VCE 5/12/2022 Board Meeting Agenda Page 1 of 3
Regular Meeting of the Valley Clean Energy Alliance
Board of Directors
Thursday, May 12, 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/86880622688
Meeting ID: 868 8062 2688
b. By phone
One tap mobile:
+1-669-900-9128,, 86880622688# US
+1-253-215-8782,, 86880622688# US
Dial:
+1-669-900-9128 US
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Meeting ID: 868 8062 2688
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 5/12/2022 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 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 April 14, 2022 Board meeting Minutes.
5. Receive 2022 Long Range Calendar.
6. Receive Financial Updates – March 31, 2022 (unaudited) financial statements.
7. Receive Legislative update.
8. Receive May 5, 2022 Regulatory update provided by Keyes & Fox.
9. Receive Community Advisory Committee April 28, 2022 meeting summary.
10. Receive update on Customer Dividend and Programs Allocation.
11. Reaffirm participation in California Community Power Tumbleweed Project via Resolution.
REGULAR AGENDA
12. Receive update from Beth Vaughan of California Community Choice Association (CalCCA).
13. Legislative Bills update from Mark Fenstermaker of Pacific Policy Group.
14. Consider approval of VCE’s Electric Vehicle Rebates customer program.
15. Consider appointment(s) to vacant At-Large seats on Community Advisory Committee.
16. 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.
17. Adjournment: The next regular meeting is scheduled for May 12, 2022 at 5 p.m. via video/teleconference.
PUBLIC PARTICIPATION INSTRUCTIONS FOR VALLEY CLEAN ENERGY BOARD OF DIRECTORS SPECIAL MEETING ON THURSDAY, MAY 12, 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.
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.
2 VCE 5/12/2022 Board Meeting Agenda Page 3 of 3
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: May 12, 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 April 14, 2022 meeting DATE: May 12, 2022
RECOMMENDATION
Receive, review and approve the attached April 14, 2022 meeting Minutes.
6 VCEA Minutes April 14, 2022 Board Meeting via Webinar Page 1 of 4
MINUTES OF THE VALLEY CLEAN ENERGY ALLIANCE
BOARD OF DIRECTORS REGULAR MEETING
THURSDAY, APRIL 14, 2022
The Board of Directors of the Valley Clean Energy Alliance duly noticed their regular meeting scheduled for Thursday, April 14, 2022 at 5:00 p.m., to be held via Zoom webinar. Chair Jesse Loren established that there was a quorum present and began the meeting at 5:02 p.m.
Board Members Present: Jesse Loren, Tom Stallard, Dan Carson, Wade Cowan, Lucas Frerichs, Don Saylor, Mayra Vega (arrived at 5:20 p.m.)
Members Absent: Gary Sandy
Welcome Chair Loren welcomed everyone.
Public Comment –
General and
Consent
Board Clerk informed those present that there were no verbal or written public comments on general topics or on any of the Consent Agenda items.
Approval of
Consent Agenda /
Resolution 2022-
011 through
Resolution 2022-
012
Chair Loren announced that the Board Clerk has noted that a few grammatical corrections have been made to the March 10, 2022 meeting Minutes. Motion made by Vice Chair Tom Stallard to approve the Consent Agenda with grammatical corrections made to the March 10, 2022 meeting Minutes, seconded by Director Dan Carson. Motion passed with Directors Gary Sandy and Mayra Vega absent. The following items were:
3. Authorized to continue remote public meetings as authorized by Assembly Bill 361;
4. Approved March 10, 2022 Board meeting Minutes as amended;
5. Received 2022 Long Range Calendar;
6. Received February 28, 2022 (unaudited) financial statement;
7. Received Legislative update provided by Pacific Policy Group;
8. Received April 6, 2022 Regulatory update provided by Keyes & Fox;
9. Received quarterly Customer Enrollment update;
10. Received Community Advisory Committee March 24, 2022 meeting summary;
11. Approved agreement with TeMix Inc. to provide implementation support services for the AgFIT (Flexible Irrigation Technology) dynamic pricing pilot program as Resolution 2022-011;
12. Received SACOG Grant – Electrify Yolo Project update;
13. Approved updates to Valley Clean Energy’s Employee Handbook as Resolution 2022-012; and,
14. Approved process for selection of CAC At-Large seats. 7 VCEA Minutes April 14, 2022 Board Meeting via Webinar Page 2 of 4 Item 15: Received
presentation on
OhmConnect
program.
Leah Goodman, Partnerships & Business Development Manager of OhmConnect, provided a presentation summarizing the VCE-OhmConnect program. The OhmConnect program is free and subsidizes smart home devices to improve energy efficiency. This program will be launched next week, with a secondary campaign in May.
Director Mayra Vega arrived at 5:20 p.m.
The Board asked questions and Ms. Goodman stated that the program is designed for residential customers, not businesses and the success rate of the 2021 program campaign was that 40% had installed a smart device, out of the approximately 300 who responded. There were no verbal or written public comments.
Item 16: Approve
participation in and
authorize VCE
Executive Officer to
execute documents
associated with
VCE participating in
the CC Power long
duration storage
project. Resolution
2022-013
VCE Staff Gordon Samuel summarized the California Community Power (CC Power) Goal Line project by reviewing slides. Mr. Samuels informed the Board that this project is the second CC Power long duration storage project being presented to the Board, which is designed to meet procurement goals, California Public Utilities Commission (CPUC) reliability procurement order requirements, and VCE’s renewable energy goals. VCE’s Strategic Plan and carbon neutral study work outlines VCE’s goal to exceed California’s Renewable Portfolio Standard (RPS) while working toward a resource portfolio that is 100% carbon neutral by 2030. This project follows the carbon neutral study and exceeds the CPUC’s requirements. Mr. Samuel informed the Board that the proposed CC Power Goal Line project was presented to the Community Advisory Committee (CAC) at their March 24, 2022 meeting and the CAC recommended that VCE participate in this long duration storage project. There were no verbal or written public comments.
Motion made by Director Lucas Frerichs to:
1) Authorize via Resolution 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 Goal Line long duration storage project with a delivery term of 15 years starting at the commercial operation date on or about June 1, 2025:
a. Project Participation Share Agreement between Valley Clean Energy, California Community Power and other participating CCAs.
b. Energy Storage Service Agreement (ESSA) - Buyer Liability Pass Through Agreement (BLPTA) between Valley Clean Energy,
California Community Power and Goal Line BESS 1, LLC.
8 VCEA Minutes April 14, 2022 Board Meeting via Webinar Page 3 of 4 Motion seconded by Director Vega. Motion passed as Resolution 2022-013 by the following vote:
AYES: Loren, Stallard, Saylor, Carson, Cowan, Frerichs, Vega NOES: None
ABSENT: Sandy
ABSTAIN: None
Item 17: Receive
and accept audited
financial
statements for the
period of July 1,
2021 to December
31, 2021 presented
by James Marta &
Company.
Mr. James Marta of James Marta & Company, presented highlights of their audit of VCE’s financials covering the time period of July 1, 2021 through December 31, 2021. A brief discussion occurred. There were no verbal or written public comments.
Motion made by Director Carson to:
1. Accept and approve the Audited Financial Statements for the period of July 1, 2021, to December 31, 2021;
2. Accept the Communication with Governance Letter; and
3. Accept the Internal Control Letter
Motion seconded by Director Don Saylor. Motion passed by the following vote:
AYES: Loren, Stallard, Saylor, Carson, Cowan, Frerichs, Vega NOES: None
ABSENT: Sandy
ABSTAIN: None
Item 18: Board
Member and Staff
Announcements
There were no comments or announcements from the Board.
Executive Officer Mitch Sears informed those present that Staff continue to work on the AgFIT program with a May 1st target state date. Conversations with the CPUC, vendors and farmers continue with a few farmers enrolled in the program.
Staff are doing an analysis of the effects of the drought on energy within the agriculture sector and their challenges. Mr. Sears informed those present that VCE was featured in Yolo County Climate Action Committee’s comments to the Yolo County Board of Supervisors on jurisdictions opting up non-solar accounts to VCE’s UltraGreen and to work together to engage communities in other energy efficiency programs.
He announced that the Time of Use (TOU) transition for residential customers continues to be underway. VCE’s Customer Service Team (CST) has not seen an increase in phone calls regarding the TOU transition. The CST have the tools they need to answer questions and assist customers.
Mr. Sears informed those present that the Department of Commerce received an anti-dumping circumvention case related to solar panels. Staff are continuing to monitor to see if there are any impacts to our projects. 9 VCEA Minutes April 14, 2022 Board Meeting via Webinar Page 4 of 4 He announced that VCE now has an Instagram account in addition to our other social media outlets. There are two (2) events coming up that VCE will be participating in: California Honey Festival in Woodland on Saturday, May 7th and Celebrate Davis in early June. He invited Board and CAC Members to come out to these events.
Director Saylor mentioned that Yolo Climate Compact is meeting on Friday, April 22 at 10 a.m. The featured program is on drought issues and how the Yolo Flood Control Irrigation District and the City of Woodland have taken steps to address the drought. Woodland’s groundwater recharge program will be featured and a discussion on how these issues are being managed. Chair Loren informed those present that the Sustainable Groundwater Management Agency has a subcommittee that is addressing drought. Attending some of these meetings by Staff might be informative and useful.
Chair Loren announced that the Board’s next regular meeting is scheduled for Thursday, May 12, 2022 at 5 p.m.
Adjournment Chair Loren adjourned the regular Board meeting at 5:59 p.m.
Alisa M. Lembke
VCEA Board Secretary
10 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: May 12, 2022
Recommendation
Receive and file the 2022 Board and Community Advisory Committee long-range calendar listing proposed meeting topics.
11 4/27/22
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
12 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 • Re/Appointment of Members to Community Advisory Committee (Annual)
• Extension of Waiver of Opt-Out Fees for one year (Annual) • Update 3-Year Programs Plan
• Draft Rate Structure
• Action
• Action
• Information
• Information/Discussion
June 23, 2022 Advisory
Committee
• Draft Rate Structure
• Update 3-Year Programs Plan
• Discussion/Action
• Information/Discussion
July 14, 2022 Board • Update on SACOG Grant – Electrify Yolo • Net Energy Metering (NEM) 3.0 Update (placeholder)
• Draft Rate Structure
• Information
• Information
• Discussion/Action
13 July 28, 2022 Advisory
Committee
• Power Procurement / Renewable Portfolio Standard update •
• Information
•
August 11, 2022 Board • •
August 25, 2022 Advisory
Committee
• 2022 Operating Budget / Renewable Portfolio Standard update • Mid-year rate update
•
• Information
September 8, 2022 Board • 2022 Operating Budget / Renewable Portfolio Standard update • Certification of Standard and UltraGreen Products (Annual) • Enterprise Risk Management Report (Bi-Annual)
• Mid-year 2022 rates review
• Information
• Action
• Information
• Information/Discussion
September 22, 2022 Advisory
Committee
• Legislative End of Session Update
• 2023 Draft Operating Budget
• Mid-year 2022 rates review
• Information
• Information
• Information
October 13, 2022 Board • Update on SACOG Grant – Electrify Yolo • Update on 2023 draft Operating Budget
• Information
• Information
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
• Information
• Information/Discussion
• Information/Discussion
November 10, 2022 Board • Certification of Power Content Label (Annual) • Preliminary 2023 customer rate options
• Preliminary 2023 Operating Budget (Annual)
• Action
• Information/Discussion
• Information
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 • Review CAC Charge (Annual)
• ERRA Filings Update (PCIA and bundled rates) (Annual) • Preliminary 2023 customer rate options
• Discussion/Action
• Information
• Information
• Information
• Discussion
• Information
• 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) • Action
• Action
• Information
• Action
14 • GHG Free attributes
• Update on SACOG Grant – Electrify Yolo
• Receive CAC 2022 Calendar Year End Report (Annual)
• Election of Officers for 2023 (Annual)
• 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)
• Action
• Information
• Action
• Action
• Action
January 26, 2023 Advisory
Committee
• •
Notes: 1. CalCCA Annual Meeting typically scheduled in November.
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) TBD Carbon Neutral by 2030 (types of energy, where procured, BTM, FOM, policy) (Discussion/Action) 2022 Quarter 3 Integrated Resource Plan / Public Workshop (IRP – update due 11/1/2022) (Discussion/Action) August/September 2022 Self Generation Incentive Program (SGIP) TBD
CAC Charge revision (as needed)
Legislative Items (as needed)
Strategic Plan additional updates (as needed)
Time of Use (TOU) (as needed)
SACOG Update (as needed)
15 Item 6
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 6
______________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Executive Officer
Edward Burnham, Finance and Operations Director
SUBJECT: Financial Update – March 31, 2022 (unaudited) financial statements (with comparative year to date information) and Actual vs. Budget year to date ending March 31, 2022
DATE: May 12, 2022
RECOMMENDATION:
Accept the following Financial Statements (unaudited) for the period of March 1, 2022 to March 31, 2022 (with comparative year to date information) and Actual vs. Budget year to date ending March 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.
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 March 31, 2022.
Financial Statements for the period March 1, 2022 – March 31, 2022 In the Statement of Net Position, VCEA, as of March 31, 2021, has a total of $5,431,356 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 $1,041 restricted assets for the Power Purchases Reserve account. VCE has incurred obligations from Member agencies and owes as of March 31, 2021, $61,261 VCE member obligations are incurred monthly due to staffing, accounting, and legal services.
16 Item 6
The term loan with River City Bank includes a current portion of $1,087,139. On March 31, 2022, VCE’s net position is $5,943,846.
In the Statement of Revenues, Expenditures, and Changes in Net Position, VCEA recorded $3,560,481 of revenue (net of allowance for doubtful accounts), of which $3,702,319 was billed in March, and $1,338,089 represent estimated unbilled revenue. The cost of the electricity for the March revenue totaled $4,099,897. For March, VCEA’s gross margin was approximate -15% and net loss totaled ($ 964,688). The year-to-date change in net position was ($4,067,775).
In the Statement of Cash Flows, VCEA cash flows from operations were ($913,783) due to March cash receipts of revenues being less than the monthly cash operating expenses.
Actual vs. Budget Variances for the year to date ending March 31, 2022 Below are the financial statement line items with variances >$50,000 and 5% • Electric Revenue - $1,101,485 and 10% – unfavorable variance is due to load being lessfavorable than planned, and the weather has been warmer than forecast during the winter months. • Purchased Power – ($1,186,219) and -8% – favorable variance is due to load being more favorable than planned, weather has been warmer than forecast, and lower power market prices during winter months.
Attachments:
1) Financial Statements (Unaudited) March 1, 2022 to March 31, 2022 (with comparative year to date information.)
2) Actual vs. Budget for the year to date ending March 31, 2022 17 VALLEY CLEAN ENERGY ALLIANCE
FINANCIAL STATEMENTS
(UNAUDITED)
FOR THE PERIOD OF MARCH 1 TO MARCH 31, 2022
PREPARED ON MAY 5, 2022
18 2
ASSETS
Current assets:
Cash and cash equivalents $ 5,431,356
Accounts receivable, net of allowance 6,279,240
Accrued revenue 1,338,089
Prepaid expenses 10,918
Other current assets and deposits 1,998,276
Total current assets 15,057,879
Restricted assets:
Debt service reserve fund 1,100,000
Power purchase reserve fund 1,041
Total restricted assets 1,101,041
TOTAL ASSETS $ 16,158,920
LIABILITIES
Current liabilities:
Accounts payable $ 406,697
Accrued payroll 66,551
Interest payable 2,482
Due to member agencies 61,261
Accrued cost of electricity 3,505,096
Other accrued liabilities (4,082)
Security deposits - energy supplies 1,980,000
User taxes and energy surcharges 109,930
Limited Term Loan 1,087,139
Loan - County of Yolo 3,000,000
Total current liabilities 10,215,074
Total noncurrent liabilities -
TOTAL LIABILITIES $ 10,215,074
NET POSITION
Restricted
Local Programs Reserve 224,500
Restricted 1,101,041
Unrestricted 4,618,305
TOTAL NET POSITION $ 5,943,846
(UNAUDITED)
VALLEY CLEAN ENERGY ALLIANCE
STATEMENT OF NET POSITION
MARCH 31, 2022
19 3
FOR THE PERIOD
ENDING
March 31, 2022 YEAR TO DATE
OPERATING REVENUE
Electricity sales, net $ 3,560,481 $ 9,914,315
TOTAL OPERATING REVENUES 3,560,481 9,914,315
OPERATING EXPENSES
Cost of electricity 4,099,897 12,834,381
Contract services 226,357 594,851
Staff compensation 102,302 293,783
General, administration, and other 94,169 252,383
TOTAL OPERATING EXPENSES 4,522,725 13,975,398
TOTAL OPERATING INCOME (LOSS) (962,244) (4,061,083)
NONOPERATING REVENUES (EXPENSES)
Other Revenue
Interest income 888 3,203
Interest and related expenses (3,332) (9,895)
TOTAL NONOPERATING REVENUES
(EXPENSES) (2,444) (6,692)
CHANGE IN NET POSITION (964,688) (4,067,775)
Net position at beginning of period 6,908,534 9,749,097 Net position at end of period $ 5,943,846 $ 5,681,322
VALLEY CLEAN ENERGY ALLIANCE
STATEMENT OF REVENUES, EXPENDITURES AND
(UNAUDITED)
CHANGES IN NET POSITION
FOR THE PERIOD OF MARCH 1, 2022 TO MARCH 31, 2022
(WITH COMPARATIVE YEAR TO DATE INFORMATION)
20 4
FOR THE
PERIOD ENDING
MARCH 31, 2022 YEAR TO DATE
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from electricity sales $ 3,483,313 $ 11,364,491 Payments to purchase electricity (3,958,765) (14,577,259) Payments for contract services, general, and adminstration (338,125) (441,978) Payments for staff compensation (100,206) (291,141)
Net cash provided (used) by operating activities (913,783) (3,945,887)
CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES
Principal payments of Debt 2,967,057 2,934,113
Interest and related expenses (3,110) (10,199)
Net cash provided (used) by non-capital financing
activities 2,963,947 2,923,914
CASH FLOWS FROM INVESTING ACTIVITIES
Interest income 888 3,203
Net cash provided (used) by investing activities 888 3,203 NET CHANGE IN CASH AND CASH EQUIVALENTS 2,051,052 (1,018,770) Cash and cash equivalents at beginning of period 4,481,345 4,481,345 Cash and cash equivalents at end of period $ 6,532,397 $ 6,088,653 Cash and cash equivalents included in:
Cash and cash equivalents 5,431,356 5,431,356
Restricted assets 1,101,041 1,101,041
Cash and cash equivalents at end of period $ 6,532,397 $ 6,532,397
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
FOR THE PERIOD OF MARCH 1 TO MARCH 31, 2022
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
21 5
FOR THE
PERIOD ENDING
MARCH 31, 2022 YEAR TO DATE
Operating Income (Loss) $ (962,244) $ (4,061,083)
(Increase) decrease in net accounts receivable (453,156.00) 1,028,604.59 (Increase) decrease in accrued revenue 360,120 430,104.26 (Increase) decrease in prepaid expenses 10,325 874,312.00 Increase (decrease) in accounts payable (6,079) (38,045.00) Increase (decrease) in accrued payroll 2,096 2,642.00
Increase (decrease) in due to member agencies (98,611) (56,684.00) Increase (decrease) in accrued cost of electricity 141,132 (1,827,073.00) Increase (decrease) in other accrued liabilities 76,766 (289,832.00) Increase (decrease) in user taxes and energy surcharges 15,868 (8,832.90) Net cash provided (used) by operating activities $ (913,783) $ (3,945,887)
RECONCILIATION OF OPERATING INCOME TO NET
CASH PROVIDED (USED) BY OPERATING ACTIVITIES
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
FOR THE PERIOD OF MARCH 1 TO MARCH 31, 2022
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
22 VALLEY CLEAN ENERGY
2022 YTD ACTUAL VS. BUDGET
FOR THE YEAR TO DATE ENDING 03/31/22
Description YTD
Actuals
YTD
Budget
YTD
Variance
%
over/-under
Electric Revenue $ 9,914,315 $ 11,015,800 $ (1,101,485) -10% Interest Revenues $ 3,528 $ 4,500 $ (972) -22%
Purchased Power $ 12,834,381 $ 14,020,600 $ (1,186,219) -8% Purchased Power Base $ 12,834,381 $ 12,595,400 $ 238,981 2% Purchased Power Contingency 2% $ - $ 1,425,200 $ (1,425,200) -100% Labor & Benefits $ 294,780 $ 329,700 $ (34,920) -11%
Salaries & Wages/Benefits $ 242,835 $ 272,400 $ (29,565) -11% Contract Labor (SMUD Staff Aug) $ - $ 14,700 $ (14,700) -100% Human Resources & Payroll $ 51,945 $ 42,600 $ 9,345 22% Office Supplies & Other Expenses $ 69,186 $ 49,200 $ 19,986 41% Technology Costs $ 9,930 $ 8,700 $ 1,230 14%
Office Supplies $ 4,021 $ 600 $ 3,421 570%
Travel $ - $ 1,500 $ (1,500) -100%
CalCCA Dues $ 27,345 $ 31,800 $ (4,455) -14%
CC Power $ 26,891 $ 6,000 $ 20,891 348%
Memberships $ 1,000 $ 600 $ 400 67%
Contractual Services $ 554,237 $ 625,500 $ (71,263) -11% Other Contract Services $ - $ 6,300 $ (6,300) -100%
Don Dame $ 1,052 $ 2,400 $ (1,348) -56%
SMUD - Credit Support $ 117,711 $ 127,000 $ (9,289) -7% SMUD - Wholesale Energy Services $ 146,961 $ 146,400 $ 561 0% SMUD - Call Center $ 196,764 $ 197,600 $ (836) 0%
SMUD - Operating Services $ 5,634 $ 15,000 $ (9,366) -62% Commercial Legal Support $ - $ - $ - 100%
Legal General Counsel $ 28,490 $ 38,700 $ (10,210) -26% Regulatory Counsel $ 12,510 $ 49,800 $ (37,290) -75%
Joint CCA Regulatory counsel $ 13,562 $ 8,100 $ 5,462 67% Legislative - (Lobbyist) $ 15,000 $ 15,000 $ - 0%
Accounting Services $ 3,252 $ 6,600 $ (3,348) -51%
Financial Consultant $ - $ 6,300 $ (6,300) -100%
Audit Fees $ 13,300 $ 6,300 $ 7,000 111%
Marketing $ 47,012 $ 61,500 $ (14,488) -24%
Marketing Collateral $ 47,012 $ 60,000 $ (12,988) -22%
Community Engagement Activities & Sponsorships $ - $ 1,500 $ (1,500) -100% Programs $ 76,870 $ 43,500 $ 33,370 77%
Program Costs $ 76,870 $ 43,500 $ 33,370 77%
Rents & Leases $ 6,400 $ 5,400 $ 1,000 19%
Hunt Boyer Mansion $ 6,400 $ 5,400 $ 1,000 19%
Other A&G $ 92,805 $ 91,400 $ 1,405 2%
Development - New Members $ - $ 6,300 $ (6,300) -100%
Strategic Plan Implementation $ (90) $ 6,300 $ (6,390) -101% PG&E Data Fees $ 87,165 $ 69,000 $ 18,165 26%
Insurance $ 3,530 $ 2,100 $ 1,430 68%
Banking Fees $ 2,200 $ 7,700 $ (5,500) -71%
Miscellaneous Operating Expenses $ 51 $ 600 $ 600 100%
Contingency $ - $ 20,000 $ 20,000 100%
TOTAL OPERATING EXPENSES 13,975,723 $ 15,247,400 $ (1,230,528) $ -8% Interest on RCB loan $ 9,895 $ 9,600 $ 295 3%
Interest Expense - Bridge Loan $ - $ - $ - 100%
NET INCOME (4,067,775) $ (4,236,700) $ 127,776 $ -3%
23 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: May 12, 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:
Climate change is challenging the old adage that April showers bring May flowers, as there was little rain during the month and flowers seem to bloom earlier and earlier each year as temperatures warm. But the saying is seemingly holding true for the state’s budget process as reporting on tax revenue collected during April is likely to blossom into a $60 billion plus surplus. Governor Newsom had initially proposed allocations for a $20 billion surplus, how he and his Administration plan to spend these additional revenues will become clearer when he releases his May Revision to the budget in the middle of the month. The Senate is not waiting for the May Revision, however, as Senate Pro Tem Atkins released a proposal of its own, dubbed “Putting California’s Wealth to Work.” The proposal includes $18 billion to address climate change, mostly focused on funding for drought response and wildfire mitigation. The Legislature is required to propose its budget by June 15, and the Governor is to adopt a final budget by June 30 to direct the new fiscal year starting July 1. Despite these obligations, the Legislature and Governor negotiated the FY 21-22 budget until the end of session and a similar process is anticipated this year. The Legislature and Governor will put a FY-22-23 budget in place by June 30 but continue to negotiate billions of dollars well past the deadline and then amend the budget in subsequent budget bills.
While the budget steps into the spotlight in May, activity on legislation will continue in high gear during the month. Bills must pass the Appropriations committee by May 20, a step in the process that usually brings the first culling of legislation. It’s a quick turnaround from there as bills must pass the Floor of the house in which the bill originated by May 27. Legislative priorities will have more of a focus by the time May turns to June. One priority that has emerged in the Senate is the electricity sector. Senator John Laird (Santa Cruz) is the lead author of SB 1020, along with Senate Pro Tem Atkins and more than 10 other Senate authors and co-authors, the bill was announced as a collective effort by the Senate’s climate working group.
24 Item 7
2 SB 1020 proposes several significant policies: 1. codifying interim carbon-free electricity targets for load-serving entities of 90% by 2035 and 95% by 2040, 2. electricity procured to serve state agencies shall be 100% carbon free by 2030, and 3. creation of a new Climate and Equity Trust to be administered by the California Affordable Decarbonization Authority (Authority). The newly created Trust would be eligible to receive funds from multiple sources, including the state’s General Fund, the Greenhouse Gas Reduction Fund, CPUC, CEC, or CARB assessed penalties, and federal funding. The newly created Authority would distribute funding pursuant to Authority created plans approved by the CPUC to IOUs, CCAs, and end-use customers of retail sellers (a similar construct is proposed for funding to POUs with oversight provided by the CEC). Funding can be used to provide direct credits on ratepayer bills, direct rebates or incentives, or reimbursement of eligible costs. Eligible costs would cover those activities currently funded by rates, including but not limited to, transportation electrification programs and incentives, building electrification, energy efficiency, wildfire mitigation activities, distributed energy resource incentives, and more. The Assembly and the Governor will surely have input on this proposal as it moves forward.
VCE’s current legislative efforts have concentrated on the following bills:
1. AB 1814 (Grayson) Transportation Electrification Funds: Community Choice Aggregators Summary: AB 1814 would authorize Community Choice Aggregators (CCAs) to submit applications to the California Public Utilities Commission (CPUC) to receive funding to administer transportation electrification programs in their service areas.
Specifically, this bill would explicitly authorize CCAs to file applications for programs and investments to accelerate widespread transportation electrification. In order to submit these applications, CCAs would be regulated to meet all of the same requirements that IOUs are currently required to meet.
This is CalCCA’s sponsored bill for the 2022 legislative session. The bill is consistent with the VCE Legislative Platform, specifically Provision 10 regarding Local Economic Development and Environmental Objectives.
Facing opposition from the California Coalition of Utility Employees and all three investor-owned utilities,he author pulled the bill before its scheduled hearing in Assembly Utilities & Energy and was never rescheduled. AB 1814 is now dead for the 2022 session Additional Information:
• This bill is sponsored by CalCCA
• VCE has submitted a support position
• Next Hearing; None
• Bill language: AB 1814
2. 1287 (Bradford) CCA and ESP Financial Security Requirements 25 Item 7
3 Summary: This bill would require the posted bond amount, or demonstrated insurance amount, at the time of registration by an electric service provider or a community choice aggregator to be no less than $500,000. The bill would also require the commission to update the financial security requirements for electric service providers and community choice aggregators to instead include costs for no less than 12 months of incremental procurement incurred by the provider of last resort, upon the customers’ involuntary return.
Specifically, the bill will:
1) Amend current law that requires a CCA or ESP to post a bond or demonstrate insurance sufficient to cover the reentry fees of customers who are involuntarily returned to an investor-owned utility to instead require a minimum bond or insurance in the amount of $500,000.
2) In calculating the insurance or bonding requirement, the PUC shall include costs for no less than 12 months of incremental procurement incurred by the provider of last resort.
SB 1287 will significantly increase the amount of insurance that VCE will need to hold to cover the unlikely event that VCE folds and its customers are involuntarily returned to PG&E. The $500,000 minimum figure and the requirement that the insurance amount include incremental procurement made by the IOU does not factor in already contracted energy for VCE’s customers. In addition, calculating the incremental procurement will be incredibly complex and challenging and will contribute to additional unnecessary cost to VCE, similar to PCIA. Lastly, this requirement will create another obstacle for communities who wish to go CCA and will all but kill any new CCAs from forming.
The bill was referred to the Senate Energy, Utilities & Communications Committee but was never heard by the committee. Accordingly, SB 1287 is dead for the remainder of the 2022 legislative session.
Additional Information
• Next hearing: None.
• The VCE Board approved an “oppose” position and staff is working on letter to register this position with the committee.
• Bill language: SB 1287
3. SB 881 (Min) Integrated Resource Plans
Summary: Requires load-serving entities to procure, in combination with other LSEs, to achieve a diverse, balanced, and reliable portfolio that realizes the GHG emission reductions set by the CA Air Resources Board’s scoping plan process. This procurement is to be planned out through the IRP, meaning that each LSE is to make procurement decisions based on the IRP approved b by the CPUC. The bill authorizes the CPUC to assess penalties or require additional procurement of an LSE who fails to meet its procurement obligations in its IRP. The additional procurement may be undertaken by an IOU with costs associated to the deficient LSE. 26 Item 7
4 SB 881 poses a number of challenges for VCE and other CCAs in that it transforms the IRP from a process of envisioning what may be possible to a plan that must be followed. Moreover, the plan that is to be followed is to achieve an undefined GHG emission reduction goal on an undefined timetable. Lastly, the providing the CPUC with authorization to order procurement be undertaken by VCE or procurement undertaken by PG&E to be paid by VCE customers cuts against one of the foundational tenets of CCAs, procurement autonomy.
CalCCA has engaged in a series of negotiations with the author and his staff, as well as the sponsor of the bill (Union of Concerned Scientists) to no avail. CalCCA has provided amendments that would satisfy CCA concerns but those proposed amendments have been rejected.
CalCCA took an oppose unless amended position, as did VCE and other CCAs, when the bill was heard in Senate Energy, Utilities, & Commerce Committee. Many committee members, including Senator Dodd, voiced their concerns with the bill and while they voted to allow it to pass the committee did comment that they may not vote for the bill again when it is presented on the Senate Floor.
Opposing SB 881 is consistent with Provision 1a of the VCE Legislative Platform to oppose legislation that limits local the local decision-making authority of CCAs.
Additional Information
• Next Hearing: The bill has been referred to the Senate Appropriations Committee and is awaiting a hearing.
• VCE has taken an Oppose Unless Amended position consistent with CalCCA’s position • Bill language: SB 881
27 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: May 12, 2022
______________________________________________________________________________ Please find attached Keyes & Fox’s April 2022 Regulatory Memorandum dated May 5, 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 May 5, 2022. 28 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: May 5, 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:
• Ensuring Summer 2021 Reliability: PG&E submitted supplemental AL 6495-E-A on April 7. The CPUC Energy Division issued nonstandard disposition letters approving VCE’s & PG&E’s Advice Letters regarding VCE’s agricultural irrigation pumping dynamic rates pilot (Pilot), which clarified the rate design and customer billing mechanisms, provided options for VCE’s recovery of administrative costs within the existing Pilot budget, established a process for review and payment of VCE invoices, and determined reporting requirements of VCE and PG&E. The Commission issued a Proposed Decision approving VCE and its vendors’ Petition for Modification (PFM) requesting an increase to the Pilot budget to cover VCE’s administrative expenses. • IRP Rulemaking: The process for LSEs to develop final load forecasts was issued in an April 20 Ruling. The final load forecasts will serve as the basis for 2022 IRPs, resource procurement requirements, RPS Plans, and GHG emission reduction targets. • RPS Rulemaking: On April 6, Assigned Commissioner Rechtschaffen issued a Ruling amending the scope of the proceeding to consider REC classification and the timing and approval process for Voluntary Allocation contracts. Rulings issued on April 11 and April 21 provided requirements for 2022 RPS Plans and updated the procedural schedule. An April 18 Ruling requested comments from the parties on questions related to Voluntary Allocation, REC classification, and scheduling. The Joint IOUs filed their proposed Market Offer process on May 2. • PCIA Rulemaking: An April 18 Ruling requested comments on the impact of voluntarily allocating renewable energy credits to CCAs on the calculation of Market Price Benchmarks (MPB) for the Power Charge Indifference Adjustment (PCIA). In addition, the Ruling directed the joint IOUs and other parties to file a proposal to revise the inputs to the Energy Index MPB 29 2
calculation by May 27 and set forth a related procedural schedule. The MPBs are a key input to the PCIA. CalCCA submitted comments in support of Staff’s proposal on April 29. • PG&E 2021 ERRA Compliance: CalCCA and two other parties filed Protests in response to PG&E’s 2021 ERRA Compliance application (filed February 28), and the parties proposed a new schedule on April 18. This case will audit the actual costs and revenues recorded during 2021 that make up the Power Charge Indifference Adjustment.
• PG&E Phase 2 GRC: PG&E filed a Motion for Evidentiary Hearing on April 22 to address issues raised by the one party responding to its non-NEM export compensation proposal for BEV (filed March 24), and a prehearing status conference is set for May 10. • PG&E Phase 1 GRC: The ALJ issued an email Ruling on April 12 that 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. PG&E filed an Application on April 20 to modify its 2023 cost of capital that requests an overall rate of return of 7.78% and a $69.3 million increase in its revenue requirement.
• RA Rulemaking (2023-2024): On April 29, the CAISO filed its Final Local Capacity Requirements Report, and the Final Flexible Capacity Requirements Report is delayed until mid-May 2022. • PG&E Regionalization Plan: On April 18, the ALJ filed a Proposed Decision approving the multi-party settlement agreement, which generally approves PG&E’s regionalization plan with only a few changes.
• Provider of Last Resort Rulemaking: Comments on the March 7 workshop to discuss the proposed framework for considering the issues and recommendations resulting from the previous Phase 1 workshop were filed April 15.
• PG&E 2020 ERRA Compliance: On April 27, the CPUC issued a Final Decision approving the Settlement Agreement, approving all uncontested requests in PG&E’s Application, and concluding Phase 1. Phase 2 of the proceeding, which remains open, will address issues related to unrealized sales and revenues resulting from PG&E’s Public Safety Power Shutoff events in 2020.
• PG&E 2019 ERRA Compliance: On April 6, the ALJ issued a Ruling requesting supplemental testimony from the IOUs and amending the procedural schedule. The Joint CCAs filed rebuttal testimony contradicting a calculation in the IOUs’ testimony. This case addresses the degree to which the IOUs should be able to recover lost revenues due to Public Safety Power Shutoff events.
• Utility Safety Culture Assessments: On April 28, the ALJ issued a Scoping Ruling that indicated the proceeding will be divided into more than one phase and determined the scope and schedule for Phase 1. Phase 1 will focus on developing safety culture assessments for the large investor-owned electric and natural gas corporations. Phase 2 will focus on developing safety culture assessments for the small multi-jurisdiction utilities and the gas storage operators. • RA Rulemaking (2021-2022): The CPUC issued D.22-04-043 on April 27 denying OhmConnect’s September 2021 PFM and closing the rulemaking. 30 3
• PG&E 2022 ERRA Forecast: On April 27, PG&E’s request for an extension from May 15 to May 31 to file its 2023 ERRA Forecast was granted.
• RA Rulemaking (2019-2020): No updates this month.
• 2022-2023 Wildfire Fund Nonbypassable Charge Rulemaking: No updates this month. • Investigation into PG&E’s Organization, Culture and Governance: No updates this month. • Direct Access Rulemaking: No updates this month.
Ensuring Summer 2021 Reliability
PG&E submitted supplemental AL 6495-E-A on April 7. The Energy Division approved VCE’s & PG&E’s Advice Letters for the Pilot on April 11 and April 26, respectively, clarifying the rate design and customer billing mechanisms and options for VCE’s recovery of administrative costs within the existing budget, establishing a process for review and payment of VCE invoices, and determining reporting requirements of VCE and PG&E. The CPUC issued a Proposed Decision increasing the Pilot budget to cover VCE’s administrative expenses.
Background: CAISO experienced rolling blackouts (Stage 3 Emergency) on August 14, 2020, and August 15, 2020, when a heatwave struck the Western U.S. and there was insufficient available supply to meet high demand. The OIR was issued to ensure reliable electric service in the event that an extreme heat storm occurs in the summer of 2021.
D.21-03-056 instituted modifications to the planning reserve margin (PRM), effectively increasing the PRM beginning summer 2021 from 15% to 17.5%. For 2021, this results in a minimum target of incremental procurement of 450 MW for PG&E, 450 MW for SCE, and 100 MW for SDG&E. The net costs associated with this incremental procurement would be shared by all customers (including CCA customers) in each IOU’s service territory. It also authorized the IOUs to implement a Flex Alert paid media campaign program to encourage ratepayers to voluntarily reduce demand during moments of a stressed grid, adopts modifications and expansions to the Critical Peak Pricing (CPP) program, and established an emergency load reduction program.
D.21-12-015 approved VCE’s dynamic rate Pilot for three years (2022-2024) and directed that it start no later than May 1. VCE’s Pilot will test whether agricultural irrigation pumping customers, which consume on average 18% of VCE’s total annual load, can shift load to more optimal times of the day, thereby saving money, reducing the burden to the grid and reducing GHG impacts. Customers participating in VCE’s Pilot will receive a “shadow bill.” PG&E will continue to bill participating customers based on existing tariffs, but the shadow bill will show the customer savings under the Pilot dynamic rate, and VCE will pay customers for the difference between the shadow bill and the customer’s usage under the otherwise applicable tariff. The Pilot scale will be limited to 5 MW of peak load. PG&E will provide funds to or reimburse VCE for crediting any savings realized by the customers with respect to the delivery component of the VCE dynamic rate Pilot in the customers’ shadow bills. D.21-12-015 authorized new funding of $3.25 million for the pumping automation technology, pricing platform and vendor fees and PG&E’s administration of the three-year Pilot.
On January 5, VCE submitted Advice Letter 11-E in accordance with D.21-12-015. On January 25, PG&E protested VCE’s Advice Letter, to which VCE replied on January 31.
On January 31, VCE, TeMix Inc., and Polaris Energy Services (collectively, the Pilot Partners) filed a Petition for Modification (PFM) of D.21-12-015 to increase the budget for this Pilot to cover VCE’s administrative costs, and the Pilot Partners also filed a Motion to Shorten Time for comments on the PFM as well as on the Commission’s proposed decision resolving the PFM. PAO filed a Response to 31 4
the Pilot Partners’ Motion to Shorten Time, on February 9, to which the Pilot Partners replied on February 18.
On February 4, PG&E submitted Advice Letter 6495-E, which the Pilot Partners Protested on February 24. The Pilot Partners objected to PG&E’s proposed pricing methodology, PG&E’s attempt to establish various participation rules for the Pilot, and other issues. PG&E replied to the Pilot Partners’ Protest on March 3.
On March 14, the Pilot Partners filed a Reply to the March 2 Responses of PG&E and the PAO to the PFM, requesting the Commission to direct PG&E to release at least $1,197,118 in previously authorized funding to enable the Pilot to launch by May 1 and authorization of VCE’s administrative costs, including DRET reporting, if required, and asserting a narrower role for PG&E in the Pilot administration.
D.21-12-015 also created an additional procurement mandate of 2,000 MW-3,000 MW for 2023, allocated exclusively to the three large IOUs (900 MW-1,350 MW each for PG&E and SCE, and 200 MW-300 MW for SDG&E). It required all incremental resources procured as a result of this proceeding to be available during the net peak. It adopted numerous additional demand-side and supply-side changes aimed at ensuring sufficient resource availability to meet the summer net peak load.
Details: VCE’s AL 11-E was approved by the Energy Division on April 11. 1 The disposition approved
the required elements of the Advice Letter, including the Pilot generation rate design and shadow bill process. The Energy Division also clarified that certain VCE administrative expenses may be recovered from existing Pilot budget categories, provided mechanisms for reviewing and funding VCE’s administrative expenses related to the Pilot, stated that PG&E need not hold a competitive solicitation for the Pilot independent evaluator, and established limited reporting requirements.
PG&E submitted supplemental AL 6495-E-A on April 7, revising the distribution rate design to conform to the UNIDE framework. The Energy Division’s disposition, issued on April 26, approved AL 6495-E, as supplemented by AL 6495-E-A with respect to the delivery component of the Pilot rate and pricing design and PG&E’s administrative budget for the Pilot. The Energy Division disapproved the elements of PG&E’s Advice Letter regarding customer eligibility, the application of Rule 12 and load cap tracking as well as the Public Advocates Office’s request for additional details as outside the scope of D.21-12-015.
The Proposed Decision (issued April 29) would grant the Pilot Partners’ request for an increase to the Pilot budget to cover VCE’s administrative expenses for the Pilot in the amount of $690,000. The Proposed Decision denies the other requests in the Pilot Partners’ PFM as these have been addressed via the Advice Letter dispositions. On May 3, the CPUC denied the Pilot Partners’ January 31 Motion to Shorten Time for opening comments on the Proposed Decision.
Analysis: After a conflicted and procedurally complex set of interactions with PG&E regarding the Pilot, VCE’s concerns have been resolved via the Energy Division’s Advice Letter dispositions and the Pilot launched in May 2022. If approved, the Proposed Decision will enable VCE to be reimbursed for its administrative expenses in running the Pilot.
Next Steps: Opening comments on the Proposed Decision are due May 19 and reply comments are due May 24. The Proposed Decision may be heard by the Commission no earlier than June 2.
Additional Information: Ruling on Pilot Partners Motion to shorten time (May 3, 2022); Proposed Decision on PFM (April 29, 2022); Energy Division’s Non-Standard Disposition Letter approving PG&E AL 6495-E and PG&E AL 6495-E-A (April 27, 2002); PG&E AL 6495-E-A (April 7, 2022); 1 Please note that although the letter is dated March 23, 2022, it was not issued by the Energy Division until April 11, 2022.
32 5
Energy Division’s Non-Standard Disposition Letter approving VCE AL 11-E (April 11, 2022); VCE, Polaris, and TeMix Reply to PAO & PG&E Responses (March 14, 2022); PAO Response to VCE, Polaris, and TeMix Reply (March 2, 2022); PG&E Response to VCE, Polaris, and TeMix Reply (March 2, 2022); VCE, Polaris, and TeMix Protest of PG&E AL 6495-E (February 24, 2022); VCE, Polaris, and TeMix Reply to PAO Response (February 18, 2022); PAO Response to Motion to Shorten Time (February 9, 2022); PG&E AL 6495-E (February 4, 2022) and Substitute Sheets for AL 6495-E (March 29, 2022); VCE Reply to PG&E Protest of VCE AL 11-E (January 31, 2022); VCE, TeMix and Polaris Petition for Modification (January 31, 2022); Motion to Shorten Time (January 31, 2022); VCE AL 11-E on Ag Pumping Pilot (January 2, 2022); PG&E Protest of VCE AL 11-E (January 25, 2021); D.21-12-069 correcting errors in D.21-12-014 (December 27, 2021); D.21-12- 015 (December 6, 2021); D.21-02-028 directing IOUs to seek additional capacity for summer 2021 (February 17, 2021); Scoping Memo and Ruling (December 21, 2020); Order Instituting Rulemaking (November 20, 2020); Docket No. R.20-11-003.
IRP Rulemaking
The process for developing final LSE load forecasts was issued in an April 20 ruling. The final load forecasts will serve as the basis for 2022 IRPs, resource procurement requirements, RPS Plans, and GHG emission reduction targets.
Background: On September 1, 2020, LSEs including VCE filed their 2020 IRPs, which included updates on each LSE’s progress towards completing additional system RA procurement ordered for the 2021-2023 years under D.19-11-016.
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 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 obligations 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 5-10pm daily.
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. The 2021 PSP is a statewide resource portfolio that meets a statewide 38 MMT GHG target for the electric sector in 2030. It is derived from an aggregation of individual LSE IRPs with adjustments to extend the timeframe beyond 2030 to 2032 for transmission planning purposes and to add the resources required in D.21-06-035 for mid-term reliability (MTR) purposes.
The decision recommends that CAISO use the 38 MMT PSP portfolio as both the reliability base case and the policy-driven base case for study in its 2022-2023 Transmission Planning Process, which is a more aggressive GHG reduction portfolio than the 46 MMT portfolio used in 2020 IRPs.
D.22-02-004 also results in the following new resource build by 2032, by technology: Gas: 0 MW; Biomass: 134 MW; Geothermal: 1,160 MW; Wind: 3,531 MW; Wind (New Transmission): 1,500 MW; Offshore Wind: 1,708 MW; Utility-Scale Solar: 17,506 MW; Battery Storage: 13,571 MW; Long-duration Storage: 1,000 MW; Load Shed DR: 441 MW.
MCAM Proposed Decision: A Proposed Decision (PD) on the Modified Cost Allocation Mechanism (MCAM) was issued on March 29 that addresses allocation and recovery of net costs of electric resource procurement for opt-out LSEs (i.e., those LSEs who elected not to self-procure) and backstop procurement obligations.
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The PD addresses the issue raised by CalCCA in its May 14 Petition for Modification of D.19-11-016 of whether the nonbypassable charge should appear on retail customers’ bills or be directly billed to the LSE. The PD would not adopt CalCCA’s proposal for the direct billing of the full MCAM costs from the IOU to the non-IOU LSE, and instead cites the Public Utilities Code’s express direction that these costs be allocated “on a fully nonbypassable basis” to “customers” (Section 365.1(c)(2)(i)-(iii)).
The PD also addresses how the costs of backstop procurement associated with D.19-11-016 and D.21-06-035 will be allocated to customers.
Details: The ALJ issued a ruling on April 20 establishing a process for LSEs to update their load forecasts in preparation for developing final load forecasts and greenhouse gas emissions benchmarks for LSEs’ 2022 IRPs. LSEs that choose to update their load forecasts must use the template from the Commission’s 2022 IRP Cycle website, while an LSE that does not wish to update its load forecasts may simply state that it does not intend to file a template in its written comments.
The updated forecasts will be filed by LSEs on May 16. The Commission and CEC staff will compile these filings and calculate final load forecasts for use by each LSE in its 2022 IRP. The final forecasts will be issued in a June 15 ruling, with peak demand forecasts confidentially distributed to each LSE on July 1.
There are three load forecasts, and an LSE may update all, some, or none of the following:
• The energy forecast (public information) provides a projection of future retail sales. If an LSE chooses not to update its energy forecast, then the IEPR-based forecast will be used. In the IEPR-based forecast, VCE is estimated to account for between 0.82% and 0.83% of PG&E energy sales.
• The peak demand forecast (non-public) may be updated by an LSE, otherwise the Commission and CEC staff will calculate a peak demand forecast based on the energy forecast, resource adequacy or other pre-existing information. • The behind-the-meter PV (BTM PV) and other demand modifier (e.g., battery storage, energy efficiency, EVs, etc.) forecast may also be updated by an LSE. These forecasts will be used by the Commission and CEC staff in calculating the final peak load forecast.
The final load forecasts will also be used to determine each LSE’s GHG benchmark for both the 30 million metric ton (MMT) and the 25 MMT 2035 target scenarios. LSEs are required to include a plan to achieve their GHG benchmark in their individual IRP filing. GHG benchmark targets for each LSE will be issued in a ruling on June 15. VCE’s current benchmarks for 2035 are based on a projected 825 GWh (1.0% of PG&E area) and is 0.086 MMT of GHG emissions under the 30 MMT scenario and 0.069 MMT of GHG emissions under the 25 MMT scenario (Table 1 at 11).
Analysis: The final load forecasts establish not only the energy, peak capacity, and RPS-related procurement basis for the 2022 IRP, but also determine VCE’s share of the aggregate electric sector’s GHG reductions. The final load forecasts will influence all procurement requirements and given the requirements for larger shares of longer-term procurement, could have a substantial impact on future costs.
MCAM: The Proposed Decision regarding the MCAM would clarify that procurement costs will only be recovered from bundled service customers, Opt-Out LSE customers, and potentially Deficient LSEs rather than all customers in an IOU’s service territory. If approved, cost recovery under MCAM will occur through a nonbypassable charge on retail customers’ bills. Resource Adequacy benefits would also be allocated on the same basis as costs for purposes of the MCAM. Additionally, if the PD is approved, an LSE may acquire unbundled RECs but the transfer of RECs to LSEs must be accompanied by a forward sale of associated energy.
Next Steps: A Final Decision on the MCAM is expected on or after May 5, after which the IOUs will file a Tier 2 Advice Letter to implement the MCAM no more than 60 days following the Final 34 7
Decision. VCE’s next IRP is due November 1. The CPUC will issue a Ruling by June 15, providing additional direction and detail on the requirements for LSEs’ 2022 IRPs.
Load Forecasts and GHG Benchmarks Schedule
• May 16, 2022: Updated load forecasts due (or statement accepting CEC forecast) • May 16, 2022: Comments due on proposed 2035 GHG targets • May 23, 2022: Reply comments on GHG targets and load forecasts • June 15, 2022: Ruling on final load forecasts and GHG targets for each LSE • July 1, 2022: Final peak capacity forecast distributed to each LSE confidentially Additional Information: Ruling establishing process for load forecasts and GHG benchmarks for 2022 IRP (April 20, 2022); Proposed Decision on the Modified Cost Allocation Mechanism (March 29, 2022); D.22-02-004 adopting 2021 Preferred System Plan (December 22, 2021); CCA Motion for Clarification (December 13, 2021); D.21-06-035 establishing a 11,500 MW by 2026 procurement mandate (June 24, 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); 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 April 6, Assigned Commissioner Rechtschaffen issued a ruling amending the scope of the proceeding to consider REC classification and the timing and approval process for Voluntary Allocation contracts. On April 11, the Assigned Commissioner and the ALJ issued a ruling providing requirements and the procedural schedule for Retail Sellers’ 2022 RPS Procurement Plans and denying the Joint IOUs’ motion to file the Market Offer Process information through a Tier 3 Advice Letter. An April 18 Ruling requested comments from the parties on questions related to Voluntary Allocation, REC classification, and scheduling. The schedule was modified in an April 21 Ruling to allow the IOUs to individually file their confidential market offer information on May 16. The joint IOUs filed their proposed Market Offer Process on May 2.
Background: This proceeding addresses ongoing RPS issues. VCE submitted its Final 2020 RPS Procurement Plan on February 19, 2021, and its 2020 RPS Compliance Report on August 2, 2021.
RPS procurement is a two-part process for LSEs to obtain RPS energy, or RECs. In the first part, called Voluntary Allocation (VA), an LSE chooses what portion of the IOU’s RPS portfolio it will accept to meet its own RPS obligations, and then, in the second part of the process, called Market Offer (MO), the IOUs offer for sale the remaining portions of their RPS portfolios that were not claimed by LSEs in the Voluntary Allocation part, together these two parts are the Voluntary Allocation/Market Offer (VAMO) process.
A Joint Motion by the IOUs (December 8, 2021) requested that the CPUC (1) expand the scope of this proceeding to address whether RECs retain their original Portfolio Content Category (PCC) classification when claimed by LSEs under the Voluntary Allocation process; (2) issue guidance on the issue of the PCC classification of allocated RECs before LSEs are required to decide whether to accept allocations; and (3) clarify that pro forma Allocation Contracts will be reviewed in early 2022 via Tier 2 advice letter and that only Allocation Contracts materially deviating from the pro forma would be subject to further review through a Tier 1 Advice Letter.
The Joint IOUs’ March 10 Motion sought authorization for review via Tier 3 Advice Letter submission of their proposed modifications to the Market Offer Process. The proposed modifications would allow delivery of Market Offer RPS resources to coincide with delivery of Voluntary Allocations on January 35 8
1, 2023, thereby generating revenue from the sale of RECs and reducing above-market costs “to benefit bundled service and departing load customers by optimizing the IOU’s PCIA portfolios.” Details: The April 6 Amended Scoping Ruling extended the statutory deadline to October 2, 2023, and expanded the scope of the proceeding to include the following issues (comments on these issues were requested in an April 18 ruling):
• PCC classification of RECs allocated under the VAMO process; and • Timing and approval process for Voluntary Allocation pro forma contracts.
An April 11 Ruling identified requirements for 2022 RPS 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. A modified schedule for RPS Track 1 allowing the IOUs to individually file confidential Market Offer information on May 16 was issued in an April 21 Ruling.
Track 1: Market Offer Process
The Joint IOUs filed their proposed Market Offer process on May 2. The Market Offer process is part of a two-step process for 2022 RPS Procurement. 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 remaining RPS Energy (RECs) not claimed by LSEs in the Voluntary Allocation will be offered to all market participants through the Market Offer process.
Track 2: RPS Plans
2022 RPS Plans (April 11 Ruling) 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. The Plans must describe procurement of RPS resources that achieve the RPS targets while minimizing cost and maximizing customer value; and discuss any plans for building retail seller-owned resources, investing in third party-owned renewable resources, and engaging in the sales of RPS-eligible resources.
Analysis: 2022 RPS Plan requirements have a greater focus on long-term planning, not only maintaining the target of procuring 65% of RPS resources from long-term contracts of 10 years or more, but also aligning the RPS plan with IRP requirements in D.21-03-010. The Voluntary Allocation mechanism has an outsized role in 2022 RPS Plans, providing LSEs an opportunity to claim a slice of an IOU’s portfolio of RPS resources prior to entering a competitive bidding process. Voluntary Allocation essentially provides LSEs a right of first refusal and accelerates and streamlines the procurement process while providing all LSEs with equal access to a representative share of an IOU’s portfolio of RPS resources, and by avoiding competitive bidding potentially offers lower-cost procurement.
Next Steps:
Track 1: Market Offer Process
• May 16, 2022: IOUs individually file confidential Market Offer information • May 22, 2022: Comments on Market Offer process due
• May 27, 2022: Reply Comments on Market Offer process due • 3Q 2022: Proposed Decision on Market Offer process
Track 2: 2022 RPS Plans
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• July 1, 2022: Draft RPS Plans filed
• August 1, 2022: Comments on Retail Sellers’ Draft Plans due • August 1, 2022: Motions requesting evidentiary hearing due • August 15, 2022: Motion to update draft RPS Plans due • August 15, 2022: Reply Comments on Retail Sellers’ Draft Plans due • 4Q 2022: Proposed Decision on Retail Sellers’ Draft Plans Market Offer Timeline
• Ongoing: Participant registration at IOU websites to receive notices regarding the solicitations
• September 16, 2022: IOUs Issue 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 Additional Information: Market Offer Process proposal by Joint IOUs (May 2, 2022); Ruling on RPS Track 1 schedule (April 21, 2022); Ruling seeking comments on Voluntary Allocations and PCC issues (April 18, 2022); Ruling identifying RPS Plan requirements (April 11, 2022); Amended Scoping Ruling expanding scope (April 6, 2022); Joint Motion by IOUs Concerning Review of Market Offer Process (March 10, 2022); VCE’s Final 2021 RPS Procurement Plan (February 17, 2022); D.22-01-025 fining Gexa for RPS non-compliance (February 1, 2022); D.22-01-004 on draft 2021 RPS Procurement Plans (January 18, 2022); D.21-12-032 modifying the ReMAT tariff (December 16, 2021); D.21-11-029 amending RPS confidentiality rules (November 19, 2021); Petition for Modification of D.20-10-005 on ReMAT pricing (October 8, 2021); Ruling aligning IOU RPS Procurement Plan requirements with PCIA decision (May 26, 2021); Docket No. R.18-07-003.
PCIA Rulemaking
An April 18 ruling requested comments on a Staff proposal regarding the impact on the RPS Adder (one Market Price Benchmark (MPB) used to calculate the Power Charge Indifference Adjustment (PCIA)) from the Voluntary Allocation of renewable energy credits to CCAs. In addition, the ruling directed the Joint IOUs and other parties to file an Energy Index MPB calculation proposal by May 27 and set forth a related procedural schedule. CalCCA submitted comments in support of Staff’s proposal on April 29.
Background: D.18-10-019 was issued on October 19, 2018, in Phase 1 of this proceeding and left the current 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 (1) adopted the consensus framework of PCIA prepayment agreements; (2) adopted the consensus guiding principles, except for one principle regarding partial payments; (3) adopted evaluation criteria for prepayment agreements; (4) did not adopt any proposed prepayment concepts; and (5) clarified that risk should be incorporated into the prepayment calculations by using 37 10
mutually acceptable terms and conditions that adequately mitigate the risks identified by Working Group Two.
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 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.
D.22-01-023 modified the PCIA market price benchmark release date to October 1 and the deadline for ERRA forecast applications to May 15 to enable the Commission to timely issue decisions on ERRA forecast applications. It adopted party proposals to establish a policy for disposition of the year-end balance in the ERRA account and to modify the calculation of the ERRA trigger point and threshold. It also adopted party proposals to support efficient party access to ERRA forecast proceeding data.
PG&E submitted, in accordance with D.22-01-004, two proposed contracts for PCIA-eligible RPS resources: AL 6517-E (February 28) proposing a Voluntary Allocation Contract and AL 6551-E (April 4) proposing a Market Offer Contract.
AL 6517-E Voluntary Allocation Contract proposal
Since PG&E’s Voluntary Allocation Contract is a confirmation to PG&E’s Edison Electric Institute (EEI) Master Power Purchase and Sale Agreement (Master Agreement), similar to the existing confirmation used in PG&E’s bundled RPS energy sales, Voluntary Allocation participants will need a Master Agreement in place with PG&E prior to execution of the Voluntary Allocation Contract.
CalCCA cited several errors in its March 21 Protest of AL 6517-E, including the misapplication of D.22-01-004’s calculation of each LSE’s load-share percentage from which the LSE may claim long-or short-term Voluntary Allocations, the contract provision(s) enabling PG&E to remove resource from the allocation pool without notice to LSEs and the resulting harm to planning efforts, and the lack of contract provisions for timely access to forecast and meter data by LSEs.
AL 6551-E Market Offer Contract proposal
PG&E submitted the Tier 2 Advice Letter 6551-E requesting approval of a pro forma Market Offer Contract for Power Charge Indifference Adjustment (PCIA)-eligible Renewables Portfolio Standard (RPS) resources, on April 4, as required by D.22-01-004. The proposed Market Offer Contract remains suspended.
This proposed Market Offer Contract is specific to the requirement of D.21-05-030 that all PCIA-eligible RPS energy remaining after a Voluntary Allocation be offered for sale in the Market Offer.
The other two requirements of D.21-05-030 – that the Market Offer process 1) be based upon existing processes, rules, oversight requirements, and reporting requirements for REC solicitations previously approved in the Commission’s RPS proceeding; and 2) include rules for utility participation in utility-administered solicitations – were addressed in the IOU’s Joint Motion in R.18- 07-003 (filed March 10).
Since PG&E’s Market Offer Contract is a confirmation to PG&E’s Edison Electric Institute (EEI) Master Power Purchase and Sale Agreement (Master Agreement), similar to the existing confirmation used in PG&E’s bundled RPS energy sales, Market Offer process participants will need a Master Agreement in place with PG&E prior to execution of the Market Offer Contract.
Details of the proposed pro forma Market Offer Contract include:
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• A Market Offer participant may bid for all the PCIA-eligible RPS portfolio that remains following Voluntary Allocation.
• PG&E proposes to deliver the PCIA-eligible RPS energy remaining after Voluntary Allocation over the final two years of the current RPS compliance period (i.e., 2023 & 2024) for reasons that include reducing administrative risk, providing flexibility for all LSEs, and enabling reevaluation for future Market Offers.
The proposed contract differs from PG&E’s CPUC-approved bundled RPS energy sale contract in the products offered and their delivery periods. The RPS energy sale contract only includes fixed volumes of bundled RECs available for purchase in calendar year 2022, while the proposed contract includes portions of PG&E’s PCIA-eligible RPS portfolio that remain unallocated following Voluntary Allocation that will be delivered over 2023 and 2024, like PG&E’s existing carbon-free allocation contract.
In its April 25 Protest, CalCCA recommended that PG&E modify its proposed Market Offer Contract to align its Market Offer product offerings with those of SDG&E and SCE so that bidders have greater certainty regarding the value of the products on which they are bidding, and to provide for timely access by counterparties to generation data from RPS resources obtained via Market Offer since generation volume is variable and information regarding actual generation is crucial.
Details: An April 18 ALJ Ruling requested comments on the impact of voluntarily allocating renewable energy credits to CCAs on the calculation of RPS Adder (one MPB used to calculate the PCIA). In addition, the ruling directed the joint IOUs and other parties to file an Energy Index MPB calculation proposal by May 27 and set forth a related procedural schedule. CalCCA submitted comments in support of Staff’s proposal on April 29.
Analysis: The two proposed contracts for procurement of PCIA-eligible RPS resources provide details of the terms for procurement of PCIA-eligible RPS resources under the Voluntary Allocation and Market Offer mechanisms. As proposed and protested by CalCCA, PG&E’s contracts do not provide for timely access to meter data by LSEs, and PG&E’s contracts contain provisions allowing the company to adjust its RPS resource mix without notice. These protested provisions create sources of uncertainty in the quantity and character of RPS resource procured from PG&E and therefore adversely impact an LSE’s ability to plan, update, or make necessary modifications for compliance purposes.
The ALJ ruling addresses the fact that voluntarily allocated RPS attributes are valued at the prior year’s MPB (i.e., the RPS Adder), potentially skewing that benchmark’s representation of recent market activity. CalCCA agreed but noted a concern about whether excluding those transactions could result in the benchmark being based on an illiquid RPS market.
Next Steps: PG&E posted a webpage with updated timelines for 2022 Voluntary Allocations:
• May 31, 2022: PG&E files ERRA Forecast Application and informs LSEs of initial forecast allocation shares for 2023 Voluntary Allocation
• May 16 – June 10, 2022: Voluntary Allocation contracting with LSEs • May 27, 2022: Joint IOU filing of Energy Index MPB Calculation Proposal • June 10, 2022: Final day for LSEs to submit Voluntary Allocation elections to PG&E • June 16, 2022: Comments on Energy Index MPB Proposal
• June 2022: PG&E completes Voluntary Allocation contracting • June 30, 2022: Reply Comments on Energy Index MPB Proposal 39 12
• Summer 2022: LSEs file Draft 2022 RPS Plans informed by Voluntary Allocation elections • October 2022: Each IOU informs LSEs of updated allocation shares for 2023 Voluntary Allocations
Additional Information: Ruling Regarding Market Price Benchmarks (April 18, 2022); Market Offer Contract (AL 6551-E) for PCIA-eligible RPS Resources remaining after VA (April 4, 2022); Voluntary Allocation Contract (Advice 6517-E) for PCIA-eligible RPS Resources (February 28, 2022); D.22-01- 023 on Phase 2 (approved January 27, 2021); Ruling requesting comments on PCIA forecasting data access (November 5, 2021); Voluntary Allocation Methodology Advice Letter 6305-E (October 25, 2021); Ruling requesting comments (September 17, 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); 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.
PG&E 2021 ERRA Compliance
CalCCA and two other parties filed protests in response to PG&E’s 2021 ERRA Compliance application (filed February 28), and the parties proposed a new schedule on April 18.
Background: PG&E’s application requested that 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. • 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 presents its Central Procurement Entity’s administrative costs recorded to the Centralized Local Procurement Sub-Account (CLPSA) in the New System Generation Balancing Account (NSGBA).
PSPS Impacts: PG&E states that since the CPUC is currently considering the utilities’ proposed common methodology for calculating unrealized volumetric sales and unrealized revenues resulting from Public Safety Power Shutoff (PSPS) events in the consolidated Phase II 2019 ERRA Compliance proceeding, it has not included with this 2021 ERRA Compliance application any testimony addressing the calculation of unrealized volumetric sales or unrealized revenues. PG&E plans to send an email to the assigned ALJ requesting direction regarding whether and in what 40 13
format PSPS information should be presented as part of this Application once the Commission has resolved the issue in the Phase II 2019 ERRA Compliance proceeding.
Issues: PG&E proposes the following issues be considered in this proceeding:
• Whether PG&E, during the record period, prudently administered and managed the following, in compliance with all applicable rules, regulations, and Commission decisions, including but not limited to Standard of Conduct No. 4 (SOC 4):
o Utility-Owned Generation Facilities
o Qualifying Facilities (QF) Contracts and Non-QF Contracts. If not, what adjustments, if any, should be made to account for imprudently managed or administered resources? • Whether PG&E achieved least-cost dispatch of its energy resources and economically triggered demand response programs pursuant to SOC 4;
• Whether the entries recorded in the Energy Resource Recovery Account and the Portfolio Allocation Balancing Account are reasonable, appropriate, accurate, and in compliance with Commission decisions;
• Whether PG&E’s greenhouse gas instrument procurement complied with its Bundled Procurement Plan;
• Whether PG&E administered resource adequacy procurement and sales consistent with its Bundled Procurement Plan;
• Whether the costs incurred and recorded in the following accounts are reasonable and in compliance with the applicable tariffs and Commission directives:
o Green Tariff Shared Renewables Memorandum Account;
o Green Tariff Shared Renewables Balancing Account;
o Disadvantaged Community - Single Family Solar Affordable Homes Balancing Account; o Disadvantaged Community - Green Tariff Balancing Account; o Community Solar Green Tariff Balancing Account;
o Centralized Local Procurement Sub-Account.
• Whether there are any safety considerations raised by this Application Details: Protests of PG&E’s application were filed by three parties including CalCCA and the Cal Advocates office. A Notice was issued on May 3 rescheduling the prehearing conference for June 8.
Analysis: The proceeding has just begun, and its full scope is yet to be determined. A CPUC determination in the Phase II 2019 ERRA Compliance proceeding on the utilities’ proposed common methodology for calculating unrealized volumetric sales and unrealized revenues resulting from PSPS events could expand the scope of this proceeding.
Next Steps: PG&E, in agreement with parties filing protests, proposed the following timeline:
• June 8, 2022: Prehearing Conference
• August 24, 2022: Cal Advocates and Intervenor Testimony • October 1, 2022: PG&E Rebuttal Testimony
• October - November 2022: Settlement Discussions
• November 14-16, 2022: Evidentiary Hearings
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• December 2, 2022: Opening Briefs
• December 19, 2022: Reply Briefs
Additional Information: Notice rescheduling prehearing conference (May 3, 2022); PG&E 2021 ERRA Compliance Application (February 28, 2022); Docket No. A.22-02-015.
PG&E Phase 2 GRC
PG&E filed a Motion for Evidentiary Hearing on April 22 to address issues raised by the one party responding to its non-NEM export compensation proposal for BEV (filed March 24), and a prehearing status conference is set for May 10. The Commission issued an order reassigning A.19-11-019 and R.19- 11-019 from ALJ Sisto to ALJ Patrick Doherty on April 27.
Background: PG&E’s 2020 Phase 2 General Rate Case (GRC) addresses marginal cost, revenue allocation and rate design issues covering the next three years. D.21-11-016 largely adopted PG&E’s proposed marginal costs and methodologies for deriving them but adopted marginal connection equipment costs proposed by the Agricultural Energy Consumers Association and marginal transmission capacity costs proposed by the Solar Energy Industries Association. It also adopted, without modification, several uncontested settlements on rate design issues (residential rate design settlement; settlement on streetlight rate design issues; Economic Development Rate (EDR) settlement; agricultural rate design; C&I rate design) and revenue allocation.
With respect to CCA issues, the adopted EDR settlement noted that PG&E and the Joint CCAs agreed to create a collaborative process “to identify and vet EDR applicants that will make it easier for CCAs to provide a generation rate reduction to CCA customers who qualify for PG&E’s EDR.” D.21-11-016 also approved the agricultural rate design settlement that proposed that the unbundling of the PCIA from the generation component of bundled rates be designed as a flat PCIA rate, not differentiated by season or TOU period, consistent with the PCIA rate design for DA and CCA customers. The PCIA rate for bundled customers will use the most recent vintage of the PCIA rate.
Finally, D.21-11-016 approved the revenue allocation settlement, including its proposal that before allocating generation revenue, instead of including the PCIA revenue in the overall generation revenue requirement, PCIA revenue will be removed from each customer class’s revenue at present rates based on the most recent vintage PCIA rates. Then, PG&E will use the adopted allocation for generation to allocate the PCIA revenue requirement to customer classes.
On January 18, parties filed a Settlement Agreement includes the following terms of the Stage 1 RTP Pilot:
Eligibility: PG&E’s bundled customers who are eligible for the B-20, B-6 and E-ELEC rates may participate on an opt-in basis. CCAs will need to affirmatively decide to participate in the Stage 1 Pilots for their customers to be eligible. PG&E agrees to work with its twelve CCAs to seek agreement from one or two of them to participate in the Stage 1 Pilots, if possible.
Duration: Stage 1 Pilots shall have a duration of 24 months, subject to potential extension.
Enrollment: PG&E will make its best efforts to program and make available for enrollment the three Stage 1 RTP rates by October 1, 2023.
Pricing: The RTP element of the Stage 1 Pilot RTP rates will replace the generation component of the customer’s otherwise applicable rate schedule. The remaining transmission, distribution, Public Purpose Program and other charges and taxes remain the same as the otherwise applicable underlying rate. The generation component to be used in the Stage 1 Pilots’ RTP rates will include:
(1) a Marginal Energy Charge, (2) a Marginal Generation Capacity Cost, and (3) a Revenue Neutral Adder (designed to make the forecasted annual generation revenue collected under the three Stage 42 15
1 Pilot RTP rates revenue neutral to the base schedule). Residential customers would have 1 year bill protection. There would be a limited amount of participation incentives as well.
All development, implementation, and operating costs for the Stage 1 Pilots, as well as for the separate Customer Research Study for residential, agricultural, and small commercial customers, will be recovered in distribution rates from all customers.
The Final Decision, D.22-03-012, adopting the Joint Stipulation, or otherwise resolving the single carryover issue of material fact about the MGCC Property Tax Adder, was issued March 18. This Decision, in accordance with the PG&E/CLECA Joint Stipulation, adopts a property tax factor of
1.25% for the 2021-2026 marginal generation capacity cost (MGCC) for new customer rates effective June 1. A corrected version of PG&E’s MGCC Report was filed on March 17.
PG&E proposed an export compensation mechanism for non-NEM customers enrolled in the Day-Ahead Hourly Real Time Pricing (DAHRTP) rate. The proposed Business Electric Vehicle (BEV) Pilot will include customers on any BEV rate and not only customers on the DAHRTP Commercial Electric Vehicle (CEV) rate. Compensation for energy will come from the CAISO market participation entity, and to the extent available will include compensation for Resource Adequacy. PG&E has not yet proposed a budget for the Pilot but has proposed a cost-effectiveness evaluation and a report on lessons learned to be issued two years after implementation. The proposal includes a market participation option instead of a tariff rate to allow all BEV customers in the PG&E service territory (including customers of CCAs or direct access providers) to participate without requiring each retail LSE to offer its own tariff rate. Some key considerations that PG&E has requested be addressed through a stakeholder process include interconnection jurisdiction, resource adequacy compensation methodology, and managing and monitoring customer revenue generation.
Details: PG&E served the required supplemental testimony (March 24) for its proposed export compensation mechanism for customers enrolled in the day-ahead real-time pricing (DAHRTP-CEV) rate that do not participate in net metering but provide behind-the-meter resources. The Vehicle Grid Integration Council (VGIC) was the only party to file responsive testimony, and rebuttal testimony was scheduled to be served on April 29. PG&E’s Motion for Evidentiary Hearing in A.20-10-011 (filed April 22) requested the Commission grant evidentiary hearings on several disputed questions related to the export compensation mechanism for customers enrolled in the day-ahead real-time pricing (DAHRTP-CEV) rate that do not participate in net metering but provide behind-the-meter resources.
The disputed issues raised by VGIC, as identified in PG&E’s Motion, are:
• Whether PG&E’s market participation approach belongs in this proceeding; • PG&E’s consideration of resource adequacy valuation and compensation; • PG&E’s proposed use of a “complex and lengthy approach” that includes a cost-benefit analysis for export valuation;
• Potential use of the same compensation mechanism for DAHRTPCEV Non-NEM as DAHRTPCEV NEM customers; and
• Dual participation in ELRP.
Analysis: This phase of the proceeding could impact real-time pricing rate design issues for PG&E customers. If the settlement agreement is adopted, VCE could elect to allow its customers to participate in the Stage 1 RTP Pilot. The Settlement Agreement provides that cost recovery of development, implementation, and operating costs for the Stage 1 Pilots, as well as for the separate Customer Research Study, would be recovered in distribution rates that both bundled PG&E and VCE customers pay.
Next Steps: Potential evidentiary hearing dates were reserved for May 18 – 20. The proceeding remains open to address RTP issues. PG&E’s April 22 Motion for an Evidentiary Hearing remains unaddressed.
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Additional Information: PG&E Motion for Evidentiary Hearing (April 22, 2022); PG&E Proposal for non-NEM export compensation (March 24, 2022); PG&E MGCC Report (corrected) (March 17, 2022); Decision on property tax adder (March 18, 2022); Ruling on timing to respond to PG&E/CLECA Motion (January 25, 2022); Motion by PG&E/CLECA to establish a separate expedited schedule (January 21, 2022); PG&E Motion on MGCC Study (January 18, 2022); PG&E Motion (January 18, 2022); Motion to Adopt Settlement Agreement (January 18, 2022); D.21- 11-016 on revenue allocation and rate design (November 19, 2021); Amended Scoping Memo and Ruling (August 25, 2021); Ruling bifurcating RTP issues into separate track (February 2, 2021); D.20-09-021 on EUS budget (September 28, 2020); Exhibit (PG&E-5) (May 15, 2020); Scoping Memo and Ruling (February 10, 2020); Application, Exhibit (PG&E-1): Overview and Policy, Exhibit (PG&E-2): Cost of Service, Exhibit (PG&E-3): Revenue Allocation, Rate Design and Rate Programs, and Exhibit (PG&E-4): Appendices (November 22, 2019); RTP Pilot Docket No. A.20-10-011; Phase 2 GRC Docket No. A.19-11-019.
PG&E Phase 1 GRC
The ALJ issued an email Ruling on April 12 that 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. PG&E filed an Application on April 20 to modify its 2023 cost of capital that requests an overall rate of return of 7.78% and a $69.3 million increase in its revenue requirement.
Background: Phase 1 GRC applications cover the revenue requirement, including the functionalization of costs into categories such as electric distribution or generation, which impact 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. PG&E proposes to have a second and third track of this Phase 1 GRC to request reasonableness review of certain memorandum and balancing account costs to be recorded in 2021 and 2022.
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.
In their Protest of PG&E’s Application, the Joint CCA parties identified the following list of preliminary issues they plan to examine or address in this proceeding:
• Compliance with the Commission’s Cost Allocation Directives in D.20-12-005 (PG&E’s most recently decided Phase 1 GRC decision), including PG&E’s cost functionalization methodology, wildfire costs, and allocation of Customer Care costs. • Reinvestments in and Recovery of Legacy Owned Generation Costs, including solar contract renewals or the decommissioning of legacy owned assets, which impact Joint CCAs’ customers through the PCIA and related vintaging of costs. • Other Issues that May Require Further Investigation and Analysis, including how costs related to PSPS Events should be tracked and allocated; whether and how any funds that PG&E receives as credits (such as Department of Energy settlement funds) should be allocated to departing load customers; and how PG&E’s regionalization proposal impacts its relationship and dealings with CCAs and their customers.
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. 44 17
PG&E’s pending November 5, 2021, Motion requests extending the turn-around time for filing rebuttal testimony from 30 days to 45 days; delaying the start of evidentiary hearings by three weeks to accommodate the proposed rebuttal testimony timeline; and requested an earlier resolution than Q4 2022 as indicated in the Scoping Memo and Ruling on PG&E’s July 16, 2021, Motion for a January 1, 2023 effective date for its 2023 revenue requirement.
On March 10, PG&E filed an Amended Application and submitted supplemental testimony on wildfire mitigation programs. Also on March 10, the ALJ issued a Ruling on the February 25 Motion filed by TURN, PG&E, and PAO denying their request to shorten time for responses to PG&E’s Amended Application and supplementary testimony on wildfire mitigation programs, and suspending the March 30, submission date for intervenor testimony pending a ruling on the February 16, Motion to Modify the Schedule filed by TURN, PG&E, and the PAO.
On March 9, PG&E submitted its recorded expense and capital data testimony for 2021.
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.
Details: 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%.
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 impact 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.
Next Steps:
The Track 1 schedule, as modified in the April 12 Ruling is:
• June 13, 2022: Intervenor Opening Testimony
• July 11, 2022: Concurrent Rebuttal Testimony
• July 12 – August 15, 2022: Meet & Confer (minimum of four times) • TBD (prior to Evidentiary Hearings): Status Conference • August 15 – August 26, 2022: Evidentiary Hearings
• November 4, 2022: Opening Briefs
• December 9, 2022: Reply Briefs
• March 24, 2023: Proceeding Submitted
• Q3 2022: Proposed Decision on PG&E
• Q2 2023: Proposed Decision on A.21-06-021
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The Track 2 schedule, as modified in the April 12 ruling is:
• 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: 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); Docket No.
A.22-04-008; Docket No. A.21-06-021.
RA Rulemaking (2023-2024)
On April 29, the CAISO filed its Final Local Capacity Requirements (LCR) Report, and the Final Flexible Capacity Requirements (FCR) Report is delayed until mid-May 2022.
Background: In Track 3B.2 of the 2021-2022 RA Rulemaking (R.19-11-009), D.21-07-014 rejected CalCCA/SCE's proposal for restructuring the Resource Adequacy (RA) program, and instead found that PG&E’s "slice-of-day" proposal best addresses the identified principles and the concerns with the current RA framework and if further developed, is best positioned to be implemented in 2023 for the 2024 compliance year. Therefore, the Decision directed parties to collaborate to develop a final restructuring proposal based on PG&E’s slice-of-day proposal through a series of 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 (further described below).
• Phase 2 consists of the Commission’s consideration of flexible capacity requirements for the following year, local capacity requirements for the next three years, and the highest-priority refinements to the RA program including modifications to the Planning Reserve Margin 46 19
Qualifying Capacity Counting Conventions, which, along with other proposals, will consider the Energy Division's biennial update to the Effective Load Carrying Capability values for wind and solar resources. Phase 2 proposals were submitted in January 2022 and this phase is expected to conclude in June 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. An LSE’s self-shown commitment must be firm for Years 1 and 2, but self-shown local resources for year 3 may be replaced like-for-like with other local resources.
Details: The Final LCR Report (April 29) was accompanied by the CAISO’s List of Physical Resources Accounted for in the 2023 and 2027 Local Capacity Technical Studies. The overall capacity needed for LCR has increased by about 336 MW or about 1.3% from 2022 to 2023. The study aids procurement and resource adequacy planning by providing load profiles and transmission capacity information that shows the effectiveness of local resources in meeting temporal local reliability needs.
Analysis: The Decision provides some additional RA flexibility for LSEs by allowing like-for-like substitution in the event of a non-performing self-shown resource and allowing replacement of year 3 resources with other local resources. There is a tradeoff for LSEs between reserving some backup local RA resources by not self-showing to the CPE and potentially incurring higher RA costs if the CPE fails to procure adequate RA resources through its competitive solicitation and as a result must use broker transactions or bilateral contracts to remedy any deficiency in the three-year forward period.
Next Steps: The procedural schedule for the ongoing tracks and working groups are as follows:
Phase 2
• May 6, 2022: Comments due on Final 2023 LCR
• May 13, 2022: Reply comments on Final 2023 LCR
• mid-May 2022: Final FCR Report published
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nd business day following Final FCR Report: Comments due on Final FCR Report • May 20, 2022: Proposed Decision on Final LCR Report and Final FCR Report (if delayed, a separate PD on Final FCR Report will be issued)
CPE Procurement Timeline
• No later than mid-May 2022: LSEs make self-shown commitment of local resources to the CPE for the applicable Resource Adequacy (RA) years.
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• No later than June 2022: The Commission adopts multi-year local RA requirements for the applicable compliance years as part of its June decision. • No later than early July 2022: CPE receives total jurisdictional share of multi-year local RA requirements for the applicable compliance years.
• July 2022: LSEs receive initial RA allocations, including Cost Allocation Mechanism (CAM) credits from CPE-procured system and flexible capacity from the prior year and any bilateral contracts.
• Mid-August 2022: CPE makes local RA showing to the Commission. • 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: 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); Workshop Report (February 28, 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); Ruling modifying procedural schedule (December 10, 2022); Scoping Memo and Ruling (December 2, 2021); Order Instituting Rulemaking (October 11, 2021); Docket No. R.21-10-002.
PG&E Regionalization Plan
On April 18, the ALJ filed a Proposed Decision that would approve the multi-party settlement agreement (MPSA) with few changes.
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, which describes how it plans to reorganize operations into new regions.
PG&E proposed to divide its service area into five new regions, each led by a Regional Vice President, and each with a Regional Safety Director to lead its safety efforts. The new 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. Other functions will remain centralized, such as electric and gas operations, risk management, enterprise health and safety, the majority of existing Customer Care and regulatory and external affairs, supply, power generation, human resources, finance, and general counsel.
In August 2020, parties filed protests and responses to PG&E’s application. Of note, South San Joaquin Irrigation District filed a Protest arguing that PG&E’s regionalization effort should not create a moratorium or interfere with municipalization efforts. 48 21
In February 2021, PG&E submitted its updated regionalization proposal (“Updated Proposal”). In response to feedback, PG&E modified its five regions (renamed North Coast, North Valley & Sierra, Bay Area, South Bay & Central Coast, and Central Valley), including moving 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.
On August 31, 2021, PG&E, the California Farm Bureau Federation, the California Large Energy Consumers Association, the Center for Accessible Technology, the Coalition of California Utility Employees, the Public Advocates Office at the California Public Utilities Commission (Cal Advocates), the Small Business Utility Advocates, and William B. Abrams filed a Motion for approval of their settlement agreement (Multi-Party Settlement Agreement, or MPSA). A separate settlement agreement is between the South San Joaquin Irrigation District and PG&E. The Multi-Party Settlement Agreement includes a framework within which PG&E will facilitate a stakeholder engagement process for parties to the Multi-Party Settlement Agreement to provide updates and a non-binding forum for input from stakeholders. The proposed settlement would have restricted participation in the Regionalization Stakeholder Group to parties or others who agree to the scope, procedures and protocols of the Regionalization Stakeholder group as outlined in the settlement.
PG&E will host two public workshops in 2022 and for each year until the completion of Phase III or its regionalization implementation to provide updates to the public about its regionalization implementation progress.
In the separate PG&E/SSJID Settlement Agreement, PG&E clarified and confirmed that its implementation of regionalization as managed by its Regionalization Program Management Office will not include any work to oppose SSJID’s municipalization efforts. However, SSJID also acknowledged that PG&E may continue to respond to SSJID’s municipalization efforts in other forums and proceedings separate from the regionalization proceeding and/or implementation of the Updated Regionalization Proposal.
VCE filed comments on the Motion for approval of the settlement jointly with Pioneer Community Energy that were critical of PG&E’s Updated Proposal and the settlement. VCE and Pioneer recommended that the CPUC reject the settlement and require changes to PG&E’s Updated Proposal, including alignment with the boundaries of regional councils of governments (COGs) and requirements to coordinate with COGs, the development of metrics to measure PG&E’s progress on key safety and customer relations issues, greater coordination between PG&E and CCAs, and improvements to the Regionalization Stakeholder Group to expand its access and efficacy.
Details: On April 18, the ALJ filed a Proposed Decision that would approve the MPSA in part, approve the PG&E/SSJID Settlement Agreement in totality, and close the proceeding.
The PD, if adopted by the Commission, would:
• Allow participation in the Regionalization Working Group (RWG) by any interested party rather than just parties to the proceeding, as suggested in comments by VCE and other parties.
• Have the RWG serve as an oversight function in PG&E’s implementation of regionalization providing PG&E additional perspectives during implementation, but not provide the RWG any decision-making authority.
• Not address metrics, including those related to safety, property damage, reliability, customer needs, etc., on the grounds that such metrics are outside the scope of this proceeding. • Create five regions defined by county boundaries.
• Add between $24.6 and $32.6 million in incremental costs. 49 22
Analysis: The implications of PG&E’s regionalization plan on CCA operations, customers, and costs remain largely unclear following the proposed MPSA. PG&E’s regionalization plan could impact PG&E’s responsiveness and management of local government relations and local and regional issues, such as safety, that directly impact VCE customers. It could also impact municipalization efforts, although the pending SSJID settlement agreement stated that PG&E’s regionalization efforts will not be in opposition to SSJID’s municipalization. As part of Region 2, VCE would be grouped with several northern counties in central and eastern California. The Proposed Decision did not address most of the comments made by VCE and Pioneer regarding the inefficacy of the Updated Proposal, suggestions for greater transparency and responsiveness, or alignment of regional boundaries with COGs.
Next Steps: Opening Comments on the Proposed Decision are due May 9, and Reply Comments are due May 16. The Proposed Decision may be heard by the Commission, at the earliest, on May
19. Additional Information: Proposed Decision (April 18, 2022); Joint Motion for approval of Settlement Agreements (August 31, 2021); Ruling granting schedule modification (August 20, 2021); Ruling denying evidentiary hearing (July 28, 2021); PG&E Joint Case Management Statement (July 20, 2021); Amended Scoping Memo and Ruling (June 29, 2021); PG&E Updated Regionalization Proposal (February 26, 2021); Ruling modifying procedural schedule (December 23, 2020); Scoping Memo and Ruling (October 2, 2020); Application (June 30, 2020); A.20-06-011.
Provider of Last Resort Rulemaking
Comments on the March 7 workshop to discuss the proposed framework for considering the issues and recommendations resulting from the previous Phase 1 workshop were filed April 15.
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. CalCCA’s comments urged a more pragmatic approach based on recent actual experience of customer returns and an evidence-based examination of the actual risks of customer returns to addressing POLR issues. Some of CalCCA’s proposals include 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, providing for recovery of financing costs if the POLR must pay for costs prior to receipt of revenues from customer returns, refining the implementation planning process for new CCAs, and implementing a three-tiered reporting rubric calibrated to the operating CCA’s circumstances.
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PG&E’s comments on the first workshop included a proposal for an insurance pool to ensure liquidity equal to about two months incremental energy procurement costs for the POLR with each CCA posting its annual contribution to the insurance pool in the form of either cash or a letter of credit, and a proposed initial set of metrics for monitoring the financial health of CCAs that the company recommended be further developed and refined through a workshop process or with other stakeholder feedback.
Details: The primary issues raised in comments to Workshop 2 were:
• Applicability of POLR to Electric Service Providers (ESPs): Both CalCCA and TURN argue that there is no basis for excluding ESPs from any POLR obligations adopted by the Commission since ESPs are subject to the same market conditions that cause CCA defaults. • Upfront Liquidity: PG&E expressed the need for upfront liquidity equal to two months of POLR costs and estimated the cost of providing energy-only service for two months to CCA customers in its territory at between $200 and $400 million. CalCCA estimated the costs for two months of CAISO service if all CCA customers statewide returned their load to POLR service to be about $800 million, and recommended that risks be defined not only by their costs but also by their probability of occurrence since it is very unlikely that all or even a majority of CCAs would fail simultaneously and “failing to account for the probability of an event will significantly over-securitize the risk at the expense of customers.” • Right of First Refusal (ROFR) or Novation: There are differences among the parties regarding both the need for the costs and benefits of resources procured by a failing LSE to follow those customers returned to POLR service, and the mechanism by which those resources might follow customers.
Other topics discussed include the mechanism of the FSR, mechanisms for financial monitoring, and the possibility of a statewide not-for-profit central entity to manage POLR.
Analysis: This proceeding could impact VCE in several ways. First, in establishing rules for existing POLRs, it will address POLR service requirements, cost allocation, and cost recovery issues should a CCA or other LSE discontinue supplying customers resulting in the need for the POLR to step in to serve those customers. Second, in setting the requirements and application process for another entity to be designated as the POLR, it could create a pathway for a CCA or other retail provider to elect to become a POLR for its service area. The preliminary questions (Appendix B to the OIR) suggest these issues will include examining topics such as CCA financial security requirements, portfolio risk and hedging, CCA deregistration, CCA mergers, and CCA insolvency.
Next Steps: The CPUC indicated in an April 21 email that a forthcoming ruling will both seek party comment on additional issues, including modifications to the Financial Security Requirements, reentry fees and deregistration process, and include or be accompanied by an update to the Phase 1 proceeding schedule. Some parties have recommended an additional workshop or technical conference.
Additional Information: POLR webpage with workshop presentations and videos; Ruling rescheduling second workshop date (February 24, 2022); Ruling setting second workshop and comment period (December 31, 2021); Ruling requesting comments (November 23, 2021); Golden State Power Cooperative Motion to remove cooperatives as respondents (October 28, 2021); Scoping Memo and Ruling (September 16, 2021); Ruling scheduling prehearing conference (April 30, 2021); Order Instituting Rulemaking (March 25, 2021); Docket No. R.21-03-011.
PG&E 2020 ERRA Compliance
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On April 27, the CPUC issued a Final Decision approving the Settlement Agreement, approving all uncontested requests in PG&E’s Application, and concluding Phase 1. Phase 2 of the proceeding, which remains open, will address issues related to unrealized sales and revenues resulting from PG&E’s Public Safety Power Shutoff events in 2020.
Background: The annual Energy Resource Recovery Account (ERRA) Compliance proceeding reviews the utility’s compliance with CPUC-approved standards for generation procurement and cost recovery activity occurring in the preceding year, such as energy resource contract administration, least-cost dispatch, fuel procurement, and balancing account entries.
The June 2021 Scoping Memo and Ruling specifies the proceeding will be divided into two phases.
Phase 1 addressed approval of PG&E’s generation procurement and cost recovery activity during 2020. 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 Phase 2 issues includes whether sales forecasting methods for adjusting the revenue requirement under current decoupling policy should be modified 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.
Settlement Agreement: 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, 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 Portfolio Allocation Balancing Account (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.
PG&E is also required to include further testimony in their 2021 Compliance case describing the actions that PG&E has taken to address the deficiencies reported in its Internal Audit Report on the PABA; an internal audit closure document with details of PG&E’s implementation of any action plans to address the deficiencies reported in the Internal Audit Report; testimony from its Chief Regulatory Officer on the actions that PG&E will take or has taken to ensure that there is proper accounting and recording of entries in the various balancing and memorandum accounts review in the ERRA compliance proceedings, including, but not limited to, the PABA.
Details: The CPUC issued D.22-04-041 on April 27 concluding Phase 1. In the Final Decision, the CPUC found that PG&E meets the standard for compliance under the Energy Resources Recovery Account (ERRA) regulatory compliance process for the 2020 record year. The decision approved the Settlement Agreement which resolved all the contested issues and approved all of PG&E’s uncontested requests.
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 52 25
2020. It also determines 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 has concluded. The proceeding remains open to consider issues in Phase 2, schedule TBD.
Additional Information: D.22-04-041 on Phase 1 (April 27, 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’s 2019 ERRA Compliance
On April 6, the ALJ issued a Ruling requesting additional information from the IOUs and amending the procedural schedule.
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 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 recommended 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.
53 26
• 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.
Next Steps: Opening Briefs are due May 27; Reply Briefs are due June 17.
Additional Information: 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.
Utility Safety Culture Assessments
On April 28, the ALJ issued a Scoping Ruling that indicated the proceeding will be divided into more than one phase and determined the scope and schedule for Phase 1. Phase 1 will focus on developing safety culture assessments for the large investor-owned electric and natural gas corporations. Phase 2 will focus on developing safety culture assessments for the small multi-jurisdiction utilities and the gas storage operators.
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. The AB 1054 assessments are specific to wildfire safety efforts and include a workforce survey, organizational self-assessment, supporting documentation, and interviews. SB 901 directs the CPUC to establish a safety culture assessment for each electrical corporation, conducted by an independent third-party evaluator. SB 901 also requires that the CPUC set a schedule for each assessment, including updates to the assessment, at least every five years, and prohibit the electrical corporations from seeking reimbursement for the costs of the safety culture assessments from ratepayers.
This proceeding will implement the statutory requirements of SB 901 relating to the Commission’s assessment of safety culture for regulated utilities, examine what methodologies should be employed in the safety culture assessments to ensure results are comparable across IOUs and can measure changes in IOU safety culture over time, consider requiring that IOUs implement specific safety management practices to improve safety culture through adoption of a Safety Management System 54 27
standard, consider adopting a maturity model to use in safety culture assessments, and determine accountability metrics.
The Prehearing Conference discussed the adoption of a definition of “safety culture” by the Commission, the scope and mechanisms that should be adopted in a safety culture assessment framework, the schedule and process to be applied to safety culture assessments, and metrics and methodologies for measuring safety culture change.
Details: On April 28, the ALJ issued a Scoping Ruling that indicated the proceeding will be divided into more than one phase and determined the scope and schedule for Phase 1. Phase 1 will focus on developing safety culture assessments for the large investor-owned electric and natural gas corporations. Phase 2 will focus on developing safety culture assessments for the small multi-jurisdiction utilities and the gas storage operators.
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 that is 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.
Analysis: This rulemaking will assess the safety culture of PG&E and other IOUs in California. 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 series of Technical Working Group meetings will be held in June and July 2022, followed by a Staff Proposal in August 2022.
• June 2022: Safety Policy Division Technical Working Group Meetings #1 and #2 • July 2022: Safety Policy Division Technical Working Group Meetings #3 and #4 • TBD: All Party Consensus Workshop on Technical Working Group Topics • August 2022: ALJ Ruling issuing Safety Policy Division Staff Proposal for Conducting Safety Culture Assessments and the Maturity Model for the Large Investor-Owned Electric and Natural Gas Corporations
• 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: 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.
RA Rulemaking (2021-2022)
The CPUC issued D.22-04-043 on April 27 denying OhmConnect’s September 2021 Petition for Modification and closing the rulemaking.
Background: This proceeding addressed Resource Adequacy (RA) requirements and structure.
D.20-12-006, issued December 2020, addressed the issues of the financial credit mechanism and competitive neutrality rules for the Central Procurement Entities (CPEs). It approved CalCCA’s proposed “Option 2,” with modifications, which allows the CPE to evaluate the shown resource 55 28
alongside bid resources to assess the effectiveness of the portfolio. D.21-06-029 (issued June 2021) adopted local capacity requirements for 2022-2024, flexible capacity requirements for 2022, and refinements to the RA program. It adopted a series of changes to the Maximum Cumulative Capacity (MCC) buckets, which function as limits on the amount of RA that may be procured from resources with different characteristics.
Details: The CPUC issued D.22-04-043 on April 27 denying OhmConnect’s September 2021 Petition for Modification and closing the rulemaking.
Analysis: Increasing the demand response cap, as OhmConnect requested and CCAs and others supported, would allow LSEs like VCE to procure a higher percentage of demand response resources to meet RA obligations than is currently allowed under the RA compliance rules. Any future proposals to broadly increase the demand response cap will require consideration of how doing so will affect grid reliability.
Next Steps: This proceeding is now closed.
Additional Information: D.22-04-043 denying OhmConnect’s September 2021 petition (April 27, 2022); OhmConnect’s Petition for Modification (September 9, 2021); D.21-07-014 on restructuring the RA program with PG&E Slice of Day proposal (July 16, 2021); D.21-06-029 adopting local capacity obligations for 2022-2024, flexible capacity obligations for 2022, and refinements to the RA program (approved June 24, 2021); 2019 Resource Adequacy Report (March 19, 2021); Scoping Memo and Ruling for Track 3B and Track 4 (December 11, 2020); D.20-12-006 on Track 3.A issues (December 4, 2020); D.20-06-031 on local and flexible RA requirements and RA program refinements (June 30, 2020); Order Instituting Rulemaking (November 13, 2019); Docket No. R.19- 11-009.
PG&E 2022 ERRA Forecast
On April 27, PG&E’s request for an extension from May 15 to May 31 to file its 2023 ERRA Forecast was granted. On February 11, the CPUC issued D.22-02-002, resolving all issues and closing the proceeding; however, an Application for Rehearing remains pending.
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 June 1, 2021, PG&E filed its 2022 ERRA Forecast application, requesting a 2022 ERRA forecast revenue requirement for ratesetting purposes of $4.736 billion. After accounting for $2.479 billion of Utility Owned Generation (UOG)-Related Costs and amounts related to capped 2020 departing load PCIA rates addressed in D.20-12-038, PG&E is requesting a revenue requirement request in this application of $2.263 billion.
PG&E’s Fourth Supplemental Testimony included both an “October Update” and a “December Update.” A group of CCA parties recommended in comments that the CPUC adopt the proposed forecasted revenue requirements and associated rates from the December Update and requested the rates be implemented by February 1, 2022. The CCA parties said that adopting the December update would reduce likely volatility between 2022 and 2023 rates and that adoption of an October Update would clearly violate State law and Commission precedent. The CCAs noted that PG&E’s forecasted costs to serve load in 2022 are 66.5% higher than in 2021.
CalCCA, the Joint CCAs, PG&E, and other parties support a 12-month amortization of the revenue requirements. In contrast, the California Large Energy Consumers Association, Agricultural Energy 56 29
Consumers Association, and California Farm Bureau Federation advocate for a 24-month amortization period.
Details: D.22-02-002 approved a 2022 forecast of electric sales and energy procurement revenue requirements of $2.4 billion, effective in rates on March 1. It found the December Update, updated again with the actual year end ERRA-main account balance provided the most accurate forecast for 2022 revenue requirements, and approved the 12-month amortization that was supported by CCAs.
Under the December Update adopted in D.22-02-002, the 2022 total PCIA rate for 2017-vintaged customers (i.e., most VCE customers) will fall 59% relative to 2021 to $0.01969/kWh for residential customers and to $0.01897/kWh on a system-average basis. The Decision also found that all customers who were financially responsible for the ERRA-PCIA Financing Subaccount (ERRA-PFS) balance should be entitled to the appropriate credit and directed PG&E to transfer the $95 million ERRA-PFS credit for 2022 to the 2020 vintage subaccount. It approved a request by CCAs and directed PG&E to include the confidential workpapers supporting the PCIA rates from the prior year’s ERRA Forecast proceeding as part of the Master Data Request it will provide in each subsequent ERRA Forecast proceeding. D.22-02-002 denied without prejudice the CCA’s request to direct PG&E to provide data demonstrating its future role as a CPE in future ERRA forecast proceedings.
On March 14, the California Large Energy Consumers Association and Agricultural Energy Consumers Association filed an Application for Rehearing (AFR) of D.22-02-002. The AFR argues that the Commission should have adopted a 24-month amortization period for the undercollected ERRA balance. PG&E filed its response to the AFR on March 29, defending the use of a 12-month amortization period. The Commission has not yet acted on the AFR.
Analysis: D.22-02-002 results in a 59% reduction to VCE’s PCIA rates in 2022 compared to 2021.
While the PCIA rate will fall substantially in 2022 for VCE customers, the non-RPS benchmarks that contributed to the reduction in the PCIA in 2022 could result in the opposite effect in 2023. That is, the same high benchmarks that helped reduce the 2022 forecast case may be too high compared to next year’s actuals, which would create large Portfolio Allocation Balancing Account (PABA) undercollection balances for 2023 rates. The change in the PCIA rate from the December Update will help mitigate such a swing in rates in 2023. D.22-02-002 also improves transparency by requiring PG&E to provide confidential workpapers supporting the PCIA rates from the prior year’s ERRA Forecast proceeding as part of the Master Data Request it will provide in each subsequent ERRA Forecast proceeding.
Next Steps: PG&E’s 2023 ERRA Forecast will be filed May 31. The proceeding is now closed.
However, as described above, an application for rehearing is pending.
Additional Information: Application for Rehearing (March 15, 2022); D.22-02-002 (February 11, 2022); Ruling modifying procedural schedule (January 14, 2022); Ruling directing PG&E to provide amortization scenarios (December 17, 2021); Scoping Memo and Ruling (August 11, 2021); Notice of Prehearing Conference (July 15, 2021); Application (June 1, 2021); Docket No. A.21-06-001.
RA Rulemaking (2019-2020)
No updates this month.
Background: This proceeding had three tracks, which have now concluded. Track 1 addressed 2019 local and flexible Resource Adequacy (RA) capacity obligations and several near-term refinements to the RA program. D.19-10-020 purported to affirm existing RA rules regarding imports but adopted a distinction in the import RA compliance requirements for resource-specific and non-resource specific contracts and required, for the first time, that non-resource-specific resources self-schedule (i.e., bid as a price taker) in the CAISO energy market. D.20-06-028 adopted revisions to the Resource Adequacy import rules based on the Energy Division’s proposal, with modifications. 57 30
In Track 2, the CPUC adopted multi-year Local RA requirements and initially declined to adopt a central buyer mechanism (D.19-02-022 issued March 4, 2019).
The second Track 2 Decision, D.20-06-002, adopted implementation details for the central procurement of multi-year local RA procurement to begin for the 2023 compliance year in the PG&E and SCE (but not SDG&E) distribution service areas, including identifying PG&E and SCE as the central procurement entities for their respective distribution service areas and adopting a hybrid central procurement framework. The Decision rejected a settlement agreement between CalCCA and seven other parties that would have created a residual central buyer structure and a multi-year requirement for system and flexible RA. Under D.20-06-002, if an LSE procures its own local resource, it may (1) sell the capacity to the CPE, (2) utilize the resource for its own system and flexible RA needs (but not for local RA), or (3) voluntarily show the resource to meet its own system and flexible RA needs, and reduce the amount of local RA the CPE will need to procure for the amount of time the LSE has agreed to show the resource. Under option (3), by showing the resource to the CPE, the LSE does not receive one-for-one credit for shown local resources. A competitive solicitation (RFO) process will be used by the CPEs to procure RA products. Costs incurred by the CPE will be allocated ex post based on load share, using the Cost Allocation Mechanism (CAM).
D.20-06-002 also established a Working Group (co-led by CalCCA) to address: (a) the development of a local capacity requirements reduction crediting mechanism, (b) existing local capacity resource contracts (including gas), and (c) incorporating qualitative and possible quantitative criteria into the RFO evaluation process to ensure that gas resources are not selected based only on modest cost differences.
In Track 3, D.19-06-026 adopted CAISO’s recommended 2020-2022 Local Capacity Requirements and CAISO’s 2020 Flexible Capacity Requirements and made no changes to the System capacity requirements. It established an IOU load data sharing requirement, whereby each non-IOU LSE (e.g., CCAs) will annually request data by January 15 and the IOU will be required to provide it by March 1. It also adopted a “Binding Load Forecast” process such that an LSE’s initial load forecast (with CEC load migration and plausibility adjustments based on certain threshold amounts and revisions taken into account) becoming a binding obligation of that LSE, regardless of additional changes in an LSE’s implementation to new customers.
Details: The proceeding remains open but is inactive.
Analysis: D.22-02-008 upheld the CPUC’s prior decision (D.20-06-002), which established a CPE.
Moving to a CPE beginning for the 2023 RA compliance year impacted VCE’s local RA procurement and compliance, including affecting VCE’s three-year local RA requirements as part of the transition to the central procurement framework. Eventually, it will eliminate the need for monthly local RA showings and associated penalties and/or waiver requests from individual LSEs, but it also eliminates VCE’s autonomy with regard to local RA procurement and places it in the hands of PG&E.
Next Steps: The proceeding remains open but is inactive. Remaining RA issues will be addressed in the successor RA rulemakings.
Additional Information: D.22-02-008 denying WPTF’s Application for Rehearing (February 11, 2022); D.20-09-003 denying PFMs filed by PG&E, CalCCA, and Joint Parties (September 16, 2020); WPTF’s Application for Rehearing of D.20-06-028 (August 5, 2020); WPTF’s Application for Rehearing of D.20-06-002 (July 17, 2020); D.20-06-028 on Track 1 RA Imports (approved June 25, 2020); D.20-06-002 establishing a central procurement mechanisms for local RA (June 17, 2020); D.20-03-016 granting limited rehearing of D.19-10-021 (March 12, 2020); D.20-01-004 on qualifying capacity value of hybrid resources (January 17, 2020); D.19-12-064 granting motion for stay of D.19- 10-021 (December 23, 2019); D.19-10-021 affirming RA import rules (October 17, 2019); D.19-06- 026 adopting local and flexible capacity requirements (July 5, 2019); Docket No. R.17-09-020. 58 31
2022-2023 Wildfire Fund Nonbypassable Charge Rulemaking No updates this month.
Background: This rulemaking continues to implement AB 1054, which extended a nonbypassable charge (NBC) on ratepayers to fund the Wildfire Fund. The CPUC issued D.20-12-024 in December 2020 that continues the Wildfire NBC amount of $0.00580/kWh for January 1, 2021, through December 31, 2021. On December 6, 2021, the CPUC issued D.21-12-006 adopting a Wildfire Fund nonbypassable charge of $0.00652/kWh for January 1 through December 31, 2022.
Details: The 2022 Wildfire Fund NBC is $0.00652/kWh, up from $0.0058/kWh in 2021. The reason for this increase is that the Department of Water Resources (DWR) demonstrated a collection shortfall of $13.0 million for 2021 and $85.0 million for 2020 (due largely to a lag in initiating and remitting IOU collections for the Wildfire Fund NBC to DWR at the outset of the Wildfire Fund NBC’s existence). Therefore, because of this total $98.0 million under-collection in 2020 and 2021, the 2022 Wildfire Fund NBC is obliged to collect both this 2020-2021 shortfall and 2022’s necessary revenue requirement of $902.4 million.
Analysis: VCE customers will pay the 2022 and 2023 Wildfire Fund NBC amounts established in this proceeding. The charge for 2022 is increasing due to an under-collection of the revenue requirement in 2021 that has been added to the revenue requirement for 2022.
Next Steps: 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.
Additional Information: D.21-12-006 on Wildfire NBC for 2022 (December 6, 2021); Ruling requesting comments on 2022 Wildfire Fund NBC (September 8, 2021): Scoping Memo and Ruling (June 8, 2021); Order Instituting Rulemaking (March 10, 2021); Docket No. R.21-03-001.
Investigation into PG&E’s Organization, Culture and Governance (Safety OII)
No updates this month.
Background: On December 21, 2018, the CPUC issued a Scoping Memo opening the next phase of an ongoing investigation into whether PG&E’s organizational culture and governance prioritize safety. This current phase of the proceeding is considering alternatives to current management and operational structures for providing electric and natural gas in Northern California.
A July 2020 ALJ Ruling described the issues that are potentially still in scope for this proceeding, which include a broad array of issues identified in the December 21, 2018, Scoping Memo, as modified by D.20-05-053 approving PG&E's reorganization plan, plus the ongoing work of NorthStar, the consultant monitoring PG&E. However, the Ruling observed that "it is not clear as a practical matter how many of those issues can be or should be addressed at this time," given PG&E is now implementing its reorganization plan and has filed its application for regional restructuring. Party comments did not explicitly raise the issue of CCA proposals to purchase PG&E electric distribution assets.
A September 4, 2020, Ruling determined that I.15-08-019 will remain open as a vehicle to monitor the progress of PG&E in improving its safety culture, and to address any relevant issues that arise, with the consultant NorthStar continuing in its monitoring role of PG&E.
In April 2021, the CPUC issued Resolution M-4852, placing PG&E into the first of six steps of the Enhanced Oversight and Enforcement process. On August 18, 2021, CPUC President Batjer sent a letter to PG&E stating that she has directed CPUC staff to investigate whether to advance PG&E further within the Enhanced Oversight and Enforcement process. President Batjer’s letter to PG&E 59 32
identified “a pattern of self-reported missed inspections and other self-reported safety incidents,” concluding that “this pattern of deficiencies warrants the fact-finding review.” PG&E self-reported missed inspections of hydroelectric substations, distribution poles, and transmission lines. PG&E also reported missing internal targets for enhanced vegetation management and failing to identify dry rot in distribution poles treated with Cellon coating. Many of these issues occurred in High Fire Threat District areas.
On October 25, 2021, President Batjer sent a letter to PG&E asserting that PG&E’s “execution and communication of its wildfire mitigation device setting known as Fast Trip has been extremely concerning and requires immediate action to better support customers in the event of an outage.” It finds that since PG&E initiated the Fast Trip setting practice on 11,500 miles of lines in High Fire Threat Districts in late July, it has caused over 500 unplanned power outages impacting over 560,000 customers. It goes on to say that these Fast Trip-caused outages occur with no notice and can last hours or days. The letter goes on to outline near-term and ongoing transparency and accountability actions, as well as cost tracking.
Details: No updates this month.
Analysis: The August 18, 2021, and October 25, 2021, CPUC letters to PG&E indicate the CPUC has significant concerns with PG&E’s outages related to both Public Safety Power Shutoff (PSPS) events and its implementation of Fast Trip. Unlike a PSPS event, by definition, Fast Trip settings do not allow for advance notice to customers of an outage.
Next Steps: The proceeding remains open, but there is no procedural schedule at this time.
Additional Information: Letter from President Batjer to PG&E on Fast Trip issues (October 25, 2021); Letter from President Batjer to PG&E (August 18, 2021); Resolution M-4852 (April 15, 2021); Letter from President Batjer to PG&E (November 24, 2020); Ruling updating case status (September 4, 2020); Ruling on case status (July 15, 2020); Ruling on proposals to improve PG&E safety culture (June 18, 2019); D.19-06-008 directing PG&E to report on safety experience and qualifications of board members (June 18, 2019); Scoping Memo (December 21, 2018); Docket No. I.15-08-019.
Direct Access Rulemaking
No updates this month.
Background: In Phase 1 of this proceeding, the CPUC allocated the additional 4,000 GWh of Direct Access load to non-residential customers required by SB 237 (2018, Hertzberg) among the three IOU territories with implementation to begin January 1, 2021.
In Phase 2, the CPUC issued D.21-06-033 recommending against any further Direct Access expansion at this time based primarily on a concern that doing so "would present an unacceptable risk to the state’s long-term reliability goals." It observed that after considering recent reliability events (i.e., the summer 2020 heat storm and resulting rolling blackouts in California and February 2021 outage event and skyrocketing electricity prices in Texas) and IRP forecasts for additional generation, expanded direct access would result in further system fragmentation that raises serious electric system reliability concerns.
Several parties, including the Alliance for Retail Energy Markets and the Direct Access Customer Coalition, filed an Application for Rehearing of D.21-06-033 in July 2021.
Details: The Application for Rehearing remains pending, otherwise the proceeding is inactive.
Analysis: This proceeding determined the CPUC’s recommendations to the Legislature regarding the potential future expansion of Direct Access in California. D.21-06-033 recommendation against 60 33
expansion of Direct Access at this time could reduce the risk of load migration from CCAs (or IOUs) to ESPs.
Next Steps: The only remaining item to be addressed in this proceeding is the Application for Rehearing filed by direct access advocates.
Additional Information: CalCCA Response to Application for Rehearing (August 13, 2021); Application for Rehearing of D.21-06-033 (July 29, 2021); D.21-06-033 recommending against direct access expansion (approved June 24, 2021); Ruling and Staff Report (September 28, 2020); Amended Scoping Memo and Ruling adding issues and a schedule for Phase 2 (December 19, 2019); Docket No. R.19-03-009; see also SB 237.
Glossary of Acronyms
AB Assembly Bill
AET Annual Electric True-up
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
MCC Maximum Cumulative Capacity
OII Order Instituting Investigation
OIR Order Instituting Rulemaking
PABA Portfolio Allocation Balancing Account
PFM Petition for Modification
61 34
PCIA Power Charge Indifference Adjustment
POLR Provider of Last Resort
PSPS Public Safety Power Shutoff
PUBA PCIA Undercollection Balancing Account
PURPA Public Utility Regulatory Policies Act of 1978 (federal) QC Qualifying Capacity
QF Qualifying Facility under PURPA
RA Resource Adequacy
ReMAT Renewable Market Adjusting Tariff
RPS Renewables Portfolio Standard
TOU Time of Use
TURN The Utility Reform Network
UOG Utility-Owned Generation
WMP Wildfire Mitigation Plan
WSD Wildfire Safety Division (CPUC)
62 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 April 28, 2022 Meeting Summary DATE: May 12, 2022
This report summarizes the Community Advisory Committee’s meeting held via Zoom webinar on Thursday, April 28, 2022.
A. Reviewed and considered making a recommendation to the Board on approving Phase 1 of VCE’s Electric Vehicle Rebate Pilot Program. Staff presented highlights of the program design, implementation and fiscal impacts of Phase 1 of the Electric Vehicle (EV) Rebates program which is focused on stacking VCE’s rebate on top of other available rebates and tax credits. The CAC discussed with Staff: potential caps on the distribution of funds to non-low-income customers, future phases of the program, outreach efforts, target audiences, eligibility, and market demand study. After Staff received additional feedback and suggestions, the CAC recommended that the Board adopt Phase 1 of VCE’s Electric Vehicle Rebate Pilot Program (7-0-0).
B. Received information on VCE load and power costs forecasting. Staff provided a summary on load and power costs used to forecast VCE’s energy, resource adequacy (RA), renewable portfolio standard positions, as well as multiple regulatory filings. Staff reviewed retail load by customer class, historical temperature data within VCE’s territory, impact of electric vehicle adoption and building electrification, load forecast process and submittals, implications of an inaccurate forecast, and power cost modeling. The CAC asked questions and discussed with Staff: forecast reconciliation, fulfilling and meeting load profile, how “seasonality” and weather , such as heat waves and/or unanticipated warmer temperatures during the fall/winter, are incorporated within forecast, frequency of adjustments, program planning to reduce customer electricity usage during peak hours, short term energy prices, net energy metering, and electric vehicle to grid integration.
Staff will present information on forecasting - revenues and budget at the CAC’s May meeting.
63 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: Customer Dividend and Programs Allocation Report DATE: May 12, 2022
RECOMMENDATIONS
Informational Report
OVERVIEW
The Board adopted the VCE Rate Structure & Dividend Program Guidelines on June 17, 2019, to be effective starting at the beginning of the following fiscal year on July 1, 2019. The FY 2021/22 (6-month) audited financials resulted in a net loss of $3.1M for the fiscal year ending on December 31, 2021. The annual net loss of $3.1M for FY 2021/22 did not meet the threshold (profitability) to allocate reserves to customer dividend(s) and the local program reserve.
CONCLUSION
No cash reserve allocation will be contributed to customer dividends and the local program reserve.
64 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: Reaffirm Participation in CC Power Tumbleweed Energy Storage Project DATE: May 12, 2022
Recommendation
Reaffirm via Resolution authorization for the Executive Officer to execute on behalf of Valley Clean Energy as a member of California Community Power (CC Power) the following agreements and any necessary ancillary documents for the Tumbleweed long duration storage project with a delivery term of 15 years starting at the commercial operation date on or about June 1, 2026:
a. Project Participation Share Agreement between Valley Clean Energy, California Community Power and other participating CCAs
b. Buyer Liability Pass Through Agreement between Valley Clean Energy, California Community Power and Tumbleweed Energy Storage, LLC.
Background
On February 10, 2022, the Board at their regular meeting authorized the Interim General Manager to execute on behalf of Valley Clean Energy as a member of CC Power to participate in the Tumbleweed long duration storage project. See February 10, 2022 Item 14 Staff Report for further details. A resolution documenting the Board’s authorization to participate was not included with the Staff Report.
Subsequently, at the Board’s March 10, 2022, the Interim General Manager Mitch Sears was appointed as VCE’s Executive Officer.
Conclusion
The attached resolution reaffirms VCE’s participation in the Tumbleweed long duration storage project and authorizing the Executive Officer to execute the necessary documents.
Attachment
1. Resolution 2022-XX Reaffirm participation in the CC Power Tumbleweed Project 65 Item 11
VALLEY CLEAN ENERGY ALLIANCE
RESOLUTION NO. 2022- _______
A RESOLUTION OF THE BOARD OF DIRECTORS OF THE VALLEY CLEAN ENERGY ALLIANCE
REAFFIRMING THE APPROVAL OF THE FOLLOWING AGREEMENTS AND ANY NECESSARY
ANCILLARY DOCUMENTS FOR THE TUMBLEWEED LONG DURATION STORAGE PROJECT AND
AUTHORIZING THE EXECUTIVE OFFICER IN CONSULTATION WITH LEGAL COUNSEL TO FINALIZE AND EXECUTE THE AGREEMENTS: 1) PROJECT PARTICIPATION SHARE AGREEMENT
BETWEEN VALLEY CLEAN ENERGY ALLIANCE, CALIFORNIA COMMUNITY POWER AND OTHER PARTICIPATING CCAs, 2) BUYER LIABILITY PASS THROUGH AGREEMENT
BETWEEN VALLEY CLEAN ENERGY ALLIANCE, CALIFORNIA COMMUNITY POWER AND
TUMBLEWEED ENERGY STORAGE, LLC
WHEREAS, VCE is a member of California Community Power (CC Power) joint powers authority; and WHEREAS, VCE in coordination with CC Power conducted a request for offers for long duration storage (LDS) projects and engaged in negotiations for the Tumbleweed project; and WHEREAS, CC Power seeks to execute agreements to effectuate its purchase of its storage resource from the Tumbleweed storage project based on the project’s desirable offering of products, pricing and terms; and
WHEREAS, the Tumbleweed project will contribute to the regulatory requirement to procure LDS for each of the CCAs that are participating in this project through CC Power by providing energy storage resources for a term of fifteen years starting on or about June 1, 2026; and WHEREAS, on February 10, 2022 staff presented to the Board for its review the Energy Storage Services Agreement, Buyer Liability Pass Through Agreement and the Project Participation Share Agreement the Board approved authorization to participate; and,
WHEREAS, on February 10, 2022, the Board approved participation in the CC Power Tumbleweed project; and
WHEREAS, this Resolution reaffirms the Board’s February 10, 2022 action approving participation in the CC Power Tumbleweed project and authorizing its Executive Officer to execute Agreements and any ancillary documents associated with its action.
NOW, THEREFORE, the Board of Directors of the Valley Clean Energy Alliance reaffirms the following:
1. The Executive Officer is authorized to execute the Agreements and any ancillary documents with the Tumbleweed Energy Storage LLC, California Community Power and participating CCAs with the terms generally consistent with those presented, in a form approved by legal counsel 66 Item 11
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
67 Item 14
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 14
To: Board of Directors
From: Mitch Sears, Executive Officer
Rebecca Boyles, Director of Customer Care and Marketing Sierra Huffman, Program and Community Engagement Analyst Subject: Electric Vehicle Rebate Pilot Program
Date: May 12, 2022
______________________________________________________________________________
RECOMMENDATION
Review and approve Phase 1 of Valley Clean Energy’s Electric Vehicle Rebate Pilot Program.
BACKGROUND
Our state has been at the forefront of electric vehicle (EV) adoption in the US. As of June 2021, California’s EV registrations, including plug-in hybrids and battery electric, total 930,811 vehicles. Battery electric vehicles are nearly half of that total, at 425,300. California has an objective to achieve five million zero-emission vehicles (ZEVs) on the road by 2030 as directed in the Executive Order (E.O. B-48-18). In addition, all new cars and passenger trucks sold in California must be ZEVs by 2035 (E.O. N-79-20). Even with the electronic chip shortage and the coronavirus pandemic, the US has seen EV sales nearly double from 308,000 in 2020 to 608,000 in 2021. California was no exception, as gas prices soared, EVs became the most economic option.
Amid the national and statewide movement in transportation electrification, VCE began developing an EV Rebate Pilot Program in mid-2021. The shift in focus from traditional gas vehicles comes with the recognition of the emissions associated with fossil fuel transportation.
The California Air Resources Board identified that nearly 35% of the State’s emissions are from the transportation sector. Understanding what EV adoption could mean for the communities it serves, VCE was motivated to explore the most effective ways to increase local EV adoption.
VCE designed a program that stacks with existing State EV rebates and incentives, providing VCE customers with additional opportunities to off-set the cost of electric and plug-in hybrid vehicles. Initial research and engagement identified that providing customers with greater financial assistance, especially to those of lower income, could increase the adoption rate of EVs by making it a more feasible financial decision.
Considering the complexities that arise from providing rebates or incentives for electric vehicles, staff is recommending that VCE take a phased approach to the pilot. Phase 1 will 68 Item 14
2 embody a simple, streamlined approach that is straightforward to implement and easy for customers to apply. Phase 1 will provide rebates to VCE customers for new electric vehicles who verify that they have received a rebate from the California Vehicle Rebate Project (CVRP).
Low-income applicants will receive a more generous rebate, and higher rebates will be provided to battery EVs as compared to plug-in hybrids. Income criteria and vehicle model eligibility will be based on the CVRP’s program standards. Phase 2 will focus on how best to expand vehicle eligibility to include used vehicles, as well as the added value and feasibility of proving a point-of-sale incentive for electric vehicle purchases.
PROGRAM DESIGN
Staff believes that taking a phased approach to this pilot is the best way to provide value while learning more about the intricacies of providing EV rebates. Phase 1 consists of the following elements:
• Outreach/Education:
o General marketing and specific marketing efforts to reach underserved populations
o Provide program materials in multiple languages;
o Conduct direct outreach to low-income housing facilities; o Promote the pilot program via print and/or radio
Budget: $10k
• Rebate amounts:
o Income-qualified VCE customers would receive $4,000 for any new qualifying battery or plug-in hybrid EV;
o All other eligible VCE customers would receive $2,000 for qualifying new plug-in hybrids or $2,500 for new battery EVs.
Budget: $80k
The EV Rebate Pilot program was designed in consultation with the CAC Programs Task Group and presented to the full CAC at their March and April meetings. The CAC supported the design and provided feedback that outreach to underserved populations should be a priority for the pilot.
Income Qualified Customers
Staff is seeking Board feedback on the following staff recommendations to ensure that income-qualified customers have equitable access to rebates in the pilot:
1. Income-qualified customer applications are given priority over standard applications.
These applications would be in a separate queue and would be processed before standard applications.
2. Income-qualified applicants could fill out a VCE interest form and VCE would consider these rebate funds “on hold” for a period of time providing time for their CVRP application to be processed.
69 Item 14
3 3. 25% of rebate funds in Phase 1 would be reserved for income-qualified applicants. If these reserved funds were not exhausted (or placed “on hold”) in the first 6 months after program launch, the funds would be released for standard applications.
Staff recommends each of the three elements listed above along with the enhanced outreach mentioned earlier in this report. This would ensure that a certain portion of rebate funds would be set aside for income-qualified applications, but if demand is low, those funds will be released for standard applications. Having the ability to release these funds would lessen the risk of concluding phase 1 of the pilot with unused rebate funds.
Existing State Rebate Programs
Three state programs and one regional program are providing financial assistance for EVs:
• Clean Vehicle Assistance Program Grant (CVAP)
• Drive Clean Assistance Program (DCAP)
• California Clean Fuel Reward (CCFR)
• Clean Vehicle Rebate Project (CRVP).
Both the CVAP and DCAP provide grants to income-qualified applicants before they purchase an EV. The CCFR is a small automatic incentive that is provided at purchase through eligible dealerships. The CVRP provides a rebate within three to six months after an EV purchase to customers who make less than the high earners cap, with greater rebates provided to low-income applicants.
Staff recommends aligning the VCE EV Rebate Pilot with the CVRP because it differentiates between low- and mid-high income, tracks that the vehicles are kept for at least 30 months, includes a luxury vehicle cap, and has funding at this time. This is the approach Redwood Coast Energy Authority chose for their EV rebate program, for many of the same reasons cited.
Staff will engage customers by participating in EV related webinars, attending local in-person events, and connecting with customers through collateral such as web materials, social media, advertising, and printed information. Webinars/in-person events give customers the opportunity to ask questions about navigating the many rebates and incentives, as well as cover topics on owning and maintaining an EV. Marketing collateral would explain the benefits of owning an EV such as reduced or eliminated gas cost, reducing greenhouse gas emissions, and potential vehicle to grid benefits. Emphasis will be put on engaging low-income customers and disadvantaged communities.
FINANCIAL IMPACT
Total proposed pilot program budget is $100,000. This is 57% of the overall VCE programs budget for 2022. A portion of the budget ($10,000) is allocated to marketing, advertising and customer engagement; while the majority ($80,000) would be allocated to rebates. A 10% contingency amount ($10,000), is included to provide flexibility for pilot implementation should demand for rebates be high, consultant program support is needed to supplement staff, etc.
Budget for marketing, advertising, customer engagement and as-needed consultant support would be reallocated to rebates if unused within 6 months of phase 1 launch. 70 Item 14
4 CONCLUSION
On April 28th, the CAC provided program feedback regarding customer eligibility and program equity. In addition to reviewing the program, the CAC supported Staff’s recommendation that the Board approve Phase 1 of the pilot.
ATTACHMENT
Electric Vehicle Rebates Program Design Form
71 Rev. 4/4/22
Program Preliminary Design/Implementation Form
Program Concept: Electric Vehicle (EV) Rebates Pilot
Date: 5/4/22
Staff Resources and Support:
Assigned Program Managers: Rebecca Boyles, Sierra Huffman Programs Task Group members: Marsha Baird, David Springer Consultant names: (potentially; still TBD) SMUD, Jim Parks, Green Ideals Scope: Develop program infrastructure and disburse rebates for Electric Vehicles to qualifying customers until program funds are exhausted. Income-qualified customers are eligible for higher rebates.
Timing: (approximate; pending approval) Announce phase 1 program roll-out after Board approval in Spring 2022. Begin phase 1 of program implementation in May 2022 (pending board approval). Begin providing rebates at the start of implementation, and close rebate application process when funds are exhausted.
Program Design Criteria Evaluation:
Criteria 1 Criteria 2 Criteria 3
Criteria Type Availability of
Funds Staff Time Strategic Plan Alignment
Reasoning
for Program
Score
Scored high; we
have internal
funds set aside
for such
programs
Scored high;
low impact
on staff time.
Multiple
CCAs have
implemented
similar
programs
and found it
easy to do,
requiring
minimal staff
time; and we
would
emulate
these
programs
Scored medium to high on strategic plan alignment:
Reduces GHG Emissions
Higher penetration of EVs in Yolo County would lead to less emissions from transportation
Customer Satisfaction
Addresses an issue of importance to customers as stated in a customer survey
Addresses Environmental Justice
Addresses the needs of the underserved, underprivileged and/or lower-income customers by making EVs more
accessible
Regulatory & Legislative Goals Alignment
Aligns with state goals of increasing penetration of EVs in CA Strategic Partnerships
Level of collaboration with local organizations: we could potentially work with California Air Resources Board, EV dealers, Yolo-Solano Air Quality Management District, low-income communities, community-based organizations, and additional stakeholders
72 Rev. 4/4/22
Program Metrics and Goals:
Metrics: The total number of EVs purchased utilizing VCE’s rebate program; number of EVs purchased and total dollars provided to low-income qualified applicants.
A calculation of avoided or reduced greenhouse gas emissions (GHG) from replacing or substituting gas vehicles with electric transportation. Emissions reductions will be calculated by estimating the number of miles a customer drives annually and comparing the carbon emissions per mile for gas to the emissions per mile for electric. The emissions per mile for electric will derive from the GHG emissions associate with VCE’s energy portfolio. There will be the potential to replace estimates with real customer data on average vehicle miles driven, through optional questions on rebate applications.
Goal: 26 EVs incentivized; including 10 income-qualified recipients Proposed Programs Budget:
Resource Source Proposed Budget $ Remaining in Program Funds Rebates Programs Budget $80,000
Marketing,
Education &
Advertising
Programs Budget $10,000
Consultants (if
applicable)
Programs Budget $10,000
Total $100,000 $124,000
Budget details:
$2,500 rebate for new or leased vehicles (16 rebates if 50% of budget used). Battery Electric Vehicles (BEV) will qualify for the full rebate of $2,500, while Plug-In Hybrid Electric Vehicles (PHEV) will receive $500 less in incentives, totaling to $2,000.
$4,000 rebate for income-qualified customers for new or leased vehicles. Low-income customers will not be subjected to lower incentives for PHEVs versus BEVs. All qualified EVs will be eligible to receive 73 Rev. 4/4/22
the full incentive amount of $4,000. (10 rebates if 50% of budget used). Total of 26 BEV rebates given if funding was split 50/50 income-qualified/not.
Organizational Goals Addressed:
Alignment with VCE’s Strategic Plan? Yes
• Goal 3. Prioritize VCE’s community benefits and increase customer satisfaction and retention and;
o 3.2 Objective: Develop programs and initiatives to better support community goals, including supporting member agency achievement of energy-sector emissions reduction targets.
o 3.5 Objective: Develop customer programs and initiatives that prioritize decarbonization, community resiliency and customer savings.
Phase 1 Program Eligibility:
1. Must be a Yolo County resident and an existing customer of Valley Clean Energy; one rebate per household
2. Must apply and be approved by Valley Clean Energy after being approved for a rebate from the Clean Vehicle Rebate Project
a. Low-income eligibility requirements set by and verified through the Clean Vehicle Rebate Project
3. Purchase an eligible vehicle:
a. New or leased EV
i. Model eligibility set by the Clean Vehicle Rebate Project
1. Includes a luxury vehicle cap, currently set at $45,000 b. Must be a plug-in hybrid or battery powered EV
Application Process:
Applications will be processed on a first-come, first-served basis until the budget is exhausted. If an applicant has been waitlisted by the Clean Vehicle Rebate Project (CVRP) because funds have become temporarily unavailable, VCE will hold program funds for them until their rebate is approved by the CVRP.
Customer applications will be available on VCE website in both English and Spanish. Delivery by email is preferred but applications will also be accepted by mail, fax, or drop-off.
Valley Clean Energy or a contracted 3rd party, will provide application support to our interested customers, as well as help them find information on and apply for additional EV rebates, like the Clean Vehicle Assistance Program and Drive Clean Assistance Program. We encourage all applicants, especially low-income, to apply for additional rebate programs.
74 Rev. 4/4/22
Dispersal of funds:
VCE will write a check using the applicant’s information.
Marketing, Education and Outreach (ME+O) Strategy:
Promote on social media, website, and evaluate cross-promotion with aligned organizations (e.g. RISE, Inc., Mutual Housing, Grid Alternatives, Davis Electric Vehicle Associations). Potential to initiate targeted mail and/or email campaigns, print or radio advertisement campaigns, as well as create marketing materials for use in car dealerships.
Board, CAC, PTG Input:
The Programs Task Group (PTG) has played a fundamental role in the development of this rebate pilot from its conception in early 2021. The PTG supports the pilot’s alignment with the Clean Vehicle Rebate Project.
On April 28th, the CAC provided program feedback regarding customer eligibility and program equity. In addition to reviewing the program, the CAC supported Staff’s recommendation that the Board approve phase 1 of the pilot
Next Steps: Develop full list of eligibility criteria and terms & conditions; expand ME+O materials; implement program.
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77 Return to:
VALLEY CLEAN ENERGY
Valley Clean Energy COMMUNITY ADVISORY COMMITTEE 604 Second Street APPLICATION Davis, CA 95616
PERSONAL DATA SHEET
Received on: Name: Are you at least 18 years old? First Middle Home Address:
Number/Street City/State/Zip Email Address: Daytime Phone Evening/Weekend Phone Business Title or Occupation: Company/Organization: Address: Street Address City, State and Zip Which Valley Clean Energy jurisdiction do you reside in? City of Davis City of Woodland County of Yolo (Unincorporated) If you do not reside in Valley Clean Energy's jurisdictions, please include a separate statement to address why you are applying for this committee.
Are you seeking to fill an At-Large Seat? Yes No
Background Information:
Why do you wish to serve as a member of the VCE Community Advisory Committee? Last
City of Winters
3/30/2022 AML
Jacobs, Kristin, E. yes
Davis CA 95616
Sustainability Manager
Fresno CA 93711
I would like to be apart of California's energy diversification movement and gain connections within the industry. Agriculture makes up a significant portion of California's energy usage but needs more representation within the state's agencies, especially during this time of change. 78 What experience/perspective would you bring to the committee? Please reference the professional sector and related professional experience below for At-Large member applications in this section.
Please list your previous and present governmental and civic experience. Indicate when, position and duties:
List any special training or experience you have that you feel would benefit your committee service:
Being connected to both family and corporate farming operations, I hear and understand multiple viewpoints and I would bring a fresh perspective from large scale agriculture within Yolo, Fresno, Tulare, and other southern counties. I would be able to offer practical feedback from the fields to proposed regulations and initiatives.
I work with influential agricultural companies that are motivated to explore alterative methods of operating that are cheaper, simpler, and more stable that current processes. no direct experience. Attend the Yolo County Sustainable Groundwater Agency meetings.
As an alumni of UC Davis's Sustainable Agriculture and Food Systems program, I was exposed to a broad range of 'sustainability' sectors and theories. Still well connected to the college, I am up to date with ongoing research in multiple areas of study.
79 Do you have any interests or associations which might present a conflict of interest? If yes, please explain:
What do you feel are your most important qualifications? What do you see as some of the significant issues facing the community in the next few years that might pertain to Valley Clean Energy's Community Advisory Committee? No
Working directly with farmers for the last few years have given me direct knowledge of their energy needs and some perspectives about the energy sector. While I understand many perspectives of farmers, I do not necessarily agree with all of them. My ability to understand differing perspectives and communicate clearly with both sides yields willingness to participate in various trials and projects.
Some major issues I foresee are battles between PGE and the state or counties revolving around infrastructure maintenance and/or energy source diversifaction. I can imagine cases being brought up where PGE is not meeting state and/or resident expectations and VCE or similar agency proposes alternative solutions. I believe that as agencies like VCE develop and gain popularity in communities, they will have more resources to provide more options and stronger solutions.
80 What do you hope to accomplish as a committee member? I am aware of the obligations and responsibilities of this committee and am willing and able to fulfill this commitment should I be appointed: (Initial here: ) Please attach your resume or any additional information or statements which you feel would be helpful to the Valley Clean Energy Board of Directors in reviewing your qualifications. AUTHORIZATION AND RELEASE I understand that in connection with this application for appointment, the information contained herein will be made available to the general public upon request. I further understand that if appointed, I may be required to take the oath of office and may be subject to requirements for filing financial disclosure statements.
Please Sign Here Date NOTE: This document is a public record and may be disclosed/released pursuant to the California Public Records Act.
FOR OFFICIAL USE ONLY
Applications will be kept on file for two years. This application will expire on: Date of appointment by the Valley Clean Energy Board: ____________ Length of term: ____________
Is this a re-appointment?
3/30/2024
3/27/22
I hope to help bridge communication between agricultural communities and VCE and similar agencies. Many entities in the agricultural sector have no opposition to alternative energy sources but do not have the time to research such options. Additionally, the agriculture industry has many innovative ideas about energy efficiency and sustainability. However, the majority of the professionals do not have the connections or time to voice their ideas to agencies like VCE.
KJ
81 5/15/2021 AML
Taylor Keith. Andrew Yes
Davis, CA 95616
I am a big advocate of everything the VCE has accomplished. I remain concerned about the subordinate position that all CCAs have with regard to their investor-owned counterparts. I would be of service to VCE and other CCAs as the sector matures, and seeks to achieve parity in the market and policy discourse with the investor-owned counterparts. I would do this by bringing about my applied knowledge of similar initiatives around the U.S., as well as my deep connections to the U.S. electric co-op system (a force multiplier for such consumer-owned utilities). It is also a desire to build-out UC Davis Energy and Efficiency and UC Cooperative Extension programming to connect the sector to third party, university research and development assets.
Asst CE Specialist, Community Economic Development
82 I am actively involved in research and development with the national electric co-operative sector, and seek to bring my knowledge and institutional resources to the California CCA system. Much like the electric co-ops, the CCAs provide for remarkable climate change mitigation practices, and allow the voice of ratepayers to be heard and acted upon in the electricity sector.
It would be my intention to draw-down my theory and practice with the electric and purchasing co-op sectors to assist VCE in enhancing its strategic objectives, and growing its capability to operate independent of major investor-owned utilities over time.
March 2001-January 2003: Legislative Aide, Congressman David Phelps. Provided analyses of key policies and legislation.
April 2010-August 2012: Board Director, Common Ground Food Co-op, Urbana, IL. Governance oversight. Planned and coordinated a major growth campaign.
January 2014 - July 2017: Board Director/Board Chair, Indiana Cooperative Development Center, Indianapolis, IN. Led a strategic planning initiative.
I am trained as a practitioner and research in governance. I am a trained facilitator. I study and have practiced board governance and consumer-stakeholder oriented management. Further, I understand multi-level governance better than most, which is a key asset for VCE as it seeks to more deeply engage with its CCA association in forming new support system organizations. 83 While I do not receive any material benefit, my connections with the electric co-op sector could be seen as a conflict of interest. That said, I currently recieve no compensation for my work with the sector.
As one of the only scholars of electric co-ops, I have deep knowledge of consumer-oriented electric utilities. I have a working and scholarly understanding of multilevel governance, so critical to the operations of the CCA sector. What’s more, I have an understanding of the overlapping forms of governance and contracting necessary for CCAs to operate in California. And in my role with the UC system, I can further assist VCE and the CCAs with accessing experts, policymakers, and industry support systems.
Many of the CCAs have made significant pledges in order to secure public support for their creation. I want to assist VCE in meeting and exceeding their public obligations.
It is also clear there needs to be strong planning for a future where the major investor-owned utilities are in constant economic and climate distress. This then involves developing CCA standalone capabilities to break dependency on the incumbent providers where possible.
Resiliency
84 5/15/2023
First, I would like to assist with the further development of VCE’s long-term strategic plan. I would like to assist VCE layout its full menu of options on everything from carbon neutrality to achieving economies of scale/scope. This then involves the second piece, which is the further development of the CCA system itself. I would like to bring to bear my extensive connections with the national electric co-op system. This involves the third piece, which is connecting VCE and the CCA system to the electric co-op business network on matters such as finance, marketing, customer relations, distributed energy, and other utilities services.
KT
May 15, 2021
85 86
87 88
6/29/2023
89 Return to:
VALLEY CLEAN ENERGY
Valley Clean Energy COMMUNITY ADVISORY COMMITTEE 604 Second Street APPLICATION Davis, CA 95616
PERSONAL DATA SHEET
Received on: Name: Are you at least 18 years old? First Middle Home Address:
Number/Street City/State/Zip Email Address: Daytime Phone Evening/Weekend Phone Business Title or Occupation: Company/Organization: Address: Street Address City, State and Zip Which Valley Clean Energy jurisdiction do you reside in? City of Davis City of Woodland County of Yolo (Unincorporated) If you do not reside in Valley Clean Energy's jurisdictions, please include a separate statement to address why you are applying for this committee.
Are you seeking to fill an At-Large Seat? Yes No
Background Information:
Why do you wish to serve as a member of the VCE Community Advisory Committee? Last
City of Winters
3/6/2022 AML
Samsel Maris Kay Yes
Davis, CA 95616
Environmental Services Intern
Woodland, CA 95695
I am deeply passionate about clean energy as a means to combat the effects of climate change.
I am a steadfast advocate for the environment, and believe the duty of repairing the planet has fallen to my generation. I believe serving on the advisory board would provide me with excellent experience in understanding the implementation of environmental technology, while allowing me to participate in governmental action.
90 What experience/perspective would you bring to the committee? Please reference the professional sector and related professional experience below for At-Large member applications in this section.
Please list your previous and present governmental and civic experience. Indicate when, position and duties:
List any special training or experience you have that you feel would benefit your committee service:
I have experience working in local government, through the lens of environmental services. I am highly involved with policy implementation and logistics. As an intern, I work with a variety of government departments, and oversee my own projects. I believe I have a unique perspective as a student, and as a parent. I am a member of the Davis community, and have a vested interest in its future, as it is where I am raising my family, and getting my education. As a college student, I will be party to the latest scientific information the university system has to offer, and would use that knowledge to supplement my stance on issues presented to me.
I am currently an intern for the City of Woodland Environmental Services, and have been since July of 2021. I have participated in the compilation of the new building project sustainability guide, which was used to create a set of guidelines for the upcoming Tech Park project. I have overseen the implementation of SB 1383, a food waste bill, at the Leisureville senior living association, where I devised a logistical plan to help the residents and staff comply with the new waste bill. I often represent Environmental Services at City events, such as National Night Out and the Honey Festival. I am also the Director of Sustainability at Woodland Community College, where I am part of the New Building Committee as a sustainability advisor, and help to implement new campus sustainability projects. I plan events, such as campaigns and recruitment efforts, for the Associated Students of Woodland Community College, and the WCC Earth Day activities. I speak at district-wide events, such as the Yuba Community College Convoation, alongside WCC President Art Pimentel, and Congressman John Garamendi.
I have participated in theatre and performing arts as an actor, singer, dancer, and director for most of my life. I use this experience to aid in public speaking, and interpersonal skills. I feel that theatre is one of the most cooperative activities one may choose to parttake in, and requires the equal effort and trust of everyone involved. I also participate in a coding and drone flying class at my college, where I assembled my own drone remote, and am learning how to code in Python script, which signals commands to my drone. I believe this experience will help me in the environmental field, as technology progresses, and is relied upon heavily. 91 Do you have any interests or associations which might present a conflict of interest? If yes, please explain:
What do you feel are your most important qualifications? What do you see as some of the significant issues facing the community in the next few years that might pertain to Valley Clean Energy's Community Advisory Committee? I have no interest in conflicting associations.
I believe I have an intuitive ability to empathize with many points of view. I have come from very humble origins, and understand the lives of many, because I have lived in so many ways. I believe my youth gives me the best voice to advocate for what is urgently needed, as Iunderstand there is no allowance for hesitation in the face of climate danger.
I believe one large concern for Davis residents are the blackouts that many people have experienced due to corporate negligence in wildfire territories. Citizens should not have to suffer due to the blatant greed and incompetence of popular energy companies. I also believe that, as the weather in Northern California grows hotter every year, residents will rely exponentially on energy to provide safety and comfort. Above all, I believe that residents of our community crave transparency. People want to be able to trust who they give their money to, and large, for-profit corporations have taken advantage of the pandemic in a wholly unsurprising way. 92 3/6/2024
93