regulatory Task Group continues to meet and discuss legislative matters. Below is a summary of the last year of the two year session.

The 2021-22 legislative session came to a conclusion in the wee hours of Thursday, September 1 following the passage/failure of one of the most impactful measures of the session. SB 846 by Senator Dodd extends the operations of the Diablo Canyon Nuclear Facility from 2025 to 2030 and provides a $1.4 billion loan to PG&E to facilitate the extension. A top priority of Governor Newsom, the Diablo Canyon extension was the bill of all bills in the final days of session.

There were plenty of other high-profile climate and energy proposals voted on in the final couple of days. A package of bills to increase California’s climate and clean energy ambitions, from putting more stringent greenhouse gas reduction goals for 2030 (AB 2133 (Quirk)) or a 2045 goal to achieve carbon neutrality (AB 1297 (Muratsuchi)) to interim clean energy targets on the way to 100% clean energy by 2045 (SB 1020 (Laird)), the end of the session has put California on a new path to confront climate change.

In addition to these significant policy bills, the final budget for Fiscal Year 2022-23 provided billions of dollars for electric vehicles and hundreds of millions of dollars to decarbonize homes, businesses, and industries. A new program at the California Energy Commission will receive $100 million to provide rebates and other incentives to homeowners to install energy efficient electric appliances, energy efficiency measures, demand flexibility measures, wiring and panel upgrades, building infrastructure upgrades, efficient air conditioning systems.

The end-of-session scrum also provided some foresight into what may be an issue CCAs must fight in the 2023 legislative session. In response to the Governor’s Diablo Canyon proposal, a handful of Assemblymembers crafted an alternative proposal that would provide funding and policy provisions to incentivize the acceleration of constructing and interconnection of more clean energy generation resources. One such provision sought to penalize load-serving entities (LSEs) with prior Resource Adequacy citations or penalties by barring those LSEs from adding 34 Item 7
2 new customers or increasing their load. CalCCA and individual CCAs did a hard press on this provision and the alternative proposal and successfully kept the concept from gaining any traction. Despite winning this round, it is possible, and maybe even likely, that a similar proposal resurfaces next year.

The following chart provides an overview of bills that staff, Pacific Policy Group, and the Community Advisory Committee’s Legislative - Regulatory Task Group monitored and engaged on throughout the year. It also shows those bills where VCE took a position.

Measure Summary Outcome VCE
Position
CalCCA
Position
SB 846
(Dodd)
Extends the operation of the Diablo
Canyon Nuclear Facility to 2030 and
loans PG&E $1.4 billion to facilitate
the extension.

Passed Legislature None None
AB 1297
(Muratsuchi)
Requires California to be carbon
neutral by the year 2045. Passed Legislature None None
AB 2133
(Quirk)
Increases the state’s 2030 climate
goals from 40% below 1990 levels to
55% below 1990 levels
Failed
Asm. Floor None None
SB 905
(Caballero)
Requires the CA Air Resources Board
to create a program and regulatory
framework for Carbon Capture and
Sequestration (CCS) projects
Passed Legislature None None
SB 1020
(Laird)
Requires load-serving entities to
procure a minimum of carbon-free
energy resources to reach goals of
90% carbon-free by 2035 and 95%
by 2040. In addition, all state
agencies shall be served by 100%
carbon free energy by 2035.

Passed Legislature None
None
(MCE and
Sonoma
Supported)
SB 1137
(Gonzalez)
Prohibits the permitting for new oil &
gas wells within 3200 feet of a home,
school, hospital, or other sensitive
receptor.

Passed Legislature None None
AB 1814
(Grayson)
Sought to authorize CCAs to submit
applications to the CPUC to receive
funding to administer
transportation electrification
programs in their service areas
Failed
Assembly U&E Support Sponsor
35 Item 7
3 SB 833
(Dodd)
Sought to require the CEC to
implement a grant program to for
local governments to develop
community energy resilience plans
Failed
Senate Approps Support None
SB 881 (Min)
Sought to authorize the CPUC to
assess penalties or require
additional procurement, which
could be undertaken by an IOU, of
an LSE who fails to meet its
procurement obligations in its IRP.

Failed
Senate Approps
Oppose
Unless
Amended
Oppose
36 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: September 8, 2022
______________________________________________________________________________ Please find attached Keyes & Fox’s August 2022 Regulatory Memorandum dated August 31, 2022, 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 August 31, 2022. 37 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: Regulatory Update
Date: August 31, 2022
Summary
Keyes & Fox LLP and EQ Research LLC, are pleased to provide VCE’s Board of Directors with this monthly informational memo describing key California regulatory and compliance-related updates from the California Public Utilities Commission (CPUC). A Glossary of Acronyms used is provided at the end of this memo.

In summary, this month’s report includes regulatory updates on the following priority issues:
• IRP Rulemaking: On August 1, VCE submitted its 2022 Incremental Procurement Compliance Filing. During July, PG&E submitted Advice Letters updating its system reliability contracts and providing its Rate Implementation Plan, and a Notice providing a progress update on its efforts to fulfill its reliability obligations.
• RPS Rulemaking: On August 29, the Commission issued Resolution E-5220 approving PG&E’s Renewable Market Adjusting Tariff (ReMAT) Program tariff and PPA with modifications. On August 15, VCE filed its Motion to Update the draft RPS Procurement Plan. • RA Rulemaking (2023-2024): On August 29, D.22-08-039 adopted the monthly regional wind effective load carrying capability (ELCC) values from the Energy Division’s Regional Wind ELCC Study for the 2023 resource adequacy (RA) year and directed the Parties to develop further proposals for quantifying demand response qualifying capacity. •
NEWMicrogrid: On July 6, the ALJ issued a Ruling requesting comments on a Staff Proposal for the Microgrid Incentive Program (MIP). On August 8, the CPUC issued D.22-08-025 denying an SDG&E request for rehearing of D.21-07-011.
•
NEWBuilding Decarbonization: On August 8, the CPUC issued a Proposed Decision that would adopt a Staff Proposal to eliminate gas line extension allowances, the 10-year refundable payment option, and the 50% discount payment option provided under the current gas line extension rules. The elimination would apply to all customers in all customer classes for new applications for gas line extensions submitted on or after July 1, 2023. 38 2
•
NEWTransportation Electrification: On August 9, the CPUC issued D.22-08-024 adopting the plug-in electric vehicle (PEV) submetering protocol and adopting electric vehicle supply equipment (EVSE) communication protocols. Under this Decision, large investor-owned utilities (including PG&E) and small multi-jurisdictional utilities are required to implement the submetering protocol for all customers with PEVs and customer-owned submeters •
NEWCommercial EV Real-Time Pricing Pilot: On August 9, the CPUC issued D.22-08-002 approving the Marginal Generation Capacity Cost Study for use by PG&E when calculating Real-Time Pricing rates, adopting the Real-Time Pricing settlement, and closing A.19-11-019. Opt-in enrollment for the Real-Time Pricing Pilot for commercial electric vehicles begins October 1, 2023.
•
NEWDemand Flexibility: The OIR was issued by the Commission on July 22. Opening comments were filed by VCE and 47 other parties, and a pre-hearing conference is scheduled for September 16.
•
NEWDemand Response Programs (2023-2027): On July 5, the Assigned Commissioner issued a Scoping Memo and Ruling defining the scope of issues and providing a procedural schedule for Phase 1.
• PCIA Rulemaking: On July 19, the CPUC issued D.22-07-008 on PCIA Data Access, resolving Phase 2 issues related to data access and voluntary allocations in market price benchmark calculations. On August 4, the ALJ issued a Ruling requesting comment on long-term fixed-price RPS transactions and providing a Staff Proposal for Incorporating Long-Term RPS Transactions into the RPS MPB.
• Provider of Last Resort Rulemaking: On July 15, the CPUC issued a Disposition Letter accepting PG&E AL 6589-E_E-A_E-B on financial security requirements for CCAs which became effective as of August 6.
• PG&E 2023 Phase 1 GRC: On July 22, PG&E filed its Track 2 request for a reasonableness review of recorded costs and recovery of $241 million in costs over two years. On August 9, PG&E filed a Case Management Statement reporting no settled issues among the Parties and withdrawing its revenue requirement request for two disputed projects. Track 1 Evidentiary Hearings were held August 15-26, and Keyes & Fox LLP cross examined a panel of PG&E witnesses on their rebuttal to the Joint CCAs’ re-vintaging testimony during the hearings. • PG&E ERRA Forecast (2023): On August 4, the Assigned Commissioner issued a Scoping Memo and Ruling setting forth the issues and a schedule intended to meet the deadline for the final 2022 Commission meeting allow for new rates to be effective January 1, 2023. • PG&E 2019 ERRA Compliance: On July 14, the CPUC issued D.22-07-009 extending the statutory deadline for the proceeding by an additional six months until March 1, 2023 in order to resolve the Phase 2 issues related to Public Safety Power Shutoff events. • PG&E 2020 ERRA Compliance: On August 11, the CPUC issued D.22-08-009 extending the statutory deadline in this proceeding through 2023 to provide an opportunity to address the Phase 2 issues related to unrealized sales and revenues resulting from PG&E’s Public Safety Power Shutoff events in 2020.
• PG&E 2021 ERRA Compliance: On August 9, the Assigned Commissioner issued a Scoping Memo and Ruling defining the issues for consideration, finding that evidentiary hearings are 39 3
needed, and providing a procedural schedule intended to conclude the proceeding within 18 months.
• PG&E Regionalization Plan: On July 25, PG&E met with the Regionalization Stakeholder Group and presented an activity schedule for future meetings and reporting. • Utility Safety Culture Assessments: On July 22, the ALJ issued a Ruling seeking comments on policy questions for safety culture assessments and distributing the Staff Safety Culture Concept Paper 1.
• Other Dockets: Provides a summary and status update of other tracked dockets that are either closed or inactive.

IRP Rulemaking
On August 1, VCE submitted its 2022 Incremental Procurement Compliance Filing. During July, PG&E submitted Advice Letters updating its system reliability contracts and providing its Rate Implementation Plan, and a Notice providing a progress update on its efforts to fulfill its reliability obligations.

Background: D.20-12-044 established a backstop procurement process that would apply to LSEs that did not opt-out of self-procuring their capacity obligations under D.19-11-016. It requires LSEs to file bi-annual (due February 1 and August 1) updates on their procurement progress relative to the contractual and procurement milestones defined in the decision.

D.21-06-035 established a new Mid-Term Reliability (MTR) procurement mandate of 11,500 MW of additional zero-emitting or RPS-eligible net qualifying capacity to be procured by 2026 by LSEs through long-term (10 or more years) contracts. VCE’s incremental obligations, identified in Table 6, are 8 MW by 2023, 23 MW by 2024, 6 MW by 2025, 4 MW of long-duration storage and 4 MW of zero-emitting resources by 2026. In addition, 10 MW out of its 2023-2025 procurement requirements must be met through zero-emitting generating capacity that is available from 5-10pm daily.

While each LSE is responsible for meeting procurement obligations to serve its own customers, D.19-11-016 directed IOU procurement on behalf of LSEs that either a) opt out of self-procurement or b) failed to acquire their share of required capacity after electing to do so. Similarly, D.21-06-035, while not allowing for LSEs to opt out of self-procurement, directed the IOUs to procure capacity on behalf of LSEs that failed to deliver their share of required energy or capacity, called backstop procurement.

D.22-02-004 adopted a 2021 Preferred System Plan (PSP) and certified VCE’s 2020 IRP. VCE’s next IRP is due November 1.

D.22-05-015 adopted Modified Cost Allocation Mechanism (MCAM) principles and methodologies that only apply to any future backstop and opt-out procurement authorized in the IRP process, but not other cost allocation situations such as those related to a central procurement entity. IOUs were required to file Tier 2 advice letters on MCAM implementation by July 18, 2022. The MCAM is based on the original Cost Allocation Mechanism (CAM) adopted in D.06-07-029. It provides a mechanism for recovery of the net costs of electric resource procurement obligations mandated in D.19-11-016 (3,300 MW) and D.21-06-035 (11,500 MW) through nonbypassable charges (NBCs) levied against customers of non-utility LSEs.

Backstop procurement costs are charged directly to customers of the deficient LSE, as a separate line item on the bill. Administrative costs are charged over a 10-year period and contract costs are charged over the life of the contract (generally 10 or more years), and Commission staff will allocate 40 4
the resource adequacy (RA) value of backstop procurement annually to the LSE over the life of the contract(s), but backstop procurement does not convey any RPS attributes associated with the procured resources, although LSEs may obtain those RPS attributes through voluntary allocation. 2022 IRP Planning Targets
A June 15 Ruling adopted planning targets for 2035, namely 30 MMT and 25 MMT. These targets are in addition to the requirements in D.22-02-004, which requires LSEs to meet their proportional share of the 2030 target of 38 MMT, and plan for a 2030 target of 30 MMT. Each LSE will have four benchmarks and must show how it intends to reach each of the benchmarks. The four benchmarks are as follows:
• For 2030: VCE’s proportional share of 38 MMT = 0.112 MMT • For 2035: VCE’s proportional share of 30 MMT = 0.088 MMT • For 2030: VCE’s proportional share of 30 MMT = 0.085 MMT • For 2035: VCE’s proportional share of 25 MMT = 0.070 MMT VCE’s final energy forecast is provided in the Load Forecasts and GHG Benchmarks spreadsheet and its confidential final load forecast was provided by the Commission on July 1.

Details: On July 20, PG&E submitted AL 6658-E with amendments to system reliability contracts approved in AL 6033-E (Procurement Toward Procurement Requirements Under D.19-11-016 – Nexus Renewables and NextEra North Central Valley).

On July 25, the CPUC posted the 2022 Procurement Summary (2021 Procurement Summary) for D.19-11-006 procurement requirements based on LSE filings from February 1. All LSEs had met their August 1, 2021 Tranche 1 obligations as of February 2022 except for PG&E and SDG&E which had shortfalls of 69.6 MW and 16.6 MW, respectively. On July 25, PG&E issued Notice that not all project contracts approved by Resolution E-5140 will be online in time to meet the August 1 Tranche 2 deadline.

On July 29, PG&E submitted AL 6654-E-A (replacing AL 6654-E in its entirety) providing its Rate Implementation Plan pursuant to D.22-05-015 to implement cost recovery associated with reliability contracts procured to meet the MCAM targets established in D.19-11-016 and Mid-Term Reliability targets established in D.21-06-035.

On August 1, VCE submitted its 2022 Incremental Procurement Compliance Filing.

Analysis: The 2022 IRP emphasizes the increasingly integrated nature of planning and procurement activities and requires LSEs to present connections among its procurement obligations for RA, reliability, energy and capacity, and the RPS. LSEs are also required to plan for multiple GHG targets in future benchmark years in their IRPs. Under the MCAM Decision (D.22-05-015), a deficiency in fulfilling RA and reliability procurement obligations results in additional, likely higher, costs to the deficient LSE’s customers for at least the next decade, and the lengthy duration of both backstop procurement costs and allocation of backstop procurement resources could easily result in unnecessary and inefficient over-procurement of resources if triggered. In July, the CPUC released its Procurement Summary findings that no LSEs were deficient in meeting reliability procurement obligations under D.19-11-016 as of the February 2022 compliance filings.

Next Steps: VCE’s next IRP is due November 1, 2022.

Additional Information: PG&E AL 6686-E (August 19, 2022); VCE 2022 Incremental Procurement Compliance Filing (August 1, 2022); PG&E AL 6654-E-A (July 29, 2022); CPUC 2022 Procurement Summary (July 25, 2022); PG&E AL 6658-E (July 20, 2022); Ruling on final load forecasts and GHG benchmarks (June 15, 2022); D.22-05-015 on Modified Cost Allocation Mechanism (May 23, 2022); Ruling establishing process for load forecasts and GHG benchmarks for 2022 IRP (April 20, 2022); 41 5
D.22-02-004 adopting 2021 Preferred System Plan (December 22, 2021); D.21-06-035 establishing a 11,500 MW by 2026 procurement mandate (June 24, 2021); Resolution E-5140 (April 19, 2021); D.21-02-028 recommending portfolios for CAISO’s 2021-2022 TPP (February 17, 2021); D.20-12- 044 establishing a backstop procurement process (December 22, 2020); PG&E AL 6033-E (December 22, 2020); Scoping Memo and Ruling (September 24, 2020); Resolution E-5080 (August 7, 2020); Order Instituting Rulemaking (May 14, 2020); Docket No. R.20-05-003.

RPS Rulemaking
On August 29, the Commission issued Resolution E-5220 approving PG&E’s Renewable Market Adjusting Tariff (ReMAT) Program tariff and PPA. On August 15, VCE filed its Motion to Update the draft RPS Procurement Plan.

Background: This proceeding addresses ongoing RPS issues. VCE submitted its Final 2021 RPS Procurement Plan on February 17, 2022, its Draft 2022 RPS Procurement Plan on July 1, and its 2020 RPS Compliance Report on August 2, 2021.

Renewable Market Adjusting Tariff (ReMAT) Program
The Renewable Market Adjusting Tariff (ReMAT) program is a feed-in tariff program for small renewable energy generators less than 3 MW in size and was established by AB 1969 and amended by SB 380, SB 32, and SB 2 (1X). The program began in 2008 and offers a fixed-price standard contract to eligible renewable resources (i.e., Qualifying Facilities under the federal Public Utilities Regulatory Policies Act) for exporting electricity to California’s three large IOUs. Electricity generated under the ReMAT program counts towards the IOUs’ RPS targets. D.21-12-032 directed the three large IOUs to each file a Tier 2 advice letter modifying their ReMAT tariffs and standard PPAs to accommodate the eligibility of facilities enhanced with storage, establish a de minimis threshold for each product category, and provide a process for the IOUs to aggregate remaining capacity to meet their individual share of the statewide ReMAT capacity target.

Voluntary Allocation and Market Offer (VAMO)
In addition, ongoing implementation issues of the Voluntary Allocation and Market Offer process (VAMO) ordered in the PCIA proceeding are considered in the RPS proceeding. Under VAMO, LSEs are first offered an election to take up to their load share percentage of the IOUs’ PCIA-eligible RPS portfolio as a direct allocation from the IOU. In the second part of the process, called the Market Offer (MO), the IOUs will offer for sale the remaining portions of their RPS portfolios that were not claimed by LSEs in the Voluntary Allocations.

An April 11 Ruling identified requirements for 2022 RPS Procurement Plans and established two parallel tracks in the proceeding. Track 1 addresses the IOU’s proposed Market Offer process and Track 2 addresses retail electricity sellers’ 2022 RPS Plans.

An April 21 Ruling established revised dates for the submission of the Market Offer Process document. Pursuant thereto, the Joint IOUs submitted the Market Offer Process document on May 2, and each IOU filed a confidential sales strategy on May 16 to complete the Market Offer Process documentation.

Track 1: Voluntary Allocation / Market Offer Process
The Joint IOUs filed their proposed Market Offer process on May 2. The IOUs proposed that in the first step, the Joint IOUs offer Voluntary Allocations at the Market Price Benchmark (MPB) in 10% increments of each LSE’s forecasted annual load share. The Joint IOUs proposed to have LSEs indicate the amounts they are taking under the Voluntary Allocation and sign pro forma Voluntary Allocation Contracts in July 2022. Then, in the second step, the Joint IOUs proposed that remaining 42 6
RPS energy not claimed by LSEs in the Voluntary Allocation will be offered to all market participants through the Market Offer process.

On May 23, PG&E submitted modifications (AL 6551-E-A) to its pro forma Market Offer Contract (AL 6551-E) in response to Protests filed by the Alliance for Retail Energy Markets and CalCCA. PG&E modified the Market Offer contract to differentiate the offered products based on whether the resource is eligible for RPS compliance.

On June 24, the Commission issued D.22-06-034 establishing rules for the PCC classification of resources obtained through the VAMO process. The Decision draws a clear distinction between RPS resources procured through Voluntary Allocation versus those procured through the Market Offer mechanism. Even though an LSE procures a “slice” of the IOU’s RPS resource portfolio through each mechanism, the PCC classification of RPS resources procured through Voluntary Allocation does not change, while RPS resources procured through the Market Offer mechanism, particularly those with PCC-0 classification, will be treated as if they were a newly contracted resource and will not necessarily retain their original PCC classification. In response to comments filed by CalCCA, the Decision clarified that LSEs who choose not to claim Voluntary Allocations must provide an explanation for that decision in their RPS Plans. On June 29, the CPUC issued Resolution E-5216 approving the Joint IOUs’ Voluntary Allocation Pro Forma Contracts (PG&E AL 6517-E and AL 6517- E-A).

Track 2: RPS Plans
Under the April 11 Assigned Commissioner’s Ruling, 2022 RPS Plans must be forward looking through 2032 and should inform the Commission of the Retail Seller’s activities and plans to procure 65% of RPS resources from long-term contracts of 10 or more years for all compliance periods beginning with the current compliance period that started on January 1, 2021, among other requirements.

VCE filed its Draft 2022 RPS Procurement Plan on July 1. VCE’s Draft Plan demonstrates that VCE is well positioned to meet or exceed all RPS requirements in the current RPS Compliance Period 4 (2021-2024), as well as in RPS Compliance Period 5 (2025-2027) and beyond. VCE indicated in its Draft 2022 RPS Procurement Plan that it does not plan to participate in VAMO.

Details: On August 1, PG&E filed AL 6666-E describing proposed modifications to its ReMat program and PPA to comply with the requirement in D.20-08-046 (Attachments A & B) that with contracts for procurement of power, capacity, or reliability with a term of 15 years or more, PG&E obtain both an acknowledgement that the operator has considered long-term climate risk and the operator’s climate risk safety plan, if available.

On August 16, the Commission issued a Disposition Letter accepting PG&E’s AL 6662-E on ReMAT pursuant to Resolution E-5209, effective July 25. On July 25, PG&E submitted AL 6662-E Modifications to PG&E’s ReMAT Program Tariff Pursuant to Resolution E-5209. New tariff prices by resource classification are:
• As-Available Non-Peaking $49.02/MWh
• As-Available Peaking $50.72/MWh
• Baseload $73.50/MWh
On August 29, the CPUC issued Resolution E-5220 approving PG&E ALs 6528-E / 6528 E-A ReMAT Program tariff and PPA with modifications. The modifications required by the Commission include removal of PG&E’s proposed negotiation process, modifying the definition of “baseload facility” to include an 80% capacity factor, and a finding that energy storage is an enhancement to a ReMAT-eligible resource and does not count towards the capacity cap. 43 7
Analysis: Recent changes to the ReMAT program require PG&E to obtain climate risk information from projects, establish standard-offer PPA prices, remove PG&E’s proposed negotiation process, and clarify that energy storage is a project enhancement that does not count towards the capacity cap.

Overall, these changes provide more favorable conditions for the small-scale renewable energy projects that are eligible for the ReMAT program and enable these projects to incorporate storage without affecting their eligibility. These changes will encourage development of more small-scale renewable energy projects with storage.

Next Steps:

Track 1: VAMO
• September 16, 2022: IOUs Issue Market Offer Solicitation • Week of September 19-23, 2022: Participants’ Webinar
• September 30, 2022: Bids Due
• October 14, 2022: IOUs Notify Qualified Participants
• October-November 2022: Agreements Executed
• November 2022: IOU Submits Agreement for CPUC Approval • 3Q 2022: Proposed Decision on Market Offer process
• 3Q 2022: Disposition on Tier 2 Market Offer Pro Forma Contract Advice Letters Track 2: 2022 RPS Plans
• 4Q 2022: Proposed Decision on LSEs’ draft RPS Procurement Plans • 1Q 2023: LSEs file final 2022 RPS Plans
Additional Information: CPUC Resolution E-5220 (August 29, 2022); VCE Motion to Update Draft 2022 RPS Procurement Plan (August 15, 2022); PGE AL 6605-E-A (August 3, 2022); VCE 2021 RPS Compliance Report (August 1, 2022); PG&E AL 6666-E (August 1, 2022); PG&E AL 6662-E (July 25, 2022); VCE 2022 Draft RPS Procurement Plan (July 1, 2022); CPUC Resolution E-5209 (June 29, 2022); D.22-06-034 establishing rules for PCC classification (June 24, 2022); Resolution E-5216 approving Joint IOUs’ Voluntary Allocation Pro Forma Contracts (June 29, 2022); PG&E AL 6605-E (May 24, 2022); PG&E AL 6551-E-A (May 23, 2022); Ruling on Procedural Schedule (May 20, 2022); Market Offer Process proposal by Joint IOUs (May 2, 2022); PG&E AL 6528-E-A (April 25, 2022); Ruling on RPS Track 1 schedule (April 21, 2022); Ruling seeking comments on Voluntary Allocations and PCC issues (April 18, 2022); PG&E AL 6517-E-A (April 11, 2022); Ruling identifying RPS Plan requirements (April 11, 2022); Amended Scoping Ruling expanding scope (April 6, 2022); PG&E AL 6551-E (April 4, 2022); PG&E AL 6528-E (March 15, 2022); Joint Motion by IOUs Concerning Review of Market Offer Process (March 10, 2022); PG&E AL 6517-E (February 28, 2022); VCE’s Final 2021 RPS Procurement Plan (February 17, 2022); D.22-01-004 on draft 2021 RPS Procurement Plans (January 18, 2022); D.21-12-032 (December 17, 2021); Docket No. R.18- 07-003.

RA Rulemaking (2023-2024)
On August 29, D.22-08-039 adopted the monthly regional wind effective load carrying capability (ELCC) values from the Energy Division’s Regional Wind ELCC Study for the 2023 resource adequacy (RA) year 44 8
and directed the Parties to develop further proposals for quantifying demand response qualifying capacity.

Background: In Track 3B.2 of the 2021-2022 RA Rulemaking (R.19-11-009), D.21-07-014 rejected proposals for restructuring the Resource Adequacy (RA) program and directed the Parties to hold additional workshops.

The December 2, 2021, Scoping Memo and Ruling divided the proceeding into an Implementation Track and Reform Track. The Reform Track encompasses consideration of a final proposed framework and the slice-of-day workshop report.

The Implementation Track is sub-divided into Phases 1, 2, and 3:
• Phase 1 of the Implementation Track considered critical modifications to the Central Procurement Entity (CPE) structure and concluded in March 2022 with issuance of D.22-03- 034.
• Phase 2 consists of the Commission’s consideration of flexible capacity requirements (FCR) for the following year, local capacity requirements (LCR) for the next three years, and the highest-priority refinements to the RA program including modifications to the Planning Reserve Margin (PRM) Qualifying Capacity Counting Conventions, which, along with other proposals, will consider the Energy Division's biennial update to the Effective Load Carrying Capability (ELCC) values for wind and solar resources. Phase 2 proposals were submitted in January 2022. Neither CalCCA nor any CCAs individually filed a Phase 2 proposal. • Phase 3 will consider the 2024 program year requirements for flexible RA, and the 2024-2026 local RA requirements. Other modifications and refinements to the RA program, as identified in proposals by parties or by the Energy Division may also be considered. Phase 3 is expected to conclude by June 2023.

D.22-03-034: This Decision established that in the event of a non-performing self-shown resource, an LSE may substitute another local resource on a like-for-like basis, and that if the CAISO makes a local Capacity Procurement Mechanism (CPM) designation for an individual deficiency then the CPE will be charged any backstop procurement costs and those costs will be allocated to all LSEs on a load ratio share basis. It also requires LSEs that either decline to self-show a local resource to the CPE or fail to bid a local resource into the CPE’s solicitation process to file a justification statement in its year-ahead Resource Adequacy filing explaining why the LSE declined to self-show or bid the local resource to the CPE.

On June 24, the CPUC issued D.22-06-050 adopting 2023-2025 Local Capacity Requirements (LCR), 2023 Flexible Capacity Requirements (FCR), and RA program refinements under the RA Reform Track of this proceeding. Among other things, with respect to RA Reform, it adopts SCE's 24-hour "slice of day" framework, with modifications, pending further development of certain implementation details. Further development of the slice-of-day framework is divided into three workstreams focused on refining counting and measurement approaches for future year requirements.

Details: D.22-08-039 adopted the monthly regional wind effective load carrying capability (ELCC) values from the Energy Division’s Regional Wind ELCC Study for the 2023 resource adequacy (RA) year.

This Decision also addressed demand response qualifying capacity methodology for the 2023 and 2024 RA years and found insufficient support for adopting the loss-of-load-weighted Load Impact Protocol, and instead directed the Parties to develop proposals on how to use the Load Impact Protocol outputs under the 24-hour slice framework for the 2024 test year in Workstream 2 of this proceeding,
Analysis: Changes to RA methodologies could impact the RA value of a variety of capacity resources which VCE makes use of, including energy storage and demand-side management programs. D.22- 45 9
08-039 did not adopt the proposed demand response qualifying capacity methodology for the 2023 and 2024 RA years and ordered development to continue. Methodology proposals have been under development for several years, and the limited progress creates uncertainty as to how resources will be measured and presents challenges for planning and procurement efforts since future operational requirements are unknown.

Next Steps: The procedural schedule for the ongoing tracks and working groups are as follows:

Reform Track Phase 2
• July – October 2022: Workstreams 1-3 to resolve remaining implementation details and methodologies as part of the RA Reform Workshops
• November 15, 2022: Final proposals from Workstreams 1- 3 filed and served • December 1, 2022: Opening comments on final proposals due • December 12, 2022: Reply comments on final proposals due • Q1 2023: Proposed decision on Reform Track Phase 2 issued CPE Procurement Timeline
• End of August 2022: LSEs in the SCE and PG&E TAC areas receive updated CAM credits for multi-year system/flexible capacity that was procured by the CPE as a result of the CPE’s multi-year local RA showing to the Commission in mid-August. • September 2022: LSEs are allocated final year-ahead system and flexible RA allocations, including CAM credits from CPE-procured system and flexible RA capacity based on revised year-ahead load forecast load ratios.
• End of October: LSEs make year-ahead system and flexible showings, and provide justification statements, if applicable, for local resources not self-shown or bid to the CPE.

Additional Information: D.22-08-039 on Regional Wind ELCC (August 29, 2022); PG&E Substitute Sheets for AL 6438-E (August 10, 2022); PG&E Substitute Sheets for AL 6436-E (August 10, 2022); D.22-06-050 on LCR and FCR Requirements and Modifications to the RA Framework (June 24, 2022); White Paper: Advanced Strategies for Demand Flexibility Management and Customer DER Compensation (June 22, 2022); Ruling on availability of MTR analysis supporting data (June 8, 2022); Ruling on Regional Wind ELCC study (June 1, 2022); Final 2023 FCR Report (May 17, 2022); Notice of Final 2023 LCR Report (April 29, 2022); Ruling modifying schedule (April 29, 2022); CAISO Local Capacity Technical Analysis (April 7, 2022); D.22-03-034 on Phase 1 of Implementation Track Modifications (March 18, 2022); Ruling modifying Phase 2 schedule and providing LOLE study and CEC Working Group Report (February 18, 2022); Proposed Decision on CPE revisions (February 10, 2022); Scoping Memo and Ruling (December 2, 2021); Order Instituting Rulemaking (October 11, 2021); Docket No. R.21-10-002.

NEWMicrogrid
On July 6, the ALJ issued a Ruling requesting comments on a Staff Proposal for the Microgrid Incentive Program (MIP). On August 8, the CPUC issued D.22-08-025 denying an SDG&E request for rehearing of D.21-07-011.

Background: R.19-09-09 was opened in September 2019 to implement the requirements of SB 1339 (Stern, 2018), which requires the CPUC, in consultation with the CAISO and CEC, to take several actions to facilitate the commercialization of microgrids for distribution customers of the large IOUs.

The initial December 2019 Scoping Memo and Ruling broke the proceeding into three tracks. Fourth 46 10
and fifth tracks were subsequently added to address the establishment of a Microgrid Incentive Program, potential contributions that microgrids can make to mitigating capacity shortages in the near-term, and the development of a multi-property microgrid framework.

Track 1: Addressed the Commission's goal of deploying resiliency planning in areas that are prone to outage events and wildfires, with the goal of putting some microgrid and other resiliency strategies in place by Spring or Summer 2020. Track 1 concluded with the issuance of D.20-06-017. Among other things, the Decision (1) approved PG&E’s Community Microgrid Enablement Program, which provides technical and financial support on a prioritized basis for community-requested microgrids for PSPS mitigation purposes; (2) approved PG&E’s Make-Ready Program for the period of 2020 through 2022, which includes enabling prioritized substations to operate in islanded mode; and (3) approved PG&E’s Temporary Generation Program, which involved leasing mobile generators for temporary use during the 2020 wildfire season.

Track 2: Resulted in the issuance of D.21-01-018 adopted several policy measures including:
• Directing the major IOUs to revise their service rules (Rules 18/19 depending on the utility) to allow microgrids to serve critical facilities on adjacent parcels. • Adopting the broad design of a microgrid tariff, which includes provisions: (a) limiting it to NEM-eligible resources and storage (with fossil resources permitted using the NEM-MT as a companion), (b) permission for exports and NEM, (c) no aggregate enrollment or project size caps except those applicable to NEM, and (d) no exemption from cost responsibility surcharges (CRS).
• The establishment of a new Microgrids and Resiliency Working Group to consider issues related to the use of non-renewable resources (e.g., export compensation), and the contours of microgrid costs and benefits as a foundation for preventing cost-shifting, which involves the contours of CRS, NBCs, departing load charges, standby charges, and stranded costs. • Directing the establishment of a Microgrid Incentive Program (budget of $200 million), subject to further development of an implementation plan which is now being considered as part of newly designated Track 4.

On April 16, 2021 the CPUC issued D.21-04-021 modifying D.21-01-018 and denying the rehearing request filed by the City of Long Beach. The Decision slightly refined two conclusions of law contained in D.21-01-018 and clarified that (1) municipal corporations are not subject to the CPUC’s regulatory authority as public utilities even if they otherwise meet the applicable definition (i.e., sell electricity to more than two other entities); and (2) maritime transportation is included in the definition of “critical facilities.”
Track 3: Resulted in the issuance of D.21-07-011, which suspended the capacity reservation component of standby charges for: (a) technologies that meet CARB's DG air pollution standards, (b) technologies that operate using cleaner renewable fuels such as renewable natural gas, biogas, or green hydrogen; and (c) customers that form a commitment to convert the microgrid to use only renewable fuels (as reasonably practicable) by December 31, 2030. D.21-07-011 required those customers to pay a "demand assurance amount" should a customer's microgrid generation be insufficient to meet the customer's demand. An evaluation of the suspension will be conducted in 2026 to determine whether the suspension is fair and provides value to the public.

Track 4: An expedited Phase 1 of Track 4 responded to the Governor's July 30, 2021 emergency proclamation seeking an acceleration of clean energy development by the Summers of 2022 and 2023 given concerns about resource availability during extreme heat events. D.21-12-004 in Phase 1 adopted programs proposed by PG&E (Temporary Generation expansion) and SDG&E (4 circuit-level microgrid projects). 47 11
Phase 2 of Track 4 is a non-expedited effort to develop a microgrid multi-property tariff to further facilitate microgrid commercialization.

Track 5: This track was added in the December 2021 Ruling to scope the value of resiliency, and it will assess the value of resiliency to inform investments in resiliency strategies. The analysis and measurement of resiliency’s value has potential to advance the goal of net zero emissions, expand investment in adaptive infrastructure and resiliency measures, while incorporating equity in grid planning.

Details: On July 6, the ALJ issued a Ruling requesting comments on a Staff Proposal for the Microgrid Incentive Program (MIP). The MIP is targeted to develop microgrid technology to bolster climate response resiliency, equitably provide system benefits to disadvantaged vulnerable populations, and reduce the potential that climate change impacts will exacerbate existing inequities among vulnerable populations.

On August 8, the CPUC issued D.22-08-025 denying an SDG&E request for rehearing of D.21-07- 011. SDG&E's request for rehearing argued, among other things, that the reservation charge suspension was adopted without proper notice, would unlawfully shift costs to other customers, the demand assurance amount is insufficiently supported by the record, and that the Commission should pursue other methods to compensate microgrid customers that does not involve reducing standby charges.

Analysis: By facilitating the commercialization of microgrids, this proceeding is opening pathways for VCE and its customers to deploy microgrids to enhance the reliability of distributed generation and provide electricity to customers even amidst system outages.

Next Steps:

Track 4 Schedule (December 2021 Ruling)
• September 2022 - Public Workshop: Stakeholder Presentation on Microgrid Multi-Property Tariff Proposals
• September 2022 - Opening Comments to Stakeholder Microgrid Multi-Property Tariff Proposals, filed and served
• October 2022 - Reply Comments to Stakeholder Microgrid Multi-Property Tariff Proposals, filed and served
• Late October 2022 - ALJ Ruling with Energy Division Staff Proposal for Microgrid Multi-Property Tariff • November 2022 - Energy Division Public Workshop on Multi-Property Tariff • November 2022 - Opening Comments to Energy Division Staff Proposal for Microgrid Multi-Property Tariff, filed and served Track 5 Schedule
• Q3 2022 – public workshops to be held on Definitions, Metrics, Tools, and Methods • Q4 2022 – public workshops to be held on Informing Grid Planning • Q1 2023 - Staff Proposal on [topic] to be issued
• Q1 2023 - ALJ Ruling Establishing 2023 Scheduling & Activities to be issued Additional Information: D.22-08-025 (August 8, 2022); ALJ Ruling Requesting Comments on attached Staff Proposal (July 6, 2022); Amended Scoping Memo and Ruling (December 17, 2021); D.21-12- 48 12
004 (December 6, 2021); Amended Scoping Ruling (August 17, 2021); D.21-07-011 (July 16, 2021); D.21-04-021 modifying D.21-01-018 (April 16, 2021); D.21-01-018 (January 21, 2021); Amended Scoping Ruling (July 3, 2020); D.20-06-017 (June 17, 2020); Scoping Memo and Ruling (December 20, 2019); OIR (September 19, 2019); Docket No. R.19-09-09.

NEWBuilding Decarbonization
On August 8, the CPUC issued a Proposed Decision that would adopt a Staff Proposal to eliminate gas line extension allowances, the 10-year refundable payment option, and the 50% discount payment option provided under the current gas line extension rules. The elimination would apply to all customers in all customer classes for new applications for gas line extensions submitted on or after July 1, 2023.

Background: The initial scope of this proceeding includes alternatives that could lead to the reduction of greenhouse gas (GHG) emissions associated with energy use in buildings, particularly issues related to the State’s goals of reducing economy-wide GHG emissions 40% below 1990 levels by 2030 and achieving carbon neutrality by 2045 or sooner.

D.20-03-027 established the framework for Commission oversight of two building decarbonization pilot programs – the Building Initiative for Low-Emissions Development (BUILD Program) and the Technology and Equipment for Clean Heating (TECH Initiative). The decision appropriated 40% of a $200 million budget for the BUILD Program and 60% for the TECH Initiative required under SB 1477.

D.21-11-002 adopted a set of guiding principles for the layering of incentives from various building decarbonization programs and a statewide Wildfire and Natural Disaster Resiliency Rebuild Program (WNDRR Program) to provide incentives to help homeowners impacted by a natural disaster rebuild all-electric homes, and provided guidance on data sharing of customer and other information among the Commission, the California Energy Commission, the participating electric utilities, and the implementers and evaluators of building decarbonization programs. Additionally, it directed the IOUs to study net energy (electric and gas) bill impacts that result when a residential customer switches from a natural gas water heater to an electric heat pump water heater. If an IOU’s study reflects a net increase in energy bills, to the IOU must propose a rate adjustment in a new Rate Design Window application in order to eliminate any financial disincentive for fuel switching.

Details: On August 8, the CPUC issued a Proposed Decision that would adopt a Staff Proposal to eliminate (with very limited exceptions) certain gas line extension rules, including allowances, a 10- year refundable payment option, and a 50% discount payment option. The elimination would apply to all customers in all customer classes for new applications for gas line extensions submitted on or after July 1, 2023. Opening comments on the Proposed Decision were filed on August 29. The Proposed Decision may be approved by the Commission as early as the September 15 Commission meeting.

Analysis: Building decarbonization generally involves a combination of increased energy efficiency and electrification. The conversion from fossil fuels to electricity is essential to reducing GHG emissions, particularly in the stock of existing buildings. Efforts to decarbonize buildings will likely increase electricity consumption and electric load in VCE’s service area and increase the rate of growth in VCE’s procurement requirements over time. Early planning for those increased requirements, supporting efforts to maximize energy efficiency as part of decarbonization efforts, and integrating distributed generation and other resources like electric vehicles will have long-term benefits and enable VCE to maximize decarbonization benefits at minimal cost within its service area.

Next Steps:

September 5, 2022 – Reply Comments on Proposed Decision due September 15, 2022 – Earliest Commission may vote on the Proposed Decision 49 13
Additional Information: Proposed Decision (August 8, 2022); ALJ Ruling on procedural schedule (March 22, 2022); Amended Phase 3 Scoping Ruling (December 17, 2021); Phase 3 Scoping Ruling (November 16, 2021); D.21-11-002 (Appendices A-E) Decision on Building Decarb Phase II (November 9, 2021); Phase 2 Scoping Ruling and Staff Proposal (August 25, 2020); D.20-03-027 Establishing Building Decarbonization Pilot Programs (April 6, 2020); ALJ Ruling Requesting Comment and Staff Proposal on Building Decarbonization Pilots (July 16, 2019); Amended Scoping Ruling (July 16, 2019); Assigned Commissioner’s Scoping Memo and Ruling (May 17, 2019); OIR (February 8, 2019); Docket No. R.19-01-011.

NEWTransportation Electrification
On August 9, the CPUC issued D.22-08-024 adopting the plug-in electric vehicle (PEV) submetering protocol and adopting electric vehicle supply equipment (EVSE) communication protocols. Under this Decision, large investor-owned utilities (including PG&E) and small multi-jurisdictional utilities are required to implement the submetering protocol for all customers with PEVs and customer-owned submeters.

Background: This rulemaking implements transportation electrification programs, tariffs, and policies and seeks to develop a comprehensive framework to guide the Commission’s role in the electrification of California’s transportation sector.

On February 3, 2020, the Administrative Law Judge issued a staff proposal, the Draft Transportation Electrification Framework (Draft TEF), intended to govern IOU transportation electrification investments and programs over the next decade. The Draft TEF posed numerous questions to stakeholders regarding Commission-jurisdictional transportation electrification efforts. Parties filed a series of comments on the Draft TEF in 2020. Peninsula Clean Energy and a group of joint CCAs filed comments arguing that CCAs should be permitted to administer transportation electrification programs funded through distribution funds.

D.21-07-028 adopted guidance and a streamlined advice letter process for the IOUs’ near-term priority (through 2025) transportation electrification investments and addressed issues of equity as they relate to transportation electrification.

D.21-12-033 implemented AB 841 by extending Commission policy to treat utility-side infrastructure upgrade costs triggered by the installation of electric vehicle supply equipment (EVSE) as distribution costs.

On February 25, Assigned Commissioner Rechtschaffen issued a Ruling proposing to substantially shift the transportation electrification framework in light of several California legislative developments and additional funding opportunities. Under this new framework, there would be five-year funding cycles with mid-term reviews. Funding Cycle 0 (through 2024) would focus implementation of $1.48 billion in already-authorized, IOU-administered programs, including those approved in D.21-07-028.

For Funding Cycle 1 (2025 – 2029), the Ruling proposed a $1 billion statewide rebate program for the installation of behind-the-meter EV chargers, prioritizing deployment in underserved and disadvantaged communities, critical sectors, medium-duty/heavy-duty vehicles and multi-unit dwellings. The Ruling proposed a single, statewide third-party administrator of the rebates and a single, statewide third-party administrator of marketing, education and outreach programs. The Ruling discussed potential roles for CCAs in this rebate framework.

On April 25 and May 16, Parties filed opening and reply comments, respectively, in response to the Ruling. The Joint CCAs argued that a uniform statewide program could leave out underserved customer segments, and that local customization of EV charger incentives by CCAs should be authorized.

Details: On August 9, the CPUC issued D.22-08-024 adopting the plug-in electric vehicle (PEV) submetering protocol and adopting electric vehicle supply equipment (EVSE) communication 50 14
protocols. Under this Decision, large investor-owned utilities and small multi-jurisdictional utilities are required to implement the submetering protocol for all customers with PEVs and customer-owned submeters. The PEV Submetering Protocol is not available to NEM customers at this time; however, by August 5, 2023, the IOUS are directed to hold a public workshop to explore potential pathways to allow PEV submetering for NEM customers and file and serve a workshop report within 60 days following the workshop.

On August 15, the Commission issued a Disposition Letter accepting PG&E’s AL 6638-E on the demonstration of pathways to scale vehicle-grid integration Pilot 3 for microgrids, effective August

11. Analysis: The protocols approved in D.22-08-024 ensure EVs may be connected to the grid with bi-directional equipment, enabling them to function as both an energy consumer and provider depending on grid needs. These capabilities will reduce the cost of EV charging and spur increased adoption of EVs. The protocols also establish uniform technology standards and prevent excess costs associated with utility requirements for duplicative grid interconnection equipment. With these protocols in place, EVs located in VCE’s service area will be able to function as an energy resource and provide grid support, potentially helping reduce curtailment and negative prices by providing demand and also providing capacity and emergency response during times of high power demand.

Next Steps: A Proposed Decision on the Assigned Commissioner’s Ruling regarding the revised transportation electrification framework was expected for Q2 2022 but has been delayed. Following the decision, the IOUs would be required to file advice letters and issue an RFP for third-party administrators.

Additional Information: D.22-08-024 (Attachment A – Submetering Protocol) (August 9, 2022); PG&E AL 6638-E (July 1, 2022); Ruling granting VCE Party Status (March 30, 2022); Ruling entering Staff Proposal on Transportation Electrification Framework to record (February 25, 2022); D.21-12-033 (December 22, 2021); D.21-07-028 (July 22, 2021); D.20-12-029 (Appendices) (December 22, 2020); D.20-12-027 (December 21, 2020); D.20-09-025 (September 28, 2020); ALJ Ruling providing Staff Proposal of Draft Transportation Electrification Framework (February 3, 2020); OIR (Appendices) (December 19, 2018); Docket No. R.18-12-006.

NEWCommercial EV Real-Time Pricing Pilot
On August 9, the CPUC issued D.22-08-002 approving the Marginal Generation Capacity Cost Study for use by PG&E when calculating Real-Time Pricing rates, adopting the Real-Time Pricing settlement, and closing A.19-11-019. Opt-in enrollment for the Real-Time Pricing Pilot for commercial electric vehicles begins October 1, 2023.

Background: PG&E proposed a pilot to evaluate customer understanding and supporting technology for a commercial electric vehicle rate featuring day-ahead hourly real-time pricing (DAHRTP-CEV). The proposed pilot differs from the CEV rate approved in D.19-10-055 by providing a dynamic price that can change every day from hour to hour. Some key issues identified for consideration in this proceeding include uncertainty regarding revenue recovery and cost shifts, the nascent nature of the customer support vendor and technology ecosystem, Community Choice Aggregator (CCA) and other Energy Service Provider (ESP) participation, bill impacts, and considerations regarding operational infrastructure and scalability. The initial proposed Pilot would allow for enrollment of 50 customers currently being served on a Business Electric Vehicle (BEV) BEV rate schedule.

The DAHRTP-CEV pilot rate was proposed as a rate rider that would replace the time-of-use (TOU) rates on Scheduled BEV-1 and BEV-2 with a generation rate based on the CAISO’s day-ahead hourly wholesale market while maintaining the rate for transmission, distribution, and nonbypassable charges from the original CEV Schedule.
51 15
D.21-11-017 approved the optional DAHRTP-CEV rate for and customer already enrolled in or eligible to enroll in a BEV rate, required customer outreach and education, and the development of evaluation metrics and reporting requirements for the opt-in rate. Approved rate components for the Pilot include a marginal energy cost (MEC) based on the CAISO hourly day-ahead market rate, a flat volumetric rate adder ($0.01972/kWh) to recover generation costs of service above marginal costs, and the same subscription charges in the existing CEV rate.

This Decision also required the development of a marginal generation capacity cost (MGCC) factor and established a Phase 2 of the proceeding to evaluate the MGCC study resulting in a proposed decision in Q3 2022.

The MGCC Study was filed on March 15, and a corrected version was filed on March 17. The Study identifies an hourly pricing formula that incorporates a temperature-adjusted net load, a price adder based on alert or notification events from the CAISO, and other adjustments, in part, to ensure a non-zero price during times with a low adjusted net load.

On March 24, PG&E filed a supplemental proposal for an export compensation mechanism for non-net energy metering (non-NEM) customers with behind-the-meter resources. This proposal would provide compensation for energy exports from the CAISO market, including resource adequacy if available and appropriate.

A Joint Motion to submit a stipulation on the MGCC was filed on April 13 by the PAO, the California Large Energy Consumers Association (CLECA), Small Business Utility Advocates (SBUA), Enel X North America, Inc. (Enel X), and PG&E. A Joint Motion for Settlement Agreement 9RTP Settlement) was filed June 24 by the PAO, Vehicle-Grid Integration Council (VGIC), Electrify America, and PG&E that resolved all issues related to the DAHRTP-CEV pilot and non-NEM export compensation. A Proposed Decision was filed on June 22.

Details: On August 15, the CPUC issued D.22-08-002 approving the MGCC Study for use by PG&E when calculating RTP rates, adopting the RTP settlement, and closing A.19-11-019.

This Decision adopts the uncontested RTP Settlement, making bundled customers on PG&E’s large commercial (B-20), small commercial (B-6), and E-ELEC residential rates, as well as unbundled customers of participating CCAs eligible to participate in the RTP Pilot (additional customers served on other commercial rates may be made eligible at a later date via a Tier 1 AL filing by PG&E).

RTP Pilot Duration: The Stage 1 pilots have a targeted launch date of October 1, 2023, and have an initial duration of 24 months, with the possibility of extension following the Commission’s review of the Interim Evaluation Report of the first 12 months that will be submitted on March 1, 2025 in a Tier 2 advice letter.

RTP Pilot Rate Design: The real-time portion of the pilot rates would only replace the generation component while transmission, distribution, Public Purpose Program, and other charges and taxes would be unchanged. The generation component includes the following:
• Marginal Energy Cost (MEC) price signal;
• Marginal Generation Capacity Cost (MGCC) price signal identical to that used in the commercial EV rate; and
• A Revenue Neutral Adder (RNA) intended to make the pilot rates revenue-neutral to the base rate schedule (also includes the PCIA charge and may be adjusted in response to general rate case cycles to maintain revenue neutrality).

Analysis: This proceeding created a real-time pricing pilot that includes pricing for both imports from and exports to the grid by commercial electric vehicles. This mechanism provides a foundation for the use of EVs as mobile energy storage systems and grid resources, potentially enabling a future where vehicles provide an automated dynamic response to real-time electricity price signals and 52 16
transportation adopts a central role in balancing electricity supply and demand, mitigating grid emergencies, and further enabling higher penetration of renewables. The RTP methodology approved in D.22-08-002 applies to PG&E real-time pricing rates used in this pilot as well as those in approved in D.21-11-017, and revisions to the methodology will be considered after an initial evaluation of the pilot.

Next Steps: Opt-in enrollment begins October 1, 2023. The MGCC Study working group must be reconvened to consider whether any revisions should be made to the marginal generation capacity cost hourly price signal methodology after the initial evaluation of the Pilot is complete, but no later than October 1, 2025.

Additional Information: D.22-08-002 Adopting Decision Real Time Pricing Pilot (August 15, 2022); Joint Motion for Settlement Agreement (June 24, 2022); Joint Motion to submit Stipulation on MGCC (April 13, 2022); PG&E Proposal for export compensation for non-NEM customers (March 24, 2022); Corrected MGCC Study (March 17, 2022); ALJ Ruling on procedural schedule (January 14, 2022); Scoping Ruling and Memo (December 17, 2021); D.21-11-017 PG&E To Implement an Optional Day-Ahead Real Time Rate (Appendix B - Joint Stipulation on Study for MGCC Rate Design Issue) (November 19, 2021); Assigned Commissioner’s Scoping Ruling and Memo (January 25, 2021); Application & Testimony (October 23, 2020); Docket No. A.20-10-011.

NEWDemand Flexibility
The OIR was issued by the Commission on July 22. Opening comments were filed by VCE and 47 other parties, and a pre-hearing conference is scheduled for September 16.

Background: This rulemaking will update the Commission’s rate design principles and guidance for advancing demand flexibility, and through it the Commission may also modify, consolidate, or eliminate existing rates and authorize additional pilots, rates, programs, studies, or tools. The objectives for the rulemaking are:
• enhance the reliability of California’s electric system; • make electric bills more affordable and equitable;
• reduce the curtailment of renewable energy and GHG emissions associated with meeting the state’s future system load;
• enable widespread electrification of buildings and transportation to meet the state’s climate goals;
• reduce long-term system costs through more efficient pricing of electricity; and • enable participation in demand flexibility by both bundled and unbundled customers.

Details: The preliminary issues scoped for this proceeding are focused on how the Commission may enable and encourage adoption of widespread demand flexibility to improve system reliability and advance State climate goals affordably and equitably. The scope covers questions regarding updated guiding principles for rate design and evaluation; the use of additional pilots, tariffs, programs, or studies; reform of demand charges and fixed charges; providing universal access to dynamic electricity pricing, and efforts to inform customers and ease the transition to dynamic rates.

On August 15, VCE and Polaris submitted joint opening comments highlighting their experience with the AgFIT Pilot, encouraging the Commission to reexamine or reform demand-based rates, supporting universal real-time access to dynamic prices for all customers and LSEs, and offering examples of lessons and experiences from the AgFIT Pilot, particularly regarding the importance of customer support and outreach, as well as the use of demand automation technology. TeMix filed 53 17
comments recommending bi-directional rates be based on scarcity pricing rather than marginal cost, supporting authorization of the CalFUSE tariff as opt-in for all customer classes immediately, replacing demand charges with scarcity pricing, using a subscription component to ensure stability and adequate revenue collection, and supporting customer engagement and education outreach efforts. CalCCA filed comments recommending that the Commission ensure that all LSEs have timely access to usage data; that IOU rate designs for transmission and distribution not adversely impact CCA generation rates to the harm of demand flexibility; that the proceeding emphasize that all customers can address the issues of reliability, affordability, and meeting of policy goals whether served as bundled or unbundled load; and that the use of fixed charges be limited to transmission and distribution rates, which are driven primarily by fixed costs.

Analysis: Although the scope of this proceeding has yet to be determined through issuance of the forthcoming Scoping Memo, the potential for broad impact for VCE’s customers is apparent. This proceeding will address issues of importance to VCE, including dynamic rates, demand response and other load shifting efforts.

Next Steps: The Commission intends to conclude this proceeding within 24 months and expects to issue a more detailed procedural schedule in late September.
• September 16, 2022 – Pre-Hearing Conference
• Q3 2022 – Scoping Memo and Ruling issued
Additional Information: Notice of Pre-Hearing Conference (August 19, 2022); VCE & Polaris Joint Comments (August 15, 2022); CalCCA Comments (August 15, 2022); OIR (July 22, 2022); Docket No. R.22-07-005.

NEWDemand Response Programs (2023-2027)
On July 5, the Assigned Commissioner issued a Scoping Memo and Ruling defining the scope of issues and providing a procedural schedule for Phase 1.

Background: This proceeding addresses the IOUs’ Demand Response (DR) Portfolio Applications required under D.17-12-003 for the years 2023-2027. IOU demand response budgets and activities for the years 2018-2022 were approved in D.17-12-003.

PG&E, SCE, and SDG&E each filed Applications for development of a demand response portfolio on May 2, and a May 25 ALJ Ruling consolidated these Applications. The Applications contain both proposals for Bridge Funding that would be expedited in order to implement 2023 programs and ensure continued operation of ongoing demand response programs, while portfolio proposals for the years 2024 – 2027 will be considered in Phase 2. A prehearing conference (PHC) was held on June 16 to discuss the scope, schedule, and other procedural matters.

Details: The July 5 Scoping Memo and Ruling divided the proceeding into two phases. Phase 1 will address the IOUs’ 2023 Bridge Year Funding Requests and consider whether the Auction Mechanism should be used with 2023 solicitations for 2024 deliveries, and Phase 2 will address the IOUs’ Applications for the years 2024-2027 and continued use of the Auction Mechanism beyond 2024. The Commission expects a Decision regarding Phase 1 to be issued during 2022 and anticipates that consideration of Phase 2 issues will also begin later in 2022.

Phase 2 issues will be scoped to address the 2024-2027 DR program proposals at a later date and will include consideration of the DR Auction Mechanism’s future beyond 2024. As part of the Phase 2 scope, the Commission plans to consider the future of the DR Auction Mechanism (Auction Mechanism), including whether it should be continued for delivery year 2024. A DR Auction Mechanism Evaluation Report (Nexant Report) was attached to the July 5 Scoping Memo and Ruling.
54 18
Analysis: This proceeding considers the IOUs’ Applications for development of demand response portfolio as well as the future use of the DR Auction Mechanism. The design, effectiveness, cost, and availability of these programs will determine their long-term efficacy in using technology to leverage demand as a grid resource. The success of DR programs has long-term potential to reduce electricity costs to consumers across the State.

Next Steps:

Phase 1 Procedural Schedule
• September 2, 2022: Concurrent Reply Briefs on Phase I Bridge Funding Applications • October 2022: Proposed Decision on Phase 1 Bridge Funding Applications • 30 days after issuance of Proposed Decision: Commission decision on Phase I Phase 1 Auction Mechanism Schedule
• September 2, 2022: Reply Testimony Due on Nexant Report and Auction Mechanism • September 9, 2022: Meet and Confer to Determine Need for Evidentiary Hearings • September 16, 2022: Last Day to Request Evidentiary Hearing and Conduct Discovery • Late September 2022: Evidentiary Hearings
• October 7, 2022: Opening Briefs on Nexant Report and Auction Mechanism • October 28, 2022: Concurrent Reply Briefs on Nexant Report and Auction Mechanism • December 2022: Proposed Decision
Additional Information: Assigned Commissioner’s Scoping Memo and Ruling and Demand Response Auction Mechanism Evaluation report by Nexant (July 5, 2022); Ruling consolidating Applications (May 25, 2022); PG&E Application (May 2, 2022); Docket No. A.22-05-002.

PCIA Rulemaking
On July 19, the CPUC issued D.22-07-008 on PCIA Data Access, resolving Phase 2 issues related to data access and voluntary allocations in market price benchmark calculations. On August 4, the ALJ issued a Ruling requesting comment on long-term fixed-price RPS transactions and providing a Staff Proposal for Incorporating Long-Term RPS Transactions into the RPS MPB.

Background: D.18-10-019 was issued on October 19, 2018, in Phase 1 of this proceeding and left the current Power Charge Indifference Adjustment (PCIA) in place, maintained the current brown power index, and adopted revised inputs to the benchmarks used to calculate the PCIA for energy RPS-eligible resources and resource adequacy capacity.

In Phase 2, D.20-08-004 the Commission adopted a framework for PCIA prepayment agreements.

D.21-05-030 removed the cap and trigger for PCIA rate increases, authorized new Voluntary Allocation, Market Offer, and Request for Information processes for RPS contracts subject to the PCIA, and approved a process for increasing transparency of IOU resource adequacy (RA) resources. However, it did not provide unbundled customers proportional access to system and flexible RA products through the RA voluntary allocation and market offer process proposed by PCIA Working Group 3. Likewise, it declined to provide unbundled customers any access to GHG-free energy on a permanent basis. The CCA Parties’ Application for Rehearing of D.21-05-030 was denied.
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D.22-01-023 modified the PCIA market price benchmark (MPB) release date to October 1 and the deadline for ERRA forecast applications to May 15 to enable the timely issuance of ERRA forecast decisions by the Commission.

On June 24, Assigned Commissioner Reynolds issued a Revised Scoping Memo and Ruling that extends the statutory deadline to June 30, 2023 to address the following issues:
• Whether greenhouse gas-free resources are under-valued in the Power Charge Indifference Adjustment (PCIA), and if so, whether to adopt an adder or allocation mechanism; • Whether to adopt a new method to include long-term fixed-price transactions in calculating the Renewables Portfolio Standard adder;
• Whether to modify the calculation of the PCIA energy index market price benchmark; and • Whether to modify or clarify the calculation of the PCIA for Voluntary Allocation or Market Offer transactions.

Details: D.22-07-008 resolved Phase 2 issues related to PCIA data access and voluntary allocations in MPB calculations. This decision establishes a standard process for a representative of CCAs to review confidential ERRA data for the purpose of developing PCIA forecasts and to disclose non-confidential analyses of PCIA forecasts to CCAs. The decision also confirms that Voluntary Allocations should be excluded from calculations of the RPS’s MPB.

The data access provided for under this decision is intended to help protect CCA customers from rate volatility by creating a process for a representative of the CCAs to review of PCIA rate and PABA balance forecasts, and to predict whether current trends are likely to continue or self-correct.

The decision ordered that CalCCA or any other CCA may convene a meeting by October 3 to discuss the proposed format and content of the non-confidential analyses of PCIA forecasts that may be disclosed to CCAs under this decision.

A joint Tier 2 Advice Letter should be filed on behalf of CCAs by December 1 containing a proposal for the following:
• A standard template for conveying descriptions of drivers of anticipated PCIA changes (using the public analysis of drivers in PG&E’s November Update in A.21-06-001 as a model) and descriptions of single- or multi-year PCIA rate projections developed by reviewing representatives;
• A public appendix with a full example analysis that uses the proposed template and dummy information;
• A proposed non-disclosure agreement based on the ERRA forecast non-disclosure agreement; and
• A list of all CCAs that seek this forecasting data access and their reviewing representatives.

CCAs’ reviewing representatives must simultaneously serve the Commission and the relevant IOU all information disclosed to clients. Reviewing representatives are permitted to disclose information only once per calendar quarter and are prohibited from disclosing any information pursuant to this decision that is not explicitly included in the approved standard template for disclosures. Joint CCAs may request modification of the standard template for disclosures no more than once per year by filing a Tier 2 Advice Letter by January 31 of each year.

On August 4, the ALJ issued a Ruling requesting comment on long-term fixed-price RPS transactions and providing a Staff Proposal for Incorporating Long-Term RPS Transactions into the RPS MPB. The Staff Proposal includes the following recommendations:
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• Including short-term index-plus (STIP) and long-term fixed-price (LTFP) PCC-1 transactions in the RPS MPB while continuing to exclude long-term index-plus (LTIP) and short-term fixed-price (STFP) transactions; • Requiring LSEs to provide an RA value for LTFP transactions that include RA capacity for use in calculating the RPS MPB; and
• For the semiannual RPS-PCIA Data Request, adding a required field for LSEs to indicate whether a transaction was mandatory, and making the existing “Deemed Capacity Value,” “Deemed Energy Value,” and “Net Market Value” fields mandatory.

Analysis: The MPB calculation is used as the basis for pricing RPS resources under the Voluntary Allocation process, and the MPB benchmark price is used in ERRA forecasts to determine PG&E’s PCIA-related revenue requirement. This proceeding is examining approaches to modifying the way the MPB is calculated, in part, to address the potential misrepresentation of current market activity resulting from use of the prior year’s MPB to value RPS resources in the Voluntary Allocation process. Changes to the MPB calculation will influence resource procurement decisions and potentially customer costs.

Next Steps: The August 4 Ruling modified the schedule such that a staff proposal on GHG-free resources will be provided along with a Ruling requesting comment in late August/early September, and the November workshop will now address both staff proposals. • September 9, 2022: Reply comments due on Ruling requesting comments on long-term RPS transactions
• August/September 2022: ALJ Ruling requesting comment on a staff proposal regarding GHG-free resources
• October 3, 2022: deadline for CCA meeting to discuss PCIA forecast disclosure • November 2022: Workshop on Staff Proposals for long-term fixed-price RPS resources and GHG-free resources
• December 1, 2022: CCAs’ Tier 2 AL proposal for PCIA data access due Additional Information: Ruling Requesting Comments and Staff Proposal for Long-Term RPS Transactions (August 4, 2022); D.22-07-008 (July 19, 2022); Revised Scoping Memo and Ruling (June 24, 2022); Proposed Decision on data access and MPB benchmarks (June 10, 2022); Ruling Regarding Market Price Benchmarks (April 18, 2022); Resolution E-5134 approving PCIA pre-payment framework ALs (March 21, 2022); D.22-01-023 on Phase 2 (approved January 27, 2021); Ruling requesting comments on PCIA forecasting data access (November 5, 2021); Ruling requesting comments (September 17, 2021); PG&E AL 5973-E-A PCIA pre-payment framework (August 13, 2021); CalCCA Application for Rehearing of D.21-05-030 (June 23, 2021); D.21-05-030 on PCIA Cap and Portfolio Optimization (May 24, 2021); D.21-03-051 granting petition to modify D.17-08-026 (March 26, 2021); Amended Scoping Memo and Ruling (December 16, 2020); PG&E AL 5973-E PCIA pre-payment framework (October 12, 2020); Joint IOUs PFM of D.18-10-019 (August 7, 2020); D.20-08-004 on Working Group 2 PCIA Prepayment (August 6, 2020); D.20-06- 032 denying PFM of D.18-07-009 (July 3, 2020); D.20-03-019 on departing load forecast and presentation of the PCIA (April 6, 2020); D.20-01-030 denying rehearing of D.18-10-019 as modified (January 21, 2020); D.19-10-001 (October 17, 2019); D.18-10-019 Track 2 Decisions adopting the Alternate Proposed Decision (October 19, 2018); D.18-09-013 Track 1 Decision approving PG&E Settlement Agreement (September 20, 2018); Docket No. R.17-06-026. 57 21
Provider of Last Resort Rulemaking
On July 15, the CPUC issued a Disposition Letter accepting PG&E AL 6589-E_E-A_E-B on financial security requirements for CCAs which became effective as of August 6.

Background: A Provider of Last Resort (POLR) is the utility or other entity that has the obligation to serve all customers (e.g., PG&E is currently the POLR in VCE's territory).

The Scoping Memo and Ruling issued September 16, 2021, provides that Phase 1 of this OIR 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 decision to set the requirements and application process for other non-IOU entities (i.e., a CCA, Energy Service Provider, or third-party) to be designated as the POLR in place of an existing POLR. Phase 3 will address specific outstanding issues not resolved in Phase 1 and 2 of this proceeding.

A workshop was held on October 29, 2021, for the purpose of reviewing the operation and expectation of Provider of Last Resort service, registration, and financial security requirements, and a second workshop was held on March 7 for the purpose of developing a framework to consider the issues and recommendations of the previous workshop.

Party comments on the first workshop were filed on March 28. Some of CalCCA’s proposals included maintaining the six-month runway to prepare for the return of customers, refining the Financial Service Requirements (FSRs) to reflect the current Market Price Benchmarks (MPBs) for Resource Adequacy (RA) and RPS products, maintaining the existing right to an RA waiver, not requiring resource procurement in advance of customer returns, and implementing a three-tiered reporting rubric calibrated to the operating CCA’s circumstances.

On May 10, PG&E submitted AL 6589-E with calculated financial security requirements for CCAs, followed by submission of supplemental AL 6589-E-A on May 17. On May 31, CalCCA filed a protest of PG&E ALs 6589-E and 6589-E-A requesting that the Commission require PG&E to correct the period for determination of “peak load” in applying the applicable resource adequacy (RA) cost based on PG&E’s own tariff by updating the proposed FSR amount using a peak demand based on the most recent 12 months of historical peaks. On July 7, PG&E submitted its second supplemental AL 6589-E-B that replaces the previous versions in their entirety and revised the number of months used to calculate each Community Choice Aggregator’s (CCA) average peak demand forecast to be consistent with PG&E’s electric Rule 23, Community Choice Aggregation Service.

Details: On July 15, the CPUC issued a Disposition Letter accepting PG&E AL 6589-E_E-A_E-B on financial security requirements for CCAs which became effective as of August 6. A confidential version of PG&E AL 6589-E-B showing the financial security requirements calculated for individual CCAs was sent to each CCA.

Analysis: PG&E’s AL 6589-E-B describes the method and the inputs for determining the Financial Security Requirement (FSR) to be contributed by each CCA to cover the costs between the time a CCA’s customers transition to POLR service and when the POLR begins receiving revenue. The resource adequacy portion of each CCA’s FSR amount is determined in part by the trailing six months’ average of the CCA’s peak load. While the costs of meeting the FSR are unavoidable, the amount of the FSR can be influenced by efforts to reduce monthly peak load.

Next Steps:
• August 2022: Energy Division Staff Proposal on Phase 1 Issues • September 2022: Workshop on Energy Division Staff Proposal • September 2022: Workshop on Potential/Example Changes to FSR Calculator 58 22
• October 2022: Opening Comments Filed and Served on Energy Division Staff Proposal/Potential Changes to FSR Calculator
• October 2022: Reply Comments Filed and Served on Energy Division Staff Proposal/Potential Changes to FSR Calculator
• Q1 2023 – Q2 2023: Phase 1 Proposed Decision
Additional Information: PG&E AL 6589-E-B and Disposition Letter (July 7, 2022); CalCCA Protest of AL 6589-E (May 31, 2022); Ruling granting extension of time and modifying procedural schedule (May 24, 2022); PG&E’s AL 6589-E-A on FSR Requirements (May 17, 2022); PG&E’s AL 6589-E on FSR Requirements (May 10, 2022); Ruling Requesting Comments (May 2, 2022); POLR webpage with workshop presentations and videos; Golden State Power Cooperative Motion to remove cooperatives as respondents (October 28, 2021); Scoping Memo and Ruling (September 16, 2021); Order Instituting Rulemaking (March 25, 2021); Docket No. R.21-03-011.

PG&E 2023 Phase 1 GRC
On July 22, PG&E filed its Track 2 request for a reasonableness review of recorded costs and recovery of $241 million in costs over two years. On August 9, PG&E filed a Case Management Statement reporting no settled issues among the Parties and withdrawing its revenue requirement request for two disputed projects. Track 1 Evidentiary Hearings were held August 15-26, and Keyes & Fox LLP cross examined a panel of PG&E witnesses on their rebuttal to the Joint CCAs’ re-vintaging testimony during the hearings.

Background: Phase 1 General Rate Case (GRC) applications cover the revenue requirement, including the functionalization of costs into categories such as electric distribution or generation, and impacts which customers (bundled, unbundled, or both) pay for the costs through rates. Phase 2 GRC applications cover cost allocation (i.e., assigning costs to customer classes, such as Residential) and rate design issues. On August 25, 2021, the CPUC Executive Director granted PG&E’s request to delay filing its next Phase 2 GRC application until September 30, 2024.

The October 1, 2021 Scoping Memo and Ruling divided the proceeding 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.

On March 9, PG&E submitted its recorded expense and capital data testimony for 2021. On March 10, PG&E filed an Amended Application and submitted supplemental testimony on wildfire mitigation programs.

PG&E and Caltrain submitted a joint report on the status of the third-party audit of costs that PG&E will incur to upgrade the East Grand and FMC substations in connection with Caltrain’s project to electrify its commuter rail system between San Jose and San Francisco. PG&E and Caltrain also requested to move consideration of PG&E’s proposal for cost recovery of Caltrain Project costs from Track 1 to Track 2 of PG&E’s 2023 GRC and proposed a schedule for the submission of testimony reporting on the Audit.

The April 12 email Ruling denied the February 16 Motion to adopt a final date for discovery regarding the earlier submitted testimony and adopted a revised procedural schedule for both Track 1 and Track 2.

On April 20, PG&E filed an application to modify its cost of capital that requests an overall rate of return of 7.78% and a $69.3 million increase in its revenue requirement. The company proposed a capital structure with 47.5% debt at a cost of 4.27%, 0.5% preferred equity at a cost of 5.52%, and 52% common equity at a cost of 11%.
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On June 13, intervenors submitted direct testimony, including Joint CCAs’ testimony regarding recovery of PG&E’s proposed generation revenue requirement from bundled and unbundled customers, a Utility-Owned Generation vintaging framework to be used in future GRC proceedings to properly track and account for generation revenue requirements, and proper functionalization of costs associated with batteries on PG&E’s electric distribution system.

On June 24, the CPUC issued D.22-06-033 establishing the effective date of PG&E’s 2023 test year revenue requirement as January 1, 2023.

Details: On July 22, PG&E filed its Track 2 request for a reasonableness review of recorded costs and recovery of $206 million in expenses and $129 million in capital expenditures for a total incremental revenue requirement increase of $241 million over two years.

On August 9, PG&E filed a Case Management Statement reporting no settled issues among the Parties and withdrawing its revenue requirement request for two disputed projects. The revenue requirement request for the Gateway Generating Station of $3 million per year for 2021, 2022, and 2023 was withdrawn because the project will not be completed during the GRC period. The request for the Renz Energy Storage project was forecast at $26.5 million, but PG&E reports that the contract for the purchase was terminated and the project will not be installed. During the 2023 GRC period, PG&E also agreed to spend $26 million on small business outreach, $6.8 million on accessibility improvements for customers with disabilities, and $4 million to support the needs of underserved communities including communities of color.

During the Track 1 Evidentiary Hearings (August 15-26), Keyes & Fox LLP cross examined a panel of PG&E witnesses on their rebuttal to the Joint CCAs’ re-vintaging testimony. In particular, the Joint CCAs’ cross examination focused on getting admissions from PG&E that:
(1) PG&E’s hydroelectric facility extensions constitute new commitments; (2) These new commitments are made on behalf of bundled customers (e.g., PG&E uses these facilities to fulfill its resource adequacy requirements on behalf of bundled customers; decisions regarding whether to sell/retire/relicense the facilities take into account bundled customers’ energy needs; PG&E’s claim that the ongoing investments in these facilities could result in a lower PCIA is irrelevant to whether the costs associated with these re-investments belong in the PCIA; other benefits that PG&E argues flow to unbundled customers from these resources being extended are unmonetized public benefits (which are also provided by CCA-owned resources)); and (3) The Joint CCAs’ general vintaging framework is designed to allow for a case-by-case consideration of new generation resource commitments made by PG&E.

Analysis: This proceeding will set the revenue requirement, and thereby ultimately impact PG&E’s rates for 2023-2026. It will establish how the revenue requirement components will be functionalized, which impacts whether the ultimately approved costs will be borne by PG&E bundled customers, unbundled customers like VCE customers, or both. It will also address numerous other issues raised in PG&E’s application that could impact rates, policies, and programs implemented by PG&E.

The resolution of the issues covered in the Joint CCAs’ direct testimony will impact how certain generation-related costs in PG&E’s current and future applications will be vintaged for purposes of PCIA cost recovery. It will also impact how the costs associated with an energy storage project are functionalized.

Next Steps:

The Track 1 schedule, as modified in the April 12 Ruling is:
• Q3 2022: Decision on PG&E Motion for Interim Rates
• November 4, 2022: Opening Briefs
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• December 9, 2022: Reply Briefs
• March 24, 2023: Proceeding Submitted
• Q2 2023: Proposed Decision on A.21-06-021
The Track 2 schedule, as modified in the April 12 ruling is:
• TBD: Amended Scoping Memo issued, if needed
• November 14, 2022: Intervenor Opening Testimony
• December 14, 2022: Concurrent Rebuttal Testimony
• December 15, 2022 – January 20, 2023 – Meet & Confer (minimum of two times) • TBD (prior to Evidentiary Hearings): Status Conference • January 23 – January 27, 2023: Evidentiary Hearings
• February 24, 2023: Opening Briefs
• March 24, 2023: Reply Briefs
• March 24, 2023: Proceeding Submitted
• 2Q 2023: Proposed Decision on A.21-06-021
Additional Information: CPUC Resolution E-5217 (August 11, 2022); Case Management Statement (August 9, 2022); PG&E Track 2 Request (July 22, 2022); PG&E AL 6641-E (July 7, 2022); D.22-06- 033 on Effective Date of 2023 Revenue Requirement (June 24, 2022); PG&E Application to establish 2023 Cost of Capital (April 20, 2022); Ruling on Motions and Request to Modify Schedule (April 12, 2022); ALJ Ruling denying Motion to Shorten Time, accepting PG&E’s Amended Application, and suspending intervenor testimony deadline (March 10, 2022); PG&E’s Amended Application (March 10, 2022); PG&E Affordability Metrics Report (February 23, 2022); ALJ Ruling on Public Participation Hearings (February 2, 2022); PG&E/Caltrain Report (February 1, 2022); Ruling denying PG&E Motion to submit supplemental testimony (November 12, 2021); Motion of PG&E to modify procedural schedule (November 5, 2021); Scoping Memo and Ruling (October 1, 2021); PG&E Application (June 30, 2021); 2023 Cost of Capital Docket No. A.22-04-008; Docket No. A.21-06-021.

PG&E ERRA Forecast (2023)
On August 4, the Assigned Commissioner issued a Scoping Memo and Ruling setting forth the issues and a schedule intended to meet the deadline for the final 2022 Commission meeting allow for new rates to be effective January 1, 2023.

Background: 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.

On May 31, PG&E filed its 2023 ERRA Forecast application, requesting a 2023 ERRA forecast revenue requirement for ratesetting purposes of $4.486 billion. After accounting for $2.373 billion of Utility Owned Generation (UOG)-Related Costs and other adjustments totaling $2.534 billion, PG&E requested a net revenue requirement of $1.952 billion. These figures are expected to change when PG&E files its Fall Update in October.
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Details: After consideration of the issues and discussion during the July 18 Pre-Hearing Conference (PHC), the August 4 Scoping Memo and Ruling identified the following issues to be considered in this proceeding:
1) Whether PG&E’s requested 2023 ERRA forecast revenue requirement is reasonable, including but not limited to consideration of the following:
(a) forecast costs for fuel and purchased power expenses; (b) disposition of PG&E’s forecast December 31 year-end balancing account balances; (c) disposition of recorded Voluntary Allocation Market Offer Memorandum Account (VAMOMA) balances; and
(d) approval of PG&E’s methodology to include 2021 and 2022 renewable energy credits (RECs) toward the 2023 Power Charge Indifference Adjustment (PCIA) revenue requirement calculation and to allocate the value of 2021 and 2022 RECs to benefit bundled and departing load customers responsible for applicable Portfolio Allocation Balancing Account (PABA) vintage costs;
2) Adopt forecasted electric sales for 2023;
3) Adopt a forecast of greenhouse gas (GHG) revenues, revenue return, and administrative, programmatic, and customer outreach costs for 2023;
4) Determine whether PG&E’s 2021 GHG administrative and customer outreach costs as reasonable; and
5) Adopt rate design proposals associated with PG&E’s total electric procurement revenue requirements to be effective in rates on January 1, 2023, including Green Tariff Shared Renewables (GTSR) rates.

Other issues, raised by CalCCA, that will also be included in the scope are:
6) Whether PG&E has adequately supported its new proposed REC Tracking and Accounting Methodology, and whether the Commission should rule that the consideration of that methodology beyond the 2023 Renewables Portfolio Standard (RPS) Compliance Year is beyond the scope of this proceeding. At the PHC PG&E confirmed that its proposal was strictly limited to 2023 and was PG&E was not seeking, nor relying on any approval, for subsequent years.
7) That PG&E should continue to return the ERRA-PCIA Financing Subaccount (PFS) credit to bundled and unbundled customers by amortizing the final year of that credit through the PABA consistent with Decision 22-02-002.

Analysis: This proceeding will determine PG&E’s rates for 2023 based on its revenue requirement forecast. While final forecast figures will not be available until October, PG&E’s Application forecasted rates for CCA customers to decline 3.6% from $0.14287/kWh to $0.13779/kWh based on a $250.26 million revenue requirement reduction. Specific procurement costs that are expected to change in the Fall Update include those related to reliability under D.19-11-016 and D.21-06-035, Central Procurement Entity (CPE) administration and procurement, Voluntary Allocation/Market Offer (VAMO) process pending Commission decisions in R.18-07-003, Next Steps: The following procedural schedule includes some timelines that are more condensed than their normal duration in an attempt to meet the deadline for the final 2022 Commission Meeting and allow for new rates to be effective January 1, 2023.
• September 7, 2022 - Intervenor Testimony
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• September 28, 2022 - Concurrent Rebuttal Testimony
• October 3, 2022 - Market Price Benchmark provided by Energy Division • October 3, 2022 - Status Conference
• October 7, 2022 - Evidentiary Hearings
• October 14, 2022 - Concurrent Opening Briefs
• October 17, 2022 - October Update from PG&E
• October 21, 2022 - Concurrent Reply Briefs
• November 1, 2022 - Comments on October Update
• November 8, 2022 - Reply Comments & Submission
• November 29, 2022 - Proposed Decision
• December 6, 2022 - Comments on Proposed Decision due
• December 9, 2022 - Reply Comments on Proposed Decision due • December 15, 2022 - Commission Meeting Target
Additional Information: Scoping Memo and Ruling (August 4, 2022); Application (May 31, 2022); Docket No. A.22-05-029.

PG&E 2019 ERRA Compliance
On July 14, the CPUC issued D.22-07-009 extending the statutory deadline for the proceeding by an additional six months until March 1, 2023 in order to resolve the Phase 2 issues related to Public Safety Power Shutoff events.

Background: Phase 1 has been resolved. The September 7, 2021, Ruling consolidated the Phase 2 ERRA compliance proceedings of PG&E, SCE, and SDG&E. The issues scoped for Phase 2 are:
• What is the appropriate methodology for calculating a utility’s unrealized volumetric sales and unrealized revenues resulting from PSPS events in any given record year? Based on this methodology, what are the utilities’ (PG&E, SCE, and SDG&E) unrealized volumetric sales and unrealized revenues resulting from 2019 Public Safety Power Shutoff (PSPS) events? • Whether it is appropriate for the utilities to return the revenue requirement equal to the unrealized volumetric sales and unrealized revenue resulting from the PSPS events in 2019.

At the October 26, 2021, workshop hosted by Energy Division, the IOUs (PG&E, SCE, and SDG&E) made a joint presentation of their proposal for a methodology to calculate the revenue requirement of the estimated unrealized volumetric sales and unrealized revenue resulting from PSPS events.

The Joint CCAs filed a Motion on November 4, 2021, requesting the CPUC clarify the scope of issues in this proceeding. The November 12, 2021, Ruling clarified the CPUC’s intent to consider a range of PSPS methodologies, which may be proposed by both the IOUs and other parties. It provided that parties may conduct additional discovery to support their proposal of a reasonable alternative PSPS methodology. The CPUC will consider a PSPS methodology that includes 63 27
unrealized generation-related volumetric sales and revenues, along with the joint IOU proposal and potentially other PSPS methodologies
Details: The Joint IOUs’ recommendations to adopt their common methodology for calculating unrealized revenue from end-use customers de-energized during PSPS events were determined to be reasonable and approval was recommended in the Joint Case Management Statement.

Previously, the CCA Parties’ testimony identified all retail rate components that should be considered to provide a full accounting of the unrealized retail revenue during PSPS events. The testimony also described how, absent a ratemaking remedy, the IOUs will fully recover their authorized revenue requirement from all customers, including those receiving no electricity service during PSPS events, through pre-established balancing account mechanisms. The CCA Parties also explained the potential impact of PSPS events on wholesale generation revenue and the need to account any such reductions if generation resources are forced offline due to PSPS events.

The CCA Parties made recommendations on the following issues which remain in dispute per the Joint Case Management Statement:
• The calculation of unrealized retail revenue during PSPS events should include additional CPUC-jurisdictional rate components tied to balancing accounts that record IOU costs incurred despite lost sales to end use customers.
• Each IOU should make a full accounting of the balancing accounts implicated by the total unrealized retail revenue.
• Unrealized wholesale generation revenue should be quantified if utility-owned generation resources, or contracts with take-or-pay provisions, are forced out of service due to a PSPS event.
• Each IOU should record adjusting entries to affected balancing accounts, equal to the unrealized retail and wholesale generation revenue as applicable, to comply with the Commission’s directive to “forgo collection in rates from customers of all authorized revenue requirement equal to estimated unrealized volumetric sales and unrealized revenue resulting from PSPS events.”
TURN also filed testimony recommending that all revenue requirements from retail sales be disallowed.

Analysis: Phase 2 of the proceeding is assessing whether PG&E should be required to return its revenue requirement associated with unrealized sales associated with its 2019 PSPS events, and the methodology and inputs for calculating such a disallowance. VCE’s customers could benefit from such a CPUC-determined disallowance, e.g., via a bill credit or reduced PG&E charges. The Phase 2 determination will also impact the 2020 and 2021 ERRA Compliance proceedings.

Next Steps: There is no current procedural schedule.

Additional Information: Order Extending Statutory Deadline (July 18, 2022); ALJ Ruling Admitting Additional Exhibits into Evidence (July 13, 2022); Amended Procedural Schedule (April 6, 2022); Joint Case Management Statement (February 25, 2022); Order Denying Rehearing of D.21-07-018 and PG&E’s application for rehearing of D.21-07-013 (December 3, 2021); Ruling consolidating ERRA compliance proceedings (September 7, 2021); PG&E Application for Rehearing of D.21-07- 013 (August 16, 2021); D.21-07-013 resolving Phase 1 (July 16, 2021); Joint Motion to Adopt Settlement Agreement (October 22, 2020); Amended Scoping Memo and Ruling (August 14, 2020); Scoping Memo and Ruling (June 19, 2020); PG&E’s Application and Testimony (February 28, 2020); Docket No. A.20-02-009.
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PG&E 2020 ERRA Compliance
On August 11, the CPUC issued D.22-08-009 extending the statutory deadline in this proceeding through 2023 to provide an opportunity to address the Phase 2 issues related to unrealized sales and revenues resulting from PG&E’s Public Safety Power Shutoff events in 2020.

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.

PG&E requested that the CPUC find it complied with its Bundled Procurement Plan (BPP) in the areas of fuel procurement, administration of power purchase contracts, greenhouse gas compliance instrument procurement, resource adequacy sales, and least-cost dispatch of electric generation resources for the 2020 calendar year. It also seeks a CPUC finding that it managed its utility-owned generation (UOG) facilities reasonably, although it recommends that CPUC review of outages at Diablo Canyon Power Plant related to the Unit 2 main generator be delayed to the 2021 ERRA Compliance review. Of significance to the Power Cost Indifference Adjustment (PCIA), PG&E requested the CPUC find that entries in its Portfolio Allocation Balancing Account (PABA), which trues up the above-market forecast of generation resources recovered through the PCIA with actual recorded costs and revenues, are accurate.

PG&E’s procurement costs recorded across the portfolio were $158.8 million higher than forecasted, allegedly due to higher-than-forecast RPS-eligible contracts, as offset by higher than forecast retained RPS and retained RA, as well as lower than forecast fuel costs for UOG facilities. Activity recorded in the PABA includes the following categories: Revenues from Customers, RPS Activity, RA Activity, Adopted UOG Revenue Requirements, CAISO Related Charges and Revenues, Fuel Costs, Contract Costs, GHG Costs, and Miscellaneous Costs. PG&E has redacted as confidential its 2020 actual and forecast costs for these categories, so it is unclear from the public filing what the magnitude is regarding the difference between actual and forecast costs for each category.

The Scoping Memo and Ruling specifies the proceeding will be divided into two phases. Phase 1 addressed whether PG&E (1) prudently administered and managed Utility-Owned Generation facilities and QF and non-QF contracts, (2) achieved least-cost dispatch of energy resources, (3) had reasonable, accurate, and appropriate ERRA and PABA entries, and (4) administered RA procurement and sales consistent with its Bundled Procurement Plan, among other issues. Phase 2 issues may be amended based on the outcome of Phase 2 of PG&E’s 2019 ERRA compliance proceeding. The tentative list of issues includes whether sales forecasting methods for adjusting revenue requirement under current decoupling policy should be adjusted to account for power not sold or purchased during a Public Safety Power Shutoff (PSPS) event in 2020, whether it is appropriate for PG&E to return the revenue requirement equal to the estimated unrealized volumetric sales and unrealized revenue resulting from the PSPS events in 2020, and the appropriate methodology for calculating PG&E’s unrealized volumetric sales and unrealized revenues resulting from 2020 PSPS events.

In testimony, Joint CCAs recommended a number of accounting adjustments that would reduce PUBA balances by more than $14.3 million. They also recommend the CPUC acknowledge that PG&E’s internal audit of its PABA concluded that the processes and controls governing PABA accounting are “Not Adequate,” and that PG&E remedy the identified deficiencies. Furthermore, they recommend that the CPUC clarify that future procurement expenses incurred by PG&E acting as the Central Procurement Entity will be reviewable in ERRA Compliance proceedings, and that PG&E should demonstrate the effect of such procurement, if any, on the PABA and ERRA balancing accounts.

PG&E agreed in rebuttal testimony that the accounting for PCIA costs attributed to customers taking service on the GTSR tariff should be adjusted to correctly credit PABA for the 2019 and 2020 record 65 29
periods, reducing the PABA balance by approximately $5 million. PG&E also agreed to present testimony in its 2021 ERRA Compliance proceeding addressing actions taken in response to the Internal Audit findings that PABA accounting process and controls were inadequate.

In the Settlement Agreement, PG&E agreed with the Joint CCAs’ position to a disallowance of $247,500 associated with CAISO penalties for load meter data errors, late submission of Resource Adequacy and Supply Plans and missed deadlines for grid modeling data or telemetry communication for PG&E’s utility owned generation and that any future sanctions for missed deadlines for grid modeling data or telemetry communication for PG&E’s utility-owned generation will not be recovered from customers. Joint CCAs agreed that CAISO sanctions associated with Power Purchase Agreements (contracted generation) were caused by the counterparty and passed through to the counterparty and should not be disallowed.

PG&E agreed that entries to the PABA for costs associated with the Green Tariff Shared Renewables program should be reduced by $5 million for 2019 and 2020, as Joint CCAs had argued. PG&E also agreed that certain issues should be in the scope of future ERRA proceedings, resolving the Joint CCA concern regarding its ability to review PG&E’s accounting with respect to transactions with the CPE in future ERRA Compliance proceedings. Finally, PG&E agreed to transfer from PABA to ERRA 2014 and 2017 Diablo Canyon Seismic Studies Balancing Account recorded costs, whereas the 2018 costs were retained in the PABA, which resolved the Joint CCAs concerns about that cost recovery.

Details: Phase 1 concluded in April 2022 with issuance of D.22-04-041 approving the Settlement Agreement. On August 11, the CPUC issued D.22-08-009 extending the statutory deadline in this proceeding through 2023 to provide an opportunity to address the Phase 2 issues related to unrealized sales and revenues resulting from PG&E’s Public Safety Power Shutoff events in 2020.

Analysis: This proceeding addresses PG&E’s balancing accounts, including the PABA, providing a venue for a detailed review of the billed revenues and net CAISO revenues PG&E recorded during 2020. It will also determine whether PG&E managed its portfolio of contracts and UOG in a reasonable manner. Both issues could impact the level of the PCIA in 2022 and 2023.

Next Steps: Phase 1 of the proceeding has concluded. Phase 2 will address issues associated with PSPS events during 2020, but it will not begin until after the Commission resolves issues related to the establishment of a common accounting methodology for PSPS events in Phase 2 of the 2019 ERRA Compliance proceeding, which is expected in Q4 of 2022.

Additional Information: D.22-08-009 (August 11, 2022); PG&E AL 6621-E (June 17, 2022); D.22-04-041 (April 21, 2022); Joint Motion for Adoption of Settlement Agreement (October 15, 2021); Scoping Memo and Ruling (June 21, 2021); Application (March 1, 2021); Docket No. A.21-03-008.

PG&E 2021 ERRA Compliance
On August 9, the Assigned Commissioner issued a Scoping Memo and Ruling defining the issues for consideration, finding that evidentiary hearings are needed, and providing a procedural schedule intended to conclude the proceeding within 18 months.

Background: PG&E’s Application requested the CPUC find that during 2021:
• It complied with its CPUC-approved Bundled Procurement Plan (BPP) in the areas of fuel procurement, administration of power purchase contracts, greenhouse gas compliance instrument procurement, resource adequacy sales, and least-cost dispatch of electric generation resources.
• It managed its utility-owned generation (UOG) facilities reasonably. 66 30
• Its expenditures in the Green Tariff Shared Renewables Memorandum Account (GTSRMA) were reasonable.
• Its entries in the Portfolio Allocation Balancing Account (PABA), Energy Resource Recovery Account (ERRA), Green Tariff Shared Renewables Balancing Account (GTSRBA), Disadvantaged Community – Single-Family Affordable Solar Homes (DAC SASH) balancing account (DACSASHBA), Disadvantaged Community - Green Tariff Balancing Account (DACGTBA), and Community Solar Green Tariff Balancing Account (CSGTBA) were consistent with applicable tariffs and CPUC directives.

PG&E also presented its Central Procurement Entity’s (CPE) administrative costs recorded to the Centralized Local Procurement Sub-Account (CLPSA) in the New System Generation Balancing Account (NSGBA).

PSPS Impacts: This Application does not include any testimony addressing the calculation of unrealized volumetric sales or unrealized revenues resulting from Public Safety Power Shutoff (PSPS) events, and once the Commission has resolved the issue in the Phase II 2019 ERRA Compliance proceeding PG&E plans to request direction from assigned ALJ regarding the presentment of PSPS information in this proceeding.

Protests of PG&E’s application were filed on April 6 by three parties including CalCCA and the Cal Advocates office. PG&E filed supplemental testimony on July 15.

Details: The August 9 Scoping Memo and Ruling identified the following issues for consideration in this proceeding:
1) Whether PG&E, during the record period, prudently administered and managed, in compliance with all applicable rules, regulations and Commission decisions, including but not limited to Standard of Conduct No. 4 (SOC 4), the following:
a) Utility-Owned Generation facilities;
b) Qualifying Facilities (QF) Contracts; and
c) Non-QF Contracts.

If not, what adjustments, if any, should be made to account for imprudently managed or administered resources?
2) Whether PG&E achieved least-cost dispatch of its energy resources and economically triggered demand response programs pursuant to SOC 4.
3) Whether the entries recorded in the ERRA and the Portfolio Allocation Balancing Account are reasonable, appropriate, accurate, and in compliance with Commission decisions. 4) Whether PG&E’s greenhouse gas compliance instrument procurement complied with its Bundled Procurement Plan.
5) Whether PG&E administered resource adequacy procurement and sales consistent with its Bundled Procurement Plan.
6) Whether the costs incurred and recorded in the following accounts are reasonable and in compliance with applicable tariffs and Commission directives:
a) Green Tariff Shared Renewables Memorandum Account;
b) Green Tariff Shared Renewables Balancing Account;
67 31
c) Disadvantaged Communities - Single Family Solar Affordable Homes Balancing Account;
d) Disadvantaged Communities - Green Tariff Balancing Account; e) Community Solar Green Tariff Balancing Account; and
f) Centralized Local Procurement Sub-Account of the New System Generation Balancing Account.
7) Whether there are any safety considerations raised by this Application. 8) What is the revenue requirement equal to the estimated unrealized volumetric sales and unrealized revenue resulting from the Public Safety Power Shutoff events in 2021 that PG&E must forgo in accordance with D.21-06-014? What is the appropriate methodology for calculating PG&E’s unrealized volumetric sales and unrealized revenues resulting from 2021 PSPS events?
Analysis: The proceeding will determine the reasonableness and appropriateness of PG&E expenditures, including some CPE administration costs. Some uncertainty remains regarding the treatment of PSPS events during this time period pending the Commission’s determination on the utilities’ proposed common methodology for calculating unrealized volumetric sales and unrealized revenues associated with PSPS events in the Phase II 2019 ERRA Compliance proceeding.

Next Steps: The Scoping Memo and Ruling adopted the following schedule:
• October 31, 2022 – Intervenors’ prepared direct testimony served • December 9, 2022 – Prepared rebuttal testimony served • December 2022 to early January 2023 – Settlement Talks held • January 6, 2023 – Status Conference
• January 11, 2023 – Completion of Settlement Talks
• January 17-19, 2023 – Evidentiary Hearing
• February 17, 2023 – Concurrent Opening Briefs due
• March 7, 2023 – Concurrent Reply Briefs due
• May-June 2023 – Proposed Decision
Additional Information: Assigned Commissioner’s Scoping Memo and Ruling (August 9, 2022); PG&E Supplemental testimony (July 15, 2022); PG&E Errata testimony (May 11, 2022); PG&E 2021 ERRA Compliance Application (February 28, 2022); Docket No. A.22-02-015.

PG&E Regionalization Plan
On July 25, PG&E met with the Regionalization Stakeholder Group and presented an activity schedule for future meetings and reporting. The proceeding is otherwise closed.

Background: D.20-05-051 approved PG&E’s reorganization following bankruptcy and directed PG&E to file a regionalization proposal (I.19-09-016). On June 30, 2020, PG&E filed its regionalization proposal in which it proposed to divide its service area into five new regions, each led by a Regional 68 32
Vice President, and each with a Regional Safety Director to lead its safety efforts. The new proposed regions would include five functional groups that report to the Regional Vice President encompassing various functions including: (1) Customer Field Operations, (2) Local Electric Maintenance and Construction, (3) Local Gas Maintenance and Construction, (4) Regional Planning and Coordination, and (5) Community and Customer Engagement, while other functions remain centralized. In February 2021, PG&E submitted an Updated Proposal with renamed regions that also moved Yolo County from Region 1 to Region 2 (North Valley & Sierra), where it would be grouped with the following counties: Colusa, El Dorado, Glenn, Lassen, Nevada, Placer, Plumas, Sacramento, Shasta, Sierra, Solano, Sutter, Tehama, and Yuba.

D.22-06-028 approved the MPSA but contained some modifications to the Proposed Decision including clarifications that PG&E must hold quarterly “town hall” meetings in each region and that any interested party may participate in the Regionalization Stakeholder Group (RSG).

Details: On July 25, PG&E held a meet and confer with the RSG and made a presentation providing a recap of the purpose and scope of the RSG and highlighted an activity schedule for future meetings.

Townhall meetings in each region will be held during August or September 2022, and the first Town Hall meeting for VCE’s region will be held on September 1.

Analysis: The implications of PG&E’s regionalization plan on CCA operations, customers, and costs remain largely unclear. As part of Region 2, VCE is grouped with Butte, Colusa, El Dorado, Glenn, Lassen, Nevada, Placer, Plumas, Sacramento, Shasta, Sierra, Solano, Sutter, Tehama, Yolo, and Yuba Counties. The Decision did not address most of the comments made by VCE and Pioneer regarding the inefficacy of the Updated Proposal, the need for the Commission to adopt and utilize metrics to measure the efficacy of PG&E’s regionalization, suggestions for greater transparency and responsiveness, or alignment of regional boundaries with existing councils of governments.

Next Steps: PG&E’s Tier 3 advice letter on regionalization implementation actions is due September 21.

PG&E is required to submit a report on its quarterly townhall meetings in each region within 45 days following the end of each quarter, and it plans to file its first Quarterly Report with the Tier 3 AL in September. The next RSG meeting is planned for late September or early October 2022.

Additional Information: PG&E Presentation to Regionalization Stakeholder Group (August 25, 2022); D.22-06-028 on Regionalization (June 24, 2022); Joint Motion for approval of Settlement Agreements (August 31, 2021); Amended Scoping Memo and Ruling (June 29, 2021); PG&E Updated Regionalization Proposal (February 26, 2021); Application (June 30, 2020); A.20-06-011.

Utility Safety Culture Assessments
On July 22, the ALJ issued a Ruling seeking comments on policy questions for safety culture assessments and distributing the Staff Safety Culture Concept Paper 1.

Background: IOU safety culture assessments are required as part of AB 1054 and SB 901. AB 1054 directed the CPUC’s Wildfire Safety Division, now the Office of Energy Infrastructure Safety, to conduct annual safety culture assessments of each electrical corporation that are specific to wildfire safety efforts and include a workforce survey, organizational self-assessment, supporting documentation, and interviews. SB 901 directed the CPUC to establish a safety culture assessment for each electrical corporation that is conducted by an independent third-party evaluator at least every five years. This proceeding will implement these safety culture assessments for regulated utilities.

The April 28 Scoping Ruling divided the proceeding into multiple phases and established the scope for Phase 1 to focus on developing safety culture assessments for the large investor-owned electric and natural gas corporations, while Phase 2 will focus on developing safety culture assessments for the small multi-jurisdiction utilities and the gas storage operators. 69 33
Phase 1 issues to be determined or considered include defining “safety culture”, the design of an inclusive and collaborative framework for conducting safety culture assessments focused on actual safety improvement, creating metrics and methodologies to evaluate the efficacy of the safety culture assessment process, and procedural matters related to the Phase 1 process timeframe, management, and coordination with other ongoing safety-related initiatives.

Details: Ideas discussed during the June and July technical working group meetings related to safety culture definitions, frameworks, and collaborations are outlined in the Staff Safety Culture Concept Paper 1. The July 22 ALJ Ruling seeks to further develop the ideas presented in the Staff Concept Paper with formal comments on these Phase 1 policy questions.

Analysis: This rulemaking will define safety culture concepts and determine how the safety culture of PG&E and other IOUs in California will be assessed and evaluated. It could impact VCE and its customers to the extent it succeeds or fails to influence PG&E’s safety culture and hence the safety of VCE customers. It could also impact the rates VCE customers pay to PG&E to mitigate or address safety issues (e.g., wildfires caused by PG&E transmission equipment; explosions from PG&E natural gas infrastructure, etc.).

Next Steps: A workshop will be held on the Staff Proposal in September 2022. • September 2022: Safety Policy Division Workshop on Staff Proposal • October 2022: Opening Comments on Staff Proposal
• November 2022: Reply Comments on Staff Proposal
Additional Information: ALJ Ruling seeking comment (Staff Safety Culture Concept Paper 1) (July 22, 2022); CPUC Safety Culture and Governance webpage; Scoping Ruling with procedural schedule (April 28, 2022); Webinar recording of the workshop (March 11, 2022); Order Instituting Rulemaking (October 7, 2021); Docket No. R.21-10-001.

Other Dockets
The following table identifies other tracked dockets that are closed or inactive.

Docket Name Status
R.21-03-001 Wildfire Fund NBC (2022-
2023) Rulemaking
The Department of Water Resources will issue a notice in September 2022 identifying the amount they calculate
will be needed for the 2023 Wildfire Fund NBC.

I.15-08-019
Investigation into PG&E
Organization, Culture and
Governance
D.21-11-010 extended the statutory deadline until
November 8, 2022 to allow for continued monitoring of
PG&E’s ongoing safety performance and to provide the
Commission time to establish next steps for the
proceeding.

R.20-11-003 Ensuring Summer 2021
Reliability D.22-06-005 closed the proceeding.

A.19-11-019 PG&E 2020 Phase 2 GRC
D.22-08-002 closed the docket; all current activity is now covered under the Commercial EV Real-Time Pricing
docket.

A.21-06-001 PG&E 2020 ERRA Forecast D.22-02-002 closed the proceeding. 70 34
R.19-03-009 Direct Access Rulemaking D.21-06-033 closed the proceeding, but a Petition for Rehearing (July 29, 2021) remains outstanding.

Glossary of Acronyms
AB Assembly Bill
ALJ Administrative Law Judge
BEV Business Electric Vehicle
BTM Behind the Meter
CAISO California Independent System Operator
CAM Cost Allocation Mechanism
CARB California Air Resources Board
CEC California Energy Commission
CPE Central Procurement Entity
CPUC California Public Utilities Commission
CPCN Certificate of Public Convenience and Necessity
DA Direct Access
ELCC Effective Load Carrying Capacity
ERRA Energy Resource and Recovery Account
GRC General Rate Case
IEPR Integrated Energy Policy Report
IFOM In Front of the Meter
IRP Integrated Resource Plan
IOU Investor-Owned Utility
LSE Load-Serving Entity
MCAM Modified Cost Allocation Mechanism
MCC Maximum Cumulative Capacity
OII Order Instituting Investigation
OIR Order Instituting Rulemaking
PABA Portfolio Allocation Balancing Account
PFM Petition for Modification
PCIA Power Charge Indifference Adjustment
POLR Provider of Last Resort
PSPS Public Safety Power Shutoff
PUBA PCIA Undercollection Balancing Account
71 35
PURPA Public Utility Regulatory Policies Act of 1978 (federal) QC Qualifying Capacity
QF Qualifying Facility under PURPA
RA Resource Adequacy
RSG Regionalization Stakeholder Group
ReMAT Renewable Market Adjusting Tariff
RPS Renewables Portfolio Standard
RTP Real-Time Pricing
TOU Time of Use
TURN The Utility Reform Network
UOG Utility-Owned Generation
VAMO Voluntary Allocation/Market Offer
WMP Wildfire Mitigation Plan
WSD Wildfire Safety Division (CPUC)
72 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 August 25, 2022 Meeting Summary DATE: September 8, 2022
This report summarizes the Community Advisory Committee’s meeting held via Zoom webinar on Thursday, August 25, 2022.

A. Received an overview of the Brown Act and social media. Inder Khalsa of Richards, Watson and Gershon (RWG), VCE’s legal counsel, provided a brief overview of the Brown Act and social media (AB 992). A few questions were asked. RWG’s 2022 Handbook on the Ralph A. Brown Act, containing a summary and full text of the Brown Act, was distributed to the CAC members in a follow up email.

B. Received a mid-year 2022 rates review. Staff provided a mid-year review of the 2022 rates and forecasted budget. The CAC discussed how the Power Purchase Agreement (PPA) projects will affect rates, how energy gaps are filled and the effects on the budget, and funding reserves and programs.

C. Power Procurement / Renewable Portfolio Standard update. Staff provided an update on the 2021 Power Content Label, PPA projects, 2022 targets and progress, and long term Renewables Portfolio Standard (RPS) forecasting and PPA timing of anticipated projects coming on line. The CAC discussed the need and timing on purchasing renewable energy certificates (RECs) to meet VCE’s goals, the need and concerns of marketing our renewable content, and balancing need with the budget.

D. New state and federal rebates and incentives for electrification and energy efficiency.

Staff provided a brief overview of the Inflation Reduction Act (IRA), with the largest share of funding for: tax credits and rebates for solar panels, wind turbines, heat pumps, energy efficiency and electric vehicles. Staff will evaluate the potential for VCE to participate in some of these rebate programs which may depend on staff availability.

The CAC are interested in learning about the opportunities and possible amounts of rebates and incentives listed within the Act and informing customers about them. 73 Item 10

VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 10
______________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Executive Officer
Edward Burnham, Director of Finance & Internal Operations SUBJECT: Bi-annual Enterprise Risk Management Report
DATE: September 8, 2022

RECOMMENDATION
Accept the Bi-annual Enterprise Risk Management Report – September 2022.

BACKGROUND & DISCUSSION
In 2018, the Board approve VCE’s Enterprise Risk Management (ERM) Policy. The policy is centered on energy best practices and is adapted from the SMUD risk management policy. In summary, the VCE ERM policy contains the following sections:
• Introduction: This section introduces the value of ERM as a structured approach to managing risk and uncertainty. It lays out the objectives of VCEA’s ERM function, providing the framework for evaluating and managing risk in the organization’s decision-making process. • ERM Roles and Responsibilities: The ERM roles are consistent with the Board-approved Wholesale Power Procurement & Risk Management Policy. The Enterprise Risk Oversight Committee (EROC) has primary responsibility for the implementation of ERM. The policy lays out the scope of the EROC’s risk management authority.
• Business Practices: This section identifies the steps of risk management and the basic process associated with each step. The intent is to provide a high-level framework. Specific tools and techniques for implementing enterprise risk management will be recommended by the portfolio manager following approval of the policy.
• Management Reporting and Metrics: The policy defines an enterprise risk report that will be provided bi-annually to the Board.

Staff has used the consistent framework described in the ERM policy to identify various risks and related mitigations, and to ensure effective mitigation and communication across all levels of the organization. The attached ERM bi-annual report describes the activities that took place since the last 74 Item 10
bi-annual update in March 2022 and the actions VCE is and will be taking to manage the top risks that have been identified.

Prior to this report, staff most recently presented the bi-annual update in March 2022 to the Board, describing progress on the ERM plan since inception. Bi-annual updates are provided in March and September of each year.

ATTACHMENT

1. Bi-annual Enterprise Risk Management Report – September 2022 75 Valley Clean Energy
Enterprise Risk
Management Report
September 2022
PURPOSE:

The purpose of the biannual ERM Report is to update VCE's Board and the public regarding the activities that took place since the last update on March 2022. 76 1
Executive Summary
Introduction and Background
In 2018, the Valley Clean Energy (VCE) Board adopted an Enterprise Risk Management (ERM) framework to provide the Board with insight into risks that could impact the ability to execute VCE's mission, build credibility and sustain confidence in VCE's governance and stakeholders, enhance the understanding of significant risks to VCE, and develop the capacity for continuous monitoring, periodic reporting of risks, and responding to changing risk circumstances. This report is the 2nd of VCE's biannual risk reports for 2022; the prior ERM biannual Report was issued on March 2022.

ERM is a strategic approach to risk management that supports the achievement of organizational objectives through the management of integrated impacts of risks as an interrelated risk portfolio. ERM is a coordinated effort by management to treat all risks effectively, thereby reducing the overall cost of risk to the organization. The General Manager has charged functional leaders to oversee the treatment of known major risk categories and provide a risk overview to the Enterprise Risk Oversight Committee (EROC).

ERM Philosophy
VCE's ERM philosophy includes the following principles:

1. Identify, assess, prudently manage, monitor, and report on a variety of business-critical risks;

2. Provide enterprise risk context and linkage to existing core business processes to improve the allocation of limited resources; ERM Approach
Staff has applied a multi-perspective approach to evaluate and estimate the trade-off between risk and cost of mitigation across VCE business functions. This approach addresses the following issues:
• Roles and responsibilities
• Definitions and language
• Risk heat map and risk exposure inventory
• Risk exposure monitoring, updating, and reporting
• Integration of ERM with key business processes
• Integration of risk awareness within corporate culture 77 2
• This framework supports the Board in exercising its overall responsibility to:
• Regulate opportunities and risks for VCE;
• Develop a better understanding of appropriate opportunities and risks for VCE; • Promote active management of risk exposure down to acceptable levels; and • Assist VCE in its achievement of business plan objectives and operational performance.

Summary of Activities through September of 2022
From an implementation perspective, progress continues on multiple fronts. Significant effort has been invested in creating an enterprise risk register. Risks to VCE have been identified, categorized, and rated. Existing risk controls and risk treatment measures implemented/proposed have also been identified. The risk register provides VCE's management with a consolidated view of risks being faced by VCE, the potential impact of those risks, mitigation actions, and assessment of short-term risk trends (i.e., higher/lower/steady).

Staff is using a consistent framework to identify various risks and related mitigations, and to ensure effective communication across all levels of the organization. In doing so, staff has completed the following developmental tasks:

1. Established Executive Director as Chief Risk Officer and Director of Finance & Internal Operations as risk process owner, focusing on day-to-day monitoring and coordination.

2. Developed ERM framework and tools

3. Conducted a risk survey

4. Developed VCE's top risk portfolio

5. Surveyed staff and management for ongoing risk input

6. Held monthly EROC meetings
Key Steps Taken Since the Last Biannual Update
Some actionable steps that VCE has taken since the last Board update in March 2022 include:

1. Have actively engaged from a regulatory and legislative standpoint, supporting regulatory statewide proceedings and settlements, meeting with key CPUC staff, and continuing progress on the annual VCE legislative platform.

2. Reduced the 2020 - 2022 RPS targets to maintain VCE's rate policy and partially mitigate the use of reserve funds during the transition to long-term power purchase agreements savings of ~$3.75M. 78 3

3. Executed 5 power purchase agreements, including 4 through California Community Power, PV plus storage, long duration storage, and geothermal technologies.

4. Adopted a cost recovery-based customer rate policy for 2022, expanded customer rate options for 2023, collections policy, and debt policy to stabilize and support establishing a credit rating.

5. Secured a short-term $5M line of credit with the County of Yolo and a 2-year line of credit for $11M with River City Bank for 2022-2023 cash flow requirements.

6. Development and launch of AgFIT pilot program that provides growers with incentives for irrigation automation and uses scheduling software, to better manage energy costs.

Key Risks
Key risks are those risks that, given VCE's current position, could negatively impact VCE's business model, future performance or prospects, solvency, liquidity, reputation, or prevent it from delivering on its local control commitment. These key risks are updated on an ongoing basis and look forward over a 5-year horizon to identify the:
• Nature and extent of risks facing VCE
• Likelihood and velocity of the risks and potential impacts • VCE's ability to reduce or control such risks
Key Priorities for Risk Management in 2022:

1. Maintain the operational risk management process

2. Provide regular updates to the Board

3. Continue to take specific actions to mitigate risks as outlined in this document

4. Begin to develop contingency plans for unexpected and emergent events Risk Portfolio
Top 5 Risks for VCE:

1. Commodity procurement

2. Regulatory & Policy risk

3. Capital availability/cash flow

4. Power Charge Indifference Adjustment ("PCIA") adjustments

5. Economic Uncertainty
79 4
The following tables outline current risks (Table 1) and summarize VCE's top risk response plan (Table 2).

Table 1: Risk Description/Level
Risk Description
Current
Residual
Risk
Target
Residual
Risk
PCIA
The PCIA rate for 2022 decreased by 57%. The 2023 PCIA rate is expected to decrease with current forward market prices. Continued uncertainty around PCIA and the impacts on bundled rates will remain for future years until a sunset date is established.

Commodity
Procurement
The 2022 market is experiencing fluctuations associated with commodity prices, including energy prices, resource adequacy, and other components of the energy portfolio.

Regulatory & Policy
risk
Risk of additional regulatory requirements increasing complexity and cost of operations.

Capital
availability/cashflow
Capital / Cashflow Risk has been slightly reduced through the adoption of the new cost recovery rate policy and renegotiated lines of credit with River City Bank.

Economic Uncertainty The risk that the ongoing geopolitical climate increases the chances of impacting gas prices, the economy, and associated cost forecasts.

Rate structure
The risk of rate design for cost of service (non-time of use (TOU), PCIA, demand charges, varying generation rates) has been reduced with an updated rate policy and additional rate/ product option for 2023. VCE will continue to develop rate-setting options to minimize risks further.

Cyber security & data
privacy
Risk of a data breach as a result of a cyber breach or physical attack. 80 5
Risk Description
Current
Residual
Risk
Target
Residual
Risk
Financial Markets
Volatility
Swings in global energy markets, financial markets, and currencies due to current geopolitical events (e.g. Russian invasion of Ukraine) have created challenges that impact VCE's short-term power costs.

Changing customer
expectations
Risk that customer's changing expectations as a result of innovation may result in reduced customer revenue and loyalty
Opt-out rate
The risk of higher than expected opt-out levels has increased with rising rates in both electricity and gas, which could adversely affect opt-out rates.

VCE will implement the "Base Green" product option to minimize opt-out activity and perform outreach as necessary.

Business model Ability to quickly identify and respond to business risks that have the potential to impact the ability to achieve VCE goals.

Media & Community Risk of unfavorable public communications or events; spillover customer dissatisfaction related to PG&E's PSPS
Unknown risks Business and utilities attempt to identify and adapt to known risks but some potential events outside of VCE's control could have a debilitating impact on utilities in general and VCE in particular.

High Risk
High/Moderate Risk
Low/Moderate Risk
Low Risk
81 6
Table 2: Summary of VCE top risk response plan
Risk Event Response Trend1 Plan Trigger/Control Owner
PCIA
Monitor risk &
actively engage
and respond
1) Continue direct involvement
with CalCCA task groups to seek
favorable rulings and
settlements in the PCIA, ERRA,
and other filings.
2) Work towards the potential
long-term goal of attaining an
option for a PCIA buy-out and
sunset date.
3) Work towards stabilization
and reduction of the PCIA from
a regulatory and legislative
standpoint
The 2023 PG&E PCIA
forecast is expected to
decrease. VCE will
continue to monitor
Energy Resource
Recovery Account (ERRA)
proceedings related to
the 2023 PG&E PCIA and
bundled rate setting.

Director of
Finance
Commodity
Procurement
Reduce &
manage risk
1) Continue to pursue long-term power purchase
agreements to reduce the
average cost of power in future
years
Execution of PPA
contracts
Regulatory rulings that
affect commodity
procurement cost and
RA cost
Director of
Power
Procurement
1 Current trend of risk for VCE- increasing , no change or decreasing 82 7
Risk Event Response Trend1 Plan Trigger/Control Owner
2) Pursue regulatory and
legislative avenues in
addressing the extreme swings
in pricing and requirements of
Resource Adequacy (RA) costs.
3) Take an active role in
regulatory proceedings at the
CPUC, including appeals, on
various regulations that impact
the cost of electricity along
with support from the CalCCA
Regulatory Committee
4) Follow the guidelines and
recommendations of VCE's
Wholesale Energy Risk Manual
Regulatory &
policy risk
Monitor risk &
actively engage
and respond
1) Take an active role in
legislative sessions (contract
with lobbyist and engage Board
members for
support/opposition on bills)
along with support from CalCCA
legislative committee
2) Follow and continue to
update the annual VCE
Legislative Platform
Weekly CalCCA
Regulatory and
Legislative Committee
meetings
Regulatory rulings
Legislative actions
Executive
Officer
83 8
Risk Event Response Trend1 Plan Trigger/Control Owner
3) Take an active role in
regulatory proceedings at the
CPUC, including appeals, on
various regulations that impact
VCE and CC's that increase cost
or bureaucracy without any
significant safety or cost
benefits to VCE and its
customers along with support
from CalCCA Regulatory
Committee
Capital
Availability/ Cash
Flow
Monitor risk &
actively engage
and respond
1) Continue towards
conserving cash, reduce debt,
and lowering cash
requirements.
2) Evaluate reserve policy
changes.
3) Work towards the 2024 goal
of securing an investment-grade credit rating.

VCE Line of credit
agreements & renewals
has been extended to
2024.

VCE is securing a
Financial Advisor to
assist in establishing
VCE’s initial investment
grade credit rating.

Implement VCE
Collections Policy
Director of
Finance
84 9
Risk Event Response Trend1 Plan Trigger/Control Owner
Rate Structure Reduce &
manage risk
1) Monitor and update Board
based on analyst forecasts for
ERRA proceeding.
2) Identify and mitigate risks
outside of VCE control to limit
impacts and frequency of rate
changes.
3) Review and update rate
policy for cost -recovery based
model
Economic outlook and
Rate forecasts
Monitor Regulatory
proceedings that impact
PCIA, RA, and ERRA.

Monitor cash short-term
and long-term impacts to
reserve funds, credit
lines, commercial
negotiations, and PPA
covenants.

Director of
Finance
85 Item 11

VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 11
TO: Board of Directors
FROM: Gordon Samuel, Assistant General Manager & Director of Power Services SUBJECT: Accept and attest to the veracity of VCE’s Power Content Label for the Standard Green and Ultra Green products for 2021
DATE: September 8, 2022
RECOMMENDATION:

Attest to the veracity of the information presented in Valley Clean Energy’s 2021 Power Source Disclosure Annual Reports and Power Content Label for the Standard Green and Ultra Green products.

BACKGROUND:

California Public Utilities Code requires all retail sellers of electric energy, including Valley Clean Energy (VCE), to disclose “accurate, reliable, and simple-to-understand information on the sources of energy, and the associated emissions of greenhouse gases,” that are delivered to their respective customers.1 Applicable regulations direct retail sellers to provide such communications no later than October 1st of each year. The format for requisite communications is highly prescriptive, offering little flexibility to retail sellers when presenting such information to customers. This format has been termed the “Power Content Label” by the California Energy Commission (“CEC”).

Information presented in the Power Content Label includes the appropriate share of total energy supply based on resource type, including both renewable and conventional fuel sources.

In the event that a retail seller meets a certain percentage of its supply obligation from unspecified resources, the report must identify such purchases as “unspecified sources of power.” Unspecified sources of power refer to electricity that cannot be sourced back to a specific generator, such as energy purchased through open market transactions.

During the 2021 calendar year, VCE delivered a portion of its electric energy supply from various renewable energy sources, including eligible hydroelectric, solar, and wind. Consistent with its multi-year transition to renewables strategy, VCE is ramping up renewables from 2020 to 2024 where it’s default product “Standard Green” is forecast to exceed 80% renewable content sourced from long-term energy contracts (solar, solar + storage, geothermal, and small hydro). As part of this approach, 12.6% of the energy delivered to VCE Standard Green 1 California Public Utilities Code Section 398.1(b).
86 Item 11
customers in 2021 was from renewable energy resources with a greenhouse gas emissions intensity of 722 lbs CO2e/MWh. For Ultra Green customers, 100% of the energy delivered in 2021 was generated from renewable energy resources with a greenhouse gas emissions intensity of 0 lbs CO2e/MWh. A copy of VCE’s Power Content Label listing the energy resources used during 2021 is attached.

Consistent with applicable regulations and CEC guidance, VCE will complete required customer communications in accordance with the October 1, 2022 deadline. All customers currently enrolled in the VCE program will receive the Power Content Label via mail or e-mail, as applicable.

To fulfill its Power Content Label reporting obligation, VCE may provide the CEC with the Board’s attestation regarding the veracity of the information presented in VCE’s 2021 Power Source Disclosure Annual Reports and Power Content Label for the Standard Green and Ultra Green products. Staff recommends VCE self-certify both the Standard Green and Ultra Green products in lieu of submitting them to a third-party Certified Public Accountant for a formal audit. VCE’s technical consultants (SMUD) prepared the Power Source Disclosure annual reports and Power Content Label, which were subsequently reviewed by another VCE consultant (EQ Research). EQ Research’s review, as detailed in the attached report, verified that the information contained in the annual reports and Power Content Label is accurate.

Based on the foregoing, staff requests that the Board accept this determination and attest to the veracity of the information included in VCE’s Power Source Disclosure annual reports and Power Content Label for the Standard Green and Ultra Green products for the 2021 calendar year.

ATTACHMENTS:
1) 2021 Annual Power Source Disclosure Report for the Standard Green Product 2) 2021 Annual Power Source Disclosure Report for the Ultra Green Product 3) 2021 Power Content Label
4) EQ Research Report re 2021 Power Source Disclosure Annual Reports and Power Content Label
87 Version: May 2022
If you have questions, contact Power Source Disclosure (PSD) staff at [email protected] or (916) 805-7439.

NOTE: Information submitted in this report is not automatically held confidential. If your company wishes the information submitted to be considered confidential an authorized representative must submit an application for confidential designation (CEC-13), which can be found on the California Energy Commissions's website at https://www.energy.ca.gov/about/divisions-and-offices/chief-counsels-office.

WEBSITE URL FOR
PCL POSTING https://valleycleanenergy.org/power-sources/ Submit the Annual Report and signed Attestation in PDF format with the Excel version of the Annual Report to [email protected]. Remember to complete the Retail Supplier Name, Electricity Portfolio Name, and contact information above, and submit separate reports and attestations for each additional portfolio if multiple were offered in the previous year.

CITY, STATE, ZIP Davis, CA 95616
PHONE 1-855-699-8232
EMAIL [email protected]
NAME Gordon Samuel
TITLE Assistant General Manager & Director of Power Services MAILING ADDRESS 604 2nd Street

CONTACT INFORMATION
2021 POWER SOURCE DISCLOSURE ANNUAL REPORT
For the Year Ending December 31, 2021

RETAIL SUPPLIER NAME
Valley Clean Energy Alliance

ELECTRICITY PORTFOLIO NAME
Standard Green
Retail suppliers are required to use the posted template and are not allowed to make edits to this format. Please complete all requested information.

GENERAL INSTRUCTIONS
88 Version: May 2022
Schedule 1: Procurements and Retail Sales
Schedule 2: Retired Unbundled RECs
Schedule 3: Annual Power Content Label Data
ACS Resource Mix Calculator
Retail suppliers may report specified purchases from ACS system power if the ACS provided its fuel mix of its specified system mix to the Energy Commission. Use the calculator to determine the resource-specific procurement quantities, and transfer them to Schedule 1.

GHG Emissions Factors
Specified Purchases: A Specified Purchase refers to a transaction in which electricity is traceable to specific generating facilities by any auditable contract trail or equivalent, such as a tradable commodity system, that provides commercial verification that the electricity claimed has been sold once and only once to retail consumers. Do not enter data in the grey fields. For specified purchases, include enter following information for each line item:

Facility Name - Provide the name used to identify the facility.

Fuel Type - Provide the resource type (solar, natural gas, etc.) that this facility uses to generate electricity.

Location - Provide the state or province in which the facility is located.

Identification Numbers - Provide all applicable identification numbers from the Western Renewable Energy Generation Information System (WREGIS), the Energy Information Agency (EIA), and the California Renewables Portfolio Standard (RPS).

Gross Megawatt Hours Procured - Provide the quantity of electricity procured in MWh from the generating facility.

Megawatt Hours Resold - Provide the quantity of electricity resold at wholesale.

Unspecified Power: Unspecified Power refers to electricity that is not traceable to specific generation sources by any auditable contract trail or equivalent, or to power purchases from a transaction that expressly transferred energy only and not the RECs associated from a facility. Do not enter procurements of unspecified power. The schedule will calculate unspecified power procurements automatically.

Complete this schedule by entering information about unbundled REC retirements in the previous calendar year.

This schedule is provided as an automated worksheet that uses the information from Schedule 1 to calculate the power content and GHG emissions intensity for each electricity portfolio. The percentages calculated on this worksheet should be used for your Power Content Label.

Retail suppliers of electricity must complete this schedule by entering information about all power procurements and generation that served the identified electricity portfolio covered in this filing in the prior year. The schedule is divided into sections: directly delivered renewables, firmed-and-shaped imports, specified non-renewables, and procurements from ACSs. Insert additional rows as needed to report all procurements or generation serving the subject product. Provide the annual retail sales for the subject product in the appropriate space. At the bottom of Schedule 1, provide the retail suppliers’ other electricity end-uses that are not retail sales, such as transmission and distribution losses. Retail suppliers shall submit a purchase agreement or ownership arrangement documentation substantiating that any eligible firmed-and-shaped product for which it is claiming an exclusion was executed prior to January 1, 2019. Any retail supplier that offered multiple electricity portfolios in the prior year must submit separate Annual Reports for each portfolio offered.

Schedule 2 - Retired Unbundled Renewable Energy Credits (RECs) Schedule 3 - Annual Power Content Label Data
Asset-Controlling Supplier (ACS) Procurement Calculator PSD Attestation

INSTRUCTIONS
Schedule 1 - Procurements and Retail Sales

INTRODUCTION
Retail suppliers are required to submit separate Annual Reports for each electricity portfolio offered to California retail consumers in the previous calendar year. Enter the Retail Supplier Name and Electricity Portfolio Name at the top of Schedule 1, Schedule 2, Schedule 3, and the Attestation.

A complete Annual Report includes the following tabs:

PSD Intro
Instructions
89 Version: May 2022
GHG Emissions Factors
Attestation
This template provides the attestation that must be submitted with the Annual Report to the Energy Commission, stating that the information contained in the applicable schedules is correct and that the power has been sold once and only once to retail consumers. This attestation must be included in the package that is transmitted to the Energy Commission. Please provide the complete Annual Report in Excel format and the complete Annual Report with signed attestation in PDF format as well.

This tab will be displayed for informational purposes only; it will not be used by reporting entities, since the emissions factors below auto-populate in the relevant fields on Schedules 1 & 3. 90 Version: May 2022
751,490
176,609
574,881
-
-
-
176,609
246,049

0.3274

DIRECTLY DELIVERED RENEWABLES
Facility Name Fuel Type
State or
Province WREGIS ID RPS ID N/A EIA ID
Gross MWh
Procured
MWh
Resold
Net MWh
Procured
Adjusted Net MWh
Procured
GHG Emissions Factor
(in MT CO2e/MWh)
GHG Emissions (in MT
CO2e) N/A
Biglow Canyon Wind Farm - Biglow Canyon 3 Wind OR W1588 63056A 56485 4,269 4,269 4,269 - - Biglow Canyon Wind Farm - Biglow Phase 2 Wind OR W1268 63055A 56485 30,984 30,984 30,984 - - Tucannon River Wind Farm - Tucannon River 1 Wind WA W4482 63027A 58571 11,015 11,015 11,015 - - Aquamarine Westside, LLC - Aquamarine Westside, LLC Solar CA W12082 64553A 62547 34,800 34,800 34,800 - - Tucannon River Wind Farm - Tucannon River 2 Wind WA W4483 63027A 58571 13,732 13,732 13,732 - - - - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A

FIRMED-AND-SHAPED IMPORTS
Facility Name Fuel Type
State or
Province WREGIS ID RPS ID
EIA ID of
REC
Source
EIA ID of
Substitute
Power
Gross MWh
Procured MWh Resold
Net MWh
Procured
Adjusted Net MWh
Procured
GHG Emissions
Factor (in MT
CO2e/MWh)
GHG Emissions
(in MT CO2e)
Eligible for
Grandfathered
Emissions?
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A

SPECIFIED NON-RENEWABLE PROCUREMENTS
Facility Name Fuel Type
State or
Province N/A N/A N/A EIA ID
Gross MWh
Procured MWh Resold
Net MWh
Procured
Adjusted Net MWh
Procured
GHG Emissions
Factor (in MT
CO2e/MWh)
GHG Emissions
(in MT CO2e) N/A
Boundary Hydroelectric Units Large hydro WA 6433 31 31 31 - - Mid-C Hydro - Rock Island 6200 and Rocky Reach 3883 (Chelan County PUD) Large hydro WA 3883 29,396 29,396 29,396 - - Mid-C Hydro - Wells (Douglas County PUD) Large hydro WA 3886 11,383 11,383 11,383 - - Mid-C Hydro - Priest Rapids and Wanapum dams (Grant County PUD) Large hydro WA 3887 3,617 3,617 3,617 - - Balch #1 PH Large hydro CA 217 352 352 352 - -
Balch #2 PH Large hydro CA 218 1,155 1,155 1,155 - -
Belden Large hydro CA 219 1,443 1,443 1,443 - -
Bucks Creek Large hydro CA 220 177 177 177 - -
Butt Valley Large hydro CA 221 204 204 204 - -
Caribou 1 Large hydro CA 222 379 379 379 - -
Caribou 2 Large hydro CA 223 1,485 1,485 1,485 - -
Cresta Large hydro CA 231 1,133 1,133 1,133 - -
Drum #1 Large hydro CA 235 403 403 403 - -
Drum #2 Large hydro CA 236 1,473 1,473 1,473 - -
Electra Large hydro CA 239 1,566 1,566 1,566 - -
Haas Large hydro CA 240 986 986 986 - -
James B Black Large hydro CA 249 3,227 3,227 3,227 - -
Kerckhoff #2 PH Large hydro CA 682 1,306 1,306 1,306 - - Kings River Large hydro CA 254 315 315 315 - -
Pit 1 Large hydro CA 265 1,159 1,159 1,159 - -
Pit 3 Large hydro CA 266 1,587 1,587 1,587 - -
Pit 4 Large hydro CA 267 1,841 1,841 1,841 - -
Pit 5 Large hydro CA 268 4,006 4,006 4,006 - -
Pit 6 Large hydro CA 269 1,984 1,984 1,984 - -
Pit 7 Large hydro CA 270 2,407 2,407 2,407 - -
Poe Large hydro CA 272 2,042 2,042 2,042 - -
Rock Creek Large hydro CA 275 1,920 1,920 1,920 - -
Salt Springs Large hydro CA 279 709 709 709 - -
Retail Sales (MWh)
Net Specified Procurement (MWh)
Unspecified Power (MWh)
Procurement to be adjusted
2021 POWER SOURCE DISCLOSURE ANNUAL REPORT
SCHEDULE 1: PROCUREMENTS AND RETAIL SALES
For the Year Ending December 31, 2021
Valley Clean Energy Alliance
Standard Green
GHG Emissions Intensity (in MT CO2e/MWh)
Net Specified Natural Gas
Net Specified Coal & Other Fossil Fuels
Net Specified Nuclear, Large Hydro, Renewables, and ACS Power GHG Emissions (excludes grandfathered emissions)
Instructions: Enter information about power procurements underlying this electricity portfolio for which your company is filing the Annual Report.

Insert additional rows as needed. All fields in white should be filled out. Fields in grey auto-populate as needed and should not be filled out. For EIA IDs for unspecified power or specified system mixes from asset-controlling suppliers, enter "Unspecified Power", "BPA", or "Tacoma Power" as applicable. For specified procurements of ACS power, use the ACS Procurement Calculator to calculate the resource breakdown comprising the ACS system mix. Procurements of unspecified power must not be entered as line items below; unspecified power will be calculated automatically in cell N9. Unbundled RECs must not be entered on Schedule 1; these products must be entered on Schedule 2. At the bottom portion of the schedule, provide the other electricity end-uses that are not retail sales including, but not limited to transmission and distribution losses or municipal street lighting. Amounts should be in megawatt-hours. 91 Version: May 2022
Stanislaus Large hydro CA 285 1,064 1,064 1,064 - -
Tiger Creek Large hydro CA 287 1,380 1,380 1,380 - -
Forbestown Large hydro CA 417 398 398 398 - -
Woodleaf Large hydro CA 419 665 665 665 - -
NID-Chicago Park Large hydro CA 412 617 617 617 - -

PROCUREMENTS FROM ASSET-CONTROLLING SUPPLIERS
Facility Name Fuel Type N/A N/A N/A N/A EIA ID
Gross MWh
Procured MWh Resold
Net MWh
Procured
Adjusted Net MWh
Procured
GHG Emissions
Factor (in MT
CO2e/MWh)
GHG Emissions
(in MT CO2e) N/A
- #N/A
- #N/A
- #N/A
- #N/A
END USES OTHER THAN RETAIL SALES MWh
Distribution losses 50,182
92 Version: May 2022
-

RETIRED UNBUNDLED RECS
Facility Name Fuel Type
State or
Province RPS ID Total Retired (in MWh)
Total Retired Unbundled RECs
2021 POWER SOURCE DISCLOSURE ANNUAL REPORT
SCHEDULE 2: RETIRED UNBUNDLED RECS
For the Year Ending December 31, 2021
Valley Clean Energy Alliance
Standard Green
INSTRUCTIONS: Enter information about retired unbundled RECs associated with this electricity portfolio.

Insert additional rows as needed. All fields in white should be filled out. Fields in grey auto-populate as needed and should not be filled out.
93 Version: May 2022
Adjusted Net Procured
(MWh)
Percent of Total Retail
Sales
Renewable Procurements 94,800 12.6%
Biomass & Biowaste - 0.0%
Geothermal - 0.0%
Eligible Hydroelectric - 0.0%
Solar 34,800 4.6%
Wind 60,000 8.0%
Coal - 0.0%
Large Hydroelectric 81,809 10.9%
Natural gas - 0.0%
Nuclear - 0.0%
Other - 0.0%
Unspecified Power 574,881 76.5%
Total 751,490 100.0%
751,490
722

0.0%
Total Retail Sales (MWh)
GHG Emissions Intensity (converted to lbs CO2e/MWh)
Percentage of Retail Sales Covered by Retired Unbundled RECs
2021 POWER SOURCE DISCLOSURE ANNUAL REPORT
SCHEDULE 3: POWER CONTENT LABEL DATA
For the Year Ending December 31, 2021
Valley Clean Energy Alliance
Standard Green
Instructions: No data input is needed on this schedule. Retail suppliers should use these auto-populated calculations to fill out their Power Content Labels. 94 Version: May 2022
2021 POWER SOURCE DISCLOSURE ANNUAL REPORT

ATTESTATION FORM
For the Year Ending December 31, 2021
Valley Clean Energy Alliance
Standard Green
I, Gordon Samuel, Assistant General Manager & Director of Power Services, declare under penalty of perjury, that the statements contained in this report including Schedules 1, 2, and 3 are true and correct and that I, as an authorized agent of Valley Clean Energy Alliance, have authority to submit this report on the company's behalf. I further declare that the megawatt-hours claimed as specified purchases as shown in these Schedules were, to the best of my knowledge, sold once and only once to retail customers.

Name: Gordon Samuel
Representing (Retail Supplier):Valley Clean Energy Alliance Signature: __________________________________________________________ Dated: June 15, 2022
Executed at: Davis, California
95 Version: May 2022
If you have questions, contact Power Source Disclosure (PSD) staff at [email protected] or (916) 805-7439.

CITY, STATE, ZIP Davis, CA 95616
PHONE 1-855-699-8232
EMAIL [email protected]
NAME Gordon Samuel
TITLE Assistant General Manager & Director of Power Services MAILING ADDRESS 604 2nd Street

CONTACT INFORMATION
2021 POWER SOURCE DISCLOSURE ANNUAL REPORT
For the Year Ending December 31, 2021

RETAIL SUPPLIER NAME
Valley Clean Energy Alliance

ELECTRICITY PORTFOLIO NAME
UltraGreen
Retail suppliers are required to use the posted template and are not allowed to make edits to this format. Please complete all requested information.

GENERAL INSTRUCTIONS
96 Version: May 2022
Schedule 1: Procurements and Retail Sales
Schedule 2: Retired Unbundled RECs
Schedule 3: Annual Power Content Label Data
ACS Resource Mix Calculator
Retail suppliers may report specified purchases from ACS system power if the ACS provided its fuel mix of its specified system mix to the Energy Commission. Use the calculator to determine the resource-specific procurement quantities, and transfer them to Schedule 1.

Facility Name - Provide the name used to identify the facility.

Fuel Type - Provide the resource type (solar, natural gas, etc.) that this facility uses to generate electricity.

Location - Provide the state or province in which the facility is located.

Gross Megawatt Hours Procured - Provide the quantity of electricity procured in MWh from the generating facility.

Megawatt Hours Resold - Provide the quantity of electricity resold at wholesale.

Complete this schedule by entering information about unbundled REC retirements in the previous calendar year.

Schedule 2 - Retired Unbundled Renewable Energy Credits (RECs) Schedule 3 - Annual Power Content Label Data
Asset-Controlling Supplier (ACS) Procurement Calculator PSD Attestation

INSTRUCTIONS
Schedule 1 - Procurements and Retail Sales

A complete Annual Report includes the following tabs:

PSD Intro
Instructions
97 Version: May 2022
GHG Emissions Factors
Attestation
This template provides the attestation that must be submitted with the Annual Report to the Energy Commission, stating that the information contained in the applicable schedules is correct and that the power has been sold once and only once to retail consumers. This attestation must be included in the package that is transmitted to the Energy Commission. Please provide the complete Annual Report in Excel format and the complete Annual Report with signed attestation in PDF format as well.

This tab will be displayed for informational purposes only; it will not be used by reporting entities, since the emissions factors below auto-populate in the relevant fields on Schedules 1 & 3. 98 Version: May 2022
4,418
4,418
-
-
-
-
4,418
0 0.0000

DIRECTLY DELIVERED RENEWABLES
Facility Name Fuel Type
State or
Province WREGIS ID RPS ID N/A EIA ID
Gross MWh
Procured
MWh
Resold
Net MWh
Procured
Adjusted Net MWh
Procured
GHG Emissions Factor
(in MT CO2e/MWh)
GHG Emissions (in MT
CO2e) N/A
Indian Valley Hydro - Indian Valley Hydro Eligible hydro CA W607 60161A 50129 1,177 1,177 1,177 - - Aquamarine Westside, LLC - Aquamarine Westside, LLC Solar CA W12082 64553A 62547 3,241 3,241 3,241 - - - - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A

SPECIFIED NON-RENEWABLE PROCUREMENTS
Facility Name Fuel Type
State or
Province N/A N/A N/A EIA ID
Gross MWh
Procured MWh Resold
Net MWh
Procured
Adjusted Net MWh
Procured
GHG Emissions
Factor (in MT
CO2e/MWh)
GHG Emissions
(in MT CO2e) N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A
Retail Sales (MWh)
Net Specified Procurement (MWh)
Unspecified Power (MWh)
Procurement to be adjusted
2021 POWER SOURCE DISCLOSURE ANNUAL REPORT
SCHEDULE 1: PROCUREMENTS AND RETAIL SALES
For the Year Ending December 31, 2021
Valley Clean Energy Alliance
UltraGreen
GHG Emissions Intensity (in MT CO2e/MWh)
Net Specified Natural Gas
Net Specified Coal & Other Fossil Fuels
Net Specified Nuclear, Large Hydro, Renewables, and ACS Power GHG Emissions (excludes grandfathered emissions)
Instructions: Enter information about power procurements underlying this electricity portfolio for which your company is filing the Annual Report.

Insert additional rows as needed. All fields in white should be filled out. Fields in grey auto-populate as needed and should not be filled out. For EIA IDs for unspecified power or specified system mixes from asset-controlling suppliers, enter "Unspecified Power", "BPA", or "Tacoma Power" as applicable. For specified procurements of ACS power, use the ACS Procurement Calculator to calculate the resource breakdown comprising the ACS system mix. Procurements of unspecified power must not be entered as line items below; unspecified power will be calculated automatically in cell N9. Unbundled RECs must not be entered on Schedule 1; these products must be entered on Schedule 2. At the bottom portion of the schedule, provide the other electricity end-uses that are not retail sales including, but not limited to transmission and distribution losses or municipal street lighting. Amounts should be in megawatt-hours. 99 Version: May 2022
- - #N/A
- - #N/A
- - #N/A
- - #N/A
- - #N/A

RETIRED UNBUNDLED RECS
Facility Name Fuel Type
State or
Province RPS ID Total Retired (in MWh)
Total Retired Unbundled RECs
2021 POWER SOURCE DISCLOSURE ANNUAL REPORT
SCHEDULE 2: RETIRED UNBUNDLED RECS
For the Year Ending December 31, 2021
Valley Clean Energy Alliance
UltraGreen
INSTRUCTIONS: Enter information about retired unbundled RECs associated with this electricity portfolio.

Insert additional rows as needed. All fields in white should be filled out. Fields in grey auto-populate as needed and should not be filled out.
101
Version: May 2022
Adjusted Net Procured
(MWh)
Percent of Total Retail
Sales
Renewable Procurements 4,418 100.0%
Biomass & Biowaste - 0.0%
Geothermal - 0.0%
Eligible Hydroelectric 1,177 26.6%
Solar 3,241 73.4%
Wind - 0.0%
Coal - 0.0%
Large Hydroelectric - 0.0%
Natural gas - 0.0%
Nuclear - 0.0%
Other - 0.0%
Unspecified Power - 0.0%
Total 4,418 100.0%
4,418
-

0.0%
Total Retail Sales (MWh)
GHG Emissions Intensity (converted to lbs CO2e/MWh)
Percentage of Retail Sales Covered by Retired Unbundled RECs
2021 POWER SOURCE DISCLOSURE ANNUAL REPORT
SCHEDULE 3: POWER CONTENT LABEL DATA
For the Year Ending December 31, 2021
Valley Clean Energy Alliance
UltraGreen
Instructions: No data input is needed on this schedule. Retail suppliers should use these auto-populated calculations to fill out their Power Content Labels. 102
Version: May 2022
2021 POWER SOURCE DISCLOSURE ANNUAL REPORT

ATTESTATION FORM
For the Year Ending December 31, 2021
Valley Clean Energy Alliance
UltraGreen
I, Gordon Samuel, Assistant General Manager & Director of Power Services, declare under penalty of perjury, that the statements contained in this report including Schedules 1, 2, and 3 are true and correct and that I, as an authorized agent of Valley Clean Energy Alliance, have authority to submit this report on the company's behalf. I further declare that the megawatt-hours claimed as specified purchases as shown in these Schedules were, to the best of my knowledge, sold once and only once to retail customers.

Name: Gordon Samuel
Representing (Retail Supplier):Valley Clean Energy Alliance Signature: __________________________________________________________ Dated: June 15, 2022
Executed at: Davis, California
103
2021 POWER CONTENT LABEL
Valley Clean Energy Alliance
https://valleycleanenergy.org/power-sources/
Greenhouse Gas Emissions Intensity
(lbs CO2e/MWh) Energy Resources Standard Green UltraGreen 2021 CA Power Mix Eligible Renewable1 12.6% 100.0% 33.6%
Biomass & Biowaste 0.0% 0.0% 2.3%
722 0 456 Geothermal 0.0% 0.0% 4.8%
Eligible Hydroelectric 0.0% 26.6% 1.0%
Solar 4.6% 73.4% 14.2%
Wind 8.0% 0.0% 11.4%
Coal 0.0% 0.0% 3.0%
Large Hydroelectric 10.9% 0.0% 9.2%
Natural Gas 0.0% 0.0% 37.9%
Nuclear 0.0% 0.0% 9.3%
Other 0.0% 0.0% 0.2%
Unspecified Power2 76.5% 0.0% 6.8%
TOTAL 100.0% 100.0% 100.0%
Percentage of Retail Sales Covered by Retired Unbundled RECs3: 0% 0% 1 The eligible renewable percentage above does not reflect RPS compliance, which is determined using a different methodology. 2 Unspecified power is electricity that has been purchased through open market transactions and is not traceable to a specific generation source.
3 Renewable energy credits (RECs) are tracking instruments issued for renewable generation. Unbundled renewable energy credits (RECs) represent renewable generation that was not delivered to serve retail sales. Unbundled RECs are not reflected in the power mix or GHG emissions intensities above.

For specific information about this electricity
portfolio, contact:

Valley Clean Energy Alliance
1-855-699-8232
For general information about the Power Content
Label, visit: http://www.energy.ca.gov/pcl/
For additional questions, please contact the
California Energy Commission at:

Toll-free in California: 844-454-2906
Outside California: 916-653-0237
Standard Green UltraGreen 2021 CA Utility Average
0 200
400
600
800
1000
Standard Green
UltraGreen
2021 CA Utility
Average
104
Valley Clean Energy Alliance

POWER SOURCE DISCLOSURE INDEPENDENT REVIEW OF

STANDARD GREEN PRODUCT AND ULTRAGREEN PRODUCT
FOR REPORTING YEAR 2021
To: Gordon Samuel, Asst. General Manager & Director of Power Resources From: Miriam Makhyoun, CEO, EQ Research, LLC
Blake Elder, Principal Analyst, EQ Research, LLC
Date: August 25, 2022
______________________________________________________________________ Introduction
Valley Clean Energy Alliance (VCE) has engaged EQ Research, LLC (EQ Research) to assist with an independent review of VCE’s Standard Green Power Source Disclosure (PSD) Annual Report and UltraGreen PSD Annual Report (together, the “Annual Reports”) for the year ending December 31, 2021.

EQ Research performed the procedures enumerated below to assist VCE with complying with the auditing and verification requirements of the PSD Program, as defined in Section 1394.2 of the California Code of Regulations, Title 20.

EQ Research obtained the underlying documentation1 used by VCE to complete the Annual Reports from VCE and accepts the accuracy of the information provided by VCE. EQ Research did not access VCE’s Western Renewable Energy Generation Information System (WREGIS) account information to verify the authenticity of the information provided by VCE but was provided an export of information from WREGIS. 2 1 All files referenced in this report can be accessed at: https://eq-research.sharefile.com/d-s4e4f26f20f12499f8b7a55bd43da30f1 2 See the file entitled, “2021PSDSupplyProductAllocations.xlsx” in the ShareFile link. 105
2 | For internal use by VCE only
Review Procedures and Findings
EQ Research based its detailed review of the Annual Reports on the audit procedures detailed in Section 1394.2(b) of the PSD program regulations. The procedures and associated findings for the Annual Reports are detailed below.

Standard Green PSD Report Review and UltraGreen PSD Report Review (b) Audit Procedures (1)(A)
EQ Research used the following publicly available sources in order to validate the information in the Annual Reports:

Source 1 (EIA): Energy Information Administration (EIA), Form EIA-923 detailed data, 2021: EIA-923 Early release Zip File, EIA923_Schedules_2_3_4_5_M_12_2021_Early_Release.xlsx, Page 1 Generation and Fuel Data, accessed on August 17, 2022 from https://www.eia.gov/electricity/data/eia923/
Source 2 (CEC): California Energy Commission (CEC), California’s Renewables Portfolio Standard (RPS) Public Search exported to Excel, accessed on August 17, 2022 from https://rps.energy.ca.gov/Pages/Search/SearchApplications.aspx EQ Research agreed the specified purchases3 by (a) facility name, (b) facility number provided by EIA, RPS ID, (c) kilowatt-hours, and (d) fuel type from the information used to prepare used to prepare the Annual Reports is consistent with what is presented in the Annual Reports Schedule 14 with one exception:
• Row 42 of Schedule 1 of Standard Green PSD Annual Report, resource, “Mid-C Hydro - Rock Island 6200 and Rocky Reach 3883 (Chelan County PUD)” includes two resources on one row (Rock Island, which is EIA Plant ID 6200 and Rocky Reach, which is EIA Plant ID 3883) and lists only EIA Plant ID 3883 (Rocky Reach’s EIA ID) in the EIA ID column of Schedule 1. The PSD report Schedule 1 is missing the 6200 EIA Plant ID in the EIA ID column even though the EIA ID is included in the Facility Name on Schedule

1. This inconsistency has no material impact on the resource percentages or greenhouse gas content of the Standard Green Product. Both resources are considered large hydro and both have a greenhouse gas emissions content of 0 MT CO2e/MWh (per “GHG Emissions Factors” tab of the PSD Annual Report spreadsheet). The combined output of the two plants is represented equally in EQ Research’s validation in Appendix A since VCE has confirmed that it does not have detail on the specific output for each plant.

EQ Research verified that the MWh listed in the Annual Reports do not exceed the annual MWh from EIA 923 data as expected (see Appendix A. Specified Facility Review Results) with one exception:
• EIA 923 2021 Early Release data shows there were 1,174 net MWh of electricity supplied by Indian Valley Hydro in 2021 but VCEA’s Schedule 1 for Standard Green shows that it purchased 1,177 MWh or 100.3% of that amount. EQ Research does not see this as a major discrepancy and expects that it could be due to rounding.

EQ Research also tested the mathematical accuracy of Schedule 1 and noted no exceptions. 3 There were no resales.
4 This information was checked against information in the following links: Source for RPS IDs:
https://rps.energy.ca.gov/Pages/Search/SearchApplications.aspx; Source for EIA IDs:
https://www.eia.gov/electricity/data/eia923/
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3 | For internal use by VCE only
(b) Audit Procedures (1)(B)(1)
EQ Research agreed the facility name, facility numbers provided by EIA and RPS, kilowatt-hours, and the fuel type from the invoice match the information used to prepare Schedule 1 of the Annual Reports.

EQ Research verified the above information by comparing information from a sample of two invoices for power purchases represented in the 2021 Annual Reports and the information used to prepare Schedule 1 of the Annual Reports along with the CEC and EIA data mentioned in (b) Audit Procedures (1)(A) above. The invoices were for purchases of 60,000 MWh of the total 181,027 MWh or 33% of the total MWh purchased by VCE for its green tariffs. The two invoices represent 60% of the RPS purchases (RECs and electricity) out of the total 99,218 MWh RPS portfolio for both green tariffs in the 2021 Annual Reports.

See Appendix B. Sample of Purchases VCE used to Prepare Schedule 1 which shows two limitations to EQ Research’s review that have been clarified by VCE as being limited only by the sample provided with no exceptions to note otherwise:

VCE confirmed that outside of the sample of two invoices reviewed by EQ Research, there are additional invoices that were not reviewed by EQ Research for the remaining 39,218 MWh of RPS purchases and invoices for another remaining 81,809 MWh of carbon-free electricity, representing a total of 121,027 MWh not contained in the invoices.

Only four resources out of 41 resources in Schedule 1 were included in the sample of two invoices but VCE confirmed the other resources also have corresponding invoices not represented in this limited sample used to examine the RPS portion of its portfolio. (b) Audit Procedures (1)(B)(2)
This is not applicable since there are no facilities in the Annual Reports owned by VCE. (b) Audit Procedures (1)(B)(3)
EQ Research verified a match between the date of generation from the two invoices in the sample to the reporting period of the information used to prepare Schedule 1.

See the “Energy Delivery Term” column in Appendix B. Sample of Purchases VCE used to Prepare Schedule 1.
(b) Audit Procedures (1)(B)(4)
This requirement is not applicable since VCE did not use unbundled Renewable Energy Credits (RECs) in its Annual Reports.
(b) Audit Procedures (1)(C)
Section 1393(d) provides that emissions from purchases of eligible firmed-and-shaped products under a purchase agreement or ownership arrangement executed prior to January 1, 2019 are excluded from a portfolio’s emissions intensity calculation. As shown on Schedule 1 of the Annual Reports, VCE did not claim any purchases from firmed-and-shaped imports for either Standard Green or UltraGreen products.
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(b) Audit Procedures (2)
EQ Research obtained a copy of the 2021 Power Content Label to be provided to VCE customers for the Standard Green and UltraGreen products. EQ Research verified that the resource portfolio percentages listed for each product on the 2021 Power Content Label match the respective percentages listed in Schedule 3 of the Power Source Disclosure Annual Reports. EQ Research also verified that the greenhouse gas emissions intensity for each product listed on the Power Content Label match those calculated on the Power Source Disclosure Annual Reports.

This report is intended solely for the information and use of the specified parties listed above and is not intended to be and should not be used by anyone other than those specified parties 108
Appendix A. Specified Facility Review Results
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Appendix B. Sample of Purchases VCE used to Prepare
Schedule 1
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Item 12
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 12
TO: Board of Directors
FROM: Edward Burnham, Director of Finance & Internal Operations Rebecca Boyles, Director of Customer Care & Marketing
Mitch Sears, Executive Officer
SUBJECT: Adopt 2022 AgFIT Budget
DATE: September 8, 2022

RECOMMENDATION

1. Approve a $1,200,000 Budget Amendment to allocate funds approved by the California Public Utilities Commission for the development and launch of VCE’s Agricultural Flexible Irrigation Technology (AgFIT) pilot program.

If approved, this Board action will:
a) Increase the 2022 Budget revenue estimate for Other Revenues - Programs by $1,200,000; and,
b) Increase the 2022 Budget expenditure appropriation for Programs - AgFIT by $1,200,000.

Staff has evaluated the costs of the program and forecasts the current-year requirement of $1,200,000 will have a net zero impact on VCE financials.

BACKGROUND AND ANALYSIS
The AgFIT pilot program is designed to provide VCE agricultural customers with hourly price signals and incentives for irrigation automation and scheduling software to better manage energy costs. More than 85% of VCE’s service territory footprint is designated for agricultural use. Due to this high concentration, the agricultural sector represents approximately 18% of VCE’s total annual load and 16% of its peak demand.

In support of VCE’s significant agricultural sector, the Board adopted a 3-year programs plan on June 10, 2021, that included an agricultural demand side program which evolved into the AgFIT dynamic rate pilot program.

At its December 2, 2021 meeting the CPUC issued decision 21-12-015 authorizing VCE’s proposed dynamic rate pilot to be made available to customers taking electric service on irrigation pumping tariffs, including program funding of $3,250,000 (inclusive of PG&E pilot related costs for $750,000). VCE’s portion of the initial CPUC funding was $2,500,000. The Pilot includes automation of agricultural pumping loads to respond to dynamic prices set by VCE and implementation of an experimental rate that incorporates energy and delivery costs in hourly 111
Item 12
2 prices. Customers who successfully respond to the prices and shift load out of expensive hours—typically the ramp hours—are projected to enjoy bill savings while contributing to grid reliability when it is most needed. A significant amount of the State’s agricultural irrigation pumping load is shiftable, presenting an important opportunity for California’s grid and environment.

Pilot Program Consultant Support
The AgFIT pilot is a unique undertaking that requires a combination of technical knowledge and electricity rate structuring that is matched with practical expertise in the agricultural sector, which is exceedingly uncommon. Polaris was awarded a grant by the California Energy Commission that is the precursor study for the AgFIT Pilot and provides them with the prerequisite skills and knowledge to support the VCE AgFIT pilot. Additionally, Polaris and TeMix sought out VCE based on our proposal submitted to the CPUC in late 2020 to implement a dynamic pricing structure to achieve load shift in the agricultural sector and formed an aligned effort to build the case for the Pilot awarded in the initial CPUC approval described above.

In addition to the industry-specific experience, VCE has relied on our general counsel and Regulatory counsel to facilitate the supplemental funding requests for the AgFit pilot program.

The CPUC awarded additional funding of $690,000 for other third-party and VCE administrative expenses. The total pilot program funding awarded by the CPUC is $3,940,000 including $750,000 for PG&E and 3,190,000 administered by VCE.

FISCAL IMPACT
As approved by the Board in January, VCE provided short-term budget support until the CPUC budget process was completed in the 2nd quarter of 2022. Following CPUC action and funding, VCE reimbursed short-term budget support expenditures incurred under pilot support services contracts to TeMix and Polaris. On January 27, 2022, the VCE Board approved a temporary budget of up to $200,000 of the program reserve fund covered by reimbursable revenues as described above.

Staff has evaluated the costs of the AgFIT program and forecasts the current-year requirement of $1,200,000 will have a net zero impact on VCE financials. VCE will continue to track and monitor its costs associated with the AgFIT Pilot and seek reimbursement through the CPUC during the three-year program for any anticipated budget amendments. AgFIT program revenues and expenditures will be included in the annual budget adoption in future years.

CONCLUSION
Staff recommends that the Board adopt the attached resolution for the budget amendment.

Attachment

1. Resolution
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RESOLUTION NO. 2022-____

RESOLUTION OF THE BOARD OF DIRECTORS OF THE VALLEY CLEAN ENERGY ALLIANCE AMENDING THE OPERATING BUDGET FOR YEAR 2022
WHEREAS, the Valley Clean Energy Alliance (“VCE”) is a joint powers agency established under the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.) (“Act”), and pursuant to a Joint Exercise of Powers Agreement Relating to and Creating the Valley Clean Energy Alliance between the County of Yolo (“County”), the City of Davis (“Davis”), the City of Woodland and the City of Winters (“Cities”) (the “JPA Agreement”), to collectively study, promote, develop, conduct, operate, and manage energy programs;

WHEREAS, on February 10, 2022, the Board adopted the 2022 Budget via resolution 2022-005, including Operating Revenues totaling $89.8M and purchased power and other operating expenses totaling $72.3M for a net income of $17.5M;
WHEREAS, On December 2, 2021, the California Public Utilities Commission issued decision 21- 12-015 authorizing VCE’s proposed “Agricultural Flexible Irrigation Technology (AgFIT)” three-year dynamic rate pilot program, to be made available to customers taking electric service on irrigation pumping tariffs, including program funding for a total of $3,190,000; NOW, THEREFORE, the Board of Directors of the Valley Clean Energy Alliance hereby adopts an Amendment to the 2022 Budget to increase program revenues for AgFIT by $1,200,000 and program expenditures for AgFIT by $1,200,000 for the costs associated with implementation of the AgFIT program in 2022.

PASSED, APPROVED AND ADOPTED, at a regular meeting of the Valley Clean Energy Alliance, held on the ____ day of _______________, 2022, by the following vote:

AYES:

NOES:

ABSENT:

ABSTAIN:
___________________________________
Jesse Loren, VCE Chair
__________________________________
Alisa M. Lembke, VCE Board Secretary
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Item 13

VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 13
____________________________________________________________________________________ TO: Board of Directors
FROM: Edward Burnham, Director of Finance & Internal Operations SUBJECT: Retention of municipal financial advisory services DATE: September 8, 2022

RECOMMENDATION

1. Adopt resolution approving services contract with PFM Financial Advisors for Municipal Financial Advisory support services.

BACKGROUND AND ANALYSIS
Beginning in January 2020, the Board directed staff to develop a multi-year strategic plan to establish goals and guide VCE’s activities over the next three years commencing in 2021. On October 8, 2020, the Board adopted VCE’s Three-Year Strategic Plan (Plan) for 2021-2023, which can be found here. The Plan included Goal 1 – financial strength and set objective 1.2 to achieve an investment grade credit rating by the end of 2024, emphasizing the importance of VCE’s financial health and independence. As part of the current Fiscal Year 2022 budget, the Board approved funding to begin the process that could lead to an investment grade credit rating for VCE.

As outlined in the Strategic Plan analysis, an investment grade credit rating demonstrates financial stability allowing VCE to pursue more favorable financial terms with counterparties and more easily address efforts to apply heavier regulatory requirements on VCE.

Establishing a Credit Rating
Establishing a credit rating for a CCA is a unique undertaking that requires a combination of technical knowledge of the energy sector, familiarity with the CCA model, and practical expertise in the financial rating sector; this combination is very uncommon. VCE issued the attached Request for Proposals (RFP) to obtain proposals for a multi-year agreement from qualified municipal financial advisors to provide Financial Advisory (FA) services. The FA services are required to support the establishment of VCE’s initial investment-grade credit rating and general FA support. The general FA support may include assisting in evaluating VCE finance policies, VCE’s debt capacity and affordability for lines of credit and long-term debts, assessing coverage ratios, and other metrics to ensure the continued success of financing requirements.
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2 Other Considerations
The California Public Utilities Commission has increased scrutiny of the basic CCA finance model by regulators and the financial sector due to the 2021 Western Community Energy CCA bankruptcy. As a result of the bankruptcy, staff anticipates that the CCA industry will see increased self and/or outside regulation associated with the establishment of new standards of practice related to the financial health of CCAs. Establishing an investment grade credit rating by an outside agency may serve to reduce this regulatory burden.

RFP Responses/Consultant Selection
Three firms submitted responsive proposals to the RFP. Senior Staff and VCE’s Treasurer, Chad Rinde, reviewed the proposals, interviewed the three firms, and reached consensus that PFM possessed the strongest combination of technical knowledge of the energy sector, familiarity with the CCA model, and practical expertise in the financial rating sector. Based on the written proposals, interviews, and proposed budget, staff is recommending VCE retain PFM to provide financial advisor services, including VCE’s pursuit of an investment grade credit rating.

FISCAL IMPACT
As approved by the Board in the adoption of the Fiscal Year 2022 Budget, VCE included $50,000 of expenditures for the first year of Financial Advisor services. As the recommended agreement is a multi-year not to exceed amount contract, the current budget allocation is anticipated to be sufficient funding for these services until the end of 2022. Staff will be returning for an additional budget allocation for these types of services as part of the FY 2023 budget.

NEXT STEPS
VCE, in partnership with PFM, will begin developing a strategy and timeline to establish an investment-grade credit rating. This strategy and timeline will include the selection of a credit rating agency for the rating, developing a rating presentation for discussion with the credit analysts, and coordinating meetings and calls with the analysts.

CONCLUSION
Staff recommends the Board approve the consultant services contract with PFM Financial Advisors for Municipal Financial Advisory support services for an amount not to exceed $65,000 for a term beginning September 8, 2022, expiring December 31, 2025.

ATTACHMENTS

1. Agreement between VCE and PFM Financial Advisors

2. Resolution 2022-XXX
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AGREEMENT BETWEEN THE VALLEY CLEAN ENERGY ALLIANCE AND

PFM FINANCIAL ADVISORS LLC
FOR

FINANCIAL ADVISORY SERVICES
THIS AGREEMENT, is entered into this 8th day of September 2022 by and between the VALLEY CLEAN ENERGY ALLIANCE, a Joint Powers Authority organized and operating under the laws of the State of California, with its principal place of business at 604 Second Street, Davis, California, 95616 ("VCE"), and PFM FINANCIAL ADVISORS LLC, a Delaware limited liability company 555 West 5th Street, Suite 3500, Los Angeles, CA 90013 (hereinafter referred to as "Consultant") (collectively referred to as the “Parties” and individually as a “Party”).

RECITALS:

A. VCE is an independent public agency duly organized under the provisions of the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.) (“Act”) with the power to conduct its business and enter into agreements.

B. Consultant possesses the skill, experience, ability, background, certification and knowledge to provide the services described in this Agreement pursuant to the terms and conditions described herein.

C. VCE and Consultant desire to enter into an agreement for financial advisory services upon the terms and conditions herein.

NOW, THEREFORE, the Parties mutually agree as follows:

1. TERM
The term of this Agreement shall commence on September 8, 2022, and shall terminate on December 31, 2025 with two one year optional extensions, unless terminated earlier as set forth herein.

2. SERVICES TO BE PERFORMED
Consultant shall perform each and every service set forth in Exhibit "A" pursuant to the schedule of performance set forth in Exhibit "B," both of which are attached hereto and incorporated herein by this reference. Upon the request of VCE, an affiliate of Consultant or a third party referred or otherwise introduced by Consultant may agree to additional services to be provided by such affiliate or third party, by a separate writing, including separate scope and compensation, between VCE and such affiliate or third party. 116
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3. COMPENSATION TO CONSULTANT
Consultant shall be compensated for services performed pursuant to this Agreement in a total amount not to exceed sixty-five thousand dollars ($65,000.00) based on the rates and terms set forth in Exhibit "C," which is attached hereto and incorporated herein by this reference.

4. TIME IS OF THE ESSENCE
Consultant and VCE agree that time is of the essence regarding the performance of this Agreement.

5. STANDARD OF CARE
Consultant agrees to perform all services required by this Agreement with the degree of skill and care, and in a manner commensurate with the prevailing standards of specially trained professionals in the San Francisco Bay Area under similar circumstances and agrees that all services shall be performed by qualified and experienced personnel. Consultant shall be responsible to VCE for any errors or omissions in the performance of work pursuant to this Agreement. Should any errors caused by Consultant be found in such services or products, Consultant shall correct the errors at no additional charge to VCE by redoing the professional work and/or revising the work product(s) called for in the Scope of Services to eliminate the errors.

Should Consultant fail to make such correction in a reasonably timely manner, such correction may be made by VCE, and the cost thereof shall be charged to Consultant. In addition to all other available remedies, VCE may deduct the cost of such correction from any retention amount held by VCE or may withhold payment otherwise owed Consultant under this Agreement up to the amount of the cost of correction.

6. INDEPENDENT PARTIES
VCE and Consultant intend that the relationship between them created by this Agreement is that of an independent contractor. The manner and means of conducting the work are under the control of Consultant, except to the extent they are limited by statute, rule or regulation and the express terms of this Agreement. No civil service status or other right of employment will be acquired by virtue of Consultant's services. None of the benefits provided by VCE to its employees, including but not limited to, unemployment insurance, workers’ compensation plans, vacation and sick leave are available from VCE to Consultant, its employees or agents. Deductions shall not be made for any state or federal taxes, FICA payments, PERS payments, or other purposes normally associated with an employer-employee relationship from any fees due Consultant.

Payments of the above items, if required, are the responsibility of Consultant. Consultant shall indemnify and hold harmless VCE and its elected officials, officers, employees, servants, designated volunteers, and agents serving as independent contractors in the role of VCE officials, from any and all liability, damages, claims, costs and expenses of any nature to the extent arising from Consultant’s personnel practices. VCE shall have the right to offset against the amount of any fees due to Consultant under this Agreement any amount due to VCE from Consultant as a result of Consultant’s failure to promptly pay to VCE any reimbursement or indemnification arising under this section.
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7. NO RECOURSE AGAINST CONSTITUENT MEMBERS OF VCE
VCE is organized as a Joint Powers VCE in accordance with the Joint Powers Act of the State of California (Government Code Section 6500 et seq.) pursuant to a Joint Powers Agreement dated March 31, 2016, and is a public entity separate from its constituent members. VCE shall solely be responsible for all debts, obligations and liabilities accruing and arising out of this Agreement. Consultant shall have no rights and shall not make any claims, take any actions or assert any remedies against any of VCE’s constituent members in connection with this Agreement.

8. NON-DISCRIMINATION
In the performance of this Agreement, Consultant, and any subconsultant under the Consultant, shall not discriminate against any employee, subcontractor or applicant for employment because of race, color, religious creed, sex, gender, gender identity, gender expression, marital status, national origin, ancestry, age, physical disability, mental disability, medical condition, genetic information, sexual orientation, military or veteran status, or other basis prohibited by law, except as provided in Government Code section 12940. Consultant shall have responsibility for compliance with this Section.

9. HOLD HARMLESS AND INDEMNIFICATION
A. General Indemnification. To the fullest extent permitted by law, Consultant shall, at its sole cost and expense, defend, hold harmless and indemnify VCE and its elected officials, officers, attorneys, agents, employees, designated volunteers, successors, assigns and those VCE agents serving as independent contractors in the role of VCE officials (collectively “Indemnitees”), from and against any and all damages, costs, expenses, liabilities, claims, demands, causes of action, proceedings, expenses, judgments, penalties, liens, and losses of any nature whatsoever, including fees of accountants, attorneys, or other professionals and all costs associated therewith (collectively “Liabilities”), in law or equity, whether actual, alleged or threatened, which arise out of, are claimed to arise out of, pertain to, or relate to the negligent or intentionally wrongful acts or omissions of Consultant, its officers, agents, servants, employees, subcontractors, materialmen, consultants or their officers, agents, servants or employees (or any entity or individual that Consultant shall bear the legal liability thereof) in the performance of this Agreement, except for Liabilities arising from the sole negligence or willful misconduct of the Indemnitees as determined by court decision or by the agreement of the Parties. Consultant shall defend the Indemnitees in any action or actions filed in connection with any Liabilities with counsel of the Indemnitees’ choice, but subject to Consultant’s approval, and shall pay all costs and expenses, including all attorneys’ fees and experts’ costs actually incurred in connection with such defense. Consultant shall reimburse the Indemnitees for any and all legal expenses and costs incurred by Indemnitees in connection therewith.

B. Intellectual Property Indemnification. Consultant hereby certifies that it owns, controls, or licenses and retains all right, title, and interest in and to any intellectual property it uses in relation to this Agreement, including the design, look, feel, features, source code, content, and other technology relating to any part of the services and including all related patents, inventions, trademarks, and copyrights, all applications therefor, and all trade names, service 118
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marks, know how, and trade secrets (collectively referred to as “IP Rights”), except as otherwise expressly provided by this Agreement. Consultant warrants that the services to be provided pursuant to this Agreement do not infringe, violate, trespass, or constitute the unauthorized use or misappropriation of any IP Rights of any third party. Consultant shall indemnify, defend, and hold Indemnitees, harmless from and against any Liabilities by a third party that the services to be provided pursuant to this Agreement infringe or violate any third-party’s IP Rights, provided any such right is enforceable in the United States. Such costs and expenses shall include reasonable attorneys’ fees of counsel of VCE’s choice, expert fees and all other costs and fees of litigation.

C. The acceptance of the services by VCE shall not operate as a waiver of these rights of indemnification. The hold harmless and indemnification provisions of this Section shall apply regardless of whether or not any insurance policies are determined to be applicable to the Liability.

D. Consultant’s indemnifications and obligations under this section shall survive the expiration or termination of this Agreement.

10. INSURANCE
A. General Requirements. On or before the commencement of the term of this Agreement, Consultant shall furnish VCE with certificates showing the type, amount, class of operations covered, effective dates and dates of expiration of insurance coverage in compliance with the requirements listed in Exhibit "D," which is attached hereto and incorporated herein by this reference. Such insurance and certificates, which do not limit Consultant’s indemnification obligations under this Agreement, shall also contain substantially the following statement:
"Should any of the above insurance covered by this certificate be canceled or coverage reduced before the expiration date thereof, the Consultant shall provide thirty (30) days’ advance written notice to VCE by certified mail, Attention: Chief Executive Officer." Consultant shall maintain in force at all times during the performance of this Agreement all appropriate coverage of insurance required by this Agreement with an insurance company that is acceptable to VCE and licensed to do insurance business in the State of California. Endorsements naming VCE as additional insured on the comprehensive general and automotive liability shall be submitted with the insurance certificates.

B. Subrogation Waiver. Consultant agrees that in the event of loss due to any of the perils for which he/she has agreed to provide comprehensive general and automotive liability insurance, Consultant shall look solely to his/her/its insurance for recovery. Consultant hereby grants to VCE, on behalf of any insurer providing comprehensive general and automotive liability insurance to either Consultant or VCE with respect to the services of Consultant herein, a waiver of any right to subrogation which any such insurer of Consultant may acquire against VCE by virtue of the payment of any loss under such insurance.

C. Failure to secure or maintain insurance. If Consultant at any time during the term hereof should fail to secure or maintain the foregoing insurance, VCE shall be permitted to obtain such insurance in the Consultant's name or as an agent of the Consultant and shall be compensated by the Consultant for the costs of the insurance premiums at the maximum rate permitted by law and computed from the date written notice is received that the premiums have not been paid. 119
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D. Additional Insured. VCE, its members, officers, employees and volunteers shall be named as additional insureds under all insurance coverages, except any workers compensation and professional liability insurance, required by this Agreement. The naming of an additional insured shall not affect any recovery to which such additional insured would be entitled under this policy if not named as such additional insured. An additional insured named herein shall not be held liable for any premium, deductible portion of any loss, or expense of any nature on this policy or any extension thereof. Any other insurance held by an additional insured shall not be required to contribute anything toward any loss or expense covered by the insurance provided by this policy.

E. Sufficiency of Insurance. The insurance limits required by VCE are not represented as being sufficient to protect Consultant. Consultant is advised to confer with Consultant's insurance broker to determine adequate coverage for Consultant.

F. Maximum Coverage and Limits. It shall be a requirement under this Agreement that any available insurance proceeds broader than or in excess of the specified minimum Insurance coverage requirements and/or limits shall be available to the additional insureds. Furthermore, the requirements for coverage and limits shall be the minimum coverage and limits specified in this Agreement, or the broader coverage and maximum limits of coverage of any insurance policy or proceeds available to the named insured, whichever is greater.

11. CONFLICT OF INTEREST
Consultant warrants that it, its officers, employees, associates and subcontractors, presently have no interest, and will not acquire any interest, direct or indirect, financial or otherwise, that would conflict in any way with the performance of this Agreement, and that it, its officers, employees, associates and subcontractors, will not employ any person having such an interest.

Consultant and its officers, employees, associates and subcontractors, if any, shall comply with all conflict of interest statutes of the State of California applicable to Consultant’s services under this Agreement, including the Political Reform Act (Gov. Code § 81000, et seq.) and Government Code Section 1090. During the term of this Agreement, Consultant may perform similar services for other clients, but Consultant and its officers, employees, associates and subcontractors shall not, without the VCE Representative’s prior written approval, perform work for another person or entity for whom Consultant is not currently performing work that would require Consultant or one of its officers, employees, associates or subcontractors to abstain from a decision under this Agreement pursuant to a conflict of interest statute. Consultant shall incorporate a clause substantially similar to this section into any subcontract that Consultant executes in connection with the performance of this Agreement. Consultant understands that it may be required to fill out a conflict of interest form if the services provided under this Agreement require Consultant to make certain governmental decisions or serve in a staff VCE, as defined in Title 2, Division 6, Section 18700 of the California Code of Regulations.

12. PROHIBITION AGAINST TRANSFERS
Consultant shall not assign, sublease, hypothecate, or transfer this Agreement, or any interest therein, directly or indirectly, by operation of law or otherwise, without prior written consent of VCE. Any attempt to do so without such consent shall be null and void, and any assignee, sublessee, pledgee, or transferee shall acquire no right or interest by reason of such 120
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attempted assignment, hypothecation or transfer. However, claims for money by Consultant from VCE under this Agreement may be assigned to a bank, trust company or other financial institution without prior written consent. Written notice of such assignment shall be promptly furnished to VCE by Consultant.

The sale, assignment, transfer or other disposition of any of the issued and outstanding capital stock of Consultant, or of the interest of any general partner or joint venturer or syndicate member or cotenant, if Consultant is a partnership or joint venture or syndicate or cotenancy, which shall result in changing the control of Consultant, shall be construed as an assignment of this Agreement. Control means fifty percent (50%) or more of the voting power of the corporation.

13. SUBCONTRACTOR APPROVAL
Unless prior written consent from VCE is obtained, only those persons and subcontractors whose names are attached to this Agreement shall be used in the performance of this Agreement.

In the event that Consultant employs subcontractors, such subcontractors shall be required to furnish proof of workers’ compensation insurance and shall also be required to carry general, automobile and professional liability insurance in substantial conformity to the insurance carried by Consultant. In addition, any work or services subcontracted hereunder shall be subject to each provision of this Agreement.

Consultant agrees to include within their subcontract(s) with any and all subcontractors the same requirements and provisions of this Agreement, including the indemnity and insurance requirements, to the extent they apply to the scope of the subcontractor’s work. Subcontractors hired by Consultant shall agree to be bound to Consultant and VCE in the same manner and to the same extent as Consultant is bound to VCE under this Agreement. Subcontractors shall agree to include these same provisions within any sub-subcontract. Consultant shall provide a copy of the Indemnity and Insurance provisions of this Agreement to any subcontractor. Consultant shall require all subcontractors to provide valid certificates of insurance and the required endorsements prior to commencement of any work and will provide proof of compliance to VCE.

14. REPORTS
A. Each and every report, draft, work product, map, record and other document, hereinafter collectively referred to as "Report", reproduced, prepared or caused to be prepared by Consultant pursuant to or in connection with this Agreement, shall be the exclusive property of VCE. Consultant shall not copyright any Report required by this Agreement and shall execute appropriate documents to assign to VCE the copyright to Reports created pursuant to this Agreement. Any Report, information and data acquired or required by this Agreement shall become the property of VCE, and all publication rights are reserved to VCE. Consultant may retain a copy of any Report furnished to VCE pursuant to this Agreement.

B. All Reports prepared by Consultant may be used by VCE in execution or implementation of: (1) The original project for which Consultant was hired; (2) Completion of the 121
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original project by others; (3) Subsequent additions to the original project; and/or (4) Other VCE projects as VCE deems appropriate in its sole discretion.

C. Consultant shall, at such time and in such form as VCE may require, furnish reports concerning the status of services required under this Agreement.

D. All Reports shall also be provided in electronic format, both in the original file format (e.g., Microsoft Word) and in PDF format.

E. No Report, information or other data given to or prepared or assembled by Consultant pursuant to this Agreement that has not been publicly released shall be made available to any individual or organization by Consultant without prior approval by VCE.

F. VCE shall be the owner of and shall be entitled upon request to immediate possession of accurate reproducible copies of Reports or other pertinent data and information gathered or computed by Consultant prior to termination of this Agreement or upon completion of the work pursuant to this Agreement.

15. RECORDS
Consultant shall maintain complete and accurate records with respect to costs, expenses, receipts and other such information required by VCE that relate to the performance of services under this Agreement, in sufficient detail to permit an evaluation of the services and costs. All such records shall be clearly identified and readily accessible. Consultant shall provide free access to such books and records to the representatives of VCE or its designees at all reasonable times, and upon reasonable advanced notice, and gives VCE the right to examine and audit same, and to make transcripts therefrom as necessary, and to allow inspection of all work, data, documents, proceedings and activities related to this Agreement. Such records, together with supporting documents, shall be maintained for a minimum period of five (5) years after Consultant receives final payment from VCE for all services required under this agreement.

16. PARTY REPRESENTATIVES
The Interim General Manager (“VCE Representative”) shall represent VCE in all matters pertaining to the services to be performed under this Agreement. Michael Berwanger (Consultant Representative”) shall represent Consultant in all matters pertaining to the services to be performed under this Agreement.

17. INFORMATION AND DOCUMENTS
A. Consultant covenants that all data, reports, documents, discussion, or other information (collectively “Data”) developed or received by Consultant or provided for performance of this Agreement are deemed confidential and shall not be disclosed or released by Consultant without prior written authorization by VCE, unless disclosure is required by law or judicial or regulatory process. VCE shall grant such authorization if applicable law requires disclosure. Consultant, its officers, employees, agents, or subcontractors shall not without written authorization from the VCE Representative or unless requested in writing by VCE’s counsel, 122
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voluntarily provide declarations, letters of support, testimony at depositions, response to interrogatories or other information concerning the work performed under this Agreement or relating to any project or property located within VCE. Response to a subpoena or court order shall not be considered “voluntary,” provided Consultant gives VCE notice of such court order or subpoena.

B. Consultant shall promptly notify VCE should Consultant, its officers, employees, agents or subcontractors be served with any summons, complaint, subpoena, notice of deposition, request for documents, interrogatories, request for admissions or other discovery request, court order or subpoena from any party regarding this Agreement and the work performed thereunder or with respect to any project or property located within VCE. VCE may, but has no obligation to, represent Consultant or be present at any deposition, hearing or similar proceeding. Consultant agrees to cooperate fully with VCE and to provide VCE with the opportunity to review any response to discovery requests provided by Consultant. However, VCE’s right to review any such response does not imply or mean the right by VCE to control, direct or rewrite the response.

C. In the event VCE gives Consultant written notice of a “litigation hold”, then as to all data identified in such notice, Consultant shall, at no additional cost to VCE, isolate and preserve all such data pending receipt of further direction from VCE.

D. Consultant’s covenants under this section shall survive the expiration or termination of this Agreement.

18. NOTICES
Any notice, consent, request, demand, bill, invoice, report or other communication required or permitted under this Agreement shall be in writing and conclusively deemed effective: (a) on personal delivery, (b) on confirmed delivery by courier service during Consultant’s and VCE’s regular business hours, or (c) three Business Days after deposit in the United States mail, by first class mail, postage prepaid, and addressed to the Party to be notified as set forth below:

TO VCE:

Valley Clean Energy Alliance
604 Second Street
Davis, CA 95616
Attention: Executive Officer
TO CONSULTANT:

Michael Berwanger
PFM Financial Advisors LLC
555 West 5th Street, Suite 3500
Los Angeles, CA 90013
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19. TERMINATION
In the event Consultant fails or refuses to perform any of the provisions hereof at the time and in the manner required hereunder, Consultant shall be deemed in default in the performance of this Agreement. If Consultant fails to cure the default within the time specified (which shall be determined by VCE but shall be not less than 10 days) and according to the requirements set forth in VCE’s written notice of default, and in addition to any other remedy available to VCE by law, the VCE Representative may terminate the Agreement by giving Consultant written notice thereof, which shall be effective immediately. The VCE Representative shall also have the option, at its sole discretion and without cause, of terminating this Agreement by giving seven (7) calendar days' prior written notice to Consultant as provided herein. Upon receipt of any notice of termination, Consultant shall immediately discontinue performance.

In the event of VCE’s termination of this Agreement due to no fault or failure of performance by Consultant, VCE shall pay Consultant for services satisfactorily performed up to the effective date of termination. Upon termination, Consultant shall immediately deliver to VCE any and all copies of studies, sketches, drawings, computations, and other material or products, whether or not completed, prepared by Consultant or given to Consultant, in connection with this Agreement. Such materials shall become the property of VCE. Consultant shall have no other claim against VCE by reason of such termination, including any claim for compensation.

20. COMPLIANCE WITH LAWS
Consultant shall keep itself informed of all applicable federal, state and local laws, ordinances, codes, regulations and requirements which may, in any manner, affect those employed by it or in any way affect the performance of its services pursuant to this Agreement. Consultant shall, at all times, observe and comply with all such laws and regulations. VCE, and its officers and employees, shall not be liable at law or in equity by reason of the failure of the Consultant to comply with this paragraph.

Consultant represents and agrees that all personnel engaged by Consultant in performing services are and shall be fully qualified and are authorized or permitted under state and local law to perform such services. Consultant represents and warrants to VCE that it has all licenses, permits, certificates, qualifications, and approvals required by law to provide the services and work required to perform services under this Agreement, including a business license. Consultant further represents and warrants that it shall keep in effect all such licenses, permits, and other approvals during the term of this Agreement.

21. CONFLICT OF LAW
This Agreement shall be interpreted under, and enforced by the laws of the State of California. The Agreement and obligations of the Parties are subject to all valid laws, orders, rules, and regulations of the authorities having jurisdiction over this Agreement (or the successors of those authorities). Any suits brought pursuant to this Agreement shall be filed with the Superior Court of the County of Yolo, State of California.
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22. ADVERTISEMENT
Consultant shall not post, exhibit, display or allow to be posted, exhibited, displayed any signs, advertising, show bills, lithographs, posters or cards of any kind pertaining to the services performed under this Agreement unless prior written approval has been secured from VCE to do otherwise.

23. WAIVER
A waiver by VCE of any breach of any term, covenant, or condition contained herein shall not be deemed to be a waiver of any subsequent breach of the same or any other term, covenant, or condition contained herein, whether of the same or a different character.

24. INTEGRATED CONTRACT
This Agreement represents the full and complete understanding of every kind or nature whatsoever between the Parties, and all preliminary negotiations and agreements of whatsoever kind or nature are merged herein. No verbal agreement or implied covenant shall be held to vary the provisions hereof. Any modification of this Agreement will be effective only by a written document signed by both VCE and Consultant. For the sake of clarity, any separate agreement between VCE and an affiliate of Consultant or any third party referred or introduced by Consultant shall not in any way be deemed an amendment or modification of this Agreement.

25. AUTHORITY
The individual(s) executing this Agreement represent and warrant that they have the legal authority and authority to do so on behalf of their respective legal entities.

26. INSERTED PROVISIONS
Each provision and clause required by law to be inserted into the Agreement shall be deemed to be enacted herein, and the Agreement shall be read and enforced as though each were included herein. If through mistake or otherwise, any such provision is not inserted or is not correctly inserted, the Agreement shall be amended to make such insertion on application by either Party.

27. CAPTIONS AND TERMS
The captions in this Agreement are for convenience only, are not a part of the Agreement and in no way affect, limit or amplify the terms or provisions of this Agreement.

28. VCE’S RIGHTS TO EMPLOY OTHER CONSULTANTS
VCE reserves the right to employ other consultants in connection with the subject matter of the Scope of Services.
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29. EXHIBITS
The Exhibits referenced in this Agreement are attached hereto and incorporated herein by this reference as though set forth in full in the Agreement. If any inconsistency exists or arises between a provision of this Agreement and a provision of any exhibit, or between a provision of this Agreement and a provision of Consultant’s proposal, the provisions of this Agreement shall control.

30. FORCE MAJEURE
Consultant shall not be liable for any failure to perform its obligations under this Agreement if Consultant presents acceptable evidence, in VCE’s sole judgment, that such failure was due to acts of God, embargoes, inability to obtain labor or materials or reasonable substitutes for labor or materials, governmental restrictions, governmental regulations, governmental controls, judicial orders, enemy or hostile governmental action, civil commotion, fire or other casualty, or other causes beyond Consultant’s reasonable control and not due to any act by Consultant.

31. FINAL PAYMENT ACCEPTANCE CONSTITUTES RELEASE
The acceptance by Consultant of the final payment made under this Agreement shall operate as and be a release of VCE from all claims and liabilities for compensation to Consultant for anything done, furnished or relating to Consultant’s work or services. Acceptance of payment shall be any negotiation of VCE’s check or the failure to make a written extra compensation claim within ten calendar days of the receipt of that check. However, approval or payment by VCE shall not constitute, nor be deemed, a release of the responsibility and liability of Consultant, its employees, subcontractors and agents for the accuracy and competency of the information provided and/or work performed; nor shall such approval or payment be deemed to be an assumption of such responsibility or liability by VCE for any defect or error in the work prepared by Consultant, its employees, subcontractors and agents.

32. ATTORNEY FEES
In any litigation or other proceeding by which a Party seeks to enforce its rights under this Agreement (whether in contract, tort or both) or seeks a declaration of any rights or obligations under this Agreement, the prevailing Party shall be entitled to recover all attorneys’ fees, experts’ fees, and other costs actually incurred in connection with such litigation or other proceeding, in addition to all other relief to which that Party may be entitled.

33. SEVERABILITY
If any provision in this Agreement is held by a court of competent jurisdiction to be illegal, invalid, void, or unenforceable, the remaining provisions will nevertheless continue in full force without being impaired or invalidated in any way.
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34. SUCCESSORS AND ASSIGNS
The terms and conditions of this Agreement shall be binding on the successors and assigns of the Parties to this Agreement.

35. NO THIRD PARTY BENEFICIARIES INTENDED
This Agreement is made solely for the benefit of the Parties to this Agreement and their respective successors and assigns, and no other person or entity may have or acquire a right by virtue of this Agreement.

36. COUNTERPARTS; FACSIMILE/PDF/ELECTRONIC SIGNATURE
This Agreement may be executed in multiple counterparts, all of which shall be deemed an original, and all of which will constitute one and the same instrument. The Parties agree that a facsimile, PDF or electronic signature may substitute for and have the same legal effect as the original signature.

37. DRAFTING PARTY
This Agreement shall be construed without regard to the Party that drafted it. Any ambiguity shall not be interpreted against either Party and shall, instead, be resolved in accordance with other applicable rules concerning the interpretation of contracts.

38. REGISTERED MUNICIPAL ADVISOR; REQUIRED DISCLOSURES
Consultant is a registered municipal advisor with the Securities and Exchange Commission (the “SEC”) and the Municipal Securities Rulemaking Board (the “MSRB”), pursuant to the Securities Exchange Act of 1934 Rule 15Ba1-2. If VCE has designated Consultant as its independent registered municipal advisor (“IRMA”) for purposes of SEC Rule 15Ba1-1(d)(3)(vi) (the “IRMA exemption”), then services provided pursuant to such designation shall be the services described in Exhibit A hereto, subject to any agreed upon limitations. Verification of independence (as is required under the IRMA exemption) shall be the responsibility of such third party seeking to rely on such IRMA exemption. Consultant shall have the right to review and approve in advance any representation of Consultant’s role as IRMA to VCE.

MSRB Rules require that municipal advisors make written disclosures to their clients of all material conflicts of interest, certain legal or disciplinary events and certain regulatory requirements. Such disclosures are provided in Consultant’s Disclosure Statement delivered to VCU prior to or together with this Agreement.
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39. INFORMATION TO BE FURNISHED TO CONSULTANT
All information, data, reports, and records in the possession of VCE or any third party necessary for carrying out any services to be performed under this Agreement (“Data”) shall be furnished to Consultant. Consultant may rely on the Data in connection with its provision of the services under this Agreement and the provider thereof shall remain solely responsible for the adequacy, accuracy and completeness of such Data.

IN WITNESS WHEREOF, the Parties have caused the Agreement to be executed as of the date set forth above.

RECOMMENDED FOR APPROVAL

PFM FINANCIAL ADVISORS LLC
By: __________________________
Name: Michael Berwanger
Title: Managing Director
Date: __________________________

VALLEY CLEAN ENERGY ALLIANCE
A Joint Powers Authority
By: ___________________________
Name: Mitch Sears
Title: Executive Officer
Date: __________________________
APPROVED AS TO FORM:
_______________________
Inder Khalsa
Counsel for VCE
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Exhibit A
Scope of Services
VCE is soliciting for “on-call” advisory services during the term of the contract for general municipal advisory services to establish VCE's investment grade credit rating and should be capable of completing debt issuances for projects if required. These services shall be provided at the request of VCE and may include:
a. Serving as VCE’s independent registered municipal advisor (IRMA). In that capacity, evaluate financial proposals received by VCE from underwriters, market participants, and rating agencies and provide written analysis, as requested. b. Reviewing rating agency methodologies and criteria and supporting calls and/or meetings related to establishing rating and rating surveillance. c. Developing rating agency strategy and approach, as needed. Preparing rating agency presentations and accompanying VCE’s staff at rating agency meetings. d. Assisting in the evaluation of VCE’s current and long-term debt capacity and debt affordability.
e. Monitoring outstanding debt for refunding opportunities. f. Preparing preliminary debt service analyses and financing plans for capital planning or other financing needs.
g. Evaluate impacts of debt, project proposals, contractual requirements, and financial metrics.
h. Assisting with developing and refining debt policies, disclosures, and financial reserve policies.
i. Presenting financing opportunities related to contemplated projects and specific areas of interest to VCE.
j. Performing other advisory services as requested.

For any anticipated debt financings, the municipal advisor role shall include the following:
a. Assist in the selection of other financing team members, as needed. b. Coordinate activities of financing team members and VCE representatives. c. Make recommendations regarding the method of sale (ex., competitive, negotiated, direct purchase, etc.) in compliance with municipal debt issuances and VCE policies. d. Analyze alternative bond and security structures and make recommendations that will be most attractive to bond and security market participants to result in the best pricing.
e. Provide information and guidance to staff about the ability and potential to purchase a portion of the debt as part of the development of the financing structure. f. Prepare debt service analysis for proposed financing, including studies under alternative market scenarios.
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g. Assist in reviewing all financing and legal documents, balancing market requirements and VCE’s ongoing financial stability.
h. Assist in ensuring full and complete disclosure in the VCE preliminary official statements and/or other financing documents.
i. Develop rating agency strategy and approaches, as needed. j. Prepare rating agency presentations and accompany VCE staff to rating agency meetings.
k. Assist VCE staff in presenting the financing to the Board of Directors, if needed. l. Monitor tax-exempt market conditions and make a recommendation regarding the time of pricing.
m. Assist with investor outreach to add pre-sale marketing of bonds. n. Evaluate the potential cost-effectiveness of credit enhancement. o. Assist VCE staff and financing team in arranging the execution of financing documents and closing financing.
p. Review and provide recommended updates to debt policy to ensure compliance with new and upcoming legal requirements before issuance.
q. Prepare post-sale closing memorandum, disclosures, and compliance documents. r. Provide advisement during any transactions about post-issuance compliance.

Additional Services
There will likely be matters that, due to complexity, size, and scope, litigation, special projects, new laws or regulations, ballot measures, etc., may require services beyond that which are encompassed in the services listed above. It may also be in VCE’s best interest to retain additional consultants for unique or specialized matters related to debt issuances. In those circumstances, the advisor may be asked to coordinate with consultants. Additional services beyond the work scope will be billed at an hourly rate. Such services would be authorized on a case-by-case basis.
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Exhibit B
Schedule of Performance

NOT APPLICABLE
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Exhibit C
Compensation
VCE shall compensate Consultant for professional services in accordance with the terms and conditions of this Agreement based on the rates and compensation schedule set forth below.

Compensation shall be calculated based on the hourly rates set forth below up to the not to exceed budget amount set forth below.

The compensation to be paid to Consultant under this Agreement for all services described in Exhibit “A” and reimbursable expenses shall not exceed a total sixty-five thousand dollars ($65,000), as set forth below. Any work performed or expenses incurred for which payment would result in a total exceeding the maximum amount of compensation set forth herein shall be at no cost to VCE unless previously approved in writing by VCE. To the extent VCE pursues a borrowing transaction and details of that transaction become better known, the Parties will negotiate and document a mutually acceptable fee arrangement for that borrowing transaction.

Rates
PFM Employee Title Hourly
Managing Director $375
Director $340
Senior Managing Consultant $310
Senior Analyst $275
Analyst $250
Invoices
Monthly Invoicing: In order to request payment, Consultant shall submit monthly invoices to VCE describing the services performed and the applicable charges (including a summary of the work performed during that period, personnel who performed the services, hours worked, task(s) for which work was performed). VCE shall pay all undisputed invoice amounts within thirty (30) calendar days after receipt up to the maximum compensation set forth herein. VCE does not pay interest on past due amounts.

Reimbursable Expenses
Administrative, overhead, secretarial time or overtime, word processing, photocopying, in house printing, insurance and other ordinary business expenses are included within the scope of payment for services and are not reimbursable expenses. Travel expenses must be authorized in advance in writing by VCE. In no event shall reimbursable expenses collectively exceed the total sum of sixty-five thousand dollars ($65,000).

Additional Services
Consultant shall provide additional services outside of the services identified in Exhibit A only by advance written authorization from VCE Representative prior to commencement of any additional services. Consultant shall submit, at the VCE Representative’s request, a detailed written proposal including a description of the scope of additional services, schedule, and proposed maximum 132
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compensation. Any changes mutually agreed upon by the Parties, and any increase or decrease in compensation, shall be incorporated by written amendments to this Agreement. 133
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Exhibit D
Insurance Requirements and Proof of Insurance
Consultant shall maintain the following minimum insurance coverage:

A. COVERAGE:
(1) Workers' Compensation:

Statutory coverage as required by the State of California. (2) Liability:

Commercial general liability coverage with minimum limits of $1,000,000 per occurrence and $2,000,000 aggregate for bodily injury and property damage.

ISO occurrence Form CG 0001 or equivalent is required.
(3) Automotive:

Comprehensive automotive liability coverage with minimum limits of $1,000,000 per accident for bodily injury and property damage. ISO Form CA 0001 or equivalent is required.
(4) Professional Liability
Professional liability insurance which includes coverage for the professional acts, errors and omissions of Consultant in the amount of at least $1,000,000. 134
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VALLEY CLEAN ENERGY ALLIANCE
RESOLUTION 2022-___

RESOLUTION OF THE BOARD OF DIRECTORS OF VALLEY CLEAN ENERGY ALLIANCE APPROVING

AN AGREEMENT WITH PFM FINANCIAL ADVISORS LLC FOR FINANCIAL ADVISORY SERVICES

AND AUTHORIZING THE EXECUTIVE OFFICER IN CONSULTATION WITH LEGAL COUNSEL TO

FINALIZE AND EXECUTE THE AGREEMENT
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 sections 6500 et seq., among the County of Yolo, and the Cities of Davis and Woodland, to reduce greenhouse gas emissions, provide electricity, carry out programs to reduce energy consumption, develop local jobs in renewable energy, and promote energy security and rate stability in all of the member jurisdictions. The City of Winters, located in Yolo County, was added as a member of VCE and a party to the JPA in December of 2019; and,
WHEREAS, on June 16, 2022, a Request for Proposal (RFP) was released by VCE seeking proposals from qualified Municipal Financial Advisors to provide general municipal advisory services and municipal advisory services to establish an investment-grade credit rating and support debt issuances for VCE (“financial advisory services”); and, WHEREAS, VCE staff reviewed and evaluated the RFP responses and conducted interviews; and, WHEREAS, staff recommend that VCE enter into an agreement with PFM Financial Advisors to provide financial advisory services.

NOW, THEREFORE, the Board of Directors of Valley Clean Energy Alliance resolves as follows:

1. The VCE Executive Officer, in consultation with VCE Legal General Counsel, is authorized to finalize, approve and execute on behalf of VCE the agreement with PFM Financial Advisors LLC for financial advisory services attached hereto for a not to exceed amount of $65,000 for a term of approximately three (3) years ending December 31, 2025, with two one year optional extensions.

PASSED, APPROVED AND ADOPTED, at a regular meeting of the Valley Clean Energy Alliance, held on the _____ day of _______ 2022, by the following vote:

AYES:

NOES:

ABSENT:

ABSTAIN:

Jesse Loren, VCE Board Chair
ATTEST:

Alisa M. Lembke, VCE Board Secretary
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Item 14
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 14
TO: Board of Directors
FROM: Mitch Sears, Executive Officer
Gordon Samuel, Assistant General Manager and Director of Power Resources SUBJECT: Wholesale Energy Services Update
DATE: September 8, 2022

RECOMMENDATION
Informational item. The purpose of this brief report is to give an update on the status of Wholesale Energy Services.

BACKGROUND
In October 2017, the VCE Board approved a Professional Services Agreement with Sacramento Municipal Utility District (SMUD), along with initial task orders to provide program launch and operational services. Soon thereafter, a series of additional Task Orders were added to the Agreement, including Task Order 3 to provide Wholesale Energy Services (WES). A large portion of the scope of services identified in Task Order 3 expires in mid-2023 and the remainder (primarily resource adequacy support) expires at the end of 20231. In 2024, VCE (or a 3rd party selected by VCE) will assume responsibility for all WES services. SMUD has worked with VCE to develop a transition strategy, plan and timeline to ensure continued service and success under other WES vendors.

UPDATE
Throughout 2022, VCE and SMUD have been engaged on developing a WES transition plan in order to have a seamless hand-off from SMUD to a newly selected vendor. The pool of potential vendors has been identified and staff has had informal discussions with potential vendors to gauge the vendors interest and the range of services they could provide. Staff’s intent is to issue a request for offers for a wholesale energy services provider in mid-September 2022, negotiate a contract and bring a contract for Board approval in November. Initial transition activities will commence in December.
1 SMUD will continue to provide other essential services to VCE under the overall Agreement through at least 2025 (e.g. Call Center Services, Billing/Data Services, etc.) 136
Item 15

VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 15
TO: Board of Directors
FROM: Edward Burnham, Director of Finance & Internal Operations Mitch Sears, Executive Officer
SUBJECT: Mid-Year Customer Rates Review
DATE: September 8, 2022

RECOMMENDATION
Receive Mid-Year update on 2022 Customer Rates

BACKGROUND/ANALYSIS
The Board adopted the 2022 VCE Budget and Customer Rates on February 10, 2022. The Board rates and budget priorities for 2022 are to rebuild financial reserves and provide financial relief to VCE’s low income customers. The February 2022 Board staff reports associated with adoption of the for budget and rates adoption can be found here:

Item-16-2022-Operating-Budget-2-10-22.pdf (valleycleanenergy.org) Item-15-2022-Customer-Rates-2-10-22.pdf (valleycleanenergy.org) As part of its Customer Rates action, the Board directed staff to monitor 2022 financial performance and recommend, if warranted, mid-year 2022 adjustments to customer rates/credits and/or allocation of additional financial resources for programs and renewable energy credits.

The unaudited financials ending June 30, 2022, are in general alignment with the financial projections used to structure the 2022 adopted budget. Since year-to-date financial performance is in-line with projections, staff has reached the conclusion that 2022 mid-year adjustments to customer rates (up or down) or allocation of additional financial resources for programs and renewable energy credits are not advisable.

Staff presented the mid-year financial overview at the August 25, 2022 CAC meeting and received feedback to evaluate additional possibilities to increase the RPS content. Staff will continue to evaluate and present possible solutions when identified.

CONCLUSION
Based on year-to-date financial performance in-line with projections, staff believes it is prudent to maintain the Board adopted 2022 customer rates and budget allocations for programs and renewable energy credits.
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Item 16

VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 16
TO: Board of Directors
FROM: Mitch Sears, Executive Officer
Edward Burnham, Director of Finance & Internal Operations SUBJECT: Introduction of Rate Adjustment System
DATE: September 8, 2022

RECOMMENDATION
Informational item – no action requested.

The purpose of this report is to provide an introductory presentation and seek Board feedback on a conceptual framework that would allow VCE’s rates to automatically adjust within a defined range to more timely and accurately reflect key external cost factors that are outside VCE’s control.

BACKGROUND/ANALYSIS
VCE and all other Load Serving Entities (i.e. CCA’s, Publicly Owned Utilities, and Investor Owned Utilities), face volatility in key external cost factors that are largely outside their control. For VCE, the primary factors are energy market fluctuations (up and down) and regulatory mandates. Most LSE’s have adopted rate adjustment systems that allow for rates and revenue to automatically adjust within defined parameters to keep pace with market and regulatory changes. The IOUs’ version of this approach is typically a “balancing account” that allow them to retroactively recover revenue since their rates are regulated by the CPUC making them difficult to adjust in a timely manner.

This report introduces a conceptual rate adjustment framework that would allow VCE to automatically adjust rates/revenues up or down based on parameters set by the Board.

VCE Financial Policies and Mitigation Strategies
In 2017, prior to launch, VCE adopted and registered its Implementation Plan (IP) with the California Public Utilities Commission (CPUC). The Plan included a provision that program rates must collect sufficient revenue from participating customers to fully fund VCE’s budget, including operating reserve funds. Over the past four years, VCE has analyzed policy options and implemented strategies to stabilize customer rates, reduce/control costs, and manage reserves. VCE’s key financial policies and mitigation strategies include:
• 2017 – VCE IP: Rates must collect sufficient revenue to fully fund VCE’s budget and operating reserves.
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Item 16
• 2020 – Strategic Plan: Maintain financial stability while continuing to offer customer choice, competitive pricing, and establishment of local programs. • 2018 – 2021 – Systematic analysis of policy options and implementation strategies to stabilize customer rates, reduce costs, and manage reserves:
o Discontinue rate discount; temporarily scaled back REC purchases; sign long-term renewable PPA’s • November 2021- Adopted cost-based rate policy.
• July 2022 – VCE Board adopted three-tiered customer product structure starting 2023.

Rate Adjustment System Concept
Currently, VCE sets rates annually for its default product to cover costs set competitively to PG&E’s rates, regardless of market volatility and/or changing regulatory requirements. While this current approach is reasonably simple to calculate and communicate, it requires VCE to use reserves to smooth unanticipated power market and regulatory impacts. To better address revenue variability associated with these impacts, Staff has investigated best practices of other Load Serving Entities. The most common approaches utilize automatic adjustments within predetermined guidelines triggered by movement in power markets (up or down), and/or additional costs associated with regulatory mandates (e.g. Power Charge Indifference Adjustment – PCIA).

Under this type of adjustment system, the Board would set adjustment limits (up or down), that could be triggered by power market movement and/or regulatory actions. Generally, implementing timely smaller adjustments reduces the potential for larger swings in customer rates if changes are implemented only once a year, consistent with VCE’s current practice. Such adjustments also moderate pressure on reserves by being more responsive to cash-flow needs.

It is important to note that these types of rate adjustment frameworks do not compel a rate adjustment if the context of a market price trend or regulatory decision does not require an adjustment to maintain long-term financial stability. For example, if market power costs are reacting to a temporary event such as a storm that knocks out transmission lines that might otherwise trigger consideration of a rate adjustment under adopted parameters, VCE could choose to “wait and see” if power markets either return to more normal levels. If however, an event and cost impacts persist, the system would allow for an adjustment to meet VCE’s revenue requirements and cost based rates policy. While this type of system offers flexibility to manage VCE rates more effectively, it does require informed design to achieve desired results and an appropriate delegation of responsibility.

Staff will be providing additional detail in its informational presentation at the meeting.

CONCLUSION/NEXT STEPS
Staff is seeking general Board feedback on this type of rate adjustment framework. If direction is given to continue developing this concept, Staff would draft a proposal for feedback/input by the Community Advisory Committee and return later this Fall with a draft rate adjustment system framework for further Board consideration.
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Item 17

VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 17
TO: Board of Directors
FROM: Mitch Sears, Executive Officer
Edward Burnham, Director of Finance & Internal Operations SUBJECT: VCE Three-Year Strategic Plan Update
DATE: September 8, 2022

PURPOSE
The purpose of this report is to:

1. Provide a progress update on the VCE Three-Year Strategic Plan (2021-2023); and

2. Begin the discussion with the Board on options for extending the Plan beyond the current end of the planning period (end of 2023).

BACKGROUND
The Board ratified the VCE Three-Year Strategic Plan (Plan) for 2021-2023 at the November 12, 2020, meeting. The strategic plan is the basis for developing annual organization and individual goals, annual budgets, key decisions, and priorities. The Plan incorporates the following schedule for status reporting:
• Quarterly Report to VCE Management
Staff will report quarterly to the Executive Officer on the status of goals, objectives and metrics for which they are responsible.
• Annual Report to Board and CAC
Staff will report annually to the Board and CAC on the status of goals, objectives and metrics, and will recommend any mitigations or amendments as may be necessary for Board approval.

Staff has provided progress updates to the Executive Officer, Community Advisory Committee (CAC), and Board as described above. This report provides key accomplishments as VCE reaches the midway point of the 2021-2023 strategic plan. Generally, Staff observes that progress has been made in each goal area and that the plan serves the overall intended purpose of aligning organizational activities with policy priorities.

Examples of key accomplishments in the first half of 2022 include:
• VCE maintained cash reserves and liquidity with lines of credit through the initial launch, COVID-19 pandemic, and power market volatility to optimize VCE’s financial health and competitiveness with PG&E. (Goal 1 – Financial Strength) • Adopted a cost recovery-based customer rate policy for 2022, expanded customer rate options, collections policy, and debt policy to support establishing a credit rating by 140
Item 17
2024. (Goal 1 – Financial Strength)
• 10 power purchase agreements (PPA) for reaching 85% renewable content by 2024, including 4 through California Community Power, PV plus storage, long duration storage, and geothermal technologies 238 MW Renewables, 128 MW BESS, and 7 MW Demand Response. (Goal 2 - Procurement & Power Supply)
• AgFIT pilot development and implementation designed to provide VCE agricultural customers with hourly price signals and incentives for irrigation automation and scheduling software to better manage energy costs. (Goal 3 – Customers & Community) • Maintained customer participation rate of over 90% for service territory through VCE’s launch phase and expansion to include Winters (Goal 3 – Customers & Community) • Completed portfolio analysis for 100% carbon neutral and carbon-free hour-by-hour by 2030 (Goal 4 – Decarbonization & Grid Innovation)
• Actively participated in the CPUC Summer Reliability proceeding (AgFit Pilot) and PG&E Regionalization Proceeding. Active in the recently concluded legislative session for 2022 (Goal 5 – Regulatory & Legislative Affairs)
• Recruited and retained key personnel for leadership and operational positions. (Goal 6 – Organizational, Workplace, and Technology)
• Joined California Community Power joint powers authority to optimize shared CCA platform to execute multiple PPAs to meet regulatory requirements. (Goal 6 – Organizational, Workplace, and Technology)
Additional key accomplishments will be included in the presentation.

Plan Update
The current Strategic Plan runs through the end of 2023. Staff is seeking early Board feedback on the approach for extending the strategic plan beyond the end of 2023. Staff has identified two basic options: (1) adopt a multi-year extension at the end of the current planning period (end of 2023); or (2) adopt one year “rolling” extensions each year so that the Plan is always 1+ years from expiration. The first option is a more formal/traditional approach that allows for a longer look ahead but lacks the more consistent update benefits associated with the “rolling” approach. Staff believes that either approach can serve VCE’s objectives but is leaning toward the rolling approach to maintain the Plan’s relevance in a fast-changing energy sector. Guidance from the Board at this early date will help Staff organize for the Plan update. 141

Valley Clean Energy Board of DirectorsSeptember 8, 2022

Valley Clean Energy Board of Directors
September 8, 2022