VCE 1/27/22 Board Special Meeting Agenda Page 1 of 4
Special Meeting of the Valley Clean Energy Alliance
Board of Directors
Thursday, January 27, 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 have 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/84342191907
Meeting ID: 843 4219 1907
b. By phone
One tap mobile:
+1-669-900-9128,, 84342191907# US
+1-346-248-7799,, 84342191907# US
Dial:
+1-669-900-9128 US
+1-346-248-7799 US
Meeting ID: 843 4219 1907
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.
1 VCE 1/27/22 Board Special Meeting Agenda Page 2 of 4
Board Members: Dan Carson (City of Davis), Jesse Loren (City of Winters), Don Saylor (Yolo County), Tom Stallard (City of Woodland), Lucas Frerichs (City of Davis), Wade Cowan (City of Winters), Gary Sandy (Yolo County), and Mayra Vega (City of Woodland) 5:00 p.m. Call to Order
1. Welcome
2. Elections of Officers for 2022
3. Public Comment: This item is reserved for persons wishing to address the Board on any VCE-related matters that are not otherwise on this meeting agenda or are listed on the Consent portion of the agenda. Public comments on matters listed on the agenda shall be heard at the time the matter is called. As with all public comment, members of the public who wish to address the Board are customarily limited to two minutes per speaker, electronically submitted comments should be limited to approximately 300 words. Comments that are longer than 300 words will only be read for two minutes. All electronically submitted comments, whether read in their entirety or not, will be posted to the VCE website within 24 hours of the conclusion of the meeting. See below under PUBLIC PARTICIPATION on how to provide your public comment.
CONSENT AGENDA
4. Authorization to continue remote public meetings as authorized by Assembly Bill 361.
5. Approve November 10, 2021 Board special meeting Minutes.
6. Receive 2022 Long Range Calendar.
7. Receive A) Financial Updates – October 31, 2021 and B) November 30, 2021 financials (unaudited) financial statements.
8. Receive Legislative update.
9. Receive January 19, 2022 Regulatory update provided by Keyes & Fox.
10. Receive January 19, 2022 Customer Enrollment update.
11. Receive Community Advisory Committee November 18, 2021 and December 16, 2021 meeting summaries.
12. Receive Community Advisory Committee 2021 Year End Report.
13. Ratify Amendment 26 to the Sacramento Municipal Utilities District Task Order 2 to implement VCE 2022 rate configuration.
14. Receive copy of signed Amendment 3 to Jim Parks Consulting agreement extending term through June 30, 2022.
15. Approve Near-term Procurement Directives and Delegations for 2022 Power Procurement Activities. (Action)
16. Ratify and approve extension of credit agreement to February 28, 2022 with River City Bank. (Action)
17. Adopt 2022 Legislative Platform. (Action)
18. Support of Senate Bill 833 (Dodd). Community Energy Resilience Act of 2022.
19. Approve temporary use of up to $200,000 of the program reserve fund to initiate the Ag FIT (Flexible Irrigation Technology) dynamic pricing pilot. (Action)
20. Ratify GHG Free Attributes for 2022 accepting large hydro and rejecting nuclear. (Action)
2 VCE 1/27/22 Board Special Meeting Agenda Page 3 of 4
REGULAR AGENDA
21. Receive Marketing and Outreach 2021 year-in review presentation. (Informational)
22. Overview of 2022 draft budget and customer rates.
23. 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.
24. Adjournment/Announcement: The Board will convene into closed session. The next regular meeting is scheduled for February 10, 2022 at 5 p.m. via video/teleconference.
CLOSED SESSION
Public comment on the closed session item only will be read at this time.
25. Public Employee Performance Evaluation (Government Code Section 54957 Position Title: Interim General Manager
PUBLIC PARTICIPATION INSTRUCTIONS FOR VALLEY CLEAN ENERGY BOARD OF DIRECTORS SPECIAL MEETING ON THURSDAY, JANUARY 27, 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.
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 3 VCE 1/27/22 Board Special Meeting Agenda Page 4 of 4
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].
4 VALLEY CLEAN ENERGY ALLIANCE
Staff Report - Item 4
____________________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Interim General Manager
Alisa Lembke, Board Clerk/Administrative Analyst
SUBJECT: Authorization to continue Remote Public Meetings as authorized by Assembly Bill 361 DATE: January 27, 2022
Recommendation
VCE Board authorize 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, (a) the COVID-19 pandemic state of emergency is ongoing, and (b) local officials continue to recommend measures to promote social distancing.
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.
5 However, legislative bodies must first find: (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.
On July 29, 2021, the County Health Officer issued the attached Amended Order for Wearing of Face Coverings in Workplaces and Public Settings. Page 3, Section 7 of the Amended Order states that all persons should wear well-fitted face coverings and practice physical distancing. Further, on September 22, 2021, the Health Officer issued the attached memorandum, recommending that all Brown Act bodies continue to meet remotely.
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.
Due to the rise in COVID-19 cases caused by the Delta Variant, on July 29, 2021, the Yolo County Health Officer issued an Amended Order for the Wearing of Face Coverings in Workplaces and Public Settings a recommendation that all Brown Act bodies meet remotely. The Amended Order requires the use of face coverings indoors and states that all persons should continue to protect themselves and others by physical distancing (see Page 3, Section 7). Further, on October 20, 2021 the Health Officer issued a memorandum to the Yolo County Board of Supervisors, reaffirmed their September 22, 2021 memorandum to continue to recommend meetings be held remotely whenever possible.
On January 11, 2022, the Board of Supervisors renewed authorization to continue remote public meetings, pursuant to Assembly Bill 361 and consistent with the attached memorandum from the Yolo County Health Officer dated January 4, 2022, wherein it states the Public Health Officer will continue to evaluate their recommendation and will communicate when there is no longer such a recommendation with respect to meetings for public bodies.
Since it has been more than 30 days since the Board last made findings pursuant to AB 361 on November 10, 2021, it is necessary for the Board to make new findings in order to continue with remote meetings. The highly contagious Omicron Variant continues to spread quickly in Yolo County and the nation, requiring the implementation of additional safety measures and precautions with respect to in-person meetings and social distancing. Therefore, it is recommended that the Board make the finding that the state of emergency is still in place and that local health officials are recommending social distancing measures, including but not limited to remote public meetings.
Staff will continue 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.
Attachments:
1. Yolo County Health Officer memorandum dated 1/4/22 to Board of Supervisors 6 COUNTY OF YOLO
Health and Human Services Agency Karen Larsen, LM F T
Directo r
Aimee Sisson, MD, MPH MAILING ADDRESS
137 N. Cottonwood Street Woodland, CA 95695
www.yolocounty.org Health Officer
D a v i s W e s t S a c r a m e n to W i n t e r s W o o d la n d 600 A Street
Davis, CA 95616
Mental Health (530) 757-5530
500 Jefferson Boulevard
West Sacramento, CA95605
Service Center (916) 375-6200
Mental Health (916) 375-6350
Public Health (916) 375-6380
111 East Grant Avenue
Winters, CA 95694
Service Center (530) 406-4444
25 & 137 N. Cottonwood Street
Woodland, CA 95695
Service Center (530) 661-2750
Mental Health (530) 666-8630
Public Health (530) 666-8645
Date: January 4, 2022
To: All Yolo County Boards and Commissions
From: Dr. Aimee Sisson, Health Officer
Subject: Remote Public Meetings
On September 22, October 20, and November 20, 2021, I issued memoranda recommending remote meetings. The case rate in Yolo County has increased significantly since the November 20 memorandum, and the current case rate represents high community transmission. In the context of high community transmission, I recommend meetings be held remotely whenever possible. I am re-issuing the earlier memorandum with updated COVID-19 case rate data.
In light of the ongoing public health emergency related to COVID-19 and the high level of community transmission of the virus that causes COVID-19, the Yolo County Public Health Officer recommends that public bodies continue to meet remotely to the extent possible. Board and Commissions can utilize the provisions of newly enacted AB 361 to maintain remote meetings under the Ralph M. Brown Act and similar laws.
Among other reasons, the grounds for the remote meeting recommendation include:
• The continued threat of COVID-19 to the community. As of January 4, 2022, the case rate is 32.3 cases per 100,000 residents per day. This case rate is considered “High” under the Centers for Disease Control and Prevention’s (CDC) framework for assessing community COVID-19 transmission; and • The unique characteristics of public governmental meetings, including the increased mixing associated with bringing together people from across the community, the need to enable those who are immunocompromised or unvaccinated to be able to safely continue to fully participate in public governmental meetings, and the challenges of ensuring compliance with safety requirements and recommendations at such meetings.
Meetings that cannot feasibly be held virtually should be held outdoors when possible, or indoors only in small groups with face coverings, maximal physical distance between participants, use of a portable HEPA filter (unless comparable filtration is provided through facility HVAC systems), and shortened meeting times. 7
This recommendation is based upon current conditions and available protective measures. The Public Health Officer will continue to evaluate this recommendation on an ongoing basis and will communicate when there is no longer such a recommendation with respect to meetings for public bodies. 8 1
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 5
TO: Board of Directors
FROM: Alisa Lembke, Board Clerk / Administrative Analyst SUBJECT: Approval of Minutes from special November 10, 2021 meeting DATE: January 27, 2022
RECOMMENDATION
Receive, review and approve the attached special November 10, 2021 meeting Minutes.
9 VCEA Minutes November 10, 2021 Board Special Meeting via Webinar Page 1 of 3
MINUTES OF THE VALLEY CLEAN ENERGY ALLIANCE
BOARD OF DIRECTORS SPECIAL MEETING
WEDNESDAY, NOVEMER 10, 2021
The Board of Directors of the Valley Clean Energy Alliance duly noticed their special meeting scheduled for Wednesday, November 10, 2021 at 5:00 p.m., to be held via Zoom webinar. Chair Carson established that there was a quorum present and began the meeting at 5:00 p.m.
Board Members Present: Dan Carson, Jesse Loren, Tom Stallard, Don Saylor (departed 6:15 p.m.), Gary Sandy, Wade Cowan, Lucas Frerichs (departed 5:28 p.m.), Mayra Vega (departed 5:30 p.m.)
Members Absent:
Welcome Chair Carson welcomed everyone.
Approval of
Regular Meeting
Agenda
Chair Carson would like to propose to amend the regular agenda to hold items 15 (Cost-based Customer Rate Policy and structure) and 16 (receive 2022 preliminary operating budget) prior to Item 14 (audited financial statements). Motion made by Director Loren to approve the November 10, 2021 special meeting agenda as amended, seconded by Director Stallard.
Motion passed unanimously. The Consent items are listed below in accordance with this motion.
Public Comment –
General and
Consent
Chair Carson opened the floor for public comment for items not listed on the agenda and items listed on the Consent Agenda. Board Clerk informed those present that there were no verbal or written public comments.
Approval of
Consent Agenda
(Resolution 2021-
022)
Motion made by Director Frerichs to approve the consent agenda, seconded by Director Loren. Motion passed unanimously. The following items were approved, ratified, and/or received:
4. renewed authorization of remote public meetings as authorized by Assembly Bill 361;
5. October 14, 2021 and October 21, 2021 meeting Minutes;
6. 2021 Long Range Calendar;
7. Financial Update – September 30, 2021 (unaudited) financial statements;
8. Legislative Update from Pacific Policy Group;
9. November 4, 2021 Regulatory update provided by Keyes & Fox;
10. November 3, 2021 Customer Enrollment Update;
11. Community Advisory Committee October 28, 2021 meeting summary;
12. Resolution 2021-022 to change fiscal year of July 1st to June 30th to align with calendar year of January 1st to December 31st; and,
13. Update of SACOG Grant – Electrify Yolo.
10 VCEA Minutes November 10, 2021 Board Special Meeting via Webinar Page 2 of 3 Item 15: Consider
adoption of Cost-based Customer
Rate Policy and
Structure /
Resolution 2021-
023
Interim General Manager Mitch Sears introduced this item and presented an updated and revised staff recommendation, which incorporates and reflects Pacific Gas & Electric’s (PG&E’s) 2022 Power Charge Indifference Adjustment (PCIA) and rates that were released on November 8th. This updated and revised staff recommendation is identified in the slides presented at this meeting and is different than the recommendation in Staff’s report on this item. The Board discussed PCIA and rate projections, formulas used to predict future costs, expenditure strategies, reserve policy, how to assist low income customers, possible constraints on VCE Board to make decisions on rates in the future, putting structure in place to recover expenditures, and having the CAC continue to look at rate options.
Motion made by Director Frerichs to approve Staff’s revised staff recommendation as presented in the slides, seconded by Director Saylor. (Director Frerichs departed at 5:28 p.m.)
Chair Carson opened the floor to public comment.
Written Public Comment: Board Clerk Alisa Lembke read written public comment received from James Skeen dated November 9, 2021 into the record about whether VCE rates will be above PG&E’s rates. (Director Vega departed at 5:30 p.m.)
Verbal Public Comment: Christine Shewmaker, CAC Chair, provided comments about the cost rate and the proposed 3 tiered rate structure and stating that budget estimates were dire. In addition, she provided her personal comment that she encourages staff to continue to look at climate change impacts on load forecasting and to continue exploring other options.
The motion made by Director Frerichs to approve Staff’s revised recommendation as stated in the slides for this item, seconded by Director Saylor was voted on. Staff’s revised recommendation is to approve resolution to:
a. Adopt cost-based rate policy;
b. Consider reserves policy update in Q1 2022; and,
c. Direct Staff to continue consideration of new customer rate structure in consultation with the CAC and return with
recommendations at a future date.
Motion passed as Resolution 2021-023 by the following vote:
AYES: Carson, Loren, Saylor, Stallard, Cowan, Sandy
NOES: None
ABSENT: Frerichs, Vega
ABSTAIN: None
11 VCEA Minutes November 10, 2021 Board Special Meeting via Webinar Page 3 of 3 Item 16: Receive
2022 preliminary
draft operating
budget
Mr. Sears introduced this item and turned it over to VCE Staff Edward Burnham who provided an overview of Staff’s report. Mr. Burnham informed those present that the information provided in the draft operating budget has not been updated with the November 8, 2021 PCIA and PG&E rates.
However, the draft budget does provide a trend and baseline going forward.
Several topics were mentioned: program opportunities, mission of VCE, possible further opportunities to further our green power label, and the importance of having VCE’s rates being low – lower than PG&E’s generation rates.
There were no written or verbal public comments.
Item 14: Receive
and accept
audited financial
statements for the
period of July 1,
2020 to June 30,
2021 presented by
James Marta &
Company
Mr. Sears introduced this item and James Marta of James Marta & Company, VCE’s auditors. Mr. Marta reviewed a summary of VCE’s financial audit for fiscal year 2020-2021. There were no verbal or written public comment. (Director Saylor departed at 6:15 p.m.)
The Board received and accepted the financial statements for the period of July 1, 2020 through June 30, 2021.
Item 17: Board
Member and Staff
Announcements
Mr. Sears reminded those presented that sits on the CC Power Board. They are nearing completion of discussing long duration storage (8 hour batteries).
It is Staff’s intention to have the VCE Board address long duration storage agreement in early 2022. In addition, the CC Power Board discussed Community Choice Aggregates (CCA) policies and standards which may have an impact on VCE’s policies. Mr. Sears showed a few slides of the Davis Co-op UltraGreen sign, the electrical vehicle (ev) charging station sign in Winters, and Putah Creek Solar Farm (Winters) development. Lastly, it was announced that a new Program & Community Engagement Analyst will start next week on Tuesday (11/15/2021). Chair Carson announced that the Board’s next regular meeting is scheduled for Thursday, December 9, 2021 at 5 p.m.
Adjournment Chair Carson adjourned the regular Board meeting at 6:29 p.m.
Alisa M. Lembke
VCEA Board Secretary
12 VALLEY CLEAN ENERGY ALLIANCE
Staff Report - Item 6
____________________________________________________________________________________ TO: Board of Directors
FROM: Alisa Lembke, Board Clerk/Administrative Analyst
SUBJECT: Board and Community Advisory Committee 2022 Long-Range Calendar DATE: January 27, 2022
Recommendation
Receive and file the 2022 Board and Community Advisory Committee long-range calendar listing proposed meeting topics.
13 1/14/22
VALLEY CLEAN ENERGY
2022 Meeting Dates and Proposed Topics – Board and Community Advisory Committee
MEETING DATE TOPICS ACTION
January 13, 2022
Special Meeting
scheduled for
January 27, 2022
Board
WOODLAND
• 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
• Informational
• Informational
January 27, 2022
January 20, 2022
Advisory
Committee
WOODLAND
• Formation of CAC Task Groups
• Update on 2022 Power Charge Indifference Adjustment (PCIA) and Rates
• Update on customer program development
• CC Power long duration storage (placeholder)
• Draft Collections Policy
• Draft Carbon Neutral report
• Action
• Informational
• Informational
• Action: Recommendation
to Board
• Informational/Discussion
• Discussion
February 10, 2022 Board
DAVIS
• CC Power long duration storage (placeholder)
• Update on customer program development
• Update on 2022 PCIA and Rates
• Update on Time of Use (TOU) (placeholder)
• Update on SACOG Grant – Electrify Yolo (placeholder)
• Strategic Plan Update (Annual)
• Carbon Neutral Report
• Action
• Informational
• Informational
• Informational
• Informational
• Informational
• Informational/Discussion
February 24, 2022 Advisory
Committee
DAVIS
• Update on SACOG Grant – Electrify Yolo (placeholder)
• 2022 Task Groups Tasks/Charge (Annual)
• Update on Time of Use (TOU) (placeholder)
• Power Procurement / Renewable Portfolio Standard Update • Informational
• Discussion/Action
• Informational
• Informational
14 • Presentment of customer program concept
• Draft Collection Policy
• Action: Recommendation
to Board
• Action: Recommendation
to Board
March 10, 2022 Board
WOODLAND
• Receive Enterprise Risk Management Report (Bi-Annual) • Collections Policy
• Presentment of customer program concept
• Update on Time of Use (TOU) (placeholder)
• Informational
• Discussion/Action
• Action
• Informational
March 24, 2022 Advisory
Committee
WOODLAND
• Update on Time of Use (TOU) (placeholder)
• Update on customer program concept
• Informational
• Informational
April 14, 2022 Board
DAVIS
• 7/1/21 thru 12/31/21 Audited Financial Statements (James Marta & Co.)
• Action
April 28, 2022 Advisory
Committee
DAVIS
• 2022 and 2023 Power Content Update
• Quarterly Strategic Plan update
• Presentment of customer program concept
• Informational
• Informational
• Informational
• Action: Recommendation
to Board
May 12, 2022 Board
WOODLAND
• Update on SACOG Grant – Electrify Yolo (placeholder)
• Presentment of customer program concept
• Informational
• Action
May 26, 2022 Advisory
Committee
WOODLAND
• Power Planning 2023 / Renewable Content
• Update 3-Year Programs Plan
• Net Energy Metering (NEM) 3.0 (placeholder)
• Update on SACOG Grant – Electrify Yolo (placeholder)
• Discussion/Action
• Informational
• Informational
• Informational
June 9, 2022 Board
DAVIS
• 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
• Action
• Action
• Informational
June 23, 2022 Advisory
Committee
DAVIS
• Prioritizing types of energy (placeholder)
• Net Energy Metering (NEM) 3.0 Update (placeholder)
• Discussion/Action
• Informational
15 July 14, 2022 Board
WOODLAND
• Net Energy Metering (NEM) 3.0 Update (placeholder) • Informational July 28, 2022 Advisory
Committee
WOODLAND
• Power Procurement / Renewable Portfolio Standard update • Legislative Bills update
• Informational
• Informational
August 11, 2022 Board
DAVIS
• •
August 25, 2022 Advisory
Committee
DAVIS
• •
September 8, 2022 Board
WOODLAND
• Update on SACOG Grant – Electrify Yolo (placeholder)
• 2022 Operating Budget / RPS update
• Certification of Standard and UltraGreen Products (Annual) • Enterprise Risk Management Report (Bi-Annual)
• Informational
• Informational
• Action
• Informational
September 22, 2022 Advisory
Committee
WOODLAND
• Legislative End of Session Update
• Update on SACOG Grant – Electrify Yolo (placeholder)
• Update on Customer Dividend and Programs Allocation
• 2023 Operating Budget
• Informational
• Informational
• Informational
• Informational
October 13, 2022 Board
DAVIS
• Update on 2023 draft Operating Budget
• Customer Dividend and Programs Allocation report
• Informational
• Action
October 27, 2022 Advisory
Committee
DAVIS
• Update on Power Content Label Customer Mailer
• Review Draft Committee Evaluation of Calendar Year End (Annual)
• Strategic Plan update
• Informational
• Informational / Discussion
• Informational
November 10, 2022 Board
WOODLAND
• Certification of Power Content Label (Annual)
• Preliminary 2023 Operating Budget (Annual)
• Action
• Informational
November 24, 2022
(Thanksgiving holiday.
Would like to
Advisory
Committee
WOODLAND
• Finalize Committee Evaluation of Calendar Year End (Annual) • Review draft revised Procurement Guide (placeholder)(Annual) • Discussion/Action
• Action: Recommendation
to Board
16 reschedule for the 3
rd
Thursday of the month
to Thursday,
November 17, 2022)
• FY22/23 Operating Budget / RPS update
• Power Procurement / Renewable Portfolio Standard Update • Review CAC Charge (tentative) (Annual)
• Informational
• Informational
• Discussion / Action
December 8, 2022 Board
DAVIS
• Approve 2023 Operating Budget (Annual)
• Receive Enterprise Risk Management Report (Annual)
• Approve revised Procurement Guide (placeholder)(Annual) • Enterprise Risk Management Report (Annual)
• FY22/23 Operating Budget / RPS update
• Update on SACOG Grant – Electrify Yolo (placeholder)
• Receive CAC 2022 Calendar Year End Report (Annual)
• Election of Officers for 2023 (Annual)
• Action
• Informational
• Action
• Informational
• Informational
• Informational
• Informational
• Nominations
December 22, 2022
(Approaching
Christmas holiday
weekend. Would like
to reschedule for the
3 rd Thursday of the
month to December
15, 2022)
Advisory
Committee
DAVIS
• 2023 CAC Task Group(s) formation (Annual)
• Election of Officers for 2023 (Annual)
• Revise CAC Charge (tentative) (Annual)
• Update on SACOG Grant – Electrify Yolo (placeholder)
• Discussion/Action
• Nominations
• Discussion / Action
• Informational
January 12, 2023 Board
WOODLAND
• Oaths of Office for Board Members (Annual if new Members) • Approve Updated CAC Charge (tentative) (Annual)
• Update on Customer Rate/Policy Structure Implementation • Action
• Action
• Informational
January 26, 2023 Advisory
Committee
WOODLAND
• Update on Customer Rate/Policy Structure Implementation • Power Procurement / Renewable Portfolio Standard Update • Strategic Plan update
• Informational
• Informational
• Informational
Note: CalCCA Annual Meeting typically scheduled in November 17 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 7A
______________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Interim General Manager
Edward Burnham, Finance and Operations Director
SUBJECT: Financial Update – October 31, 2021 (unaudited) financial statements (with comparative year to date information) and Actual vs. Budget year to date ending October 31, 2021
DATE: January 27, 2022
RECOMMENDATION:
Accept the following Financial Statements (unaudited) for the period of October 1, 2021 to October 31, 2021 (with comparative year to date information) and Actual vs. Budget year to date ending October 31, 2021.
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 October 31, 2021.
Financial Statements for the period October 1, 2021 – October 31, 2021 In the Statement of Net Position, VCEA, as of October 31, 2021, has a total of $4,459,682 in its checking, money market and lockbox accounts, $1,100,000 restricted assets for the Debt Service Reserve account, $1,986,833 restricted assets related to supplier deposits, and $2,207,786 restricted assets for the Power Purchases Reserve account. VCE has incurred obligations from Member agencies and owes as of October 31, 2021, $149,619. VCE member obligations are incurred monthly due to staffing, accounting, and legal services.
18 The term loan with River City Bank includes a current portion of $1,218,913. On October 31, 2021, VCE’s net position is $10,884,443.
In the Statement of Revenues, Expenditures, and Changes in Net Position, VCEA recorded $3,736,485 of revenue (net of allowance for doubtful accounts), of which $4,616,159 was billed in October and $1,968,070 represent estimated unbilled revenue. The cost of the electricity for the October revenue totaled $3,802,919. For October, VCEA’s gross margin was approximately (1.78%), and operating loss totaled ($418,287). The year-to-date change in net position was ($1,596,947).
In the Statement of Cash Flows, VCEA cash flows from operations were ($404,886) due to October cash receipts of revenues being lower than the monthly cash operating expenses.
Actual vs. Budget Variances for the year to date ending October 31, 2021 Below are the financial statement line items with variances >$50,000 and 5% • Electric Revenue - $4,398,407 and 24% – variance is due to load being more favorable year-to-date than planned; the continued COVID and recessionary impacts and the weather has been warmer than forecast. • Purchased Power - $2,128,691 and 10% – variance is due to load being more favorable year-to-date than planned; the COVID and recessionary impacts and the weather has been warmer than forecast.
Attachments:
1) Financial Statements (Unaudited) October 1, 2021 to October 31, 2021 (with comparative year to date information.)
2) Actual vs. Budget for the year to date ending October 31, 2021 19 VALLEY CLEAN ENERGY ALLIANCE
FINANCIAL STATEMENTS
(UNAUDITED)
FOR THE PERIOD OF OCTOBER 1 TO OCTOBER 31, 2021
PREPARED ON NOVEMBER 29, 2021
20 2
ASSETS
Current assets:
Cash and cash equivalents $ 4,459,682
Accounts receivable, net of allowance 8,285,674
Accrued revenue 1,968,070
Prepaid expenses 29,841
Other current assets and deposits 1,986,883
Total current assets 16,730,150
Restricted assets:
Debt service reserve fund 1,100,000
Power purchase reserve fund 2,207,786
Total restricted assets 3,307,786
Noncurrent assets:
Other noncurrent assets and deposits
Total noncurrent assets -
TOTAL ASSETS $ 20,037,936
LIABILITIES
Current liabilities:
Accounts payable $ 534,498
Accrued payroll 49,967
Interest payable 2,988
Due to member agencies 149,619
Accrued cost of electricity 4,527,897
Other accrued liabilities 528,898
Security deposits - energy supplies 1,980,000
User taxes and energy surcharges 160,713
Limited Term Loan 1,218,913
Total current liabilities 9,153,493
Noncurrent liabilities
Term Loan- RCB
Total noncurrent liabilities -
TOTAL LIABILITIES $ 9,153,493
NET POSITION
Restricted
Local Programs Reserve 224,500
Restricted 3,307,786
Unrestricted 7,352,157
TOTAL NET POSITION $ 10,884,443
(UNAUDITED)
VALLEY CLEAN ENERGY ALLIANCE
STATEMENT OF NET POSITION
OCTOBER 31, 2021
21 3
FOR THE PERIOD
ENDING
OCTOBER 31, 2021 YEAR TO DATE
OPERATING REVENUE
Electricity sales, net $ 3,736,485 $ 22,566,375
TOTAL OPERATING REVENUES 3,736,485 22,566,375
OPERATING EXPENSES
Cost of electricity 3,802,919 22,634,520
Contract services 184,933 909,706
Staff compensation 141,967 409,901
General, administration, and other 22,577 199,836
TOTAL OPERATING EXPENSES 4,152,396 24,153,963
TOTAL OPERATING INCOME (LOSS) (415,911) (1,587,588)
NONOPERATING REVENUES (EXPENSES)
Other Revenue
Interest income 1,371 6,113
Interest and related expenses (3,747) (15,472)
TOTAL NONOPERATING REVENUES
(EXPENSES) (2,376) (9,359)
CHANGE IN NET POSITION (418,287) (1,596,947)
Net position at beginning of period 11,302,730 12,481,390 Net position at end of period $ 10,884,443 $ 10,884,443 (UNAUDITED)
FOR THE PERIOD OF OCTOBER 1, 2021 TO OCTOBER 31, 2021
(WITH COMPARATIVE YEAR TO DATE INFORMATION)
22 4
FOR THE
PERIOD ENDING
OCTOBER 31, 2021 YEAR TO DATE
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from electricity sales $ 4,865,570 $ 23,142,527 Receipts for security deposits with energy suppliers - - Payments to purchase electricity (4,897,025) (24,685,434) Payments for contract services, general, and adminstration (222,543) (1,500,246) Payments for staff compensation (150,888) (403,639)
Other cash payments - -
Net cash provided (used) by operating activities (404,886) (3,446,792)
CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES
Principal payments of Debt (32,943) (131,774)
Interest and related expenses (3,724) (15,743)
Net cash provided (used) by non-capital financing activities (36,667) (147,517)
CASH FLOWS FROM INVESTING ACTIVITIES
Interest income 1,371 6,113
Net cash provided (used) by investing activities 1,371 6,113 NET CHANGE IN CASH AND CASH EQUIVALENTS (440,182) (3,588,196) Cash and cash equivalents at beginning of period 8,207,650 11,355,664 Cash and cash equivalents at end of period $ 7,767,468 $ 7,767,468 Cash and cash equivalents included in:
Cash and cash equivalents 4,459,682 4,459,682
Restricted assets 3,307,786 3,307,786
Cash and cash equivalents at end of period $ 7,767,468 $ 7,767,468
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
FOR THE PERIOD OF OCTOBER 1 TO OCTOBER 31, 2021
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
23 5
FOR THE
PERIOD ENDING
OCTOBER 31, 2021 YEAR TO DATE
Operating Income (Loss) $ (415,911) $ (1,587,588)
(Increase) decrease in net accounts receivable 1,328,278.00 (481,463.00) (Increase) decrease in accrued revenue (220,224) 967,221.00 (Increase) decrease in prepaid expenses (9,212) (14,698.00) (Increase) decrease in inventory - renewable energy credits - - (Increase) decrease in other assets and deposits - -
Increase (decrease) in accounts payable (83,801) 50,537.00 Increase (decrease) in accrued payroll (8,921) 6,262.00 Increase (decrease) in due to member agencies 94,564 26,213.00 Increase (decrease) in accrued cost of electricity (1,094,106) (2,050,914.00) Increase (decrease) in other accrued liabilities (16,584) (452,756.00) Increase (decrease )security deposits with energy suppliers - - Increase (decrease) in user taxes and energy surcharges 21,031 90,394.00 Net cash provided (used) by operating activities $ (404,886) $ (3,446,792)
RECONCILIATION OF OPERATING INCOME TO NET CASH
PROVIDED (USED) BY OPERATING ACTIVITIES
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
FOR THE PERIOD OF OCTOBER 1 TO OCTOBER 31, 2021
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
24 VALLEY CLEAN ENERGY
ACTUAL VS. BUDGET FYE 6-30-2022
FOR THE YEAR TO DATE ENDING 10/31/21
10/31/2021 10/31/2021
YTD YTD YTD %
GL# Description FY2022 Actuals FY2022 Budget Variance over/-under 301.00 Electric Revenue 22,566,375 18,167,968 4,398,407 24% 311.00 Interest Revenues 6,113 18,800 (12,687) -67%
415.00 Purchased Power 22,634,520 20,505,829 2,128,691 10% Labor & Benefits 409,902 388,327 21,575 6%
451.10 Salaries & Wages/Benefits 353,451 325,826 27,625 8% 451.20 Contract Labor - 17,476 (17,476) -100%
453.41 Human Resources & Payroll 56,451 45,024 11,427 25% Office Supplies & Other Expenses 76,080 62,816 13,265 21% 452.10 Technology Costs 8,429 11,344 (2,915) -26%
452.15 Office Supplies 1,143 768 375 49%
452.25 Travel - 2,032 (2,032) -100%
452.30 CalCCA Dues 37,845 41,405 (3,560) -9%
CC Power 28,440 6,667 21,774 327%
452.35 Memberships 224 600 (376) -63%
Contractual Services 855,430 924,828 (69,398) -8%
453.10 Other Contract Services - 8,000 (8,000) -100%
453.15 Don Dame 4,616 3,333 1,283 38%
453.20 SMUD - Credit Support 241,990 211,936 30,054 14% 453.21 SMUD - Wholesale Energy Services 195,948 195,324 624 0% 453.22 SMUD - Call Center 265,230 262,212 3,018 1%
453.23 SMUD - Operating Services 36,256 20,000 16,256 81% 453.24 Commercial Legal Support - - - 100%
453.25 Legal General Counsel 30,842 50,430 (19,588) -39% 453.36 Regulatory Counsel 37,055 64,887 (27,831) -43%
453.37 Joint CCA Regulatory counsel 204 10,506 (10,303) -98% 453.38 Legislative - (Lobbiest) 25,000 20,000 5,000 25% 453.40 Accounting Services 2,290 8,405 (6,115) -73%
453.41 Financial Consultant - 8,333 (8,333) -100%
453.42 Audit Fees 16,000 61,462 (45,462) -74%
453.60 PG&E Acquisition Consulting - - - 100%
Marketing 44,407 78,002 (33,595) -43%
459.05 Marketing Collateral 44,357 75,913 (31,556) -42% 459.15 Community Engagement Activities & Sponsorships 50 2,088 (2,038) -98% Programs - 45,000 (45,000) -100%
Program Costs - 45,000 (45,000) -100%
Rents & Leases 4,770 8,040 (3,270) -41%
457.10 Hunt Boyer Mansion 4,770 8,040 (3,270) -41%
Other A&G 126,907 136,046 (9,139) -7%
459.08 Development - New Members - 8,000 (8,000) -100%
459.09 Strategic Plan Implementation 25,611 25,000 611 2% 459.10 PG&E Data Fees 67,694 100,049 (32,355) -32%
459.20 Insurance 6,681 2,577 4,104 159%
459.70 Banking Fees 26,921 420 26,500 6306%
463.10 Miscellaneous Operating Expenses 1,946 2,147 (201) 0% 463.99 Contingency - 45,666 (45,666) -100%
TOTAL OPERATING EXPENSES 24,153,962 22,196,700 1,957,262 9% 481.10 Interest on RCB loan 15,472 15,743 (271) -2%
NET INCOME (1,596,947) (4,025,675) 2,428,729 -60%
25 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 7B
______________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Interim General Manager
Edward Burnham, Finance and Operations Director
SUBJECT: Financial Update – November 1, 2021 (unaudited) financial statements (with comparative year to date information) and Actual vs. Budget year to date ending November 30, 2021
DATE: January 27, 2022
RECOMMENDATION:
Accept the following Financial Statements (unaudited) for the period of November 1, 2021 to November 30, 2021 (with comparative year to date information) and Actual vs. Budget year to date ending November 30, 2021.
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 November 30, 2021.
Financial Statements for the period November 1, 2021 – November 30, 2021 In the Statement of Net Position, VCEA, as of November 30, 2021, has a total of $4,476,243 in its checking, money market and lockbox accounts, $1,100,000 restricted assets for the Debt Service Reserve account, $1,989,603 restricted assets related to supplier deposits, and $2,460,740 restricted assets for the Power Purchases Reserve account. VCE has incurred obligations from Member agencies and owes as of November 30, 2021, $96,982. VCE member obligations are incurred monthly due to staffing, accounting, and legal services.
26 The term loan with River City Bank includes a current portion of $1,185,969. On November 30, 2021, VCE’s net position is $10,907,459.
In the Statement of Revenues, Expenditures, and Changes in Net Position, VCEA recorded $3,493,719 of revenue (net of allowance for doubtful accounts), of which $3,168,670 was billed in November and $2,025,445 represent estimated unbilled revenue. The cost of the electricity for the November revenue totaled $3,039,444. For November, VCEA’s gross margin was approximately 13.01%, and net income totaled $23,016. The year-to-date change in net position was ($1,573,931).
In the Statement of Cash Flows, VCEA cash flows from operations were $304,913 due to November cash receipts of revenues being more than the monthly cash operating expenses.
Actual vs. Budget Variances for the year to date ending November 30, 2021 Below are the financial statement line items with variances >$50,000 and 5% • Electric Revenue - $4,566,782 and 21% – variance is due to load being more favorable year-to-date than planned; the continued COVID and recessionary impacts and the weather has been warmer than forecast. • Purchased Power - $1,850,679 and 8% – variance is due to load being more favorable year-to-date than planned; the COVID and recessionary impacts and the weather has been warmer than forecast. • Program Costs – ($56,250) and (100%) – favorable variance to budget is due to not having utilized budgeted annual program costs expected in later periods.
• Contingency – ($56,900) and (100%) – favorable variance to budget is due to not having a need yet to utilize the contingency funds set aside in the budget.
Attachments:
3) Financial Statements (Unaudited) November 1, 2021 to November 30, 2021 (with comparative year to date information.)
4) Actual vs. Budget for the year to date ending November 30, 2021 27 VALLEY CLEAN ENERGY ALLIANCE
FINANCIAL STATEMENTS
(UNAUDITED)
FOR THE PERIOD OF NOVEMBER 1 TO NOVEMBER 30, 2021
PREPARED ON JANUARY 18, 2022
28 2
ASSETS
Current assets:
Cash and cash equivalents $ 4,476,243
Accounts receivable, net of allowance 7,434,060
Accrued revenue 2,025,445
Prepaid expenses 567,260
Other current assets and deposits 1,989,603
Total current assets 16,492,611
Restricted assets:
Debt service reserve fund 1,100,000
Power purchase reserve fund 2,460,740
Total restricted assets 3,560,740
Noncurrent assets:
Other noncurrent assets and deposits
Total noncurrent assets -
TOTAL ASSETS $ 20,053,351
LIABILITIES
Current liabilities:
Accounts payable $ 562,447
Accrued payroll 54,089
Interest payable 2,769
Due to member agencies 96,982
Accrued cost of electricity 4,754,278
Other accrued liabilities 407,324
Security deposits - energy supplies 1,980,000
User taxes and energy surcharges 102,034
Limited Term Loan 1,185,969
Total current liabilities 9,145,892
Noncurrent liabilities
Term Loan- RCB
Total noncurrent liabilities -
TOTAL LIABILITIES $ 9,145,892
NET POSITION
Restricted
Local Programs Reserve 224,500
Restricted 3,560,740
Unrestricted 7,122,219
TOTAL NET POSITION $ 10,907,459
(UNAUDITED)
VALLEY CLEAN ENERGY ALLIANCE
STATEMENT OF NET POSITION
NOVEMBER 30, 2021
29 3
FOR THE PERIOD
ENDING
NOVEMBER 30,
2021 YEAR TO DATE
OPERATING REVENUE
Electricity sales, net $ 3,493,719 $ 26,060,094
TOTAL OPERATING REVENUES 3,493,719 26,060,094
OPERATING EXPENSES
Cost of electricity 3,039,444 25,673,964
Contract services 278,843 1,188,549
Staff compensation 33,098 442,999
General, administration, and other 117,083 316,919
TOTAL OPERATING EXPENSES 3,468,468 27,622,431
TOTAL OPERATING INCOME (LOSS) 25,251 (1,562,337)
NONOPERATING REVENUES (EXPENSES)
Other Revenue
Interest income 1,293 7,406
Interest and related expenses (3,528) (19,000)
TOTAL NONOPERATING REVENUES
(EXPENSES) (2,235) (11,594)
CHANGE IN NET POSITION 23,016 (1,573,931)
Net position at beginning of period 10,884,443 12,481,390 Net position at end of period $ 10,907,459 $ 10,907,459 (WITH COMPARATIVE YEAR TO DATE INFORMATION)
VALLEY CLEAN ENERGY ALLIANCE
STATEMENT OF REVENUES, EXPENDITURES AND
(UNAUDITED)
CHANGES IN NET POSITION
FOR THE PERIOD OF NOVEMBER 1, 2021 TO NOVEMBER 30, 2021 30 4
FOR THE
PERIOD ENDING
NOVEMBER 30, 2021 YEAR TO DATE
CASH FLOWS FROM OPERATING ACTIVITIES
Receipts from electricity sales $ 4,229,279 $ 27,371,806 Receipts for security deposits with energy suppliers - - Payments to purchase electricity (2,813,063) (27,498,497) Payments for contract services, general, and adminstration (1,079,607) (2,579,853) Payments for staff compensation (28,976) (432,615)
Other cash payments (2,720) (2,720)
Net cash provided (used) by operating activities 304,913 (3,141,879)
CASH FLOWS FROM NON-CAPITAL FINANCING ACTIVITIES
Principal payments of Debt (32,944) (164,718)
Interest and related expenses (3,747) (19,490)
Net cash provided (used) by non-capital financing
activities (36,691) (184,208)
CASH FLOWS FROM INVESTING ACTIVITIES
Interest income 1,293 7,406
Net cash provided (used) by investing activities 1,293 7,406 NET CHANGE IN CASH AND CASH EQUIVALENTS 269,515 (3,318,681) Cash and cash equivalents at beginning of period 7,767,468 11,355,664 Cash and cash equivalents at end of period $ 8,036,983 $ 8,036,983 Cash and cash equivalents included in:
Cash and cash equivalents 4,476,243 4,476,243
Restricted assets 3,560,740 3,560,740
Cash and cash equivalents at end of period $ 8,036,983 $ 8,036,983
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
FOR THE PERIOD OF NOVEMBER 1 TO NOVEMBER 30, 2021
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
31 5
FOR THE
PERIOD ENDING
NOVEMBER 30, 2021 YEAR TO DATE
Operating Income (Loss) $ 25,251 $ (1,562,337)
(Increase) decrease in net accounts receivable 851,614.00 370,151.00 (Increase) decrease in accrued revenue (57,375) 909,846.00 (Increase) decrease in prepaid expenses (537,419) (552,117.00) (Increase) decrease in inventory - renewable energy credits - - (Increase) decrease in other assets and deposits (2,720) (2,720.00) Increase (decrease) in accounts payable 27,949 78,486.00 Increase (decrease) in accrued payroll 4,122 10,384.00
Increase (decrease) in due to member agencies (52,637) (26,424.00) Increase (decrease) in accrued cost of electricity 226,381 (1,824,533.00) Increase (decrease) in other accrued liabilities (121,574) (574,330.00) Increase (decrease )security deposits with energy suppliers - - Increase (decrease) in user taxes and energy surcharges (58,679) 31,715.00 Net cash provided (used) by operating activities $ 304,913 $ (3,141,879)
RECONCILIATION OF OPERATING INCOME TO NET
CASH PROVIDED (USED) BY OPERATING ACTIVITIES
(WITH YEAR TO DATE INFORMATION)
(UNAUDITED)
FOR THE PERIOD OF NOVEMBER 1 TO NOVEMBER 30, 2021
VALLEY CLEAN ENERGY ALLIANCE
STATEMENTS OF CASH FLOWS
32 VALLEY CLEAN ENERGY
ACTUAL VS. BUDGET FYE 6-30-2022
FOR THE YEAR TO DATE ENDING 11/30/21
11/30/2021 11/30/2021
YTD YTD YTD %
GL# Description FY2022 Actuals FY2022 Budget Variance over/-under 301.00 Electric Revenue 26,060,094 21,493,312 4,566,782 21% 311.00 Interest Revenues 7,406 23,500 (16,094) -68%
415.00 Purchased Power 25,673,964 23,823,285 1,850,679 8% Labor & Benefits 442,999 483,952 (40,953) -8%
451.10 Salaries & Wages/Benefits 374,233 407,283 (33,050) -8% 451.20 Contract Labor - 20,389 (20,389) -100%
453.41 Human Resources & Payroll 68,766 56,280 12,486 22% Office Supplies & Other Expenses 90,318 78,520 11,798 15% 452.10 Technology Costs 13,213 14,180 (967) -7%
452.15 Office Supplies 1,481 960 521 54%
452.25 Travel - 2,540 (2,540) -100%
452.30 CalCCA Dues 46,960 51,756 (4,796) -9%
CC Power 28,440 8,333 20,107 241%
452.35 Memberships 224 750 (526) -70%
Contractual Services 1,115,011 1,151,357 (36,346) -3%
453.10 Other Contract Services - 10,000 (10,000) -100%
453.15 Don Dame 5,010 4,167 843 20%
453.20 SMUD - Credit Support 287,557 275,430 12,128 4%
453.21 SMUD - Wholesale Energy Services 244,935 244,155 780 0% 453.22 SMUD - Call Center 330,745 327,943 2,802 1%
453.23 SMUD - Operating Services 56,736 25,000 31,736 127% 453.24 Commercial Legal Support - - - 100%
453.25 Legal General Counsel 41,139 63,038 (21,899) -35% 453.36 Regulatory Counsel 68,012 81,108 (13,096) -16%
453.37 Joint CCA Regulatory counsel 204 13,133 (12,929) -98% 453.38 Legislative - (Lobbiest) 30,000 25,000 5,000 20% 453.40 Accounting Services 3,374 10,506 (7,132) -68%
453.41 Financial Consultant - 10,417 (10,417) -100%
453.42 Audit Fees 47,300 61,462 (14,162) -23%
453.60 PG&E Acquisition Consulting - - - 100%
Marketing 64,850 97,534 (32,684) -34%
459.05 Marketing Collateral 64,800 94,921 (30,120) -32% 459.15 Community Engagement Activities & Sponsorships 50 2,614 (2,564) -98% Programs - 56,250 (56,250) -100%
Program Costs - 56,250 (56,250) -100%
Rents & Leases 7,950 10,050 (2,100) -21%
457.10 Hunt Boyer Mansion 7,950 10,050 (2,100) -21%
Other A&G 225,391 170,089 55,302 33%
459.08 Development - New Members - 10,000 (10,000) -100% 459.09 Strategic Plan Implementation 57,436 31,250 26,186 84% 459.10 PG&E Data Fees 133,144 125,093 8,051 6%
459.20 Insurance 7,891 3,221 4,670 145%
459.70 Banking Fees 26,921 525 26,395 5025%
463.10 Miscellaneous Operating Expenses 1,946 2,684 (738) 0% 463.99 Contingency - 56,900 (56,900) -100%
TOTAL OPERATING EXPENSES 27,622,430 25,930,621 1,691,809 7% 481.10 Interest on RCB loan 19,000 19,490 (490) -3%
NET INCOME (1,573,931) (4,433,300) 2,859,369 -64%
33 1
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 8
To: Board of Directors
From: Mitch Sears, Interim General Manager
Subject: Legislative Update – Pacific Policy Group
Date: January 27, 2022
______________________________________________________________________________ Pacific Policy Group, VCE’s lobby services consultant, continues to work with Staff and the Community Advisory Committee’s Legislative - Regulatory Task Group continues to meet and discuss legislative matters. Below is a summary:
The 2022 legislative calendar has been published and January 3, 2022 marks the Legislature’s return to Sacramento. As 2022 is the second year of the two-year session, a number of two-year bills must pass their house of origin by January 31, 2022 in order for those legislative vehicles to remain active. SB 612 (Portantino) is a two-year bill but has already passed out of its original house and its next deadline is July 1, 2022 when bills must pass a policy committee of the other house.
In addition to consideration of two-year bills, January will bring about Governor Newsom’s proposal for the 2022-23 state budget. The Legislature and Governor spent much of the 2021 session negotiating a record surplus and 2022 is likely to be similar. The Legislative Analyst’s Office recently published its fiscal outlook for the 2022-23 budget and is currently projecting a $31 billion surplus (resources in excess of current law commitments) to allocate in 2022‑23. The Governor’s proposed budget is due by January 10, 2022 and the Legislature must respond with its own budget proposal by June 15, 2022. With such a large amount of unspoken for funding to allocate it is likely the negotiations will go well into August. 34 1
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 9
To: Board of Directors
From: Mitch Sears, Interim General Manager
Subject: Regulatory Monitoring Report – Keyes & Fox
Date: January 27, 2022
______________________________________________________________________________ Please find attached Keyes & Fox’s December 2021 Regulatory Memorandum dated January 19, 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 January 19, 2022. 35 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
Ben Inskeep, Principal Analyst, EQ Research, LLC
Subject: Regulatory Update
Date: January 19, 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: The CPUC issued D.21-12-015, approving VCE’s proposed agricultural irrigation pumping dynamic rates pilot, with some modifications. It also adopted numerous other supply- and demand-side changes to address near-term reliability concerns, although the 2,000-3,000 MW procurement mandate would apply specifically to the IOUs. VCE submitted Advice Letter 11-E on January 5, 2022, detailing information on its implementation of its pilot.
• IRP Rulemaking: On December 10, 2021, several CCAs filed a Motion requesting clarification and interim guidance on a modified CAM. On December 22, 2021, the ALJ issued a Proposed Decision adopting a 2021 Preferred System Plan. The PD would certify VCE’s 2020 IRP, finding numerous sections were “exemplary.”
• PG&E 2022 ERRA Forecast: PG&E filed its Fourth Supplemental Testimony, on which parties filed reply comments. In response to an ALJ Ruling, PG&E provided additional information on different amortization scenarios for the ERRA-Main balance through its Fifth Supplemental Testimony. PG&E also submitted reply comments. In January, parties participated in a meet-and-confer meeting and provided statements on January 6, 2022. The ALJ modified the schedule in a January 14 ruling, setting up the proceeding for a February 10 decision. • RPS Rulemaking: The IOUs filed a Joint Motion requesting an expansion of the scope of this rulemaking to consider issues pertaining to the Voluntary Allocation and Market Offer. On December 10, 2021, the ALJs issued a Proposed Decision on draft 2021 RPS Procurement Plans, which the CPUC approved as D.22-01-004 on January 18, 2022. D.22-01-004 directs retail sellers including VCE to file final Plans by February 17, 2022. VCE was praised for its sections on portfolio diversity and reliability, which the CPUC identified as an example for other retail sellers to follow when updating their RPS Plans. The CPUC also issued D.21-12-032 modifying the Renewable Market Adjusting Tariff.
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• Utility Safety Culture Assessments: Parties filed reply comments regarding the preliminary scope and schedule provided in the Order Instituting Rulemaking for this rulemaking to develop and adopt IOU safety culture assessments under SB 901.
• PG&E’s Phase 2 GRC: PG&E held a Settlement Conference that discussed a draft settlement on the outstanding real-time pricing issues in this proceeding. • PG&E’s Phase 1 GRC: No updates this month. On November 5, 2021, PG&E filed a motion requesting modifications to the procedural schedule.
• 2022-2023 Wildfire Fund Nonbypassable Charge Rulemaking: The CPUC issued D.21-12- 006 adopting a Wildfire Fund NBC of $0.00652/kWh for January 1, 2022, through December 31, 2022.
• RA Rulemaking (2023-2024): The Assigned Commissioner issued a Scoping Memo and Ruling.
Parties filed Phase 1 proposals, a workshop was held, new and revised proposals were filed, comments on proposals and the workshop were submitted, and then reply comments were submitted. Workshops were also held on behind-the-meter RA counting for hybrid and storage resources and to develop PG&E’s Slice-of-Day proposal and related RA program structural reform.
• PG&E’s 2019 ERRA Compliance: On January 18, 2022, the CCA Parties and TURN filed Phase 2 testimony.
• PCIA Rulemaking: The ALJ issued a Proposed Decision targeting improvements to the process of establishing the PCIA in ERRA proceedings. Parties filed comments and replies on the PD.
Parties also filed responses and replies in response to a November Ruling requesting comments on CalCCA’s proposal to authorize a nondisclosure agreement to allow CCAs and other entities with customers who pay the PCIA to access confidential, market-sensitive ERRA and PABA monthly report data year-round for the limited, non-proceeding purpose of developing PCIA rate forecasts.
• Provider of Last Resort Rulemaking: Parties filed comments in response to the November 23, 2021, ALJ Ruling posing questions addressing: (1) clarity and content of the Workshop 1 notes filed by CalCCA on November 5, 2021, and (2) questions on Workshop 1 and what changes if any are recommended to adequately meet POLR requirements. An email to parties tentatively rescheduled the date of the second workshop to February 22, 2022. • PG&E’s 2020 ERRA Compliance: No updates this month. On October 15, 2021, parties filed a Settlement Agreement resolving disputed issues in this proceeding. • Investigation into PG&E’s Organization, Culture and Governance: No updates this month. • PG&E Regionalization Plan: No updates this month. On September 10, 2021, Parties, including VCE, filed comments on the August 31, 2021, motion for approval of settlement agreements, followed by reply comments on September 17, 2021.
• Direct Access Rulemaking: No updates this month. In August, CalCCA filed a response to a July application for rehearing filed by a coalition of parties supporting expansion of Direct Access, who challenged a June CPUC decision that recommended against any re-opening of Direct Access. This proceeding is otherwise closed.
• RA Rulemaking (2021-2022): No updates this month. On October 11, 2021, parties filed responses to OhmConnect’s Petition for Modification of D.20-06-031, to which OhmConnect responded on October 25, 2021. The October 11, 2021, Order Instituting Rulemaking in the RA Rulemaking (2023-2024) closed this proceeding, except to resolve OhmConnect’s Petition for Modification.
• RA Rulemaking (2019-2020): No updates this month. Two applications for rehearing remain the only outstanding items to be addressed in this proceeding, which is now closed. 37 3
Ensuring Summer 2021 Reliability
On December 6, 2021, the CPUC issued D.21-12-015, approving VCE’s proposed agricultural irrigation pumping dynamic rates pilot, with some modifications. It also adopted numerous other supply- and demand-side changes to address near-term reliability concerns, although the 2,000-3,000 MW procurement mandate would apply specifically to the IOUs. On December 27, 2021, the CPUC issued D.21-12-069 correcting errors in D.21-12-015. VCE submitted Advice Letter 11-E on January 5, 2022, detailing information on its implementation of its pilot. • 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. • Details: 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, 2022. 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 burden to the grid and reducing GHG impacts. Customers participating in VCE’s dynamic rate pilot will receive a “shadow bill.” PG&E may 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 existing 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 authorizes new funding to PG&E of $3.25 million for the administration and execution of the three-year pilot. VCE and/or PG&E may engage a service provider with a suitable IT platform to automate dynamic hourly prices and make them accessible to customers and automated agricultural water pumps. PG&E, in coordination with VCE, is directed to contract with an independent evaluator to conduct a mid-term and final evaluation of this pilot. The mid-term evaluation report is due December 31, 2023, and a final evaluation is due March 1, 2025.
VCE’s advice letter provided information on the implementation of its pilot and stated that VCE and PG&E have discussed the pilot’s budget with the Energy Division and currently plan to file a Petition for Modification to increase the budget for this Pilot to ensure that the total budget covers both VCE’s and PG&E’s administrative costs.
D.21-12-015 also creates 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 requires 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.
• Analysis: D.21-12-015 approved VCE’s innovative proposed agricultural pumping dynamic rates pilot. D.21-12-015 made numerous other changes designed to increase supply and decrease demand during net peak periods, but it largely focuses on IOUs to achieve its aims, including expanding the Central Procurement Entity function of PG&E and SCE to allow for additional procurement. LSEs are encouraged to accelerate their procurement previously ordered in D.21- 38 4
06-035, but are not required to do so, and the decision declines to adopt an incentive for LSEs to accelerate procurement.
• Next Steps: The proceeding is now closed. Protests to VCE’s advice letter are due January 25, 2022. PG&E must submit its Tier 2 Advice Letter (in coordination with VCE) on February 4, 2022.
VCE must start its pilot by May 1, 2022.
• Additional Information: D.21-12-069 correcting errors in D.21-12-014 (December 27, 2021); D.21-12-015 (December 6, 2021); D.21-09-045 denying rehearing of D.21-03-056 (September 23, 2021); D.21-06-027 (approved June 24, 2021); Order denying applications for rehearing (May 20, 2021); D.21-03-056 (March 25, 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
On December 10, 2021, several CCAs filed a Motion requesting clarification and interim guidance on a modified CAM. On December 22, 2021, the ALJ issued a Proposed Decision adopting a 2021 Preferred System Plan. The PD would certify VCE’s 2020 IRP, finding numerous sections were “exemplary.” • 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.
The September 24, 2020 Scoping Memo and Ruling clarified that the issues planned to be resolved in this proceeding are organized into the following tracks: General IRP oversight issues, procurement track, Preferred System Portfolio development, the Transmission Planning Process, and Reference System Portfolio Development.
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. After review of the compliance filings, CPUC Staff will bring a Resolution before the Commission specifying the amount of backstop procurement required for a particular IOU on behalf of each LSE for each procurement tranche (2021, 2022, and 2023).
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. It ordered that the resources from Diablo Canyon be replaced with at least 2,500 MW of zero-emitting resources. In addition, it specifies that 2,000 MW of the procurement mandate required for 2026 must be “long-lead-time” (LLT) resources, with half coming from long-duration storage and the other half from zero-emitting resources with an 80% or greater capacity factor, with the Decision pointing to geothermal and biomass as the resources best-suited to meet this category. VCE is permitted to use resources that were not online or in-development and contracted and approved by its Board as of June 30, 2020 to count towards its procurement requirements (i.e., contracts approved by the VCE Board and executed after June 30, 2020, can count towards VCE’s procurement mandates). LSEs will not be given the option to opt out up front from providing their proportional share of the capacity required by D.21-06-035. The February 1, 2023 compliance filing will be the first check on the status of LLT resource procurement. VCE’s new obligations and a description of the specific resource requirements for each subcategory of procurement are detailed in the following table. 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. • Details: The PD adopts a 2021 PSP, which 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 39 5
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. It also directs staff to work with the CEC and CAISO to develop a policy-driven sensitivity case designed to test the transmission buildout necessary for a 30 MMT core portfolio with high electrification.
The PD would result in VCE's 2020 IRP being certified by the CPUC (in contrast to 24 other LSEs that have to file supplemental information). It calls VCE’s IRP "exemplary" with respect to the following sections: preferred conforming portfolios, focus on DACs, cost and rate analysis, hydro generation risk management, and long-duration storage development. The PD also maintains a two-year IRP planning cycle (vs. a 3-year cycle) and establishes a September 1, 2022 deadline for the next round of LSE IRPs.
The PD recommends the adoption of the 38 MMT “Core Portfolio” updated with the 2020 IEPR managed mid-demand forecast and High EV penetration assumption, which 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; Pumped (long-duration) Storage: 1,000 MW; Load Shed DR: 441 MW.
The CCA motion for clarification pertains to cost recovery of resources under D.19-11-016, would imposed a 3,300 MW procurement of system RA. Cost recovery and other issues, including RA credits, were to be addressed by a modified Cost Allocation Mechanism (mCAM) that was to be developed by the Commission later in time, but a decision on the mCAM has not yet been issued.
Accordingly, the CCAs requested that the CPUC issue an order providing further clarification and interim guidance regarding recently departing load customers. • Analysis: The PD would certify VCE’s 2020 IRP. It would also adopt a PSP that accelerates the build-out of clean energy resources by adopting a more aggressive GHG reduction target for the electricity sector over the coming decade (i.e., the 38 MMT instead of the 46 MMT used in the 2020 IRP). The PSP is comprised entirely of renewable energy, energy storage, and demand response resources, with no new gas. The PD would extend the due date of VCE’s next IRP by four months to September 1, 2022.
• Next Steps: The schedule is as follows:
o VCE’s Next IRP Due Date: September 1, 2022 (if the pending PD is adopted) o Procurement track: The PD declines to adopt additional procurement requirements.
VCE’s next compliance filing for its Mid-Term Reliability procurement demonstration is due February 1, 2022.
o General IRP oversight issues: The PD would maintain the two-year IRP cycle. o Preferred System Portfolio Development: Reply comments on the PD are due January 19, 2022, and the PD may be heard, at the earliest, at the CPUC's January 27 business meeting.
• Additional Information: Proposed Decision adopting 2021 Preferred System Plan; 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.
PG&E 2022 ERRA Forecast
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On December 14, 2021, PG&E filed Fourth Supplemental Testimony. On December 20, 2021, parties filed reply comments in response to PG&E’s Fourth Supplemental Testimony. In response to a December 17, 2021, Ruling, PG&E provided additional information on different amortization scenarios for the ERRA-Main balance on December 28, 2021, through its Fifth Supplemental Testimony. PG&E also submitted reply comments on December 30, 2021. On January 4, 2022, parties participated in a meet-and-confer meeting and provided statements on January 6, 2022. On January 14, 2022, the ALJ issued a Ruling modifying the procedural schedule, with a final decision now expected on February 10, 2022. • Background: Energy Resource and Recovery Account (ERRA) forecast proceedings establish the amount of the PCIA and other non-bypassable charges 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. • Details: 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. Under the December Update, the 2022 total PCIA rate for 2017-vintaged customers (i.e., most VCE customers) would fall 59% relative to 2021 to $0.01974/kWh for residential customers and to $0.01898/kWh on a system-average basis.
CalCCA and the Joint CCAs support a 12-month amortization of the revenue requirements presented in the December Update, rather than the 18-month or 24-month scenarios presented by PG&E in its Fifth Supplemental Testimony in late December. PG&E and DACC also support the 12-month amortization, and Public Advocates Office does not oppose it. In contrast, the California Large Energy Consumers Association, Agricultural Energy Consumers Association, and California Farm Bureau Federation advocate for a 24-month amortization period.
On January 14, 2022, the ALJ issued a Ruling modifying the procedural schedule by pushing back the date of the issuance of a PD. The final decision is now expected to be approved on February 10, 2022.
• Analysis: PG&E agreed with the Joint CCAs on the SF headquarters allocation. It continued to fight against transparency in its rates, but then caved on providing the prior year’s workpapers to the CCAs in each case in its Reply Brief. Based on a decision to the Joint CCAs’ (including VCE) PFM in the GTSR proceeding, PG&E will include a change to its GTSR ratemaking that would change the program from a discount to a premium. Lastly, PG&E continues to fight against parties being able to analyze its CPE transactions in a transparent manner. 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 year’s forecast case may be too high compared to next year’s actuals, which would create large 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.
• Next Steps: The next steps are the issuance of a Proposed Decision, followed by an opportunity for comments and the adoption of a final decision, anticipated to be issued on January 24, 2022.
Comments on the PD will be due January 31, 2022, reply comments are due February 3, 2022, and a final decision can be adopted on February 10, 2022. 41 7
• Additional Information: 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.
RPS Rulemaking
On December 8, 2021, the IOUs filed a Joint Motion requesting an expansion of the scope of this rulemaking to consider issues pertaining to the Voluntary Allocation and Market Offer. On December 10, 2021, the ALJs issued a Proposed Decision on draft 2021 RPS Procurement Plans, which the CPUC approved, issuing D.22-01-004 on January 18, 2022. D.22-01-004 directs retail sellers including VCE to file final Plans by February 17, 2022. VCE was praised for its sections on portfolio diversity and reliability, which the CPUC identified as an example for other retail sellers to follow when updating their RPS Plans.
On December 16, 2021, the CPUC issued D.21-12-032 modifying the Renewable Market Adjusting Tariff (ReMAT).
• Background: This proceeding addresses ongoing RPS issues. VCE submitted its Final 2020 RPS Procurement Plan on February 19, 2021, its Draft 2021 RPS Procurement Plan on July 1, 2021, and its 2020 RPS Compliance Report on August 2, 2021.
On September 18, 2020, the ALJ issued a Ruling attaching Staff’s Proposed Framework for integrating RPS Procurement Plan requirements into the IRP proceeding uses a two-phased approach that makes a relatively minor change to RPS reporting in the current IRP cycle, while fully integrating all elements of RPS Procurement Plans into the next IRP cycle, proposed to commence in the 2023 calendar year (instead of 2022, under the current two-year cycle, although the issue of a two-year versus three-year cycle is not discussed). It is currently unclear when the CPUC will address this proposal.
• Details: D.22-01-004 directs VCE to include in its Final 2021 RPS Procurement Plan due February 17, 2022, a discussion “explain[ing] how mid-term reliability procurement obligations impact RPS compliance requirements and how they are included in the quantitative assessment" and update its Project Development Status section to provide additional narrative description of project status. In addition to receiving praise for its sections on portfolio diversity and reliability, VCE is identified as falling under the category of having its current contracts forecasted to meet its 65% long-term contract requirement in contrast to numerous other CCAs and ESPs. D.22-01- 004 declined a request by CCAs to allow party comments early in the process on the timing and structure of RPS Procurement Plan filings, finding that the CPUC "do[es] not expect any substantial new filing requirements" and that the requirements have been well established by now. D.22-01-004 also approved a request by several CCAs and directed Energy Division to set a process whereby they inform a retail seller that its Final RPS Plan met the expectations of the Commission.
D.21-12-032 requires IOUs to accept facilities with storage devices in their ReMAT programs, establishes a de minimis threshold for each product category, and a process through which the IOUs must aggregate remaining capacity across one or two of the three product categories, if necessary, to meet their individual shares of the statewide ReMAT capacity target. It also find that CCAs and other LSEs are not eligible to take on any of the IOUs’ ReMAT procurement targets.
D.21-12-032 declined to address a petition for modification filed by PG&E and SCE that requested authority to recover the above-market costs associated with existing and future ReMAT contracts through the equal-cents per kilowatt hour PPP charge that is applied to all distribution customers including CCAs and stated that this issue will be addressed before this proceeding closes or be scoped into the successor RPS proceeding.
The IOUs’ Joint Motion request that the CPUC (1) expand the scope of this proceeding to address whether RECs retain their original PCC classification upon allocation under the Voluntary Allocation process; (2) issue guidance on the issue of the PCC classification of allocated RECs 42 8
before LSEs are required to decide whether to accept allocations on May 1, 2022; 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.
• Analysis: D.22-01-004 directs VCE to file a final 2021 RPS Procurement Plan with only a limited number of modifications needed, finding VCE’s draft plan to be compliant in nearly every area it addressed. D.22-01-004 also will help remove the uncertainty about whether and when VCE's Final RPS Plan is deemed compliant in the future by establishing a process for Energy Division to let retail sellers know when their final plans have been approved, as opposed to the current process which does not include retail sellers receiving any such notification. • Next Steps: VCE’s Final 2021 RPS Procurement Plan is due February 17, 2022. R.18-07-003 is expected to close in September 2022, with a new proceeding to be opened to address RPS issues going forward.
• Additional Information: 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); Ruling establishing issues and schedule for 2021 RPS Procurement Plans (March 30, 2021); D.21-01-005 directing retail sellers to file final 2020 RPS Procurement Plans (January 20, 2021); Ruling on Staff proposal aligning RPS/IRP filings (September 18, 2020); Scoping Ruling (November 9, 2018); Docket No. R.18-07-003.
Utility Safety Culture Assessments
On December 29, 2021, parties filed reply comments regarding the preliminary scope and schedule provided in the Order Instituting Rulemaking for this rulemaking to develop and adopt IOU safety culture assessments under SB 901.
• 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 first of which will be published in fall 2021. 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 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 rulemaking implements SB 901. • Details: This proceeding will implement the statutory requirements of SB 901 relating to the Commission’s assessment of safety culture for regulated utilities. It will 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. It will also consider adopting the process and framework to oversee safety culture assessments of gas utilities and gas storage operators, in addition to electrical corporations as required by SB 901. It will consider requiring that IOUs implement specific safety management practices to improve safety culture through adoption of a Safety Management System standard, consider adopting a maturity model to use in safety culture assessments, and determine accountability metrics.
No CCA parties filed comments or reply comments on the Order Instituting Rulemaking. • Analysis: This rulemaking will assess the safety culture of PG&E and other IOUs in California.
While its direct focus is on IOUs like PG&E, it could impact VCE and its customers to the extent it influences PG&E’s safety culture and contributes to the safety of VCE customers, as well as the 43 9
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 prehearing conference is expected to be held, followed by the issuance of a Scoping Memo and Ruling that will identify the issues in scope in this proceeding and the procedural schedule.
• Additional Information: Order Instituting Rulemaking (October 7, 2021); Docket No. R.21-10- 001.
PG&E’s Phase 2 GRC
On January 12, 2022, PG&E held a Settlement Conference that discussed a draft settlement on the outstanding real-time pricing issues in this proceeding. • 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.
• Details: The proceeding remains open to address real-time pricing issues, with an evidentiary hearing on the topic scheduled later this month. According to PG&E, a draft settlement is in the works, but at this time no settlement agreement has been filed. • Analysis: This phase of the proceeding could impact real-time pricing rate design issues for PG&E customers.
• Next Steps: The proceeding remains open to address RTP issues. A Meet and Confer is scheduled for January 18, 2022. An evidentiary hearing on RTP issues is scheduled for January 24-26, 2021, followed by opening briefs in February 2022, reply briefs in March 2022, a proposed decision in June 2022, and a decision in July 2022.
• Additional Information: 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); Docket No. A.19-11-019.
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PG&E Phase 1 GRC
No updates this month. On November 5, 2021, PG&E filed a motion requesting modifications to the procedural schedule.
• 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. PG&E will file its next Phase 2 GRC application by September 30, 2021.
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:
o 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. o 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. o 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 will address the majority of matters, including PG&E’s requested revenue requirement together with safety and environmental and social justice issues. Track 2 will address 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, also address safety and environmental and social justice. In addition to establishing the scope and schedule of the proceeding, the Scoping Memo and Ruling directed PG&E to serve testimony to seek approval for any revisions to the forecasted expenditures for its 10,000-mile undergrounding proposal that fall within the timeframe covered by this proceeding. In addition, in an effort to further explore the available affordability metrics based on a motion by TURN, the Scoping Memo and Ruling directed PG&E to work with Energy Division to prepare an analysis, due one month before intervenor testimony is due. However, TURN’s motion requesting a Ruling requiring PG&E to supplement its proposal with an alternative spending plan that limits the growth in proposed spending by the rate of inflation was denied.
• Details: 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 that Q4 2022 as indicated in the Scoping Memo and Ruling of PG&E’s July 16, 2021 Motion for a January 1, 2023 effective date for its 2023 revenue requirement. • 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 45 11
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 next steps in Track 1 are public participation hearings in January/February 2022, a PG&E status report in February 2022 regarding changes to its cost forecast for wildfire programs, a PG&E affordability metrics report at least one month before intervenor testimony, PG&E testimony on its 2021 recorded expenditures by March 22, 2022, and intervenor testimony on April 29, 2022. Proposed and final decisions are anticipated in Q2 2023.
In Track 2, public participation hearings are scheduled for November 2022, and intervenor testimony is due November 14, 2022. A proposed decision is anticipated in Q2 2023, and a final decision is anticipated in Q3 2023.
• Additional Information: 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.21-06-021.
2022-2023 Wildfire Fund Nonbypassable Charge Rulemaking On December 6, 2021, the CPUC issued D.21-12-006 adopting a Wildfire Fund NBC of $0.00652/kWh for January 1, 2022, through December 31, 2022.
• Background: This rulemaking continues to implement AB 1054, which extended a non-bypassable charge on ratepayers to fund the Wildfire Fund. The CPUC issued D.20-12-024 in December 2020 that continues the Wildfire Non-Bypassable Charge (NBC) amount of $0.00580/kWh for January 1, 2021, through December 31, 2021. The NBC amount of 2022 and 2023 will be established in this proceeding.
• Details: The 2022 Wildfire Fund Non-Bypassable Charge is $0.00652/kWh, up from $0.0058/kWh in 2021. The reason for this increase is that the Department of Water Resources 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 the 2022’s necessary revenue requirement of $902.4 million. • Analysis: VCE customers will pay the 2022 and 2023 Wildfire Fund Non-Bypassable Charge 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 need to be the 2023 Wildfire Fund Non-Bypassable Charge.
• 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.
RA Rulemaking (2023-2024)
The Assigned Commissioner issued a Scoping Memo and Ruling on December 2, 2021. Parties filed Phase 1 proposals on December 13, 2021, a workshop was held on December 14, 2021, new and revised proposals were filed December 23, 2021, comments on proposals and the workshop were submitted January 5, 2022, and reply comments were submitted January 13, 2022. Workshops were also 46 12
held on behind-the-meter (BTM) RA counting for hybrid and storage resources and to develop PG&E’s Slice-of-Day proposal and related RA program structural reform. • 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 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 is further developed, is best positioned to be implemented in 2023 for the 2024 compliance year. Therefore, it 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 PG&E Slice of Day Framework will establish RA requirements based on a “slice-of-day” framework, which seeks to ensure load will be met in all hours of the day, not just during gross peak demand hours. The proposal also attempted to ensure there is sufficient energy on the system to charge energy storage resources. The proposed framework would establish RA requirements for multiple slices-of-day across seasons and would establish a counting methodology to reflect an individual resource’s ability to produce energy during each respective slice (e.g., six four-hour periods of the day).
The OIR establishes two tracks to this rulemaking. First, the ongoing major RA structural reforms being considered through a workshop process based on PG&E’s “slice-of-day” proposal (previously referred to as “Track 3B.2” in the R.19-11-009 RA rulemaking), is now the “Reform Track” in this rulemaking. All other issues relating to RA procurement obligations and program implementation details will be separated into an “Implementation Track.” The Implementation Track will address Local RA requirements for 2023-2026, Flexible RA requirements for 2023- 2024, potential modifications to the Central Procurement Entity structure and process, potential modifications to the Planning Reserve Margin, potential modifications to Qualifying Capacity Counting Conventions and Effective Load Carrying Capability (i.e., how different types of resources are counted and credited for RA compliance), and refinements to the RA program.
The CPUC authorized the creation of a BTM Counting Convention Working Group in D.21-06- 029, which was the RA decision that adopted local capacity obligations for 2022-2024, flexible capacity obligations for 2022, and refinements to the RA program. The final product of the working group will be a report that covers both a set of eight issues identified by the CPUC and explicit proposals.
• Details: The 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 Workshop Report to be submitted into the RA proceeding in February 2022. The Implementation Track is sub-divided into Phases 1, 2, and 3:
o Phase 1 of the Implementation Track will consider critical modifications to the CPE structure. Phase 1 is expected to conclude by March 2022. o 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, which include: Modifications to the Planning Reserve Margin Qualifying Capacity Counting Conventions, which among other proposals will consider the Energy Division's biennial update to the Effective Load Carrying Capability values for wind and solar resources, including the development of regional values for wind resources. Phase 2 is expected to conclude in June 2022. o 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 Energy Division may also be considered. Phase 3 is expected to conclude by June 2023.
• Analysis: This proceeding will determine VCE’s RA obligations and applicable RA rules for the 2023-2024 compliance periods. It will also be the forum for determining major RA structural reforms, such as those being discussed related to PG&E’s “slice-of-day” proposal. The workshop process on PG&E’s Slice of Day proposal could result in major changes to the RA program structure beginning in the 2024 RA compliance year. The new structure would seek to ensure 47 13
load (including energy storage charging) will be met in all hours of the day, not just during gross peak demand hours and would move RA from a monthly compliance obligation to a seasonal obligation. The details of the framework would be further fleshed out through the workshop process and need to be approved by the CPUC in 2022.
• Next Steps: The procedural schedule for the ongoing tracks and working groups are as follows:
Phase 1
• Proposed Decision: February 2022
• Final Decision: March 2022
Phase 2
• Party and Energy Division proposals: January 21, 2022 • Workshop on proposals: February 2022
• Comments on workshop/proposals: February 14, 2022
• Reply comments on workshop/proposals: February 24, 2022 • Proposed Decision: May 2022
• Final Decision: June 2022
Reform Track
• Workshops: concluding January 19, 2022
• Workshop report: February 2022
BTM Counting Convention Working Group meeting dates (9am-1pm): January 28, 2022; February 8, 2022; February 22, 2022.
• Additional Information: 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’s 2019 ERRA Compliance
On January 18, 2022, intervenors filed Phase 2 testimony. • 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:
o 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 PSPS events? o 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 IOUs’ testimony provided additional information on the common methodology for calculating the potential unrealized sales that may result from a PSPS event to be used in a potential rate disallowance, which relies on the energy-related portion of the CPUC-jurisdictional distribution charge for this purpose. CCA representatives pushed back at the October 26, 2021, workshop that the IOUs had not considered unrealized revenues from utility-owned generation that had not been bid into the CAISO market. The ALJ requested the CCAs make a motion to clarify whether that issue is in scope in the proceeding. 48 14
Accordingly, 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: According to the Joint IOUs’ proposal, only energy-related distribution rates would be used to determine the unrealized revenue from end-use customers de-energized during PSPS events, ignoring several additional retail rates and other sources of revenue that are reduced by PSPS events.
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 describes 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 explain 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 recommend the following:
1. 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.
2. Each IOU should make a full accounting of the balancing accounts implicated by the total unrealized retail revenue.
3. 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.
4. 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 disallowance. VCE’s customers could benefit from such a CPUC-determined disallowance, e.g., via a bill credit or reduced PG&E charges. The November 12, 2021, Ruling clarified that CCAs may dispute the Joint IOUs’ unrealized revenue methodology and conduct discovery and propose alternative methodologies, such as those that would fairly consider unrealized revenues from utility-owned generation that had not been bid into the CAISO market unlike the Joint IOUs’ proposal.
• Next Steps: IOU rebuttal testimony is due February 15, 2022, and a Joint Case Management Statement is due February 25, 2021.
• Additional Information: 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 49 15
Memo and Ruling (June 19, 2020); PG&E’s Application and Testimony (February 28, 2020); Docket No. A.20-02-009.
PCIA Rulemaking
On December 17, 2021, the ALJ issued a Proposed Decision targeting improvements to the process of establishing the PCIA in ERRA proceedings. Parties filed comments and replies on the PD, respectively, on January 6, 2022, and January 11, 2022. Parties also filed responses on December 9, 2021 and replies on January 6, 2022 in response to a November Ruling requesting comments on CalCCA’s proposal to authorize a nondisclosure agreement to allow CCAs and other entities with customers who pay the PCIA to access confidential, market-sensitive ERRA and PABA monthly report data year-round for the limited, non-proceeding purpose of developing PCIA rate forecasts. • 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. Phase 2 relied primarily on a working group process to further develop a number of PCIA-related proposals. Three workgroups examined three issues: (1) issues with the highest priority: Benchmark True-Up and Other Benchmarking Issues; (2) issues to be resolved in early 2020: Prepayment; and (3) issues to be resolved by mid-2020: Portfolio Optimization and Cost Reduction, Allocation and Auction.
D.20-08-004, in response to the recommendations of Working Group 2, (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 mutually acceptable terms and conditions that adequately mitigate the risks identified by Working Group Two.
The Phase 2 Decision, D.21-05-030, addressed the recommendations of PCIA Working Group 3 and 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 challenges the Decision’s rejection of the RA voluntary allocation and market offer and GHG-free energy allocation. It argues that D.21- 05-030 violates Public Utilities Code Section 366.2(g), which guarantees CCA customers the full benefit of the resources for which they bear cost responsibility through the PCIA charge. While CCA customers pay for the RA and GHG-Free products in the PCIA portfolio, the Phase 2 Decision, provides only bundled customers preferential access to RA products and no access to GHG-Free energy on a long-term basis. The CCA Parties argue that since D.21-05-030 effectively requires unbundled customers to pay equally for benefits only bundled customers receive, the Phase 2 Decision also violates the Section 365.2 prohibition against cost-shifting among unbundled and bundled customers.
A Staff Proposal on which the August Ruling requested comments would move the Market Price Benchmark calculation date up by one month – from November 1 to October 1 – to allow for a “normal” proceeding schedule and enable flexibility in addressing last- minute issues. Staff’s analysis found that the effects of changes in the forecast RPS and RA adders on PCIA rates are relatively small and concluded that the largest driver of changes to PCIA rates would be the energy index.
• Details: The PD modifies 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 would adopt party proposals to establish a policy for 50 16
disposition of the year-end balance in the ERRA account and to modify the calculation of the ERRA trigger point and threshold. It also adopts party proposals to support efficient party access to ERRA forecast proceeding data.
The PD would keep the proceeding open to consider additional Phase 2 issues, including:
o Whether greenhouse gas-free resources are under-valued in the PCIA, and if so, whether to adopt an adder or allocation mechanism.
o Whether to adopt a new method to include long-term fixed-price transactions in calculating the Renewables Portfolio Standard adder.
o Whether to modify the calculation of the PCIA energy index market price benchmark. o Whether to provide CCAs with access to confidential, market sensitive ERRA monthly reports information for the non-proceeding purpose of creating PCIA rate forecasts.
CalCCA expressed support for the PD. The one substantive change it recommended is that the PD direct that each ERRA proceeding’s schedule require the IOUs to provide their updated prepared testimony no later than 14 days following the issuance of the market price benchmarks (MPB) on October 1.
• Analysis: The PD would make improvements to the annual ERRA process and CCA access to pertinent IOU data. The issues on which parties filed comments in response to a November Ruling impact CCAs’ ability to gain access to confidential IOU data pertinent to the calculation and implementation of the PCIA.
• Next Steps: The PD may be heard, at the earliest, at the Commission’s January 27, 2022 Business Meeting. In addition, D.21-05-030 identified the following next steps:
o January 2022: Once the 2021 RFIs are approved, the IOUs may request approval for Contract Assignments and Contract Modifications in response to the RFI by filing Tier 3 advice letters.
o February 2022: After approval of the joint methodology advice letter, IOUs will inform LSEs of their potential Voluntary Allocation shares.
o May 2022: IOUs and LSEs complete the process of determining interest in Allocation elections.
o June 2022: Each IOU confirms Voluntary Allocations and propose Market Offers in their 2022 RPS Procurement Plans. LSEs request approval for Voluntary Allocations in their 2022 RPS Procurement Plans.
• Additional Information: Proposed Decision on Phase 2 (December 17, 2021); Ruling requesting comments on PCIA forecasting data access (November 5, 2021); Ruling requesting comments (September 17, 2021); CalCCA Application for Rehearing of D.21-05-030 (June 23, 20210: 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.
Provider of Last Resort Rulemaking
On December 17, 2021, parties filed comments in response to the November 23, 2021, ALJ Ruling posing questions addressing: (1) clarity and content of the Workshop 1 notes filed by CalCCA on 51 17
November 5, 2021, and (2) questions on Workshop 1 and what changes if any are recommended to adequately meet POLR requirements. A January 13, 2022, email to parties tentatively rescheduled the date of the second workshop to February 22, 2022.
• Background: A 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). In 2019 the Legislature passed SB 520, which defined POLR for the first time in statute, confirmed that each IOU is the POLR in its service territory, and directed the Commission to establish a framework to allow other entities to apply and become the POLR for a specific area (a “Designated POLR”). This rulemaking will implement SB 520.
The Scoping Memo and Ruling describes the issues that are within scope in the proceeding and the procedural schedule going forward, although most of the procedural dates currently lack specificity. 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. • Details: CalCCA comments included the following recommendations:
o POLR service should be limited to 60 days to allow returned customers to transition from the returning LSE to the customer’s chosen LSE, consistent with the existing “safe harbor” provision for DA switching.
o Given the limited term and scope of service and the need to avoid unnecessary costs, the POLR should not engage in advance procurement or hedging. o RPS and IRP responsibility for returned customers should shift directly from the returning LSE to the customer’s new LSE, with a waiver of these obligations for the POLR consistent with the existing waiver for RA obligations adopted in D.20-06-031. o The CPUC should compare Reentry Fees and actual costs for Western Community Energy’s customer return to determine whether the current formulation provides sufficient precision to ensure a reasonable outcome.
o A POLR right of first refusal of procurement contracts held by the returning LSE raises legal and commercial issues and should not be considered. o To minimize the risk of LSE default by newly launched CCA, Implementation Plan requirements should be modified to incorporate a milestone procedure to be administered by the CCA’s governing board, quarterly updates to Energy Division on the status of milestone achievement, transparency through the use of a publicly available information portal available, and feasibility studies provided to the local governing board built on transparent and standardized referents.
o Financial service requirements (FSR) should vary with the financial health of an LSE, limiting FSRs for LSEs maintaining investment-grade credit ratings and LSEs voluntarily providing limited metrics to the CPUC for review; all other LSEs should bear responsibility for the currently formulated FSR.
• 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.
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• Next Steps: Reply comments are due February 25, 2022. A second workshop in Phase 1 has been tentatively rescheduled for February 22, 2022.
• Additional Information: 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
No updates this month. On October 15, 2021, parties filed a Settlement Agreement resolving disputed issues in this proceeding.
• Background: The annual ERRA Compliance proceeding reviews the utility’s compliance with CPUC-approved standards for generation-procurement and cost recovery activity occurring in the preceding year, such as energy resource contract administration, least-cost dispatch, fuel procurement, and balancing account entries.
PG&E is requesting that the CPUC find it complied with its Bundled Procurement Plan (BPP) in the areas of fuel procurement, administration of power purchase contracts, greenhouse gas compliance instrument procurement, resource adequacy sales, and least-cost dispatch of electric generation resources for the 2020 calendar year. It also seeks a CPUC finding that it managed its utility-owned generation (UOG) facilities reasonably, although it recommends that CPUC review of outages at Diablo Canyon Power Plant related to the Unit 2 main generator be delayed to the 2021 ERRA Compliance review. Of significance to the PCIA, PG&E is requesting the CPUC find that entries in its Portfolio Allocation Balancing Account (PABA), which trues up the above-market forecast of generation resources recovered through the PCIA with actual recorded costs and revenues, are accurate.
PG&E’s procurement costs recorded across the portfolio were $158.8 million higher than forecasted, allegedly due to higher-than-forecast RPS-eligible contracts, as offset by higher than forecast retained RPS and retained RA, as well as lower than forecast fuel costs for UOG facilities. Activity recorded in the PABA includes the following categories: Revenues from Customers, RPS Activity, RA Activity, Adopted UOG Revenue Requirements, CAISO Related Charges and Revenues, Fuel Costs, Contract Costs, GHG Costs, and Miscellaneous Costs.
PG&E has redacted as confidential its 2020 actual and forecast costs for these categories, so it is unclear from the public filing what the magnitude is regarding the difference between actual and forecast costs for each category.
The Scoping Memo and Ruling specifies the proceeding will be divided into two phases. Phase 1 will address whether PG&E (1) prudently administered and managed Utility-Owned Generation facilities and QF and non-QF contracts, (2) achieved least-cost dispatch of energy resources, (3) had reasonable, accurate, and appropriate ERRA and PABA entries, and (4) administered RA procurement and sales consistent with its Bundled Procurement Plan, among other issues. Phase 2 issues may be amended based on the outcome of Phase 2 of PG&E’s 2019 ERRA compliance proceeding. The tentative list of issues include whether sales forecasting methods for adjusting revenue requirement under current decoupling policy should be adjusted to account for power not sold or purchased during a Public Safety Power Shutoff (PSPS) event in 2020, whether it is appropriate for PG&E to return the revenue requirement equal to the estimated unrealized volumetric sales and unrealized revenue resulting from the PSPS events in 2020, and the appropriate methodology for calculating PG&E’s unrealized volumetric sales and unrealized revenues resulting from 2020 PSPS events.
In testimony, Joint CCAs recommended a number of accounting adjustments that would reduce PUBA balances by more than $14.3 million. They also recommend the CPUC acknowledge that PG&E’s internal audit of its PABA concluded that the processes and controls governing PABA 53 19
accounting are “Not Adequate,” and that PG&E remedy the identified deficiencies. Furthermore, they recommend that the CPUC clarify that future procurement expenses incurred by PG&E acting as the Central Procurement Entity will be reviewable in ERRA Compliance proceedings, and that PG&E should demonstrate the effect of such procurement, if any, on the PABA and ERRA balancing accounts.
PG&E agreed in rebuttal testimony that the accounting for PCIA costs attributed to customers taking service on the GTSR tariff should be adjusted to correctly credit PABA for the 2019 and 2020 record periods, reducing the PABA balance by approximately $5 million. PG&E also agreed to present testimony in its 2021 ERRA Compliance proceeding addressing actions taken in response to the Internal Audit findings that PABA accounting process and controls were inadequate.
• Details: In the Settlement Agreement, PG&E agreed with the Joint CCAs’ position to a disallowance of $247,500 associated with CAISO penalties for load meter data errors, late submission of Resource Adequacy and Supply Plans and missed deadlines for grid modeling data or telemetry communication for PG&E’s utility owned generation and that any future sanctions for missed deadlines for grid modeling data or telemetry communication for PG&E’s utility-owned generation will not be recovered from customers. Joint CCAs agreed that CAISO sanctions associated with Power Purchase Agreements (contracted generation) were caused by the counterparty and passed through to the counterparty and should not be disallowed.
PG&E agreed that entries to the PABA for costs associated with the Green Tariff Shared Renewables program should be reduced by $5 million for 2019 and 2020, as Joint CCAs had argued.
PG&E also agreed that certain issues should be in the scope of future ERRA proceedings, resolving the Joint CCA concern regarding its ability to review PG&E’s accounting with respect to transactions with the CPE in future ERRA Compliance proceedings.
Finally, PG&E agreed to transfer from PABA to ERRA 2014 and 2017 Diablo Canyon Seismic Studies Balancing Account recorded costs, whereas the 2018 costs were retained in the PABA, which resolved the Joint CCAs concerns about that cost recovery. • Analysis: This proceeding addresses PG&E’s balancing accounts, including the PABA, providing a venue for a detailed review of the billed revenues and net CAISO revenues PG&E recorded during 2020. It 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: A PD is anticipated for Q1 2022.
• Additional Information: 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.
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 54 20
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. The Ruling declined to close the proceeding but also declined to move forward with CCAs’ consideration of whether PG&E’s holding company structure should be revoked and whether PG&E should be a “wires-only company,” as well as developing a plan for service if PG&E's CPCN is revoked in the future.
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. This six-step process could ultimately result in a revocation of PG&E’s certificate of public convenience and necessity if it fails to take sufficient corrective actions. Resolution M-4852 found that PG&E made insufficient progress toward approved safety or risk-driven investments and is not sufficiently prioritizing its Enhanced Vegetation Management (EVM) based on risk. It found that PG&E is not doing the majority of EVM work – or even a significant portion of work – on the highest risk lines.
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 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.
• 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 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.
PG&E Regionalization Plan
55 21
No updates this month. On September 10, 2021, Parties, including VCE, filed comments on the August 31, 2021, motion for approval of settlement agreements, followed by reply comments on September 17, 2021.
• Background: In D.20-05-051 approving PG&E’s reorganization following bankruptcy, PG&E was directed to file a regionalization proposal (Docket No.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 proposes to divide its service area into five new regions. PG&E will appoint a Regional Vice President by June 2021 to lead each region, along with Regional Safety Directors to lead its safety efforts in each region. 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 M&C, (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. In addition, five CCAs filed responses or protests to PG&E’s application, with MCE and EBCE filing protests and City of San Jose, City and County of San Francisco, and Pioneer Community Energy filing responses.
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. PG&E also provided more information on the new leadership positions that it is creating and its “Lean Operating System” implementation.
Currently, PG&E is in Phase 1 of 3 of its regionalization plan, which is focused on refining regional boundaries, establishing roles and governance for regional leadership, and recruiting and hiring for those positions. In Phase 2 (second half of 2021 through 2022), PG&E will establish and implement the regional boundaries and provide the resources and staffing to support it. In Phase 3 (2023 and after), PG&E will continue to reassess, refine and collaborate with other functional groups to improve efficiencies, safety, reliability and customer service.
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). 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 for stakeholders. The proposed settlement would restrict 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.
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• Details: VCE filed comments on 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. • Analysis: The implications of PG&E’s regionalization plan on CCA operations, customers, and costs are largely unclear based on the information presented in PG&E’s application and updated application. 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.
• Next Steps: A Proposed Decision will be issued next. In light of CPUC President Batjer’s imminent departure, it appears that issuance of a Proposed Decision has been delayed. • Additional Information: 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.
Direct Access Rulemaking
No updates this month. On August 13, 2021, CalCCA filed a response to a July application for rehearing filed by a coalition of parties supporting expansion of Direct Access, who challenged a June CPUC decision that recommended against any re-opening of Direct Access. This proceeding is otherwise closed.
• 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. Further portions of the Decision:
o Observed that Direct Access providers do not have a track record of relying on long-term contracts to meet their energy needs, which could impede the development of new, needed resources.
o Noted that allowing expansion could undermine the long-term contracts that LSEs such as CCAs have already entered (i.e., due to load migration) and make it difficult for them to enter new contracts.
o Stated that currently, the CPUC is not able to ensure that Direct Access expansion would not increase GHG emissions and other pollutants when compared to retaining the current 57 23
cap, as Direct Access providers have historically relied primarily on unspecified power and lead to a net decline in clean energy procurement.
• Details: In their July Application for Rehearing, parties including the Alliance for Retail Energy Markets and the Direct Access Customer Coalition argued that:
o The CPUC broke the law and abused its discretion when it disregarded the express duties imposed on it by SB 237.
o D.21-06-033 ignored the substantial evidence in the record as it pertains to: (1) concerns about electric service provider (ESP) procurement performance and (2) the alleged threat to reliability posed by load migration due to an expansion of Direct Access is inaccurate and discriminatory.
o D.21-06-033 discriminates against non-residential customers and the ESPs that wish to serve them, thereby violating the dormant Commerce Clause of the US Constitution. o D.21-06-033 relied on "misrepresentations of facts and speculations." CalCCA’s August response argued that:
o The CPUC’s interpretation of the statute was consistent with its plain language and legislative history.
o The Decision is supported by the findings required by statute and is also adequately supported by findings based on the entire administrative record. o The dormant Commerce Clause argument fails because the Decision applies equally to both in-state and out-of-state ESPs, and therefore does not unfairly discriminate against out-of-state interests.
o The argument that the Decision discriminates against both ESPs and their customers and therefore violates their Equal Protection rights fails the “rational basis” test in that the Decision is based on the findings regarding electric grid reliability and environmental concerns.
• Analysis: This proceeding determined the CPUC’s recommendations to the Legislature regarding the potential future expansion of DA in California. D.21-06-033 recommending against 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.
RA Rulemaking (2021-2022)
No updates this month. On October 11, 2021, parties filed responses to OhmConnect’s Petition for Modification of D.20-06-031, to which OhmConnect responded on October 25, 2021. The October 11, 2021, Order Instituting Rulemaking in the successor RA rulemaking, R.21-10-002, closed this proceeding, except to resolve OhmConnect’s Petition for Modification. • Background: This proceeding is divided into 4 tracks, with the focus in 2021 being on Tracks 3 and 4, described in more detail below. Going forward, a workshop process will be used to generate an RA restructuring proposal in Q1 2022, with the goal of implementing more substantial program changes in 2023 for the 2024 RA compliance year. 58 24
Track 3A (completed): D.20-12-006, issued December 2020, addressed the issues of the financial credit mechanism and competitive neutrality rules for the CPEs. It approved CalCCA’s proposed “Option 2,” with modifications, which allows the CPE to evaluate the shown resource alongside bid resources to assess the effectiveness of the portfolio. The financial credit mechanism will apply only to new preferred or energy storage resources (i.e., non-fossil-based resources) with a contract executed on or after June 17, 2020. It also adopted PG&E’s competitive neutrality proposal for PG&E’s service territory. Finally, D.20-12-006 found that the Local Capacity Requirements Working Group should continue to discuss recommendations and develop solutions for consideration in CAISO’s 2022 LCR process.
Track 3B.1 and Track 4 (completed): 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. It required resources in all MCC buckets to have availability on Saturday for the 2022 RA compliance year. This had the effect of modifying the DR and Categories 1 and 2 buckets to add Saturday. DR contracts with an execution date prior to the effective date of D.21- 06-029 will be grandfathered and not subject to the new Saturday availability requirement. It also revised the Category 1 availability criteria (4 consecutive hours of availability from 4-9 p.m. from May-September) to increase the monthly minimum availability from 40 hours to 100 hours (and 96 hours for February) and to require year-round availability. D.21-06-029 requested that the CEC launch a stakeholder working group process as part of the 2021 IEPR and make recommendations on several topics intended to support a comprehensive and consistent DR measurement and verification strategy, to be considered for implementation during the 2023 RA compliance year. Finally, D.21-06-029 added a new RA deficiencies penalty structure to the current penalty structure, layering on a penalty multiplier for repeat RA deficiencies based on a point system beginning in the 2022 RA compliance year.
Track 3B.2 (Ongoing, now in R.21-10-002): D.21-07-014 rejected CalCCA/SCE's proposal for restructuring the 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 is further developed, is best positioned to be implemented in 2023 for the 2024 compliance year.
Therefore, it 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 PG&E Slice of Day Framework will establish RA requirements based on a “slice-of-day” framework, which seeks to ensure load will be met in all hours of the day, not just during gross peak demand hours. The proposal also attempted to ensure there is sufficient energy on the system to charge energy storage resources.
The proposed framework would establish RA requirements for multiple slices-of-day across seasons and would establish a counting methodology to reflect an individual resource’s ability to produce energy during each respective slice (e.g., six four-hour periods of the day). • Details: OhmConnect’s Petition for Modification of D.20-06-031 requested that the CPUC raise the demand response Maximum Cumulative Capacity limit of 8.3% to 11.3%. OhmConnect says that the change is needed to create the room for growth envisioned in D.20-06-031 and meet the requirements of the Governor’s Emergency Proclamation ordering state energy agencies to expedite and expand DR programs to reduce the likelihood of future rotating power outages.
A group of CCAs (RCEA, San Diego Community Power, and San José Clean Energy) and EBCE filed responses in support of OhmConnect’s Petition for Modification. The group of CCAs said a higher cap would enable more flexibility for them in meeting their RA requirements, and help California meet system reliability needs. EBCE’s reasons for supporting the petition were provided in a confidential attachment to its response.
• Analysis: If OhmConnect’s Petition for Modification is granted, it would allow LSEs like VCE to procure a higher percentage of demand response resources to meet its RA obligations than it is currently allowed under the RA compliance rules.
• Next Steps: A proposed decision addressing OhmConnect, Inc.’s petition for modification and closing this proceeding is expected to be filed in Q4 2021. 59 25
• Additional Information: 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.
RA Rulemaking (2019-2020)
No updates this month. Two applications for rehearing remain the only outstanding items to be addressed in this proceeding, which is now closed.
• Background: This proceeding had three tracks, which have now concluded. Track 1 addressed 2019 local and flexible 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.
In Track 2, the CPUC previously 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 did not specify the identity of the central buyer) and a multi-year requirements 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 CAM mechanism. D.20-06-002 also established a Working Group (co-led by CalCCA) to address: (a) the development of an 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.
On October 30, 2019, CalCCA filed a PFM of D.19-06-026, seeking the creation of an RA waiver process in 2020 for system and flexible RA obligations. 60 26
Details: The only two remaining items to be addressed in this proceeding are two applications for rehearing filed by Western Power Trading Forum (WPTF). First, on July 17, 2020, WPTF filed an Application for Rehearing of D.20-06-002, the Track 2 Decision creating a multi-year central procurement regime for local RA capacity. It requested rehearing and reconsideration of the rejected settlement agreement between WPTF, CalCCA, and other parties, arguing that D.20-06- 002 will discourage the procurement of local resources by individual LSEs, discriminates against natural gas resources while increasing the need for CAISO backstop procurement, may undermine reliability by making it more difficult to integrate renewables with the larger western grid, and creates a “sale for resale” procurement construct that could place it under FERC’s jurisdiction as a wholesale, rather than a retail, transaction.
Second, on August 5, 2020, WPTF filed an Application for Rehearing of D.20-06-028 with respect to the self-scheduling requirements for non-resource specific RA imports. • Analysis: D.20-06-002 established a central procurement entity and mostly resolved the central buyer issues, although several details are being refined through a Working Group. Moving to a central procurement entity beginning for the 2023 RA compliance year will impact 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.
The Track 1 Decision on RA imports most directly impacted LSEs relying on RA imports to meet their RA obligations by increasing the difficulty of procuring such RA in the future. • Next Steps: The only issues remaining to be addressed in this proceeding are WPTF’s Applications for Rehearing. Remaining RA issues will be addressed in the successor RA rulemaking, R.19-11-009.
• Additional Information: 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.
Glossary of Acronyms
AB Assembly Bill
AET Annual Electric True-up
ALJ Administrative Law Judge
BioMAT Bioenergy Market Adjusting Tariff
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
61 27
CPUC California Public Utilities Commission
CPCN Certificate of Public Convenience and Necessity
CTC Competition Transition Charge
DA Direct Access
DWR California Department of Water Resources
ELCC Effective Load Carrying Capacity
ERRA Energy Resource and Recovery Account
EUS Essential Usage Study
GRC General Rate Case
IEPR Integrated Energy Policy Report
IFOM In Front of the Meter
IRP Integrated Resource Plan
IOU Investor-Owned Utility
ITC Investment Tax Credit
LSE Load-Serving Entity
MCC Maximum Cumulative Capacity
OII Order Instituting Investigation
OIR Order Instituting Rulemaking
PABA Portfolio Allocation Balancing Account
PD Proposed Decision
PG&E Pacific Gas & Electric
PFM Petition for Modification
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
RDW Rate Design Window
ReMAT Renewable Market Adjusting Tariff
RPS Renewables Portfolio Standard
SCE Southern California Edison
SED Safety and Enforcement Division (CPUC)
SDG&E San Diego Gas & Electric
TCJA Tax Cuts and Jobs Act of 2017
62 28
TOU Time of Use
TURN The Utility Reform Network
UOG Utility-Owned Generation
WMP Wildfire Mitigation Plan
WSD Wildfire Safety Division (CPUC)
63 1
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 10
TO: Board of Directors
FROM: Rebecca Boyles, Director of Customer Care & Marketing SUBJECT: Customer Enrollment Update (Information)
DATE: January 27, 2022
RECOMMENDATION
Receive and review the attached Customer Enrollment update as of January 19, 2022.
64 0
20 40
60 80
100
120
140
160
Monthly Opt Outs
Item 10 - Enrollment Update
Status Date: 01/19/22 1
All Winters customers are now enrolled and are included in this table. % of Load Opted Out
Davis Woodland Winters Yolo Co Total Residential Commercial Industrial Ag NEM Non-NEM VCEA customers 27,904 20,650 2,545 10,755 61,854 53,804 6,094 7 1,861 10,841 51,013 Eligible customers 29,182 23,702 2,853 12,307 68,044 59,098 6,699 7 2,136 11,995 56,049 Participation Rate 96% 87% 89% 87% 91% 91% 91% 100% 87% 90% 91% Residential Commercial Industrial Ag Total
10% 9% 0% 13% 10%
65 Davis
77%
Woodland
15%
Unincorp. Yolo
6%
Winters
2%
315 Opt Ups*
0 5
10 15
20 25
Monthly Opt Ups*
Item 10 - Enrollment Update
Status Date: 01/19/22 2
* The numbers in the pie chart represent opt ups for customers who are currently enrolled. The numbers in the bar graph represent opt up actions taken regardless of current enrollment status. 66 0
5 10
15 20
25 Monthly Opt Ups*
Davis Unincorp. Yolo Woodland Winters
0 50
100
150
200
Monthly Opt Outs
Davis Unincorp. Yolo Woodland Winters
Item 10 - Enrollment Update
Status Date: 01/19/22 3
* These numbers represent all opt up actions ever taken regardless of current customer enrollment status. 67 Item 10 - Enrollment Update
Status Date: 01/19/22 4
* These numbers represent all opt up actions ever taken regardless of current customer enrollment status.
Davis
67%
Woodland
21%
Unincorp. Yolo
10%
Winters
2%
486 Opt Ups*
Davis
21%
Woodland
48%
Unincorp. Yolo
27%
Winters
4%
10566 Opt Outs
68 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 11
TO: Board of Directors
FROM: Alisa Lembke, Board Clerk / Administrative Analyst SUBJECT: Community Advisory Committee November 18, 2021 and December 16, 2021 Meeting Summaries
DATE: January 27, 2022
This report summarizes the Community Advisory Committee’s meetings held via Zoom webinar on Thursday, November 18, 2021 and on Thursday, December 16, 2021.
November 18, 2021 Meeting Summary:
A. Received Update on Quarterly Power Content. The CAC received an update on the power content for 2021, including load summary, target versus current estimations, and status of renewable energy contracts (Aquamarine, Putah Creek Energy Farm, and Tierra Buena). It was noted by Staff that the estimated power to be received from the PGE large hydro allocation is significantly less than originally expected due to the drought. Also, due to increased ag pumping and heat storms this summer, additional short term RECs were purchased to meet the RPS requirement.
B. GHG Free 2022 Attributes (large hydro and/or nuclear). Staff presented background information and solicited feedback from the CAC regarding VCE accepting 2022 and beyond allocation of GHG-free attributes (large hydro and/or nuclear) from PG&E. Staff explained that PG&E has been offering GHG-free attributes on a yearly basis; when attributes are accepted a one year agreement is entered into; and, moving forward, if attributes are offered in 2023 and beyond and there are no significant changes in VCE’s position, Staff would provide the offering to the CAC and Board as a consent agenda item.
After a brief discussion, the CAC via a motion, support Staff’s recommendation to recommend to the Board that they accept 2022 allocation of large hydro carbon free attributes; reject 2022 allocation of nuclear power carbon free attributes; and, in the event the future attributes (2023 and beyond) are made available to VCE and there are no major changes in VCE’s position, bring back to the CAC and Board on consent for approval. (7-1- 0). The one no vote was from a CAC member who favors accepting the nuclear as well as the large hydro allocations.
C. Cost-Recovery based Policy and Customer Rate Structure. Interim General Manager Mitch Sears provided an overview of the background on rates, financial update, what information has changed since this item was presented to the CAC and motion adopted by the Board. Mr. Sears reviewed the 2022 reserve target, rate recommendation, rates implementing procedure, and Staff’s recommendation. The CAC discussed the Board’s 69 decision about rates effective November 1, 2021, VCE’s policy to match PG&E generation rates, and how that will affect future rates. The members of the Rates Task Group, Mr.
Kristov and Mr. Braun, then gave a short report. They suggested that the methodologies and information used in forecasting be looked at and discussed soon. The CAC continued to discuss: PG&E’s filing on November 8, 2021 updating PG&E rate increase and power charge indifference adjustment (PCIA) decrease, various budget scenarios, how VCE’s resources will affect budget, current and future forecast modeling, and Staff’s recommendation. After the CAC discussed Staff’s recommendation, the CAC recommend (6-2-0) that the Board approve the following:
• Adopt customer rates for 2022 to match PG&E 2022 generation rates for all customer classes except CARE and FERA customers to cover VCE’s FY 2022 budget expenditures and to achieve 120-150 days cash reserves by the end of 2022;
• Adopt a 2022 rates implementing procedure including the following:
a. Provide a 5% rate discount for CARE and FERA customers in 2022; b. Direct staff to prepare an analysis of budget including an increase to 2022 renewable portfolio content percentage and return to CAC and Board in Q1/2 2022 with recommendations.
c. Direct staff to conduct a review of the VCE Dividend Policy and potential rate discounts including but not limited to:
i. Providing a 5% rate discount for all customer classes during peak summer months in 2022 (June – September.);
ii. Providing an additional 5% rate discount for CARE and FERA customers during peak summer months (June – September.); iii. Allocating additional funds for community program
implementation.
d. and return to CAC and Board in Q1/2 2022 with recommendations.
Lastly, Mr. Sears informed those present that a discussion on forecasting will be brought to the Rates Task Group for further exploration, with the intent of providing an overview of what was discussed back to the CAC at a future meeting soon.
D. Introduction to community resiliency. CAC Member Lorenzo Kristov provided an introduction to community resiliency, defined sustainability and resiliency, and provided an overview of the layered architecture of community resiliency. The CAC are interested in having future conversations on strategies and policies for building resilient communities, including energy resilience. It was suggested that a future workshop be held to bring together experts on resiliency to help inform others on this topic.
E. Reviewed Near-term Procurement Directives and Delegations for 2022 Power Procurement Activities. The CAC received an update on the delegations and directives necessary for VCE and SMUD staff to continue procurement activities on behalf of VCE’s power supply portfolio. Staff provided a high-level overview of the products necessary to meet compliance obligations and maintain a balanced power portfolio while meeting power supply portfolio targets set by the VCE Board.
70 December 16, 2021 Meeting Summary:
A. Reviewed and provided recommendation on VCE 2022 Legislative Platform. The CAC received a detailed review of the draft 2022 Legislative Platform provided by Mark Fenstermaker of Pacific Policy Group. He informed those present that he worked with the Staff and Leg/Reg Task Group by reviewing the 2021 platform. As a result, the 2022 platform had no major edits since many of the bills are still alive and/or may come back in 2022. The CAC recommend that the Board approve the 2022 Legislative Platform outlining a number of legislative issues and positions VCE would take on each. (9-0-0) B. Received preliminary results of zero-carbon portfolio study from Carbon Neutral Task Group. The CAC received preliminary results of the zero-carbon portfolio study, prepared by Energeia USA; and, presented by Staff, Carbon Neutral Task Group members, and Maggie Riley of Energeia USA. Staff sought input from the CAC on the preliminary results before finalizing the report. Several comments were provided regarding generation, storage, availability and accessibility to potential power resources, using the final report as a stepping stone to potentially modify VCE’s renewable energy policy, and hour by hour costs and options. The CAC noted that the report has not been finalized; however, the preliminary results presented tonight are useful and informative.
The CAC made a recommendation that the meeting materials-slides on the preliminary results of the zero-carbon portfolio study be forwarded to the Board for consideration. (9-0-0)
C. Review and discuss formation of CAC Task Groups for 2022. The CAC discussed the formation of task groups for 2022. It was agreed that the Legislative/Regulatory, Outreach and Programs task groups were needed in 2022. Potential task groups focusing on: rates, procurement, carbon neutrality, decarbonization, and resiliency were discussed. As a result of their discussion, both the Rates and Carbon Neutral task groups would continue; however, their “charges” would need to be modified to reflect the current needs of the Board, Staff and goals outlined in VCE’s Strategic Plan. The CAC asked that each task group provide a draft “charge” to be reviewed and discussed at the CAC’s next meeting. The CAC asked that VCE’s Strategic Plan (SP) be distributed to the CAC members for reference; for the task groups to incorporate the goals outlined within the SP into their draft “charges”; and, to work with VCE Staff, when needed, on drafting the “charges”.
D. Strategic Plan update. Mr. Sears updated the CAC on progress of the goals outlined in VCE’s 3 year Strategic Plan. Suggestions were provided by the CAC that the cadence of reporting could possibly be changed from quarterly reports to bi-yearly reporting. To assist with engagement of community and staff, it was suggested that a staff representative from each jurisdiction attend the CAC meetings.
E. Election of 2022 Chair and Vice Chair. Yvonne Hunter will be the Interim Chair and Marsha Baird will be the Interim Vice Chair, both for 3 months time. CAC Members 71 were encouraged to take on these roles and to communicate their interest and/or questions to Interim General Manager Mitch Sears. Outgoing Chair Shewmaker expressed her hope that there would be more financial stability in the year ahead and that would allow the CAC more time to focus on long range goals consistent with VCE’s long term mission. She also mentioned that she felt it was important to not loose sight of the importance of resiliency.
72 1
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 12
TO: Board of Directors
FROM: Alisa Lembke, Board Clerk / Administrative Analyst SUBJECT: Community Advisory Committee 2021 Year End Report DATE: January 27, 2022
RECOMMENDATION
Receive and file the Community Advisory Committee’s 2021 Year End Report.
Attachments:
1. CAC 2021 Year End Report including Task Group Reports 73 VALLEY CLEAN ENERGY
COMMUNITY ADVISORY COMMITTEE
2021 YEAR END REPORT
Background and Introduction
The Community Advisory Committee (CAC) of the Valley Clean Energy Alliance (VCEA) was created by the Board in December 2016 and held its first meeting in August 2017. In September 2017, the Board adopted a “charge” for the CAC outlining its goals, purpose and direction. The CAC charge was updated and approved by the Board in November 2018 and again in January 2021. This report summarizes the main activities and issues addressed by the CAC during 2021.
2021 CAC Members:
Davis: Gerry Braun, Yvonne Hunter, Lorenzo Kristov (through October 2021) Woodland: Mark Aulman, Chris Casey (through May 2021), Christine Shewmaker (Chair) Unincorporated Yolo County: Marsha Baird, Cynthia Rodriguez (Vice Chair), Winters : Peter Meyer (through May 2021), Jennifer Rindahl, David Springer At large member(s): Lorenzo Kristov (October 2021)
Main Activities and Issues Addressed 2021
1. Recommendations to the Board on VCE policy
1. Encouraging new building electrification
2. Strategic Marketing Plan
3. Joining CA Community Power JPA
4. Three Year Program Plan
2. Reviewed and provided input on critical issues facing VCEA, including:
1. Power procurement and load forecasting
2. Finance and budget-related items and rate concerns
3. CAC Structure
3. Organized 2021 task groups to work closely with Staff on pressing issues in key areas driven by the newly adopted Strategic Plan and report back to the full CAC. These were:
Legislative/Regulatory, Outreach, Programs, Rates, and Decarbonization and Carbon Neutral. (Summary reports on work of task group are in the Appendix.)
4. Welcomed new VCE Staff Edward Burnham in April. Saw the departure of contract attorney Harriet Steiner and staff Tessa Tobar in June 2021. 74 Conclusion
Over the past year, the CAC has continued to work closely with Staff and has provided considered insights to the Board on issues, both from their represented communities and on the science and practical issues of the work of VCE. The Committee has been closely directed by the newly adopted Strategic Plan and Environmental Justice statement, current financial issues facing VCE, the law surrounding changes to power sources and requirements, deadlines self-imposed and by law, and the community interest in energy direction. The CAC has assisted in providing essential information for changes to power sources mandated by both required and chosen deadlines to further production of clean energy and the necessity to reach carbon neutrality by 2030. These significant and life altering goals have directed the work of the CAC to advise the VCEA specifically on achieving its highest priorities in energy and the business of delivering safe and clean power, critical to the success of VCEA.
Attachments:
1. Board Charge to the CAC
2. Task Group Summaries
A. Legislative/Regulatory
B. Outreach
C. Programs
D. Rates
E. Carbon Neutral
75 Valley Clean Energy Alliance
Community Advisory Committee
Updated Charge
(January 21, 2021)
Consistent with the policy adopted by the Valley Clean Energy Alliance (VCEA) Board of Directors, the VCEA Community Advisory Committee (CAC) adopts this Charge to guide its activities. • Advise the VCEA Board of Directors and VCEA staff on VCEA’s general policy and operational objectives, including, but not limited to:
• portfolio mix and objectives,
• policy related financial considerations and rate options, and • strategic objectives and plans designed to reduce carbon emissions, accelerate development of local resources and increase energy resilience in member jurisdictions.
• Review implementation and provide input on action options related to VCE’s Strategic Plan and Environmental Justice statement adopted in 2020. • Assist and advise VCEA staff and consultants on:
• community outreach, marketing and programs for its member communities,
• monitoring legislative and regulatory activities related to Community Choice Energy issues, and
• the development of public information materials related to customer energy investments and choices.
To achieve the goals and mission of VCEA, the CAC will:
• monitor organizational performance toward fulfillment of the VCEA Board of Director’s Vision Statement and may recommend policy changes to further the VCEA vision, • advise and assist the Board, staff and consultants through its task groups or other means consistent with California’s open meeting laws,
• evaluate, advise and assist VCEA by making recommendations on select items at the request of the Board or the Interim General Manager or in consultation with the Interim General Manager, and
• periodically review this charge and make recommendations for changes to the Board of Directors as new issues, opportunities and challenges impacting the VCEA arise. 76 Adopted Sept. 2017 // Updated Nov. 2018 // Updated January 2021
VCE COMMUNITY ADVISORY COMMITTEE
LEG/REG TASK GROUP
2021 ACTIVITIES REPORT
Task Group Members: Yvonne Hunter, Lorenzo Kristov, Jennifer Rindahl, Christine Shewmaker VCE Staff: Mitch Sears
2021 Charge: Work with VCE’s lobbyist and VCE staff to:
• Provide feedback, technical information and strategic advice to VCE staff on key legislative and regulatory issues facing VCE and the CCA community in general, including legislation and regulatory issues related to VCE’s Strategic Plan and Environmental Justice Statement. • Provide periodic reports to the CAC about legislation and regulatory issues. • Solicit recommendations from the CAC on VCE positions on key legislation and proceedings. • Contribute to VCE’s engagement with legislators and other stakeholders. • Advise VCE staff on CalCCA’s regulatory work where and when appropriate.
Highlights of Accomplishments in 2021
During 2021, the Leg/Reg Task Group met bi-weekly with staff and VCE’s lobbyist and worked closely with them to:
1. Review pending legislation, provide feedback, technical and policy information, strategic guidance and recommend VCE positions and legislative strategies for pending legislation and regulatory issues.
2. Update the Legislative Platform to incorporate, among other topics, appropriate items from the newly adopted VCE strategic plan and EJ statement for review by the CAC and consideration by the VCE board (in process).
3. Provide input on VCE’s engagement with legislators and other stakeholders, especially related to SB 612.
4. Consider key issues for potential legislative engagement in the 2021-2022 legislative session (ongoing).
5. Provide periodic information related to selected regulatory proceedings before the Public Utilities Commission.
Challenges
1. Staying informed about CPUC regulatory activities that affect VCE and other CCAs in the same manner in which the Task Group is informed about legislative issues.
2. Navigating the legislative process during both the COVID pandemic and a budget excess.
Opportunities
1. Continue to engage local stakeholders and other potential partners in advancing VCE’s positions on legislative and regulatory issues. Ongoing also opportunity for engaging general public in legislation that benefits CCA, such as SB 612.
2. Incorporate relevant topics from the newly adopted Strategic Plan into the Task Group’s work. 77 VCE COMMUNITY ADVISORY COMMITTEE
OUTREACH TASK GROUP (OTG)
2021 ACTIVITIES REPORT
Task Group Members: Mark Aulman (chair), Marsha Baird, Yvonne Hunter VCE Staff: Rebecca Boyles
2021 Outreach Task Group Charge
• Collaborate with VCEA staff and consultants on community outreach to, and liaison with, member communities
• Assist in the development of public information strategies, planning, and materials related to VCEA policies and programs. As requested by staff, review draft materials and provide comments Highlights of Accomplishments:
• Reviewed and provided editorial feedback on pre-release marketing materials including NEM communications, VCE Newsletter, and specific collateral projects. • Reviewed substantial modifications to the VCE website including new topic areas, such as environmental justice and a Spanish language version, as well as program offerings and customer information -- Ohm Connect, Putah Creek solar, electric vehicle information, financial assistance, navigating time-of-use, and ‘understanding your bill’. • Assisted with the development of advertising, including testimonials . • Consulted on modifications to Call Center operations to help minimize opt-outs. • Monitored social media for VCE-related postings and replied as needed. • Continued monthly task group meetings to review near-term project calendar and provided feedback on specific projects.
• Conducted ongoing review of messaging strategies for consistency and appropriateness. • Maintained contact with member communities to coordinate future opportunities for coordinated outreach.
Lessons Learned – Challenges and Opportunities
Challenges:
• Continuing work is needed to develop targeted messages and communications approaches to specific audience segments.
• Ongoing effort is is needed to emphasize environmental justice. • The regulatory environment has driven Power Content Label adjustments and potential rate changes that are complex and may be difficult to explain to customers.
Opportunities:
• The VCEA Strategic Plan provides the opportunity to promote VCE as a trusted community resource. • VCE’s value proposition will be continually enhanced through the communication of technological advances and program innovations that create benefits for customers, such as new local renewable energy sources and local grid improvements, new battery storage resources, continuing electrification of the built environment, and consumer-focused energy conservation advice. 78 VCE COMMUNITY ADVISORY COMMITTEE
PROGRAMS TASK GROUP (PTG)
2021 ACTIVITIES REPORT
Task Group Members: Marsha Baird (co-chair), David Springer (co-chair) VCE Staff: Rebecca Boyles
2021 Charge: The CAC Programs Task Group will assist Staff with planning and implementation of Customer Programs that meet the VCE Mission and Strategic Plan. Specifically, the Task Group will:
(1) collaborate with Staff on 3-year programs plan and annual updates; (2) advise on programs budget strategy for CY2021;
(3) review programs and financial mechanisms (such as rebates, incentives, PACE) and make recommendations of options, with special attention to VCE customer segments, such as agriculture and disadvantaged and underserved; and,
(4) provide updates at monthly CAC meetings on issues being reviewed by the task group.
Highlights of Accomplishments:
• Reviewed and provided feedback on VCE’s 3-year Programs Plan. The Plan includes the goals from VCE’s Strategic Plan and a system for prioritizing programs. The Plan was approved by the Board in June 2021 after incorporating input from the CAC. • Assisted Staff with the development of new VCE programs:
o Help Avoid Blackouts -- Implemented by Staff with partner OhmConnect. Task group provided input at monthly meetings.
o Electric Vehicle Rebates – Researched EV rebate programs offered by CCAs and other organizations. Program Design Implementation Form will be reviewed by CAC and then taken to Board for approval with a goal of program implementation in early 2022. • Brainstormed and discussed with Staff future programs such as Ag Demand Response partnership with Polaris and Dual Fuel Heat Pump Program. • Continued promotion of news article titled “Flattening the Curve” which serves as an educational piece with ways customers can shift their electricity usage away from peak times. • Assisted Staff with update of Energy Efficiency Program with 2021 rebate information.
Lessons Learned – Challenges and Opportunities
Challenges:
• Locating sources of funding for programs.
• Limited staff time to develop programs due to lean staffing and other marketing activities and priorities.
Opportunities
• Continue to learn from experiences of other CCAs on programs that have worked well for their customers.
• Research grants and other funding options.
79 October 20, 2021, page 1
VCE COMMUNITY ADVISORY COMMITTEE
RATE OPTIONS TASK GROUP
2021 ACTIVITIES REPORT
Members
Lorenzo Kristov (Chair), Gerry Braun
VCE Staff: Edward Burnham
Charge
Assist staff, consultants, and the Valley Clean Energy Board Subcommittee as requested, when existing or new rate options are being considered and evaluated.
Help staff evaluate the impact of current and potential rate options on VCE customer responses and other energy choices, including Environmental Justice considerations.
Specific Tasks
1. Conduct CAC Rate Options Task Group meetings and expand participation to other interested CAC members or external experts, as needed.
2. Review rate-related financial analysis conducted by staff and consultants and provide staff with input and feedback.
3. Review proposed staff recommendations regarding rate options, including Net Energy Metering, and provide input and feedback.
4. Inform CAC on rate options and analyses reviewed by the Task Group. 2021 Activities
The Task Group met at least nine times between March and October 2021 with VCE staff Mitch and Edward and VCE consultant Don Dame to understand and discuss VCE’s current and evolving financial situation and consider new rate options to address financial concerns.
The March-July meetings were mainly focused on developing scope of work (SOW) details for consultant to evaluate benefits and impacts of adding a third rate option to VCE’s offerings, at a lower rate and lower renewable energy content than VCE’s existing offerings. The third option would be a “compliance” option whose renewable energy content would minimally comply with state requirements. Following discussion with the task group, VCE issued a task order to SMUD to perform the analysis and provide VCE with the model staff could use to perform additional analyses.
Starting in September the meetings turned to recent and near-term impacts of volatility in VCE’s costs for energy and resource adequacy procurement and PCIA, and how those impacts might affect design and timing of introducing the new rate option. This effort remains work-in-progress as of the filing of this report. 80 VCE COMMUNITY ADVISORY COMMITTEE
CARBON NEUTRAL TASK GROUP
2021 ACTIVITIES REPORT
Members: Cynthia Rodriguez (Chair), Gerry Braun, Christine Shewmaker, Lorenzo Kristov VCE Staff: Gordon Samuel
Charge: Assist staff and consultants in evaluating feasibility and creating a road map for both carbon-neutral and carbon-free-hour-by-hour power by 2030. Strategic plan reference goal 2 and 2.5.
Tasks
o Support VCE staff’s timetable for performing and completing this effort o Assist in input for and evaluation of model development o Evaluate different types of power that can be included in model o Consider impacts of plan on future IRP
o EJ component – consider importance of some local resources because of impact on local jobs.
Strategic Plan Goals
Goal 2: Manage power supply resources to consistently exceed California’s Renewable Portfolio Standard (RPS) while working toward a resource portfolio that is 100% carbon neutral by 2030.
2.5: Objective: Study and present options for achieving a 100% carbon neutral resources portfolio as well as 100% carbon free resource portfolio (carbon free hour by hour) by 2030.
Highlights of Accomplishments:
Assisted staff with:
• Preparing and keeping to a timeline
• Formulating standard definitions of renewable electricity, carbon free electricity, carbon neutral and hour by hour.
• Preparing an RFO to engage a consultant to prepare 4 portfolios • Presenting an overview of first six months of work to CAC Brainstormed with staff on:
• Sensitivities to load forecasts such as EV penetration, all electric home impact on load, climate, drought, etc.
• Next steps once we obtain the 4 example portfolios from our consultant ( Energeia) - prepare summary of positives and negatives of each portfolio-present to CAC recommendation of which portfolio to use in order of best outcomes -outline time table of advancement of chosen portfolio
• What the ongoing role of a task group will/should be as relates to decarbonization, etc. 81 Lessons Learned – Challenges and Opportunities
Challenges:
• Creating an RFO to appeal to the largest number of bidding contractors in a suitable price range
• Prioritizing the contractor obligations to craft a plan to reach carbon requirements under law and policy
• Cost competitiveness/affordability of the hour by hour scenarios will most likely be a challenge
Opportunities:
• Continue to learn from experiences of other CCAs and LSE on their approaches to carbon neutral and carbon free hour by hour.
• Contact and review other groups’ systems and successes arriving at carbon limitations. • Possible contractors brought information and depth of understanding of available systems
• Various long term storage technologies and approaches may present opportunities. 82 1
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 13
To: Board of Directors
From: Mitch Sears, Interim General Manager
Rebecca Boyles, Director of Customer Care and Marketing Subject: Amendment 26 (Implementation of Rate Configuration) to Task Order 2 of the SMUD Professional Services Agreement
Date: January 27, 2022
______________________________________________________________________________
RECOMMENDATION
Adopt resolution ratifying approval of Amendment 26 to Task Order 2 of the Sacramento Municipal Utilities District (SMUD) Professional Service Agreement authorizing the implementation of rate configuration.
BACKGROUND
On October 12, 2017 the VCE Board approved a Professional Services Agreement with the Sacramento Municipal Utility District (SMUD) and Task Orders 1 and 2 to provide program launch and operational services. Soon thereafter, a series of additional Task Orders were implemented to the Agreement, including Task Order 3 to provide Wholesale Energy Services; Task Order 4 to provide Operational Staff Services to VCE; and Task Orders 5 (Long Term Renewable Procurement Services) and 6 (Expansion of VCE Service to Winters, CA).
As discussed at Board meetings dating back to 2018 and more recently during Board deliberations on fiscal year budget adoption this summer, rate determining factors and rising power market prices have stretched VCE’s financials and forced the Board to adopt cost mitigation measures beginning as early as 2018 (e.g. rate increase, delayed procurement of renewables, reduced program activity). After a thorough discussion on current projections, on October 21, 2021 a 5% average generation rate adjustment effective November 1, 2021 for customer classes excluding California Alternative Rates for Energy (CARE) and Family Electric Rates Assistance (FERA) customers was approved. SMUD prepares and produces VCE’s generation rates. There was a need to amend Task Order 2 of our agreement with SMUD to reflect SMUD’s reconfiguration and implementation of VCE’s generation rates.
Financial Impact: The cost for reconfiguring and implementing VCE’s generation rates is $26,372.
83 2
CONCLUSION
The recommended Board action ratifies Interim General Manager Mitch Sears recent signature of Amendment 26 to Task Order 2 (Data Management and Customer Call Center Services) for SMUD to implement VCE’s rate configuration.
Attachments:
1. Signed Amendment 26 to Task Order 2 (Data Management and Customer Call Center Services)
2. Resolution ratifying approval of Amendment 26 (Implementation of Rate Configuration) to Task Order 2 to the VCE-SMUD Professional Services Agreement 84 AMENDMENT 26 Rate Configuration TO EXHIBIT A, TASK ORDER 2 11/8/2021 AMENDMENT 26 TO EXHIBIT A: Scope of Services
A.2 Task Order 2 – Data Management and Customer Call Center Services SMUD and VCE agree to the following services, terms, and conditions described in this Amendment 26 to Exhibit A, Task Order No. 2 (Amendment 26), the provisions of which are subject to the terms and conditions of the Master Professional Services Agreement (Agreement) between the Parties. If any specific provisions of this Amendment 26 conflict with any general provisions in the Agreement or Task Order 2, the provisions of this Amendment 26, shall take precedence. Capitalized terms used in this Amendment which are not defined in this Amendment will have the respective meanings ascribed to them in the Agreement or a previous Amendment thereof.
Section 1, SCOPE OF WORK, is amended to include Section 1.5.10. with the sections below:
“1.5.10. Implement VCE Rate Configuration.
Features
• 5% additional premium (opposite of discount) to generation rates • 5% additional premium (opposite of discount) to demand rates • Premium amounts will be shown in-line (no additional presentment) • 5% additional premium will only affect NON CARE and NON FERA • Effective 11/1/2021
Deliverables and Due Dates
The rate configuration scope of work is scheduled for deployment for bill cycles that begin on or after November 1, 2021.
Milestone Responsible Party Due Date
1 Task Order Amendment executed VCE November 12, 2021
2 Configuration complete SMUD November 21, 2021
3 Go-live date SMUD December 1, 2021
“
Section 4, COMPENSATION FOR SERVICES is amended to add the following:
“For work associated with Section 1.5.10, effective on the implementation date (December 1, 2021), there will be a one-time fee of $26,372.”
Section 5, PAYMENT TERMS, is amended to add the following:
“For work associated with Section 1.5.10, SMUD will provide an invoice with the fixed fee for the implementation of this rate configuration upon implementation, and payment will be due net thirty (30) days from date of the invoice.”
[Signature Page follows]
85 AMENDMENT 26 Rate Configuration TO EXHIBIT A, TASK ORDER 2 11/8/2021
SIGNATURES
The Parties have executed this Amendment 26, and it is effective as of the date of last signature below.
Valley Clean Energy
By:
Name:
Title:
Date:
Approved as
to Form:
Sacramento Municipal Utility District
By:
Name:
Title:
Date:
Approved as
to Form:
Brandy Bolden
Chief Customer Officer
11/9/2021
Mitch Sears
Interim General Manager
December 8, 2021
N/A
86 1
VALLEY CLEAN ENERGY ALLIANCE
RESOLUTION NO. 2022 - ___
A RESOLUTION OF THE VALLEY CLEAN ENERGY ALLIANCE RATIFYING INTERIM GENERAL MANAGER’S APPROVAL AND EXECUTION OF AMENDMENT 26 (IMPLEMENTATION OF RATE CONFIGURATION) TO TASK ORDER 2 TO THE
SACRAMENTO MUNICIPAL UTILITIES DISTRICT PROFESSIONAL SERVICES AGREEMENT WHEREAS, The Valley Clean Energy Alliance (“VCE”) was formed as a community choice aggregation agency (“CCA”) on November 16, 2016, Under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Yolo, and the Cities of Davis and Woodland, to reduce greenhouse gas emissions, provide electricity, carry out programs to reduce energy consumption, develop local jobs in renewable energy, and promote energy security and rate stability in all of the member jurisdictions. The City of Winters, located in Yolo County, was added as a member of VCE and a party to the JPA in December of 2019; and, WHEREAS, on August 31, 2017, the VCE Board considered a proposal by the Sacramento Municipal Utilities District (“SMUD”) to provide program launch and operational services and subsequently directed VCE staff to negotiate a services agreement between VCEA and SMUD for consideration and action by the VCEA Board; and,
WHEREAS, on September 21, 2017, the SMUD Board of Directors authorized its CEO to enter into a contract with VCE to provide Community Choice Aggregate (CCA) support services; and, WHEREAS, On October 12, 2017 the VCE Board approved the Master Professional Services Agreement and Task Order 1 (technical and analytical services) and Task Order 2 (Data Management and Call Center Services) to provide program launch and operational services consistent with the SMUD proposal and VCE Board direction; and, WHEREAS, in October 2018, Amendment 4 to Task Order 2 updating VCE’s base program from “LightGreen” to “Standard Green” was approved; and,
WHEREAS, in April 2019, Amendment 10 to Task Order 2 adding detail to SMUD’s invoicing methodologies in the Compensation for Services section updating was approved; and, WHEREAS, in June 2019, Amendments 11 and 12 to Task Order 2 implementing the Annual Dividend program and second Net Energy Metering (NEM) True-Up Policy was approved; and, WHEREAS, in August 2019, Amendment 13 to Task Order 2 updating data management and customer call center service rate was approved; and,
WHEREAS, in May 2020, Amendment 16 to Task Order 2 authorizing the configuration of VCE’s billing system to enable vintage year specific rates was approved; and, 87 2
WHEREAS, in July 2020, the Board received a signed copy by VCE’s Interim General Manager of Amendment 18 to Task Orders 2, 3 and 4 increasing the billable hourly rates by 2.0% effective July 1, 2020; and,
WHEREAS, in October 2020, the Board approved Amendment 20 to Task Order authorizing SMUD to implement the 2019 California Energy Commission Power Content Label email scope of work; and,
WHEREAS, on May 13, 2021 the Board ratified signed Amendment 23 to Task Order 2 which implemented an outbound call campaign to customers in billing arrears; and, WHEREAS, on June 10, 2021 the Board ratified Amendment 22 to Task Order 2 which implemented a way for Net Energy Metering customers to donate their credit online; and, WHEREAS, on July 8, 2021 the Board approved Amendment 24 to Task Order 2 which reduced the VCE’s call center hours; and,
WHEREAS, on October 21, 2021 the Board approved a 5% average generation rate adjustment effective November 1, 2021 for customer classes excluding California Alternative Rates for Energy (CARE) and Family Electric Rates Assistance (FERA) customers; and, WHEREAS, as a result, VCE’s rates needed to be reconfigured and implemented by SMUD; and, WHEREAS, to implement VCE’s rate configuration, Amendment 26 was signed by Interim General Manager Mitch Sears.
NOW, THEREFORE, the Board of Directors of the Valley Clean Energy Alliance resolves as follows:
1. Ratify Interim General Manager’s approval and execution of Amendment 26 to Task Order 2 (Data Management & Customer Call Center Services) implementing VCE’s rate configuration.
88 3
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:
_____________________________________
______________, VCE Chair
__________________________________
Alisa M. Lembke, VCE Board Secretary
EXHIBIT A: Amendment 26 to Master Professional Services Agreement Task Order 2 89 1
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 14
To: Board of Directors
From: Mitch Sears, Interim General Manager
Subject: Receipt of signed Amendment 3 to Jim Parks Agreement for Consultant Services extending the six (6) months
Date: January 27, 2022
______________________________________________________________________________
RECOMMENDATION
Receive copy of signed Amendment 3 to Jim Parks Agreement for Consultant Services extending the contract six (6) months for a new expiration date of June 30, 2022.
BACKGROUND
On June 29, 2020, VCE entered into an agreement for consultant services with James Parks to provide transitional director duties, including SACOG grant and other program activities, with the new Director of Customer Care and Marketing Rebecca Boyles. The agreement was for a not to exceed amount of $10,000 and was set to expire on December 31, 2020.
In December 2020, Amendment 1 to the agreement was signed expanding the tasks to include key account services and extending the contract through December 31, 2021. In July 2021, Amendment 2 to the agreement was signed to increase the not to exceed amount by $8,000 for a new not to exceed amount of $18,000.
Mr. Parks continues to provide assistance to Staff with key account services for designated commercial, industrial, and agricultural customer outreach and SACOG grant and other program activities.
Through December 2021, a total of $11,300 has been expended of the not to exceed amount of $18,000 leaving $6,700 remaining. Amendment 3 extends the expiration date of December 31, 2021 by six (6) months for a new expiration date of June 30, 2022.
Attachments
1. Amendment 3 to the Jim Parks Agreement for Consultant Services
2. Exhibit C – Schedule of Services
90 VCE —#3 Amendment - Jim Parks
THIRD AMENDMENT
TO THE AGREEMENT FOR CONSULTANT SERVICES
BETWEEN
VALLEY CLEAN ENERGY ALLIANCE
AND
JIM PARKS
1. Parties and Date.
This Third Amendment to the Consultant Services Agreement (“#3 Amendment”), is made and entered into as of this 1
st day of January 2022, by and between Valley Clean Energy Alliance, a Joint Powers Agency, existing under the laws of the State of California with its principal place of business at 604 2nd Street, Davis, California 95616 (“VCE”) and Consultant, Jim Parks, with its principal place of business at 4478 G Street, Sacramento, California 95819 (“Jim Parks”). VCE and Jim Parks are sometimes individually referred to as “Party” and collectively as “Parties.” Recitals.
1. On June 29, 2020 VCE and Jim Parks entered into an “Agreement for Consultant Services”, for the purpose of retaining Jim Parks to provide the services described in Exhibit A of the Agreement. The Agreement was for a term of six (6) months and a total amount not to exceed $10,000.
2. On December 28, 2021 Interim General Manager signed Amendment One (1), extending the term for one year, for a new expiration date of December 31, 2021, and expanding tasks to include key account services. On June 29, 2021 Interim General Manager signed Amendment Two (2), increasing the not to exceed amount by $8,000 for a new not to exceed amount of $18,000.
3. VCE and Jim Parks now desire to further amend the Agreement to extend the term by six (6) months, through June 30, 2022, with no changes to the revised scope of services as outlined in Amendment One (1): Exhibit A: Scope of Services or to the not to exceed amount as outlined in Amendment Two (2): Exhibit D – Payment.
Now therefore, for good and valuable consideration, the amount and sufficiency of which is hereby acknowledged, the Parties agree as follows:
1. Section 1.4 of the Agreement is hereby amended in its entirety to read as follows:
1.4 Term. The term of this Agreement, which began on June 29, 2020, shall end on June 30, 2022 unless amended as provided in this Agreement, or when terminated as provided in Article 5.
91 VCE —#3 Amendment - Jim Parks
2. Exhibit C – Schedule of Services is hereby replaced in its entirety by Exhibit C – Schedule of Services attached hereto.
3. Except as amended by this #3 Amendment, all other provisions of the Agreement will remain in full force and effect.
4. If any portion of this #3 Amendment is declared invalid, illegal, or otherwise unenforceable by a court of competent jurisdiction, the remaining provisions shall continue in full force and effect.
[Signatures on Next Page]
92 93
VCE —#3 Amendment - Jim Parks
EXHIBIT C
SCHEDULE OF SERVICES
The scope of this contract commences on June 29, 2020 through June 30, 2022. The Agreement and the schedule may be extended by mutual agreement in writing by both parties. 94 1
VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 15
TO: Board of Directors
FROM: Mitch Sears, Interim General Manager
Gordon Samuel, Assistant General Manager & Director of Power Services SUBJECT: Near-term Procurement Directives and Delegations for 2022 Power Procurement Activities
DATE: January 27, 2022
RECOMMENDATION
Staff recommends the Board adopt a resolution approving the Near-term Procurement Directives and Delegations to SMUD for procuring portions of VCE’s power portfolio for calendar year 2022 through 2023
BACKGROUND AND ANALYSIS
On January 14, 2021, the Board approved VCE’s Procurement Directives and Delegations of Authority which established the near-term procurement plan for 2021.
The intent of this staff report is to update the approval of delegations necessary for VCE and SMUD staff to continue procurement activities on behalf of VCE’s power supply portfolio. This update provides a high-level overview of the products necessary to meet compliance obligations and maintain a balanced power portfolio while meeting power supply portfolio targets set by the VCE Board.
Principles Guiding Procurement Directives and Delegations of Authority The procurement directives and delegations of authority will be guided by the following principles and allow VCE and SMUD staff to:
• Meet VCE’s compliance, regulatory, and business practice requirements under the California Public Utilities Commission (CPUC), California Independent System Operator (CAISO), and other relevant regulatory agencies;
• Satisfy the power supply portfolio targets set by the VCE Board; 95 2
• Minimize the potential risk exposure of the portfolio, according to practices defined in VCE’s Wholesale Energy Risk Manual;
• Provide the appropriate amount of administrative flexibility for staff to carry out procurement actions.
Product Categories
Resource Adequacy
As a CPUC jurisdictional Load Serving Entity, VCE is required to meet the compliance obligations of the Resource Adequacy (RA) program. The RA program ensures sufficient resources are available to support the anticipated demand in California. The CPUC along with CAISO administer the program and define the requirements necessary to meet reliability standards.
VCE is allocated its share of obligations based on its load ratio of PG&E’s service territory. The delegation for this product allows VCE to meet its RA obligations in a timely manner, support reliability of the grid, and avoid financial penalties. It also allows for the sale of RA when VCE has a long position.
Renewable Energy
CPUC sets minimum renewable energy requirements under its Renewable Portfolio Standards (RPS) program. Along with meeting any annual renewable targets set by the Board, VCE is obligated to adhere to required renewable percentages over the CPUC-defined compliance periods. Some of this renewable energy obligation will be met with Power Purchase Agreements (PPAs) for resources that are still under construction (e.g. Resurgence 90MW solar, 75 MW battery project), as well as online resources (e.g. Indian Valley hydro and Aquamarine Solar). The rest of the requirements can be met with short-term purchases of RPS-qualified energy from existing resources in the market. The delegation approvals are designed to allow staff to procure around the uncertain new resource online dates to meet renewable energy portfolio targets. Procurement of these short-term purchases of RPS-qualified energy are expected to diminish in future years as VCE’s long-term PPA’s displace the need.
Carbon-Free Energy
Carbon-Free energy is a voluntary product that reduces the carbon content of VCE’s power supply. This comes mainly from large-hydro generation resources that do not qualify as Renewable under the RPS program. The delegation for this product allows staff to procure enough carbon-free energy to meet the target set by the Board, taking into consideration the uncertainty of annual PG&E carbon-free allocations.
Price Hedging Energy
Purchasing energy on a forward basis allows VCE to fix some of its power supply costs ahead of more volatile and uncertain spot market prices. A procurement milestone is set to ensure the targeted amount of energy hedging is completed in a timely manner. Under VCE’s Enterprise Risk Management Policy, VCE’s Enterprise Risk Oversight Committee (EROC) reviews and 96 3
provides guidance to staff on the timing and execution of the hedging strategy to meet procurement directives and minimize budget exposure.
CAISO Market Energy and Congestion Revenue Rights
CAISO Market Energy is scheduled for VCE daily into the Day Ahead Market, as required by the CAISO, based on daily forecasts of VCE hourly wholesale loads. SMUD staff currently purchase and sell energy on a daily basis to maintain balance between forecasted demand and supply.
Congestion Revenue Rights (CRRs) are financial instruments allocated by the CAISO to Load Serving Entities for the purpose of hedging the cost of transmission congestion between generation sources and load. Although CRR portfolio management can be quite complex, with auction mechanisms involving multiple hubs on the system, this delegation allows VCE’s portfolio manager to only nominate CRRs that are directly related to VCE’s supply portfolio. VCE is restricted to participation in the allocation process that does not involve price bidding or speculation.
Portfolio Composition Approach
VCE’s portfolio management strategy is evolving as its portfolio matures. VCE has signed multiple long-term renewable PPAs, contributing to the renewable composition of the California grid. Renewable PPAs bring a level of uncertainty regarding construction completion and online dates, as well as annual output. Whereas VCE’s early procurement actions focused primarily on firm volume deliveries from existing generation assets, VCE will be the off-taker of variable output resources under the long-term agreements. Once all PPA assets are online, VCE anticipates exceeding renewable targets set by the California RPS program. But the uncertainty during the transition to new resources complicates the achievement of internal portfolio targets. Irrespective, VCE is required to achieve the renewable target for the California RPS program compliance period and is on course to meet these minimum requirements. The upcoming RPS compliance period is 2021-2024.
PG&E’s carbon-free allocations will continue into calendar year 2022, and these carbon-free allocations are expected to contribute to VCE’s carbon-free portfolio content in the form of large hydro resources paid for by VCE customers in the Power Charge Indifference Adjustment (PCIA). However, the exact volumes of these resources will not be certain until after the calendar year is complete.
Procurement Directives
Taking into account the considerations outlined in the sections above, Table 1 shows the specific Procurement Directives and Delegations recommended for 2022. 97 4
Table 1. 2022 Procurement Directives
REQUESTED ACTION
Adopt a resolution approving:
1. Near-term Procurement Directives and Delegations to SMUD for procuring portions of VCE’s power portfolio for calendar year 2022 through 2023 Product For Year
Procurement
Milestone Date
Cumulative
Percentage Procured
by Milestone Date Delegated To Notes
CAISO Market Energy 2019 1/1/2019
CAISO Market Energy 2022 Daily 100% SMUD Procure Day Ahead and Imbalance Energy for 100% of VCE wholesale load.
Congestion Revenue Rights 2019 1/1/2019
Congestion Revenue Rights 2022 Monthly During Year Up to 100% SMUD Request monthly allocations, if economic, as approved by VCE AGM.
Congestion Revenue Rights 2023 October 31, 2022 Up to 100% SMUD Request annual and/or quarterly year ahead allocations, if economic, as approved by VCE AGM.
Price Hedging Energy 2019 1/1/2019
Price Hedging Energy 2022 Daily/Balance of Month TBD SMUD Daily hedging strategy to be revisited, contingent upon analysis of Daily and/or Balance of Month hedging efficacy, changes upon approval of EROC.
Price Hedging Energy 2023 December 31, 2022 100% SMUD Quantity and timing contingent upon review by the VCE EROC of forward market power prices/trends.
Renewable Energy 2019 1/1/2019
Renewable Energy 2022 September 30, 2022 100% * SMUD True up procurement as needed based upon actual loads/updated load forecast and updated PPA generation
forecast.
Renewable Energy 2023 December 31, 2022 100%* SMUD Minimal short term renewable procurements anticipated, based upon expected long term renewable PPA deliveries.
Once greater certainty regarding renewable online dates, procure short term PCC1 power as needed and approved by GM.
Large Hydro Energy 2019 1/1/2019
Large Hydro Energy 2022 September 30, 2022 100% * SMUD 100% of the forecast need for Large Hydro. Only needed if carbon-free portfolio targets exceed expected PG&E allocation volume.
Large Hydro Energy 2023 December 31, 2022 up to 100% * SMUD Up to 100% of the forecast need for Large Hydro, based upon pricing and availability, as approved by VCE GM. Only needed if VCE sets 2023 carbon-free portfolio target that exceeds expected PG&E allocation volume.
Resource Adequacy Capacity 2019 1/1/2019
Resource Adequacy Capacity 2022 October 31, 2021 100% SMUD Procure for any remaining monthly RA deficiencies and sell monthly RA surpluses, as approved by GM.
Resource Adequacy Capacity 2023 October 31, 2021 100% SMUD All RA products forecast, including some provision for RA from possible CEC Load Forecast adjustments or Local RA obligation increases, required to achieve compliance by October 31, 2022 for 2023. Procurement amount may exceed 100% in total for year to insure that all months achieve at least 100%
compliance.
Valley Clean Energy Power Procurement Directives and Delegations for Calendar 2022 Note: Procurement milestone dates represent targets but do not represent expiration of SMUD delegation. Where necessary to achieve compliance, procurement is approved under this delegation until the next calendar year delegation is approved by the Board of Directors. 98 Item 15
VALLEY CLEAN ENERGY ALLIANCE
RESOLUTION NO. 2022- _______
A RESOLUTION OF THE BOARD OF DIRECTORS OF THE VALLEY CLEAN ENERGY
ALLIANCE APPROVING THE NEAR-TERM PROCUREMENT DIRECTIVES AND DELEGATIONS FOR 2022 POWER PROCUREMENT ACTIVITIES FOR PORTIONS OF VALLEY CLEAN ENERGY’S POWER PORTFOLIO FOR CALENDAR YEAR 2022 THROUGH 2023 WHEREAS, in order to achieve its strategic goals, VCE has established procurement policies and goals and on January 18, 2018 the Board approved VCE’s Procurement Guide which provided the roadmap for implementation and established the procurement plan for 2018 and 2019 power portfolio, along with delegations to Sacramento Municipal Utilities District (“SMUD”) to execute on this plan; and,
WHEREAS, on January 23, 2019, the Board adopted via Resolution 2019-002 a revised Procurement Guide and delegated authority to VCEA Staff and SMUD to procure energy for calendar years 2020, 2021 and 2022, including the procurement of price hedging energy for VCE’s expected 2020 needs with no delegation to procure hedging energy beyond 2020, consistent with the procurement policy and guide; and,
WHEREAS, on December 12, 2019, the Board adopted Resolution 2019-018 approving the 2020 Procurement Plan, directives and delegations for procuring VCE’s power portfolio for calendar year 2021, the targeted portfolio mix, and the maintenance of minimum renewable target for 2021; and,
WHEREAS, at the Board’s June 11, 2020 meeting, policy strategies were adopted to plan for incorporation of long-term renewable contracts into VCE’s portfolio, to address fiscal year 2020/2021 Power Charge Indifference Adjustment (PCIA) and Resource Adequacy (RA) cost impacts; and,
WHEREAS, on January 21, 2021, the Board adopted via Resolution 2021-004 and delegated authority to VCEA Staff and SMUD to procure energy for calendar years 2021 through 2023 and the elimination of specific portfolio renewable and carbon-free targets in 2022.
NOW, THEREFORE, the Board of Directors of the Valley Clean Energy Alliance resolves as follows:
1. Approves Directives and Delegations to SMUD for procuring portions of VCE’s power portfolio for calendar year 2022 through 2023 as shown below:
99 Item 15
Product For Year
Procurement
Milestone Date
Cumulative
Percentage Procured
by Milestone Date Delegated To Notes
CAISO Market Energy 2019 1/1/2019
CAISO Market Energy 2022 Daily 100% SMUD Procure Day Ahead and Imbalance Energy for 100% of VCE wholesale load.
Congestion Revenue Rights 2019 1/1/2019
Congestion Revenue Rights 2022 Monthly During Year Up to 100% SMUD Request monthly allocations, if economic, as approved by VCE AGM.
Congestion Revenue Rights 2023 October 31, 2022 Up to 100% SMUD Request annual and/or quarterly year ahead allocations, if economic, as approved by VCE AGM.
Price Hedging Energy 2019 1/1/2019
Price Hedging Energy 2022 Daily/Balance of Month TBD SMUD Daily hedging strategy to be revisited, contingent upon analysis of Daily and/or Balance of Month hedging efficacy, changes upon approval of EROC.
Price Hedging Energy 2023 December 31, 2022 100% SMUD Quantity and timing contingent upon review by the VCE EROC of forward market power prices/trends.
Renewable Energy 2019 1/1/2019
Renewable Energy 2022 September 30, 2022 100% * SMUD True up procurement as needed based upon actual loads/updated load forecast and updated PPA generation
forecast.
Renewable Energy 2023 December 31, 2022 100%* SMUD Minimal short term renewable procurements anticipated, based upon expected long term renewable PPA deliveries.
Once greater certainty regarding renewable online dates, procure short term PCC1 power as needed and approved by GM.
Large Hydro Energy 2019 1/1/2019
Large Hydro Energy 2022 September 30, 2022 100% * SMUD 100% of the forecast need for Large Hydro. Only needed if carbon-free portfolio targets exceed expected PG&E allocation volume.
Large Hydro Energy 2023 December 31, 2022 up to 100% * SMUD Up to 100% of the forecast need for Large Hydro, based upon pricing and availability, as approved by VCE GM. Only needed if VCE sets 2023 carbon-free portfolio target that exceeds expected PG&E allocation volume.
Resource Adequacy Capacity 2019 1/1/2019
Resource Adequacy Capacity 2022 October 31, 2021 100% SMUD Procure for any remaining monthly RA deficiencies and sell monthly RA surpluses, as approved by GM.
Resource Adequacy Capacity 2023 October 31, 2021 100% SMUD All RA products forecast, including some provision for RA from possible CEC Load Forecast adjustments or Local RA obligation increases, required to achieve compliance by October 31, 2022 for 2023. Procurement amount may exceed 100% in total for year to insure that all months achieve at least 100%
compliance.
Valley Clean Energy Power Procurement Directives and Delegations for Calendar 2022 Note: Procurement milestone dates represent targets but do not represent expiration of SMUD delegation. Where necessary to achieve compliance, procurement is approved under this delegation until the next calendar year delegation is approved by the Board of Directors.
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:
_____________________________________
___________, VCE Chair
__________________________________
Alisa M. Lembke, VCE Board Secretary
100
1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 16
To: Board of Directors
From: Mitch Sears, Interim General Manager
Edward Burnham, Director of Finance & Internal Operations Subject: Extension of Credit Agreement with River City Bank Date: January 27, 2022
______________________________________________________________________________
RECOMMENDATION
Approve and Ratify the short-term extensions (September 1, 2021 through February 28, 2022) of the Amended and Restated Credit Agreement (RLOC Agreement) and Term Note from River City Bank (RCB) approved on September 10, 2020.
BACKGROUND AND ANALYSIS
At the December 14, 2017 Board meeting, the Board adopted a resolution to select RCB as the credit and banking services vendor for VCE. VCE authorized the Interim General Manager to execute a letter of intent and enter into negotiations for final contracts with RCB for VCE credit facilities. On March 7, 2018, the Interim General Manager executed a term sheet for up to $11,000,000 in total credit facilities for VCE with RCB.
At the May 10, 2018 Board meeting, the Board approved the Credit Agreement with RCB and authorized the Board Chair to approve and execute the Credit Agreement. The availability of the RLOC was set to expire one year from the execution of the agreement (May 15, 2019) and received a series of extensions.
At the September 10, 2020 Board meeting, the Board adopted Resolution 2020-026 that approved the Amended and Restated Credit Agreement (RLOC Agreement) and attached draft Modification of Term Note from River City Bank (RCB). The Resolution authorized the Interim General Manager to conduct any final negotiations and sign all necessary related documents resulting in the execution of Attachment 1.
On July 8, 2021, VCE authorized the Interim General Manager to conduct any final negotiations and sign all necessary documents on behalf of VCE for the short-term extension of the Amended and Restated Credit Agreement (RLOC Agreement) and Term Note from River City Bank (RCB). On August 25, 2021, the Interim General Manager amendments for the short-term extension through January 1, 2021. Due to the cancellation of the VCE December Board meeting, the Interim General Manager executed the attached December 30, 2021 amendments to extend the RLOC agreement through February 28, 2022, to allow for time to adopt 2022 rates and budgets incorporating the final CPUC ERRA decisions. 101
2 The current RLOC Agreement has a limit of $5,000,000 available for cash advances and an additional $2,000,000 available for Letters of Credit, for a total RLOC of $7,000,000. Since August of 2018, VCE has not drawn on the RLOC and currently has a $0 balance. Except for the extension of the RLOC, no other material changes in the attached amendments.
As part of receiving the RLOC renewal described above, the Term Loan Note was modified to mature on March 1, 2022 (Attachment 2 - Modification of Term Note). Though this was significantly earlier than the original 5-year term. On March 1, 2022, a final payment of approximately $1.087 million is due to pay off the Term Loan. Note: RCB has communicated that there is a high probability the payment due date could be extended.
Staff believes that the RLOC and Term Loan amortization extension is mutually beneficial for RCB and VCE to allow additional clarity regarding these factors (e.g., 2022 PG&E rates will be official on February 10, 2022, with the proposed decision published on January 24, 2022). Rate changes are expected to be effective March 1, 2022.
CONCLUSION
Staff recommends the Board approve and ratify the Amended and Restated Credit Agreement (RLOC Agreement) and Modification of Term Note from River City Bank (RCB).
Attachments
1. Amendment to Credit Agreement – August 2021
2. Second Modification to Term Note – August 2021
3. Second Amendment to Credit Agreement – December 2021
4. Third Modification to Term Note – December 2021
5. Resolution 2021-017 Extending Line of Credit and Term Note – July 2021
6. Resolution to extend Credit Agreement and Modification to Term Note 102
Amendment to Credit Agreement
AMENDMENT TO CREDIT AGREEMENT
This Amendment to Credit Agreement (this Amendment ) is entered into as of August 25, 2021, by and between VALLEY CLEAN ENERGY ALLIANCE, a public agency formed under the provisions of the Joint Exercise of Powers Act of the State of California, Government Code Section 6500 et. seq. ( Borrower ), and RIVER CITY BANK, a California corporation ( Lender ).
1. Background and Purpose.
1.1 Lender and Borrower have entered into a revolving credit facility as set forth in that certain Amended and Restated Credit Agreement Credit Agreement dated as of September 15, 2020. Capitalized terms used and not otherwise defined herein shall have the meanings set forth in the Credit Agreement.
1.2 Borrower has requested an extension of the Revolving Credit Termination Date, which is currently defined as September 1, 2021.
1.3 Lender is willing to grant Borrower request, on the terms and conditions provided herein.
NOW, THEREFORE, in consideration of the mutual benefits of the parties hereto and for other valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties agree as follows:
2. Amendments. The Credit Agreement is hereby amended as follows:
2.1 Definitions. The definition of the Revolving Credit Termination Date is hereby restated in full as follows:
January 1, 2022. 2.2 Financial Covenants. Section 10.7 of the Credit Agreement is hereby amended to add the following periods:
Section 10.7. Change in Net Position. Borrower must achieve a cumulative (year-to-date) change in Net Position, measured as of the end of each fiscal quarter, equal to or better than:
Period Maximum Loss
6/30/2021 9/30/2021 ($4,560,000.00)
6/30/2021 12/31/2021 ($8,300,000.00)
Position means total assets less total liabilities.
103
Amendment to Credit Agreement
3. Conditions Precedent to Effectiveness. The effectiveness of this Amendment is expressly conditioned upon the satisfaction of all of the following conditions:
3.1 Documents. Borrower shall have executed and Lender shall have received all of the following documents:
(a) this Amendment;
(b) the Invoice provided herewith;
(c) the Second Modification of Term Note in the form provided herewith, extending the Maturity Date of the Term Loan from September 1, 2021, to the new Revolving Credit Termination Date; and
(d) Such other documents and information as Lender may reasonably request.
3.2 Authorization Documents. Lender shall have received, in form and substance satisfactory to Lender, copies of any documents evidencing the authorization of Borrower to enter into this Amendment, as Lender may reasonably request.
3.3 Representations and Warranties. All representations and warranties contained herein shall be true and correct in all material respects, and no Default or Event of Default shall have occurred and be continuing.
3.4 Modification Fee. Lender shall have received payment of a Loan Modification Fee in connection with this Amendment in the amount of $7,000.00.
4. Representations and Warranties. By signing this Amendment, Borrower hereby represents and warrants that (a) all representations and warranties in the Credit Agreement are true and correct in all material respects as of the date hereof, (b) Borrower is duly authorized to enter into this Amendment, and (c) no Default or Event of Default has occurred or is continuing.
5. Continuing Validity. Except as expressly modified by this Amendment, the terms of the Credit Agreement remain unchanged and in full force and effect. Consent by Lender to this Amendment
changed, nor obligate Lender to agree any future amendments. Nothing in this Amendment will constitute a waiver or satisfaction of any Obligations of Borrower. [Signatures appear on following page.]
104
Amendment to Credit Agreement
IN WITNESS WHEREOF, the parties hereto have executed and delivered this Amendment as of the first date written above.
VALLEY CLEAN ENERGY ALLIANCE
By: _____________________________
Mitch Sears
Interim General Manager
RIVER CITY BANK
By: _____________________________
Name: _____________________________
Its: _____________________________
105
Second Modification Note No. 5084548841-201 Page 1
SECOND MODIFICATION OF TERM NOTE
This SECOND MODIFICATION OF TERM NOTE (this ) is entered into as of August 25, 2021, by and between VALLEY CLEAN ENERGY ALLIANCE, a public agency formed under the provisions of the Joint Exercise of Powers Act of the State of ), and RIVER CITY BANK
Lender
WHEREAS, Borrower has executed and delivered to Lender that certain Term Note (as amended, the Term ) dated as of October 17, 2019, made by Borrower and payable to the order of Lender in the original principal amount of $1,976,610.13; WHEREAS, the Term Note evidences a loan (the Term Loan ) from Lender to Borrower representing the conversion of outstanding advances under a revolving line of credit in accordance with the terms of that certain Credit Agreement dated as of May 16, 2018, as amended and restated by that certain Amended and Restated Credit Agreement (the Credit ) dated as of September 15, 2020, between Borrower and Lender; WHEREAS, Borrower and Lender have previously amended the Term Note pursuant to a First Modification of Term Note dated as of September 15, 2020; WHEREAS, the parties have agreed to certain modifications of the Credit Agreement, including but not limited to an extension of the Revolving Credit Termination Date (as such term is defined therein) to January 1, 2022, as set forth in that certain Amendment to Credit Agreement (the ) dated as of the date hereof, between Borrower and Lender; WHEREAS, it is a condition to the Amendment that the maturity date of the Term Loan be extended to January 1, 2022, to coincide with the new Revolving Credit Termination Date; NOW THEREFORE, in consideration of the foregoing recitals and other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Borrower and Lender agree to modify the Term Note as follows:
1. Borrower will pay this loan in equal principal payments of $32,943.50 each. next principal payment is due September 1, 2021, and all subsequent principal payments are due on the same day of each month after that. In addition, Borrower will pay regular monthly payments of all accrued unpaid interest due as of each payment date, beginning September 1, 2021, with all subsequent interest payments to be due on the same day of each is due January 1, 2022, and will be for all
outstanding principal and all accrued interest not yet paid.
Except as expressly modified herein, the terms of the Term Note shall remain unchanged and in full force and effect. Nothing in this Modification shall constitute a satisfaction of the Term Loan or a waive right to require strict performance of the Term Loan and all other obligations of Borrower to Lender.
106
Second Modification Note No. 5084548841-201 Page 2
This Modification contains the entire agreement between the parties with respect to the matters addressed herein and supersedes all prior agreements and understandings with respect to thereto. This Modification may not be contradicted by evidence of any prior agreement or contemporaneous oral agreement.
IN WITNESS WHEREOF, the undersigned have executed this Modification as of the date first written above.
VALLEY CLEAN ENERGY ALLIANCE
By: _____________________________
Mitch Sears
Interim General Manager
RIVER CITY BANK
By: _____________________________
Name: __________________________
Its: _____________________________
107
Second Amendment to Credit Agreement
SECOND AMENDMENT TO CREDIT AGREEMENT
This Amendment to Credit Agreement (this Amendment ) is entered into as of December 29, 2021, by and between VALLEY CLEAN ENERGY ALLIANCE, a public agency formed under the provisions of the Joint Exercise of Powers Act of the State of California, Government Code Section 6500 et. seq. ( Borrower ), and RIVER CITY BANK, a California corporation ( Lender ).
1. Background and Purpose.
1.1 Lender and Borrower have entered into a revolving credit facility as set forth in that certain Amended and Restated Credit Agreement (as amended, Credit Agreement dated as of September 15, 2020. Capitalized terms used and not otherwise defined herein shall have the meanings set forth in the Credit Agreement.
1.2 Lender and Borrower have previously extended the Revolving Credit Termination Date pursuant to an Amendment to Credit Agreement dated as of August 25, 2021, between Borrower and Lender.
1.3 Borrower has requested a further extension of the Revolving Credit Termination Date, which is currently defined as January 1, 2022.
1.4 Lender is willing to grant Borrower request, on the terms and conditions provided herein.
NOW, THEREFORE, in consideration of the mutual benefits of the parties hereto and for other valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties agree as follows:
2. Amendments. The Credit Agreement is hereby amended as follows:
2.1 Definitions. The definition of the Revolving Credit Termination Date is hereby restated in full as follows:
March 1, 2022. 3. Conditions Precedent to Effectiveness. The effectiveness of this Amendment is expressly conditioned upon the satisfaction of all of the following conditions:
3.1 Documents. Borrower shall have executed and Lender shall have received all of the following documents:
(a) this Amendment;
(b) the Invoice provided herewith;
108
Second Amendment to Credit Agreement
(c) the Third Modification of Term Note in the form provided herewith, extending the Maturity Date of the Term Loan from January 1, 2022, to the new Revolving Credit Termination Date; and
(d) Such other documents and information as Lender may reasonably request.
3.2 Authorization Documents. Lender shall have received, in form and substance satisfactory to Lender, copies of any documents evidencing the authorization of Borrower to enter into this Amendment, as Lender may reasonably request.
3.3 Representations and Warranties. All representations and warranties contained herein shall be true and correct in all material respects, and no Default or Event of Default shall have occurred and be continuing.
3.4 Fees. Lender shall have received payment of a Loan Modification Fee in connection with this Amendment in the amount of $3,400.00, and Documentation Fee in the amount of $500.00.
4. Representations and Warranties. By signing this Amendment, Borrower hereby represents and warrants that (a) all representations and warranties in the Credit Agreement are true and correct in all material respects as of the date hereof, (b) Borrower is duly authorized to enter into this Amendment, and (c) no Default or Event of Default has occurred or is continuing.
5. Continuing Validity. Except as expressly modified by this Amendment, the terms of the Credit Agreement remain unchanged and in full force and effect. Consent by Lender to this changed, nor obligate Lender to agree any future amendments. Nothing in this Amendment will constitute a waiver or satisfaction of any Obligations of Borrower. [Signatures appear on following page.]
109
Second Amendment to Credit Agreement
IN WITNESS WHEREOF, the parties hereto have executed and delivered this Amendment as of the first date written above.
VALLEY CLEAN ENERGY ALLIANCE
By: _____________________________
Mitch Sears
Interim General Manager
RIVER CITY BANK
By: _____________________________
Name: _____________________________
Its: _____________________________
110
Third Modification Note No. 5084548841-201 Page 1
THIRD MODIFICATION OF TERM NOTE
This THIRD MODIFICATION OF TERM NOTE (this ) is entered into as of December 29, 2021, by and between VALLEY CLEAN ENERGY ALLIANCE, a public agency formed under the provisions of the Joint Exercise of Powers Act of the State of ), and RIVER CITY BANK
Lender
WHEREAS, Borrower has executed and delivered to Lender that certain Term Note (as amended, the Term ) dated as of October 17, 2019, made by Borrower and payable to the order of Lender in the original principal amount of $1,976,610.13; WHEREAS, the Term Note evidences a loan (the Term Loan ) from Lender to Borrower representing the conversion of outstanding advances under a revolving line of credit in accordance with the terms of that certain Credit Agreement dated as of May 16, 2018, as amended and restated by that certain Amended and Restated Credit Agreement (the Credit ) dated as of September 15, 2020, between Borrower and Lender; WHEREAS, Borrower and Lender have previously amended the Term Note pursuant to a First Modification of Term Note dated as of September 15, 2020, and Second Modification of Term Note dated as of August 25, 2021;
WHEREAS, the parties have agreed to certain modifications of the Credit Agreement, including but not limited to an extension of the Revolving Credit Termination Date (as such term is defined therein) to March 1, 2022, as set forth in that certain Second Amendment to Credit Agreement (the ) dated as of the date hereof, between Borrower and Lender; WHEREAS, it is a condition to the Amendment that the maturity date of the Term Loan be extended to March 1, 2022, to coincide with the new Revolving Credit Termination Date; NOW THEREFORE, in consideration of the foregoing recitals and other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Borrower and Lender agree to modify the Term Note as follows:
1. Borrower will pay this loan in equal principal payments of $32,943.50 each. next principal payment is due January 1, 2022, and all subsequent principal payments are due on the same day of each month after that. In addition, Borrower will pay regular monthly payments of all accrued unpaid interest due as of each payment date, beginning January 1, 2022, with all subsequent interest payments to be due on the same day of each month is due March 1, 2022, and will be for all outstanding
principal and all accrued interest not yet paid.
Except as expressly modified herein, the terms of the Term Note shall remain unchanged and in full force and effect. Nothing in this Modification shall constitute a satisfaction of the 111
Third Modification Note No. 5084548841-201 Page 2
right to require strict performance of the Term Loan and all other obligations of Borrower to Lender.
This Modification contains the entire agreement between the parties with respect to the matters addressed herein and supersedes all prior agreements and understandings with respect to thereto. This Modification may not be contradicted by evidence of any prior agreement or contemporaneous oral agreement.
IN WITNESS WHEREOF, the undersigned have executed this Modification as of the date first written above.
VALLEY CLEAN ENERGY ALLIANCE
By: _____________________________
Mitch Sears
Interim General Manager
RIVER CITY BANK
By: _____________________________
Name: __________________________
Its: _____________________________
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113
114
115
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VALLEY CLEAN ENERGY ALLIANCE
RESOLUTION NO. 2022 - ___
RESOLUTION OF THE BOARD OF DIRECTORS OF THE VALLEY CLEAN ENERGY ALLIANCE
AUTHORIZING THE EXTENSION OF ITS REVOLVING LINE OF CREDIT AND TERM NOTE WITH
RIVER CITY BANK
WHEREAS, The Valley Clean Energy Alliance (“VCE”) was formed as a community choice aggregation agency (“CCA”) on November 16, 2016, Under the Joint Exercise of Power Act, California Government Code sections 6500 et seq., among the County of Yolo, and the Cities of Davis and Woodland, to reduce greenhouse gas emissions, provide electricity, carry out programs to reduce energy consumption, develop local jobs in renewable energy, and promote energy security and rate stability in all of the member jurisdictions. The City of Winters, located in Yolo County, was added as a member of VCE and a party to the JPA in December of 2019; and, WHEREAS, VCEA solicited competitive bids for banking and credit services and selected River City Bank (RCB) to lend VCEA up to $11 million as a revolving line of credit to fund power purchases as part of administrating CCE programs, which had a term of 12-months at variable rates with an option to extend another 6 months and was convertible to a five-year term loan with a fixed interest rate; and,
WHEREAS, on May 10, 2018, the VCEA Board via Resolution 2018-012 approved the Credit Agreement between VCEA, as borrower, and the RCB, as lender; and, WHEREAS, the $11 million revolving line of credit expired on May 15, 2019 and on April 11, 2019, the Board via Resolution 2019-005 extended the line of credit for another 6 months, extending the term to November 15, 2019; and,
WHEREAS, on October 10, 2019, the Board approved via Resolution 2019-014 converting the $1,676,610 Revolving Line of Credit (RLOC) balance to an amortized 5-year term loan; approved the renewal terms consistent with the October 3, 2019 term sheet for the existing RLOC for a new expiration date of November 15, 2020; and authorized VCE interim General Manager, in consultation with VCE Legal Counsel, to negotiate the Credit Agreement with RCB based on the renewal terms; and,
WHEREAS, Since November 15, 2019, VCE has received a series of extensions to the RLOC from RCB. The current renewal expired on August 31, 2020; and, WHEREAS, on September 10, 2020, the Board approved via Resolution 2020-026 an one-year extension of the RLOC to September 1, 2021, with a revised limit of $7 million, of which all is available for Letters of Credit and $5 million is available for Cash Advances to fund operational 117
- 2 -
needs. Additionally, RCB and VCE have agreed in principal to a modification to the Term Note, including an earlier Final Payment date of September 1, 2021; and, WHEREAS, RCB and VCE have agreed in principal to a short-term extension of the amended and restated credit agreement inclusive of the revolving line of credit and term note as approved by Resolution 2020-026 on September 10, 2020; and, WHEREAS, on July 8, 2021 the Board approved and authorized via Resolution 2021- 017 the Interim General Manager to conduct any final negotiations and sign all necessary related documents on behalf of VCE for the short term extension of the Amended and Restated Credit Agreement (RLOC Agreement) and Term Note from River City Bank (RCB) approved on September 10, 2020.
NOW, THEREFORE, the Board of the Valley Clean Energy Alliance resolves as follows:
Approves and Ratify the Amended and Restated Credit Agreement (RLOC Agreement) and Term Note from River City Bank (RCB) approved on September 10, 2020 extensions executed by the Interim General Manager.
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:
___________________________________
___________, VCE Chair
___________________________________
Alisa M. Lembke, VCE Board Secretary
Attachments:
1. VCE Resolution 2021-017 Extending RCB Credit Agreement - July 2021
2. Amendment to Credit Agreement – August 2021
3. Second Modification to Term Note – August 2021
4. Second Amendment to Credit Agreement – December 2021
5. Third Modification to Term Note – December 2021
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VALLEY CLEAN ENERGY ALLIANCE
Staff Report - Item 17
____________________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Interim General Manager
Mark Fenstermaker, Pacific Policy Group
SUBJECT: Legislative Platform - 2022
DATE: January 27, 2022
Recommendation
Approve the 2022 Legislative Platform outlining positions VCE would take on various legislative issues.
Background
At the July 8, 2020 Board Meeting, the VCE Board of Directors adopted VCE’s first legislative platform.
It was noted at that time that the legislative platform would be updated for the next legislative session to reflect ongoing and new legislative priorities.
The purpose of the updated draft legislative platform is to formalize and organize VCE’s approach to legislative activity. The legislative platform is meant to be an inward facing document to provide guidance to VCE’s lobbyist Mark Fenstermaker of Pacific Policy Group (PPG) for the 2021 legislative session and beyond. PPG will continue to use the platform to help structure VCE’s efforts and communications with legislators to work toward desired outcomes. The updated platform is based on previous direction from the Board and Community Advisory Committee (CAC) and primarily reflects existing areas of interest identified either formally or informally by the Board and CAC.
Analysis
Throughout the 2021 legislative session, VCE’s lobbyist Mark Fenstermaker of Pacific Policy Group (PPG), the Interim General Manager and the Legislative and Regulatory Task Group (Leg/Reg Task Group) members vetted a number of bills and utilized the Legislative Platform as part of their decision-making process in terms of what position VCE should register, if any. Following the 2021 legislative session, PPG, Staff and the Leg/Reg Task Force evaluated the legislative platform to determine if edits were needed to the platform in advance of the 2022 legislative session. The group reviewed legislation proposed during the 2021 legislative session, with particular focus on 2-year bills that are technically still alive, and discussed relevant and current issues relative to VCE.
Following review and discussion, the group of PPG, Staff, and the Leg/Reg Task Force concluded that the legislative platform used during the 2021 legislative session remains applicable for the 2022. As the 119
2022 legislative session is the 2nd year of the 2-year session, there are 2-year bills still in play that could satisfy provisions of the platform. In addition, many provisions of the platform touch on issues that will be important to VCE for years to come, such as CCA governance and statutory authority or renewable energy generation sources even with successful 2021 bills that address this issue such as AB 843 (Aguiar-Curry). Finally, the ongoing nature of the COVID-19 pandemic warrant a provision to respond to this crisis remain on the platform in 2022 (but hopefully not in 2023).
The key topic/issue areas remain in the draft 2022 platform:
1. Governance and Statutory Authority
2. Restructuring the Electric Utility Sector
3. Resource Adequacy
4. Power Cost Indifference Adjustment (PCIA)
5. Public Safety Power Shut-Offs (PSPS)
6. Community Resilience
7. Renewable Energy Generation Sources
8. Local Economic Development and Environmental Objectives
9. Miscellaneous
Within the attached draft 2022 Legislative Platform minor edits are underlined to assist the Board in identifying changes made to the adopted 2020 platform.
CAC Recommendation
At the CAC’s December 16, 2021 meeting, the draft 2022 Legislative Platform was presented and reviewed, and the CAC made a recommendation that the Board approve the attached 2022 Legislative Platform to help guide VCE legislative activities in the 2021 legislative session.
Conclusion
Staff is recommending that the CAC recommend Board approval of the attached legislative platform to help guide VCE legislative activities.
Attachment
1. Draft 2022 Legislative Platform with underlined edits 120
1 2022 Valley Clean Energy Legislative Platform
Adopted ___________
Introduction
Valley Clean Energy is a joint-powers authority organized pursuant to California law that includes the cities of Davis, Woodland, and the unincorporated areas of County of Yolo (and the city of Winters as of January 2021). The purpose of VCE is to enable the participating jurisdictions to determine the sources, modes of production and costs of the electricity they procure for the customers in the VCE service territory. PG&E, the incumbent Investor Owned Utility, continues to deliver the electricity procured by VCE and performs billing, metering, and other electric distribution utility functions and services. Customers within the participating jurisdictions may opt-out of VCE and remain a PG&E customer. VCE is governed by a Board of Directors consisting of council members and supervisors from its member jurisdictions.
The mission of VCE is to provide cost-competitive clean electricity, product choice, price stability, energy efficiency, and greenhouse gas emission reductions to residents and businesses in its member agencies. In addition, VCE provides a greater level of transparency and accountability in regard to energy sources and prices as VCE’s board consists of local elected officials.
This Legislative Platform serves as a guide for legislative engagement in the 2021 legislative session that is based on positions that VCE has taken on past legislation, as well as the principles set forth in VCE’s Vision Statement, Strategic Plan, and Environmental Justice Statement. It will be updated annually to reflect new issues that VCE will address each legislative session. To review VCE’s vision statement, please see https://valleycleanenergy.org/wp-content/uploads/VCEA-Vision-Statement-11-16-17.pdf.
Note: For tracking purposes, platform language added for the 2021 session is shown in underline.
Issue Areas
1. Governance and Statutory Authority
VCE will:
a. Oppose legislation that limits the local decision-making authority for CCAs, including rate-setting authority and procurement of energy and capacity to serve their customers. b. Oppose legislation that limits VCE’s ability to effectively serve its customers. c. Support efforts of CCAs to engage with their customers and promote transparency in their operations. Similarly, VCE will oppose legislation that restrict or limit these abilities.
d. Support legislation that makes it easier for other cities and counties to form a CCA, become members of VCE or other CCAs, and oppose legislation that restricts that ability. 121
2 2. Restructuring the Electricity Utility Sector
VCE will:
a. Work with other local governments interested in forming municipal electric utilities, as well as the California Municipal Utilities Association, to expand opportunities for municipalization. This includes supporting legislation that expands opportunities for CCAs to become municipal electric utilities.
b. Support legislation and advocate for reforms to the utility regulatory and business model to transform Investor Owned Utilities (IOUs) so that they must deliver greater benefits to ratepayers, increase safety and reliability, and reduce costs. c. Advocate for greater collaboration to occur between CCAs and incumbent IOUs, particularly in local planning efforts related to energy, EV charging, community resource centers, etc.
d. Support efforts that result in IOUs providing meter data in real time to enable CCAs to better forecast and schedule load.
e. Support effective legislation that would transform PG&E to a public power or customer owned entity.
3. Resource Adequacy
VCE will:
a. Support the efforts of CalCCA to create a central procurement entity for residual Resource Adequacy needs.
b. Oppose legislation that would supplant CCAs procurement authority for Resource Adequacy.
c. Advocate for and support efforts to remove barriers to demand response, microgrids and behind the meter resources to provide Resource Adequacy.
4. Power Cost Indifference Adjustment (PCIA)
VCE will:
a. Support CalCCA efforts to increase the transparency of IOU electricity contracts that provide the basis for Power Cost Indifference Adjustment (PCIA) charges that VCE (and its customers) and other CCAs must pay.
b. Support efforts that create a pathway to wind down the PCIA. c. Support legislation that would bring stability to the PCIA and/or provide new mechanisms for CCAs to securitize PCIA charges.
d. Oppose legislation that would increase or expand exit fees, including PCIA, on CCA customers.
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3 5. Public Safety Power Shut-Offs (PSPS)
VCE will:
a. Support legislation that increases the notification and transparency requirements on IOUs as they implement a PSPS.
b. Support legislation that creates standards for PSPS implementation and penalties on IOUs that execute PSPS below those standards.
c. Support legislation that creates rules and procedures to ensure PSPSs are implemented narrowly and only as absolutely necessary.
d. Support legislation that requires IOUs to notify impacted cities, counties and CCAs of impending PSPS.
6. COVID-19 Response
a. Support legislation or budget appropriations to alleviate residential and commercial financial hardship caused by the COVID-19 pandemic that could disrupt electricity service to VCE customers or restrict VCE customers accessing clean energy opportunities. This could include, for example, assistance to avoid electric service disconnection or economic recovery funding for transportation electrification.
7. Community Resilience
VCE will:
a. Advocate for and Support funding for programs implemented by CCAs and their member jurisdictions to increase community resilience to wildfires, PSPS events and other potential service disruptions.
b. Support legislation that reduces barriers to microgrid development by CCAs. c. Oppose legislation that would enable IOUs to be the only developer of microgrids. d. Support legislation that increases development of community level resources and distributed energy resources that reduces the need for new transmission and distribution infrastructure.
8. Renewable Energy Generation Sources
VCE will:
a. Support legislation that expands opportunities for or reduces barriers to the development of renewable energy sources, including, but not limited to, wind, solar, bioenergy, battery storage, small hydro, and geothermal, as long as local development and siting criteria are consistent with city and county land use authority and other local and state regulatory requirements.
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4 b. Oppose legislation that requires CCAs to purchase specific renewable energy products, thus limiting the ability of CCAs to meet local energy needs in a cost-effective manner and in conflict with their local procurement and rate setting authority.
9. Environmental Justice
a. Engage in legislation that directly or indirectly impacts the ability of underserved communities in the VCE service territory to have affordable, reliable and clean energy.
b. Support legislation that strengthens the resilience of vulnerable communities to adapt to the impacts of climate change.
c. Support legislation that enables all communities, including emerging and historically marginalized communities, and individuals, regardless of race, color, national origin, religion, sexual orientation, sex, gender identity, age, disability or socioeconomic status, in California to participate in the transition to a zero carbon electrical grid in a cost-effective manner.
d. Support efforts to enable all communities, including emerging and historically marginalized communities, and individuals, regardless of race, color, national origin, religion, sexual orientation, sex, gender identity, age, disability or socioeconomic status, in California to participate in the decarbonization of the state’s building stock and the transportation sector.
10. Local Economic Development and Environmental Objectives VCE will:
a. Support legislation that enhances opportunities for CCAs to promote local economic development through locally designed programs that meet the unique needs of its member agencies and customers.
b. Support efforts to enhance development of local and regional sources of renewable energy.
c. Support legislation that enables CCAs to collaborate with their member jurisdictions on local energy resources and projects to advance environmental objectives.
11. Miscellaneous
VCE will:
• Oppose legislation that expands direct access or the ability or economic incentives for electric service providers to selectively recruit CCA or IOU customers. • Support legislation that would create renewable content and environmental standards for electric service providers to match the products offered by CCAs. 124
VALLEY CLEAN ENERGY ALLIANCE
Staff Report - Item 18
____________________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Interim General Manager
Mark Fenstermaker, Pacific Policy Group
SUBJECT: Recommendation to the Board on legislative position: SB 833 DATE: January 27, 2022
Recommendation:
Support SB 833 (Dodd)
Background and Analysis
The 2022 legislative session commenced on January 3, 2022, and legislators are in the process of introducing bills, some of which are reintroductions of bills that died in the 2021 session. Staff, working with VCE’s lobbyist Mark Fenstermaker of Pacific Policy Group and the Community Advisory Committee’s Legislative and Regulatory Task Group, will identify bills as they are introduced to review, analyze, and discuss potential positions to recommend to the Board as appropriate. At the most recent meeting between Staff, the Legislative and Regulatory Task Group, and Mr. Fenstermaker, the group discussed SB 833 (Dodd) and identified the bill as one to support.
Staff is recommending the Board adopt a support position on SB 833 based on the following analysis:
(Note: VCE supported Senator Dodd’s attempt in 2021 to enact similar policy with SB 99, but that bill was held in Assembly Appropriations)
SB 833 (Dodd) Community Energy Resilience Act of 2022
Summary: This bill adds new sections to the Public Resources Code to create a new program to be administered by the California Energy Commission (CEC) to award grants to local governments for the development of community energy resilience plans and for expediting local governments’ review of permits for distributed energy resources.
Specifically, the bill will:
1) Require the CEC to develop and implement a grant program for local governments to develop community energy resilience plans and expedite permit review of distributed energy resources by local governments
125
2) Require a plan to, among other things, identify critical facilities, locations and facilities where the construction of microgrids or other distributed energy sources could meet local resilience needs, and potential funding sources for implementing projects in the plan. 3) Require a local government to submit its plan to the commission within 6 months of adopting the plan. 4) Require each IOU to transparently solicit interest from legacy resource contract holders in renegotiating, buying out, or otherwise reducing costs from these contracts.
VCE supported Senator Dodd’s attempt in 2021 to enact similar policy with SB 99, but that bill was held in Assembly Appropriations.
This bill is consistent with the VCE Legislative Platform, specifically provision 7 regarding legislation regarding community resilience.
Additional Information
• The Climate Center is the sponsor of this bill
• Next hearing: The bill is awaiting referral to a policy committee. • Bill language: SB 833
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1 VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 19
To: Board of Directors
From: Mitch Sears, Interim General Manager
Rebecca Boyles, Director of Customer Care and Marketing Edward Burnham, Director of Finance & Internal Operations Subject: Approve temporary use of up to $200,000 of the program reserve fund to initiate the Ag FIT (Flexible Irrigation Technology) dynamic pricing pilot. (Action) Date: January 27, 2022
______________________________________________________________________________
RECOMMENDATION
Approve temporary use of up to $200,000 of the program reserve fund to initiate the Ag FIT (Flexible Irrigation Technology) dynamic pricing pilot.
BACKGROUND AND ANALYSIS
More than 85% of VCE’s service territory is designated for agricultural use. Due to this high concentration, the agricultural sector represents approximately 18% of VCE’s total annual load and 16% of its peak demand.
On December 14, 2017, the VCE Board adopted a Financial Reserve Policy that included a local programs reserve fund equal to a minimum of 1% of net income.. The Program Reserve Fund currently has $225K. In addition, the Board adopted a 3-year programs plan on June 10, 2021 that included an agricultural demand side program which evolved into the Ag FIT dynamic rate pilot program.
At its December 2, 2021, the CPUC issued decision 21-12-015 authorizing VCE’s proposed dynamic rate pilot to be made available to customers taking electric service on irrigation pumping tariffs. The Pilot includes automation of agricultural pumping loads to respond to dynamic prices set by VCE and implementation of an experimental rate that incorporates energy and delivery costs in hourly prices. Customers who successfully respond to the prices and shift load out of expensive hours—typically the ramp hours—are projected to enjoy bill savings of over 10% while contributing to grid reliability when it is most needed. A significant amount of the State’s agricultural irrigation pumping load is shiftable, presenting an important opportunity for California’s grid and environment.
VCE, along with several partners, had proposed this innovative 3-year pilot more than a year earlier as a way to help address grid reliability during peak electricity summer months.
Significant effort was required to steer though the obstacles critics placed in the path during 127
2 the CPUC process. And, although the pilot was approved, it includes budget provisions that now require VCE to use its existing program reserve as a temporary (reimbursable) source of funds to launch the pilot by the May 1st deadline set by the CPUC. Once CPUC funds are made available later in 2022, VCE’s programs reserve fund will be reimbursed. Notes: (1) the funds remaining in the programs reserve will be adequate to meet the needs associated with VCE’s other local programs that are in development (i.e. customer education/engagemet on electric heat pumps ans EV’s); and (2) VCE is in the process of working with the CPUC to expand the administrative budget to minimize financial outlays by VCE and its partners for the pilot.
Ag Fit Pilot Program Framework
Program Budget
The overall funding allocated by the CPUC to the 3-year pilot is $3.25M. The anticipated temporary budget requirement from VCE for this program for 2022 is $200,000 for funding VCE contractors for services related to program start-up and implementation.
Implementation Participants
VCE will collaboratively lead the administration and implementation with the support of Polaris, TeMIX, CPUC Energy Division, and PG&E.
Program Launch Date
The three-year pilot program will be launched by May 1, 2022.
Anticipated Program Benefits to participants
• Automation. Incentives up to $150 per HP to help pay for technology to improve operations and reduce costs.
• Bill Savings. 10-15% monthly savings for irrigating when power is least expensive. • Easy. The intuitive app makes it easy for growers to plan schedules in response to hourly prices published a week in advance. No demand charges. No penalties. No clawbacks.
• Flexible. Use irrigation technology provided by any vendor, or none at all.
Automated, remote/manual, or fully manual.
FISCAL IMPACT
The anticipated temporary budget of up to $200,000 of the program reserve fund will be covered by future reimbursable revenues to have a net neutral impact on the budget. Staff will review and provide a more detailed program budget for the three-year program in Q2/22.
If approved, the Ag FIT program budget will be included in the staff recommended budget to the Board on February 10, 2022.
CONCLUSION
Staff recommends the Board approve temporary use of up to $200,000 of the program reserve fund to initiate the Ag FIT (Flexible Irrigation Technology), dynamic pricing pilot, to meet the desired program timeline.
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VALLEY CLEAN ENERGY ALLIANCE
Staff Report – Item 20
____________________________________________________________________________________ TO: Board of Directors
FROM: Mitch Sears, Interim General Manager
Gordon Samuel, Assistant General Manager & Director of Power Services SUBJECT: Valley Clean Energy’s Policy regarding PG&E allocation of Greenhouse Gas (GHG)-free (Large Hydro and Nuclear) resources to Community Choice Aggregators DATE: January 27, 2022
RECOMMENDATION
1. Accept the 2022 allocation of large hydro carbon free attributes paid for by VCE customers;
2. Reject the 2022 allocation of nuclear power carbon free attributes;
3. Ratify the Interim General Manager’s approval to enter into an agreement with PG&E to accept only the Large Hydro portion of the 2022 GHG free allocations; and
4. In the event the future attributes (2023 and beyond) are made available to VCE and there are no material changes in VCE’s position, staff recommends:
a. Continuing to bring this item to the Community Advisory Committee (CAC) and Board as part of their respective consent agendas.
BACKGROUND
PG&E owns or contracts for a number of GHG-free resources (including large hydro and nuclear from Diablo Canyon Power Plant). PG&E has been able to count these resources on its power content label (PCL) to meet its GHG-free targets. Load serving entities (LSEs), on the other hand, have been paying for those same assets through Power Charge Indifference Adjustment (PCIA), yet do not receive any of the GHG-free benefits – this includes VCE.
In mid-2019, CCAs approached PG&E to discuss whether PG&E would be agreeable to selling energy from their large hydro facilities1. PG&E ultimately refused to make sales in 2019, but subsequently approached CCAs and offered to allocate GHG-free resources (nuclear and large hydro) to CCAs and other eligible load serving entities (LSEs).
1 Large hydro and nuclear resources count as GHG-free on the power content label (PCL), and investor-owned utilities (IOUs) have been benefiting from counting those resources to meet their GHG-free targets. LSEs, on the other hand, have been paying for those same assets through PCIA, yet do not receive any of the GHG-free benefits through the PCL. 129
2 Eventually the allocations became available in 2020, and the VCE Board elected to receive the large hydro only attributes. This became effective in the third quarter of 2020 and VCE received approximately 24,000 MWHs in 2020. For 2021, VCE has received 13,000 MWHs from February through June and anticipate a total of approximately 25,000 – 30,000 MWHs (note: VCE will not know the final 2021 numbers until Q2 2022).
There is no obligation to accept this allocation of GHG-free attributes. An LSE can choose to accept neither resource pool, one or the other, or both. The volume that each LSE receives will ultimately depend on the volume of electricity generated by each resource pool and the proportion of PG&E’s load served by the LSE.
TENTATIVE SCHEDULE
2022 Carbon Free Sales Tentative Timeline
November 1, 2021 • Notice Issued
Up to Week of November 15,
2021
• PG&E will provide Eligible LSEs with 2022 Sales Agreement for review
Wednesday, November 24, 2021
(ACTION REQUIRED)
• Feedback on form Sales Agreement due to PG&E
Up to Week of December 13,
2021 (ACTION REQUIRED)
• PG&E will provide Eligible LSEs Offers and a final version of 2022 Sales Agreement
• PG&E and Eligible LSEs will execute 2022 Sales Agreement January 1, 2022 (pending
execution of Sales Agreement)
• Expected start of Delivery Period under 2022 Sales
Agreement
Week of June 14, 2022
(approximation)
• First Quarterly Report for 2022 with estimated Allocation Amount will be distributed
On or about April 15, 2023 • Final Report for 2022 will be distributed to participating LSEs
RECOMMENDATION
As discussed with the Board in the past on this same topic related to the 2020 and 2021 allocations, staff continues to believe that:
• The potential reputational risk from accepting the nuclear allocation as part of our GHG-free target is greater than the potential savings for accepting this allocation. • The monetary savings for either of these allocations is very low. • Generally nuclear is not considered a clean fuel source due to risks associated with spent fuel and practical long-term disposal options.
• Three of the twelve northern California CCAs elected to receive the nuclear allocation in the past and are presenting it on their power content labels. 130
3 Based on these factors, staff believes that VCE is better served by accepting the hydro allocation for 2022, but not the nuclear allocation. Staff did present this topic to the CAC in November, and the majority of the CAC agree with this approach.
In summary, the staff recommendation to the Board is:
1. Accept the 2022 allocation of large hydro carbon free attributes paid for by VCE customers;
2. Reject the 2022 allocation of nuclear power carbon free attributes;
3. Ratify the Interim General Manager’s approval to enter into an agreement with PG&E to accept only the Large Hydro portion of the 2022 GHG free allocations; and
4. In the event the future attributes (2023 and beyond) are made available to VCE and there are no material changes in VCE’s position, staff recommends:
a. Continuing to bring this item to the Community Advisory Committee (CAC) and Board as part of their consent agendas.
Attachment:
1. Resolution Accepting Large Hydro Power GHG
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Item 20
1 VALLEY CLEAN ENERGY ALLIANCE
RESOLUTION NO. 2022-___
A RESOLUTION OF THE VALLEY CLEAN ENERGY ALLIANCE ACCEPTING THE 2022
ALLOCATION OF LARGE HYDRO POWER GHG ATTRIBUTES FROM PACIFIC GAS &
ELECTRIC AND AUTHORIZING THE INTERIM GENERAL MANAGER IN CONSULTATION
WITH LEGAL COUNSEL TO FINALIZE AND EXECUTE RELATED AGREEMENTS WHEREAS, the Valley Clean Energy Alliance (“VCE”) is a joint powers agency established under the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.) (“Act”), and pursuant to a Joint Exercise of Powers Agreement Relating to and Creating the Valley Clean Energy Alliance between the County of Yolo (“County”), the City of Davis (“Davis”), the City of Woodland and the City of Winters (“Cities”) (the “JPA Agreement”), to collectively study, promote, develop, conduct, operate, and manage energy programs; WHEREAS, large hydro and nuclear do not directly emit any GHG emissions, but do not qualify under the state’s RPS program;
WHEREAS, Pacific Gas and Electric (PG&E) owns and contracts for a number of GHG-free resources (including large hydro and nuclear) and count these resources on its power content label to meet its GHG-free targets;
WHEREAS, Load serving entities (LSEs), including Community Choice Aggregators (CCAs) such as VCE, have been paying for those same assets through Power Charge Indifference Adjustment (PCIA), but do not receive any of the GHG-free benefits; WHEREAS, in 2020 PG&E approached CCAs and offered to allocate GHG-free resources to CCAs and other eligible LSEs requiring no payment, and limited in the resources to which it applies (in-state, large hydroelectric, and nuclear); WHEREAS, in May 2020 and January 2021 VCE Board elected to accept the large hydroelectric GHG-free attributes for calendar year 2020 and 2021;
WHEREAS, for calendar year 2022 PG&E is again offering LSEs large hydro and nuclear GHG-free attributes.
///
///
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Item 20
2 NOW, THEREFORE, the Board of Directors of the Valley Clean Energy Alliance resolves as follows:
1. Accept the 2022 allocation of large hydro carbon free attributes paid for by VCE;
2. Reject the 2022 allocation of nuclear power carbon free attributes; and
3. The Interim General Manager is authorized to finalize, execute, and sign all agreements with PG&E on behalf of VCE and in consultation with legal counsel to implement the Board’s decision.
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:
_____________________________________
__________, VCE Chair
__________________________________
Alisa M. Lembke, VCEA Board Secretary
133